An Introduction to Concepts and Issues
Distributed utility planning ("DUP") is a concept in which modular electrical generation and
storage technologies, and specifically targeted demand-side management ("DSM") programs
(collectively "distributed resources"), are strategically sited and operated to supplement central
station generation plants and the transmission and distribution ("T&D") grid for the purpose of
cost-effectively obtaining both location-specific and system-wide customer benefits. Applicable
generation technologies include small-scale internal combustion engine-generator sets, small gas
turbine generators and microturbines, energy storage systems, and a number of "clean"
generation technologies including photovoltaics, wind turbines, and fuel cells. The benefits
obtained from DUP can include reducing the loading of T&D systems, thereby avoiding or
deferring major equipment upgrades; improving local power quality; reducing T&D system
losses; and, given the shorter lead times and the modularity of the technologies involved,
reducing the risk and cost of generation and T&D over-capacity by more closely matching
electrical supply to demand.
Distributed utility planning provides the potential for significant benefits for utilities and their
customers while lowering financial, environmental, and institutional risks. The modularity of the
generation technologies and DSM strategies provides utilities with flexibility in the emerging
competitive markets to meet uncertain load growth. The power quality and grid support
functions of distributed resources can provide new business opportunities to distribution
companies otherwise constrained by regional boundaries or low load growth. DUP also offers an
early market-entry path for cost-effective applications of newly emerging clean generation
technologies.
Background(1)
By the middle 1960s, the electric industry in the United States had developed into a highly
vertically integrated structure. This structure evolved because of the increasing economies of
scale of large central generating stations, the relatively low cost of T&D infrastructure, the
relative ease in siting large generation and transmission, and steady robust load growth. By the
1970s, these conditions began to change. Power plant economies of scale, which had increased
steadily during the industry's first 100 years, started to level out. Load growth slowed and
became less predictable. Increased environmental awareness made difficult the siting of new
central generating stations and transmission lines.
Since the late 1980s, investment in T&D infrastructure has outpaced that of generation. These
T&D investments are often under utilized as T&D systems are designed to meet infrequent and
relatively large peak loads. During this same period, the cost and performance of small-scale
generation has improved dramatically, and the design and delivery of DSM options has matured.
On the customer side of the meter, the proliferation of computer based devices and processes has
resulted in the need for high quality power and enhanced reliability.
From a regulatory perspective, the Public Utility Regulatory Policies Act of 1978 ("PURPA")
opened electric generation to non-utility generators by allowing them to interconnect and sell
power to the established utilities. The Energy Policy Act of 1992 allowed a new class of exempt
wholesale generators and established a federal policy for open access to the nation's transmission
systems. These policies, together with advancements in gas turbine technology over the past
twenty years, led to the rise of independent power producers ("IPPs") and demonstrated that the
integrated monopoly utility may neither be a necessary nor the most economic model for electric
generation. The success of IPPs is one of the primary drivers behind the current deregulation
trend. On the states' level, including Vermont, deregulation initiatives are underway that would
provide competition in the generation sector and unbundle the generation, transmission, and
distribution functions of integrated utilities.
All of these factors are increasing the pressures on electric utilities to reduce costs and to increase
the value of their services to customers. The traditional approach of building new central
generation, transmission lines, and distribution lines may no longer be feasible or be the most
cost-effective strategy to meet customers' demands for electrical services. It is in this context
that DUP emerges as an attractive option.
The Benefits of Distributed Resources
The value provided by distributed resources includes both the traditional capacity and energy
credits associated with a generation or DSM resource together with some or all of the following
benefits:
Transmission and Distribution Support. Strategically placed distributed resources can be used to
defer or eliminate the need for T&D additions and upgrades that otherwise would be required to
serve new load. Deferring or eliminating T&D infrastructure can provide substantial value to
utilities and their customers. This is especially true in areas where T&D infrastructure has been
placed underground or anyplace where the cost of capacity additions are high. Distributed
resources, especially those placed towards the ends of distribution feeders, can supply additional
benefits to the grid including lower line losses and voltage support. As the penetration of
distributed resources increases, regional and inter-regional transmission upgrades could be
deferred and the likelihood of transmission constraints reduced. Distributed resources that defer
or avoid the need for T&D upgrades also reduce utilities' risk of stranding T&D investments.
Power Quality and Reliability. To date, the primary driver of emerging DUP applications has
been the desire for enhanced power quality and reliability. The earliest applications of
distributed generation have been in commercial and industrial settings where high quality, very
reliable power is valued. The application of distributed resources at customer facilities offers
utilities a strategy for tailoring services to specific customer needs. This approach can build
customer relationships and create new business opportunities in an emerging competitive market.
Environmental Performance. Distributed resource technologies generally have lower
environmental impacts than conventional fossil-fueled generation. This is especially true for
DSM, fuel cell, and photovoltaic technologies because they: 1) tend to be physically small;
2) create little or no noise; 3) require little water; and 4) produce relatively low air emissions.
One of the most promising distributed resource technologies, gas-fueled microturbines, has
negligible SO2 emissions and significantly lower NOX emissions than central station fossil
generation. Microturbines are also physically small, produce low noise emissions and require
little or no water. The low environmental impacts of distributed resources enhance the suitability
of placing these technologies close to loads and populations where they are able to provide
maximum benefits. For some commercial users, environmental issues are a major concern.
Distributed resource technologies can provide these users with a strategy to generate good public
relations and to "green" their product, thereby enhancing their image and improving their sales.
Energy Price Risk Management. The onset of competition in the generation sector is expected to
result in increased energy price volatility. DUP can help manage risks in the generation sector in
several ways. First, the modularity of distributed resources offers a way to build new capacity in
a manner that closely follows load growth, thereby reducing the risk of errors in demand
projection. Second, systems that rely on relatively large generating units are more susceptible to
capacity shortages resulting from unplanned outages. Installation of smaller sized distributed
technologies would reduce the risk arising from unplanned outages.
Price risk can also be reduced for individual customers. By employing a so-called "convergence"
strategy, customers purchase and consume "units of power" from a variety of sources, and the
distinction between the use of electricity and other energy sources becomes blurred. For
example, an electric customer could purchase and install a gas-fired microturbine. Ownership of
the microturbine allows the customer to switch between buying natural gas for on-sight
generation and buying electricity from the market. This strategy increases the customer's fuel
flexibility and reliability and reduces exposure to price fluctuations for either gas or electricity.
Localized Economic Benefits. Certain distributed generation technologies placed on customers'
premises can be operated in a cogeneration mode. Cogeneration can result in lower overall
energy bills for the customer as well as provide some of the broader benefits discussed above.
Also, distributed resources, by their nature, create investments in the local community. Such
investments provide enhanced local economic benefits when compared to investments made in
larger, more remote generation resources.
To provide both traditional and distributed benefits, distributed resource technologies should
have the following characteristics: First, distributed resource technologies should be scalable to
meet the capacity limitations of utility distribution systems and substations. Most distribution
feeder capacities are in the range of 5 megaWatts ("MW") to 10MW. Substation capacities limit
the installation of distributed generation in substations to 20MW or so. While actual limitations
depend on the distributed resource's specific location, the network configuration, and existing
loads, it is clear that generating units greater than several MW in capacity generally are not
suitable for distributed resource applications. Second, distributed resource technologies should
be modular. It is anticipated that as distributed generation technologies mature, they will benefit
from economies of mass production and will be manufactured and sold like appliances.
Modularity permits shortened times for engineering, site preparation, field assembly, and
installation. Finally, when T&D deferral or elimination is sought, the distributed resources
employed should be of sufficient capacity and provide the appropriate output characteristics to
alter local peak demand profiles.
At present, United States and Canadian firms buy about 3,400MW of small generators each year.
While most of this generation provides backup power, some of this generation provides the
primary electric source for selected loads and facilities.(2) Forecasters predict substantial growth
in the distributed generation market in the coming years. The Electric Power Research Institute
estimates a potential distributed generation market of 2500MW per year in the U.S. by the year
2010. The U.S. Department of Energy estimates that by the year 2010, distributed generation
will account for as much as 20% of all new domestic power generation capacity additions.(3)
Fuel Cells. Fuel cells produce electricity and heat by combining fuel and oxygen in an
electrochemical reaction. Fuel cells can operate on a variety of fuels including natural gas,
propane, landfill gas, and hydrogen. Unlike traditional generating technologies, fuel cells do not
use a combustion process to convert fuel into heat and mechanical energy. Rather, a fuel cell's
direct conversion of chemical energy into heat and electrical energy results in quiet operation,
low emissions, and high efficiencies. With present technologies, fuel cell electrical efficiencies
range from 40% to 60%, and their combined electrical and heat efficiencies are over 80%.
Nearly all commercially installed fuel cells operate in a cogeneration mode. In addition, fuel
cells provide very reliable, premium quality electrical power and are therefore attractive to
customers operating sensitive electronic equipment. Presently, the cost of fuel cells are relatively
high at about $3,000 per kiloWatt ("kW"). However, if automotive applications of fuel cells
progress and mass production occurs, it is anticipated that the cost of fuel cells could fall as low
as $100/kW.
Microturbines. Microturbines are small gas turbines, with one moving part, ranging in size from
30kW to several hundred kW. Like fuel cells, microturbines operate on a variety of fuels
including gasoline, diesel, and natural gas.(4) Microturbines are quiet, operate at high speeds, and
employ rectifiers and static power converters to convert high-frequency alternating current
("AC") to direct current ("DC") and then to 60 Hertz AC. Like larger gas turbines, microturbines
are readily dispatchable and well suited for commercial and industrial applications. First
generation microturbines yield relatively low efficiencies of about 30%, but also have moderate
capital costs of around $600/kW. It is anticipated that microturbines that are fueled by natural
gas, without cogeneration, will produce electricity for 7 cents to 10 cents per kiloWatthour
("kWh") making them competitive with utility service in the near term.
Photovoltaics. Photovoltaic ("PV") panels are made of semiconductor devices that convert
sunlight into DC electricity. Static power converters are used to convert the DC into usable
60 Hertz AC. PV panels are modular, lightweight, contain no moving parts (unless tracking
devices are used), release no emissions, need no water, and have low operation and maintenance
requirements. Photovoltaic panels can be placed on rooftops giving this technology significant
siting flexibility. Compared to other distributed technologies, however, photovoltaics remain
relatively costly at about $5,000/kW installed. PV technology also requires relatively large areas
to produce significant amounts of power. The most common applications of PV technology to
date have been to power small loads in remote, off-grid sites where utility line extension costs
are prohibitive. As photovoltaics become more widely used, it is anticipated that resulting mass
production will lead to significant price decreases.
Demand Side Management. Demand-side management consists of utility
activities designed to influence customers' use of electricity in order to produce
desired changes in peak demands, energy use, and load shapes. DSM includes:
1) energy efficiency programs that, for example, promote and install efficient
appliances, lighting, heating, and industrial processes; 2) utility direct
load control of specific customer loads and end uses; and 3) rate designs
such as time-of-use rates, interruptible rates, and real-time pricing. Utilities
have gained significant experience with DSM during the past decade. Whereas
DSM has traditionally provided utilities with an alternative to generation expansion,
under DUP, DSM is now viewed as an alternative to T&D upgrades. A more detailed
discussion of DSM in Vermont can be found in Vermont Electric
Utility Demand Side Management Accomplishments: History and Current Trends
Others. A number of other technologies exist that are appropriate for DUP applications. The
most established distributed technology is the reciprocating engine/generator set. These engines
run on a variety of fuels, come in sizes from 5kW to tens of megaWatts, and have installed costs
ranging from $500/kW to $1,500/kW. These sets are mass produced, are supported by
established sales and maintenance infrastructures, and are now available as residential and
commercial cogeneration packages. The drawbacks to this technology include relatively high
emissions, high noise, and frequent maintenance. One of the fastest growing distributed
technologies is wind turbines. Recent technological advances have increased the efficiency and
reliability of wind turbines while lowering their costs. Installed costs for wind turbines range
from $1000/kW to $3000/kW. While wind turbines have no fuel requirements and zero
emissions, there are potential noise and visual aesthetic concerns, depending on the specific
application. Another class of distributed technology is the energy storage system, with the most
common energy storage device being the battery. Batteries store energy in chemical form and
like other storage devices can be used for peak shaving, spinning reserve, outage support, and
voltage and transient stability. While not yet viable for storing large amounts of energy, batteries
are currently used for uninterruptible power supplies, support for off-grid PV and wind systems,
and emergency backup for lighting and controls.
The interconnection of generation to distribution systems represents a substantial change from
traditional distribution system design. Most distribution systems are designed to accept power at
a single point from higher voltage transmission systems, usually at a distribution substation, and
then distribute the power in a single direction along radial feeders to customers. With distributed
generation, however, the uni-directional nature of power flow on distribution circuits can be
changed with potentially significant effects on voltage regulation, the behavior of the system
during faults, system protection, and safety procedures. Because the distribution system is the
portion of the power system that is closest to customers, its performance under the presence of
distributed generation directly influences the quality and reliability of power delivered to
customers.
Because voltage regulation and protection devices are coordinated under the assumption that
power flows in one direction only, distribution equipment, controls, and operating procedures
may require modification under the presence of distributed generation. The impact of distributed
generation on feeders, and the extent to which modifications are required, will depend on the
saturation and location of distributed generation units. Even at low penetrations, care must be
taken to ensure that appropriate system protection and safety procedures are in place. Of
particular concern is the possibility of "islanding," a condition in which a distributed generator
energizes a portion of a distribution system at a time when the remainder of the system is de-energized. Unintentional islanding can result in safety hazards and damage to customer
equipment.
To safely and reliably integrate distributed generation into power systems, generation
interconnection standards are required. On a national level, interconnection standards for
distributed photovoltaic generation is presently being developed by the Institute of Electrical and
Electronic Engineers ("IEEE") in a cooperative effort with Underwriters Laboratories ("UL").(5) A
final standard, IEEE Standard 929, is expected to be available by September 1999. An effort by
the IEEE to develop distributed generation interconnection standards for all types of generation
has recently begun. This standard, IEEE Standard 1547, is expected to be available in two to
three years. Presently, individual states and utilities are developing distributed generation
interconnection standards. In Vermont, interim interconnection standards have been established
by the Public Service Board for a subset of the distributed generation that is eligible for net
metering.(6) The Vermont Department of Public Service has drafted interconnection guidelines
applicable to all types of distributed generation up to 1MW in capacity that are interconnected to
radial distribution circuits.(7)
Recent developments in generation technology, together with the restructuring of the electric
utility industry, have focused attention on distributed resources as a retail access option and new
business opportunity for electric and gas utilities. For example, a subsidiary of Unicom
Corporation, the parent company of Commonwealth Edison, has formed an alliance with
AlliedSignal to market Allied's soon-to-be commercialized 75kW microturbine. GPU
Incorporated, a New Jersey and Pennsylvania based electric utility, co-founded Ballard
Generation Systems to develop and commercialize fuel cells. Plug Power, developer of fuel cells
for residential applications, was formed by Detroit Edison and fuel cell developer Mechanical
Technology, Inc. The ONSI Corporation, a pioneer in commercial fuel cell development, has
developed and commercialized a 200kW fuel cell. More than 170 of these fuel cells are in
service worldwide.
Examples of distributed resource applications can be found throughout the industry. The First
National Bank of Omaha will soon install four fuel cells at its new credit card processing center
to provide high quality, highly reliable power for its main frame computer. Niagara Mohawk
Power Corporation has installed a Power Enhancement and Delivery System ("PEDS") on one of
its distribution circuits. PEDS is a photovoltaic powered generation system and uninterruptible
power supply capable of overriding voltage anomalies and short-term outages on a scale
appropriate for small feeders or large customers. Hannaford Brothers Company has placed
generation at a number of its supermarkets to provide baseload power and to protect against
outages. Hannaford claims savings of up to $40,000 per day in avoided produce losses in the
event of an outage. Pacific Gas and Electric Company installed a 500kW photovoltaic plant at
its Kerman substation near Fresno, California, for grid support. The New York Power Authority
has installed a 200kW fuel cell in Yonkers, New York, that runs on digester gas from sewage
treatment. This unit reduces annual air emissions by 26 tons from reduced fossil fuel use and
from the utilization, as opposed to flaring of digester gas.
In Vermont, a $5 million transmission expansion in the Green Mountain Power Corporation
service territory has been deferred by the use of an interruptible contract with a major ski area.
In the Vermont Gas Systems service territory, a number of 60kW natural gas-fired reciprocating
engine cogeneration systems have been installed that provide electricity, process heat, and space
heat to a variety of commercial and institutional customers.
Barriers to Distributed Resource Development
To date, few electric utilities have fully embraced DUP. This is likely due, in part, to a number
of regulatory and institutional barriers to distributed resource development including the
dispersion of benefits, incompatible regulatory structures, and the changes and distractions
accompanying industry restructuring. Several of these barriers are discussed below together with
possible strategies for addressing these barriers.(8)
Dispersed Benefits. It is unlikely that the full array of benefits of a distributed resource
installation will accrue to the owner of that installation. This could lead to a market failure in
which societal resources are allocated inefficiently. Consider, for example, the hypothetical
installation of a fuel cell at the site of an electronics manufacturer located on a constrained
distribution feeder. Benefits to the manufacturer from this installation include premium quality
power, enhanced reliability, and process heat. Benefits to the distribution utility serving this
manufacturer are voltage support and the deferral of feeder upgrades. The general public
benefits from reduced air emissions and avoided postage stamp T&D rate increases. The energy
marketing firm involved benefits from increased interaction with its customer and lower supply
risk. From a societal perspective, the sum of all of these benefits, depending on the situation,
could exceed the incremental cost of the fuel cell over the cost of conventional options. At the
same time, no single set of benefits is large enough to entice any one entity to ultimately own and
install the unit. Hence, a market failure results.
One method of overcoming this barrier could be the introduction of appropriate regulatory
policy. For example, regulators could provide incentives to distribution utilities to install
distributed resources in a manner similar to that provided for the installation of demand side
resources. Small generators could be provided benefits from emission credit trading systems.
The most desirable resources could be afforded streamlined permitting, subsidies, or net metering
treatment. End users that install distributed resources could be provided targeted tax exemptions.
Cost Recovery Structures. Traditional cost-of-service ratemaking, which rewards utilities for
prudent capital investments, provides little financial incentive for utilities to lower their
investments in T&D. Generally speaking, cost-of-service ratemaking rewards increased T&D
capital spending over least-cost alternatives, creates disincentives to invest in energy efficiency
programs, and creates incentives for utilities to increase electricity sales.
Replacing cost-of-service ratemaking with performance-based ratemaking ("PBR") has the potential to reward utilities that effectively implement DUP. In principle, PBR rewards utilities for efficient operation and high-quality service, as measured by performance relative to pre-established targets, rather than for capital investments and electricity sales. Historically, PBR targets and incentive mechanisms have varied greatly, depending on the particular outcomes desired. For the purpose of encouraging utilities to adopt DUP, it is unlikely that simple mechanisms such as price caps would be appropriate. In order for PBR to prompt utilities to pursue DUP, the adoption of carefully chosen PBR targets and mechanisms would be required.(9)
As a precursor to PBR, service quality and reliability benchmarking would need to be
established.
Industry Restructuring. Electric utility industry restructuring and the anticipation of retail
competition have diverted the attention of utilities away from initiatives such as DUP. In recent
years, the focus of electric utilities has been on changes brought about by retail choice, recovery
of stranded costs, divestiture of generation, and mergers and acquisitions. Cost cutting by
utilities in preparation for competition has discouraged the investments in research,
experimentation, and organizational development required to make DUP work.
Utilities can be encouraged to pursue DUP through targeted regulatory directives, incentives, and
cost-recovery mechanisms. In the short term, experimentation could be encouraged and
rewarded until the uncertainties of restructuring have diminished. Over the long term, broad
policies on planning and cost recovery in a restructured industry could be established that reward
cost reduction through DUP.
Planning Methodologies. Traditional distribution planning methods and models do not account
for the various costs and benefits of distributed resources. The data required for a comprehensive
assessment of distributed resources in a given area may be undeveloped.
Utility distribution planners could be encouraged to develop and utilize models that account for
the costs and benefits of distributed resources. DUP models presently under development should
be assessed, modified, and applied where appropriate. Utilities could also begin to collect and
better understand the non-traditional data that is necessary for sound distributed resource
development. This data could include local area load forecasts; existing and planned customer
generation; customer end-use data; the value placed by customers on power quality and
reliability; and the cost, performance, and availability of emerging distributed resource
technologies.
Generation Ownership and Integration. In order to effectively integrate distributed generation
into distribution systems, distribution system planning needs to be closely integrated with
generation planning. Such integration is a departure from traditional distribution system
planning functions. In states where retail competition is in place, this integration may be further
complicated by the required separation or divestiture of generation away from the monopoly
distribution company. In the event that distribution companies are permitted to own and operate
distributed generation, it is still possible that distributed generation could be developed and
owned by other entities. Regardless of the specific circumstances, the need for close cooperation
between distribution companies and generators could present a barrier to distributed resource
development.
In the short term, regulators could permit distribution company ownership of generation that is
clearly targeted to T&D on the condition that the power be sold to wholesalers or power
exchanges and not on the retail market. Distribution companies could also co-invest in
distributed generation projects to reduce uncertainties about development and operation. For the
long term, communication between distribution companies, their customers, and generation
developers should be enhanced to coordinate the development of distributed generation with
distribution system expansion.
In recent years, through policy statements and initiatives, the Department has supported and
encouraged the development of DUP in Vermont.(10) The Department views DUP as consistent
with the Vermont statute and Public Service Board precedents mandating least-cost integrated
resource planning for the state's electric utilities.(11) The Department regards DUP as instrumental
for implementing its policies promoting the development of sustainable and renewable energy
resources in Vermont.(12) The Department also considers DUP to be consistent with its policy of
optimizing existing T&D infrastructure and minimizing the creation of new T&D corridors in the
state.(13)
Recently, the Department has been involved in a number of initiatives supporting the
development of distributed resources in Vermont. First, as discussed previously, performance-based ratemaking is likely the most appropriate cost-recovery strategy for encouraging DUP.
The Department has supported the establishment of PBR through its policy statements in the
context of electric utility restructuring.(14) The Department has also been active in the process of
establishing reliability benchmarking, a prerequisite to the introduction of PBR.(15) Second, the
Department was instrumental in the recent passage of net metering legislation in Vermont.(16) Net
metering provides incentives for the development of small-scale, renewable, distributed
generation. Third, as discussed previously, the Department has developed interconnection
guidelines for generators under 1MW in capacity that are interconnected to radial distribution
lines. Fourth, the Department has developed DUP guidelines that expand the traditional T&D
planning process to include distributed resource options for determining least-cost T&D system
expansions.(17) And fifth, the Department has been working with several Vermont businesses,
including a major ski area, to promote wood-fired cogeneration systems.(18)
Soon, the Department will enter into a formal collaborative process with Vermont's electric
utilities in an effort to build upon, revise, and further specify the implementation procedures
contained in the Department's DUP guidelines.(19) This collaborative process will also seek to
develop: 1) procedures for revising integrated resource planning filings by electric utilities to
reflect the principles of DUP; 2) externalities and risk adjustments to be used in DUP; and
3) streamlined procedures for identifying T&D projects that may require implementation before
the completion of a full DUP process.
1. This section summarizes a thorough discussion provided in Distributed Utility Technology Cost, Performance, and Environmental Characteristics, Yih-huei Wan and Steve Adelman, National Renewable Energy Laboratory, NREL/TP-463-7844, June 1995.
2. Power Engineering, February 1999, p. 22.
3. Ibid.
4. The term "gas turbine" refers not to the input fuel but to the fact that the turbine is powered by expanding high-temperature, high-pressure gases resulting from fuel combustion.
5. The IEEE is attempting to coordinate its Standard 929 with Underwriters Laboratories Standard UL 1741. UL 1741 is a test procedure that can be performed by an independent body to verify that inverters intended for use with utility-interconnected PV systems meet the recommendations of Standard 929. IEEE P929, Recommended Practice for Utility Interface of Photovoltaic (PV) Systems, Draft 10, February 1999.
6. In Vermont, generation powered by renewable resources up to 15kW in capacity, and farm anaerobic digestion systems up to 100kW in capacity, are eligible for net metering. 30 V.S.A. § 219a. The Vermont Public Service Board has established interim interconnection standards for generation powered by renewable resources up to 15kW in capacity. Vermont PSB Order Docket No. 6181, April 21, 1999.
7. To date, the Department's Interconnection Guidelines are advisory only and have not been adopted by the Public Service Board as a state standard. A copy of the Interconnection Guidelines is available by contacting the Vermont Department of Public Service at (802) 828-2811.
8. This section borrows from discussions contained in Helping Distributed Resources Happen: A Blueprint for Regulators, Advocates, and Distribution Companies, Fred Gordon, et.al, December 21, 1998.
9. Extensive discussions of performance-based ratemaking and its applicability to DUP can be found in: Legal, Regulatory & Institutional Issues Facing Distributed Resources Development, John Nimmons & Associates, Inc.; and Performance-Based Regulation in a Restructured Electric Industry, Synapse Energy Economics, Inc.
10. See for example: Fueling Vermont's Future, Comprehensive Energy Plan and Greenhouse Gas Action Plan Volume 1, pp. 3-29, 4-26 and Volume 2, pp. 3-159, 4-63, 1998; Vermont Twenty Year Electric Plan, p. 5-18, 1994; Docket No. 5854, Position Paper of the Vermont Department of Public Service, pp. 26, 57-58, March 25, 1996; Docket No. 5980, The Power to Save: A Plan to Transform Vermont's Energy-Efficiency Markets Appendix 5, May 23, 1997; Docket No. 5980, Memorandum of Understanding between the Vermont Department of Public Service, Central Vermont Public Service Corporation, and Green Mountain Power Corporation, pp. 17-22, April 30, 1999.
11. In general, the requirement for electric utility integrated resource planning is established in 30 V.S.A. § 218c and Vermont Public Service Board Docket No. 5270.
12. Fueling Vermont's Future, Comprehensive Energy Plan and Greenhouse Gas Action Plan Volume 1, pp. 2-4 to 2-8 and generally Chapter 4; Volume 2, pp. 2-8 to 2-20, 3-139 to 3-162 and generally Chapter 4, 1998; Vermont Twenty Year Electric Plan, pp. 1-2 to 1-6 and 4-51 to 4-56, 1994.
13. Vermont Twenty Year Electric Plan, pp. 5-19 and 5-24, 1994.
14. Docket No. 5854, Position Paper of the Vermont Department of Public Service, p. 67, March 25, 1996.
15. See Vermont Statewide Standards for Electric Utility Reliability Tracking and Reporting, A Report by the Vermont Electric Utility Reliability Task Force, May 8, 1998.
16. 30 V.S.A. § 219a.
17. Docket No. 5980, The Power to Save: A Plan to Transform Vermont's Energy-Efficiency Markets , Appendix 5, May 23, 1997.
18. Further information on the Department's biomass initiatives is available in The DPS and Biomass Development
19. See Docket No. 5980, Memorandum of Understanding between the Vermont Department of Public Service, Central Vermont Public Service Corporation, and Green Mountain Power Corporation, pp. 17-22, April 30, 1999.