Demand
Side Management
www.DemandSideManagement.com
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Price of Addiction ### to Foreign Oil |
Would your company be
interested in reducing its' energy expenses and carbon footprint by 25% to 35%
or more? We
are now offering a no-cost Demand Side Management audit for new commercial or
industrial customers that can answer yes to the following four questions:
1. Does your commercial or industrial facility use more than $100,000.00 of electricity and/or natural gas per month?
2. Has your facility experienced increased energy expenses?
3. Is your facility at least 5 years old and the facility has not completed any energy improvements in the past 5 years?
4. Would you be willing to install our recommended energy improvements that we find from the Demand Side Management audit - wherein we would guarantee that the savings of the improvements would pay for them?
If you answered yes to the above 4 questions, and your facility's energy expenses are over $100,000.00/month, call us today at: (832) 758 - 0027 to schedule your Demand Side Management audit!
For More Information about our Demand Side Management, and Energy Management Solutions for Commercial and Industrial Clients - or, to Schedule a No-cost Demand Side Management Audit that will Provide you with Recommendations and How you can Reduce your Energy Expenses, call us today at: (832) 758 - 0027
We partner and collaborate with other forward thinking companies and communities that are interested in changing the outdated power and energy model of the past - inefficient and highly-polluting central power plants that average 33% efficiency - to a new paradigm and model for the future - community-based cogeneration and trigeneration power plants at more than 90% efficiency - and therefore provides power and energy at lower prices while significantly reducing and even eliminating typical power plant emissions and greenhouse gas emissions.
Trigeneration Technologies, LLC.
"The
Trigeneration Experts"
the ONLY Company that Builds Integrated Cogeneration
& Trigeneration Plants on a Single
Skid with
Effective System Efficiencies that Exceed 90%
LEASING
OPTIONS NOW AVAILABLE
ON OUR NEW COGENERATION
AND
TRIGENERATION
POWER PLANTS!
Our
Optional SCR System Reduces
Nitrogen Oxides To "Non-Detect"
Without Ammonia or Urea
Our
small footprint Cogeneration Trigeneration
Plants measure:
15' wide x 15' in height x 55' in length
We Can Design, Build, and Install Your Next Cogeneration
or Trigeneration Power Plant and have it
online in less than 130 days!
Trigeneration Technologies, LLC. (www.Trigeneration.com) is a privately held company that was founded by several of the board members at the Renewable Energy Institute. Their specialty is trigeneration. They manufacture, sell and install trigeneration power plants that approach 100% net system efficiency. This means their trigeneration power plants provide nearly 100% of the power and energy from the fuel our trigeneration plants use, in the form of cooling (air conditioning) heating (hot water and/or steam) and electricity that our customers use in the businesses and buildings.
Put another way, their trigeneration power plants produce three energies for the price of one.
Trigeneration Technologies' newest manufacturing plant is now under construction and is located near Conroe, Texas. They expect the new facility to be completed by September - their present manufacturing plant is located near Palm Springs, California. They will be able to significantly increase their trigeneration power plant production at their new location to keep up with demand for their trigeneration power plants.
At over 92% net system efficiency, Trigeneration Technologies' trigeneration power plants are about 300% more efficient at providing energy than your current electric utility. That's because the typical electric utility's power plants are only about 33% efficient - they waste 2/3 of the fuel in generating electricity in the enormous amount of waste heat energy that they exhaust through their smokestacks.
Trigeneration is defined as the simultaneous production of three energies: cooling, heating and power. Trigeneration Technologies' trigeneration power plants use the same amount of fuel in producing three energies that would normally only produce just one type of energy. This means their customers that have their trigeneration power plants have significantly lower energy expenses, and a lower carbon footprint.
Trigeneration Technologies' smallest "standard" trigeneration power plant starts at $75,000 for a 50 kW trigeneration power plant. All of their trigeneration power plants can produce 20 degree F. cooling, as well as steam and hot water while generating 50 kW of power. They can build trigeneration power plants up to 10 MW and with system efficiencies approaching 100%.
Read more about our Trigeneration Power Plants on their Specifications page.
Trigeneration Technologies' trigeneration power plants are the ideal onsite power and energy solution for customers that include:
Data Centers, Hospitals, Universities, Airports, Central Plants, Colleges & Universities, Dairies, Server Farms, District Heating & Cooling Plants, Food Processing Plants, Golf/Country Clubs, Government Buildings, Grocery Stores, Hotels, Manufacturing Plants, Nursing Homes, Office Buildings / Campuses, Radio Stations, Refrigerated Warehouses, Resorts, Restaurants, Schools, Server Farms, Shopping Centers, Supermarkets, Television Stations, Theatres and Military Bases.
Not sure what size trigeneration power plant your facility will need?
Trigeneration Technologies can help as they offer of a Phase I Trigeneration Feasibility Study that will help you make a decision whether one of our trigeneration power plants are right for your facility and what the optimum sized trigeneration power plant would be. The Phase I Trigeneration Feasibility costs $50,000.00 (for most facilities). This does not include costs for travel, lodging and incidental expenses in the event they need to travel to your facility. The Phase I Trigeneration Feasibility requires about 60 to as many as 90 days to complete. At the conclusion and delivery of our Phase I Trigeneration Feasibility, you will know if your facility is a candidate for trigeneration and if your facility should consider trigeneration - you will have their recommendations as to the optimum size trigeneration power plant. You will also have an estimate as to how much money you will save by installing your new trigeneration power plant at your facility. If you order your new trigeneration power plant from Trigeneration Technologies within 30 days of the date of delivery of the Phase I Trigeneration Feasibility, they will reduce the cost of your new trigeneration power plant by half the cost of the study or $25,000.00.
To get started on the Phase I Cogeneration/Trigeneration Feasibility Study, they require one half of the fee or $25,000.00 plus the $2,500.00 deposit advance toward reimbursable expenses. The $25,000.00 balance is due when they deliver the report. Call (832) 758 - 0027 to schedule our Phase I Cogeneration/Trigeneration Feasibility Study.
For pricing and delivery information on Cogeneration or Trigeneration power plants, call (832) 758 - 0027 or send an email with your project's requirements to: info @ cogeneration .net
We can package any combination of standard size plants to come up with your optimum size system. Our standard and customized Cogeneration and Trigeneration power plants use the leading brands of reciprocating engines or turbines and include our proprietary Waste Heat Recovery technologies that help us achieve system efficiencies greater than 90% and effective heat rates as low as 4050 btu's/kW. We provide both standard and customized Cogeneration and Trigeneration plants that meet our customer's most stringent economic and environmental requirements.
Our Cogeneration and Trigeneration Power Plants can run on renewable fuels for even greater environmental and economic savings! These fuels or energy sources include: Biomethane, B100 Biodiesel, Dimethyl-Ether and natural gas fuels as well as Solar energy in our Solar Trigeneration power plants. Efficiencies of our Cogeneration and Trigeneration power plants are now exceeding 90% with up to 95% lower emissions when using Biomethane and B100 Biodiesel fuel.
Trigeneration is a technology whose time as come! Particularly for commercial clients who want to decrease their energy expenses and carbon footprint, while increasing energy efficiency and profits. This is possible as trigeneration power plants surpass 90% net system efficiency.
In association with the Renewable Energy Institute, affiliated companies, strategic partners and investors, including Trigeneration Technologies, we provide "turnkey" trigeneration power plant development services that range from initial Engineering Feasibility & Economic Analysis Studies through project installation, start-up and commissioning, Operations & Maintenance, and Long Term Service Agreements for the lifetime of our systems.
Our trigeneration plants can use renewable fuels such as Biomethane, B100 Biodiesel or Dimethyl Ether, instead of fossil fuels to run them. We also offer an optional selective catalytic reduction technology that takes NOx down to "non-detect" without the use of ammonia or urea on our new trigeneration plants.
Our range of services (some provided by affiliate companies, strategic partners or manufacturing suppliers) include:
-
Design/engineering, Engineering Feasibility and Economic Analysis Studies
-
Legal
-
Energy Service Agreements
-
Power Purchase Agreements
-
Build
-
Finance
-
Own
-
Operate
-
Maintain
-
Long Term Service Agreements
Our
renewable energy projects generate Renewable
Energy Credit or Certified
Emission Reduction credits, which provide an additional income stream from
our projects.
We
Can Design, Build, and Install Your New Trigeneration
Power Plant and
have it online in less than 130 - 150 days!
Our "Turnkey" Integrated Trigeneration
Energy Systems are Available from 60 kW to over 10 MW with system efficiencies
> 90% While Providing Practically-free Heating (and Cooling with
Trigeneration) and generating power for commercial and industrial customers
for as low as 4 cents/kW! We are the only company that builds,
fabricates, packages (on a single skid) and "integrates" Trigeneration
power plants.
Standard Trigeneration Power Plants sizes in kW:
60 kW
200 kW
450 kW
750 kW
75 kW
250 kW
500 kW
800 kW
100 kW
300 kW
600 kW
850 kW
150 kW
400 kW
700 kW
900 kW
Standard Cogeneration and Trigeneration Power Plants sizes in MW:
1 MW
2 MW 3 MW
4 MW 5 MW
We can package any combination of standard size plants to come up with your
optimum size system. Our standard and customized Trigeneration
power plants use the leading brands of reciprocating engines or turbines and
include our proprietary Waste Heat Recovery
technologies that help us achieve system efficiencies greater than 90% and
effective heat rates as low as 4050 btu's/kW. We provide both standard
and customized Trigeneration plants that meet
our customer's most stringent economic and environmental requirements.
Our Trigeneration Power Plants can run on renewable fuels for even greater environmental and economic savings! These fuels or energy sources include: Biomethane, B100 Biodiesel, Dimethyl-Ether and natural gas. Net system efficiencies of our Trigeneration power plants are now exceeding 90% with up to 95% lower emissions when using Biomethane and B100 Biodiesel fuel.
For pricing and delivery information on our Cogeneration or Trigeneration power plants, call (832) 758 - 0027 or send an email with your project's requirements to: info @ trigeneration .com
Our
New "Integrated" Trigeneration
Plants have Very High Efficiencies & Low Fuel Costs.
The Effective Heat Rate is Approximately
4050 btu/kW & System Efficiency is 92%
Pictures of the Newest 900 kW
Cogeneration Plant Presently Being Built for New Customer Features (2) Guascor
Natural Gas Engines
@ 450 kW each on one Skid for a Total of 900 kW
Our onsite trigeneration power and energy system can be an ideal solution for
customers wanting increased power reliability and decreased energy and
environmental costs. A few of the types of buildings and businesses that
would benefit from an onsite trigeneration plant include the following:
Airports
Casinos
Central Plants
Colleges & Universities
Dairies
Data Centers & Server Farms
District Heating & Cooling plants
Food Processing Plants
Golf/Country Clubs
Government
Buildings and Facilities
Grocery Stores
Hospitals
Hotels
Manufacturing Plants
Military
Bases
Nursing Homes
Office
Buildings / Campuses
Radio Stations
Refrigerated
Warehouses
Resorts
Restaurants
Schools
Server Farms
Shopping centers
Supermarkets
Television Stations
Theatres
For pricing and delivery information on our Cogeneration
or Trigeneration power plants, call (832) 758
- 0027 or send an email with your goals, objectives and requirements to:
info @ trigeneration .com
Our
Centrifugal Chiller HVAC Plant Will
Lower your Heating and Air-Conditioning Costs By Up To 75% (for
Commercial/Industrial Clients only with a Minimum size of 60 Tons A/C)
Call (832) 758 - 0027 for more information
What is Demand Side Management?
Demand
Side Management, or "DSM" is the process of managing the consumption
of energy, generally to optimize available and planned generation resources.
Not all businesses are candidates for cogeneration or
trigeneration, however,
your company may be a great candidate for other energy-saving solutions. One
of these is Demand Side Management, or "DSM". We also provide
cost-effective DSM solutions.
According to the Department of Energy, Demand Side Management refers to "actions taken on the customer's side of the meter to change the amount or timing of energy consumption. Utility DSM programs offer a variety of measures that can reduce energy consumption and consumer energy expenses. Electricity DSM strategies have the goal of maximizing end-use efficiency to avoid or postpone the construction of new generating plants."
What is Automated Demand Response?
Automated
Demand Response is a Demand Side Management solution that is
specifically designed for a customer's specific location, energy/power
requirements, and also for the specific electric rates for that customer's
location. Automated Demand Response does not involve human intervention, but is initiated at a facility through receipt of an external communications signal.
Automated Demand Response is a rather new area of DSM technologies and may
provide a lucrative revenue stream for customers who can curtail electric load in response to demand incentives, ICAP payments, and/or commodity prices.
Automated demand response technology seeks to automatically, through
software and hardware applications, to respond to variations in the
electricity/power market prices.
Demand Response or Demand Side Management can be achieved through demand reduction, by shifting load to a less expensive time period, or by substituting another resource for delivered electricity (such as
natural gas or onsite power generation, also known as "distributed
generation."
Demand Response (DR) is a set of activities to reduce or shift electricity use to improve electric grid reliability, manage electricity costs, and ensure that customers receive signals that encourage load reduction during times when the electric grid is near its capacity. The two main drivers for widespread demand responsiveness are the prevention of future electricity crises and the reduction of electricity prices. Additional goals for price responsiveness include equity through cost of service pricing, and customer control of electricity usage and bills. The technology developed and evaluated in this report could be used to support numerous forms of DR programs and tariffs.
A recent pilot test to enable an Automatic Demand Response system in California has revealed several lessons that are important to consider for a wider application of a regional or statewide Demand Response Program.
The six facilities involved in the site testing were from diverse areas of our economy. The test subjects included a major retail food marketer and one of their retail grocery stores, financial services buildings for a major bank, a postal services facility, a federal government office building, a state university site, and ancillary buildings to a pharmaceutical research company. Although these organizations are all serving diverse purposes and customers, they share some underlying common characteristics that make their simultaneous study worthwhile from a market transformation perspective. These are large organizations. Energy efficiency is neither their core business nor are the
decision-makers who will enable this technology powerful players in their organizations. The management of buildings is perceived to be a small issue for top management and unless something goes wrong, little attention is paid to the building manager's problems.
All of these organizations contract out a major part of their technical building operating systems. Control systems and energy management systems are proprietary. Their systems do not easily interact with one another. Management is, with the exception of one site, not electronically or computer literate enough to understand the full dimensions of the technology they have purchased. Despite the research teams development of a simple, straightforward method of informing them about the features of the demand response program, they had significant difficulty enabling their systems to meet the needs of the research. The research team had to step in and work directly with their vendors and contractors at all but one location. All of the participants have volunteered to participate in the study for altruistic reasons, that is, to help find solutions to California's energy problems. They have provided support in workmen, access to sites and vendors, and money to participate. Their efforts have revealed organizational and technical system barriers to the implementation of a wide scale
program.
What is Demand Response and How is it Different from "Demand Side Management"?
"Demand Response" is a subset of Demand Side Management (DSM) or a potential Demand Side Management program solution which helps make the electric grid much more efficient and balanced by assisting the electric grid's commercial and industrial customers reduce their electric demand, and/or shifts the time period when they use their electricity, and/or prioritizes the way they use electricity, and in so doing, reduces their overall energy costs. A Demand Side Management Program will include measures that promotes the following:
-
Reduced customer peak and overall energy demand
-
Improves the electric grid's reliability
-
Balances the electric grid through increased efficiency
-
Energy efficiency
-
Manages electricity costs
-
Conservation through both behavioral and operational changes
-
Load management
-
Fuel switching
-
Distributed energy
-
And provide systems that encourage load shifting or load shedding during times when the electric grid is near its capacity or electric power prices are high
Demand Response has also been defined as a "Demand Side Management" subset that is a set of time dependent activities that reduces or shifts electricity use of selected customers.
Electric power generation and distribution systems are strongly affected by supply-side policies (how, when, and where to generate electricity, how to couple generation into the grid, how to transmit and distribute generated electricity) and demand-side policies (pricing schemes, conservation efforts, customer premises automation, and, in extreme circumstances, rolling blackouts). Demand-side programs focus on reducing the peak-to-average demand profiles through automation in the customer premises.
What are Demand Response Programs?
Demand Response Programs are programs usually designed and offered by electric utilities that offers those clients that sign-up for specific DR programs with financial incentives and other benefits that help those participating customers to curtail energy use. These actions by the electric utilities and participating clients provide a reliable, predictable amount of power (megawatts) that the ISO's and RTO's can count on during an emergency when energy supplies are low, and there is an inadequate amount of available power generation. The electric utilities typically require that those customers that enroll in their DR program(s) install certain software and hardware, that communicates with these client's online energy management systems, and can control these client's electric power requirements as needed.
What is Load Response?
Load response and Load Response programs operate in response to requests for peak load reductions with little, if any, discretion in compliance on the part of the customer. The buyer or operator, such as a traditional utility, load serving entity, curtailment service provider, or grid operator, directs load response programs.
What is Price Response?
Price Response and Price response programs operate based on voluntary actions of customers in response to economic signals. The differences between Price Response and Load Response programs are a matter of degree. The most pronounced difference is price response programs rely on wholesale clearing prices as a primary signal or method to reimburse customers for their participation, and are much more likely to be voluntary. Some load response programs have the same characteristics, but are skewed toward a command-and-control methodology.
More
About Price Response and Load Response Programs
Load
response is a type of demand side management solution that commercial and
industrial customers may choose to employ in response to wholesale electricity
prices or other market incentives which can serve several important
system-wide functions.
For example, retail customers can ease tight capacity situations and mitigate reliability concerns by reducing their electric power usage or consumption. By reducing consumption in response to price signals or other financial incentives, retail customers also can reduce peak wholesale electricity prices, mitigate price volatility, and reduce opportunities for market manipulation.
It is not necessary for all customers to participate in these emergency or economic load response programs; even the response of a small percentage of customers can produce significant benefits for the electric grid and its customers.
In order to participate in load response programs, customers need load response “tools” or solutions that can assist them in reducing their electric power usage at the appropriate times.
The two main categories of load response tools are communications devices and mechanisms for modifying a customer’s usage of electricity supplied by the grid during peak hours and conditions. Customers have two basic mechanisms for reducing their demand on the local electricity grid. They can simply reduce their electricity at key times through load response management, energy efficiency or energy conservation measures and improvements, or the customer can shift their source of electricity from the grid to on-site cogeneration or trigeneration power and energy systems thereby reducing their use of grid electricity but not their overall use of electricity.
Emergency load response can be implemented with readily available technology. For example, load response software can be installed in a building (e.g., an industrial facility, an office building, or commercial establishment, or even a home) that would connect to the outside world (signals sent by the Independent System Operator) with building control systems (e.g., thermostats, light dimmers). The building owner or operator could choose to respond to the signal or not. With currently available software, building operators could be notified through e-mail, cellular phone, and alpha-numeric paging of an expected reliability threat and could respond as simply as pressing a “yes” or “no” button included with the system. An affirmative answer would trigger predetermined changes to building systems (e.g., the lights could dim twenty percent, the AC thermostat could rise two degrees) for a set time.
Emergency load response to serve a reliability function is not new technology. For years, electric utilities and system operators have offered special rates to customers who were willing to curtail their load upon request from the utility or system operator to avert short-term reliability problems. On hot days when demand threatens to overwhelm the available capacity on the system, customers willing and able to lower the amount of electricity they draw from the grid offer a resource that can be tapped to delay or avoid the need for more drastic measures, including rolling brown-outs or rolling black-outs. Customers participating in load response programs don’t just avoid costs associated with consuming at high prices at peak periods; they can receive payments from “selling” the power they don’t use at market prices.
Simply put, the electricity that the customer decides not to use at peak times can be sold back into the energy market at peak prices.
Background on Demand Side Management
Demand-side management (DSM) programs consist of the planning, implementing,
and monitoring activities of electric utilities that are designed to encourage
consumers to modify their level and pattern of electricity usage.
In the past, the primary objective of most DSM programs was to provide
cost-effective energy and capacity resources to help defer the need for new
sources of power, including generating facilities, power purchases, and
transmission and distribution capacity additions. However, due to changes
occurring within the industry, electric utilities are also using DSM to
enhance customer service. DSM refers only to energy and load-shape modifying
activities undertaken in response to utility-administered programs. It does
not refer to energy and load-shape changes arising from the normal operation
of the marketplace or from government-mandated energy-efficiency standards.
Historical Information of DSM (1999)
In 1999, 848 electric utilities report having demand-side management (DSM)
programs. Of these, 459 are classified as large, and 389 are classified as
small utilities. This is a decrease of 124 utilities from 1998.(1) DSM costs
were almost unchanged at 1.4 billion dollars in both 1998 and 1999.
Energy Savings for the 459 large electric utilities increased to 50.6 billion
kilowatt hours, 1.4 billion kilowatt hours more than in 1998. These energy
savings represent 1.5 percent of annual electric sales of 3,312 billion
kilowatthours(2) to ultimate consumers in 1999.
Actual peak load reductions for large utilities decreased in 1999 to 26,455
megawatts. Potential peak load reductions of 43,570 megawatts were an increase
of 2,140 over 1998.
In 1999, incremental energy savings for large utilities were 3.1 billion
kilowatt hours, incremental actual peak load reductions were 2,263 megawatts.
Technologies Used in Demand Side Management:
These energy conservation technologies are implemented to reduce total energy
use. Specific technologies include energy-efficient lighting, appliances, and
building equipment, all of which can be found on the EREN Buildings Energy
Efficiency page. For energy efficiency at industrial sites, see the EREN
Industrial Energy Efficiency page.
Load Leveling:
These technologies are used to smooth out the peaks and dips in energy demand
— by reducing consumption at peak times ("peak shaving"),
increasing it during off-peak times ("valley filling"), or shifting
the load from peak to off-peak periods — to maximize use of efficient
baseload generation and reduce the need for spinning reserves.
Load control:
Energy management control systems (EMCSs) can be used to switch electrical
equipment on or off for load leveling purposes. Some EMCSs enable direct
off-site control (by the utility) of user equipment. Typically applied to
heating, cooling, ventilation, and lighting loads, EMCSs can also be used to
invoke on-site generators, thereby reducing peak demand for grid electricity.
Energy storage devices located on the customer's side of the meter can be used
to shift the timing of energy consumption.
Issues Involving the Implementation Demand Side Management Solutions
Include: Public Benefits Programs, Rate Schedules, Time-of-Use Rates,
Power Factor Charges, and Real-Time-Pricing
Public Benefits Programs
Prior to electricity industry restructuring, utilities were responsible for a
variety of programs (including DSM) that meet social objectives. Under
restructuring, funding for these programs is typically through a small
surcharge ("wires charge" or "system benefits charge") on
utility bills.
Rate Schedules
Utilities can structure their rates to encourage customers to modify their
pattern of energy use.
Time-of-Use Rates
Time-of-use
rates involve charging higher prices for peak electricity as a way to shift
demand to off-peak periods. Interruptible rates offer discounts in exchange
for a user commitment to reduce demand when requested by the utility.
Power Factor Charges
Power
factor charges can be implemented to discourage commercial and industrial
utility customers from partially loading their electrical equipment, as this
requires the utility to generate extra current to cover the resulting system
losses.
Real-Time Pricing
Real-time pricing is where the electricity price varies continuously (or hour by hour) based on the utility's load and the different types of power plants that have to be operated to satisfy that demand.
The
Growing Need of Demand Side Management
(reprinted
with permission by the Author, Satish Saini)
|
Analysis of the Ontario electricity market since it opened for competition in May 2002 shows it on the verge of facing supply shortages leading to reliability problems and dependent on importing expensive electricity leading to high rising prices. Ontario’s
Deregulated Electricity Market: Power
Position in Ontario The hourly import levels since market opening in May 2002 up to August 31, 2003 indicate an average import level of 1,120 MW for all hours. During the 2,171 hours when Ontario demand exceeded 20,000 MW the average import level was 1,579 MW. During the 265 hours when Ontario demand exceeded 23,000 MW the average import level was 2,436 MW, which occasionally reached the Ontario’s coincident import capability of around 4,000 MW. The cause of these heavy imports and supply shortage is stated to be the forced shut down of some generating plants and the delays in returning other generating stations to service as planned that had been taken out of service for routine maintenance. Even in the future forecast, Ontario’s power generation capacity is said to be insufficient to meet the expected loads. The main reason to worry is that over the next 10 to 15 years, approximately 40 per cent of the current installed capacity will reach the end of its nominal life while the demand is going to increase. Electricity
Prices in Ontario The IMO sets the wholesale electricity prices by collecting offers from suppliers and bids from purchasers to determine on-the-spot market price for electricity. It uses these offers and bids to match electricity supply with demand, and establishes the Hourly Ontario Energy Price called HOEP. So energy prices change from time to time depending upon the demand and available supply. After deregulating the market in May 2002, the Ontario government freezed the retail price to be paid by residential, commercial and other low volume designated consumers at 4.3 cents per Kwh ($ 43.00 per Mwh) in December, 2002. Having a look at the following Table-1 showing the maximum HOEP of each month since May 2002, we find it to be as high as $ 1028.42 per Mwh, i.e. to be 24 times higher than the fixed price of $ 43.00 per Mwh Table
1.
Even if we leave aside this maximum HOEP during the month and take the monthly weighted average of this price, we find from the following Table-2 that even the monthly weighted average price has been more than 1.5 times the fixed price in many months. Table
2.
After analyzing the maximum HOEP and Monthly Weighted Average Price of each month as compared to the fixed price, we see from the following Table-3 that it was on an average 350 times during a single month (i.e. on an average 12 times during a day) that the HOEP has been higher than the fixed price Table
3. Number of Times HOEP greater than the Fixed Price During the Month
(No.):
What
makes the price volatile: How
to control Price Volatility and Supply Shortages For short term measures the supply-side management is not effective as it takes long time for units to start up (if these are available) and meet the rising demand immediately, rather it is demand side management which can be implemented immediately and in more economic ways to keep the balance. Why
DSM is so significant in Ontario The provincial policies by this time are not attracting any good investments in new power generation plants and our old plants already aging, we stand on the verge of facing severe power crises in the future. And by this time we are familiar with the huge economical losses faced due to blackouts. Moreover, seeing the electricity price almost always above the fixed set price and growing burden on the tax payers in the shape debt due to subsidies by freezing price, Ontario needs strong DSM strategies. Potential
of DSM in Ontario In one of the statement by a representative of IMO, it was mentioned that Ontario has been able to reduce demand by as much as 4,500 megawatts. This reduction was an important contributor to avoid the need for rotational power outages in Ontario after blackout. This proves the potential of DSM in Ontario and what we need is a dedicated and sincere approach by various segments of the Power Sector in the province. We
can achieve this by using various Tools and Techniques of DSM as
follows: Automated/Smart
Metering DSM
Techniques
Energy
Conservation and Efficiency programs There are various opportunities and techniques available for reducing energy consumption such as efficient lighting, variable speed drives, solar hot water systems etc. These technologies reduce demand, help in lowering high peak prices and also reduce greenhouse gas emissions due to less stress on generating plants. Load Response Programs (LRP) Load Response Programs are an effective part of Demand Side Management. These are the actions undertaken in response to electricity supply position and wholesale market price of electricity. Or in other sense these refer to switching off or reschedule of non-essential and non-critical loads by the end users in response to the request of IMO or the utilities. This can lead to save the system network from exceeding its peak rating. There are a large variety of load equipments and applications that can be switched on or off at a particular times to reduce electricity demand from the network. Depending
upon the market drivers these can be classified in two broad
categories: Market/Price
based programs: These programs can include Day Ahead Demand Response Program, where the end users respond to price signals and reduce loads when the price exceeds their set Base Price on day to day or day-ahead time basis. Depending
upon the participants and implementing agencies, these can be of two
types as
Infrastructure
for LRP Benefits
of DSM:
DSM
Program Approaches:
These DSM programs and policies can be promoted and implemented at different levels of the society as:
Each of these units has its own significant role to play. But the optimum results can be obtained by coordinating all the three. Government agencies can make various policies and regulations, provide subsidies for these programs and Utilities can implement these more effectively through different cost-effective and customized programs in coordination with the end-users i.e. the consumers. DSM
Programs Strategies
Successful
DSM Studies It has been studied in U.S. that with universal application, peak energy demand could be lowered by at least 30,000 MW nationally, equivalent to perhaps as many as 250 peaking plants that would not need to be built. Society could avoid the burning of 680 bcf of gas per year and 31,000 tons of NOx emissions. A study in 2002 showed that New York’s electricity market along with its grid operator and large electric utility companies has the potential to reduce demand for electricity by at least 1300 megawatts (MW) through Demand Side Management techniques, which is enough to supply power to 1.3 million homes. Similarly the Internal Energy Efficiency Program of Ontario Power Generation (OPG) in Canada since 1994 has helped to save 2,131 GWh of energy every year, 2.4 million metric tons of emission savings for CO2, NOx and SO2 and a saving of US$85.2 million every year. Conclusion Thus it provides significant economic, system reliability and environmental benefits. DSM techniques are the cheapest, fastest and cleanest way to solve our electricity problems. These can be immediately implemented and many times at one-tenth the cost of building new power plants. This is what needed at this moment in Ontario when it is passing through the phase of uncertainty, already partially backed out from its deregulation policies by placing price caps or regulating prices. Forecast about power shortage in Ontario in the coming years, aging existing power plants with less investments in new generation compel us to go for the only option left i.e. controlling demand through Demand Side Management to avoid blackouts and power imports at high prices. |
Electric
Utility Demand Side Management
Glossary of Terms
Actual
Peak Reduction - The actual reduction in annual peak load (measured in
kilowatts) achieved by consumers that participate in a utility DSM program. It
reflects the changes in the demand for electricity resulting from a utility
DSM program that is in effect at the same time the utility experiences its
annual peak load, as opposed to the installed peak load reduction capability
(i.e., Potential Peak Reduction). It should account for the regular cycling of
energy efficient units during the period of annual peak load.
Annual Effects - The total changes in energy use (measured in megawatt
hours) and peak load (measured in kilowatts) caused by all participants in
your DSM programs. This includes new and existing participants in existing
programs (those implemented in prior years that are in place during the given
year), all participants in new programs (those implemented during the given
year), and participants in DSM programs that were terminated after 1992.
Please note that Annual Effects are not a summation of 12 monthly peaks or the
aggregate of the Incremental Effects for the reporting year, but are the total
effects of all DSM programs for all participants (new and existing) for the
year.
Direct Load Control - DSM program activities that can interrupt
consumer load at the time of annual peak load by direct control of the utility
system operator by interrupting power supply to individual appliances or
equipment on consumer premises. This type of control usually involves
residential consumers. Direct Load Control as defined here excludes
Interruptible Load and Other Load Management effects.
Energy Effects - The changes in aggregate electricity use (measured in
mega watt hours) for consumers that participate in a utility DSM program.
Energy Effects represent changes at the consumer's meter (i.e., exclude
transmission and distribution effects) and reflect only activities that are
undertaken specifically in response to utility-administered programs,
including those activities implemented by third parties under contract to the
utility. To the extent possible, Energy Effects should exclude non-program
related effects such as changes in energy usage attributable to
non-participants, government-mandated energy-efficiency standards that
legislate improvements in building and appliance energy usage, changes in
consumer behavior that result in greater energy use after initiation in a DSM
program, the natural operations of the marketplace, and weather and
business-cycle adjustments.
Energy Efficiency - DSM programs that are aimed at reducing the energy
used by specific end- use devices and systems, typically without affecting the
services provided. These programs reduce overall electricity consumption
(reported in mega watt hours), often without explicit consideration for the
timing of program-induced savings. Such savings are generally achieved by
substituting technologically more advanced equipment to produce the same level
of end-use services (e.g., lighting, heating, motor drive) with less
electricity. Examples include energy saving appliances and lighting programs,
high-efficiency heating, ventilating and air conditioning (HVAC) systems or
control modifications, efficient building design, advanced electric motor
drives, and heat recovery systems.
Incremental Effects - The annual changes in energy use (measured in
mega watt hours) and peak load (measured in kilowatts) caused by new
participants in existing DSM programs and all participants in new DSM programs
during a given year. Reported Incremental Effects are annualized to indicate
the program effects that would have occurred had these participants been
initiated into the program on January 1 of the given year. Incremental effects
are not simply the Annual Effects of a given year minus the Annual Effects of
the prior year, since these net effects would fail to account for program
attrition, equipment degradation, building demolition, and participant
dropouts. Please note that Incremental Effects are not a monthly disaggregate
of the Annual Effects, but are the total year's effects of only the new
participants and programs for that year.
Interruptible Load - DSM program activities that, in accordance with
contractual arrangements, can interrupt consumer load at times of seasonal
peak load by direct control of the utility system operator or by action of the
consumer at the direct request of the system operator. This type of control
usually involves commercial and industrial consumers. In some instances, the
load reduction may be affected by direct action of the system operator (remote
tripping) after notice to the consumer in accordance with contractual
provisions.
Load Shape - a method of describing peak load demand and the
relationship of power supplied to the time of occurrence.
Other Load Management - DSM programs other than Direct Load Control and
Interruptible Load that limit or shift peak load from on-peak to off-peak time
periods. It includes technologies that primarily shift all or part of a load
from one time-of-day to another and secondarily may have an impact on energy
consumption. Examples include space heating and water heating storage systems,
cool storage systems, and load limiting devices in energy management systems.
This category also includes programs that aggressively promote time-of-use (TOU)
rates and other innovative rates such as real time pricing. These rates are
intended to reduce consumer bills and shift hours of operation of equipment
from on-peak to off-peak periods through the application of
time-differentiated rates.
Potential Peak Reduction - The potential annual peak load reduction
(measured in kilowatts) that can be deployed from Direct Load Control,
Interruptible Load, Other Load Management, and Other DSM Program activities.
(Please note that Energy Efficiency and Load Building are not included in
Potential Peak Reduction.) It represents the load that can be reduced either
by the direct control of the utility system operator or by the consumer in
response to a utility request to curtail load. It reflects the installed load
reduction capability, as opposed to the Actual Peak Reduction achieved by
participants, during the time of annual system peak load.
Program Cost - Utility costs that reflect the total cash expenditures
for the year, reported in nominal dollars, that flowed out to support DSM
programs. They are reported in the year they are incurred, regardless of when
the actual effects occur.
Background
Demand-side management (DSM) programs consist of the planning, implementing,
and monitoring activities of electric utilities which are designed to
encourage consumers to modify their level and pattern of electricity usage.
In the past, the primary objective of most DSM programs was to provide
cost-effective energy and capacity resources to help defer the need for new
sources of power, including generating facilities, power purchases, and
transmission and distribution capacity additions. However, due to changes that
are occurring within the industry, electric utilities are also using DSM as a
way to enhance customer service. DSM refers to only energy and load-shape
modifying activities that are undertaken in response to utility-administered
programs. It does not refer to energy and load-shape changes arising from the
normal operation of the marketplace or from government-mandated
energy-efficiency standards.
Additional Historical DSM Information
In 1997, 971 electric utilities reported having DSM programs. Of these, 561
are classified as large and 410 are classified as small utilities. The 561
large utilities account for 89.5 percent of the total retail sales of
electricity in the United States.(1)
Energy savings for the 561 large electric utilities decreased to 56,406
million kilowatthours (kWh), 5,436 million kWh less than in 1996. These energy
savings represent 1.8 percent of annual electric sales of 3,140 billion kWh to
ultimate consumers in 1997.
Actual peak load reductions, the goal of the DSM program, for large utilities
was 15.4 percent lower in 1997, at 25,284 megawatts, than in 1996. Potential
peak load reductions were 14.7 percent lower in 1997 than in 1996.
DSM costs continued to decrease from $1.9 billion in 1996 to $1.6 billion in
1997.(2) This is the fourth consecutive year that DSM costs have decreased
from a high of $2.7 billion in 1993.
For 1997, incremental energy savings for large utilities were 4,832 million
kilowatthours, and incremental actual peak load reductions were 2,326
megawatts.
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1. Large utilities are those reporting sales to ultimate consumers or sales
for resale greater than or equal to 120,000 mega watt hours. Small utilities
with sales to ultimate consumers and sales for resale of less than 120,000
mega watt hours are only required to report incremental energy savings and
peak load reduction, and total utility and total DSM costs for the reporting
year and for the first forecast year.
2. It is tempting, but misleading, to compare DSM costs to supply-side
investments on an unadjusted cost-per-kilowatt hours or cost-per-kilowatt
basis. The calculation of appropriate measures for economic comparisons of DSM
and supply-side investments requires that consideration of the life-cycle cost
of the options being compared be addressed on an integrated basis (i.e., the
interaction of the change in end-use patterns with the production function of
the utility must be considered over the expected life of the various options
being compared). In addition, the rate impacts of each alternative must be
compared because alternative DSM/supply-side combinations may result in
differing patterns of revenue requirements over time. The data presented are
not sufficient to allow for such comparison.
