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Price of Addiction ### to Foreign Oil |
“spending hundreds and hundreds and hundreds of billions of dollars every year for oil, much of it from the Middle East, is just about the single stupidest thing that modern society could possibly do. It’s very difficult to think of anything more idiotic then that.” R. James Woolsey, Jr., former Director of the CIA
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.
We
Package, Sell and Install Highly-efficient
Cogeneration and Trigeneration
energy systems
Trigeneration Technologies, LLC. is a privately held company formed by the founder of the Renewable Energy Institute. Our specialty is cogeneration and trigeneration energy systems that are packaged for us according to our specifications by our supplier. Our cogeneration and trigeneration energy systems exceed 80% net system efficiency. A recent 900 kW cogeneration system's system efficiency exceeded 90% net system efficiency.
What is "Cogeneration"?
Did you know that 10% of our nation's electricity now comes from "cogeneration" plants?
And
because cogeneration is so efficient, it
saves its customers up to 40% on their energy expenses, and provides even greater savings to our
environment through significant reductions in fuel usage and much lower greenhouse
gas emissions.
Cogeneration
- also known as “combined heat and
power” (CHP), cogen, district energy, total energy, and combined cycle, is the simultaneous production of heat (usually in the form of hot water and/or steam) and power, utilizing one primary
fuel such as natural gas, or a renewable fuel, such as Biomethane,
B100 Biodiesel, or Synthesis
Gas.
Cogeneration technology is not the latest industry buzz-word being touted as the solution to our nation's energy woes. Cogeneration is a proven technology that has been around for over 120 years!
Our nation's first commercial power plant was a
cogeneration
plant that was designed and built by Thomas Edison in 1882 in New York. Our
nation's first commercial power plant was called the "Pearl Street
Station."
What
is "Trigeneration"?
Trigeneration takes cogeneration one additional step. Trigeneration is defined as the simultaneous production of three forms of energy - typically, Cooling, Heating and Power - from only one fuel input. Put another way, our trigeneration energy systems produce three different types of energy for the price of one.
Our Trigeneration energy systems overall system efficiencies have exceeded 85% efficiency.
Typical "central" power plants that electric utility companies own and operate normally do not use the heat generated from the combustion and power generation process. Therefore, they are only about 30% to 35% efficient, wasting 65% to 70% of the available energy, that is simply wasted, and lost, with the heat going up their smokestacks.
Here is a trigeneration diagram that better reflects the trigeneration process:
Trigeneration
Diagram & Description
Trigeneration Power Plants' Have the Highest System Efficiencies and are
About 300 % More Efficient than Typical Central Power Plants
Trigeneration plants are installed at locations that can benefit from all three forms of energy. These types of installations that install trigeneration power plants are called "onsite power generation" also referred to as "decentralized energy."
One of our company's principal's first experience with the design and development of a trigeneration power plant was the trigeneration power plant installation at Rice University in 1987 where our trigeneration development team started out by conducting a "cogeneration" feasibility study. We installed a 4.0 MW Ruston gas turbine for the power plant. Rice University selected an EPC company that installed the trigeneration power plant, along with waste heat recovery boilers and absorption chillers. A "waste heat recovery boiler" captures the heat from the exhaust of the gas turbine. From there, the recovered energy was converted to chilled water - originally from (3) Hitachi Absorption Chillers - 2 were rated at 1,000 tons each, and the third Hitachi Absorption Chiller was rated at 1,500 tons. The Hitachi absorption chillers were replaced shortly after their installation by the EPC company. The first trigeneration plant at Rice University was so successful, they added a second 5.0 MW trigeneration plant so today, Rice University is now generating about 9.0 MW of electricity, and also producing the cooling and heating the university needs from the trigeneration plant and circulating the trigeneration energy around its campus.
Trigeneration Chart
Trigeneration's
"Super-Efficiency" compared
with other competing technologies
As you can see, there is No Competition for Trigeneration!
How
we make and distribute electricity is changing! The
electric power transmission and distribution system (the electric
"grid") is changing and evolving from the electric grid of the
19th and 20th centuries, which was inefficient, polluting, high-cost, and
“dumb” which resembles:
…..To the electric grid of the 21st century (see slide below) that will be
Decentralized, Smart, Efficient and provide “pollution
free power” to customers who remain on the
electric grid. The electric grid of the future will be comprised of
Onsite Power
Generation plants fueled with Biomethane,
B100 Biodiesel, Geothermal, Synthesis
Gas, Wind & Solar power - located at Residential, Commercial, Industrial
and City/Municipal Locations. Some customers will choose to dis-connect from the
grid entirely.
Typical "central" power plants and the electric utility companies that own them will either be shut-down, closed or go out of business due to one or more of the following: failed business model, inordinate expenses related to central power plants that are inefficient, excessive pollution/emissions, high costs, and failure to provide efficient, carbon free energy and pollution free power that reduces our dependence on foreign oil and makes us Energy Independent while reducing and eliminating Greenhouse Gas Emissions
Our
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.
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.
Call (832) 758 - 0027 for more information about community-based cogeneration and trigeneration power plants, or about making your community, hospital, university or other commercial facility a model for the future.
We presently contract the packaging of our new trigeneration power plants by a 3rd party/supplier but plan to build a new trigeneration manufacturing plant - near Houston, Texas where we will be able to significantly increase our trigeneration power plant production.
At about 86% to 93% net system efficiency, our 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. Our 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 our customers that have our trigeneration power plants have significantly lower energy expenses, and a lower carbon footprint.
Our smallest trigeneration power plant "basic" power plant starts at $600,000 for a 200 kW trigeneration system.
All of our trigeneration power plants can produce 20 - 42 degree F. chilled water, as well as steam and hot water while generating at least 200 kW of power. We can build trigeneration power plants up to 10 MW and with system efficiencies approaching 100%.
Read more about our Trigeneration Power Plants on our Specifications page.
Not sure what size trigeneration power plant to order or whether trigeneration is right for your business?
We can help!
Not sure what size trigeneration power plant to order or whether trigeneration is right for your business?
We can help as we offer three types of Trigeneration Feasibility Reviews & Studies!
Our Trigeneration Feasibility will help you make a decision whether one of our trigeneration power plants are right for your facility.
Trigeneration
Feasibility Study
and Analysis
Provides a solid basis for moving a potential renewable energy project forward. The cost for this depends on the type, location, amount of time we require, and any additional requirements that may be included by the client.
Generally, a trigeneration feasibility study a good option for clients considering trigeneration that need a trigeneration energy system that is over 1.0 MW and up to about 3.0 MW.
The time required to complete the study is about 90 to 120 days, on average.
The final study we deliver is usually the basis for the customer to obtain a loan, power purchase agreement, energy services agreement or placing an order with us.
To start a Trigeneration Preliminary Study and Analysis, we require a 50% cash payment of the study cost plus a refundable deposit for our reimbursable expenses.
Trigeneration
Detailed Concept,
Engineering and Design Analysis
The detailed engineering design is a good option for clients that would need a trigeneration energy system with an estimated Trigeneration energy system over 3.0 MW and above. In a detailed engineering design, the trigeneration energy system is conceived, designed and engineered as a custom fit and optimized energy solution for your specific facility.
Final result is usually ready for a company to start construction. A detailed engineering design can take from 4 months to 6 months to complete. The fee will generally run as a percentage of the total installed cost of the trigeneration energy system, and generally costs anywhere from 5% to 15% of the overall cost of the project.
To start a detailed trigeneration engineering design, we require a 50% cash payment of the total fee plus a refundable deposit for our reimbursable expenses.
Our trigeneration feasibility studies and engineering design are led by our licensed engineers. Our goal is to help you determine whether your renewable energy is viable, identify the merits of your proposed renewable energy project, identify weak points, provide our recommended course of action, as well as our recommendations for products and equipment that need further review or consideration. Our Feasibility Studies are an excellent "foundation" for building your next renewable energy project.
If you order your new trigeneration power plant from us within 30 days of the date of delivery of our Trigeneration Feasibility Review or Study, we will reduce the cost of your new trigeneration power plant by half the cost of the study and apply the fee to the purchase.
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 our trigeneration power plants surpass 90% net system efficiency.
This is possible through our trigeneration power plants that surpass 90% system efficiency for our clients that need cooling, heating and power - which covers about 99% of all commercial buildings and companies.
While most new trigeneration power plants are capable of being fueled with clean natural gas, we are dedicated to ending the use of fossil fuels by providing renewable energy and renewable fuels such as B100 Biodiesel or Biomethane. Simultaneously, we are focused on reducing and eliminating greenhouse gas emissions and carbon dioxide emissions.
In association with the Renewable Energy Institute, affiliate companies and investors, 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.
Trigeneration Technologies' trigeneration power plants' net system's efficiencies surpass any potential competitor. We guarantee our standard trigeneration power plants will exceed 90% net system efficiency.
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 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.
"The Trigeneration Experts" -
the ONLY Company that Builds Integrated Trigeneration
Plants on a Single Skid with Effective System Efficiencies that Exceed 90%.
Our
Optional SCR System Reduces Nitrogen Oxides To "Non-Detect"
Without Ammonia or Urea
Our
small footprint Trigeneration Plants
measurements are: 15' wide by 15' in height by and 55' in length
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:
200 kW
450 kW
750 kW
250 kW
500 kW
800 kW
300 kW
600 kW
850 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
are committed to excellence and exceeding our customers goals and objectives,
and will NOT use equipment from the following manufacturers:
Capstone microturbines
Daewoo engines
Kawasaki turbines
Guascor engines
in ANY of our cogeneration or trigeneration power plants.
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, Synthesis Gas and natural gas. Net system efficiencies of our Trigeneration power plants are now exceeding 90% with up to 95% lower emissions when using Biomethane, B100 Biodiesel, Dimethyl-Ether or Synthesis Gas as the fuel for Trigeneration power plants.
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
Read more about our Trigeneration Power Plants on our Specifications page.
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 our latest Cogeneration Plant Presently Being Built for New Customer.
This Cogeneration Plant is Rated at 900 kW and Features (2) Natural Gas Engines
@ 450 kW each on one Skid.
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
We would be interested in
meeting with potential joint venture partners who are as committed and
passionate as we are about making a difference in the world by assisting us with
the capital we need to begin mass-producing our +/- 90% efficient trigeneration
power plants which will soon be located on the roof (or next to the building) of
every commercial business - such as restaurants, office buildings,
supermarkets/grocery stores, hospitals, casinos, universities, dairies, data
centers and server farms.
Equity positions now available for qualified joint venture partners in multiple trigeneration projects we are seeking to develop with leading Fortune 1000 companies. Our joint venture equity partners will assist us with manufacturing our cogeneration or trigeneration plants and start installing them on the roof-tops or next to our customer's facilities - pending orders from hospitals and restaurants who have agreed to purchase all of our energy generated from our trigeneration plants through our Energy Services Agreement (similar to a Power Purchase Agreement except in the case of an Energy Services Agreement, we also sell the hot water/steam and chilled water, in addition to the electricity our trigeneration plants generate).
Our
trigeneration plants will;
* forever change the way that energy is generated and used.
* will be fueled with "green fuels" such as; Biomethane, B100 Biodiesel, Synthesis Gas (generated from biomass feedstock and "converted" through Biomass Gasification plants), Dimethyl Ether or Solar Energy.
* eliminate or greatly reduce our customer's electric demand charges.
* significantly increase the amount of renewable energy used in the U.S. and
around the world when renewable fuels such as Biomethane,
B100 Biodiesel, Synthesis
Gas or Dimethyl Ether
* stop/reverse climate change by reducing greenhouse gas emissions and
carbon dioxide emissions.
* reduce and eventually eliminate the use of "fossil fuels."
*
reduce the need for inefficient and expensive central power plants owned by
utility companies.
* promote energy independence.
* end America's dependence on oil from OPEC and other countries in the Middle-East, Venezuela and end our need for importing natural gas from Russia.
Prospective joint venture partners are invited to send an introductory email regarding your interests in renewable energy along with your financial abilities and expectations to: info@Trigeneration.com
More information and background on cogeneration
Primary fuels commonly used in cogeneration include natural gas, oil, diesel fuel, propane, coal, wood, wood-waste and bio-mass. These "primary" fuels are used to make electricity, a "secondary" fuel. This is why electricity, when compared on a btu to btu basis, is typically 3-4 times more expensive than primary fuels such as natural gas.
An example of a cogeneration process would be the automobile in which the primary fuel (gasoline) is burned in an internal combustion engine - this produces both mechanical and electrical energy (cogeneration). These combined energies, derived from the combustion process of the car's engine, operate the various systems of the automobile, including the drive-train or transmission (mechanical power), lights (electrical power), air conditioning (mechanical and electrical power), and heating of the car's interior when heat is required to keep the car's occupants warm. This heat, which is manufactured by the engine during the combustion process, was “captured” from the engine and then re-directed to the passenger compartment.
Due to competitive pressures to cut costs and reduce emissions of air pollutants and greenhouse gasses, owners and operators of industrial and commercial facilities are actively looking for ways to use energy more efficiently. One option is cogeneration, also known as combined heat and power
(CHP). Cogeneration/CHP is the simultaneous production of electricity and useful heat from the same fuel or energy. Facilities with cogeneration systems use them to produce their own electricity, and use the unused excess (waste) heat for process steam, hot water heating, space heating, and other thermal needs. They may also use excess process heat to produce steam for electricity production. Cogeneration currently coexists with a regulated industry that is going through major structural changes that may limit or expand its application.
Cogeneration and
The concept of cogeneration is not
new, as we discussed previously. Early in this century, before there was an extensive network of power lines, many industries had cogeneration plants. As utilities became established and grew, most states began to regulate them in order to limit their pricing power. The Public Utilities Holding Act of 1935
(PUHCA), together with amendments to the Federal Power Act (also in 1935), were the final steps in protecting utility companies from competition. These laws created vertically integrated utilities with responsibility for the production, transmission, and distribution of power. In exchange for their exclusive franchises (territories) and guaranteed revenues, utilities agreed to government regulation of rates and service. Under these rules, more investments in infrastructure and more sales meant more profits. As the network of power lines grew and electricity from utilities became more economical, industrial facilities bought more of their electricity from utilities. However, many industries still had to generate process heat on-site. The economies of scale that the utilities were able to obtain at that time, as well as the availability of low-priced process heat from cheap oil and gas, removed incentives to retain cogeneration equipment.
In the past three decades, however, the long-term trend of energy prices generally moved upward. Building more and more large power plants no longer provided economies of scale. This was a major factor in the increasing use of cogeneration by commercial and industrial facilities.
The Public Utilities Regulatory Policies Act of 1978 (PURPA) provided further encouragement for developers of cogeneration plants. Section 210 required utilities to purchase excess electricity generated by "qualified facilities"
(QFs) and to provide backup power at a reasonable cost. QFs included plants that used renewable resources and/or cogeneration technologies to produce electricity. PURPA cogenerators must use at least 5% of their thermal output for process or space heating (10% for facilities that burn oil or natural gas). In many cases, this forced independent cogenerators to accept very low rates for their steam production in order to become a qualified facility under
PURPA. Another problem is the rate at which utilities purchase a cogenerator’s excess power production.
Most states set the price at "avoided cost," or the cost to the utility of producing that extra power. Utilities with excess power generation capacity are often allowed to have extremely low avoided costs. This practice has created artificial barriers to cogeneration as well as to independent power generators.
The Energy Policy Act of 1992 (EPAct) tried to create a more competitive marketplace for electricity generation. It created a new class of power generators known as Exempt Wholesale Generators
(EWGs). These are exempt from PUHCA regulation and can sell power competitively to wholesale customers. A cogeneration facility can be (but does not have to be) a QF under PURPA and an EWG under
EPAct. This happens when the facility is in the exclusive business of wholesale power sales, and makes no retail power sales to its "steam host" (customer).
Cogeneration Technology
A typical cogeneration system consists of an engine, steam turbine, or combustion turbine that drives an electrical generator. A waste heat exchanger recovers waste heat from the engine and/or exhaust gas to produce hot water or steam. Cogeneration produces a given amount of electric power and process heat with 10% to 30% less fuel than it takes to produce the electricity and process heat separately.
There are two main types of cogeneration concepts: "Topping Cycle" plants, and "Bottoming Cycle" plants. A topping cycle plant generates electricity or mechanical power first. Facilities that generate electrical power may produce the electricity for their own use, and then sell any excess power to a utility. There are four types of topping cycle cogeneration systems. The first type burns fuel in a gas turbine or diesel engine to produce electrical or mechanical power. The exhaust provides process heat, or goes to a heat recovery boiler to create steam to drive a secondary steam turbine. This is a combined-cycle topping system. The second type of system burns fuel (any type) to produce high-pressure steam that then passes through a steam turbine to produce power. The exhaust provides low-pressure process steam. This is a steam-turbine topping system. A third type burns a fuel such as natural gas, diesel, wood, gasified coal, or landfill gas. The hot water from the engine jacket cooling system flows to a heat recovery boiler, where it is converted to process steam and hot water for space heating. The fourth type is a gas-turbine topping system. A natural gas turbine drives a generator. The exhaust gas goes to a heat recovery boiler that makes process steam and process heat. A topping cycle cogeneration plant always uses some additional fuel, beyond what is needed for manufacturing, so there is an operating cost associated with the power production.
Bottoming cycle plants are much less common than topping cycle plants. These plants exist in heavy industries such as glass or metals manufacturing where very high temperature furnaces are used. A waste heat recovery boiler recaptures waste heat from a manufacturing heating process. This waste heat is then used to produce steam that drives a steam turbine to produce electricity. Since fuel is burned first in the production process, no extra fuel is required to produce electricity.
An emerging technology that has cogeneration possibilities is the fuel cell. A fuel cell is a device that converts hydrogen to electricity without combustion. Heat is also produced. Most fuel cells use natural gas (composed mainly of methane) as the source of hydrogen. The first commercial availability of fuel cell technology was the phosphoric acid fuel cell, which has been on the market for a few years. There are about 50 installed and operating in the United States. Other fuel cell technologies (molten carbonate and solid oxide) are in early stages of development. Solid oxide fuel cells
(SOFCs) may be potential source for cogeneration, due to the high temperature heat generated by their operation.
Cogeneration Applications
Cogeneration systems have been designed and built for many different applications. Large-scale systems can be built on-site at a plant, or off-site. Off-site plants need to be close enough to a steam customer (or municipal steam loop) to cover the cost of a steam pipeline. Industrial or commercial facility owners can operate the plants, or a utility or a non-utility generator (NUG) may own and operate them. Manufacturers use 90% of all cogeneration systems. Some industries and waste incinerator operators who own their own equipment realize sizable profits with cogeneration.
Another large-scale application of cogeneration is for district heating and cooling. Many colleges, hospitals, office buildings and even cities, that have extensive district heating and cooling systems, have at their core, a cogeneration or trigeneration power plant. The University of Florida has a 42 Megawatt (MW) gas turbine cogeneration plant, built in partnership with the Florida Power Corporation. Some large cogeneration facilities were built primarily to produce power. They produce only enough steam to meet the requirements for qualified facilities under PURPA. If no steam host is nearby, one can be built. For example, there are large (80 MW) plants operating under PURPA that have large greenhouses as "steam hosts." The greenhouses operate without losing money only because their steam heat is virtually free of charge. These types of plants are candidates to become EWGs in the new regulatory environment.
Many utilities have formed subsidiaries to own and operate cogeneration plants. These subsidiaries are successful due to the operation and maintenance experience that the utilities bring to them. They also usually have a long-term sales contract lined up before the plant is built. One example is a 300 MW plant that is owned and operated by a subsidiary co-owned by a utility and an oil company. The utility feeds the power directly into its grid. The oil company uses the steam to increase production from its nearby oil wells.
Cogeneration systems are also available to small-scale users of electricity. Small-scale packaged or "modular" systems are being manufactured for commercial and light industrial applications. Modular cogeneration systems are compact, and can be manufactured economically. These systems, ranging in size from 20 kilowatts (kW) to 650 kW produce electricity and hot water from engine waste heat. It is usually best to size the systems to meet the hot water needs of a building. Thus, the best applications are for buildings such as hospitals or restaurants that have a year-round need for hot water or steam. They can be operated continuously or only during peak load hours to reduce peak demand charges, although continuous operation usually has the quickest payback period.
Several companies also attempted to develop systems that burn natural gas and fuel oil for private residences. These home-sized cogeneration packages had a capacity of up to 10 kW, and were capable of providing most of the heating and electrical needs for a home. As of May 2000, none of the companies that developed these systems are selling these units. Several fuel call manufacturers are targeting residential and small commercial applications.
Environmental Issues
While cogeneration provides several environmental benefits by making use of waste heat and waste products, air pollution is a concern any time fossil fuels or biomass are burned. The major regulated pollutants include particulates, sulfur dioxide (SO2), and nitrous oxides (NOx). Water quality, while a lesser concern, can also be a problem. New cogeneration plants are subject to an Environmental Protection Agency (EPA) permit process designed to meet National Ambient Air Quality Standards (NAAQS). Many states have stricter regulations than the EPA. This can add significantly to the initial cost of some cogeneration facilities located in urban areas.
Some cogeneration systems, such as diesel engines, do not capture as much waste heat as other systems. Others may not be able to use all the thermal energy that they produce because of their location. They are therefore less efficient, and the corresponding environmental benefits are less than they could be. The environmental impacts of air and water pollution and waste disposal are very site-specific for cogeneration. This is a problem for some cogeneration plants because the special equipment (water treatment, air scrubbers, etc.) required to meet environmental regulations adds to the cost of the project. If, on the other hand, pollution control equipment is required for the primary industrial or commercial process anyway, cogeneration can be economically attractive.
Even the environmental groups are on the cogeneration bandwagon. Since its' founding, the Sierra Club has supported total energy (cogeneration). See the Sierra Club's statement on energy policy.
Cogeneration and Future Market Development
Several factors will affect the growth of cogeneration activities. They include the initial cost of buying and bringing a cogeneration system on-line, maintenance costs, and environmental control requirements. Some electric utilities do not need additional electricity. They may have excess generation capacity or a stable customer base. This leads to lower "avoided cost" rates, which reduces the viability of cogeneration projects that rely heavily on power sales to utilities.
The restructuring of the electric power generation and distribution industry that is currently underway in many states, makes it more attractive for developers to become independent power producers and to build "electricity only" power plants, instead of cogeneration plants. There has also been a great deal of pressure from utility and industrial special interests to repeal or amend PURPA.
If they are successful, it could be difficult for new cogeneration projects to get off the ground. Barring that development, improved technology and cooperation among industries, businesses, utilities, and financiers should provide impetus to the continued development of both cogeneration projects and independent power production projects.
One significant impetus for cogeneration is the issue of global climate change from global warming caused by the greenhouse effect, of which fossil fuel combustion is a major contributor.
Cogeneration is the environmentally-friendly, economically-sensible way to produce power, simultaneously saving significant amounts of money and also dramatically reducing total greenhouse gas emissions.
____________________________________________________________________________________
EPA Moves Closer To Regulating Greenhouse
Gas Emissions
April 18, 2009
By: Webmaster
www.CarbonDioxideEmissions.com
www.CarbonEmissions.com
www.GreenhouseGasEmissions.com
WASHINGTON — In a major reversal of years of government policy regarding Greenhouse
Gas Emissions, the Environmental Protection Agency today proposed regulating
Greenhouse Gas Emissions to
combat and reverse global warming and climate change.
"In both magnitude and probability, climate change is an enormous problem" said E.P.A's Administrator Lisa Jackson in their 130 page report on Greenhouse Gas Emissions. "This finding confirms that greenhouse gas pollution is a serious problem now and for future generations. Fortunately, it follows [US President Barack H. Obama's] call for a low-carbon economy and strong leadership in Congress on clean energy and climate legislation. Greenhouse Gas Emissions and greenhouse gas pollution problems have a solution, one that will create millions of green jobs and end our country's dependence on foreign oil," according to Jackson.
Jackson said this report found that projected levels of Greenhouse Gas Emissions "endanger the public health and welfare of current and future generations." The finding came two years after the Supreme Court ruled the EPA had the authority to regulate Greenhouse Gas Emissions under the Clean Air Act.
"Renewable Energy Technologies such as; Anaerobic Digesters, Biomethane, Concentrating Solar Power, Geothermal Power Plants are "carbon neutral energy" technologies, and generate no new Greenhouse Gas Emissions. Power generated from Biomass Gasification power plants, are "carbon negative energy" solutions which actually remove carbon dioxide emissions from the atmosphere, according to the Founder and Chairman of the Institute for Climate Solutions, and the Renewable Energy Institute's Mont Goodell.
For
more information, see the Greenhouse
Gas Emissions website at: www.GreenhouseGasEmissions.com
____________________________________________________________________________________
President-elect Obama has pledged to significantly reduce Greenhouse Gas Emissions.
The price tag for reducing Greenhouse Gas Emissions ranges from a low of $150 billion to a high of over $1 Trillion/year, every year, for the next 20 years, plus an additional $9.3 Trillion according to the article “Is Obama’s Energy Plan Enough?” by Time Magazine (Nov. 22, 2008)
http://www.time.com/time/health/article/0,8599,1859040,00.html?imw=Y
In the third to last paragraph of this article, it states, “And if we want to increase the share of renewables — and control the growth of greenhouse gas emissions — we'll need to spend an additional $9.3 trillion, if we're aiming to stay below the 2 degree C warming max recommended by the Intergovernmental Panel on Climate Change. (Of course, an increasing number of scientists argue that we need to avoid even that level of warming.) "We would need concerted action from all major emitters," said Nabuo Tanaka, the head of the IEA.
The United Nations has stated that “the market for Greenhouse Gas Emissions Credits will be valued at $2 Trillion by 2012.”
____________________________________________________________________________________
Our
cogeneration or trigeneration
energy systems will;
* forever change the way that energy is generated and used.
* will be fueled with "green fuels" such as; Biomethane, B100 Biodiesel, Synthesis Gas (generated from biomass feedstock and "converted" through Biomass Gasification plants), Dimethyl Ether or Solar Energy.
* eliminate or greatly reduce our customer's electric demand charges.
*
significantly increase the amount of renewable energy used in the U.S. and
around the world when renewable fuels such as Biomethane,
B100 Biodiesel, Synthesis
Gas or Dimethyl Ether
* stop/reverse climate change by reducing greenhouse
gas emissions and carbon
dioxide emissions.
* reduce and eventually eliminate the use of "fossil fuels."
*
reduce the need for inefficient and expensive central power plants owned by
utility companies.
* promote energy independence.
* end America's dependence on oil from OPEC and other countries in the Middle-East, Venezuela and end our need for importing natural gas from Russia.
Prospective joint venture partners are invited to send an introductory email regarding your interests in renewable energy along with your financial abilities and expectations to: info@Trigeneration.com
____________________________________________________________________________________
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.
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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.
--------------------------------------------------------------------------------
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.
