Climate Challenge - Climate Challenge Options Workbook

Management of Supply Assets to Reduce, Avoid, or Sequester Greenhouse Gases

A utility's decisions regarding the use of generation facilities will ultimately affect its overall emissions profile. These decisions can be programmatic and long-term, or more discrete and shorter-term, and could result in an overall reduction of the utility's greenhouse gas emissions. Examples include:

Performance incentives related to productivity of people and/or hardware (e.g., heat rate and capacity factor targets) and other administrative or procedural initiatives leading to improved operating performance and lower emissions;

Resource decisions involving application of financial and human resources in such a way as to maximize availability of more efficient, lower-emitting units;

Energy supply decisions based on an IRP process that includes greenhouse gas considerations; and

Preferential dispatch of generation sources that emit lower levels of greenhouse gases when such resource options otherwise have equivalent cost.

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Barriers:

Decisions that prove to be costly will adversely affect a utility's competitive position.
Ratemaking is directed towards least-cost planning. Recovery of costs in rates for reduced or least emissions dispatch is uncertain.
Price shock on customers. Many industrial and commercial customers which use large quantities of electricity will incur harm from higher rates. Regional productivity will be negatively affected, with potential for lay-offs.
Preferential dispatch increases the risk of stranded investment for higher-emitting facilities with remaining useful economic life.
Preferential dispatch may conflict with established policies for best economic dispatch in powerpools or other regional authorities.
Unemployment and other negative social and economic impacts associated with reduced utilization of high-carbon fossil-fueled plants (unemployment in the mining sector, decline in transportation volume and other activities associated with use of generation facilities).
In some states the costs associated with management of supply assets in a manner other than least-cost consideration may be borne by stockholders while the benefits are passed through to ratepayers. The success of management efforts consistent with this option is uncertain.

Solutions:

Make information available for utility use to facilitate favorable management decisions incorporating the above-described considerations.
Provide ratemaking incentives for implementation of programs designed to improve the performance of existing supply assets.
Allow the marketplace to establish preferences for dispatch as utilities implement their plans to reduce, avoid, or sequester greenhouse gases on a voluntary basis.

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Option Category:

Other

Forestry Carbon Management Projects

Carbon dioxide and other greenhouse gases can be managed through many different types of forestry activities:

forest preservation and management projects to reduce CO2 emissions and maintain sequestered carbon by reducing deforestation and harvest impacts;

forest management to enhance existing carbon sinks (e.g., fertilization);

creation of new carbon sinks by planting on former mine sites, pasture, agricultural land, buffer zones at industrial sites and power plants or degraded forest sites;

storing carbon in wood products; and

trees shading buildings and homes, as well as serving as windbreaks, reduce air conditioning needs, fossil fuel use, and CO2 emissions.

The CCAP includes three initiatives to address greenhouse gases through forestry: CCAP Action #9 - Cool Communities program; CCAP Action #43 - Reduce the Depletion of Nonindustrial Private Forests; and CCAP Action #44 - Accelerate Tree Planting in Nonindustrial Private Forests.

A single sequestration project might offset millions of tons of carbon emissions over its lifetime. Preliminary information indicates that some measures have a relatively low cost per ton of carbon sequestered, especially when conducted outside the U.S. Secondary environmental and social benefits often result from some of these projects.

As discussed in the biomass generation section, wood or other biomass can be turned into a carbon offset through its conversion to energy if it is used in lieu of fossil fuel. Net CO2 emissions are effectively zero for a system where CO2 released during biomass combustion is simultaneously sequestered by the next energy crop.

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Barriers:

Uncertainty at the state level regarding how forest carbon management projects will be treated by regulators.
Office of Surface Mining regulations result in economic and other disincentives to tree planting on surface mine lands.
Competition for land use.
Many barriers exist to using trees for bioenergy e.g., agricultural subsidies encourage traditional crops.
Limited information regarding costs.
CCAP Actions #43 and #44 are limited to forests less than 1,000 acres or 5,000 acres with special Secretarial permission.

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Solutions:

Support information exchange programs.
Develop information regarding state regulatory treatment, costs and benefits of different projects, availability of financial assistance, etc.

Industry-proposed solutions requiring legislative, policy, or regulatory action.

Eliminate barriers such as in the federal surface mine reclamation regulations.
Reconsider land use policy (e.g., USDA's Conservation Reserve Program and agricultural subsidies).
Remove limits of size of woodlands eligible for CCAP Actions #43 and #44.

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Partnerships:

DOE, USDA (including US Forest Service), EPA, DOS, DOI (Office of Surface Mining), state regulatory commissions and agencies, cooperative forestry agencies, environmental non-governmental organizations (NGOs), professional forestry associations, farmers and farmers' associations, recycling and solid waste organizations, Utility Biomass Energy Commercialization Association, EPRI, National Wood Energy Association.

Case Studies:

The utility industry has a long history of involvement with forest management and tree-planting programs, through preserving forest lands for both recreation use and wildlife habitat, tree maintenance around power lines, education of homeowners on tree placement in order to minimize service interruptions from line interference, and commercial forestry on utility-owned lands. Recently, utilities have initiated numerous forestry projects to conserve energy and to offset CO2 emissions.

Utility companies are involved in American Forests' Global ReLeaf and EPA/American Forests' Cool Communities programs. The CCAP calls for DOE to expand the Cool Communities program by 250 new cities (compared to seven now) and 100 federal facilities over a 10-year period. In each city DOE will seek to sign agreements with a sponsoring utility.
New England Electric Power Company (NEES) and PacifiCorp have initiated forest carbon management efforts. In Oregon, PacifiCorp is experimenting with reforesting rural pasture land with Douglas fir through an agreement with landowners to maintain trees for 45 to 65 years. PacifiCorp is also involved with projects to reforest fire-damaged lands in Washington and Idaho, and a tree planting project in Russia. NEES is engaged in a project designed to reduce CO2 released during the logging process in Malaysia. Elements of the project include improved siting of logging trails, directional felling of trees, and vine removal prior to harvest, all intended to decrease damage to undergrowth and unharvested trees during the logging process, thereby decreasing CO2 released to the atmosphere as well as facilitating regeneration of the forest.
The APPA's Tree Power Program has a goal of planting 16 million trees, one for each public power customer.
Applied Energy Services Corp. is undertaking carbon management projects in Guatemala, Paraguay, and elsewhere in South America. Tenaska Inc. plans to plant trees in Washington State and protect tropical rain forests in Costa Rica.
Electric utility organizations in other nations are sponsoring or considering such programs. In the Netherlands, the Dutch Electricity Generating Board has established the Forest Absorbing Carbon Dioxide Emission (FACE) foundation at an annual cost of over $10 million over the next 25 years. An internal report of Japan's Central Research Institute of the Electric Power Industry recommends establishment of a program to manage carbon via forestry.
Metropolitan Edison (Met Ed) has been promoting a variety of tree replacement programs for several years. One such program targets street trees growing under distribution conductors. Met Ed's "Municipal Tree Replacement Program" (MTRP) is a joint undertaking of the utility, participating municipalities, and Pennsylvania State University (PSU).
The Utility Forest Carbon Management Program (UFCMP) is an initiative developed by the EEI for Climate Challenge participants and other utilities. It establishes a coordinated electric utility plan to manage CO2 and other greenhouse gases through different forestry activities. The goal of the UFCMP is to identify, evaluate, and implement forest carbon management projects. Potential projects will be identified from Federal, state, and private entities. Projects will be carefully evaluated and the most promising will be considered for support.

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Option Category:

Other

Agricultural Greenhouse Gas Management Projects

Carbon dioxide and other greenhouse gas emissions can often be managed through the variety of agricultural activities which utilities and their customers engage in, such as:

planting trees and shrubs as wind breaks and shelterbelts which reduce energy usage;

conservation tillage to reduce soil disturbance and maintain higher soil carbon and nitrogen content;

improving efficiency of fertilizer and pesticide use, reducing energy usage during their manufacture and transportation;

reducing post-application fertilizer nitrogen emissions by changing application rate, placement, and timing;

creation of new carbon sinks by planting halophytes (salt-tolerant plants) on otherwise unproductive desert coastal lands;

recovering and using methane for on-farm power production (see "Animal Manure Methane Energy Recovery" option); and

reduced methane emissions from ruminants (i.e., cattle) through improved nutrition and other management practices.

The CCAP includes four initiatives to address greenhouse gases through agriculture: CCAP Action # 17 - Improve Efficiency of Fertilizer Nitrogen Use; CCAP Action # 18 - Reduce Pesticide Use; CCAP Action # 38 - Expand AgStar Partnership Program with Livestock Producers; and CCAP Action #39 - Improve Ruminant Productivity and Product Marketing.

Woody or non-woody biomass (e.g., trees, switchgrass, halophytes) can be turned into a carbon offset through its conversion to energy if used in lieu of fossil fuel. Net CO2 emissions are effectively zero for a system where CO2 released during biomass combustion is simultaneously sequestered by the next energy crop.

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Barriers:

Uncertainty at the state level regarding how carbon management projects will be treated by regulators.
Competition for land use.
Many barriers exist to bioenergy crops e.g., agricultural subsidies encourage traditional crops.

Solutions:

Develop information regarding state regulatory treatment, international project considerations, costs and benefits of different projects, availability of financial assistance, etc.
Support efforts to reconsider land use policy (e.g., USDA's Conservation Reserve Program and agricultural subsidies).

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Partnerships:

DOE, USDA (including US Forest Service), EPA, state regulatory commissions and agencies, cooperative forestry agencies, environmental non-governmental organizations, professional farmers' associations, recycling and solid waste organizations, Utility Biomass Energy Commercialization Association, EPRI, and the National Wood Energy Association.

Case Studies:

Baltimore Gas & Electric and other utilities own and operate farms.
American Electric Power manages large tracts of marginal and prime agricultural cropland.
Salt River Project and the EPRI are sponsoring a research project using halophytes, plants that grow in salty soil or can be irrigated with brackish water, to sequester carbon.
Tennessee Valley Authority has extensive experience with nitrogen fertilizers.
Mesquite Lake Resource Recovery Project in El Centro California burns up to 40 tons of cattle manure per hour.

METHANE MANAGEMENT AND USE

The management and use of methane can significantly reduce the overall emission of greenhouse gases. There are a variety of ways that utilities can reduce emissions of methane. Four options of methane reduction are presented here: Coal Mine Methane Recovery, Landfill Methane Energy Recovery, Reduce Emissions of Natural Gas, and Animal Manure Methane Energy Recovery.

Coalbed methane can be a significant source of natural gas, both for use in pipelines and where pipeline construction is not practical, or gas quality is low, on-site generation of electricity or other process uses.

Capture and use of landfill methane as fuel for electricity generation is done through the development of well fields and collection systems at the landfill. Collected methane can be used for on-site power generation or pipelined to a nearby existing generating station. Where electric generation is impractical, flaring is preferred over direct venting to reduce emissions and fire hazards.

Utilities can encourage their natural gas suppliers to use "Best Management Practices" to reduce emissions associated with the production and transmission of the natural gas they purchase. In addition, utilities that distribute natural gas can agree to undertake a variety of actions to reduce the methane emissions associated with natural gas distribution systems.

Utilities can work with livestock producers to reduce overall emissions of methane form manure management systems by collecting the methane for electricity generation or on-farm fuel. Utilities can also encourage livestock producers to participate in the AgSTAR program.

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Option Category:

Other - Methane Management and Use

Coal Mine Methane Recovery

Description:

Coalbed methane can be collected by the mine operator or by a project developer before, during or after mining occurs, and the recovered gas can then be used to generate electricity, as a fuel for nearby industrial purposes, or sold to gas pipelines. These projects can result in significant greenhouse gas emission reductions. For example, a project at four mines in Alabama is reducing emissions by 1.5 million metric tons of carbon equivalent annually, through the sale of 13 billion cubic feet of methane each year to a natural gas pipeline.

Currently, there are at least eleven U.S. mines that produce coalbed methane in conjunction with coal mining and sell it to pipelines. However, at least another twenty mines collect medium-to high-quality methane in order to mine their coal safely and then vent this methane to the atmosphere. These mines represent opportunities for utilities to work with the mine operators to develop a use strategy for the gas that is already being recovered. Utilities may also be able to participate in projects at coal mines that are not currently recovering any methane in conjunction with mining, by implementing projects that include both gas recovery and utilization.

EPA is implementing the Coalbed Methane Outreach Program, designed to identify attractive project opportunities at the gassiest coal mines in the United States and to remove barriers to implementation. The program is focused primarily on opportunities at the 75 gassiest mines in the United States. DOE is implementing a complementary R&D program to advance the state-of-the-art in methane recovery and use technologies.

Barriers:

Lack of information about the importance of recovering the methane liberated by coal mines, which has traditionally been viewed solely as a safety hazard in mining because it is highly explosive.

Difficulty financing projects, due to the preference of coal companies for investments in core coal mining improvements.

Restricted markets for recovered gas, due to low need for additional electricity capacity in key coal mining regions and constrained pipeline capacity throughout the Appalachian region.

Uncertain coalbed methane ownership.

Cost for establishing methane collection systems maybe high. Power generation (cost per MWh) may not be competitive with alternative energy sources.

Difficult to quantify methane not emitted due to a methane management action.

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Solutions:

Obtain information on specific project opportunities, available technologies, and other key issues from EPA's Coalbed Methane Outreach Program. Review information contained in EPA's "Profiles of the Gassiest U.S. Coal Mines," to identify attractive projects.
Work with major coal suppliers (or other companies and mines) to develop projects that reduce methane emissions.
Work with state agencies to raise awareness of the coalbed methane resource and support the development of programs and policies that can encourage projects.
Publicize actions taken at the state and Federal levels in response to [[section]] 1339 of the EPAct, which addresses uncertain coalbed methane ownership.
Support research, development, and cost-shared demonstration projects of new coal mine methane gas gathering and utilization technologies.

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Partnerships:

EPA, DOE, EPRI, National Coal Association, other electric utilities and power producers, coal companies.
EPA Coalbed Outreach Program Manager, Dina Kruger, (202) 233-9039.

Case Studies:

Jim Walter Resources of Brookwood AL. Since the early 1980s, Jim Walter Resources has recovered methane from four coal mines in Alabama. Each year, about 13 Bcf of high-quality methane is produced from a variety of mine degasification approaches and sold to a nearby pipeline. This program has reduced mining costs by more than $1/ton and enabled the continued economic operation of the coal mines, in addition to resulting in significant methane emission reductions.
Consolidation Coal Co (Consol) in Buchanan County, VA. Beginning in 1993, Consol initiated a methane recovery program at its Buchanan mine and four mines formerly owned by Island Creek Coal Co. The company built a 40-mile pipeline to market the methane and currently sells more than 20 Bcf annually.
Soldier Canyon Mine in Price, UT. This mine has had a methane recovery project since the mid 1980s. Using only in-mine methane recovery methods, more than 2 Bcf of methane is recovered annually and sold to a pipeline.
Waste gases have been successfully utilized from a sealed mine to supply electric generation in Cambria County, Pennsylvania.

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Option Category:

Other - Methane Management and Use

Landfill Methane Energy Recovery

Description:

The recovery and use of methane from landfills can significantly reduce the overall emissions of greenhouse gases. Landfills are the largest anthropogenic source of methane in the U.S. They currently represent 36 percent of the total methane emissions associated with human activities. There are a variety ways that utilities can reduce overall emissions of methane from landfills. Landfill methane can be collected by developing gas recovery systems, and it can then be used to generate electricity, as a fuel for nearby industrial purposes, or enriched and sold to gas pipelines.

Currently, there are more than 100 landfill methane energy recovery projects in the U.S., which avoid emissions of over 50 billion cubic feet of methane per year. The approximately 85 projects that generate electricity constitute over 300 MW of electric capacity. Recent studies by EPA and EPRI estimate that up to 750 U.S. landfills could profitably recover and use the methane they are currently generating.

EPA is expanding its Landfill Methane Outreach Program, which identifies attractive project opportunities and removes barriers to their implementation. The program will have a State Ally component, in which EPA and various state agencies work together to encourage landfill methane recovery projects where appropriate and to remove the barriers to project development. The expanded program will also have a Utility Ally component, in which EPA and utilities sign a Memorandum of Understanding (MOU). Under the MOU, the Utility Ally commits to develop a strategy for encouraging landfill methane recovery projects where appropriate and EPA commits to provide technical information and support, including detailed information on candidate sites, workshops, as well as public recognition. DOE is implementing a complementary R&D program to develop and demonstrate new state-of-the-art approaches for methane recovery and use at landfills.

Barriers:

Lack of information on available technologies and attractive project sites for methane recovery at landfills.

Permitting and other regulatory hurdles, including complex air emission requirements and treatment of landfill gas condensate.

Perception of high risk associated with landfill gas recovery projects.

Size of landfill needed to produce enough methane for economic generation (about 1 million cubic yards of solid waste is needed for a 1 to 3 MW system).

Cost for establishing methane collection systems maybe high. Power generation (cost per MWh) may not be competitive with alternative energy sources.

Uncertainty of obtaining long-term landfill methane rights.

Air emissions requirements and disposal of condensate created.

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Solutions:

Participate as a Utility Ally in EPA's Landfill Methane Outreach Program.
Work with state agencies to raise awareness of the landfill methane resource and develop programs and policies that can encourage projects.
For investor-owned utilities, take advantage of landfill methane eligibility for [[section]] 29 of the Internal Revenue Code, Non-conventional Gas Tax Credit, and for publicly-owned utilities, take advantage of EPAct [[section]] 1212, Renewable Energy Production Incentive to enhance the economic viability of recovery projects.
Contact EPA's Landfill Methane Outreach Program Project Hotline, (202) 233-9092, with information on barriers that arise in the development of projects, so that the Outreach Program can focus attention on addressing these barriers.
Obtain copies of EPA's Landfill Methane Outreach Program materials, which include profiles of landfill recovery project opportunities in key states, information on available incentives for landfill methane recovery projects, and guidance on available technologies, applicable regulations, etc.

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Partnerships:

EPA, DOE, NSWMA, SWANA, EPRI, EEI, APPA, NRECA, landfill methane energy recovery developers, and landfill owners and operators.
EPA, Landfill Methane Outreach Program-Utility Ally Manager, Nabilah Haque, (202) 233-9758.

Case Studies:

I-95 Sanitary Landfill in Fairfax Country, VA. The I-95 landfill collects 3.3 mmcfd of landfill gas and uses 8 internal combustion engines to produce 6 MW of electricity for sale to Virginia Power. The gas recovery system is controlled by Fairfax Country, and the energy recovery facility is owned and operated by the energy recovery developer.
Mountaingate Facility, Los Angeles, CA. This landfill is now closed, but the gas recovery system still collects 5 mmcfd of landfill gas, which is piped to UCLA, 4.5 miles away. UCLA currently uses the gas in its steam plant for annual savings of about $400,000. UCLA is in the process of developing a 47 MW gas turbine cogeneration plant, which will use the landfill gas.
Emerald People's Utility District (EPUD), Eugene, OR. EPUD worked with Lane County, OR and a private investment company to develop a 3.4 MW plant at the Short Mountain Landfill.
Los Angeles Department of Water & Power landfill methane recovery.
Tennessee Valley Authority landfill methane recovery.
Winnebago County, Wisconsin, 2 MW landfill unit.
New England Power's (NEES) "Green RFP" selected four landfill methane projects for development.
NEES landfill methane recovery for electricity generation project purchases at Johnston, RI (R.I. Central Landfill) and Rochester, NH.
Minnesota Methane, a partnership between a Northern States Power subsidiary and a Caterpillar equipment distributor (Ziegler), is using recovered landfill gas as fuel for generation projects. Current projects total over 6 MW, with several other projects being developed.

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Option Category:

Other - Methane Management and Use

Reduce Emissions of Natural Gas

Description:

Utilities can encourage their natural gas suppliers to use "Best Management Practices" to reduce emissions associated with the production and transmission of the natural gas they purchase. In addition, utilities that distribute natural gas can undertake a variety of actions to reduce the methane emissions associated with natural gas distribution systems.

To support reductions of methane emissions from U.S. natural gas systems, EPA has created the Natural Gas STAR program, part of the CCAP. Under this voluntary program, gas distribution, transmission, and production companies sign a Memorandum of Understanding (MOU) with EPA. By signing the MOU, Natural Gas STAR partners agree to review and implement cost-effective "best management practices" as appropriate. Best Management Practices currently include, for example, rehabilitation or replacement of leaky distribution pipe and directed inspection and maintenance at surface facilities. EPA's commitment to Natural Gas STAR partners includes implementation support through workshops and training courses, analysis of emerging technologies and practices that can reduce methane emissions, elimination of regulatory barriers and public recognition for participating companies. Natural Gas STAR has been endorsed by the American Gas Association and the Gas Research Institute.

Barriers:

Lack of information about emission rates from various parts of the natural gas system and the available technologies and practices that can reduce emissions.

Disincentives to reduce methane emissions, as regulated gas companies are allowed to recover the cost of "lost gas" through rates.

Perception of technical risk with companies reluctant to undertake independent research and demonstration projects to establish the feasibility of available emerging technologies.

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Solutions:

Participate in EPA's Natural Gas STAR program.
Work with industry associations, such as the AGA and GRI, to support research, development and demonstration of new technologies and practices to reduce methane emissions from different components of the U.S. natural gas system.
Support state and Federal efforts to encourage efficient operation of the natural gas system, by addressing regulatory barriers that may preclude the implementation of environmentally beneficial technologies and/or reduce the economic incentives of companies to reduce their methane emissions.

Partnerships:

EPA, DOE, AGA, GRI, NGSA, API, and natural gas production, transmission and distribution companies
EPA, Natural Gas STAR Program Manager, (202) 233-9044

Case Studies:

Consolidated Edison Co. of New York, Inc. (Con Edison) -- Through its accelerated pipe rehabilitation program, started in 1988, Con Edison reduced its year-end workable leak backlog from almost 1,400 leaks in 1987 to just 52 leaks in 1993, and decreased the number of incoming leaks by more than 1,000 per year since 1990. This aggressive leak program resulted in annual natural gas savings of 78.5 mmcf per year, about $200,000 in the cost of gas. Con Edison was the first utility to field test Smart Regulators, a new technology that reduces the average pressure in gas distribution systems during lower demand periods, leading to lower methane emissions from leaks.
Pacific Gas and Electric Company (PG&E) -- Between 1977 and 1985, PG&E reduced emissions by 96 mmcf from high-bleed pneumatic devices by switching to "low" or "no-bleed" devices. From 1986 to 1995, the installation of these devices is expected to save an additional 800 mmcf. The total savings are estimated to be $2 million.

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Option Category:

Other - Methane Management and Use

Animal Manure Methane Energy Recovery

The recovery of methane from manure management systems can significantly reduce the overall emission of greenhouse gases. In 1990, animal manure accounted for about 10 percent of the U.S. methane emissions associated with human activities. Utilities can work with large livestock producers to reduce overall emissions of methane from animal waste lagoons by encouraging producers to cover their lagoons and collect the methane for electricity generation or on-farm fuel.

EPA, together with USDA and DOE, is implementing the AgSTAR program, under which livestock producers and the government sign a Memorandum of Understanding. AgSTAR participants agree to install AgSTAR selected technology where profitable, while EPA provides support in the form of decision support software to aid in project evaluation and system design, guidance materials, and public recognition. Utilities can support AgSTAR by encouraging livestock producers to participate in the program and supporting energy recovery at manure management system sites by cooperating in project implementation.

Lack of information and expertise regarding methane recovery systems. Information is frequently difficult to obtain and often incomplete for site-specific technical and economic evaluations.

Poor technical perception, because many early methane recovery projects were unsuccessful due to mechanical and maintenance problems.

Siting and permitting. Adding a methane recovery system to an existing manure management system may require permit modifications. In some cases, the costs may be substantial.

Difficult financing, since implementing projects requires an up-front investment in capital equipment that can be difficult for livestock producers.

Cost for establishing methane collection systems is high. Power generation (cost per MWh) may not be competitive with alternative energy sources.

Difficult to quantify methane not emitted due to a methane management action.

Solutions:

Support EPA's AgSTAR Program by supporting electricity generation or other use of the methane recovered from animal waste lagoons.
Work with state agencies and livestock producers to raise awareness of the opportunities to profitably use animal waste methane as a fuel source.
Publicize eligibility of methane collected from animal waste lagoons under the Section 29 Unconventional Gas Tax Credit and EPAct [[section]] 1212 Renewable Energy Production Incentive, both of which can enhance the economic viability of recovery projects.

Partnerships:

EPA, USDA, DOE, livestock producers, electric utilities, and equipment suppliers.
EPA, AgSTAR Program Manager, Kurt Roos, 202/233-9041.

Case Studies:

Dairy Facility. Since 1982, a 500-head dairy has been using a conventional methane digester system to help solve its wastewater lagoon problems. The recovered methane is used at the dairy to provide the facility's electrical requirements, and waste heat is captured to provide hot water for milking parlor cleaning. The digester also provides substantial savings in monthly lagoon cleaning plus additional revenues from sales to a local nursery of the nutrient rich solid fraction of the manure. As a result, the investment reduced annual O&M costs by about $53,000 and provides a 21 percent annual rate of return.
Pork Production Facility. In 1980, a 1,000 sow farrow-to-finish facility covered a portion of the existing lagoon to collect methane for on-farm energy applications. The collected methane fuels a 75-kw engine generator, and waste heat is used for space heat and grain drying. The investment reduced annual O&M costs by about $36,000 and provides a 34 percent annual rate of return.

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Option Category:

Other

District Heating and Cooling

In many downtown metropolitan areas the opportunity exists to replace individual building heating and cooling units with more efficient, centralized systems. With the phaseout of CFCs, many building owners will have to consider rebuilding or replacing their air conditioning systems. A non-CFC centralized system, e.g., ice storage, can be more efficient (reducing electrical demand) and could use off-peak power.

Another way to improve the energy efficiency of District Heating and Cooling (DHC) systems is to use waste heat from cogeneration for district heating and cooling. Cogenerated DHC systems deliver waste heat to buildings and/or convert the heat to chilled water for air conditioning. A 21.5 MMt reduction of carbon equivalent by the year 2010 could be achieved if cogeneration capacity provided baseload thermal energy for 50 percent of the estimated 6,000 existing DHC systems in the U.S. today.

Lack of analysis to measure the efficiency, environmental impacts, economic and institutional aspects of DHC.

Not included in IRP decisions about power plant capacity, thermal energy supply, and the environment.

Air quality regulations often penalize a large cogenerating DHC plant, even though such a plant may actually reduce overall emissions because it would displace many small sources which use fuel less efficiently and without advanced environmental controls.

Solutions:

Fully implement [[section]] 172 of EPAct, which calls for a study by DOE of the cost-effectiveness, energy efficiency, and environmental impacts of DHC.
Encourage cities, states, and utilities to include DHC in developing integrated resource plans for meeting end use energy needs.
Credit for DHC facilities during the permitting process for emissions they offset.

Partnerships:

DOE Contact: Floyd Collins, Office of Energy Management, Utility Systems Division, (202) 586-9191, (202) 586-0784(fax).

Case Studies:

Commonwealth Edison district cooling program using ice storage.
St. Paul District Energy Inc. district heating and cooling system.
Trenton, New Jersey cooling program using cold water storage.
Jamestown, New York, was the first community in New York to construct a hot water cogeneration district heating system. The system allows customers to cut their heating bills by 20 to 40 percent. The system displaces the equivalent of more than one million gallons of oil annually by using waste heat from Jamestown's coal-fired power plant as its central heating source.

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Option Category:

Other

Operational Actions

Electric utilities presently engage in many activities that result in improved air quality, waste minimization, and/or general pollution prevention. Some of these activities also result in the reduction, limitation, or prevention of greenhouse gas emissions. Assessing these activities for their greenhouse gas management potential may present opportunities to account for greenhouse gas reductions and facilitate new ideas for operational actions that can result in emission reductions. Such actions may include:

employee travel reduction programs -- compressed work weeks, car pool incentives, van pool subsidies, telecommuting policies, and other practices that result in reduced employee commuter-miles;

office and workplace conservation programs -- installation of energy-efficient lighting, teleconferencing, installation of "sleep mode" computers or low-power monitors, outreach programs and conservation incentives for employees, and other work force demand reductions programs. The EPA Green Lights program is an example of such an initiative;

replacement of conventional spray paint systems with electrostatic paint systems; and

conversion from greenhouse gas emitting chemicals in print shops, productions areas, construction and maintenance shops, generating stations, and other operating facilities.

Many other opportunities exist; some may be utility-specific or region-specific. Examination of general pollution-prevention options and operational practices may provide potentially significant opportunities for reduction, limitation, or prevention of greenhouse gas emissions.

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Barriers:

Reluctance of employees to car pool.
Lack of energy surveys or professional energy audits of company-owned facilities.
Some utilities have no means for offering incentives to themselves for conservation improvement (such as those offered to their customers).
Products and systems being selected without considering efficiency or fully assessing users' needs.
Project cost justification for internal applications.
Limited technological support for facilities management decision makers.

Solutions:

Provide employee incentives to car pool. Distribute statistics of areas where employees live and work to facilitate car pooling.
Policy revisions to allow telecommuting and compressed work weeks in appropriate areas of company operation.
Develop a conservation educational program and support materials for employees.
Provide support for the application of new technologies.

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Partnerships:

Bus companies, public transit, and rent-a-van operations.
States that have mandated travel reduction programs (e.g., California).
DOE, International Facility Management Association, Building Owners Management Association, EPRI, EPA, state agencies, electrical and mechanical suppliers and manufacturers.

Case Studies:

EPA's Green Lights Program.
EPRI's 1992 "Survey of Utility Demand Side Management Programs."
"Conservation Improvement Program" in Minnesota.
Florida Power & Light "Teleconferencing Program."
Metropolitan Edison has implemented an extensive source reduction strategy to reduce the generation of industrial and hazardous wastes at generating stations and area operating facilities. These strategies include product substitution, process modification, waste segregation, and employee awareness and have initially accomplished the virtual elimination of the use of all chlorinated and ignitable solvents and a two-thirds reduction in the generation of corrosive wastewaters.

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Option Category:

Other

Use of Coal Combustion Byproducts

Coal-fired electric power plants produce in excess of 90 million tons of solid by-products each year. These by-products are primarily fly ash and bottom ash. Fly ash comprises over 80 percent of the coal combustion byproducts generated.

The chemical properties of fly ash are such that it can be used in many cement and concrete applications as a substitute for portland cement. The manufacture of portland cement requires considerable amounts of fossil energy and produces CO2 emissions as a result of the calcination process. Replacing portland cement with fly ash will reduce the amount of fossil energy consumed and associated greenhouse gas emissions.

An example would be the use of fly ash in the production of autoclaved cellular concrete block. This lightweight precast concrete building material has significantly superior insulating characteristics compared to conventional concrete block. In addition to reducing the use of portland cement, the production and use of cellular concrete block can also reduce greenhouse gas emissions by reducing energy needed for heating and cooling and by reducing transportation-related emissions.

Currently, less than 25 percent of the fly ash produced is being utilized in any form, with less than half of that amount being used as a portland cement substitute. With approximately 60 million tons of portland cement being produced annually in the U.S., there is considerable potential for increased substitution of fly ash.

In addition, there is an ever-increasing amount of gypsum and other sludges being generated from flue gas desulfurization processes. In many cases this material can replace raw gypsum in industrial and agricultural applications. This can avoid the energy cost and emissions associated with the acquisition and use of raw gypsum.

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Barriers:

Not all ash is suitable for cement or other high-value applications.
Institutional barriers include potential users' lack of familiarity with coal combustion byproducts (CCBP) applications, users' perception of CCBP inferiority, and general difficulties associated with CCBP competing with an accepted virgin material. Legal barriers center on liability associated with Comprehensive Environmental Response, Cleanup and Liability Act (CERCLA) and other federal and state environmental regulations. The most significant regulatory barrier is the designation of the material as a "waste" and resultant regulatory control over CCBP applications; inconsistency between state and federal regulations and among states presents additional barriers. Other barriers can be termed "technical," e.g., inconsistency in the characteristics or lack of quality assurance and quality control of the CCBP produced.
Low NOX operation can affect ash quality.
Although cellular concrete has been manufactured for over 60 years and is used in more than 35 countries, there are no manufacturing facilities for it in North America.

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Solutions:

Prepare a credible and comprehensive analysis of the environmental benefits of using coal ash, making use of available data. Also, prepare an analysis of the "life-cycle" environmental impacts and benefits of a variety of construction materials including conventional concrete, concrete with fly ash, high-performance concrete with fly ash, asphalt, steel, wood products, and plastics composites.

Section 1334 of EPAct directed DOE to conduct a study of the institutional, legal, and regulatory barriers to increased CCPB utilization, including recommendations to eliminate those barriers. Preliminary recommendations of the study include both public and private initiatives. Governmental initiatives include: (1) establishment of national goal status for CCBP recycling; (2) regulatory classification defining pre-approved CCBP uses; (3) mandates and guidelines in Federal procurement; (4) economic incentives, including tax incentives for CCBP use; (5) action to limit legal barriers; and (6) Federal inter-agency coordination. Private initiatives (with governmental assistance) include: (1) development of CCPB product specifications; (2) development of technical assistance and education programs; (3) byproduct quality assurance; and (4) research, development and demonstration of CCBP applications.

Executive Order 12873 offers an additional opportunity to remove barriers to CCBP utilization. The Order directs Federal agencies to develop "positive procurement guidelines" for environmentally preferable goods, including recovered materials; concrete containing fly ash is one of the materials covered in the Order. Thus, Federal agencies are directed to increase their procurement of fly ash concrete products, providing opportunities for demonstration and educational programs.

Environmentally sound use of CCBP could be encouraged by limiting potential liability under Superfund.

To minimize potential "institutional" barriers, electric utilities could undertake the following steps:

Demonstrate a willingness to use CCBP in their own projects to set an example for potential CCBP customers. An essential step to achieve this is to specify fly ash-containing cement and cement products and other CCBP in all internal utility construction projects.
Educate the public, potential CCBP users, and government agencies on the numerous potential uses of CCBP. Actual applications should be enumerated, as well as how CCBP performs with regard to "traditional materials" (e.g., fly ash concrete vs. portland cement concrete, bottom ash vs. blasting grits, etc.). If possible, tangible examples (small samples of CCBP-containing materials) should be provided.
Develop additional demonstration projects (e.g., the construction of a house or building containing as much CCBP-containing materials as possible) and use associations, governmental agencies, and the media to help publicize these projects.
Encourage development of the market for cellular concrete block by promoting it as a superior, environmentally friendly building material.

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Partnerships:

The electric utility industry, through EEI and the American Coal Ash Association, should work with DOE on the implementation of recommendations of the [[section]] 1334 Barriers Study and The Federal Office of Procurement Policy on implementation of Executive Order 12873.

Case Studies:

American Electric Power "Coal Ash Utilization Program."
EPRI Final Report TR-100473, March 1992 "High Volume Fly Ash Concrete Technology."
EPRI Final Report GS-6129, January 1989 "Ash-in-Concrete Model Development."
EPRI Final Report TR-101774, January 1993 "Proceedings: Tenth International Ash Use Symposium."
New England Power's (NEES) coal ash carbon separation project at its Salem Harbor Station.
The Jacksonville Electric Authority (JEA) sells the major by-products, such as fly ash, from the operation of the St. Johns River Power Park for re-use in the construction industry, saving valuable landfill space. In 1990, JEA sold 204,000 tons of these by-products, saving $530,000 in avoided landfill costs.
Pennsylvania Electric Company (PENELEC) is conducting R&D on two different technologies to determine the amount of carbon in the flyash leaving coal-fired generating units. By measuring carbon in the flyash in real-time, unit efficiency can be improved and maintained.
PENELEC is conducting research on alternative uses of coal combustion by-products. Currently, the bottom ash is being sold from the Homer City units for anti-skid materials. Flyash from the Keystone station is being used in the construction of the US Route 422 bypass extension around Indiana, PA. Initiatives have included the use of these materials in structural fills, mine closures and road construction.

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Option Category:

Other

Waste Heat Utilization

In the process of generating electricity through the combustion of fossil fuels or use of nuclear energy, a significant portion of the heat energy available in the fuel is wasted. Typical coal-fired electric power plants use only around 34 percent of the available energy in the fuel. Even the most recent combined cycle systems can only utilize slightly over 50 percent. The fact that a portion of the available energy is wasted in the production of electricity is due to the nature of the energy conversion process. As the Second Law of Thermodynamics states, "only a portion of the available energy can be converted into useful energy."

The largest waste heat source at a power plant is the large volume of warm water produced by the condensing of steam. There is considerable energy in this source. Utilization of it could displace the consumption of fossil fuels and result in a reduction of greenhouse gas emissions.

Waste heat streams from the electric generation process are not readily adaptable to conventional heating or process uses.

Establishment of a waste heat application at the power plant site can be a problem due to lack of space.

Backup heat supply during outages.

Difficulty in finding thermal host to locate near power plant.

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Partnerships:

DOE, EPRI, greenhouses, utilities, and state Departments of Conservation.

Case Studies:

Pennsylvania Power & Light's Montour plant uses waste heat for greenhouses.
Baltimore Gas & Electric powerplant waste heat is used to heat a State of Maryland fish farm.
New England Power's (NEES) "Green RFP" selected an organic rankine cycle waste heat recovery project for installation at the back end of existing spark ignition engines.
Northern States Power's Sherco Plant's use of waste heat for greenhouses.
Approximately ten acres of greenhouse are heated using the warm water from the Pennsylvania Electric Company's Homer City Station cooling towers. The greenhouse is used by a local grower to provide plants of all types.

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Other

Recycling

Recycling saves natural resources, landfill space, and energy. Savings in energy can be translated into reduced greenhouse gas emissions. The savings potential is considerable. In 1989, for example, the recycling of aluminum cans alone saved more than 12 billion kWh of electricity, the energy equivalent of some 20 million barrels of oil.

Utility involvement in recycling can take the form of company recycling programs and/or support of regional or local public programs.

Establishing markets for recycled products.

Difficulty in quantification of environmental impact and greenhouse gas reduction.

Solutions:

Participate in CCAP Action #16 to accelerate source reduction, pollution prevention, and recycling.

Partnerships:

Work with industry trade associations such as the Steel Recycling Institute, the American Coal Ash Association, and others. Support national initiatives such as the U.S. Conference of Mayors, National Office Paper Recycling Project.

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Case Studies:

Northern States Power (NSP) has an appliance recycling program which provides free removal and recycling of refrigerators, freezers, and window air conditioners. Chlorofluorocarbons (CFCs), sulfur dioxide refrigerants, and other hazardous chemicals are recovered from appliances recycled through the program and are safely recycled or disposed of in an environmentally sound manner.
The NSP "BRITE" (Being Responsible in Today's Environment) program is a set of waste management programs used internally by NSP employees to increase efforts to conserve, reduce, and recycle. It is estimated that NSP has saved $1.7 million through 1993 in waste hauler costs due to its recycling programs. Specific accomplishments include recycling over 350 tons of paper, 5,000 lbs of shrink-wrap, 1,100 laser printer cartridges, 800 tons of wood (pallets, reels), and 3,700 gallons of antifreeze.
The Jacksonville Electric Authority received the 1990 Mimi and Lee Adams Environmental Award in the business/corporation category for its conservation and preservation programs, which made significant contributions in pollution prevention and control.
Metropolitan Edison has implemented an extensive recycling program, which addresses the recycle of paper and cardboard products, waste oils and oil filters, scrap metals, batteries, antifreeze, oil contaminated soil and wood products. This program has resulted in the recycle of approximately 66 percent of the hazardous wastes and over 385 tons of the industrial wastes generated by the company.
Pennsylvania Electric Company has begun a "Partners in Quality" educational and assistance program for its industrial customers. The program includes seminars to educate customers concerning the handling, minimization, and replacement of hazardous materials and wastes such as ozone-depleting substances, volatile organic compounds, and potentially hazardous coatings.

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Other

Reductions of Greenhouse Gas Emissions Other Than CO2 and Methane

While the primary focus of the Climate Challenge Program is on CO2, there are other greenhouse gases or greenhouse gas precursors that utilities have an opportunity to control. These gases include NOX and CFCs. Most of these gases are emitted in activities that are peripheral to the utilities' core activities. In the case of NOX, the contribution of the gas to global climate change is not well defined and is not uniform from region to region. Nevertheless, utilities have an opportunity to contribute to Climate Challenge by controlling these other gases on a site-specific basis.

Lack of scientific understanding of the quantitative impacts of other greenhouse gases on climate change in relation to CO2.

Possibility that reductions in some greenhouse gases, primarily NOX, may have a negative impact on other environmental conditions, such as ozone formation.

Solutions:

Continue air modeling studies now underway to determine the need for, and effectiveness of, limiting or reducing the emission of other greenhouse gases.
Assist in the development of regulations that allow for regional differences in control technologies and goals for the control of other greenhouse gases.
Continue to seek appropriate, accurate equivalence factors to equate the reduction of other greenhouse gases with CO2.

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Other

Enhanced Oil Recovery (EOR)

The combustion of fossil fuels results in the production of flue gases containing CO2. The potential exists for utilities to enter into partnerships with the oil and gas industry to utilize the flue gas CO2 for enhanced oil recovery (EOR). The capture of CO2 from energy generation or manufacturing plants seems more logical than tapping natural deposits of CO2 While flue gases from current power plants require costly purification to meet the purity requirements for EOR, existing ammonia manufacturing plants and coal gasification plants produce CO2 vent gases which are pure enough for EOR.

The utilization of waste CO2 from utility generation facilities for EOR would increase the percentage of recoverable hydrocarbons from existing domestic well fields. EOR provides an opportunity to more fully develop existing energy resources while reducing the release of CO2 to the atmosphere.

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Barriers:

EOR may not be cost-effective or suitable for all oil fields, but if technical barriers can be overcome, it can provide an efficient low-pressure displacement in many reservoirs.
While some CO2 is recovered with the oil produced, it is separated and re-injected into the oil reservoir. Essentially, all CO2 injected remains in the reservoir.
Carbon dioxide is usually not available near the oil fields and as such usually requires long distance pipelines to bring it to the fields for use. The pipelines must be sited and routed in accordance with applicable regulatory requirements. These can include approval from state public service commissions, USDOT, and the Army Corps of Engineers.

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Solutions:

Encourage the evaluation of oil fields well in advance of potential CO2 EOR to determine the feasibility. Support use of new drilling and recovery technology to reduce capital requirements and operating costs, thereby improving the economic viability of EOR.
Work with regulatory agencies to facilitate pipeline siting and routing procedures.
Support state and federal programs that strive to maximize recovery of natural resources from existing oil fields by utilizing existing industrial sources of CO2 for EOR.
Utilities can enter into partnerships with industries that can capture CO2 rich streams that could be used for EOR.

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Other

Solar Water Heating, A Renewable Energy Source

Solar hot water heating is applicable to a wide range of residential and commercial situations and is an established and mature technology which displaces, either directly or indirectly, the combustion of fossil fuels. Solar water heating equipment consists of low-temperature solar thermal collectors and thermal storage. These functions can be combined into a simple "batch" heater. Solar water heating equipment can assist in reducing peak electric demand and therefore greenhouse gas emissions in areas of high solar insolation.

Premium for solar hot water heaters is approximately $1600 above the cost of a conventional electric hot water heater.

Applicability of solar hot water heaters is site specific, not all buildings or situations are good candidates for the technology.

Solutions:

Develop package efficiency applications for solar installations that integrate with existing utility rebate and state grant programs.

Partnerships:

Solar Energy Industry Association - Peter Lowenthal, (202) 383-2600, National Community Action Foundation, other utilities, state government energy offices.

Case Studies:

State of Florida.
Sacramento Municipal Utility District.
General Public Utilities.

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Other

Education and Information Programs

Education of residential, commercial, and industrial customers, employees, and members of other institutions, organizations, and communities that can influence emissions of greenhouse gases.