Report of the Panel on DOE’s Distributed Energy Resources Program
This report presents an estimate by the Panel on DOE’s Distributed Energy Resources Program of the prospective benefits of the combined heat and power (CHP) component of DOE’s distributed energy resources (DER) R&D program. The charge given to the panel by NRC’s Committee on Prospective Benefits of DOE’s Energy Efficiency and Fossil Energy R&D Programs, Phase Two, was to apply the methodology and approach of the Phase One committee to estimating benefits of the CHP program. The panel applied that methodology, taking into account technical and market (including regulatory issues) risks, both of which affect the program’s ability to meet its goals. The methodology required the panel to make observations regarding program emphasis, benefits, and other factors that might assist it in its assessment. This report describes the panel’s work and presents its observations about the program and suggestions for improvement as well.1
In summary, the CHP component of the DER program is designed to demonstrate four integrated CHP applications, each having greater than 70 percent combined electric and thermal efficiency, that could be manufactured and installed (assuming commercial-scale production) cheaply enough to result in a 4-year payback to customers by 2008. The CHP budget request for 2006 is $20.5 million. Key findings of the panel are (1) the 70 percent efficiency goal is achievable in the stated time frame in the end-use applications targeted by the program, but the payback goal is not, except in areas of the country where electricity is constrained or costs are high relative to natural gas; (2) the program produces a positive net present value (NPV) economic benefit under the four global scenarios assessed, ranging from $46 million to $83 million; and (3) the CHP program as a component of the larger DER program is too small to be modeled accurately using conventional models, and any further application of the committee’s methodology should be to larger-impact programs. For many participating facilities, originally drawn to the CHP program for economic reasons, the protection against blackouts provides an important value-added service. For others, the economic benefits do not justify investment in CHP; instead, security is the deciding factor. In any case, security is recognized as an important benefit of CHP and one likely to become even more critical in the future. Understanding the value that customers assign to selected CHP attributes and the trade-offs they are willing to make and assigning a dollar value to those attributes would go a long way toward positioning the CHP program in the marketplace. Monetizing the value of attributes would add to the positive net economic benefit figures reported above in item 2.
DISTRIBUTED ENERGY RESOURCES PROGRAM: SUMMARY AND BUDGET
The DER R&D program is designed to improve the technology and encourage the adoption of distributed energy technologies. Many, but not all, of the technology applications in the DER program are configured as CHP or cogeneration projects in which the thermal energy recovered from the engine is used at a customer facility to provide hot water, space heating, or cooling. Of the $56.6 million DOE budget request for its DER program for 2006, $20.5 million, or 36 percent, is directed at the activities called “End-Use System Integration and Interface,” which is the program area subject
to this panel assessment.2 The technologies and applications supported within this program area are predominately CHP projects. The DER program has the mission of improving the prime movers (microturbines, for instance) and their related technology development, while the CHP component of the DER program is focused on demonstrating system integration and application while reducing costs. DOE works with component equipment and technology manufacturers to develop and demonstrate CHP systems, that provide both electrical power and heating or cooling at customer sites with minimal site-specific engineering. The program strives to standardize the technical and engineering analysis required to install and operate CHP systems, making them applications-ready.
The stated goal of the CHP program is to demonstrate four integrated CHP applications, each having >70 percent combined electric and thermal efficiency, that could be manufactured and installed (assuming commercial-scale production) cheaply enough to give customers a 4-year payback by 2008.3 The program is targeting four integrated systems applications—one each in an office building, a hospital, a college building, and a supermarket. On the one hand, the panel believes that the 70 percent efficiency goal is not difficult to achieve, as CHP systems are available today that meet or exceed the 70 percent efficiency goal. The attainment of the 70 percent efficiency goal, however, is highly dependent on the characteristics of the CHP system’s application, including the electrical load and thermal load it is serving and the profiles of both. On the other hand, it believes that the 4-year payback criterion presents a significant challenge owing to the high capital costs of CHP systems and the need for sufficient thermal heating or cooling load. Moreover, the price differential between the CHP host facility’s electricity prices and CHP fuel prices can dramatically affect the economics of CHP projects and, as a result, the payback. The panel applauds DOE’s program focus on demonstrating CHP applications in the broader, more challenging markets targeted and, in particular, on demonstrating applications that the panel believes are unlikely to be developed without government support. If successful, the CHP program should result in more systems being designed and installed that meet the efficiency and payback goals, which would lead to more rapid deployment and greater customer confidence in system performance.
The panel heard presentations from DOE and its contractors and had the opportunity to ask questions and speak informally with program representatives at each of its meetings. DOE provided information and data about specific CHP system applications funded through the program, and it shared freely with the panel problems and difficulties with the technology and component integration as well as program successes. For this the panel is grateful. DOE and its contractors were also very responsive to the data requests of the panel.
BENEFITS ANALYSIS OF THE CHP PROGRAM
DOE estimates the benefits of the entire DER program using the U.S. Energy Information Administration’s National Energy Modeling System (NEMS) and the MARKet ALlocation model (MARKAL). DOE estimated the contributions from its DER program through 2025, in terms of gigawatts (GW) generated, natural gas savings, oil savings, consumer energy savings, carbon emission reductions, and nonrenewable energy savings. The benefits estimates provided by DOE are generally consistent with its Government Performance Results Act (GPRA) reporting.4 Estimates were provided for 2010, 2015, 2020, ending in 2025 (from NEMS) and for 2020, 2030, 2040, and 2050 (from MARKAL). By providing data for overlapping years, 2020 and 2025, the panel was able to consider the differences in estimates from the two models. The panel decided to base its probabilities and benefits estimate on the NEMS model, because panel members were more familiar with it and its horizon was shorter.
Since the NEMS analysis was conducted for the DER program as a whole, the panel requested that DOE and its contractors develop a simplified approach for parsing out the benefits that would likely be attributable to the CHP program component. DOE complied with this request by first scaling the total benefits of the DER program by the CHP proportion of the total DER budget. Following this, benefits were further adjusted to reflect CHP penetration in the commercial sector only and to account for the CHP program focus in office buildings, hospitals, college buildings, and supermarkets. Industrial and utility sector CHP applications are not included in this scaling. DOE estimated that the 2.2 GW of CHP capacity added through 2025 is attributed to the CHP program (of the total 64 GW of DER added nationally by 2025, as used in the GPRA analysis).5 The panel accepted this as a reasonable first-order approximation for CHP penetration in the marketplace attributable to the DOE R&D program.6
DOE’s estimates of the quantity of CHP added as a re-
sult of its program are based on several key assumptions: principally, the expected costs and payback period for the CHP applications; the estimated maximum portion of the commercial buildings sector (new and retrofit) representing the total potential market; and market penetration of CHP as a function of system economics, defined by the payback period. In its benefits analysis, DOE evaluates a “program” case, where the technical goals of the program are assumed to be met and the total potential commercial CHP market is assumed to be 50 percent of new buildings and 5 percent of buildings being retrofitted. DOE compares this to a “without DOE” set of assumptions, where the technical and payback goals are reached 10 years later than with the program, and the total retrofit market is much smaller. DOE’s estimate of the incremental capacity attributed to the DOE R&D program incorporates an assumption that without the DOE program, technical achievement would be delayed by 10 years.
The panel explicitly assessed the likelihood of meeting technical and market outcomes with and without the DOE program using the decision tree analysis prescribed by the committee, rather than assuming a 10-year delay without the program.7 Because of this difference in assumptions, when the panel applied the scaling method suggested by DOE for estimating the benefits of the CHP program, it started with the incremental installed DER capacity in the “program case” over and above that of the NEMS reference case. The program case analysis versus the AEO Reference Case used by the panel begins with a DER contribution of 77 GW rather than the 64 GW used in the GPRA analysis. The estimated incremental contribution from the CHP program assuming DOE’s goals are met then becomes at 2.65 GW by 2025.8
The panel found neither NEMS nor MARKAL to be well suited for determining the benefits of such a small niche set of technologies and applications.9 Since the models are national in scope and CHP technology is likely to be valued differently in different regions of the country, the panel does not believe that the models are able to reflect market penetration accurately. At the panel’s request, DOE developed a simplified approach to parse the likely benefits of the CHP program from the larger DER portfolio that was modeled in NEMS, which the panel appreciated and readily accepted. Since both models evaluate market penetration on a national level, they provide an overly optimistic projection of the reduction in environmental emissions that results from displacing electricity generated in coal-burning power plants. The models also have no reasonable mechanism for calculating the intrinsic benefits of this technology, such as security and electric system reliability. Use of these technologies will provide greater benefits to the end-user based on electricity reliability in the face of possible outages. Many commercial and institutional customers consider security and insurance-against-business-disruption factors as being important considerations when contemplating the use of DER—a factor that NEMS is not able to capture. The NEMS model’s shortcomings were fully considered when the panel developed its probabilities of CHP market adoption.
Electricity System Constraints Scenario
The methodology prescribed by the committee requires the panel to evaluate the program under three different global scenarios: an Annual Energy Outlook (AEO) Reference Case scenario, a High Oil and Gas Prices scenario, and a Carbon Constrained scenario. As allowed by the methodology, the panel elected to define a fourth global scenario, where there are assumed to be severe constraints on the electricity system. The Electricity Constrained scenario captures benefits of the CHP program where its impacts might be of greatest value—that is, in regions of the country where electricity service is most constrained. The scenario assumes that the electric distribution system is unable to meet the peak electricity demand of its customers.10 As defined by the panel, the scenario assumes that sufficient power is not available for some extended time (weeks or months) in one or more high-demand-load pockets in the affected regions of the country. The critical power shortage can be mitigated by taking several actions, including reducing voltage; imposing
selected rolling blackouts; terminating supply to selected high-demand customers with interruptible electricity service contracts; increasing real-time electricity prices; improving energy efficiency in the service area; and installing CHP systems in load-constrained areas.
At the panel’s request, DOE worked with Lawrence Berkeley National Laboratory staff to estimate the gigawatt contribution of CHP nationally by 2025 under the Electricity Constrained scenario. While the market penetration of the CHP technologies improves under this scenario, it still does fully capture the reliability and security value of CHP technologies.
The Panel’s Decision Tree Analysis
To estimate the expected benefits of the CHP program, the panel developed a decision tree representing various decision paths and technical and market outcomes, and assigned probabilities to each uncertainty. The decision tree developed by the panel is illustrated in Figure K-1. The first node represents a decision about DOE funding: the likelihood of technical success and market success depends on whether the DOE program is funded, and the benefit of the program will ultimately be estimated as the difference between the yes and no branches.
Since the payback period depends on local electricity prices relative to natural gas prices (assuming that CHP systems under study burn natural gas), two types of local market conditions were defined: locally high electricity prices and locally low electricity prices, as represented by the second node in the decision tree. The panel then estimated the likelihood of achieving specific payback periods and market penetration rates separately for the different local market conditions.
The third node represents three possible outcomes for technical success, defined by the panel as the payback period for a system with at least 70 percent efficiency (less than 4 years, 5 to 7 years, or 8 years or more). The final node represents three possible market success outcomes, defined by the portion of the market adopting CHP technologies assuming a 4-year or shorter payback period. High market adoption was defined by the panel as implementing CHP systems in 50 percent of new buildings and 5 percent of existing buildings; moderate market adoption was defined as 25 percent of new and 2.5 percent of existing; and low was defined as 10 percent of new and 1 percent of existing buildings. Market penetration is a function of the payback period to customers having installed the CHP technology. DOE gave the panel its assumed market penetration curve (function) for use in estimating probabilities of technical and market success.
Assessment of Technical and Market Success
Panel members estimated the probability of achieving each specified level of technical success as defined by the payback, both with and without DOE funding. This was done for the two local market conditions and each of the four global benefits scenarios described previously.
The panel discussed each member’s probability of technical success and the reasons for the assignment of the probabilities, and developed consensus estimates. The panel then developed estimates of the probability of achieving each of the three specified levels of market success both with and without DOE funding, under each of the two local market conditions and for each of the four global scenarios.
The consensus estimates are illustrated in Figures K-2 though K-6, which show the cumulative probability for selected payback periods for a CHP system that is 70 percent or more efficient in a locally high-electricity-price market with DOE funding. These figures allow comparison of the estimated impact of the four global scenarios on technical success. The panel estimated the highest likelihood of technical success in the Electricity Constrained scenario and the lowest in the High Oil and Gas Prices scenario (because higher natural gas prices will make it more difficult for CHP technologies to achieve a shorter payback).
Figures K-4, K-5, and K-6 show the cumulative probability for various payback periods under each of the four global scenarios and illustrate the effect of DOE funding and of local market conditions. The panel estimated a higher likelihood of achieving a shorter payback with the DOE program than without it and higher likelihoods in the locally high electricity price market than in the locally low-electricity-price market.
Finally, the panel also estimated the likelihood of achieving different levels of market adoption for CHP technologies. The consensus probabilities are shown in Figure K-7. The panel estimated a higher likelihood for strong market adoption with DOE funding than without DOE funding. It estimated the highest likelihood of market adoption in the Electricity Constrained scenario.
Prospective Benefits Results
The panel estimated CHP program benefits for each of the four global scenarios by using its probabilities for technical and market success and DOE’s estimate of incremental CHP capacity installed under conditions of high technical and market success to develop an estimate of incremental CHP capacity attributable to the DOE program. That value was then multiplied by the dollar value per gigawatt assessed by the panel to yield the expected economic benefits of the program.
The estimated increase in CHP installed, given the panel’s assessment of the technical and market risks, is illustrated in Figure K-8. The figure shows the expected value of the CHP that DOE estimates will be added due to its program (the top solid line) and the panel’s estimate of the CHP that will be added if both technical and market success are low (the bottom solid line). For each global scenario, and for each of
the two local market conditions, the expected value of the CHP addition is calculated as the probability-weighted average of all possible technical and market success outcomes specified in the decision tree (and shown with the diamond and cross markers). Separate estimates are shown for CHP additions with and without the DOE program. Figure K-9 shows the uncertainty around the expected Electricity Constrained additions for each scenario and each local market condition. This figure reproduces Figure K-8 but includes uncertainty bars representing the 10th to 90th percentiles of the estimated incremental CHP. This uncertainty is derived directly from the estimated incremental CHP associated with each of the technical and market success end points from the decision tree and the panel’s estimates of the probability of each of those technical and market outcomes.
Economic Benefits. The panel used secondary research to assign a dollar value to CHP savings (it looked at CHP economic analyses studies conducted elsewhere in the country). Generally, in today’s economic climate, CHP technologies are barely breaking even on a net economic resource basis—the present value of life-cycle benefits are roughly equal to the present value of life-cycle costs. The panel assumed that this situation is likely to improve in the near term as CHP technology improves and niche applications are being found that would provide CHP with an economic advantage over the next-best alternative, the purchase of electricity and thermal energy. The panel determined that CHP could easily provide a 10 percent net benefit above its costs over the study period, leading to a benefit-cost ratio of 1.1. While the net benefit could be higher or lower than 10 percent, the panel assumed the 10 percent was a reasonable approximation, given that the technology is expected to improve and the economics of CHP, given current and expected future energy costs, are also expected to improve. This assumption translates into a net economic benefit of approximately $230 per kilowatt of installed CHP. This is calculated on an electricity system avoided cost basis and takes into account for the initial CHP investment and life-cycle operating costs.
To calculate the NPV of the economic benefits, the panel considered the incremental capacity attributable to the program in each year from 2006 to 2025, estimated the economic value by year, and then calculated the NPV of that benefits stream using a 3 percent discount rate, as recommended by
the full committee. The panel further assumed that installed CHP would deliver economic benefits for a minimum of 10 years.
The panel’s estimate of expected economic benefit from DOE’s CHP program is shown in Figure K-10 for each of the four global scenarios. Net economic benefits range from a low of $46 million in the High Oil and Gas Prices scenario to a high of $83 million in the Electricity Constrained scenario. This net benefit is assumed to be made available for a DOE CHP program investment of approximately $20 million per year. The panel estimates that the DOE CHP program provides a net economic benefit to the country under each of the four global scenarios.
Environmental Benefits. Clean and efficient CHP has the potential to reduce overall emissions since it uses cleanburning natural gas as a fuel and it displaces central station generation power and local combustion boilers and furnaces used to generate steam, heating, or hot water. If the thermal use of the CHP system is high, and especially if the steam, heat, or hot water was previously produced using a less clean burning fuel, a switch to CHP clearly confers air emissions benefits both locally and regionally. If the displaced heat was previously produced by burning natural gas or if the thermal output of the CHP system is used to displace electric space cooling, there might still be regional air emission benefits from CHP, since the overall high fuel utilization efficiency reduces emissions of CO2 and criteria pollutants; the local effects are less clear. Even a very clean CHP unit still produces some NOx and other gases close to loads. Whether these small emissions are significant compared to background emissions from cars, trucks, buses, boilers, furnaces, and food cooking is debatable. The benefit of using less central station power also varies depending on whether the source is a dirty old coal plant, a modern combined cycle facility, or a nuclear or hydro plant.
As a practical matter, local air permits, especially in nonattainment areas, act as barriers to CHP. Important issues related to CHP penetration include the size of systems and hence their need to comply with local laws and regulations, the availability of fuels and environmental permitting for the use of such fuels, and proximity to population. Unfortunately, the parts of the country in which electric and gas rates favor CHP also tend to be the same ones with high population densities and air pollution concerns. The panel believes that at modest levels of penetration, the cleaner burning CHP systems considered in this DOE program will not materially degrade anyone’s environment nor will they help address major pollution concerns. At higher penetrations, CHP will help reduce global CO2 emissions and SO2, NOx, particulates, and mercury to the degree that it displaces fuels like coal and oil, either at central power plants or locally, to produce steam, heat, or hot water. Even if a clean fuel such as natural gas is displaced by a CHP installation, either centrally or locally, there will still tend to be environmental benefits. The environmental benefits accrue from the decreased energy use attributable to CHP systems that are more efficient than the baseline of central power and local boilers or furnaces. High thermal utilization and fewer emissions tend to improve the overall environmental impact of CHP. DOE programs to further reduce the already low emissions from CHP and to enable even greater heat utilization with cost-effective technologies will enhance CHP’s already overall favorable environmental performance.
Security Benefits. Security benefits arise from the reduction in primary energy use associated with the implementation of CHP technologies. The term “security” as defined by the panel for the CHP program has several meanings, including (1) invulnerability to terrorist attacks and natural disasters, (2) insensitivity to energy disruptions caused by reductions in oil imports, and (3) customer protection from the effects of disruptions to utility electric service. Like all energy efficiency measures, CHP reduces primary energy use and helps improve energy security of the type described in item (2) above. However, the unique benefit of CHP is to decentralize power production and locate it at or close to loads, providing benefits of the types described in (1) and (3) above. Considerable concern has been expressed in recent years about the need to reduce the threat and potential costs of acts of terrorism through greater use of distributed energy resources. However, CHP has the ability to reduce the risk and costs of many other adverse events, including utility outages from storm events, cars hitting power poles, squirrels chewing through wires, to more unusual but devastating outages such as the daylong loss of power to 50 million people in the Northeast on August 14, 2003. It must be noted, however, that reliance on natural-gas-fired distributed generation is also subject to terrorist attacks on pipelines.
When properly configured, CHP protects many different customers and loads from utility service disruptions. The least expensive type of clean, grid-connected CHP operating in parallel with the utility grid uses induction generators, which immediately stop generating when the utility power that supplies their excitation is removed. This automatic safety feature makes many utilities favor induction equipment. Unfortunately, the induction systems do not directly help customers during supply disruptions. To get the benefit
of grid parallel operation and stand-alone capability, a CHP system needs to use synchronous generators and more expensive automatic switchgear to provide emergency load isolation and utility system protection. The problem becomes more difficult and more expensive to solve if the generator is operating on a network system, such as in New York City and many other large urban areas, rather than on the more common radial distribution systems.
Many critical facilities, including hospitals, nursing homes, computer warehouse facilities, and some tall buildings dependent on elevators, are required to have backup generators to carry all or part of their load during a blackout. These are almost invariably cheap, dirty, diesel-powered generators, permitted to run a very limited number of hours in a year. Emergency backup diesels need to be regularly started and actively maintained if they are to be relied on during an emergency. Such generators also often have only very limited fuel storage on-site, making operation during an occasional longer outage problematic. For these reasons as well as in the interest of lower emissions, a clean, natural-gas-based CHP system might offer a better solution than an emergency diesel generator. Natural-gas-powered CHP would provide
energy-efficiency-based savings during normal times and superior reliability during an emergency. In addition, there is usually no fuel limitation during prolonged blackouts.
For many facilities originally drawn to CHP for economic reasons, the added protection against blackouts is an important value-added service. For others for which the economics are not attractive enough to compel investment in CHP, security is the deciding factor and economic benefit is a byproduct. In any case, security is recognized as an important benefit of CHP and one likely to become even more critical in the future. The DOE CHP program should fully recognize this fact and direct efforts at reducing the cost and improving the performance of interconnection technology to allow CHP systems to safely operate both grid-parallel and grid-isolated as well as on network systems. The current DOE systems integration program has not emphasized security enough, although all CHP R&D will tend to provide some security benefit. The panel feels security should be a much more important program goal.
In addition to applying the committee’s methodology to DOE’s CHP program for estimating prospective benefits, the panel also discussed at some length the focus of the program and the projects being funded. As a result of these discussions, the panel suggests that DOE consider addressing the following items as it selects CHP projects for funding that could improve both program payback and ultimate program success:
Electrical energy is worth approximately three times as much as thermal energy. Overall system efficiency is less important than knowing the relative amounts of electrical and thermal energy. A system with 38 percent electrical efficiency and 32 percent thermal efficiency creates a much higher value and shorter payback than a system with 26 percent electrical efficiency and 44 percent thermal efficiency even though both have an overall efficiency of 70 percent.
In calculating payback, it is important to know the electrical load factor. Clearly a system operating 24 hours per day will have a much shorter payback than a system operating 12 hours per day.
In calculating payback, it is important to know the thermal load factor and how this profile coincides with the electrical load profile. When the thermal load drops to zero, as can happen in comfort conditioning in mild weather, the fuel cost of electricity effectively doubles.
To optimize payback and load profiling (items 2 and 3 above), it might be advantageous to power only part of a facility’s electrical load and leave the rest to be powered by the local utility company. With fewer or smaller generator sets online, less heat would be produced, thus more closely matching the minimal thermal load profile. Correspondingly, steady electrical loads with flat load factors maximize total kilowatt-hours produced and minimize payback. Thus, powering selective steady loads such as lighting will produce the greatest return on investment.
Capital cost can be reduced by eliminating redundant CHP units. If lighting is the load to be served by CHP, loss of one generator set may reduce the lighting level but the facility will continue to operate. The need for redundancy is reduced.
The heat rejected from most prime movers is at a lower temperature than the heat from a fired boiler or water heater. As the final exhaust temperature is typically 300 F to prevent condensation and acid corrosion, the percentage of heat that can be recovered is less than with a fired boiler or water heater. However, if the exhaust heat is used in a drying, baking, or preheating operation, the 300 F limitation no longer applies and the thermal efficiency is much higher. In addition, when the exhaust heat exchanger is eliminated, the capital cost is lower.
DOE should consider working more closely with utilities to encourage utility ownership of CHP systems. Paralleling CHP with the utility grid eliminates the need for redundant units, improves system efficiency by allowing the equipment to follow thermal load, and improves facility security by providing an independent source of electricity. If the utility owns and/or operates the CHP systems, it can dispatch them as needed to maximize overall efficiency and minimize pollutant emissions. It can also use them as peaking units when necessary. Utility ownership of distributed generation would be consistent with the obligation of utilities to serve the public. DOE should support replicable pilot applications where there are offsetting capital costs for, say, standby generators in hospitals or standby generators and uninterruptible power systems in data centers. DOE should address the problem of institutional barriers and work with regulatory agencies and utilities to eliminate or reduce them. The panel further observed that
Funding for CHP from entities other than DOE was fairly easily identified, with many states investing more in CHP than DOE.
NEMS and MARKAL are reasonable models for examining the integration of larger technologies and energy systems into the U.S. energy markets. However, to properly evaluate the potential of niche CHP technologies to penetrate the marketplace, more specific models must be used. These systems might do well to address regional issues associated with technology use and factors related to electrical system security and reliability.
DOE staff and contractors made an effort to tease out the benefits of the CHP program that the panel was interested in (simple approach to estimating benefits), which made the panel’s work more manageable.
The panel reached the following conclusions on technical risks:
The best results of the DOE program will be realized where CHP exhaust heat is used for drying and baking food products, preheating combustion air for large conventional boilers, or inputting to spray dryers. The fuel cost per kilowatt-hour of CHP systems is lowest in these applications, and electrical efficiency is less critical. Equipment costs will be less also, as there is no downstream heat transfer.11
The economics of a conventional CHP system with an exhaust-heat water heater is more difficult. The cost is significantly higher, from the addition of the downstream heat transfer to the need for more installation engineering. Also, either a utility interface or a redundant unit is generally required.12
OBSERVATIONS ON THE PROSPECTIVE BENEFITS METHODOLOGY
The panel found the prospective benefits methodology and matrix framework to be workable and generally easy to understand. It found the application of the methodology to be valuable in helping to quantify the expected benefits of the end-use system integration and interface aspects of DOE’s CHP program. Nonetheless, the panel struggled with several key issues that required extensive discussion and additional information from DOE. While the overall efficiency and payback goals of the program are clearly stated, the CHP program strategies do not clearly align with the goals, making it more difficult to apply the methodology to the program. For example, the 70 percent system efficiency and the 4-year financial payback goals by 2008 are defined for different applications in different market segments. Goals might be met in one market segment sooner than in another. Also, without a clear cost goal (equivalent to a CHP system cost per unit of output), the payback goal is not well enough defined. The DOE articulation of goals made it difficult for the panel to consider assigning probabilities to technical achievement and market penetration. Also, because CHP penetration will vary depending on the relative costs of electricity and natural gas, as well as on electricity system constraints, probabilities were not easily assigned across the national market. The panel suggests that DOE consider setting a system cost goal (cost per kilowatt or per million Btu) rather than payback. The panel also suggests that the NRC consider applying the prospective benefits methodology to larger DOE R&D programs, not to subprogram components.
The panel decided to expand the benefits matrix to include a fourth scenario, Constrained Electricity, which it believes would more accurately capture the full benefits of DER technology generally and CHP in particular. Since the benefits of CHP are more regional than national, perhaps CHP program goals could be specified regionally, with applications focused on particular market segments in different parts of the country. This regional specification of the CHP goal would have greatly simplified the probability estimates of the expert panel members. In addition, the committee might consider selecting for review using its methodology DOE R&D programs that are national in scope and whose success is not highly dependent on where they are.
PANEL MEMBERS’ BIOGRAPHIES
Paul A. DeCotis, Chair, is director of energy analysis at the New York State Energy Research and Development Authority (NYSERDA), where he oversees statewide energy planning and policy analysis, corporate strategic planning, program evaluation, and energy emergency planning and response. Prior to joining NYSERDA, Mr. DeCotis was chief of policy analysis at the New York State Energy Office. He is the record access officer to the State Energy Planning Board and chair of the Interagency Energy Coordinating Working Group, made up of staffs of the New York state departments of public service, environmental conservation, transportation, and economic development, which is charged with preparing New York’s energy plan. He is also a member of the New York Independent System Operator (NYISO) Management Committee, the Business Issues Committee, and the Energy Working Group of the Coalition of Northeastern Governors (CONEG). Mr. DeCotis is president of Innovative Management Solutions, a management consulting practice, specializing in strategic planning and policy development, mediation, and organizational and executive management training and development. He is an adjunct professor in the MBA program at the Sage Graduate School and in the Public Policy Department at Rochester Institute of Technology, and was formerly at the School of Industrial and Labor Relations at Cornell University. He is currently on the board of directors of the Association of Energy Service Professionals, serving as executive vice president and U.S. Department of Energy experts review panel chair for the Weatherization Program evaluation. Mr. DeCotis was past
peer review panel chair of the U.S. DOE Federal Energy Management Program, and was also a member of the Committee on Prospective Benefits of DOE’s Energy Efficiency and Fossil Energy R&D Programs. He has a B.S. in international business management from the State University of New York College at Brockport, an M.A. in economics from the State University at Albany, and an M.B.A. in finance and management studies from Russell Sage College.
James W. Dally (NAE) has had a distinguished career in industry, government, and academia and is the former dean of the College of Engineering at the University of Rhode Island. Dr. Dally is Glenn L. Martin Institute Professor of Engineering (emeritus) at the University of Maryland at College Park. His former positions include senior research engineer, Armour Research Foundation; assistant director of research, Illinois Institute of Technology Research Institute; and senior engineer, IBM. Currently, he is also an independent consultant. Dr. Dally is a mechanical engineer and the author or coauthor of six books, including engineering textbooks on experimental stress analysis, engineering design, instrumentation, and the packaging of electronic systems, and has published approximately 200 research papers. He has served on a number of NRC committees and is currently on the Panel on Air and Ground Vehicle Technology for the Army Research Laboratory Technical Assessment Board and on the Committee on Review of Federal Motor Carrier Safety Administration’s Truck Crash Causation Study. He has a B.S. and an M.S. from the Carnegie Institute of Technology and a Ph.D. from the Illinois Institute of Technology.
Marija Ilić holds a joint appointment at Carnegie Mellon as professor of electrical and computer engineering and engineering and public policy, where she has been a tenured faculty member since October 2002. Her principal fields of interest include electric power systems modeling; design of monitoring, control, and pricing algorithms for electric power systems; normal and emergency control of electric power systems; control of large-scale dynamic systems; nonlinear network and systems theory; and modeling and control of economic and technical interactions in dynamical systems with applications to competitive energy systems. She is an IEEE fellow and an IEEE distinguished lecturer, as well as a recipient of the First Presidential Young Investigator Award for Power Systems. In addition to her academic work, Dr. Ilićc is a consultant for the electric power industry and the founder of New Electricity Transmission Software Solution, Inc. (NETSS, Inc.). From September 1999 until March 2001, Dr. Ilić was a program director for control, networks and computational intelligence at the National Science Foundation. Prior to her arrival at Carnegie Mellon, Dr. Ilić held the positions of visiting associate professor and senior research scientist at the Massachusetts Institute of Technology. From 1986 to 1989, she was a tenured faculty member at the University of Illinois at Urbana-Champaign, where she taught since 1984. She has also taught at Cornell and Drexel. She has worked as a visiting researcher at General Electric and as a principal research engineer in Belgrade. Dr. Ilić has coauthored several books on large-scale electric power systems. Dr. Ilić received her M.Sc. and D.Sc. degrees in systems science and mathematics from Washington University in St. Louis and earned her M.E.E. and engineering diploma from the University of Belgrade.
Lester B. Lave (IOM) is the Harry B. and James H. Higgins Professor of Economics and University Professor; director, Carnegie Mellon Green Design Initiative; and codirector, Carnegie Mellon Electricity Industry Center. His teaching and research interests include applied economics, political economy, quantitative risk assessment, safety standards, modeling the effects of global climate change, public policy on greenhouse gas emissions, and understanding the issues surrounding the electric transmission and distribution system. He is a member of the Institute of Medicine and a recipient of the Distinguished Achievement Award of the Society for Risk Analysis. He has a B.S. in economics from Reed College and a Ph.D. in economics from Harvard University.
Robin Mackay was the founder of Capstone Turbine Corporation in 1988 and served as vice president of marketing until he retired in 1996. He also served on the board of directors from the company’s inception until 2000, when it went public. Prior to that Mr. Mackay spent 24 years with the Garrett Corporation (later AlliedSignal Aerospace, now Honeywell), where he was director of industrial market development. He was responsible for the sale of several hundred gas turbine generator sets into cogeneration applications, as well as booking research contracts for advanced concepts such as microturbines, gas-turbine-driven air conditioners, closedcycle gas turbines, subatmospheric gas turbines, and gas turbines mounted on air bearings. Prior to that he spent 6 years with Boeing, where he sold, installed, and brought on line the first all-turbine cogeneration system using two 140-kW Boeing gas turbines in 1962. Mr. Mackay graduated from McGill University with a degree in mathematics and economics. He holds eight patents and has two pending. He has authored numerous papers for the SAE, ASME, AEE, and other organizations. The most recent is a paper entitled “High Efficiency Vehicular Gas Turbines,” presented at SAE’s Future Transportation Technology Conference in September. Mr. Mackay has a small company, Agile Turbine Technology, LLC, in Manhattan Beach, California. Agile cooperates with other companies who wish to use Mr. Mackay’s patents.
Ali Nourai received his doctorate in engineering from the Rensselaer Polytechnic Institute in 1978. He is a strategic technology consultant in American Electric Power and is responsible for distributed generation and energy storage
programs. During his 26 years of activities in the utility industry, Dr. Nourai has developed and applied many techniques to improve the energy efficiency and performance of power systems. He holds seven patents and has published a number of technical papers. He works closely with the energy storage program in DOE’s Office of Electricity Delivery and Energy Reliability and serves as a regular peer reviewer for the energy storage projects of DOE. He is a registered professional engineer in the state of Ohio and received the Walter Fee Award from IEEE’s Power Engineering Society for professional contributions and technical competence through significant engineering achievements.
Terry Surles is currently director for the Pacific International Center for High Technology Research. PICHTR’s activities focus on the demonstration and deployment of renewable energy technologies in Pacific island nations (PINs). These activities also include technical training and capacity building for PIN nationals for the operation and maintenance of renewable energy systems. Previously, he was vice president at the Electric Power Research Institute (EPRI) and its subsidiary, the Electricity Innovations Institute. Before joining EPRI, Dr. Surles was program manager at Public Interest Energy Research (PIER) and assistant director for science and technology of the California Energy Commission. Dr. Surles was the associate laboratory director for energy programs at Lawrence Livermore National Laboratory, following his time at the California Environmental Protection Agency as deputy secretary for science and technology. Dr. Surles was at Argonne National Laboratory for a number of years, holding a number of positions in the energy and environmental systems area, with his last position being general manager for environmental programs. Dr. Surles holds a B.S. in chemistry from St. Lawrence University and a Ph.D. in chemistry from Michigan State University. He was a member of the Phase One committee.
Gunnar Walmet has been with the New York State Energy Research and Development Authority (NYSERDA) for over 20 years. He has been the director of NYSERDA’s industry and buildings R&D programs since 1989. These two R&D programs helped companies implement dozens of innovative, energy-efficient, environmentally beneficial technologies and processes. Many of NYSERDA’s industry and building projects have resulted in patents and awards, including “The Best of What’s New” award by Popular Science, DOE’s National Award for Energy Innovation, and the Governor’s Pollution Prevention Award, as well as awards from such diverse groups as R&D 100, the National Center for Appropriate Technology, the American Society of Mechanical Engineers, Renew America, and the U.S. Environmental Protection Agency. The work has resulted in several new businesses, thousands of jobs created or saved, and tens of millions of dollars in product sales each year. Successful buildings R&D projects include creating the internationally renowned Lighting Research Center at Rensselaer Polytechnic Institute; developing the nation’s first non-ozone-depleting supermarket refrigeration and air-conditioning system; commercializing a pulse combustion boiler and a gas-fired hydronic boiler; developing several district heating systems; and innovative programs in demand reduction and real-time pricing. The industry program has been instrumental in developing a radio-frequency induction heating system, commercializing an adaptive controller for resistance welding, constructing the state’s first full-scale indoor fish-production facility, an academic center for remanufacturing technology, developing and demonstrating an environment-friendly paint booth for solvent-based coatings, and developing an optical lens system to monitor wafer contamination in semiconductor production. Under Mr. Walmet, NYSERDA has also implemented the nation’s most aggressive program to promote CHP, or cogeneration, and to demonstrate superconducting power systems. Prior to joining NYSERDA, he was an engineer at GE’s R&D Center and Medical Systems Division in Schenectady, where he helped develop a new membrane blood oxygenator for use in open-heart surgery, helped design the gas cleanup train for a pilot-scale coal gasifier, and developed biogas purifying systems. His research at GE resulted in 14 issued patents. In 2003 Mr. Walmet won national recognition from the American Council for an Energy-Efficient Economy, which named him a Champion for Energy Efficiency. He has an M.S.M.E. from Union College and a B.S.M.E. from Trinity College.