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APPENDIX A Case Studies This appendix provides case studies of eight existing and planned district heating and cooling systems that are discussed in the report. Except where noted, the case studies have been drawn from the papers presented at the 1984 International Symposium on District Heating and Cooling. The case studies document the findings, conclusions, recommendations of the committee. They also illustrate and the range of district heating and cooling systems in the United States, the problems encountered in putting the systems into operation, and the solutions to those problems. In particular, the studies show the importance of leadership and the need to adapt district heating and cooling to local conditions. Each case study shows a different political, institutional, or technical approach to implementing district heating and cooling systems. The St. Paul case, for example, illustrates the strong leadership of a mayor, the Baltimore case that of a city planning department. Willmar, Piqua, Trenton, and Jamestown on the other hand, took different technical approaches. Finally, the Pittsburgh, Fairbanks, and Los Angeles cases represent different institutional arrangements. Several of the case studies contain cost comparisons of the technical options that might help others decide whether or how to ~ ~ ~ ~ Specifically, the case adopt a district heating and cooling system. studies discuss the following: o St. Paul Minnesota: A new hot water district heating system was developed by a not-for-profit company incorporated by the city, the state energy agency, and the association representing the building owners and managers. The new system replaces an older, investor-owned utility steam system. o Willmar, Minnesota: The first new medium-temperature, hot water district heating system was built by a municipally owned utility to replace an older steam system. 95

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96 o Piqua, Ohio: A municipally owned utility that operates a steam-based district heating system serving the central business district built a new hot water system to serve an industrial park, with an extension to serve single-family residences. 0 Trenton, New Jersey: A cogenerating district heating system operated by a for-profit corporation supplys high-, medium-, and low-temperature hot water in separate distribution loops to three different sets of users. o Jamestown, New York: An existing municipally owned electric utility was retrofitted for cogeneration with a closed-loop, two-pipe, hot water district heating system. O Baltimore, Maryland: A pr ivately owned and operated municipal solid waste incinerator uses recaptured heat for cogeneration of electricity and thermal energy in a district heating and cooling system. 0 Pittsburgh, Pennsylvania: The steam heating subsidiary of an investor-owned utility was acquired by a not-for-profit cooperative formed by the customers of the former system. o Fairbanks, Alaska: A new hot water district heating system was added to an existing and well-maintained municipally owned steam system to serve new customers. o Los Angeles, California: A new steam, hot water, and chilled water district heating and cooling system was developed and has been operated by the unregulated subsidiary of an investor-owned gas utility. So. PAUL, MINNESOTA One of the newest urban district heating and cooling systems in the United States is located in St. Paul, Minnesota. The District Heating Development Corporation (DHDC) was incorporated in July 1979 as a not-for-profit organization by the city of St. Paul, the St. Paul Building Owners and Managers Association (BOMA) , and the Minnesota Energy Agency (MEA). The system was designed to replace St. Paul's older steam system. DHDC's board of directors is chaired by the mayor of St. Paul. Board members include representatives of Northern States Power Company (NSP) , the local gas, electricity, and steam utility, and those of bu tiding owners, bus iness and labor groups, and the state government. Hans O. Nyman, former manager of the 800-MW system in Uppsala, Sweden, and then a consultant to the MEA, was selected as DHDC's president. The St. Paul market area consisted of more than 300 buildings downtown (Figure A-1. A survey of those buildings showed that 61 percent used natural gas, 31 percent were connected to the existing steam system, and 8 percent used oil or electricity. More than half used hot water for heating. The existing heat load was estimated at 245 MW. Planned development added another 40 MW, for a total of 285 MW. Government

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97 // U] LU LL z - Ul is: Cat in _~ o a' sat To S 8 i H - o .~1 Sat o Sat o

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98 and hospitals represented one-third of the building load and privately owned structures the remainder. Various heat sources are located within or near the project area. These include two coal-fired power plants, one now owned by DHDC. In addition, there are large boilers at the state capitol and in four nearby hospitals. Depending on the heating load growth, the turbine units of one coal-fired plant could be converted to cogeneration, possibly in the mid-1980s, to supply heat to the district heating and cooling system. The pipes will have a maximum pressure of 250 psi. The temperature of the water will vary depending on the outside temperature. During summer, when heating loads are small, the system's water temperature would be about 190F (90C). The 250F (120C) temperature selected for the system is designed to use waste heat captured through cogeneration. The St. Paul system will use a prefabricated steel pipe insulated with polyurethane and encased in a polyethylene jacket. Conversion of Building Heating Systems As a part of the St. Paul project, several studies were performed to determine the feasibility and cost of converting buildings to use a hot water district heating system (Table A-1. A main concern was the diversity of heating systems found in buildings in the central business district, many of which were connected to the old NSP steam system. This diversity resulted from the range in building sizes and ages--from new ones to those 90 years old. Therefore, the cost of conversion was one of the key economic and marketing issues facing St. Paul. The conversion design sought to achieve the best life-cycle cost rather than to minimize the first cost of connection to the hot water system, which would have required a year-round temperature of about 300 to 350F (150 to 175C). Such high temperatures could be used to heat buildings with existing steam distribution systems. This would lower initial costs, but would leave St. Paul with a district heating system that was less eff icient and more difficult to control. The system would also have higher maintenance costs than a medium~temperature, hot water system. Therefore, St. Paul decided to limit its hot water temperature to 250F (120C) to reduce the construction and operating costs of the system, to convert the distribution network to a hot water thydronic) system economically, and to replace outmoded equipment. The conversion cost studies indicated that buildings that supplied hot water to the perimeter heating system, air side systems, or both would be converted the most economically to a med. ium-temper ature system. The average unit conversion cost for such systems is $40 per kW(th). In contrast, heating systems with steam supplied to the perimeter have the highest unit conversion cost, from $140 to $400 per kW(th). The uncertainty of the conversion costs for such buildings,

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99 TABLE A-1 Preliminary Studies for the St. Paul District Heating System Date Study Developments January 1979 Federal-state study finds positive indications for hot water district heating in St. Paul. July 1979 DHDC was formed to coordinate further development. August 1979 Heat load surveys began. March 1980 Building conversion studies were under way. May 1980 Initial heat load projections were completed. July 1980 Preliminary economic feasibility study was underway. September 1980 Building conversion and conceptual piping design reports were finished. November 1980 Preliminary economic feasibility study was completed. SOURCE: District Heating Development Corporation. as evidenced by the range of costs found in the survey, indicate that individual building surveys and cost estimates are necessary to establish the conversion costs for specific buildings or customers. Therefore, design assistance to potential customers should be considered part of the marketing phase of implementing such a system. The investment in a new system such as St. Paul's may require incentives to encourage building owners to make adaptations. However, owners benefit from modernizing existing heating systems because the more efficient hydropic systems reduce energy consumption. Information on converted buildings and studies of potential conversions from steam to hydropic systems document 10- to 20-percent energy savings. Additional energy savings of 20 percent can be realized when conservation features are included in building system conversions. As a part of its marketing program, DHDC developed a computer program to analyze the annual cash flows for current customers of

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100 steam and natural gas. The program calculates the cumulative cash flow after a customer hooks up to the DHDC system. A five- to seven-year payback period, based on the time for a positive cumulative cash flow to occur, is considered the target for positive customer response to the investment risk in building conversion. The results of the analysis show that the five- to seven-year payback criterion is met for all current natural gas customers even if unit conversion costs are as high as $275 (1980 dollars) per kW(th). For current steam customers, the payback period criterion is met if a high unit conversion cost of $275 per kW(th) of demand results in 25-percent or greater energy savings, or a moderate conversion cost of $175 per kW(th) results in 5-percent or greater energy savings. Financing The preliminary economic feasibility study was completed in November 1980. This study indicated that a hot water system using proven design principles could be built at reasonable cost and financed at the then-current interest rate for tax-exempt revenue bonds of 10 percent given a customer load of 165 MW, or about 60 percent of the potential market in the initial service area. DHDC financed the study phase of the project, which cost more than 83 million (Figure A-2), with more than $1 million in assistance from the Department of Energy. By January 1981, DHDC was entering its initial marketing phase. The plan was to explain the economic advantages of a hot water system to the local customers and get enough of them to sign binding 30-year contracts, while simultaneously completing the final system design, selling bonds, and beginning construction by the fall of that year. First, customers were not as eager to sign up as expected. Despite high steam rates and the dim future for NSP's decrepit steam system, most steam customers were not ready to invest in the building retrofit necessary to connect to the new system. Gas and oil users, despite rapidly escalating fuel prices and the memory of recent supply shortages, were even more reluctant to sign up for hot water service. By the fall of 1981, only 8 customers representing a total of 14 MW had signed contracts for the hot water system. As these marketing difficulties were being encountered, bond interest rates soared to record highs, reaching more than 14 percent by October 1981. This both delayed the adoption of a workable financing plan and contributed to marketing problems, keeping customer commitments below those needed to make the system work. Given these problems, many people thought the St. Paul hot water system would never get off the ground. But a small group of believers managed to keep the project going and to find solutions that made construction possible.

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USES ($000) SOURCES ($000) In-Kind Contributions $180 Interest Income ~ and Misc. 46K r Lease Revenues $252 ~ 101 System Design $957 - ~ lima nanemQnt Mel /: \ \ IRAQ// \ I merest $88 / NSP Grant $500 Cash . _ . . _ ~ ~ , Legal, and Other Consultants $912 Depreciation $289 State G rant $111 ~-T . ~ Admin. Costs $170 - - - - - - Federal Grants $1 ,001 City and State \/ Loans $960 Bidg. Conversion / $252 ~ Economics / X $165 \ FIGURE A-2 St. Paul District Heating Development Corporation development funding, 1979-1982, in thousands of dollars (totalling $3.05 million) (District Heating Development Corporation).

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102 Because of DHDC's nonprofit structure, an important element of financing the St. Paul project was the assumption of risk by its customers. It was known from the start that this would be necessary to obtain the required "A" rating on a stand-alone bond issue, and this was communicated clearly to prospective customers. In shifting risks to customers, the orig inal DHDC service contract went to great lengths to tie the customer to specific obligations and requirements while preserving maximum operating flexibility for DHDC. As marketing efforts proceeded, however, it became clear that this approach could not be sold to enough customers to make the system feasible. Therefore, in the fall of 1981, DHDC began detailed negotiations with a committee of BOMA to develop a new service agreement, which would be more marketable while still providing the necessary security for the bonds to finance construction. After long and difficult negotiations, DHDC and BOMA reached a new agreement in May 1982. By July, customers representing 83 MW had signed contracts, and by September 30, 1982, the revised feasibility target of 135 MW had been exceeded. The new customer contract was only one of the factors that made this success possible, however. Another major factor was that interest rates were finally declining, increasing confidence in the system's feasibility. Financing improvements affecting both the system and the customer conversions made a major difference in how customers viewed the system' s economics. Besides the unacceptability of the orig inal customer contract, another problem made clear during initial marketing was the inadequacy of the financial assistance available to customers for converting their building heating systems. Conversion costs were a significant deterrent for many customers, especially for those who owned older buildings heated by steam systems. The preliminary economic feasibility study had proposed a conversion loan program funded through bond issues by the St. Paul Port Authority. However, high interest rates and bad economic conditions made even the below-market-rate loans from the St. Paul Port Authority prohibitively expensive for many building owners. This problem was particularly acute for the nonprofit organizations owning buildings in the market area, including cultural facilities, social service agencies, and several large hospitals. In late 1981, the mayor of St. Paul asked the St. Paul Foundation to put together a program to provide the missing financial assistance for nonprofit customers. Based on studies of the feasibility and the economic benefits to the customer of both conversion and other energy conservation measures, the St. Paul Foundation created an Energy Reinvestment Fund in the spring of 1982, funded by S2.6 million in grants and long-term loans from a variety of foundation and corporate donors. Under this program, nonprofit organizations signing hot water contracts could receive funding to ensure that their cash positions were at least as favorable after conversion as if they had not converted.

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103 As the program entered the "home stretch," however, even all these resources were not sufficient to make the project viable. As the inflation rate continued to fall through 1982, reducing the projected price escalation of competing fuels, it became necessary to lower the proposed system's target rates to maintain the competitive advantage in payback projections. With long-term revenue bond rates remaining above 10 percent, this could not be dorm without major changes in the financing structure for the project. Throughout the development of St. Paul's district heating project, city government support was essential. The mayor made energy conservation a prime focus of his administration and, as chairman of DHDC, worked to provide the necessary elements for the successful development of the new system. The city took the lead in convincing the U.S. Department of Housing and Urban Development (HUD) that the project could significantly contribute to local economic development and, at the same time, could demonstrate nationally the usefulness of district heating and cooling as a catalyst for economic development. In August 1982, when it became clear that lower prices for competitive fuels and reduced hot water demand would require significant improvements in financing, the city developed a flexible repayment plan to make the financing work. The final element needed to complete the financing was a letter of credit to support the floating-rate bonds. This was required both to provide the needed liquidity for the ongoing remarketing of the bonds and to ensure a high rating of the issue. The First National Bank of St. Paul provided a "AA"-rated letter of credit on favorable terms. While the project could not have succeeded without the support of all the groups mentioned above and that of many more, it was the project team that kept the project alive through setback after setback. Despite sometimes overwhelming problems, the team proceeded because the consequences of failure--abandonment of the district heating tradition in St. Paul and loss for the foreseeable future of the benefits of a central heating system--were more severe than the obstacles. In demonstrating the final economic feasibility of the project, DHDC worked with the Gilbert/Commonwealth consulting firm of Reading, Pennsylvania. The firm had direct experience and a matter-of-fact, open-minded approach to the economic structure and feasibility of the project. The changes in rate formulas negotiated with BOMA were incorporated smoothly into the financial model, as were subsequent changes in the financing structure. The emphasis was on accepting the unique realities of the St. Paul situation rather than trying to make those realities conform to abstract notions of standard utility practice. Underwriting by E. F. Hutton and Company, and by Piper, Jaffray, and Hopwood, combined access to innovative financing techniques being developed in New York with a solid knowledge of local conditions, including the degree of local commitment to the project. Hutton provided the concept and structure for the floating-rate bonds, the

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104 central feature of the final financing. Piper, Jaffray, and Hopwood provided local support during the long period when the project's future was in doubt and vital help in developing the final combination of subordinated financing approaches that, together with the floating- rate bonds, made the project work. How the Financing Works The largest element of St. Paul's financing plans (Figure A-3) was the sale of $30.5 million in 30-year tax-exempt revenue bonds through the St. Paul Housing and Redevelopment Authority tHRA). For the debt service to be reasonable, a way had to be found to reduce the effective rate paid by DHDC to less than 10 percent. This was done, first, by reducing the total amount of bonds through increased subordinated financing and, second, by adopting the insured floating- rate bond structure developed by E. F. Hutton. Under this structure, DHDC is guaranteed an effective bond rate of 8.625 percent. A portion of this amount goes each month to the holders of the bonds and the rest to the participating insurance company as a premium. If the interest rate to the bondholders ever exceeds 8.625 percent, the excess is payable by the insurance company. Currently, because these bonds can be sold back at par on short notice and thus trade like short-term rather than long-term investments, they bear interest of about 5 percent. The floating-rate bonds are backed by a letter of credit from the First National Bank of St. Paul, with participation by the First National Bank of Minneapolis and the Northwestern Banks of St. Paul and Minneapolis. The second element of the St. Paul financing is the Urban Development Action Grant (UDAG) funding. This consists of $7.5 million granted to the city by HUD and an additional $2.3 million in matching local funds. The total $9.8 million is loaned by St. Paul to DHDC at 5 percent interest. Interest compounds for 10 years before repayment is required to begin. The term of repayment, originally 10 years, was lengthened to 20 years to enhance the competitiveness of hot water rates. The third and final element of the project financing is the $5.5 million "equity loan" provided by St. Paul. As the name implies, this funding replaces equity in the sense that it bears no interest and is repaid flexibly as allowed by project revenues. This funding provides a "flywheel" effect, reducing the impact of short-term cost pressures on system rates and virtually ensuring that customers will enjoy lower rates than can be achieved with competitive fuels. Conclusion Despite the difficulties involved in bringing to fruition such a project, the city of St. Paul is expediting development of the

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USES ($000,000) SOURCES ($000,000) Piping System $24.51 \ Revenue /, Bonds ~ $30.5 \ 105 \ \ - Other Development and / Startup Costs $3.98 /\ Interest During Hi< Construction $3.75 / Financing Costs V and Reserves . ~$6.18 Heat Sources $6.64 City Equ ity Loan , $5 5 /City / ,,' of,''' \ Equipment $0.74 >N UDAG Loan $9.8 - - / HUD FIGURE A-3 St. Paul District Heating Development Corporation system financing, in millions of dollars (totaling $45.8 million) (District Heating Development Corporation).

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114 representing more than 90 percent of the heat load. Most prospective customers now use steam heating. The conversion of the terminal heating units to use hot water constitutes a significant part of the conversion work. The total cost of converting the l9 buildings to hot water is estimated at $954,000, including direct costs for all material, equipment, labor, contractor's overhead and profit, engineering fees, and a contingency fund. A 20-year economic analysis was performed for each of the l9 customers to determine their annual cash flows and payback periods. Total retrofit costs were estimated in 1985 dollars and an annual loan payment was determined for each customer based on the percentage of the retrofit cost financed and the financing terms of a 9-percent loan for 15 years. The customer's average cost of gas ($5.68 per million Btu from the National Fuel Gas Distribution Corporation in January 1984) was escalated at 7.5 percent per year. The customer's annual energy costs with district heating were determined based on current consumption, current boiler efficiency, potential end-use energy savings, and the calculated unit cost of the system. Potential end-use energy savings for present steam users are achieved by eliminating trap losses and decreasing line losses. The customer's yearly tax effects were calculated based on tax rate, depreciation, interest payments, energy costs, and the expensing deduction. The Internal Revenue Service allows a one-time, $5,000 expensing deduction and an accelerated five-year depreciation on heating equipment. Annual costs for energy, financing, and taxes were used to determine the annual savings for customers switching to the system. Two payback periods were calculated: a traditional payback period assuming no financing, and a payback period with f inancing, which would be achieved when the accumulated savings exceed the unpa id principal and any cash investment. In all cases, the payback period for the l9 core customers is expected to be three years or less, with a positive cash flow in the first year. Economic Analysis The economic analysis presumed ownership by the Jamestown Board of Public Utilities. The required revenue approach was used to determine the necessary customer rates. Total system costs were calculated and compared with the total quantity of heat sold to determine the minimum customer rate. Total system costs include fixed and operating expenses, replacement electricity, and gross receipt taxes. Calculated capital costs include all direct and indirect costs associated with the power plant retrofit and the piping systems. The annual carrying charges for the system investment were calculated based on LOO-percent debt financing with bond rates of 7 percent and 9.75 percent. A bloating fixed bond is being considered

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115 to finance the project, which could result in a 7-percent bond rate. The utility pays no income or property taxes, and its endurance rate is 0.5 percent. The analysis was conducted for a 30-year life cycle. The replacement electricity costs are charged against the system to compensate for the reduction in electrical output caused by the retrofit. Replacement electricity costs are $42/MWh. Pumping costs are calculated at $30/MWh. Power costs are escalated at 7.5 percent per year. Annual costs of operating and maintenance materials are estimated to be 3 percent of the capital costs of the heat source and 1 percent of the capital costs of piping, escalated at 7.5 percent annually. Steam costs are calculated at S2.07 per thousand pounds in 1984 dollars, escalated at 1 percent per year. The quantities of replacement electricity, pumping power, and steam were determined from the load duration curve. Tables A-3 and A-4 show the cost of district heating for a $3-million capital investment in the power plant and piping (in 1984 dollars), financed through 7-percent bonds. The estimated first-year cost to the district heating customer is $8 per million Btu delivered. This compares favorably to the $5.68 paid for gas in January 1984, when the inef f iciencies of the customers' existing thermal system are considered (i.e., annual boiler efficiencies and losses from steam lines and traps). At 70-percent annual system efficiency, the district heating rate is competitive with the rate for gas. The spread between the two will grow in the future, insofar as gas prices rise as they are expected to--more rapidly than the price of coal. Several factors contribute to the attractive costs of district heating for Jamestown. These include an existing coal-fired facility that will cogenerate electricity through a low-cost power plant retrofit, municipal ownership that results in attractive bond rates, high annual use because of several large customers with good load factors, cold winters (7,900 heating degree days), relatively few underground obstacles, and low-cost retrofit for steam customers. BALTIMORE, MARYLAND Baltimore has had a district heating system in the downtown business area since the early laces. The system, which was until recently owned and operated by the Baltimore Gas and Electric Company (BG&~), has had approximately 600 customers since 1978. A moratorium on new customers was instituted at that time. Unfortunately, this was also a time of rapid and extensive redevelopment of Baltimore's inner harbor area. BG&E's moratorium forced new buildings in the area to invest in individual heating and cooling facilities, and many potential customers for the steam system were lost. For a variety of reasons, including highly seasonal steam sales, reliance on expensive natural gas and fuel oil, and lack of provision for condensate return, BG&E began looking for ways to leave

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116 the district heating business to concentrate on their other products, natural gas and electricity. In 1973 BG&E contracted to purchase steam from the Baltimore City Pyrolysis Plant, which had been built as part of a research and development effort sponsored by the U.S. Environmental Protection Agency. Steam produced from solid waste was purchased and used in the downtown system. This arrangement could have provided energy from a plentiful and renewable fuel, but the pyrolysis plant proved to be very unreliable and closed in 1981. A decision was made in 1980 to replace the pyrolysis plant with a larger, more reliable waste-to-energy facility, using the same site and proven mass-burning technology. As would be expected, the Northeast Maryland Waste Disposal Authority approached BG&E concerning energy sales, with the hope of renegotiating or reinstating the steam sale agreement that had been in effect during the years of the plant's operation. Unfortunately, since BG&E wanted to leave the steam business, it did not offer a thermal energy price sufficient to make the waste-to-energy economics work. While the principal source of income for the waste-to-energy project comes from disposal fees, energy sales are needed to make disposal fees competitive. Project economics were more favorable if the facility produced electricity for sale. Because additional waste disposal capacity was needed in the Baltimore region, other options, such as the authority's purchasing the downtown district heating system from BG&E or developing other thermal markets, were not explored in detail. At that time, the authority and local governments were mainly concerned with ensuring that a waste disposal facility was operational. However, the authority saw an opportunity for thermal energy sales, so the project's contractual structure was written to allow thermal energy sales later. Project Identification As one of the original 28 cities in HUD's district heating and cooling assessment program, Baltimore began to look at district heating opportunities in 1981. Under the direction of the city's planning department, a panel of interested agencies identified two "early start" systems that would provide a basis for expanding and developing district heating in Baltimore. Both involved large institutional users as "anchor" customers. Both projects included the southwest facility as a thermal source. The Cherry Hill system involved the sale of medium-temperature hot water (250 to 280F; 120 to 140C) directly from the southwest facility to a variety of users in the Cherry Hill and Westport areas of South Baltimore. The anchor customers were identified as the 1,600-unit Cherry Hill homes and C. K. Anderson public housing projects (collectively known as the "Cherry Hill homes") operated by the Housing Authority of Baltimore City tHABC).

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117 In addition, six public schools, the South Baltimore General Hospital, private housing, and a proposed industrial park were identified as potential customers. The Hopkins-East Baltimore system was the second system studied. It would expand the existing downtown distribution system to serve adjacent customers. Its identified anchor customers are the more than 2,000 units of public housing in the Central Avenue housing project, the Johns Hopkins University Hospital, the Baltimore city jail, and the Maryland state penitentiary. The U.S. Post Office, public schools, very dense private housing, and other public housing offer additional opportunities. In this case, a steam system would be used from either a new thermal facility or an extension of the BG&E system. Steam from the southwest facility would be moved through the BOSE system to customers. In August 1982 Baltimore applied for and subsequently received one of the original HUD Phase II assistance awards to continue developing district heating opportunities identified under the original program. Because of the institutional and technical complexity of the Hopkins-East Baltimore system, the city and its project team decided to concentrate on implementing the Cherry Hill system first and to refine the Hopkins-East Baltimore project concept with an eye toward future implementation. Project Team Organization Certain factors are required in implementing any kind of district heating system. In Baltimore, many important factors were present in Cherry Hill. One was the difficulty the Housing Authority of Baltimore City experienced with its established district heating system serving Cherry Hill. The system was very old and HABC was exploring ways to correct its problems. At the same time, Baltimore Refuse Energy System Company (RESCO) and the Solid Waste Authority were looking for markets for excess thermal energy produced by the southwest facility, and Baltimore was interested in promoting district heating to encourage development and improve the quality of services to institutional facilities in the city. In addition, the Solid Waste Authority and Baltimore RESCO, through the southwest facility project structure, represented a convenient institutional approach for developing, financing, and operating such a system. During the second phase, Baltimore asked the Solid Waste Authority to coordinate the implementation of the Cherry Hill system. Drawing on experience in implementing the southwest facility, the Solid Waste Authority put together a project team, which included all parties to the project. Key decisions were made by the two primary project participants, HABC and Baltimore RESCO, early in developing the system. These decisions were supported by the technical, economic, and financial

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118 experts in each organization and by the project team. HABC decided to replace the Cherry Hill's steam distribution and in-building heating system with hot water district heating and to renovate the existing oil-fired central boiler plant. Baltimore RE8CO decided to install an extraction turbine at the southwest facility, which could provide hot water at the appropriate temperature and in the appropriate quantity to the potential customers in Cherry Hill. For the Cherry Hill project, the Solid Waste Authority organized multidisciplinary teams to implement the facility, an approach it had used successfully in other projects. A number of working groups were set up to coordinate the technical, economic, legal, and institutional work. These groups were intended to continue in existence throughout the project. The involvement of individual team members would depend on the specific needs of the task at hand . Project Development There were two particularly interesting obstacles to implementing the Cherry Hill system: the allocation of benefits to project participants and the question of if and when a thermal energy supplier becomes a regulated public utility. Three parties should benefit from the Cherry Hill district heating system: HABC, Baltimore RESCO, and those who dispose of wastes at the southwest facility. The project team seeks to provide potential participants with the benefits needed to convince them to participate in the project. However, the benefits are obvious for only two of the parties. Baltimore RESCO requires revenue from the sale of thermal energy sufficient to offset its expenses and liabilities and to provide a reasonable return on capital investment. Those disposing of waste expect a portion of the revenue from thermal energy sales to be credited to them in the form of reduced disposal fees (somewhat as they share revenues from the sale of electricity with Baltimore RESCO). The major difficulty in allocating benefits to these two parties is in defining how much benefit each is entitled to. The allocation of benefit to HABC is a different matter. In deciding to reconstruct Cherry Hill's central heating system to convert it from steam to hot water, HABC is implementing a system that is more efficient and therefore less expensive to operate and maintain than the old one. Economic analysis has shown that an oil-fired, central hot water heating system can save money compared with individual gas boilers in each building or continuing the existing steam system. In addition, HABC could realize additional savings by contracting with Baltimore RESCO to guarantee the provision of energy to Cherry Hill. The use of refuse to produce energy, particularly through cogeneration, gives Baltimore RESCO some leeway in what it must charge per unit of energy. There is also leeway in how the price of energy

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119 might escalate over time. For example, Baltimore RESCO could offer HABC a discounted price for energy (compared to current energy production costs) and also some discount from the escalation rate of the alternative fuel over the life of the contract e This purchase of thermal energy from Baltimore RESCO would allow HABC to shut down its central heating plant. In fact, the central heating plant could be sold or leased to Baltimore RESCO for use as an emergency heat source, which would provide additional revenue to HABC. Under current HUD policy, HABC will benefit from the conversion to a new hot water system because Cherry Hill will use less energy than if it relied on the old steam system. Since total energy consumed will be lower, both HUD and HABC will benefit. HABC will also benefit from reduced operation and maintenance costs for the new hot water system. Current HUD rules, however, do not allow housing authorities to benefit from switching from high-cost fuel to lower-cost fuel; in this case, from oil to refuse. What this policy does, in this particular instance, is to direct benefits to certain parties, since HABC can only receive a relatively small benefit (related to the operation of the central boiler facility and efficiencies inherent in the new distribution system). The major benefits must be divided between Baltimore RESCO and subdivisions represented by the Solid Waste Authority. The situation for other customers who will be added to the new system is not the same, since savings from lower-cost energy can be taken directly. In the instance of Cherry Hill, the housing authority's situation is not as detrimental to implementing the project as it may seem. Even though HABC's direct monetary benefit is marginal compared to what it might be, indirect benefits can be obtained. One is that HABC will not have to operate the central heating plant. In addition, the money saved by using lower-cost fuels could be used to reduce the waste disposal fees at the southwest facility. In this way, all Baltimore residents would share the benefits of the new district heating system. Utility Regulation Another obstacle to the Baltimore project is the regulation of sources of thermal energy by the Maryland Public Service Commission (PSC). The PSC regulates "all public service companies . . . engaged in or operating in the utility business in this state . . . ." Preliminary legal opinion indicates that the decision whether to regulate a company as a "public service company," according to Maryland law, relies heavily on the number of customers the company serves. To a company in the waste-to-energy business, like Baltimore RESCO, PSC regulation is not desirable. The company's main activity is disposing of solid waste by using it to produce energy for sale. Sale of electricity to a single customer, in this case BG&E (a regulated utility), presents no undue hardships and allows Baltimore RESCO to

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120 concentrate on disposing of wastes and producing energy. In trying to use the energy value of the waste more fully through cogeneration, Baltimore RESCO does not want to stray far from its primary business. A district heating system serving a limited number of large institutional users is perfect for this scenario. As noted earlier, the Cherry Hill system could include a variety of customers in addition to HABC. These customers include public schools, a hospital, private housing, and a proposed industrial park. The preliminary legal opinion is that the sale of thermal energy to two institutional users (that is, HABC and public schools) would not open Baltimore RESCO to PSC regulation. Sale to private housing or an industrial park, on the other hand, would virtually ensure regulation. To work within this strict interpretation of "public service company," the project team is structuring the Cherry Hill system to include only large institutional users initially, but with the ability to serve all identified Cherry Hill customers. Once the basic system is in place, the project team will attempt to secure an agreement with a regulated utility or company willing to use the thermal energy available to the system to serve the additional customers. The logical entity for this venture would have been BG&E. However, BG&E corporate policy is to concentrate on providing gas and electric utility service and to end its steam business involvement. To this end, BE&E has agreed to sell its downtown steam system to Thermal Resources of Baltimore, Inc. Discussions have been held with Thermal Resources concerning sale of steam from the southwest facility for use in the downtown system. Since this company is interested in expanding district heating in Baltimore, using the downtown system as a base, it may agree to develop the Hopkins-East Baltimore system or to expand the Cherry Hill system to the other identified customers in the area. PITTSBUK;H, PENNSYLVANIA The Allegheny Steam Heating Company, a subsidiary of Duquesne Light, operated a steam system that served buildings in downtown Pittsburgh. The oil-fired system was experiencing high losses in the distribution system, a situation common to many older systems. Owing to the system's energy sources and conditions, the price of steam to the customers increased to more than $20 per thousand pounds. This was one of the highest rates for district heating in this country. The building owners served by the system were obviously concerned by its cost. As a result they investigated the feasibility of purchasing the steam system and operating it themselves. Based on system evaluations, the building owners' group decided that it could operate the system as a cooperative, using natural gas, more effectively than the existing utility. On June 1, 1983, Pittsburgh Allegheny County Thermal, Ltd. (PACT), a nonprofit cooperative, officially took over most of the downtown Pittsburgh steam system. The system is a true cooperative in that

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121 each of the 150 customers pays based on individual usage and the direct cost of natural gas. The system that once charged more than $20 per thousand pounds now charges $13 per thousand pounds, plus the fuel adjustment. The system was sold for $1. This allowed Duquesne Light to sell an unprofitable operation to a group that needed a viable steam utility. PACT has installed new gas-fired package boilers in an unused part of a Duquesne Light boiler house, which PACT leases. PACT is responsible for operations and has established a capital improvement program to improve the efficiency of the system. FAIRBANKS, ALASKA Fairbanks, Alaska, added a new hot water district heating system in 1982 to its existing and well-maintained steam system, which was built in 1905. The initial 12,000-foot (3,660 m) hot water loop began service to a school, library, and swimming pool complex that year, using 16 to 18 MBtu/h of the loop' s 70-MBtu/h capacity. The Fairbanks system was expanded in 1983 to connect six additional customers located along the route. To facilitate customer hookups, 3-inch (7.6 cm) service taps and 6-inch (15.2 cm) service tees were installed during the initial installation of the 10-inch (25.4 cm) hot water loop. The new connection lines have now been installed for the six additional residential hookups, three of which are in operation. These are a triplex, the two-story First Lutheran Church of Fairbanks, and the three-bedroom parsonage. With respect to the remaining three, the city utility is awaiting receipt of final plans regarding how the structures will be connected to the system. Under the process used in Fairbanks, customers who have agreed to join the system have 90 days from the date when the service loops are installed to their buildings to complete the connection. The plans submitted by the building owner for city approval must show both the configuration of the in-building heating system and the plan for the district heating system hookup. This is done to ensure that connections are of high quality and to preserve the integrity of the entire system at the minimum service charge whether the connection is completed or not. Thus, the customers have an incentive to complete their connections. Of the new connections, five will use radiant heat and one will use hot water with an existing forced-air distribution system. Planning is now in progress for the next construction season, which will start in April. Negotiations are currently under way between the utility and the school system to add another school to the loop. Three potential routes for the added spur are under study, with potential to add additional customers along the route. Expansion beyond those buildings now under discussion will hinge on increasing the heat-generating potential of the coal-fired boilers,

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122 which currently provide the $6-per-million-pound steam for the downtown system and for the new, expanding hot water loop. LOS ANGELES, CALIFORNIA Started in 1965 as part of the development of the Twentieth Century Fox back lot, the Century City "central plant" system shows how district heating and cooling can help spur urban redevelopment. In the 1.5-square mile (3.8 km2)area, the Century City central plant supplies 150-lb steam, or 375F (190C) hot water, and 41F (5C) chilled water to the 18 high-rise buildings within the complex (Figure A-6. The Century Plaza Hotel uses steam for its laundry, kitchen, and other uses. It is the system's only steam customer. The other buildings, which include office towers, condominium apartments, an entertainment center, retail stores and shops, and a medical center, all receive hot water. Cooling is provided through a 41F (5C), chilled-water distribution system to all buildings. The sources of the chilled water are two 7,500-ton, 20,000-gal/min steam-driven centrifugal chillers. In addition, four absorption units (two of 1,000 tons, two of 750 tons) provide a base of constant chilled water production, which at times can supply the off-peak air-conditioning demand. Two additional but smaller centrifugal chillers bring the plant's total air conditioning capacity to 25,000 tons. The current peak air- conditioning load reaches 17,000 tons. Creative innovations have been used to produce the 150-lb steam needed to power the absorption units, which are always operating. These include steam generation from boilers that heat water, which were built into the exhaust and muffler system of the gas-fired engine used to drive the high-capacity water pumps, and the extraction of steam from the two condensing turbines and one back-pressure turbine, which drive three of the four centrifugal chillers. (The fourth chiller, supplied by Carrier, is electrically driven). Two 600-lb/h turbines provide most of the steam generated to drive the chillers. They also provide the steam and hot water for the heating loop, where average demand is 40 million Btu/h. Two smaller boilers, rated at 300-lb pressure and capable of producing 80,000 lb/in, provide backup. They can supply both the hotel's steam and the system's hot water needs while driving the one back-pressure turbine chiller. History The Century City district heating and cooling system is one of seven operating in Southern California. Century City and other operations result from the Pacific Lighting Corporation's desire to diversify its operations. Among its holdings, Pacific Lighting owns the Southern

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124 California Gas Company. Central Plants, Inc., was established as a Pacific Lighting subsidiary to build and operate nonregulated district heating and cooling systems. The Century City system is the largest of the seven. is the Bunker Hill plant in downtown Hill Redevelopment Area. There, major customers of this 375F (190C) hot water, 41F (5C) chilled water, system include the Bonaventure Hotel, Bunker Hill Square apartment complex, the 52-story Security Pacific Bank Tower, and the Union Bank Square Development. Like Century City, the Bunker Hill project was carried out with a redevelopment effort that totally cleared the land. In Century City, the fact that the Alcoa Corporation was developing the area in open land facilitated the development of the district heating and cooling system. Next in size Los Angeles, serving the Bunker _ _ The first two structures built in Century City were built with self-contained heating and cooling apparatus. After that, Central Plants, Inc., proposed a district heating and cooling system. The developers liked it because, in addition to the system's efficiency, the building owners realized the benefits of not having to buy and install expensive boilers and chillers, thereby ~~ Today, the Century lowering maintenance costs and manpower demands. City facility operates efficiently with a total crew ot 17. Century City is still growing, as is its district heating and cooling system. A new hotel annex currently under construction adjacent to the Century Plaza Hotel. The new hotel has already been connected. Manholes and service tees are also in place to service a planned high-rise apartment building .