|
Items in cart [1] |
Questions? Call 888-624-8373 |
| ||||||||||||
| Copyright © 2009. National Academy of Sciences. All rights reserved. Terms of Use and Privacy Statement |
Below are the first 10 and last 10 pages of uncorrected machine-read text (when available) of this chapter, followed by the top 30 algorithmically extracted key phrases from the chapter as a whole.
Intended to provide our own search engines and external engines with highly rich, chapter-representative searchable text on the opening pages of each chapter.
Because it is UNCORRECTED material, please consider the following text as a useful but insufficient proxy for the authoritative book pages.
Do not use for reproduction, copying, pasting, or reading; exclusively for search engines.
OCR for page 95
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
OCR for page 96
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
OCR for page 97
97
//
U]
LU
LL
z
-
Ul
is:
Cat
in
_~
o
a'
sat
To
S 8 i
H
-
o
.~1
Sat
o
Sat
o
OCR for page 98
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 190°F (90°C). The 250°F (120°C) 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 350°F (150° to 175°C). 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
250°F (120°C) 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,
OCR for page 99
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
OCR for page 100
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.
OCR for page 101
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).
OCR for page 102
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.
OCR for page 103
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
OCR for page 104
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
OCR for page 105
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).
OCR for page 114
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
OCR for page 115
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
OCR for page 116
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 280°F; 120° to 140°C) 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).
OCR for page 117
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
OCR for page 118
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
OCR for page 119
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
OCR for page 120
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
OCR for page 121
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,
OCR for page 122
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 375°F (190°C) hot water, and 41°F
(5°C) 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 41°F (5°C), 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
OCR for page 123
OCR for page 124
Representative terms from entire chapter:
hot water
123
c
-
o
me
a_
I
auvA31noo Ol-~A1~( )
aUVA311108 CHINOS VANES
- ])r In/ ilr
onto AUlNnoD S313ONY SO] n I n R R n
only A~nOD 189~N
~ a_ --raw - 'nosmd 1 L
o
C!
in
In
flu
~ E
- He
Al C!
Z
O to
¢' U
mu
oo
!~§
o
W ~ X ~ W
2- ~ · ~ _
Ud O S ~ ~ ~ ~
L) ~ ~r ~ ~ O
o-
x
~o c: ~J
O CE L~ · · ~ O _
- g =0
Z ° 0
z m ~s m O Z O ~ Z
_ _ ~ ~ _ ~ ~ - ~ _ <
, ~ :3 ~C ~ ~ ~ r ~ c ~ ~ ~
Z Z Z ~ Z A c ~ O <: ~ Z Z
cu UJ ~ ~ ~ Lu O c ~ m ~ tu
O (_) ~ - ~ - ~ Z ~ cn
~ ~ ~ lO ~ ~ cr 0 - c~ ~ q
_ _ _ . _ _ _ ~, ~, c~ -, ~. -~
S~
o
z
4,,
c
~3
_ _
D -
- [o
~ _
C ~
O D
W
~_
LU C
r O c
~ ~0, _
c ~o
c
~ 3 ~,
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 375°F
(190°C) hot water, 41°F (5°C) 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
.
