Engineering Assessment – Denver District Steam

Exhibit No TMF-9
Page 1 of 37
Engineering Assessment – Denver District Steam System
Colorado PUC E-Filings System
Prepared By
Public Service Company of Colorado
Engineering and Construction
March 15, 2013
Exhibit No TMF-9
Page 2 of 37
Table of Contents
Table of Contents __________________________________________________________ 2
1.
Overview _____________________________________________________________ 3
2.
Assessment of the current condition of the Denver District Steam System _________ 4
a.
b.
i.
ii.
iii.
1.
2.
c.
i.
ii.
1.
2.
iii.
iv.
1.
2.
Summary ______________________________________________________________________4
Overview of Steam Generation _____________________________________________________5
Steam supply capacity and reliability _________________________________________________5
Historical overview of steam production operations _____________________________________6
Steam system operations and maintenance practices _____________________________________8
Pressure Vessels _________________________________________________________________9
Piping ________________________________________________________________________10
Production and Distribution Facilities _______________________________________________10
Zuni Station ___________________________________________________________________10
Denver Steam Plant _____________________________________________________________11
Maintenance practices at DSP have been robust _______________________________________12
DSP package boiler replacement versus Sun Valley ____________________________________14
State Steam Plant _______________________________________________________________14
Distribution System _____________________________________________________________15
The condition of the distribution system and ongoing maintenance ________________________16
Building interconnections_________________________________________________________21
3. Future Capital Investment and O&M Expenditure for the System (5 year, 10 year,
and 20 year) _____________________________________________________________ 21
4.
Efficiency of district steam versus self generation by customers ________________ 25
5. Water use: Public Service steam distribution system versus customer owned heating
system.__________________________________________________________________ 26
6.
Environmental emissions of central plants versus customer owned generation____ 28
7.
Conclusion __________________________________________________________ 28
2
Exhibit No TMF-9
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1. Overview
The Colorado Public Utilities Commission (“Commission” or “CPUC”) in Decision
No. C13-0174-I directed Public Service Company of Colorado (“Public Service” or the
“Company”) to provide additional information regarding the long-term viability of the
Company’s district steam business in support of its application for a certificate of public
convenience and necessity (“CPCN”) for its proposed Sun Valley Steam Center (“Sun
Valley”) and for approval of its proposed regulatory plan.
This assessment (“Report”) provides certain of the information directed by the
Commission in Decision No. C13-0174-I with respect to the engineering assessment of the
steam generating and distribution facilities, a description of the viability of the steam system
as a whole, and a forecast of the capital investments and operating and maintenance
expenditures to maintain steam utility service to customers over the next 5, 10, and 20 years.
In addition, this report contains information regarding the relative efficiency of the steam
system as compared with on-site furnaces or boilers fueled by natural gas at each customer
site. This report also addresses the environmental differences between the centralized steam
system and customer-sited heating systems.
Finally, the report addresses the relative
differences in water requirements between the centralized steam system and customer-sited
heating systems.
Given that the Commission has asked for information over the next 5, 10, and 20
years (Decision No. C13-0174-I, ¶19), the focus of this assessment is primarily on the system
over the next twenty years. However, all of the generating assets with the exception of Zuni
will continue to operate over the next 20 years and beyond. For example, the Sun Valley
Steam Center (“Sun Valley”) is proposed to replace Zuni Station Unit No. 1 (“Zuni”) in 2015
and its expected life is 60 years.
As discussed herein, the steam generation assets are in good condition and have been
properly maintained over the course of operation of the system. Capital investment is
relatively low with the exception of the construction of the Sun Valley project in 2015 and
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the replacement of the unit 1 boiler at the Denver Steam Plant in 2028. All other capital is
ongoing capital used to maintain the system. Operations and Maintenance expenses remain
constant after the installation of the Sun Valley project and upgrades to the distribution
system in the Central Platte Valley area.
As discussed, the district steam system is more efficient than customer-sited systems
at send out after the boilers; however, if the inherent losses in the steam distribution system
are included, the two systems are approximately equivalent. The district steam system in its
current open-loop uses about 98 percent more water than a customer-sited closed-loop
system. Finally the district steam system has environmental controls that are effective in
avoiding air emissions while customer-sited systems do not.
2. Assessment of the current condition of the Denver
District Steam System
a. Summary
Public Service’s downtown Denver District Steam System is regularly assessed based
on a routine maintenance schedule. Any required repairs or other facility-related issues are
addressed as they arise and are prioritized in the maintenance schedule. Overall, the steam
system is in good condition. As we discuss in detail below, we routinely inspect our
facilities, and based on these inspections, we are not aware of any major maintenance issues.
Based on our engineering assessment of the systems, the Company’s only expected major
capital investment over the next 20 years, other than the Sun Valley project, is the
replacement of the Unit #1 boiler at the Denver Steam Plant (“DSP”) in 2028 at a projected
cost of six million dollars.
The Company’s future capital requirements are based on
historical data from the previous ten years of capital investment needs adjusted for the
current known condition of the equipment. Based on the assessment of condition of the
equipment, the steam system has a capital plan that accounts for future upgrades and
replacements as detailed in this report that allows the system to operate as expected. The
only exception to the above assessment is Zuni Station, which, although not a steam energy
department facility, provides steam production capability critical to the district steam
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business. According to the Company’s Energy Supply group, Zuni Station has reached the
end of its useful life for both steam and electric generation and is scheduled to come off line
in 2015 due to the uneconomic cost of operations and maintenance given its age and
condition as well as its duty cycle and use since it was first constructed. There are many
common pieces of equipment that are at end of life and that are used for both steam and
electric generation such as the boiler, boiler feed pump, water treatment equipment and other
common equipment.
Zuni Station is an electric generating plant asset, and steam
“purchases” steam production from the electric department through an internal cost
allocation. Steam is essentially a customer of the electric department and does not have
dominion or control over the decisions affecting the plant, however once retired, steam must
plan to replace Zuni’s capacity. This report assumes that Zuni Station will be replaced by the
Sun Valley Steam Center project, with a planned in-service timeframe during the fall of
2015.
b. Overview of Steam Generation
i. Steam supply capacity and reliability
The Company’s district steam system has access to approximately 660,000 pounds
per hour (“pph”) in total boiler capacity comprised of generation from three steam plants:
Zuni Station with an approximate capacity of 280,000 pph; DSP with an approximate
capacity of 260,000 pph; and the State Steam Plant (“SSP” also referred to as the “Capitol
Steam Plant”) with an approximate capacity of 120,000 pph. The Company has sized the
Sun Valley Steam Center to approximate the steam capacity of Zuni Station and therefore the
capacity of the total system will remain consistent after the replacement of the Zuni Station
with Sun Valley; this was done to maintain and sustain current production operations. A
three-plant arrangement allows sufficient capacity to maintain the steam production
equipment during non-peak periods and allows sufficient redundancy so that the Company
can reliably serve its current and foreseeable customer base without interruption. The three
production plant system also allows customers to be served during distribution system
maintenance.
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The steam system has a history of exceptional customer reliability with a record
that reports no customer service interruptions over the last several decades. To be clear,
individual elements of the system are out-of-service periodically, but the system as a whole
has had no unplanned outages that impacted service to customers. To achieve this reliability,
the steam system operating staff applies best practices from both Xcel Energy’s Energy
Supply power generation business and from the International District Energy Association
(“IDEA”), a district energy industry trade organization. These practices are more fully
described below in the maintenance and operations description for each plant. In addition to
the application of best practices, the Company has a long history of operating its steam
system and evaluating the characteristics of the system to optimally operate and maintain the
system. The combination of employing best practices and applying this experience has
resulted in very effective operations.
ii. Historical overview of steam production operations
Public Service’s steam business has a long history of operation, having been
originally incorporated as the Denver City Steam Heating Company in December 1879.
From 1879 until the early 1940’s, the district steam business served its customers based
solely on steam produced from the Denver Steam Plant, formerly referred to as the “1875
Delgany Plant”. In the 1940’s, the Zuni Unit No. 1 became the primary source of steam after
installation of a coal-fired cogeneration unit with steam extraction equipment. At that time,
DSP became the secondary and backup source of steam production in the system. In 1964,
Public Service signed a long-term lease with the State of Colorado and installed a new boiler
that would be housed within the Capitol complex – the State Steam Plant (“SSP”) - optimally
located on the opposite side of the District Steam system from DSP and the Zuni Station.
This addition established a three-pronged approach to the operation of the Company’s district
steam system that facilitated a reliable steam supply while adding flexibility to distribution
operations because of the triangular positioning of the three plants within the network.
For several years, the plants were dispatched with Zuni as primary, DSP secondary
and SSP as backup. The dispatch priority remained with Zuni until a combination of the loss
of steam extraction and the conversion from coal to natural gas eliminated the efficiency
advantages of dispatching Zuni as the primary steam supply. In 1972 and 1974, two new
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boilers were built at DSP and the new DSP units (Units #1 and 2 that are in service today).
These units were designed as modular package boilers and became the primary source of
steam, with Zuni providing about 30 percent of the annual steam supply needs. In the
1990’s, an economizer was added to Unit #2 at DSP, further improving the overall system
efficiency. In 2004, a new 20-year lease was signed with the State and Public Service
replaced the old SSP boilers with a single 120,000 pph unit. In this brief historical account, it
is important to note that all steam demand has been reliably served using these steam sources
and that all three of these facilities are required to be in operation and generating steam to
meet peak send out requirements during peak heating periods, which can run from December
through March of each year. Figure 1 shows each of the steam generation systems in a
triangular configuration to meet the needs of steam customers.
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Figure 1. District Steam System with Three-Plant Configuration
iii. Steam system operations and maintenance practices
The Company presently produces all steam for its steam system by burning natural
gas as its primary fuel. Zuni can also burn #6 oil and DSP can also burn #2 oil during natural
gas curtailments and for testing. Fuel use is based on daily load forecasting, which is
comprised of weather, customer demand, and system availability. Operations are monitored
and data is collected on a continuous basis. By having and maintaining the ability to burn
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oil, the steam system is able to take interruptible natural gas transportation service, which
saves customers money over firm gas service.
A work management system is utilized to prioritize and schedule preventative and
corrective maintenance to ensure the reliability of the production facilities. Prioritization is
based on a hierarchy of system categories, including critical equipment, regulatory
requirements, safety, manufacturer recommendations, inspection and testing support. All of
the plants and the distribution system have a preventative maintenance (“PM”) program and
schedule. PM’s are maintenance work orders defining what work is to be performed. The
PM’s are defined for each piece of equipment and reside in the Company’s Maximo software
system. These PM programs facilitate the proactive maintenance of the system, which
increases the overall reliability and availability of the plants and the distribution system. The
Company believes these programs have been instrumental in the steam system’s stellar
unplanned outage record.
The annual scheduled maintenance is done on each production unit prior to the next
heating season so that minimal maintenance is needed during peak season. All plant systems
(air, fuel water, boiler, controls, etc.) are inspected and repaired or replaced as necessary and
auxiliary equipment (pumps, boilers, fans, tanks transmitters and gauges) are inspected,
calibrated and maintained. Standard scheduling tools are used to track and schedule the
repair maintenance. Materials needed for repair are obtained using the Company’s standard
sourcing procedures.
1. Pressure Vessels
A designated Company quality control inspector inspects the boilers during planned
outage periods, which are scheduled to allow sufficient time to make any needed repairs or
plan future work prior to the peak heating season. Any welding repairs that are done are
given an R-stamp Number and/or Non Boiler External Piping (“NBEP”) #’s in compliance
with standards required for boiler pressure code piping or pressure piping by American
Society of Mechanical Engineers, Power Piping Code (“ASME” B31.1), which defines
piping safety, minimum requirements for the design, materials, fabrication, installation,
testing, inspection, operations and maintenance (“O&M”) of the piping systems. Our
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practices are in conformance with the 2011 National Board Inspection Code (“NBIC”). The
boilers are also inspected by the Company’s insurance carrier and state inspectors, as well as
by the Company’s certified boiler inspectors and chemists. The conclusions from these
assessments are used in estimating the condition of the boiler based on parameters such as
boiler tube wall thickness, boiler cleanliness, boiler tube failure concerns, visual assessment
of the boiler internals and other engineering considerations.
Each plant is assessed
individually.
2. Piping
The distribution system consists of 16 miles of pipe in and under the streets of
downtown Denver. An important diagnostic parameter for the distribution system that is
indicative of the health of the system and possibly a warning of problems within or upstream
of the distribution network is the pressure, measured in pounds per square inch (“psi”). Each
of the operations work shifts tracks and monitors the distribution system continually for
irregularities in pressures at various points in the system. Normal pressures are generally 105
psi on the intermediate customer side and 25 psi on the low pressure customer side. All
permitted facilities meet or exceed minimum environmental requirements. The schedule
calls for operations and maintenance work to be completed prior to the next heating season.
c. Production and Distribution Facilities
i. Zuni Station
Zuni Station, as shown in Figure 2 is located along the Platte River in the Sun Valley
district of Denver. Zuni Unit 1 is an asset capable of providing approximately 280,000
pounds per hour of steam and 59 MW of electric generation capacity. This unit provides 50
percent of the peak steam load and accounts for 30 percent of the annual sales for the steam
system. Zuni was last repowered in the mid 1940s and it has reached the end of its useful
life. Zuni 1 was retired from electrical service at the end of 2009 and Zuni 2 and common
plant are currently slated for retirement in late 2015 after the Sun Valley project becomes
operational. The operations and maintenance costs for Zuni are increasing and any capital
invested is depreciated over the then-shorter remaining life. These increasing O&M and
capital costs have made Zuni uneconomic in the dispatch order for electric generation as
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compared to its fleet alternatives. Because of its high heat rate and relatively long start-up
period, Zuni Station is operated very seldom for the electric system. In fact, since the 2007
resource plan, the Company has indicated a retirement date for Zuni Station of between 2012
and the end of 2015.
Figure 2. Zuni Station
If Zuni is to be kept in reliable operating condition beyond 2015, the Company will
need to incur significant capital costs to replace boiler tubing, boiler burners, boiler controls
and other associated equipment (pumps, fans, valves, etc.) given that the boiler at Zuni is
over 67 years old and it has had significant operation over its lifetime. In addition to many
years of base load operation, the unit was started frequently since its conversion to natural
gas.
ii. Denver Steam Plant
DSP is centrally located at 1875 Delgany Street in the Central Platte Valley and
nearby to the downtown business district. Steam has been supplied from this site since 1879.
As indicated earlier, the DSP was completely rebuilt in 1972 and 1974 with new package
boilers. DSP is currently first in the dispatch order and is the primary source of steam for the
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system. DSP accounts for 70 percent of the annual sales and 50 percent of the peak steam
load. DSP will continue to operate well into the future because it has been well maintained,
which includes routine equipment assessment, preventative maintenance, and because the
two low pressure package units are in good operating condition. The advantage of package
boilers is that the boilers and auxiliary equipment can be easily replaced as shown in Figure 3
where the deaerator is being replaced. As a result, there are no major capital expenditures
planned for DSP until 2028 when boiler #1 is slated for replacement. The boiler replacement
is included in the capital expenditure details.
Figure 3. Denver Steam Plant – Deaerator Replacement
1. Maintenance practices at DSP have been robust
The fact that DSP is a package boiler facility and that periodic capital replacements
have been made over time along with implementation of good operating and maintenance
practices will allow the business to reliably produce steam from this unit well into the future.
As a result, only incremental on-going capital investments have been required
notwithstanding the age of the facility. Currently a repair is scheduled for the #2 boiler at
DSP during the annual outage in 2013 and there are no unexpected maintenance issues that
are classified as high priority. All other maintenance items including time sensitive repairs
such as safeties are scheduled as part of the PM program and the cost of these repairs are
included in the capital and operations and maintenance forecasts. Repair projects have been
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identified and established based on previous years’ work during annual outages. In the last
two years approximately $75,000 was budgeted for those repairs.
A plant inspection and evaluation process is updated and implemented on an annual
basis and is comprised of major and minor systems inspections with all systems eventually
assessed. For example reports, see Appendix A. As discussed, during annual outages
inspections from certified Company boiler inspectors and State Boiler Inspectors are
completed. The inspections include but are not limited to:
ƒ
Visual examination of the boiler internals and boiler externals such as the
steam drum and the deaerator.
ƒ
Annual Non Destructive Evaluation (NDE) of the plant piping systems.
ƒ
Vibration analyses for the forced drive (FD) fans and pumps.
ƒ
Internal boiler inspections for the steam drums to include the fire box and
numerous auxiliary systems by Public Service and vendor chemists on an
annual basis.
ƒ
Inspection of auxiliary systems; for example the deaerator and degassifier.
ƒ
Completion of PM’s and work orders for all major and auxiliary systems
during a planned outage.
Using the ascribed approach, the steam systems have had no forced outages due to
boiler tube failures. After the annual plant outage, an evaluation is done using inspection
reports and information on systems that may need repairs are identified and prioritized. The
#2 boiler front replacement at the DSP is one example of a capital project repair as result of
these evaluations. Based on the PM practices, inspections and historical findings, there are
no plans for major replacements of equipment until 2028, which is the scheduled replacement
of the #1 boiler.
The Unit 1 boiler is over 40 years old and through continued proper maintenance in
addition to modest capital investment, it is expected to last until 2028. At that time the
Company plans to replace the unit. Unit 2 is expected to last for more than 20 years with an
expected replacement around 2035. Although unit 1 and unit 2 were installed only two years
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apart, the current seven year forecasted difference in the replacement timeframe between unit
1 and unit 2 is because the unit 2 boiler is in relatively good condition and after the new plant
is on line it will not need to operate as often.
2. DSP package boiler replacement versus Sun Valley
There is a difference between the cost of replacing the package boilers at the DSP and
the cost of a new facility such as the Sun Valley project because the Sun Valley project is a
completely new plant. Costs for Sun Valley include site development, building construction,
auxiliary and additional equipment needed for a new plant (water treatment, air compressors,
maintenance shops, backup fuel storage, water and chemical storage, etc.), and facility
interconnection costs (electric, water, steam, gas and sewer). This infrastructure is already in
place at the DSP. The cost of the Sun Valley Steam Center’s two boilers represents about 33
percent of the total costs with another 56 percent in direct installation costs such as
demolition, siting, infrastructure development and buildings with the remaining 11 percent of
the costs as indirect charges for technical services and management of construction.
iii. State Steam Plant
The State Steam Plant shown in Figure 4 was commissioned in 2005 as a replacement
for another Company boiler previously in service at the Capitol Complex that had reached
the end of its useful life. This plant can provide up to approximately 120,000 pph of steam to
the system. This facility is relatively new and is in good condition thus it will not need major
capital upgrades over the next 30 years. The maintenance practices at the SSP are similar to
those for the DSP as discussed.
Incorporating the State Capitol boiler into the steam system’s distribution grid
including the Denver Steam plant and Zuni Station resulted in a three production system
approach that triangulates the entire system and enhances overall system reliability both from
a production and a distribution perspective. The SSP is dispatched as a peaking plant but it
facilitates distribution system maintenance without service disruptions by operating during
planned outages which are planned for non-peak periods. Dual-fuel capability at the Denver
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Steam plant and Zuni complete the reliability outlook for customers. The life of the State
boiler plant is expected to be 60 years.
Figure 4. State Steam Plant – Boiler Installation
iv. Distribution System
The main downtown Denver Steam distribution system has approximately 16 miles of
steam main piping which connects all production facilities with a grid that delivers steam to a
large area of the Denver core downtown business district as shown in the system map in
Figure 1. The district steam business provides service to its approximately 133 customers (at
year end 2012).
Public Service and its predecessors have distributed steam in the downtown Denver
service territory since the 1880’s. In the mid-1980’s, improvements in design standards,
pressure support, and safety were incorporated into the distribution system, however there is
no condensate return system. The system was upgraded in 1980 to include an intermediate
pressure system, allowing for better pressure support to customers throughout the system.
The improvements included some design standards as well as installation of new safety relief
equipment on the system.
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The steam distribution system supplies intermediate pressure service at approximately
105 psi and low pressure service at approximately 25 psi. While direct buried steam mains
are the backbone of the distribution system, operations are controlled using a series of
expansion joints, valves, condensate removal equipment, and pressure reducing stations.
Some of this equipment is shown in Figure 5.
Much of this equipment is housed in
underground installations referred to as vaults. The customers are served from the main
pipeline through service laterals and are isolated from the system via customer-owned
reducing stations and valves.
Figure 5. Glenarm Main
1. The condition of the distribution system and ongoing maintenance
Proper planned routine maintenance and capital upgrades are and have been made to
the distribution system so that it remains reliable over time, similar to the Company’s electric
and gas distribution systems. The Steam system has a vault inspection program which
consists of inspecting the vaults structurally along with the mechanical equipment within the
vaults. The program targets a complete inspection of all the vaults on a two year cycle.
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During the inspections, minor items are corrected by the maintenance crew and more
significant items are noted on the inspection report for follow-up. The findings are reviewed
and logged by the Distribution Superintendent. The logs are constantly reviewed throughout
the year and the items that are in need of attention are prioritized and corrected according to
the severity and importance of the issue. Emergency items are completed immediately when
public safety or reliability is impacted. An item noted on the inspection such as an isolation
valve that will not hold, piping that is corroding due to outside environmental issues, or a
vault that is deteriorating, would be reviewed and prioritized based on employee and public
safety, funding, customer interruption or impact and scheduling for permits.
Every January, a final re-prioritization is completed and the projects are assigned to
the staff as capital or O&M projects for the current year work. Using this methodology,
equipment conditions may be monitored over a number of years. In the case of main
replacements, smaller repairs may be more prudent than wholesale main replacements. The
effect of this methodology stretches out the funding requirements for replacement of even the
remaining blocks of the oldest main.
The design of the main piping includes a protective casing around the main as shown
in Figure 6, and unless disturbed or hit during other utility construction, pipe age is not the
deciding factor in determining whether a pipe should be replaced.
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Figure 6. Piping Cross Section
These mains are under existing inspection programs and undergo the same review as
other capital repairs. In addition to reviewing the need for replacing equipment based on age
and condition to ensure reliability, the Company also considers the location of the equipment
and the number of customers that the pipeline serves. Hence the Company considers the
number of customers that would benefit from an upgrade in prioritizing work. If the work
does not receive priority in the current year, then the project is moved to the next year and reevaluated during the next budget cycle.
Some projects and maintenance issues require system outages in order to repair the
equipment. Records are used to help plan when to address projects along with information
about any new items that need attention and that fall within the outage area and are noted for
correction during the outage timeframe.
The Company uses historical data on prior annual distribution work which indicates
that there will be 12 to 15 equipment replacement projects that fall within the capital criteria
and make up a significant portion of the annual distribution capital budget. Since all of the
next year’s work is not known during the budgeting process, a set amount of funds is
budgeted based on the previous year’s work.
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The design of the distribution system is sound. The system conforms to standards
required for pressure piping by ASME B31.1, which defines piping safety, minimum
requirements for the design, materials, fabrication, installation, testing, inspection, operation
and maintenance of the piping system. Upgrades to the Public Service Company system
design are evaluated in several ways. Public Service is a member of the International District
Energy Association (“IDEA”), which is the industry association of district heating and
cooling system owners and participates in member technical exchanges.
Technical
exchanges include discussion on topics such as innovations on safe operation, design
improvements in thermal distribution systems, confined spaces, urban construction,
emergency preparedness, and customer service related to the installation, operation, and
construction of steam networks. There is also an annual IDEA Distribution forum where
peers discuss distribution issues and planning. In addition to IDEA activity, all Public
Service system design, construction, and project management work has mechanical and civil
engineering oversight.
Construction activity for capital work is normally scheduled during the off-peak
summer months and coordinated with the customer to minimize any negative impacts.
Routine maintenance is also scheduled during outages to perform capital work in order to
minimize customer disruptions. By planning the work during off-peak hours, performing
routine maintenance during planned outages, and coordinating with customers, system
interruptions are managed, and as a result there have been no unplanned outages in the last
decade.
The steam mains in the system are direct buried in most cases. The steam mains
consist of a steam carrier pipe which is insulated and has a sealed outside conduit around the
insulation as shown in Figure 7. The outer conduit is wrapped in various ways to provide
cathodic protection to the main, which helps prevent corrosion of the metal piping and
casing.
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Figure 7. Piping Cross Section
Physical inspection of the system piping is rarely done because it requires excavation
to expose the underground piping. On occasion excavation is done to expose very old mains
that date back to 1911 in order to inspect a small section of the main. In such instances as
shown in Figure 8, the overall condition of these mains has been found to be good. All of the
older piping is on the low pressure, 25 psig, side of the system.
Figure 8. Older Underground Main at Excavation
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2. Building interconnections
Public Service Company owns the service into our customers’ buildings up to the
downstream side of the steam pressure reducing station, which in most cases is just inside a
building’s basement wall. Internal piping within the building to the customer’s equipment is
owned by the building. Approximately half of our steam customers have front end metering,
while half have condensate (back end) metering.
Metering equipment is owned and
maintained by the Company.
Annual preventative and corrective routine maintenance is performed by the Steam
Department on the equipment that is located at the customer’s site, but owned by the
Company. Throughout the year crews perform inspections on each building interconnection
and the associated metering equipment. If a minor issue is found during these inspections,
this maintenance worked is performed during the inspection, but more significant items are
noted on the building inspection sheets, reviewed, and logged so that the work can be
scheduled in the future when either the equipment is repaired or replaced.
3. Future Capital Investment and O&M Expenditure for
the System (5 year, 10 year, and 20 year)
The Company has estimated the capital and O&M costs of the steam system over the
next 20 years and found that only modest investment in capital is required with the exception
of the Zuni replacement with the Sun Valley Steam Center and the replacement of one of the
package boilers at the Denver Steam Plant. The Capital forecast is shown in Table 1.
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Table 1. Capital Forecast for the District Steam Business
District Steam 20 Year Forecast - Capital Projects
Denver Steam Plant,
State Steam Plant &
Sun Valley Steam
Sun Valley Steam
Center Center Construction
2013
2014
2015
2016
2017
$
$
$
$
$
403,666
275,000
500,000
766,000
766,000
$
$
$
$
$
2018
2019
2020
2021
2022
$
$
$
$
$
15,227
131,940
1,095,882
842,805
66,017
$
$
$
$
$
2023
2024
2025
2026
2027
2028*
2029
2030
2031
2032
2033
$
$
$
$
$
$
$
$
$
$
$
137,081
86,176
116,620
106,413
349,878
6,136,859
147,055
60,838
141,986
75,959
126,599
$
$
$
$
$
$
$
$
$
$
$
165,000
15,445,000
13,390,000
Cumulative
Cumulative
Cumulative
Steam Distribution
System
$
$
$
$
$
1,462,000
800,000
1,663,000
1,793,000
3,694,000
TOTAL
$
$
$
$
$
2,030,666
16,520,000
15,553,000
2,559,000
4,460,000
5 Year Total
$
41,122,666
$
$
$
$
$
$
$
$
$
$
1,908,485
2,882,388
2,480,956
1,958,760
2,560,463
10 Year Total
$
52,913,718
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,253,019
1,200,385
2,587,959
1,473,571
1,464,417
8,657,481
1,261,631
1,175,196
2,768,731
1,189,015
1,239,655
$
77,184,778
1,893,258
2,750,448
1,385,074
1,115,955
2,494,446
1,115,938
1,114,209
2,471,339
1,367,158
1,114,539
2,520,622
1,114,576
1,114,358
2,626,745
1,113,056
1,113,056
20 Year Total
The forecast is based on a review of historical capital requirements along with an
assessment of future needs. The years that are relatively flat in terms of capital investment as
shown in Figure 9 cover forecasted repairs based on historical trends and other
considerations. The peaks in the curve represent major investment to replace end-of-life
systems.
22
Exhibit No TMF-9
Page 23 of 37
Millions
District Steam Business Capital Project Forecast
$18
$16
$14
$12
Sun Valley
Steam Center
Construction
Denver Steam
Plant Unit 1
Boiler
$10
$8
$6
$4
$2
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
*
20
29
20
30
20
31
20
32
20
33
$-
Figure 9. Graphical representation of the Capital Forecast for the District Steam Business
A current list of projects for 2013 is shown in Table 2 as a representative year for
normal replacement and upgrades.
Table 2. 2013 Budgeted Capital Projects
2013 Detailed Capital Projects
1
2
3
4
5
6
7
8
9
10
11
12
Vault 19WY.1 Replacement
Glenarm 1300 Block Expansion Joint Leak Repair/Replacement
1300 Arapahoe Leak Repair Expansion Joint Replacement
Vault TL27ZU Replacement
Vault WE17.3 Leak Repair and Vault Replacement
Vault LI16.1 Replacement
Customer Metering
Vault 18MK.1 Replacement
Vault AR13.1 Replacement
Vault LW17.1 Valve Replacement
Vault 18LW.2, Reg Station Valve Replacement
Vault CA17.3 Reg Station Valve Replacement
The operations and maintenance expenses are shown as escalated dollars in Table 3
beginning in 2001 for historical comparison.
23
Exhibit No TMF-9
Page 24 of 37
Table 3. District Steam O&M (escalated dollars)
District Steam Operating Expenses
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Total O&M
2,391,311
3,039,356
3,864,580
4,200,213
4,333,676
4,331,999
4,409,998
4,688,207
4,872,514
5,107,550
5,503,757
6,494,221
6,046,192
6,703,822
7,396,347
7,690,004
7,642,884
8,302,197
8,452,786
8,640,571
8,815,811
9,018,295
9,178,928
9,396,655
9,595,678
9,860,380
10,020,596
10,247,082
10,472,760
10,703,938
10,940,764
11,183,382
11,431,944
The district steam business utilizes the same cost control measures on O&M
employed throughout the Company.. As Figure 10 shows, changes in the growth rate of
O&M expenses remain flat after the Sun Valley Steam center is operational and after
distribution system upgrades.
24
Exhibit No TMF-9
Page 25 of 37
Millions
District Steam System O&M
$14
30%
$12
25%
20%
$10
15%
$8
10%
$6
5%
$4
0%
$2
-5%
-10%
20
01
20
03
20
05
20
07
20
09
20
11
20
13
20
15
20
17
20
19
20
21
20
23
20
25
20
27
20
29
20
31
20
33
$-
Total O&M
Year over Year Change in O&M (%)
Figure 10. District Steam O&M Curves
4. Efficiency of district steam versus self generation by
customers
Modern day package steam boilers have an efficiency of around 84 percent when
operating at full load. During conditions of low load the units will start to cycle on and off
and the efficiency declines. Low load conditions occur in the summer when building heating
requirements are minimized and steam is used primarily for domestic hot water.
The District Steam System operates its multiple boilers in a way that allows it to
support system load and to bring units on line or take them off line as load requirements
dictate. This generally prevents the boiler from having to operate in a cycling mode where
the unit continues to burn gas to generate steam without a requisite system load. Avoiding
cycling improves the steam production efficiency. Thus a district steam boiler operating
25
Exhibit No TMF-9
Page 26 of 37
without cycling at a higher load point allows them to have a higher efficiency than a typical
building with its own boiler; moreover system redundancy is reduced because the centralized
system can take advantage of load diversity. The loss in efficiency due to boiler cycling in
buildings is estimated to be on the order of 15 to 20 percent.
Although the district steam system has advantages in efficiency due to capacity sizing
and load diversity, these advantages are somewhat tempered by losses in distribution. The
steam system has an inherent distribution system loss of 15 to 18 percent, which is largely
attributed to the large amount of underground distribution piping with inherent heat loss.
Such distribution heat losses would not be the experience of a customer operating a building
with its own heat production facility. The losses would be more akin to 5 percent on the high
side based on the testing that the Company has performed. Depending on the actual partial
loading there could be a building savings/loss of +/-5 percent in a building that self generates
its heat versus using district steam. The new Sun Valley project efficiency will be around 84
percent at send out to the distribution system. The average calculated efficiency of our
current generating units is 75 percent for Zuni, 76 percent for DSP boiler #1, 81 percent for
DSP boiler #2, and 83 percent for the SSP Boiler.
There may be some efficiency from the aggregation of load that we have not
attempted or been able to quantify. Over the course of a year, the Steam System’s boilers are
more efficient than a customer unit based on send out efficiency, but because of the
distribution system loss, the overall efficiency of the Company’s district steam system and a
customer-owned system at its facility is about the same.
5. Water use: Public Service steam distribution system
versus customer owned heating system.
On average the steam system uses approximately 400 acre-feet of water per year. As
a comparison, an electric generating station that uses both wet and dry cooling producing
about 750 MW of electricity at peak uses over 14,000 acre-ft of water per year. As a result,
the relative water usage of the steam system is small by comparison to other energy uses and
extremely small by comparison to other uses of water such as agriculture. The Colorado
Conservation Water Board’s latest assessment of water usage in the state indicated that less
26
Exhibit No TMF-9
Page 27 of 37
than 2 percent of Colorado’s water usage is used for power generation. Other users included
municipal and self-supplied industrial (9 percent) and agricultural (89 percent).
The Company’s district steam system does not have a condensate return system, so all
of the water that is used to generate steam is sent to the sanitary sewer system making water
available for downstream usage. The Company is working with Denver to bring recycled
water to the Zuni site where Sun Valley Steam Center is proposed to be located and to the
DSP site, which will allow the Company to use essentially 100 percent recycled water,
eliminating the need for the Company to use potable water for most of its steam production.
Denver Water operates a recycled water plant and distribution system which takes
legally-reusable effluent from the Metro Wastewater’s Robert Hite Treatment facility, treats
it further, and then distributes it to various locations within the Denver Water service area for
industrial and irrigation use. When built out, Denver Water plans to reuse 17,500 acre-feet of
water annually through this system. Currently, the system is being developed in phases to
respond to identified demands and to extend the system to its planned build-out.
If recycled water were used to generate steam, additional capital investment would be
required to extend the recycled water distribution system to the Company’s facilities and to
cover the costs to add or expand the existing onsite water treatment capability at each steam
facility. The additional capital coupled with the billed cost of recycled water results in added
costs to the system as a tradeoff for not using potable water. To date, the Company has
requested order-of-magnitude capital costs (physical system expansion and system
development charges) from Denver Water as a start on implementing this option. Onsite
treatment of recycled wastewater to yield water of sufficient quality to use in the steam
system is anticipated to be extensive, potentially including water clarification and reverse
osmosis treatment. The Company would have to study the costs of obtaining and treating the
recycled water to determine the economic viability of reuse water to supply the district steam
business’ needs. Reuse water is neither a feasible nor available option to customer-owned
buildings in the downtown Denver area.
At a customer facility, customers that self-generate would likely have a return system
with a water loss of approximately 2 percent. This loss is termed as the blowdown and
27
Exhibit No TMF-9
Page 28 of 37
represents the water lost to the drain or sanitary sewer. This also represents the amount of
fresh water that a customer system would need annually. The entire system might be flushed
every few years with all of the water replaced in aggregate. In general, a customer building
with its own closed system would use approximately 98 percent less water than the district
steam system per year. This figure, however, does not take into account that some of our
customers use the condensate from our system for other uses (for example cleaning), that
they would have to replace if they operated their own closed loop system. The Company has
not tried to quantify the level of other uses for the water.
6. Environmental emissions of central plants versus
customer owned generation
The Company has assessed the emissions from the district steam system versus
customer-owned generation and we would expect lower emissions from the Company’s
central plant system versus customer owned generation. This is due to several factors;
Central steam generation plants obtain air permits and are required to meet strict air emission
guidelines, which the Company has met. Customer-owned generation would not have such
regulated oversight in emissions and would not need to obtain an air permit because smaller
size units are typically unregulated. As a result, air emissions are uncontrolled and could be
higher. The central plant emissions are monitored and emission is highly controlled through
good emission control technology. As the Company has experienced with its electric system,
air emissions regulations target larger systems because a reduction in emissions at a larger
unit has a greater impact on overall air quality. In addition, the scale of these units allows for
the absorption of the cost of emission controls. In most cases, we assume that the customer
owned equipment would be less than 10 MMBtu/hr maximum fuel input, which is of small
enough size to avoid the emission control requirements of a district system such as the
Company’s.
7. Conclusion
The Company has assessed its district steam generating and distribution system
viability over the next 20 years and has determined that there are no major issues for the
28
Exhibit No TMF-9
Page 29 of 37
system. The main capital expenditures that are required are replacement of Zuni Station with
the Sun Valley Steam Center at an estimated cost of $29 million and the replacement of the
unit 1 boiler at DSP at an estimated cost of $6 million. All other capital is budgeted and is
the ongoing incremental capital needed to maintain the system. O&M expenses are flat after
the year 2019 when both the Sun Valley Steam Center and investment upgrades in the
distribution system are complete. The Company has good maintenance practices for its
system with good results; hence the system is reliable, well-maintained and safe.
The Company has assessed the efficiency, water usage and environmental emissions
of its system versus customer sited heating systems. The findings are that these systems are
equivalent in efficiency when the distribution system losses of the steam system are included,
the steam system uses relatively more water than a customer-sited closed loop system, and
the steam system is more environmentally compliant than a customer sited system. Although
the Company’s steam system uses relatively more water than a closed loop system, the
Company can modify its system to use recycled water, while customer-sited facilities do not
have this option.
29
Exhibit No TMF-9
Page 30 of 37
Appendix A – Example plant inspection and evaluation reports
Engineering Assessment – Denver District Steam System
Exhibit No TMF-9
Page 31 of 37
ii
Exhibit No TMF-9
Page 32 of 37
iii
Exhibit No TMF-9
Page 33 of 37
iv
Exhibit No TMF-9
Page 34 of 37
v
Exhibit No TMF-9
Page 35 of 37
vi
Exhibit No TMF-9
Page 36 of 37
vii
Exhibit No TMF-9
Page 37 of 37
viii