HomeMy WebLinkAboutMunicipality of Anchorage - Landfill Gas Utilization Economic Evaluation for Anchorage Regional Landfill - Dec 2004Landfill Gas Utilization
Economic Evaluation for
Anchorage Regional Landfill
Anchorage, Alaska
Prepared for
Municipality of Anchorage
Supported by
US Department of Energy
Regional Biomass Energy Program
Grant #DE-FG51-02R021317
Prepared by
2360 Bering Drive
San Jose, CA 95131
(408) 382-5800
May 2004
Project No. 10148003000000
i
CONTENTS
LIST OF TABLES AND ILLUSTRATIONS ii
1 INTRODUCTION 1-1
1.1 Option 1 – Electricity Generation 1-1
1.2 Option 2 –Transmission of LFG to Enstar Natural Gas Pipeline 1-1
1.3 Option 3 – Transmission of LFG to Eagle River School 1-2
1.4 Option 4 – Transmission of LFG to National Guard Facilities 1-2
1.5 Option 5 – Transmission of LFG to Fort Richardson Facilities 1-2
1.6 Option 6 – Transmission of LFG to Existing Municipal Light & Power (ML&P)
Plant (George M. Sullivan No. 2). 1-2
1.7 Option 7 – Transmission of LFG to Proposed Municipal Light & Power (ML&P)
at Fossil Creek. 1-2
1.8 Option 8 – Treatment of Liquid Generated or Collected at the Anchorage Landfill
1-3
2 ESTIMATED LANDFILL GAS GENERATION 2-1
2.1 Model Input 2-1
2.2 Model Output 2-1
3 LANDFILL GAS CHARACTERIZATION AND UTILIZATION 3-1
3.1 Landfill Gas Characterization and Utilization for Electrical Generation Equipment
3-1
3.2 Landfill Gas Utilization for Boilers 3-2
4 POTENTIAL LFGTE PROJECT SUBSIDIES 4-1
4.1 Federal Renewable Energy Tax Credits 4-1
4.2 Renewable Energy Production Incentive (REPI) 4-1
4.3 Discussion of Potential Valuable Landfill Gas Attributes 4-2
4.4 Greenhouse Gas Credit Values 4-3
4.5 Trading Brokers 4-4
5 ECONOMIC ANALYSIS 5-1
5.1 Project Assumptions and Analysis 5-1
5.2 Option 1 – Electricity Generation 5-2
5.3 Option 2 – Transmission of LFG to Enstar Natural Gas Pipeline 5-4
5.4 Option 3 - Transmission of LFG to Eagle River School 5-5
5.5 Option 4 – Transmission of LFG to National Guard 5-6
5.6 Option 5 – Transmission of LFG to Fort Richardson 5-7
5.7 Option 6 – Transmission of LFG to Existing ML&P Facility (George M. Sullivan
Power Plant No. 2) 5-8
CONTENTS (Continued)
ii
5.8 Option 7 – Transmission of LFG to Proposed ML&P Facility (Fossil Creek Power
Plant) 5-9
5.9 Option 8- Treatment of Liquid Generated or Collected at the Anchorage Regional
Landfill 5-10
6 SUMMARY OF FINDINGS 6-1
7 LIMITATIONS 7-1
CONTENTS (Continued)
iii
APPENDICES
Appendix 1 LFG Generation Model
Appendix 2 Laboratory Analysis and Possible “Clean-up” Process
Appendix 3 Financial Pro Forma for Option 1 (Electrical Generation)
Appendix 4 Topographic Map for Option 2 (Enstar)
Appendix 5 Financial Pro Forma for Option 2 (Enstar)
Appendix 6 Proposed Boiler Specifications for Eagle River School
Appendix 7 Topographic Map for Option 3 (Eagle River School)
Appendix 8 Financial Pro Forma for Option 3 (Eagle River School)
Appendix 9 Topographic Map for Option 4 (National Guard)
Appendix 10 Financial Pro Forma for Option 4 (National Guard)
Appendix 11 Topographic Map for Option 5 (Ft. Richardson)
Appendix 12 List of Natural Gas Burning Equipment at Ft. Richardson
Appendix 13 Financial Pro Forma for Option 5 (Ft. Richardson)
Appendix 14 Topographic Map for Option 6 (ML&P George M. Sullivan Power Plant)
Appendix 15 Financial Pro Forma for Option 6 (ML&P George M. Sullivan Power Plant)
Appendix 16 Topographic Map for Option 7 (ML&P Fossil Creek)
Appendix 17 Financial Pro Forma for Option 7 (ML&P Fossil Creek)
Appendix 18 Financial Pro Forma for Option 8 (Treatment of Liquid Collected at the ARL)
1-1
1 INTRODUCTION
The Municipality of Anchorage (MOA) has retained EMCON/OWT, Inc. to perform an
economic evaluation of its landfill gas (LFG) beneficial use options. The evaluation is
based on the anticipated LFG recovery rates and considers the cost of design, equipment
procurement, equipment installation, revenue streams, potential government subsidies,
and operations and maintenance (O&M) for the proposed facilities.
This LFG beneficial use study was supported in part by funding from the US Department
of Energy Regional Program Grant No. DE-FG51-02R0211317. This funding does not
constitute any endorsement by the US Department of Energy of the results of the study.
The LFG beneficial use options evaluated for this study are described below. Due to the
poor financial performance of the electrical generation option, two scenarios were
generated. The first electrical generation scenario included costs to construct and
maintain the LFG collection system; the second scenario did not. All of the subsequent
beneficial use options included costs to construct and maintain the LFG collection
system. The Anchorage Regional Landfill is required by Federal New Source
Performance Standards to install and operate such a system.
Due to the difficulty in assessing the value of intangible items such as positive public
relations for the Municipality as a result of using LFG as a beneficial use, these items are
not included in this economic evaluation. The Municipality may want to consider the
value of such intangible items in its final decision to proceed or not proceed with a
project.
1.1 Option 1 – Electricity Generation
Option 1 involves electrical generation with a series of internal combustion engines that
are designed to ignite LFG. Electricity generated by the engines may be sold to a local
utility at its avoided cost rates.
1.2 Option 2 –Transmission of LFG to Enstar Natural Gas
Pipeline
Option 2 includes compression and transmission of LFG into a high-pressure natural gas
pipeline, which runs adjacent to the landfill (990 feet way). Enstar Natural Gas Company
owns the natural gas pipeline. For this option we have reviewed the clean-up
requirements and required operating pressure of the pipeline.
Section 1 – Introduction
1-2
1.3 Option 3 – Transmission of LFG to Eagle River School
Option 3 includes compression of LFG in a low-pressure pipeline and then transmitted
approximately 0.6 miles to the Eagle River School campus for use in its boilers. The
Eagle River School boilers would be modified to allow burning of dual fuels (LFG and
natural gas).
1.4 Option 4 – Transmission of LFG to National Guard
Facilities
Option 4 includes compression of LFG in a low-pressure pipeline and then transmitted
approximately 2.7 miles to the National Guard facilities for use in its boilers. National
Guard boilers would be modified to allow burning of dual fuels (LFG and natural gas).
1.5 Option 5 – Transmission of LFG to Fort Richardson
Facilities
Option 5 includes compression of LFG in a low-pressure pipeline and then transmitted
approximately 5.1 miles to Ft. Richardson for use in its boilers. Ft. Richardson boilers
would be modified to allow burning of dual fuels (LFG and natural gas).
1.6 Option 6 – Transmission of LFG to Existing Municipal Light
& Power (ML&P) Plant (George M. Sullivan No. 2).
Option 6 includes compression of LFG in a low-pressure pipeline and then transmitted
approximately 6.75 miles for use in ML&P’s closest operating electrical plant equipment.
ML&P equipment would be modified to allow burning of dual fuels (LFG and natural
gas).
1.7 Option 7 – Transmission of LFG to Proposed Municipal
Light & Power (ML&P) at Fossil Creek.
Option 7 includes compression of LFG in a low-pressure pipeline and then transmitted
approximately 2.1 miles to the proposed Fossil Creek facility for use in its electrical
generation equipment. ML&P equipment would be modified to allow burning of dual
fuels (LFG and natural gas).
Section 1 – Introduction
1-3
1.8 Option 8 – Treatment of Liquid Generated or Collected at
the Anchorage Landfill
Option 8 includes the utilization of LFG to treat liquids generated or collected at the
Anchorage Regional Landfill. These liquids include leachate generated at the landfill and
glycol collected and disposed of by the Municipality. Due to unfavorable preliminary
financial estimates, less detailed discussions of these options are contained in subsequent
sections of this report. .
2-1
2 ESTIMATED LANDFILL GAS GENERATION
EMCON/OWT used its proprietary LFG generation model to estimate the quantity of
LFG that will be generated at the Anchorage Regional Landfill.
2.1 Model Input
The LFG model is based on waste inflow, waste composition, waste moisture, and the
potential for air intrusion. The input for the LFG model was determined based on site-
specific data provided by Anchorage Regional Landfill. Assumptions were made based
on EMCON/OWT’s knowledge of the landfill and nationwide studies of municipal solid
waste. The input for the LFG generation model is provided in Appendix 1.
2.2 Model Output
The LFG generation model output is also provided in Appendix 1. The annual utilizable
quantity of LFG (as shown in the LFG generation model output) was used over the 10-
year project life in the economic evaluation. The model output indicates that the average
quantity of LFG generated over the 10-year project life is approximately 1,383 scfm
(Year 1: 1,101 scfm and Year 10: 1,632 scfm). This utilizable quantity of LFG represents
the quantity of LFG expected to be delivered to the blower/flare facility by the LFG
collection and control system over the 10-year project life.
All LFG flow rates quoted above are the expected generation rate. The actual quantity of
LFG that may be available for beneficial use may be slightly less than the reported
generation rates. This reduction of LFG collected versus generated is known as the
“collection efficiency.” Collection efficiency is determined based on LFG well spacing,
cover type, cover maintenance, percent of sideslopes allowing air intrusion, and
maintenance of the LFG collection system. Typical collection efficiencies reported for
geomembrane lined and capped sites are 90 to 95%. Typical collection efficiencies
reported for capped soil and poorly operated LFG collection systems is 60 to 65%. Based
on our review of the plans for LFG collection system design and MOA staff members’
extensive knowledge of LFG design, construction, operations, and their high standards
for each of these disciplines, EMCON/OWT feels a collection efficiency of 75% is very
achievable. Therefore, the model output indicates that the average quantity of collectable
LFG over the 10-year project life is approximately 1,037 scfm (Year No.1: 826 scfm and
Year No. 10: 1,224 scfm).
3-1
3 LANDFILL GAS CHARACTERIZATION AND UTILIZATION
3.1 Landfill Gas Characterization and Utilization for Electrical
Generation Equipment
LFG contains many contaminants that have detrimental effects on LFGTE collection,
processing, and distribution equipment. The control of these contaminants can create
secondary air compliance issues related LFGTE plant emissions.
Beside the corrosive properties of LFG caused by contaminants (e.g., hydrogen sulfide,
formation of carbonic acid, etc.,), siloxanes are probably the most troublesome
contaminate for electrical generation equipment. Siloxane testing is now becoming well
known as a primary maintenance and engine performance problem. Siloxane levels can
range from low part per billion by volume (ppbv) levels to several hundred part per
million by volume (ppmv). The reduction of siloxanes to silica dioxide is inevitable as
the gas is burned to produce power and heat.
Siloxanes can cause significant operational problems on LFG utilization projects (e.g.,
microturbines, internal combustion engines, fuel cells, large-scale turbines, catalyst
systems, etc.). The impact of the silica deposition and abrasion is different at every
landfill, but can have a significant maintenance cost impact on equipment.
Most LFGTE projects use internal combustion (IC) engines to generate electricity. The
silica dioxide can reduce head life; plate out and cause bypass of valves, score cylinders
and liners; shorten life of spark plugs; cause increased oil changes; reduce the online
power production time and profit; poison catalyst; produce incomplete combustion
products; and lower engine and/or turbine efficiency.
Having knowledge of all these, EMCON/OWT had the LFG tested for its basic fuel,
volatile organic compounds (VOCs), siloxane, and sulfur components. The results of this
testing are briefly discussed below. The complete laboratory analysis and a possible
“clean-up” process are contained in Appendix 2.
Upon review of data from the samples, it appears this site may be a suitable candidate for
power generation using standard internal combustion (IC) engine technology. Currently,
only the removal of siloxanes should be considered to extend the operational life, reduce
the operational costs, and improve the uptime of the anticipated power generation.
Further testing is recommended after collection wells are installed to check the blend of
fuel components along with VOC and siloxanes.
Section 3 – Landfill Gas Characterization and Utilization
3-2
3.2 Landfill Gas Utilization for Boilers
The effects of burning the methane gas recovered from a landfill can be divided into the
following four main categories:
• Effects on boiler efficiency,
• Effect on maximum boiler output capacity or production,
• Effects due to individual compounds in LFG stream, and
• Design changes needed to accommodate using LFG.
3.2.1 Effects on Boiler Efficiency
Typically LFG is introduced into burners that were designed for natural gas having an
energy content of 980 to 1,020 Btu/dscf (dry standard cubic foot). LFG has an energy
content typically of 400 to 600 Btu/dscf. It can be shown by calculation that converting a
boiler from natural gas to LFG will reduce the boiler efficiency by approximately 1%.
This theoretical drop in efficiency is partially offset by a decreased exhaust gas
temperature due to the increased radiative heat transfer coefficient of the combustion
gases due to the increased levels of CO2 in the fuel gas. It should be noted that this
decrease in efficiency is less than the change to other fuels (i.e. changing from #2 fuel oil
to natural gas is a reduction of over 3% in efficiency).
3.2.2 Effect on Maximum Boiler Output Capacity or Production
Because of the lower heating value per cubic foot of LFG, a higher volume of fuel
introduction to the burner is required for equal heat input. Typically twice as many cubic
feet of LFG must be fed as natural gas to get the same Btu input to the burner. The net
effect of this is to increase the total volume of exhaust gas in the stack. This is an
increase of roughly 10% volume flow of gas in the stack. On a boiler where the
combustion air fan is exactly sized for the burner rated input this would have the net
effect of reducing the maximum energy input by 10% when firing LFG. However,
properly sized burners typically have combustion air fans, which are oversized by 20% or
more to account for variations in stack design and installation. In addition, boilers
normally operate at 75% or less of capacity and 100% capacity are only used during
warm-up from light off and this decrease in capacity is usually not detectable in
operation. It should be noted that during the typical boiler tuning the boiler maximum
firing rate is reduced to 85% to 90% of name plate capacity in order to achieve optimal
firing at the lower firing rates. Because the fuel component of both LFG and natural gas
is methane the amount of combustion air required to burn 1 MMBtu of methane gas is
equal to the amount required to burn 1 MCF of natural gas (natural gas is measured in
Section 3 – Landfill Gas Characterization and Utilization
3-3
MCF or thousand cubic feet which at 1,000 Btu/cf by specification gives 1 MCF = 1
MMBtu) so that there is no net increase in combustion air required when changing fuels
for equal heat input.
3.2.3 Effects Due to Individual Compounds in LFG Stream
The major components of LFG are methane (CH4), carbon dioxide (CO2), nitrogen (N2),
oxygen (O2) and other trace components primarily water vapor (H2O), non-methane
organic compounds (NMOCs), hydrogen sulfide (H2S), and siloxane (SiOx).
Methane is the primary energy component of LFG and is consumed during the
combustion process. The combustion process is carefully regulated and is required to be
controlled in such a manner that combustion products such as carbon monoxide (CO),
nitrous oxides (NOx), and unburned hydrocarbons (CH4 and NMOC) are minimized.
A major environmental benefit of burning LFG is that methane when released into the
atmosphere is 21 times more effective at heat retention that carbon dioxide or in other
words burning the methane contained in LFG has a net effect of reducing the total amount
of greenhouse gases released from a landfill by a factor of 20. It is recognized by the US
EPA that for each 1 MMBtu of LFG that is burned and not released from the landfill there
is a net reduction of 1 ton of equivalent CO2 released into the atmosphere. In a typical
large project this reduction will be in the hundreds of thousands of tons of CO2
reductions per year.
The carbon dioxide and nitrogen in the gas stream are inert and have no effect on the
combustion process other than to:
(i) cool the theoretical flame temperature thereby decreasing efficiency as
described above, and;
(ii) increase the total volume of exhaust gases, which must be removed by the
combustion air fan thereby decreasing maximum input as described above.
(2) It is important to note that the nitrogen in the fuel gas stream is not the same as
what is commonly referred to as fuel born nitrogen, which is typically found in
both liquid and solid fuels in the form of nitrates. In those cases the fuel bound
nitrogen will add to the total NOx production of the boiler. Because the nitrogen
in the fuel stream is non-reactive as well as the carbon dioxide they both act to
reduce the flame temperature, which has the net effect of reducing the amount of
prompt NOx formed in the combustion process. Burner manufacturers such as
COEN document a total NOx reduction of up to 30% when burning LFG versus
natural gas. This reduction is due to the cooler flame temperatures in the
combustion zone, which has the same effect as flue gas recirculation (FGR)
without the performance and maintenance penalties associated with FGR.
Section 3 – Landfill Gas Characterization and Utilization
3-4
(3) Because of the nature of gas recovery at a landfill there is always trace amounts of
water vapor present (from 0.3% to 3% by volume) in the fuel gas stream. While
the water has no effect on combustion and is negligible when compared to the
approximately 15% water vapor present in the exhaust gas due to the combustion
of the hydrogen component of the methane contained in the LFG there is no net
effect on the boiler proper. However, care must be taken to prevent water
accumulation in the gas delivery piping and gas train especially when this piping
is located out of doors in cold environments.
(4) In the gas stream from a typical landfill there are varying amounts of NMOCs,
which can vary from as little as 100 ppmv to over 2,000 ppmv. Since all the
species that may be found in LFG are hydrocarbons they are nearly completely
destroyed in the combustion process. There are no significant detrimental effects
due to the presence of NMOCs in the LFG stream.
(5) Hydrogen sulfide (H2S) is another trace compound, which is typically found in
LFG and is a poisonous gas at elevated concentrations. Typical levels of H2S in
methane gas streams are close to 10 ppmv, which is high enough to be detectable
by its distinct sour (rotten egg) odor. Typical natural gas has up to 3 ppmv of H2S,
which puts both fuels on roughly equal footing as to the potential for harm. H2S is
converted to SO2 during the combustion process.
(6) Siloxane often is found in LFG and can vary from a few parts per billion to many
parts per million. Siloxane is a gas that contains bound silicon. Upon reaching
typical combustion temperatures it is converted into silicon dioxide, which forms
a very light non-toxic dust that typically passes through the boiler. In most
applications small accumulations of this dust are removed annually and disposed
of. The only problems noted with this dust are on boilers with serrated fin or tight
spaced fin economizers, which act as particulate filters and can become plugged
with the silica dust. The silica dust does not adhere to most surfaces and is
removed by light brushing or air pressure. Economizers with wide fin spacing
(i.e. less than 3 fins per inch) typically do not plug with the silica dust.
3.2.4 Design changes needed to accommodate using LFG
In most situations LFG will be introduced to a boiler that already exists. The following
are design changes or modifications that should be examined. Not all of these will be
required on any given installation and it is possible that very minimal modifications will
be required. When new equipment is purchased to burn LFG, the manufacturer will be
responsible for the required design to adequately burn LFG. It should be noted that the
following assume that the LFG is being used in a existing gaseous fuel (typically natural
gas) fired boiler or process burner, in cases where the burner is used with liquid or solid
Section 3 – Landfill Gas Characterization and Utilization
3-5
fuels then the manufacturer of the burner should be contacted for specific
recommendations.
(1) Because of the increased volume of fuel required to match energy input,
LFG is normally introduced into an existing burner through a separate gas
train with separate modulating gas control valve. Typically, if the same
burner ring is to be used then the feed pressure of the gas to the ring is
increased a factor of 1.5 to 4 times that of natural gas.
(2) Since the energy content of LFG can vary by as much as 20%, an oxygen
trim system should be considered for larger (over 10 MMBtu/hr input)
burners and boilers. In these larger installations the increase in efficiency
due to oxygen trim will normally pay for itself in less than a year due to
increased boiler efficiency.
(3) Installations where there is less LFG available than the maximum required
input of the boiler, a co-fire system can be employed. Co-fire systems
have oxygen trim and will allow for maximum consumption of LFG while
allowing for the boiler to reach full fire when needed.
(4) In installation where continuity of service is desired, minimal control
modifications can be made so that loss of LFG availability will cause an
automatic transfer to natural gas or other back up fuel.
(5) In some burners (particularly larger or liquid fueled burners), a new gas-
firing ring will need to be added specifically for LFG.
(6) On newer installations, many manufacturers have experience with burning
LFG due to its similarity to sewage treatment plant digester gas. Most
boiler manufacturers have an existing design for digester gas. Digester gas
differs from LFG only in its much higher concentration of H2S.
(7) Typically the pilot will continue to be fired with natural gas. In
installations where LFG is the only fuel a propane pilot is normally used.
The preceding is intended as guides to use in evaluating the potential use of LFG as a fuel
and not as specific design recommendations. At this time, no “clean up” for the boiler
fuel application is being considered. A qualified engineer should be employed on any
project to insure the safe and successful use of LFG as an alternative fuel.
4-1
4 POTENTIAL LFGTE PROJECT SUBSIDIES
As part of this study EMCON/OWT researched the availability of governmental subsidies
that exist to help offset the cost of LFGTE system development. A list of the potential
subsidies that were researched is provided below.
4.1 Federal Renewable Energy Tax Credits
Federal Renewable Energy Tax Credits, also known as “Section 29 tax credits,” are not
available at this time. In the past, tax credits were available for projects that used landfill
gas as a fuel. Credits that were beneficial to tax payers were valued at $1.00. Landfill
gas equivalent to 1 million Btus was one credit. For comparison purposes, the past
program (expiring) values the credit at $1.059 per million Btu. Federal legislation will be
necessary for this program to become available again. Whether or not such legislation
passes in 2004 is speculative at best given the political situation and the upcoming
presidential election.
The 108th Congress debated energy bill legislation without success. Whether or not an
energy bill passes in 2004 is debatable and what the bill will contain is, again,
speculative. The bill that was progressing in 2003 valued landfill gas as a tax credit; the
suggested value was $3 per barrel of oil equivalent. This made the tax credit associated
with landfill gas used in an energy project at $0.50 per million Btu. The bill also limited
the amount of LFG that can be used to create a tax credit to only 200,000 ft cubed per
day.
4.2 Renewable Energy Production Incentive (REPI)
REPI funds are available to help subsidize LFGTE development costs for entities that are
not typically eligible for tax credits (e.g., public agencies such as the Municipality of
Anchorage). Since its inception, REPI funds have designated LFG as a second tier
renewable energy. Renewable energy sources, such as wind power, are given a higher
priority when distributing funds. Second tier energy sources receive funds only after the
available funds are distributed to higher tier renewable energy sources. While LFG
projects have received REPI funds in the past, EMCON/OWT has not included this
subsidy in the financial pro forma contained in subsequent sections. If the MOA does
develop the LFGTE project using internal funds, annual REPI applications should be
submitted.
Section 3 – Potential LFGTE Project Subsidies
4-2
4.3 Discussion of Potential Valuable Landfill Gas Attributes
This brief discussion is included to demonstrate that the attributes associated with landfill
gas can be a valuable asset to the owner. Any activity associated with a landfill and its
landfill gas should be undertaken with this knowledge. Any decisions should take into
account the current situation as it relates to the attributes discussed below. The situation
may change in the near future due to local, regional, national, and international politics.
4.3.1 Valuable Attributes of Landfill Gas
Landfill gas is a valuable commodity due to its source, municipal solid waste, and its
main constituent, methane. LFG is recognized as a renewable energy by the US DOE,
USEPA, most state energy programs, and the international bodies working to control
global warming. Electricity produced from LFG or beneficial use of the LFG can be a
source of credit that can have many values. While the areas for credit or value are still
developing across the United States and around the world, the following discussion will
assist the Municipality of Anchorage in understanding the value of these attributes and
will suggest approaches for how to proceed.
4.3.2 Renewable Energy Credits
A Renewable Energy Credit (REC) is an attribute that is given to landfill gas by those
states that have legislated renewable portfolio standards (RPS). Generally, electricity
produced by LFG is considered to have an ancillary REC attribute due to the avoided use
of fossil fuel. For each megawatt of electricity produced from LFG, one REC unit is
produced. States that have legislated a RPS generally allow RECs from LFG projects to
be used to attain compliance with the mandated portfolio standard. A portfolio standard
generally requires a pre-established percentage of energy produced from renewable
sources be sold by the power suppliers.
Electricity suppliers attain compliance with the mandated RPS through free-market
purchase of RECs from generators, who are sometimes referred to as Qualified Facilities.
RECs have been purchased for $4.50 to $40.00 per REC in Massachusetts, New Jersey,
and most recently Connecticut. Recent discussions (January 2004) with environmental
REC brokers reveal a weak market for RECs in areas not required to utilize them, such as
Alaska. The price suggested was $1.00 per REC for these “weak” areas.
RECs may be sold and “wheeled” to other states from non-RPS states1.2. These “deals”
are not lucrative at this time, with potential prices in the range of $1 to $2 per REC. This
1 Personal communication: Ana Giovinetto, Evolution Markets, and B. K. Maillet Shaw EMCON January
2004
Section 3 – Potential LFGTE Project Subsidies
4-3
is due to the voluntary market in states with no requirement to supply RECs in their
electricity portfolios. Buyers may be difficult to identify. According to one broker, the
market is probably oversold. It does show, however, that a national market is emerging.
4.4 Greenhouse Gas Credit Values
While there are few regulatory drivers in the United States for a greenhouse gas (GHG)
credit market, there is a great deal of activity at the state level to develop mandatory
carbon dioxide reduction programs. There are few regulatory requirements for utilities,
industries, and businesses to reduce their GHG emissions; therefore, there is currently
little incentive to purchase GHG offsets.
Some trades of CO2E (calculated on a CO2 equivalent basis) have taken place despite the
negative situation relative to required CO2 reductions. Companies will occasionally need
CO2E offsets. Oregon and Massachusetts have requirements for new energy producers to
offset some or all of their CO2 emissions. LFG has played a role in at least one of these
situations in the Commonwealth of Massachusetts. The Energy Facility Siting Council
(of Massachusetts) required Mirant Energy to pay $300,000 for CO2E credits for
reconstruction of a power plant.
Greenhouse gas credits are the attributes assigned by climate change programs to the
reductions in GHG emissions that are above the required levels, if any. Projects
undertaken to reduce GHG gasses qualify as GHG credits. They are generally referred to
as carbon dioxide equivalents or CO2E. The issue of whether or not the landfill is
required to control the landfill gas is very important to the creation of credits. Landfills
that are required to reduce the LFG may not have any credits available due to the
additionally3 requirement.
Discussions regarding GHG or climate change are occurring across this country. Most
state programs, such as those found in Oregon, Massachusetts, California, Connecticut,
and New Hampshire, see the need for a federal program with widespread inter-sector
trading of CO2E. This bodes well for existing and future LFG-to-energy projects. The
project owner should have the mechanisms in place to properly track and document the
LFG used and credits generated. The US Department of Energy (DOE) 1605B program
is an excellent way to start this process. The program is currently being improved to
ensure better information and that CO2E credits are registered. The revisions will be in
place within the year. DOE’s program requires gas measurement, gas generation
documentation, and equipment calibration. Regular data collection from the project
2 Personal communication between Natsource, Matt Williamson and B.K. Maillet, Shaw EMCON, January
2004
3 Additionally: Kyoto protocol and other protocols such as the World Resource Institute and World
Business Council for Sustainable Development will not allow credits from projects.
Section 3 – Potential LFGTE Project Subsidies
4-4
should be collected and maintained. As the data is filed with DOE, the credits will be
available for others to view and perhaps acquire.
At a recent SWANA LFG conference in San Antonio, Texas, Carl Bartone, a World Bank
Environmental Consultant, described his work in developing LFG to Energy projects in
Central and South America. He also described the value of the CO2E that will be the
commodity traded in the GHG arena. Bartone reports that the cost of producing a CO2E
is in the range of $3 to $4 per TCO2E from the Prototype Carbon Fund (PCF) data. He
also reports that in a 2002 report, the PCF has suggested that the marginal cost of
compliance with CO2 reductions is on the order of $15 per TCO2E. The consensus of
experts around the world is that LFG is a valuable commodity to be tracked and
documented in order to obtain the value of the credits as programs develop.
4.5 Trading Brokers
There are many traders that can handle the sale or transfer of LFG energy project
attributes. Evolution Markets, Cantor-Fitzgerald, and Natsource are among them. As the
project develops, the brokers should be made aware of the project details and schedule.
They may be able to place sales or commitments in advance with additional revenue for
the project. EMCON/OWT can prepare the introductions and information necessary for
the brokers to understand the project. Additional information on their services may be
found at the following web sites:
Natsource: www.natsource.com
Evolution Markets: www.evomarkets.com
Cantor Fitzgerald: www.cantor.com
Ecosecurities: www.ecosecurities.com
None of the above subsidies have been included in the financials contained in the
subsequent section.
5-1
5 ECONOMIC ANALYSIS
5.1 Project Assumptions and Analysis
The following assumptions have been made for the purpose of comparing each of the
beneficial use options:
• The project pro forma period of 10 years (2006-2015) is commonly used for
landfill gas to energy financial feasibility analysis. As analysis periods go to 15
years or longer, there is greater uncertainty inherent in making financial
predictions that far into the future. Also, Internal Revenue Service depreciation
tables allowed owners to use 10-year depreciation for tax purposes and this further
supported 10 years as an industry practice. It must be noted that the equipment,
with proper maintenances, may be fully operable for longer periods. The pro
formas include the depreciation methods and lives as outlined in GASB 34
(government accounting standards). The Summary page of each pro forma
includes the basic MUSA and depreciation assumptions and the 10-year total
MUSA contribution.
• An annual inflation rate of 2 percent
• Financial pro formas were developed at a breakeven or slight positive cash flow,
as MOA wishes to encourage the beneficial use of LFG generated at its landfill.
• Since the Municipal Utility Service Assessment that applies to Enterprise Fund
entities (such as the landfill), the pro formas incorporate the asset net book value
based millage rate (16 mils) and the revenue based 1.25% contribution.
• Two scenarios were analyzed for electrical generation. One of the scenarios
excludes costs to design, permit, construct, operate, and maintain the LFG
collection system, and the other includes these costs. All subsequent options
include the costs to design, permit, construct, operate, and maintain the LFG
collection system.
• Project financing, permitting, and construction will occur during 2005. Actual
beneficial use revenues will begin on January 1, 2006.
Production, capital, revenue, and O&M cost assumptions are provided for each of these
options in the following sections.
Section 4 – Economic Analysis
5-2
5.2 Option 1 – Electricity Generation
To determine the economic feasibility of an electrical generation plant at the Anchorage
Regional Landfill, the number of engines that could be brought on-line at the site is first
determined. For this facility we recommend using Caterpillar engine/generator sets,
primarily because the landfill operations already use a significant amount of CAT
equipment and also because CAT engines have a good history of performance with LFG.
Based on the requirements of CAT G3516LE engines, a total of three engines could
initially be brought into service for electrical generation. Three engines require
approximately 918 scfm of LFG at a 50% methane concentration and will generate a
gross 804 kW each. An additional generator can be brought on-line for every 306 scfm of
LFG extracted. The decision to bring more generators on-line can be made at a later date.
Capital and O&M costs for the engines are based on the utilization of three engines to
produce electricity. As shown in the financial pro-forma statement for this option (see
Appendix 3), the electricity sold by three CAT G3516LE engines is 195,070-megawatt
hours from 2006 to 2015 assuming 95% on-line and 3% plant loads are used by the plant.
It is assumed that the electricity generated will be sold to a local utility.
Utility deregulation is not currently available in Alaska; therefore, power must be sold to
local utilities. If enacted, deregulation will allow retail wheeling of your power on local
utility distribution lines. This allows you to sign up customers (through a licensed power
broker) and sell power to them instead of the customers purchasing the power from local
utilities. The idea of wheeling is to provide power to a customer at a lower cost than the
utilities, but at a higher rate than they would receive if you had an avoided cost contract.
The power lines directly adjacent to the Anchorage Regional Landfill are owned by
Matanuska Electric Association (MEA). However, MEA is contractually obligated to
buy all of its power from Chugach Electric until 2014. Currently, MEA purchases power
at a rate of 5.9 cents per kWh (average avoided cost of electrical generation and
transmission). Based on recent discussions with Chugach Power (Peter Poray), they have
verbally quoted an average electrical generation avoided cost of 4.2-cents per kWh.
However, Chugach is only willing to sign new power purchase agreements (PPA) in the
3-cent per kWh range. The avoided cost provided above may vary over the next several
years, thereby affecting the economic analysis.
Since power cannot be sold directly to MEA, power must be wheeled to Chugach using
MEA power lines. Wheeling charges for the pro formas contained in Appendix 3 assume
a wheeling rate of $0.005/kWh and an interconnection cost of $250,000.
With three CAT generators operating at 95% availability and 3% plant loads,
approximately 20.07 million kWh will be available for sale each year. During the years
2006 through 2008 it is expected that gas availability will result in slightly lower
production rates of 17.1 to 19.2 million kWh until the landfill’s gas recovery rate is
Section 4 – Economic Analysis
5-3
sufficient for full loading of the engine. As directed by MOA staff, we have developed
our pro formas on a breakeven basis. The breakeven point for the scenario that includes
GCCS construction and operations is 5.47 cents per kWh. The breakeven point for the
scenario excluding GCCS construction and operations is 4.81 cents per kWh.
In order for the MOA to sell wholesale or retail power it will need licensing as a qualified
facility (QF) by the Federal Energy Regulatory Commission (FERC). QF applications are
typically prepared for all LFG-to-Energy projects. Having QF status forces the local
utility to purchase excessive power generated but not sold to a retail customer at avoided
rates.
5.2.1 Option 1A – Electrical Generation Using Engine Generator Sets
Including Costs of Gas Collection System Installation and Annual O&M
Expenses
1. LFG VOLUMES – The project consists of three CAT Triton Powerpacks with
CAT 3516LE engines. Fuel requirements are 306 scfm (50% methane content)
per engine. Initial recoverable gas is estimated at 826 scfm, which will result in
slightly reduced kWh output; however, by 2009 the engines will have sufficient
fuel for full load operation. Future gas recovery estimates indicate that additional
engine generator sets could be added, however, our pro forma is based on three
units throughout the project life.
2. REVENUES – Based on the projected power generation, 195.07 million kWhs
could be sold over the next 10 years. To break even or produce a slight positive
cash flow (including wellfield construction and O&M costs) will require a power
sales rate of 5.47 cent per kWh, escalated 1% per year. At this rate, the
anticipated revenue for the ten-year period will be $11,176,000.
3. CAPITAL COSTS – The capital cost to construct the wellfield, generation
equipment, gas processing equipment and, interconnect with utility transmission
grid will be approximately $4,109,000.
4. O&M COSTS – The O&M costs inclusive of the wellfield, generation
equipment, gas processing, and interconnect, as well as general and administrative
costs, are projected to be $6,327,000 over the 10-year project life.
5. SUMMARY – Over the 10-year project life, the expected revenues at a sale price
of 5.47 cents per kWh will be $11,176,000. Over the same time period, the
projected expenses, including cost of ownership, will be $10,860,000.
Section 4 – Economic Analysis
5-4
5.2.2 Option 1A – Electrical Generation Using Engine Generator Sets
Excluding Costs of Gas Collection System Installation and Annual O&M
Expenses
1. LFG VOLUMES – No change.
2. REVENUES – Based on the projected power generation, 195.07 million kWhs
could be sold over the next 10 years. To break even or produce a slight positive
cash flow (including wellfield construction and O&M costs) will require a power
sales rate of 4.81 cent per kWh, escalated 1% per year. At this rate, the
anticipated revenue for the ten-year period will be $9,827,000.
3. CAPITAL COSTS – The capital cost to construct the wellfield, generation
equipment, gas processing equipment, and interconnect with utility transmission
grid will be approximately $3,207,000.
4. O&M COSTS – The O&M costs inclusive of the wellfield, generation
equipment, gas processing, and interconnect, as well as general and administrative
costs, are projected to be $6,048,000 over the 10-year project life.
5. SUMMARY – Over the 10-year project life, the expected revenues at a sale price
of 4.81 cents per kWh will be $9,827,000. Over the same time period, the
projected expenses, including cost of ownership, will be $9,584,000.
5.3 Option 2 – Transmission of LFG to Enstar Natural Gas
Pipeline
An Enstar Natural Gas Company pipeline exists approximately 990 feet east of the
proposed blower and flare station location. A topographic map is provided in Appendix 4
that displays the pipe routing and tie-in location for this option. A cross-section of this
pipe routing is also contained in the same appendix.
Based on discussions with Mr. Andrew D. White of Enstar, this natural gas pipeline
operates at a maximum of 900-psig pressure. Mr. White also indicated that it is Enstar’s
policy to only accept gas into its system that has a heating value of approximately 1,000
Btu’s per cubic foot. Since raw LFG typically has a heating value of 400 to 550 Btu/cf,
cleaning up the MOA LFG to remove carbon dioxide and air will be required.
A financial pro forma was calculated using industry-accepted figures (see Appendix 5).
For this scenario, it was assumed that this end user could utilize all generated LFG.
Results of this estimate indicate the following:
Section 4 – Economic Analysis
5-5
1. LFG VOLUMES – For the year 2006, the projected flow of LFG recovered is
826 scfm or 209,000 mmBtus. After clean up of the gas, only 160,000 mmBtus
(77% conversion to saleable Btu’s) will be available for injection into the
pipeline.
2. REVENUES – Based on the projected flows per year, assuming a 95% utilization
factor and 77% conversion to saleable Btu’s, 2,009,000 mmBtus could be
recovered and processed for sale over the next 10 years. To break even or
produce a slight positive cash flow (including wellfield construction and O&M
costs) will require a sales price of $4.32 per mmBtu, escalated 2% per year. At
this price, the anticipated revenue for the ten-year period will be $9,571,094.
3. CAPITAL COSTS – The capital cost to construct the wellfield, pipeline (990
feet), purchase compressors, and cleanup equipment will be approximately
$2,995,000.
4. O&M COSTS – The O&M costs inclusive of the wellfield, pipeline, compressor,
cleanup equipment, and electrical, as well as general and administrative costs, are
projected to be $5,605,654 over the 10-year project life.
5. SUMMARY – Over the 10-year project life, the expected revenues at a sale price
of $4.32 will be $9,571,094. Over the same time period, the projected expenses,
including cost of ownership, will be $8,935,635.
Further evaluation of this beneficial use option appears to be unnecessary. The primary
reasons this option is not economically feasible are as follows:
1 Enstar requires “clean up” of the LFG. This adds significant capital and O&M
costs.
2. The existing Enstar line is operated at a maximum of 900-psig pressure.
Compression of gas to 900 psig adds significant capital and takes a significant
amount of electric power.
5.4 Option 3 - Transmission of LFG to Eagle River School
An economic analysis was performed to determine the feasibility of constructing a
pipeline to the Eagle River School and transporting LFG to the site for use in its boilers.
The proposed boiler specifications for Eagle River School are provided in Appendix 6. A
topographic map is provided in Appendix 7 that displays the pipe routing and tie-in
location for this option. A cross-section of this pipe routing is also contained in the same
appendix. Initial discussions with the School District were very encouraging, and they
are open to the idea of utilizing LFG. However, after further analysis, the school would
only utilize a small portion of the available LFG.
Section 4 – Economic Analysis
5-6
A detailed economic analysis for this scenario was calculated using industry-accepted
figures (see Appendix 8). Results of this financial pro forma indicate the following:
1. LFG VOLUMES – Based on the past consumption of LFG at a similar existing
school in the area, Eagle River School is anticipated to require an estimated flow
of 105 scfm at 50% methane.
2. REVENUES – Based on the projected demand per year, 265,420 mmBtus could
be sold over the next 10 years. To break even or produce a slight positive cash
flow (including wellfield construction and O&M costs) will require a sales price
of $18.87 per mmBtu, escalated 2% per year. At this price, the anticipated
revenue for the ten-year period will be $5,484,108.
3. CAPITAL COSTS – The capital cost to construct the wellfield, pipeline (2.0797
miles), purchase compressors, and end user upgrades will be approximately
$2,186,000.
4. O&M COSTS – The O&M costs inclusive of the wellfield, pipeline, and
compressor, and electrical as well as general and administrative costs, are
projected to be $2,653,798 over the 10-year project life.
5. SUMMARY – Over the 10-year project life, the expected revenues at a sales
price of $18.87 will be $5,484,108. Over the same time period, the projected
expenses, including cost of ownership, will be $5,085,151.
Further evaluation of this beneficial use option appears to be unnecessary. The primary
reasons this option is not economically feasible are as follows:
1. Eagle Valley School gas demand is too low and is not consistent throughout the
year. Most of the demand is during the winter months. This condition does not
generate enough cash to offset capital and O&M costs.
2. The length of the pipeline is too long to justify the small amount of gas demanded.
This adds significant capital costs
5.5 Option 4 – Transmission of LFG to National Guard
An economic analysis was performed to determine the feasibility of constructing a
pipeline to the National Guard facilities and transporting LFG to the site for use in its
boilers. A topographic map is provided in Appendix 9 that displays the pipe routing
and tie-in location for this option. A cross-section of this pipe routing is also
contained in the same appendix. Initial discussions with the National Guard were
very encouraging, and they are open to the idea of utilizing LFG. Natural gas
consumption, equipment make and model numbers, etc., provided by the National
Section 4 – Economic Analysis
5-7
Guard revealed that only a few pieces of equipment are suitable for conversion to
utilize LFG (i.e., four Weil-McLain Boilers that use Gordon Piatt Burners). Because
of this, the demand for LFG during warmer months of the year is substantially below
the LFG production rate. A detailed economic analysis for this scenario was
calculated using industry-accepted figures (see Appendix 10). For this scenario, it was
assumed only a portion of the generated LFG could be utilized by the National Guard.
Results of this financial pro forma indicate the following:
1. LFG VOLUMES – For the year 2006, the projected flow of LFG recovered is
826 scfm. However, the National Guard Armory's seasonal gas demand is such
that the Armory annual usage of LFG would be approximately 650 scfm.
2. REVENUES – Based on the projected flows per year assuming a 95% utilization
factor, 1,643,000 mmBtus could be recovered for sale over the next 10 years. To
break even or produce a slight positive cash flow (including wellfield construction
and O&M costs) will required a sales price of $3.45 per mmBtu, escalated 2% per
year. At this price, the anticipated revenue for the ten-year period will be
$6,198,000.
3. CAPITAL COSTS – The capital cost to construct the wellfield, pipeline (2.734
miles), purchase compressors, and end user upgrades will be approximately
$2,492,000.
4. O&M COSTS – The O&M costs inclusive of the wellfield, pipeline, and
compressor, and electrical as well as general and administrative costs, are
projected to be $2,969,000 over the 10-year project life.
5. SUMMARY – Over the 10-year project life, the expected revenues at a sales
price of $3.45 will be $6,198,000. Over the same time period, the projected
expenses, including cost of ownership, will be $5,742,000.
5.6 Option 5 – Transmission of LFG to Fort Richardson
An economic analysis was performed to determine the feasibility of constructing a
pipeline to Fort Richardson and transporting LFG to the site for use in its boilers. A
topographic map is provided in Appendix 11 that displays the pipe routing and tie-in
location for this option. A cross-section of this pipe routing is also contained in the same
appendix.
Initial discussions with Ft. Richardson were very encouraging, and they are open to the
idea of utilizing LFG. The natural gas demand for Ft. Richardson vastly exceeds the
generation rate of LFG from the Anchorage Regional Landfill. A listing of the over 500
natural gas burning pieces of equipment (shown in Appendix 11) was provided by Ft.
Section 4 – Economic Analysis
5-8
Richardson staff (Debra S. Breindel). Of these nearly 500 pieces of equipment, 4 large
Cleave-Brooks boilers appear to be best suited for conversion to operate on LFG.
Cleaver-Brooks boilers have a good history of being converted to LFG use, and the ones
at Ft. Richardson are located in one single location (Building No. 726). This single high
gas demand location is ideal for LFG utilization and eliminates the need for elaborate and
costly gas delivery infrastructure.
A detailed economic analysis for this scenario was calculated using industry-accepted
figures (see Appendix 13). For this scenario, it was assumed that this end user could
utilize all the generated LFG. Results of this financial pro forma indicate the following:
1. LFG VOLUMES – For the year 2006, the projected flow of LFG recovered is
826 scfm. It is assumed that Fort Richardson Building #726 would use all
available gas.
2. REVENUES – Based on the projected flows per year, assuming a 95% utilization
factor, 2,620,000 mmBtus could be recovered for sale over the next 10 years. To
break even or produce a slight positive cash flow (including wellfield construction
and O&M costs) will require a sales price of $2.72 per mmBtu, escalated 2% per
year. At this price, the anticipated revenue for the ten-year period will be
$7,861,211.
3. CAPITAL COSTS – The capital cost to construct the wellfield, pipeline (5.1454
miles), purchase compressors, and end user upgrades will be approximately
$3,256,000.
4. O&M COSTS – The O&M costs inclusive of the wellfield, pipeline, and
compressor, and electrical as well as general and administrative costs, are
projected to be $3,564,149 over the 10-year project life.
5. SUMMARY – Over the 10-year project life, the expected revenues at a sales
price of $2.72 will be $7,861,211. Over the same time period, the projected
expenses, including cost of ownership, will be $7,189,410.
5.7 Option 6 – Transmission of LFG to Existing ML&P Facility
(George M. Sullivan Power Plant No. 2)
An economic analysis was performed to determine the feasibility of constructing a
pipeline to the nearest existing ML&P facility and transporting LFG to the site for use in
its natural gas burning equipment (boilers, gas turbines, etc.). A topographic map is
provided in Appendix 14 that displays the pipe routing and tie-in location for this option.
A cross-section of this pipe routing is also contained in the same appendix. Initial
discussions with ML&P were encouraging, and they are open to the idea of utilizing LFG.
Section 4 – Economic Analysis
5-9
However, after further analysis, the nearest plant was determined to be over six miles
away.
It is preferred that a low-pressure piece of equipment be utilized for the LFG delivered to
this power plant. Preliminary discussions with ML&P staff indicated that a low-pressure
end use could most likely be identified. If a low-pressure piece of equipment is not
available and a high-pressure application is required to be utilized, the cost of
pressurization will substantially increase capital expenditures. For this option, it was
assumed a low pressure could be identified.
A detailed economic analysis for this scenario was calculated using industry-accepted
figures (see Appendix 15). For this scenario, it was assumed that this end user could
utilize all the generated LFG. Results of this financial pro forma indicate the following:
1. LFG VOLUMES – For the year 2006, the projected flow of LFG recovered is
826 scfm. It is assumed that the George M. Sullivan Power Plant would use all
available gas.
2. REVENUES – Based on the projected flows per year, assuming a 95% utilization
factor, 2,620,000 mmBtus could be recovered for sale over the next 10 years. To
break even or produce a slight positive cash flow (including wellfield construction
and O&M costs) will require a sales price of $2.86 per mmBtu, escalated 2% per
year. At this price, the anticipated revenue for the ten-year period will be
$8,256,531.
3. CAPITAL COSTS – The capital cost to construct the wellfield, pipeline (6
miles), purchase compressors, and end user upgrades will be approximately
$3,527,000.
4. O&M COSTS – The O&M costs inclusive of the wellfield, pipeline, and
compressor, and electrical as well as general and administrative costs, are
projected to be $3,598,169 over the 10-year project life.
5. SUMMARY – Over the 10-year project life, the expected revenues at a sales
price of $2.86 will be $8,256,531. Over the same time period, the projected
expenses, including cost of ownership, will be $7,522,934.
5.8 Option 7 – Transmission of LFG to Proposed ML&P Facility
(Fossil Creek Power Plant)
An economic analysis was performed to determine the feasibility of constructing a
pipeline to a ML&P proposed facility at Fossil Creek and transporting LFG to the site for
use in its electrical generating equipment. A topographic map is provided in Appendix
Section 4 – Economic Analysis
5-10
16 that displays the pipe routing and tie-in location for this option. A cross-section of this
pipe routing is also contained in this same appendix. Initial discussions were held with
ML&P, and they are very open to the idea of utilizing LFG because they could
incorporate LFG use into their design. Again, it was assumed a low-pressure application
could be identified for the proposed power plant. If a low-pressure piece of equipment is
not available and a high-pressure application is required to be utilized, the cost of
pressurization will substantially increase capital expenditures.
A detailed economic analysis for this scenario was calculated using industry-accepted
figures (see Appendix 17). For this scenario, it was assumed that this end user could
utilize all the generated LFG. Results of this financial pro forma indicate the following:
1. LFG VOLUMES – For the year 2006, the projected flow of LFG recovered is
826 scfm. It is assumed that the proposed Fossil Creek Power Plant would use all
available gas.
2. REVENUES – Based on the projected flows per year, assuming a 95% utilization
factor, 2,620,000 mmBtus could be recovered for sale over the next 10 years. To
break even or produce a slight positive cash flow (including wellfield construction
and O&M costs) will require a sales price of $2.14 per mmBtu, escalated 2% per
year. At this price, the anticipated revenue for the ten-year period would be
$6,194,794.
3. CAPITAL COSTS – The capital cost to construct the wellfield, pipeline (2.0797
miles), purchase compressors, and end user upgrades will be approximately
$2,285,000.
4. O&M COSTS – The O&M costs inclusive of the wellfield, pipeline, and
compressor, and electrical as well as general and administrative costs, are
projected to be $3,165,628 over the 10-year project life.
5. SUMMARY – Over the 10-year project life, the expected revenues at a sales
price of $2.14 will be $. Over the same time period, the projected expenses,
including cost of ownership, will be $5,713,379.
5.9 Option 8- Treatment of Liquid Generated or Collected at the
Anchorage Regional Landfill
5.9.1 Leachate Evaporation Using LFG
Leachate generated by the landfill is currently accumulated by a collection system and
transported to an off-site wastewater treatment plant owned and operated by the
Section 4 – Economic Analysis
5-11
Municipality of Anchorage. Leachate evaporation utilizing LFG has been conducted as
part of this study to enable the Municipality to compare the evaporation costs to its
current disposal costs.
Option 8 involves disposing of leachate by the proposed flare facility to incorporate
EMCON/OWT’s patented Leachate Evaporator (E-Vap). The E-Vap evaporates leachate
and the off vapors are destroyed in an enclosed flare, thus eliminating the need for
complex treatment of leachate.
Prior to performing a detailed economic analysis of this option, a rough estimate was
calculated using industry-accepted figures. The results of this rough estimate determined
the following:
1. On average, the leachate collection system at the Anchorage Regional Landfill has
collected approximately 7,000,000 gallons per year since 1990.Pending
implementation of design changes currently under consideration (including
complete recirculation) may significantly reduce this volume.
2. Collection, transport, and disposal costs are limited to transportation and are in the
range of 2 to 3 cents per gallon.
3. Typical costs for treatment of collected leachate by our patented E-Vap
technology are higher than 3 cents per gallon.
Based on current leachate collection rates, a 20,000-gpd-leachate evaporator would be
needed. Recent pro forma for this size unit (with a flare) indicated a disposal cost of
approximately 6.8 cents per gallon. Again, the landfill is currently hauling leachate to the
city sewage treatment plant for a cost of less than 3 cents for trucking and no cost from
the treatment plant. Therefore, further evaluation of this beneficial use option appears to
be unnecessary.
5.9.2 Glycol Recycling Using LFG
At the request of the MOA, EMCON/OWT has briefly reviewed the feasibility of
utilizing LFG to recycle glycol collected at the landfill. The option of recycling glycol
utilizing LFG has been included as a part of this study so the Municipality can compare
the recycling costs to its current disposal costs.
Prior to performing a detailed economic analysis of this option, a rough estimate was
calculated using industry-accepted figures. The results of this rough estimate determined
the following:
1. On an annual basis, the Municipality receives $8,400 for the collection and
disposal of 12,000 gallons of glycol ($0.70 per gallon) from its customers.
Section 4 – Economic Analysis
5-12
2. The Municipality’s annual disposal costs for the 12,000 gallons are $35,000.
3. Engineering design, permitting, equipment procurement, construction, startup and
commissioning a fully developed project cost for a glycol distillation system and
heating device will be greater than $300,000.
4. O&M costs of 5% of capital investment will be approximately $15,000 per year
5. 6000 gpy of glycol could be recovered and sold at a price of $2.50 per gallon,
generating an annul income of only $15,000.
6. The payback period for the $300,000 investment exceeds generally accepted
accounting practices.
An initial pro forma was developed for the potential glycol scenario and is contained in
Appendix 18. This pro forma indicated that at a $4.50 per gallon resale price, the
required breakeven quantity is 14,700 gallons per year. Because of processing
constraints, this equates to collecting nearly 30,000 gallons of waste glycol per year.
Again, the MOA currently collects approximately 12,000 gallons per year. Additionally,
MOA is concerned about competing with other private entities for other sources of waste
glycol. Therefore, further evaluation of this beneficial use option appears to be
unnecessary.
6-1
6 SUMMARY OF FINDINGS
A summary of the findings for each of the options presented in Section 5 is provided
below:
• LFG modeling indicates that sufficient recoverable quantities of LFG are present
to support 2.4 MW electricity generation (Option No. 1). The electricity
produced can be sold to several different local utilities, including Municipal Light
& Power.
Negotiation of an electric sales agreement with the a local utility is necessary
under this option. These negotiations are quite often a long and difficult process
and are typically more difficult with the absence of a local or state renewable
energy portfolio standard.
The most lucrative electric sale potential appears to be with MEA (currently
buying power at from Chugach at 5.9 cent per kW) At this rate, a LFGTE project
would breakeven (LFG collection/flaring costs included in pro forma: 5.84 cents
per kW) or be profitable (LFG collection/flaring costs included in pro forma: 4.81
cents per kW). Because MEA is obligated to purchase all their power from
Chugach Electric until 2014, a special exemption will be required. It is anticipated
that renewable energy requirement will soon be requested by the federal
government at local military bases. If this requirement is requested the probability
of obtaining this exemption or a direct sale to another utility or the federal
government is drastically increase.
• The capital and O&M to operate a high Btu LFG plant and inject the LFG into
Enstar’s nearby pipeline (Option No. 2) is not economically feasible.
• The capital and O&M to operate a LFG pipeline to the Municipality of Anchorage
Eagle Valley School (Option No. 3) is not economically feasible.
• The sale of medium Btu LFG to the National Guard (Option No. 4) may be
economically feasible, but there appears to be more lucrative options available
(see Option Nos. 5, 6 and 7).
• Sale of a medium Btu LFG to ML&P, Ft. Richardson (Option No. 5), appears to
economically feasible and provides just slightly better financial results than the
sale of LFG to George M. Sullivan Power Plant No. 2 (Option No. 6) The boiler
identified for conversion are new pieces of equipment and are planned for long
term use on the base. However, Fort Richardson has been included on previous
6-2
base realignment and closure (BRAC) lists and therefore could present
considerable financial risk if closed. In addition, negotiating a gas sales agreement
with the Federal government and the equipment operator (i.e., Honeywell) may be
more troublesome than other options.
• Sale of medium Btu LFG to ML& P’s George M. Sullivan Power Plant No. 2
(Option No. 6) appears to be economically feasible. Only the sale of LFG to the
proposed Fossil Creek Facility (Option No.7) substantially outperforms this
option. Since this plant already exists and is owned by the MOA, this option may
present the least amount of risk.
• Sale of medium Btu LFG to ML& P’s proposed Fossil Creek Facility (Option No.
7) appears to be economically feasible. This option appears to be the most
economically feasible, but does present the risk of delayed construction or even
never being built.
• Option 8, utilizing LFG to treat on-site liquid (leachate and glycol) is not
economically feasible.
7-1
7 LIMITATIONS
The services described in this report were performed consistent with generally accepted
professional consulting principles and practices. No other warranty, expressed or
implied, is made. These services were performed consistent with our agreement with the
Municipality of Anchorage. This report is solely for the use and information of
Anchorage Regional Landfill unless otherwise noted. Any reliance on this report by a
third party is at such party's sole risk.’
Opinions and recommendations contained in this report apply to conditions existing when
services were performed and are intended only for the client, purposes, locations, time
frames, and project parameters indicated. We are not responsible for the impacts of any
changes in environmental standards, practices, or regulations subsequent to performance
of services. We do not warrant the accuracy of information supplied by others, nor the
use of segregated portions of this report.
The LFG generation modeling techniques used by EMCON/OWT and the LFG industry
are, by definition, hypothetical, and can only be used as a very general tool for producing
a range of estimates to aid in determining the direction of further investigations. Actual
LFG generation and collection rates are dependent on many variables, including: refuse
composition, moisture, pH, cover soil permeability, well spacing, continuing fill rates,
etc.. Typically these parameters are not well defined at the time of modeling and/or differ
somewhat from those actually experienced during future site operation.
The LFG generation modeling provided herein was performed with today’s current
standards of practice and no warranty or representation, expressed or implied, is made, as
to the actual LFG production that will occur in the future. Opinions and
recommendations contained in this report are based on the information available and
certain assumptions that were deemed reasonable when our services were performed. We
are not responsible for the impacts of any changes in information, site operations or
methods that may change in the future.
APPENDIX 1
LANDFILL GAS GENERATION MODEL
LANDFILL GAS GENERATION MODEL INPUT SUMMARYMunicipality Of Alaska (Moderately Dry/Moderately Wet)General Information Waste Stream Composition Analysis performed by:Erik C. KorsmoProject number: Component Composition 1 Composition 2Date of analysis: 01/19/04OrganicsAnalysis TimeframeFood waste9.0% N/AGarden waste19.0% N/AOpening year of the landfill: 1987 Paper waste33.0% N/AClosing year of the landfill: 2043 Other organics7.0% N/AAnalysis performed through the year: 2100 Organic Subtotal68.0% N/AInorganics32.0% N/ASite Operating ConditionsTotal100.0% N/ARefuse moisture condition: Moderately DryRefuse temperature: 90 °FAverage compacted refuse density: 1,200 lb/cyGeneration Rate PropertiesLFG System Recovery EfficiencyRapid subgroup conversion time: 4 yrsIntermediate subgroup conversion time: 33 yrsSlow subgroup conversion time: 120 yrsID Number Recovery EfficiencyEffective PeriodEPA Modeling Parameters1 70% 1987 - 2100Methane generation potential (Lo): 6,000 ft3/MgMethane generation rate (k):0.02 yr-1NMOC concentration (CNMOC):4,000 ppmvN:\PROJECTS\LANDFILL GAS DESIGN CENTER DATABASE\MODELS\EMCON LFG MODELING\MOA LFG Generations:M.Dry-M.Wet Inputs Page 1 of 5
Summary of Results
Municipality Of Alaska (Moderately Dry/Moderately Wet)
Year
Annual Refuse
Acceptance Rate
Cumulative
Refuse
Acceptance Rate
Upper limit of
LFG Generation
Rate
Lower limit of
LFG Generation
Rate
Upper limit of
LFG Recovery
Rate
Lower limit of
LFG Recovery
Rate
Average LFG
Generation Rate
EPA LFG
Recovery Rate
(tons) (tons) (scfm) (scfm) (scfm) (scfm) (scfm) (scfm)
1987 25,053 25,053 0 0 0 0 0 0
1988 184,644 209,697 322127
1989 191,885 401,581 23 15 16 11 20 59
1990 201,797 603,378 45 29 31 21 39 112
1991 196,115 799,493 82 54 58 38 71 166
1992 224,296 1,023,788 127 83 89 58 110 218
1993 223,047 1,246,835 184 120 129 84 160 277
1994 233,982 1,480,817 251 164 176 115 219 334
1995 240,884 1,721,701 331 216 231 151 287 393
1996 227,815 1,949,516 417 272 292 191 363 453
1997 251,990 2,201,506 507 331 355 232 441 509
1998 250,657 2,452,163 599 390 419 273 521 569
1999 280,866 2,733,028 683 446 478 312 594 629
2000 279,760 3,012,788 770 502 539 352 670 695
2001 279,666 3,292,454 854 557 598 390 743 760
2002 304,592 3,597,046 938 612 657 428 816 824
2003 284,400 3,881,446 1,023 667 716 467 889 893
2004 300,000 4,181,446 1,103 719 772 504 959 956
2005 300,000 4,481,446 1,186 773 830 541 1,031 1,021
2006 300,000 4,781,446 1,266 826 886 578 1,101 1,085
2007 300,000 5,081,446 1,345 877 942 614 1,170 1,148
2008 300,000 5,381,446 1,423 928 996 649 1,237 1,210
2009 300,000 5,681,446 1,497 976 1,048 683 1,302 1,270
2010 300,000 5,981,446 1,568 1,023 1,098 716 1,364 1,330
2011 300,000 6,281,446 1,636 1,067 1,145 747 1,423 1,388
2012 300,000 6,581,446 1,701 1,109 1,191 777 1,479 1,445
2013 300,000 6,881,446 1,763 1,150 1,234 805 1,533 1,501
2014 300,000 7,181,446 1,822 1,188 1,275 832 1,584 1,555
2015 300,000 7,481,446 1,877 1,224 1,314 857 1,632 1,609
2016 300,000 7,781,446 1,930 1,259 1,351 881 1,678 1,661
2017 300,000 8,081,446 1,980 1,292 1,386 904 1,722 1,713
2018 300,000 8,381,446 2,028 1,323 1,420 926 1,764 1,764
2019 300,000 8,681,446 2,073 1,352 1,451 947 1,803 1,813
2020 300,000 8,981,446 2,117 1,380 1,482 966 1,841 1,862
2021 300,000 9,281,446 2,158 1,407 1,510 985 1,876 1,909
2022 300,000 9,581,446 2,197 1,433 1,538 1,003 1,910 1,956
2023 300,000 9,881,446 2,234 1,457 1,564 1,020 1,942 2,001
2024 300,000 10,181,446 2,269 1,480 1,588 1,036 1,973 2,046
2025 300,000 10,481,446 2,303 1,502 1,612 1,051 2,002 2,090
2026 300,000 10,781,446 2,334 1,522 1,634 1,066 2,030 2,133
N:\PROJECTS\LANDFILL GAS DESIGN CENTER DATABASE\MODELS\EMCON LFG MODELING\MOA LFG Generations:M.Dry-M.Wet
Outputs Page 2 of 5
Summary of Results
Municipality Of Alaska
(continued)
Year
Annual Refuse
Acceptance Rate
Cumulative
Refuse
Acceptance Rate
Upper limit of
LFG Generation
Rate
Lower limit of
LFG Generation
Rate
Upper limit of
LFG Recovery
Rate
Lower limit of
LFG Recovery
Rate
Average LFG
Generation Rate
EPA LFG
Recovery Rate
(tons) (tons) (scfm) (scfm) (scfm) (scfm) (scfm) (scfm)
2027 300,000 11,081,446 2,365 1,542 1,655 1,080 2,056 2,175
2028 300,000 11,381,446 2,394 1,561 1,676 1,093 2,082 2,217
2029 300,000 11,681,446 2,421 1,579 1,695 1,105 2,106 2,257
2030 300,000 11,981,446 2,448 1,596 1,713 1,117 2,128 2,297
2031 300,000 12,281,446 2,473 1,613 1,731 1,129 2,150 2,336
2032 300,000 12,581,446 2,496 1,628 1,748 1,140 2,171 2,374
2033 300,000 12,881,446 2,519 1,643 1,763 1,150 2,191 2,412
2034 300,000 13,181,446 2,541 1,657 1,779 1,160 2,209 2,448
2035 300,000 13,481,446 2,561 1,671 1,793 1,169 2,227 2,484
2036 300,000 13,781,446 2,581 1,683 1,807 1,178 2,244 2,519
2037 300,000 14,081,446 2,600 1,696 1,820 1,187 2,261 2,554
2038 300,000 14,381,446 2,618 1,707 1,832 1,195 2,276 2,588
2039 300,000 14,681,446 2,635 1,718 1,844 1,203 2,291 2,621
2040 300,000 14,981,446 2,651 1,729 1,856 1,210 2,305 2,653
2041 300,000 15,281,446 2,667 1,739 1,867 1,217 2,319 2,685
2042 300,000 15,581,446 2,681 1,749 1,877 1,224 2,332 2,717
2043 300,000 15,881,446 2,696 1,758 1,887 1,231 2,344 2,747
2044 2,709 1,767 1,896 1,237 2,356 2,777
2045 2,689 1,754 1,882 1,227 2,338 2,722
2046 2,670 1,741 1,869 1,219 2,322 2,668
2047 2,626 1,713 1,838 1,199 2,284 2,616
2048 2,570 1,676 1,799 1,173 2,235 2,564
2049 2,499 1,630 1,749 1,141 2,173 2,513
2050 2,412 1,573 1,688 1,101 2,097 2,463
2051 2,311 1,507 1,618 1,055 2,009 2,414
2052 2,200 1,434 1,540 1,004 1,913 2,367
2053 2,084 1,359 1,459 951 1,812 2,320
2054 1,973 1,287 1,381 901 1,715 2,274
2055 1,874 1,222 1,312 856 1,630 2,229
2056 1,781 1,162 1,247 813 1,549 2,185
2057 1,693 1,104 1,185 773 1,473 2,141
2058 1,610 1,050 1,127 735 1,400 2,099
2059 1,532 999 1,072 699 1,332 2,057
2060 1,458 951 1,020 666 1,268 2,017
2061 1,388 905 971 633 1,207 1,977
2062 1,321 862 925 603 1,149 1,938
2063 1,258 820 881 574 1,094 1,899
2064 1,198 782 839 547 1,042 1,862
2065 1,142 745 799 521 993 1,825
2066 1,088 710 762 497 946 1,789
N:\PROJECTS\LANDFILL GAS DESIGN CENTER DATABASE\MODELS\EMCON LFG MODELING\MOA LFG Generations:M.Dry-M.Wet
Outputs Page 3 of 5
Summary of Results
Municipality Of Alaska
(continued)
Year
Annual Refuse
Acceptance Rate
Cumulative
Refuse
Acceptance Rate
Upper limit of
LFG Generation
Rate
Lower limit of
LFG Generation
Rate
Upper limit of
LFG Recovery
Rate
Lower limit of
LFG Recovery
Rate
Average LFG
Generation Rate
EPA LFG
Recovery Rate
(tons) (tons) (scfm) (scfm) (scfm) (scfm) (scfm) (scfm)
2067 1,037 676 726 473 902 1,753
2068 989 645 692 451 860 1,719
2069 942 615 660 430 820 1,684
2070 899 586 629 410 782 1,651
2071 857 559 600 391 745 1,618
2072 818 533 572 373 711 1,586
2073 780 509 546 356 678 1,555
2074 744 485 521 340 647 1,524
2075 710 463 497 324 618 1,494
2076 678 442 475 310 590 1,464
2077 648 422 453 296 563 1,435
2078 618 403 433 282 538 1,407
2079 591 385 414 270 514 1,379
2080 565 368 395 258 491 1,352
2081 540 352 378 246 469 1,325
2082 516 336 361 235 449 1,299
2083 493 322 345 225 429 1,273
2084 472 308 330 215 410 1,248
2085 451 294 316 206 392 1,223
2086 432 282 302 197 376 1,199
2087 413 270 289 189 359 1,175
2088 396 258 277 181 344 1,152
2089 379 247 265 173 330 1,129
2090 363 237 254 166 316 1,107
2091 348 227 243 159 302 1,085
2092 333 217 233 152 290 1,063
2093 320 208 224 146 278 1,042
2094 306 200 214 140 266 1,022
2095 294 192 206 134 255 1,001
2096 282 184 197 129 245 982
2097 270 176 189 123 235 962
2098 260 169 182 119 226 943
2099 249 163 174 114 217 924
2100 239 156 168 109 208 906
N:\PROJECTS\LANDFILL GAS DESIGN CENTER DATABASE\MODELS\EMCON LFG MODELING\MOA LFG Generations:M.Dry-M.Wet
Outputs Page 4 of 5
05001,0001,5002,0002,5003,00019871991199519992003200720112015201920232027203120352039204320472051205520592063206720712075207920832087209120952099Upper limit of LFG Generation RateLower limit of LFG Generation RateAverage LFG Generation RateLandfill Gas Generation Rate (scfm)Municipality Of AlaskaLandfill Gas Generation Rate (M.Dry/M.Wet)YearN:\PROJECTS\LANDFILL GAS DESIGN CENTER DATABASE\MODELS\EMCON LFG MODELING\MOA LFG Generations:M.Dry-M.Wet Gen & Rec Page 5 of 5
Lag Time Conversion Time Peak Results (scfm) Present Results (scfm)Rapid Moderate Slow Rapid Moderate Slow Year Upper LFG Lower LFG Average Year Upper LFG Lower LFG AverageDry < 80 1 1 2 7 80 200 2056 1,156 754 809 2004 160 105 139 Dry/M.Dry < 80 1 1 2 6 60 170 2044 1,190 776 1,035 2004 224 146 195 M.Dry/Dry < 80 0 1 1 6 60 170 2048 2,116 1,380 1,840 2004 462 301 401 M.Dry < 80 0 1 1 5 40 140 2044 2,482 1,619 2,158 2004 944 616 821 (R) M. Dry/M.Wet 80 0 1 1 4 33 120 2044 2,591 2,253 1,690 2004 1,055 688 918 (R) M. Dry/M.Wet 90 0 1 1 4 33 120 2044 2,709 1,767 2,356 2004 1,103 719 959 (R) M.Wet/M.Dry 80 0 0 1 4 33 120 2044 3,285 2,142 2,856 2004 1,703 1,111 1,481 (R) M.Wet/M.Dry90 0 0 1 4 33 120 2044 3,474 2,266 3,021 2004 1,801 1,175 1,566 (R) M.Wet 80 0 0 1 3 25 100 2044 3,321 2,166 2,888 2004 2,087 1,361 1,814 (R) M.Wet 90 0 0 1 3 25 100 2044 3,513 3,055 2,291 2004 2,207 1,439 1,919 (R) = Assumes Recirculation ActivitiesBold = Output AttachedPurpose:Lag Time Conversion TimeRapid Moderate Slow Rapid Moderate Slow1 1 2 7 80 200 Methodology:0 1 1 5 40 1400 0 1 3 25 1000 0 0 2 15 70 Prepared By: Erik C. Korsmo Date: 1/20/2004Checked By: Douglas M. Gatrell Date: 1/20/2004Notes:1. EMCON assumes refuse temperature to be approximately 65 degrees F. based on owner provided information.2. EMCON assumes recirculation will raise temperature of refuse 10 - 15 degrees F.3. EMCON Modeling does not recognize any significant influence in Unit Gas Yield for temperatures below 80 degrees F.4. EMCON-LFGM proprietary model was utilized for the generation rates. Complete output information is available upon request.5. EMCON assumes the filling rates would continue at 300,000 tons/year until year 2043.WetDryUtilizing EMCON's LFGM, vary the moisture and temperature parameters to determine the most accurate representation of the existing and future LFG generation.M.DryM.Wet081,&,3$/,7<2)$/$6.$/)*6(16,7,9,7<*(1(5$7,215(68/76Description Temp.Determine the future LFG generation for the Municipality of Anchorage - Regional Landfill, based on the existing information provided by the owner.Default ValuesDescription
APPENDIX 2
LABORATORY ANALYSIS AND POSSIBLE “CLEAN-UP” PROCESS
AIR TOXICS LTD.@
AN ENVIRONMENTAL ANALYTICAL LABORATORY
Air Toxics Ltd. Introduces the Electronic Report
Thank you for choosing Air Toxics Ltd. To better serve our customers, we are providing your report by e-mail.
This document is provided in Portable Document Format which can be viewed with Acrobat Reader by
Adobe.
This electronic report includes the following:
• Work order Summary;
• Laboratory Narrative;
• Results; and
• Chain of Custody (copy).
180 BLUE RAVINE ROAD, SUITE B FOLSOM, CA - 95630
(916) 985-1000 .FAX (916) 985-1020
Hours 8:00 A.M to 6:00 P.M. Pacific
E-mail to:samplereceiving@airtoxics.com
AIR TOXICS LTD.
AN ENVIRONMENTAL ANALYTICAL LABORATORY
@
Mr. Paul Tower
Applied Filter Technology
19524 75th Ave SE
Snohomish, WA 98296
WORK ORDER #: 0311168A
CLIENT: BILL TO:
PHONE:
Mr. Paul Tower
Applied Filter Technology
19524 75th Ave SE
Snohomish, WA 98296
360-668-6021
360-668-7017
11/11/03
DATE COMPLETED:11/19/03
P.O. #
PROJECT #826931.04002003
SHAW/EMCON-Anchorage Regional
Work Order Summary
FAX:
DATE RECEIVED:CONTACT:Kelly Buettner
NAMEFRACTION #TEST VAC./PRES.
RECEIPT
01A 301B Modified TO-14A Tedlar Bag
02A Lab Blank Modified TO-14A NA
03A CCV Modified TO-14A NA
04A LCS Modified TO-14A NA
CERTIFIED BY:
Laboratory Director
DATE:
Name of Accrediting Agency: NELAP/Florida Department of Health, Scope of Application: Clean Air Act,
Accreditation number: E87680, Effective date: 07/01/03, Expiration date: 06/30/04
180 BLUE RAVINE ROAD, SUITE B FOLSOM, CA - 95630
(916) 985-1000 . (800) 985-5955 . FAX (916) 985-1020
11/24/03
Page 1 of 11
This report shall not be reproduced, except in full, without the written approval of Air Toxics Ltd.
Air Toxics Ltd. certifies that the test results contained in this report meet all requirements of the NELAC standards
Certfication numbers: AR DEQ, CA NELAP - 02110CA, LA NELAP/LELAP- AI 30763, NJ NELAP - CA004
NY NELAP - 11291, UT NELAP - 9166389892
LABORATORY NARRATIVE
Modified TO-14A
Applied Filter Technology
Workorder# 0311168A
One 1 Liter Tedlar Bag sample was received on November 11,2003. Thelaboratory performed analysis via
modified EPA Method TO-14A using GC/MS in the full scan mode. The method involves concentrating up
to 0.5 liters of air. The concentrated aliquot is then flash vaporized and swept through a water management
system to remove water vapor. Following dehumidification, the sample passes directly into the GC/MS for
analysis. See the data sheets for the reporting limits for each compound.
Method modifications taken to run these samples include:
Requirement ATL ModificationsTO-14A
Continuing Calibration criteria </= 30% Difference </= 30% Difference with two allowed out to </= 40%
Difference; flag and narrate outliers
Initial Calibration criteria RSD<30% RSD</=30%, two compounds allowed up to 40%.
Moisture control Nafion Dryer Multisorbent trap
Blank acceptance criteria <0.20 ppbv <Reporting Limit
Primary ions for Quantification Freon 114: 85, Carbon
Tetrachloride: 117,
Trichloroethene: 130,
Ethyl Benzene, m,p-
and o-Xylene: 91
Freon 114: 135, Carbon Tetrachloride: 119, Trichloroethene:
95, Ethyl Benzene, m,p- and o-Xylene: 106
Dilutions for Initial Calibration Dynamic dilutions or
static using canisters
Syringe dilutions
BFB absolute abundance criteria Within 10% of that
from previous day.
CCV internal standard area counts are compared to ICAL,
corrective action for > 40% D
Sample Load Volume 400 mL Varied to 200 mL
Receiving Notes
The chain of custody information for sample 301B did not match the entry on the sample tag. The
discrepancy was noted in the Login email and the information on the chain of custody was used to process
and report the sample.
There were no analytical discrepancies.
Analytical Notes
Eight qualifiers may have been used on the data analysis sheets and indicates as follows:
B - Compound present in laboratory blank greater than reporting limit (bac kground subtraction not
performed).
J - Estimated value.
E - Exceeds instrument calibration range.
S - Saturated peak.
Q - Exceeds quality control limits.
U - Compound analyzed for but not detected above the reporting limit.
UJ- Non-detected compound associated with low bias inthe CCV
Definition of Data Qualifying Flags
Page 2 of 11
N - The identification is based on presumptive evidence.
File extensions may have been used on the data analysis sheets and indicates
as follows:
a-File was requantified
b-File was quantified by a second column and detector
r1-File was requantified for the purpose of reissue
Page 3 of 11
SAMPLE NAME: 301B
ID#: 0311168A-01A
MODIFIED EPA METHOD TO-14A GC/MS FULL SCAN
b111125File Name:
AIR TOXICS LTD.
Dil. Factor:133
Date of Collection: 11/10/03
Date of Analysis: 11/12/03 01:12 AM
(uG/m3)(ppbv)(uG/m3)(ppbv)Compound
AmountAmountRpt. LimitRpt. Limit
66 330 3400 17000Freon 12
66 470 130 900Freon 114
66 170 4600 12000Vinyl Chloride
66 260 Not Detected Not DetectedBromomethane
66 180 1600 4400Chloroethane
66 380 2600 15000Freon 11
66 270 86 3401,1-Dichloroethene
66 520 150 1100Freon 113
66 230 15000 52000Methylene Chloride
66 270 9600 390001,1-Dichloroethane
66 270 2300 9200cis-1,2-Dichloroethene
66 330 Not Detected Not DetectedChloroform
66 370 390 22001,1,1-Trichloroethane
66 420 Not Detected Not DetectedCarbon Tetrachloride
66 220 1300 4200Benzene
66 270 Not Detected Not Detected1,2-Dichloroethane
66 360 620 3400Trichloroethene
66 310 Not Detected Not Detected1,2-Dichloropropane
66 310 Not Detected Not Detectedcis-1,3-Dichloropropene
66 250 5200 20000Toluene
66 310 Not Detected Not Detectedtrans-1,3-Dichloropropene
66 370 Not Detected Not Detected1,1,2-Trichloroethane
66 460 Not Detected Not DetectedTetrachloroethene
66 520 Not Detected Not Detected1,2-Dibromoethane (EDB)
66 310 Not Detected Not DetectedChlorobenzene
66 290 69 300Ethyl Benzene
66 290 96 420m,p-Xylene
66 290 Not Detected Not Detectedo-Xylene
66 290 Not Detected Not DetectedStyrene
66 460 Not Detected Not Detected1,1,2,2-Tetrachloroethane
66 330 Not Detected Not Detected1,3,5-Trimethylbenzene
66 330 Not Detected Not Detected1,2,4-Trimethylbenzene
66 410 Not Detected Not Detected1,3-Dichlorobenzene
66 410 Not Detected Not Detected1,4-Dichlorobenzene
66 350 Not Detected Not Detectedalpha-Chlorotoluene
66 410 Not Detected Not Detected1,2-Dichlorobenzene
66 150 Not Detected Not Detected1,3-Butadiene
66 240 17000 62000Hexane
66 230 9300 33000Cyclohexane
66 280 4600 19000Heptane
66 450 Not Detected Not DetectedBromodichloromethane
66 580 Not Detected Not DetectedDibromochloromethane
Page 4 of 11
SAMPLE NAME: 301B
ID#: 0311168A-01A
MODIFIED EPA METHOD TO-14A GC/MS FULL SCAN
b111125File Name:
AIR TOXICS LTD.
Dil. Factor:133
Date of Collection: 11/10/03
Date of Analysis: 11/12/03 01:12 AM
(uG/m3)(ppbv)(uG/m3)(ppbv)Compound
AmountAmountRpt. LimitRpt. Limit
66 330 Not Detected Not DetectedCumene
66 330 Not Detected Not DetectedPropylbenzene
270 560 Not Detected Not DetectedChloromethane
270 2000 Not Detected Not Detected1,2,4-Trichlorobenzene
270 2900 Not Detected Not DetectedHexachlorobutadiene
270 640 910 2200Acetone
270 840 Not Detected Not DetectedCarbon Disulfide
270 660 Not Detected Not Detected2-Propanol
270 1100 Not Detected Not Detectedtrans-1,2-Dichloroethene
270 950 Not Detected Not DetectedVinyl Acetate
270 800 2300 68002-Butanone (Methyl Ethyl Ketone)
270 800 720 2200Tetrahydrofuran
270 970 Not Detected Not Detected1,4-Dioxane
270 1100 260 J 1100 J4-Methyl-2-pentanone
270 1100 Not Detected Not Detected2-Hexanone
270 2800 Not Detected Not DetectedBromoform
270 1300 Not Detected Not Detected4-Ethyltoluene
270 970 Not Detected Not DetectedMethyl tert-butyl ether
270 510 Not Detected Not DetectedEthanol
J = Estimated value.
Container Type: 1 Liter Tedlar Bag
Limits%RecoverySurrogates
Method
105 70-1301,2-Dichloroethane-d4
100 70-130Toluene-d8
101 70-1304-Bromofluorobenzene
Page 5 of 11
SAMPLE NAME: Lab Blank
ID#: 0311168A-02A
MODIFIED EPA METHOD TO-14A GC/MS FULL SCAN
b111108aFile Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/11/03 03:03 PM
(uG/m3)(ppbv)(uG/m3)(ppbv)Compound
AmountAmountRpt. LimitRpt. Limit
0.50 2.5 Not Detected Not DetectedFreon 12
0.50 3.6 Not Detected Not DetectedFreon 114
0.50 1.3 Not Detected Not DetectedVinyl Chloride
0.50 2.0 Not Detected Not DetectedBromomethane
0.50 1.3 Not Detected Not DetectedChloroethane
0.50 2.8 Not Detected Not DetectedFreon 11
0.50 2.0 Not Detected Not Detected1,1-Dichloroethene
0.50 3.9 Not Detected Not DetectedFreon 113
0.50 1.8 Not Detected Not DetectedMethylene Chloride
0.50 2.0 Not Detected Not Detected1,1-Dichloroethane
0.50 2.0 Not Detected Not Detectedcis-1,2-Dichloroethene
0.50 2.5 Not Detected Not DetectedChloroform
0.50 2.8 Not Detected Not Detected1,1,1-Trichloroethane
0.50 3.2 Not Detected Not DetectedCarbon Tetrachloride
0.50 1.6 Not Detected Not DetectedBenzene
0.50 2.0 Not Detected Not Detected1,2-Dichloroethane
0.50 2.7 Not Detected Not DetectedTrichloroethene
0.50 2.3 Not Detected Not Detected1,2-Dichloropropane
0.50 2.3 Not Detected Not Detectedcis-1,3-Dichloropropene
0.50 1.9 Not Detected Not DetectedToluene
0.50 2.3 Not Detected Not Detectedtrans-1,3-Dichloropropene
0.50 2.8 Not Detected Not Detected1,1,2-Trichloroethane
0.50 3.4 Not Detected Not DetectedTetrachloroethene
0.50 3.9 Not Detected Not Detected1,2-Dibromoethane (EDB)
0.50 2.3 Not Detected Not DetectedChlorobenzene
0.50 2.2 Not Detected Not DetectedEthyl Benzene
0.50 2.2 Not Detected Not Detectedm,p-Xylene
0.50 2.2 Not Detected Not Detectedo-Xylene
0.50 2.2 Not Detected Not DetectedStyrene
0.50 3.5 Not Detected Not Detected1,1,2,2-Tetrachloroethane
0.50 2.5 Not Detected Not Detected1,3,5-Trimethylbenzene
0.50 2.5 Not Detected Not Detected1,2,4-Trimethylbenzene
0.50 3.0 Not Detected Not Detected1,3-Dichlorobenzene
0.50 3.0 Not Detected Not Detected1,4-Dichlorobenzene
0.50 2.6 Not Detected Not Detectedalpha-Chlorotoluene
0.50 3.0 Not Detected Not Detected1,2-Dichlorobenzene
0.50 1.1 Not Detected Not Detected1,3-Butadiene
0.50 1.8 Not Detected Not DetectedHexane
0.50 1.7 Not Detected Not DetectedCyclohexane
0.50 2.1 Not Detected Not DetectedHeptane
0.50 3.4 Not Detected Not DetectedBromodichloromethane
0.50 4.3 Not Detected Not DetectedDibromochloromethane
Page 6 of 11
SAMPLE NAME: Lab Blank
ID#: 0311168A-02A
MODIFIED EPA METHOD TO-14A GC/MS FULL SCAN
b111108aFile Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/11/03 03:03 PM
(uG/m3)(ppbv)(uG/m3)(ppbv)Compound
AmountAmountRpt. LimitRpt. Limit
0.50 2.5 Not Detected Not DetectedCumene
0.50 2.5 Not Detected Not DetectedPropylbenzene
2.0 4.2 Not Detected Not DetectedChloromethane
2.0 15 Not Detected Not Detected1,2,4-Trichlorobenzene
2.0 22 Not Detected Not DetectedHexachlorobutadiene
2.0 4.8 Not Detected Not DetectedAcetone
2.0 6.3 Not Detected Not DetectedCarbon Disulfide
2.0 5.0 Not Detected Not Detected2-Propanol
2.0 8.0 Not Detected Not Detectedtrans-1,2-Dichloroethene
2.0 7.2 Not Detected Not DetectedVinyl Acetate
2.0 6.0 Not Detected Not Detected2-Butanone (Methyl Ethyl Ketone)
2.0 6.0 Not Detected Not DetectedTetrahydrofuran
2.0 7.3 Not Detected Not Detected1,4-Dioxane
2.0 8.3 Not Detected Not Detected4-Methyl-2-pentanone
2.0 8.3 Not Detected Not Detected2-Hexanone
2.0 21 Not Detected Not DetectedBromoform
2.0 10 Not Detected Not Detected4-Ethyltoluene
2.0 7.3 Not Detected Not DetectedMethyl tert-butyl ether
2.0 3.8 Not Detected Not DetectedEthanol
Container Type: NA - Not Applicable
Limits%RecoverySurrogates
Method
101 70-1301,2-Dichloroethane-d4
99 70-130Toluene-d8
95 70-1304-Bromofluorobenzene
Page 7 of 11
SAMPLE NAME: CCV
ID#: 0311168A-03A
MODIFIED EPA METHOD TO-14A GC/MS FULL SCAN
b111103File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/11/03 11:39 AM
%RecoveryCompound
108Freon 12
115Freon 114
116Vinyl Chloride
111Bromomethane
106Chloroethane
106Freon 11
1051,1-Dichloroethene
107Freon 113
101Methylene Chloride
1061,1-Dichloroethane
106cis-1,2-Dichloroethene
101Chloroform
1031,1,1-Trichloroethane
105Carbon Tetrachloride
105Benzene
1031,2-Dichloroethane
108Trichloroethene
1101,2-Dichloropropane
105cis-1,3-Dichloropropene
105Toluene
102trans-1,3-Dichloropropene
1041,1,2-Trichloroethane
106Tetrachloroethene
1061,2-Dibromoethane (EDB)
104Chlorobenzene
104Ethyl Benzene
106m,p-Xylene
102o-Xylene
104Styrene
991,1,2,2-Tetrachloroethane
1131,3,5-Trimethylbenzene
1031,2,4-Trimethylbenzene
991,3-Dichlorobenzene
991,4-Dichlorobenzene
102alpha-Chlorotoluene
941,2-Dichlorobenzene
1061,3-Butadiene
107Hexane
107Cyclohexane
107Heptane
106Bromodichloromethane
113Dibromochloromethane
Page 8 of 11
SAMPLE NAME: CCV
ID#: 0311168A-03A
MODIFIED EPA METHOD TO-14A GC/MS FULL SCAN
b111103File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/11/03 11:39 AM
%RecoveryCompound
107Cumene
119Propylbenzene
109Chloromethane
1141,2,4-Trichlorobenzene
114Hexachlorobutadiene
103Acetone
107Carbon Disulfide
1062-Propanol
104trans-1,2-Dichloroethene
104Vinyl Acetate
1042-Butanone (Methyl Ethyl Ketone)
102Tetrahydrofuran
1101,4-Dioxane
1064-Methyl-2-pentanone
1072-Hexanone
111Bromoform
1274-Ethyltoluene
102Methyl tert-butyl ether
115Ethanol
Container Type: NA - Not Applicable
Limits%RecoverySurrogates
Method
97 70-1301,2-Dichloroethane-d4
101 70-130Toluene-d8
101 70-1304-Bromofluorobenzene
Page 9 of 11
SAMPLE NAME: LCS
ID#: 0311168A-04A
MODIFIED EPA METHOD TO-14A GC/MS FULL SCAN
b111105File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/11/03 12:46 PM
%RecoveryCompound
119Freon 12
134 QFreon 114
129Vinyl Chloride
116Bromomethane
135 QChloroethane
112Freon 11
1041,1-Dichloroethene
104Freon 113
99Methylene Chloride
1011,1-Dichloroethane
109cis-1,2-Dichloroethene
100Chloroform
981,1,1-Trichloroethane
110Carbon Tetrachloride
117Benzene
1081,2-Dichloroethane
108Trichloroethene
1101,2-Dichloropropane
107cis-1,3-Dichloropropene
115Toluene
107trans-1,3-Dichloropropene
1081,1,2-Trichloroethane
110Tetrachloroethene
961,2-Dibromoethane (EDB)
107Chlorobenzene
113Ethyl Benzene
112m,p-Xylene
108o-Xylene
113Styrene
961,1,2,2-Tetrachloroethane
1061,3,5-Trimethylbenzene
941,2,4-Trimethylbenzene
901,3-Dichlorobenzene
871,4-Dichlorobenzene
109alpha-Chlorotoluene
881,2-Dichlorobenzene
1161,3-Butadiene
102Hexane
101Cyclohexane
100Heptane
100Bromodichloromethane
103Dibromochloromethane
Page 10 of 11
SAMPLE NAME: LCS
ID#: 0311168A-04A
MODIFIED EPA METHOD TO-14A GC/MS FULL SCAN
b111105File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/11/03 12:46 PM
%RecoveryCompound
113Cumene
88Propylbenzene
123Chloromethane
1021,2,4-Trichlorobenzene
107Hexachlorobutadiene
104Acetone
102Carbon Disulfide
1042-Propanol
108trans-1,2-Dichloroethene
103Vinyl Acetate
1032-Butanone (Methyl Ethyl Ketone)
100Tetrahydrofuran
1071,4-Dioxane
1024-Methyl-2-pentanone
942-Hexanone
85Bromoform
984-Ethyltoluene
101Methyl tert-butyl ether
116Ethanol
Q = Exceeds Quality Control limits.
Container Type: NA - Not Applicable
Limits%RecoverySurrogates
Method
96 70-1301,2-Dichloroethane-d4
99 70-130Toluene-d8
103 70-1304-Bromofluorobenzene
Page 11 of 11
AIR TOXICS LTD.@
AN ENVIRONMENTAL ANALYTICAL LABORATORY
Air Toxics Ltd. Introduces the Electronic Report
Thank you for choosing Air Toxics Ltd. To better serve our customers, we are providing your report by e-mail.
This document is provided in Portable Document Format which can be viewed with Acrobat Reader by
Adobe.
This electronic report includes the following:
• Work order Summary;
• Laboratory Narrative;
• Results; and
• Chain of Custody (copy).
180 BLUE RAVINE ROAD, SUITE B FOLSOM, CA - 95630
(916) 985-1000 .FAX (916) 985-1020
Hours 8:00 A.M to 6:00 P.M. Pacific
E-mail to:samplereceiving@airtoxics.com
AIR TOXICS LTD.
AN ENVIRONMENTAL ANALYTICAL LABORATORY
@
Mr. Paul Tower
Applied Filter Technology
19524 75th Ave SE
Snohomish, WA 98296
WORK ORDER #: 0311168B
CLIENT: BILL TO:
PHONE:
Mr. Paul Tower
Applied Filter Technology
19524 75th Ave SE
Snohomish, WA 98296
360-668-6021
360-668-7017
11/11/03
DATE COMPLETED:11/20/03
P.O. #
PROJECT #826931.04002003
SHAW/EMCON-Anchorage Regional
Work Order Summary
FAX:
DATE RECEIVED:CONTACT:Kelly Buettner
NAMEFRACTION #TEST VAC./PRES.
RECEIPT
01A 301B ASTM D-5504 Tedlar Bag
02A Lab Blank ASTM D-5504 NA
03A LCS ASTM D-5504 NA
CERTIFIED BY:
Laboratory Director
DATE:
Name of Accrediting Agency: NELAP/Florida Department of Health, Scope of Application: Clean Air Act,
Accreditation number: E87680, Effective date: 07/01/03, Expiration date: 06/30/04
180 BLUE RAVINE ROAD, SUITE B FOLSOM, CA - 95630
(916) 985-1000 . (800) 985-5955 . FAX (916) 985-1020
11/21/03
Page 1 of 5
This report shall not be reproduced, except in full, without the written approval of Air Toxics Ltd.
Air Toxics Ltd. certifies that the test results contained in this report meet all requirements of the NELAC standards
Certfication numbers: AR DEQ - 03-084-0, CA NELAP - 02110CA, LA NELAP/LELAP- AI 30763, NJ NELAP - CA004
NY NELAP - 11291, UT NELAP - 9166389892
LABORATORY NARRATIVE
ASTM D-5504
Applied Filter Technology
Workorder# 0311168B
One 1 Liter Tedlar Bag sample was received on November 11,2003. The laboratory performed the analysis of
sulfur compounds via ASTM D-5504 using GC/SCD. The method involves direct injection of the air sample into
the GC viaa fixed 1.0 mLsampling loop. See the data sheets for the reporting limits for each compound.
The chain of custody information for sample 301B did not match the entry on the sample tag. The discrepancy
was noted in the Login email and the information on the chain of custody was used to process and report the
sample.
Sample 301B was received past the recommended hold time of 24 hours. The discrepancy was noted in the
Login email and the analysis proceeded.
Receiving Notes
Ethyl Methyl Sulfide and n-Butyl Mercaptan coelute with 3-Methyl Thiophene. The corresponding peak is
reported as 3-Methyl Thiophene.
Analytical Notes
Seven qualifiers may have been used on the data analysis sheets and indicate as follows:
B - Compound present in laboratory blank greater than reporting limit.
J - Estimated value.
E - Exceeds instrument calibration range.
S - Saturated peak.
Q - Exceeds quality control limits.
U - Compound analyzed for but not detected above the detection limit.
M - Reported value may be biased due to apparent matrix interferences.
File extensions may have been used on the data analysis sheets and indicates
as follows:
a-File was requantified
b-File was quantified by a second column and detector
r1-File was requantified for the purpose of reissue
Definition of Data Qualifying Flags
Page 2 of 5
SAMPLE NAME: 301B
ID#: 0311168B-01A
SULFUR GASES BY ASTM D-5504 GC/SCD
b111106File Name:
AIR TOXICS LTD.
Dil. Factor:20.0
Date of Collection: 11/10/03
Date of Analysis: 11/11/03 12:15 PM
(ppbv)(ppbv)Compound
AmountRpt. Limit
80 15000Hydrogen Sulfide
80 Not DetectedCarbonyl Sulfide
80 94Methyl Mercaptan
80 180Ethyl Mercaptan
80 Not DetectedDimethyl Sulfide
80 Not DetectedCarbon Disulfide
80 1900Isopropyl Mercaptan
80 Not Detectedtert-Butyl Mercaptan
80 Not Detectedn-Propyl Mercaptan
80 Not DetectedEthyl Methyl Sulfide
80 Not DetectedThiophene
80 Not DetectedIsobutyl Mercaptan
80 Not DetectedDiethyl Sulfide
80 Not DetectedButyl Mercaptan
80 Not DetectedDimethyl Disulfide
80 1403-Methylthiophene
80 Not DetectedTetrahydrothiophene
80 Not Detected2-Ethylthiophene
80 Not Detected2,5-Dimethylthiophene
80 Not DetectedDiethyl Disulfide
Container Type: 1 Liter Tedlar Bag
Page 3 of 5
SAMPLE NAME: Lab Blank
ID#: 0311168B-02A
SULFUR GASES BY ASTM D-5504 GC/SCD
b111103File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/11/03 09:29 AM
(ppbv)(ppbv)Compound
AmountRpt. Limit
4.0 Not DetectedHydrogen Sulfide
4.0 Not DetectedCarbonyl Sulfide
4.0 Not DetectedMethyl Mercaptan
4.0 Not DetectedEthyl Mercaptan
4.0 Not DetectedDimethyl Sulfide
4.0 Not DetectedCarbon Disulfide
4.0 Not DetectedIsopropyl Mercaptan
4.0 Not Detectedtert-Butyl Mercaptan
4.0 Not Detectedn-Propyl Mercaptan
4.0 Not DetectedEthyl Methyl Sulfide
4.0 Not DetectedThiophene
4.0 Not DetectedIsobutyl Mercaptan
4.0 Not DetectedDiethyl Sulfide
4.0 Not DetectedButyl Mercaptan
4.0 Not DetectedDimethyl Disulfide
4.0 Not Detected3-Methylthiophene
4.0 Not DetectedTetrahydrothiophene
4.0 Not Detected2-Ethylthiophene
4.0 Not Detected2,5-Dimethylthiophene
4.0 Not DetectedDiethyl Disulfide
Container Type: NA - Not Applicable
Page 4 of 5
SAMPLE NAME: LCS
ID#: 0311168B-03A
SULFUR GASES BY ASTM D-5504 GC/SCD
b111102File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/11/03 08:34 AM
%RecoveryCompound
110Hydrogen Sulfide
104Carbonyl Sulfide
108Methyl Mercaptan
109Ethyl Mercaptan
98Dimethyl Sulfide
91Carbon Disulfide
104Isopropyl Mercaptan
102tert-Butyl Mercaptan
107n-Propyl Mercaptan
108Ethyl Methyl Sulfide
98Thiophene
106Isobutyl Mercaptan
104Diethyl Sulfide
108Butyl Mercaptan
104Dimethyl Disulfide
1083-Methylthiophene
117Tetrahydrothiophene
1122-Ethylthiophene
1122,5-Dimethylthiophene
136 QDiethyl Disulfide
Q = Exceeds Quality Control limits.
Container Type: NA - Not Applicable
Page 5 of 5
AIR TOXICS LTD.@
AN ENVIRONMENTAL ANALYTICAL LABORATORY
Air Toxics Ltd. Introduces the Electronic Report
Thank you for choosing Air Toxics Ltd. To better serve our customers, we are providing your report by e-mail.
This document is provided in Portable Document Format which can be viewed with Acrobat Reader by
Adobe.
This electronic report includes the following:
• Work order Summary;
• Laboratory Narrative;
• Results; and
• Chain of Custody (copy).
180 BLUE RAVINE ROAD, SUITE B FOLSOM, CA - 95630
(916) 985-1000 .FAX (916) 985-1020
Hours 8:00 A.M to 6:00 P.M. Pacific
E-mail to:samplereceiving@airtoxics.com
AIR TOXICS LTD.
AN ENVIRONMENTAL ANALYTICAL LABORATORY
@@
Mr. Paul Tower
Applied Filter Technology
19524 75th Ave SE
Snohomish, WA 98296
WORK ORDER #: 0311168C
CLIENT: BILL TO:
PHONE:
Mr. Paul Tower
Applied Filter Technology
19524 75th Ave SE
Snohomish, WA 98296
360-668-6021
360-668-7017
11/11/03
DATE COMPLETED:11/21/03
P.O. #
PROJECT #826931.04002003
SHAW/EMCON-Anchorage Regional
Work Order Summary
FAX:
DATE RECEIVED:CONTACT:Kelly Buettner
NAMEFRACTION #TEST VAC./PRES.
RECEIPT
01A 301B Modified ASTM D -1945 Tedlar Bag
02A Lab Blank Modified ASTM D-1945 NA
03A LCS Modified ASTM D-1945 NA
CERTIFIED BY:
Laboratory Director
DATE:
Name of Accrediting Agency: NELAP/Florida Department of Health, Scope of Application: Clean Air Act,
Accreditation number: E87680, Effective date: 07/01/03, Expiration date: 06/30/04
180 BLUE RAVINE ROAD, SUITE B FOLSOM, CA - 95630
(916) 985-1000 . (800) 985-5955 . FAX (916) 985-1020
11/21/03
Page 1 of 6
This report shall not be reproduced, except in full, without the written approval of Air Toxics Ltd.
Air Toxics Ltd. certifies that the test results contained in this report meet all requirements of the NELAC standards
Certfication numbers: AR DEQ - 03-084-0, CA NELAP - 02110CA, LA NELAP/LELAP- AI 30763, NJ NELAP - CA004
NY NELAP - 11291, UT NELAP - 9166389892
LABORATORY NARRATIVE
Modified ASTM D-1945
Applied Filter Technology
Workorder# 0311168C
One 1 Liter Tedlar Bag sample was received on November 11,2003. Thelaboratory performed analysis via
modified ASTM Method D-1945 for Methane and fixed gases in natural gas using GC/FID or GC/TCD.
The method involves direct injection of up to 1.0 mLof sample. See the data sheets for the reporting limits for
each compound.
Method modifications taken to run these samples include:
Requirement ATL ModificationsASTM D-1945
Sum of total sample
components
Sum of original values
should not differ from
100.0% by more than
1.0%.
Sum of original values may range between 75-125%.
Sample analysis Equilibrate samples to
20-50° F. above source
temperature at field
sampling
No heating of samples is performed.
Sample calculation Response factor is
calculated using peak
height for C5 and
lighter compounds.
Peak areas are used for all target analytes to quantitate
concentrations.
Standard preparation Prepared by blending
pure standards
Purchased blend certified to ± 5% accuracy or better
Normalization Mathematically
normalize results to
equal 100%.
Unnormalized results are reported unless otherwise
specified.
Receiving Notes
The chain of custody information for sample 301B did not match the entry on the sample tag. The
discrepancy was noted in the Login email and the information on the chain of custody was used to process
and report the sample.
Thepresence of Carbon Monoxide may have been masked by the Methane peak insample 301B.
Propane and Propylene co-elute. Peak isquantitated as propane.
Analytical Notes
Six qualifiers may have been used on the data analysis sheets and indicate as follows:
J - Estimated value.
E - Exceeds instrument calibration range.
S - Saturated peak.
Q - Exceeds quality control limits.
U - Compound analyzed for but not detected above the detection limit.
M - Reported value may be biased due to apparent matrix interferences.
Definition of Data Qualifying Flags
Page 2 of 6
File extensions may have been used on the data analysis sheets and indicates
as follows:
a-File was requantified
b-File was quantified by a second column and detector
r1-File was requantified for the purpose of reissue
Page 3 of 6
SAMPLE NAME: 301B
ID#: 0311168C-01A
NATURAL GAS ANALYSIS BY MODIFIED ASTM D-1945
3111304File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: 11/10/03
Date of Analysis: 11/13/03 10:15 AM
(%)(%)Compound
AmountRpt. Limit
0.10 2.9Oxygen
0.10 11Nitrogen
0.0010 Not DetectedCarbon Monoxide
0.00010 46Methane
0.0010 32Carbon Dioxide
0.0010 Not DetectedEthane
0.0010 0.0058Propane
0.0010 0.0023Isobutane
0.0010 0.0011Butane
0.0010 Not DetectedNeopentane
0.0010 Not DetectedIsopentane
0.0010 Not DetectedPentane
0.010 Not DetectedC6+
Total BTU/Cu.F. = 460
Total Sp. Gravity = 0.88
Container Type: 1 Liter Tedlar Bag
Page 4 of 6
SAMPLE NAME: Lab Blank
ID#: 0311168C-02A
NATURAL GAS ANALYSIS BY MODIFIED ASTM D-1945
3111303File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/13/03 09:22 AM
(%)(%)Compound
AmountRpt. Limit
0.10 Not DetectedOxygen
0.10 Not DetectedNitrogen
0.0010 Not DetectedCarbon Monoxide
0.00010 Not DetectedMethane
0.0010 Not DetectedCarbon Dioxide
0.0010 Not DetectedEthane
0.0010 Not DetectedPropane
0.0010 Not DetectedIsobutane
0.0010 Not DetectedButane
0.0010 Not DetectedNeopentane
0.0010 Not DetectedIsopentane
0.0010 Not DetectedPentane
0.010 Not DetectedC6+
Container Type: NA - Not Applicable
Page 5 of 6
SAMPLE NAME: LCS
ID#: 0311168C-03A
NATURAL GAS ANALYSIS BY MODIFIED ASTM D-1945
3111302File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/13/03 08:23 AM
%RecoveryCompound
86Oxygen
96Nitrogen
95Carbon Monoxide
93Methane
94Carbon Dioxide
98Ethane
91Propane
92Isobutane
92Butane
95Neopentane
94Isopentane
93Pentane
92C6+
Container Type: NA - Not Applicable
Page 6 of 6
AIR TOXICS LTD.@
AN ENVIRONMENTAL ANALYTICAL LABORATORY
Air Toxics Ltd. Introduces the Electronic Report
Thank you for choosing Air Toxics Ltd. To better serve our customers, we are providing your report by e-mail.
This document is provided in Portable Document Format which can be viewed with Acrobat Reader by
Adobe.
This electronic report includes the following:
• Work order Summary;
• Laboratory Narrative;
• Results; and
• Chain of Custody (copy).
180 BLUE RAVINE ROAD, SUITE B FOLSOM, CA - 95630
(916) 985-1000 .FAX (916) 985-1020
Hours 8:00 A.M to 6:00 P.M. Pacific
E-mail to:samplereceiving@airtoxics.com
AIR TOXICS LTD.
AN ENVIRONMENTAL ANALYTICAL LABORATORY
@
Mr. Paul Tower
Applied Filter Technology
19524 75th Ave SE
Snohomish, WA 98296
WORK ORDER #: 0311168D
CLIENT: BILL TO:
PHONE:
Mr. Paul Tower
Applied Filter Technology
19524 75th Ave SE
Snohomish, WA 98296
360-668-6021
360-668-7017
11/11/03
DATE COMPLETED:11/20/03
P.O. #
PROJECT #826931.04002003
SHAW/EMCON-Anchorage Regional
Work Order Summary
FAX:
DATE RECEIVED:CONTACT:Kelly Buettner
NAMEFRACTION #TEST
01AB 301B Siloxanes
02A Lab Blank Siloxanes
03A LCS Siloxanes
CERTIFIED BY:
Laboratory Director
DATE:
Name of Accrediting Agency: NELAP/Florida Department of Health, Scope of Application: Clean Air Act,
Accreditation number: E87680, Effective date: 07/01/03, Expiration date: 06/30/04
180 BLUE RAVINE ROAD, SUITE B FOLSOM, CA - 95630
(916) 985-1000 . (800) 985-5955 . FAX (916) 985-1020
11/21/03
Page 1 of 5
This report shall not be reproduced, except in full, without the written approval of Air Toxics Ltd.
Air Toxics Ltd. certifies that the test results contained in this report meet all requirements of the NELAC standards
Certfication numbers: AR DEQ - 03-084-0, CA NELAP - 02110CA, LA NELAP/LELAP- AI 30763, NJ NELAP - CA004
NY NELAP - 11291, UT NELAP - 9166389892
LABORATORY NARRATIVE
Siloxanes
Applied Filter Technology
Workorder# 0311168D
Two Vial samples were received on November 11,2003. The laboratory performed analysis for siloxanes by
GC/MS. A sample volume of 1.0 uL was injected directly onto the GC column. Initial results are in ug/mL. The
units are converted to total micrograms (ug) by multiplying the result (ug/mL) by the total volume (mL) contained
in the impinger. See the data sheets for the reporting limits for each compound.
A Temperature Blank was not included with the shipment. Temperature was measured on a representative
sample and was not within 4 +/- 2 degrees C. Coolant in the form of blue ice was present. The client was
notified via the login fax/email and the analysis proceeded.
Receiving Notes
A front and back impinger was received for each sample. Each impinger was analyzed separately. The results
for each analyte were then additively combined and reported as a single concentration. The reported surrogate
recovery is derived from the front impinger analysis only.
Analytical Notes
Six qualifiers may have been used on the data analysis sheets and indicate as follows:
B - Compound present in laboratory blank greater than reporting limit.
J - Estimated Value.
E - Exceeds instrument calibration range.
S - Saturated peak.
Q - Exceeds quality control limits.
M - Reported value may be biased due to apparent matrix interferences.
File extensions may have been used on the data analysis sheets and indicates
as follows:
a-File was requantified
b-File was quantified by a second column and detector
r1-File was requantified for the purpose of reissue
Definition of Data Qualifying Flags
Page 2 of 5
SAMPLE NAME: 301B
ID#: 0311168D-01AB
SILOXANES - GC/MS
h111910File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: 11/10/03
Date of Analysis: 11/19/03 01:42 PM
(ug)(ug)Compound
AmountRpt. Limit
25 31Octamethylcyclotetrasiloxane (D4)
25 Not DetectedDecamethylcylopentasiloxane (D5)
50 Not DetectedDodecamethylcyclohexasiloxane (D6)
25 Not DetectedHexamethyldisiloxane
25 Not DetectedOctamethyltrisiloxane
Impinger Total Volume(mL): 25.0
Container Type: Vial
Limits%RecoverySurrogates
Method
76 70-130Hexamethyl disiloxane -d18
Page 3 of 5
SAMPLE NAME: Lab Blank
ID#: 0311168D-02A
SILOXANES - GC/MS
h111904File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/19/03 11:01 AM
(ug)(ug)Compound
AmountRpt. Limit
1.0 Not DetectedOctamethylcyclotetrasiloxane (D4)
1.0 Not DetectedDecamethylcylopentasiloxane (D5)
2.0 Not DetectedDodecamethylcyclohexasiloxane (D6)
1.0 Not DetectedHexamethyldisiloxane
1.0 Not DetectedOctamethyltrisiloxane
Impinger Total Volume(mL): 1.00
Container Type: NA - Not Applicable
Limits%RecoverySurrogates
Method
92 70-130Hexamethyl disiloxane -d18
Page 4 of 5
SAMPLE NAME: LCS
ID#: 0311168D-03A
SILOXANES - GC/MS
h111903File Name:
AIR TOXICS LTD.
Dil. Factor:1.00
Date of Collection: NA
Date of Analysis: 11/19/03 10:36 AM
%RecoveryCompound
97Octamethylcyclotetrasiloxane (D4)
96Decamethylcylopentasiloxane (D5)
Not SpikedDodecamethylcyclohexasiloxane (D6)
102Hexamethyldisiloxane
93Octamethyltrisiloxane
Impinger Total Volume(mL): 1.00
Container Type: NA - Not Applicable
Limits%RecoverySurrogates
Method
91 70-130Hexamethyl disiloxane -d18
Page 5 of 5
APPENDIX 3
FINANCIAL PRO FORMA FOR OPTION 1
(ELECTRICAL GENERATION)
(CAT 3516) L
Triton Power Pack 925
2.4 MW POWER PLANTSCENARIO - AA 2.5.1
MINIMUM 3% IRR ON 10 YR. CASH FLOW
INTERCONNECT ALLOWANCE = $250,000
WHEELING CHARGE = $0.005 per KWH
NO GCCS CONSTRUCTION & GCCS O&M
MUSA CONTRIBUTIONS and GASB 34 DEPRECIATION
SHAW GROUP
04-May-2004EMCON/OWT, INC. - DEVELOPED PROJECTS
Anchorage, Alaska
ASSUMPTIONS
Gas Flow at 75% of Average Generation Rate from 1/19/04 Gas Generation Model
Triton Power Pack 925 (CAT 3516) Low Emissions3Gensets installed - Recip Engines - number of units =
SCFM306Gas Requirement per Genset - SCFM @ 50% Methane
per KWH$0.0481Power sale price per kWh =
$3,207,000Total project installed cost.
per KWH$0.0050Wheeling cost per kWh
per Kwh$0.0481POWER SALE RATE PROJECT DESCRIPTION:
per YR.1.00%POWER RATE INFLATOR
per kWh$0.0050WHEELING CHARGEkW2,412PROJECT CAPACITY:
per kWh$0.0000GAS COSTper mW$1,329,602CAPITAL COST
per YR.2.00%GAS COST INFLATOR0.00%FINANCING - loan to cost
per Kwh gross$0.0150O&M COST - Gen Plant2.75%FINANCING - interest rate
per YR.2.00%O&M COST INFLATOR100.00%GASCO OWNERSHIP
$0.0000ENERGY GRANT per kWh95.00%UTILIZATION RATE
N:\PROJ\GASRECOV\Anchorage Alaska\Anchorage_2.4MW_Triton_15yr.qpw
15 YEAR 10 YEARYEAR 1FINANCIAL PERFORMANCE SUMMARY
CENTS/KWH$CENTS/KWH$CENTS/KWH$
OPERATING STATISTICS
295,433,795195,070,47517,125,783KILOWATT HOURS SOLD
93.22%92.32%81.05%UTILIZATION FACTOR
INCOME STATEMENT
5.17$15,267,7085.04$9,827,4494.81$823,750TOTAL REVENUES
3.048,967,2582.955,753,8932.83485,225COSTS OF REVENUES
2.136,300,4502.094,073,5561.98338,525GROSS PROFIT
1.093,207,0001.643,207,0002.68458,143DEPRECIATION and AMORTIZATION
0.16458,0310.15294,8230.1424,713ADMINISTRATIVE EXPENSE
0.892,635,4190.29571,732(0.84)(144,330)INCOME BEFORE DEBT SERVICE
0.0000.0000.000INTEREST COST
0.892,635,4190.29571,732(0.84)(144,330)INCOME BEFORE INCOME TAXES
0.0000.0000.000INCOME TAXES
0.0000.0000.000TAX CREDITS
0.13396,0940.17328,0910.62105,591MUSA CONTRIBUTIONS
0.89$2,239,3250.29$243,641(0.84)($249,921)NET INCOME
CASH FLOW
OPERATIONS
0.76$2,239,3250.12$243,641(1.46)($249,921) NET INCOME
ADD BACK:
1.093,207,0001.643,207,0002.68458,143 DEPRECIATION and AMORTIZATION
0.0000.0000.000 INTEREST COSTS
1.845,446,3251.773,450,6411.22208,222 CASH FLOW AVAILABLE FOR DEBT SERVICE
DEBT SERVICE
0.0000.0000.000 PRINCIPAL PAYMENTS
0.0000.0000.000 INTEREST COSTS
0.0000.0000.000 TOTAL DEBT SERVICE
1.845,446,3251.773,450,6411.22208,222 CASH FLOW AFTER DEBT SERVICE
INVESTMENT
(1.09)(3,207,000)(1.64)(3,207,000)(18.73)(3,207,000) CAPITAL EXPENDITURES
0.0000.0000.000 EXISTING EQUITY IN GCCS
(1.09)(3,207,000)(1.64)(3,207,000)(18.73)(3,207,000) NET NEW CAPITAL EXPENDITURES
0.0000.0000.000 PROCEEDS OF FINANCING
(1.09)(3,207,000)(1.64)(3,207,000)(18.73)(3,207,000) NET INVESTMENT REQUIREMENTS
0.76$2,239,3250.12$243,641(17.51)($2,998,778)CASH AVAILABLE (REQUIRED)
FINANCIAL ANALYSIS
8.3%3.0%INTERNAL RATE OF RETURN
9.0SIMPLE PAYBACK in YEARS
NANADEBT COVERAGE RATIO
NPV of AFTER TAX CASH FLOWS
$742,256($301,772)($2,769,649)5.00% DISCOUNT RATE
($296,872)($844,481)($2,656,105)10.00% DISCOUNT RATE
($573,039)($1,000,037)($2,613,224)12.00% DISCOUNT RATE
$2,635,419$571,732($144,330)EARNINGS BEFORE INTEREST & TAXES (EBIT)
EARNINGS BEFORE INTEREST, TAXES,
$5,842,419$3,778,732$313,812 DEPRECIATION & AMORTIZATION (EBITDA)
N:\PROJ\GASRECOV\Anchorage Alaska\Anchorage_2.4MW_Triton_15yr.qpw 05-May-04 05:24:24 PM
(CAT 3516) L
Triton Power Pack 925
2.4 MW POWER PLANTSCENARIO - AA 2.5.2
MINIMUM 3% IRR ON 10 YR. CASH FLOW
INTERCONNECT ALLOWANCE = $250,000
WHEELING CHARGE = $0.005 per KWH
GCCS CONSTRUCTION & GCCS O&M INCLUDED
MUSA CONTRIBUTIONS and GASB 34 DEPRECIATION
SHAW GROUP
04-May-2004EMCON/OWT, INC. - DEVELOPED PROJECTS
Anchorage, Alaska
ASSUMPTIONS
Gas Flow at 75% of Average Generation Rate from 1/19/04 Gas Generation Model
Triton Power Pack 925 (CAT 3516) Low Emissions3Gensets installed - Recip Engines - number of units =
SCFM306Gas Requirement per Genset - SCFM @ 50% Methane
per KWH$0.0547Power sale price per kWh =
$4,109,000Total project installed cost.
per KWH$0.0050Wheeling cost per kWh
per Kwh$0.0547POWER SALE RATE PROJECT DESCRIPTION:
per YR.1.00%POWER RATE INFLATOR
per kWh$0.0050WHEELING CHARGEkW2,412PROJECT CAPACITY:
per kWh$0.0000GAS COSTper mW$1,703,566CAPITAL COST
per YR.2.00%GAS COST INFLATOR0.00%FINANCING - loan to cost
per Kwh gross$0.0150O&M COST - Gen Plant2.75%FINANCING - interest rate
per YR.2.00%O&M COST INFLATOR100.00%GASCO OWNERSHIP
$0.0000ENERGY GRANT per kWh95.00%UTILIZATION RATE
N:\PROJ\GASRECOV\Anchorage Alaska\Anchorage_2.4MW_Triton_GCCS_15yr.qpw
15 YEAR 10 YEARYEAR 1FINANCIAL PERFORMANCE SUMMARY
CENTS/KWH$CENTS/KWH$CENTS/KWH$
OPERATING STATISTICS
295,433,795195,070,47517,125,783KILOWATT HOURS SOLD
93.22%92.32%81.05%UTILIZATION FACTOR
INCOME STATEMENT
5.88$17,362,6535.73$11,175,9145.47$936,780TOTAL REVENUES
3.169,342,4283.075,991,6982.96506,102COSTS OF REVENUES
2.718,020,2252.665,184,2162.51430,678GROSS PROFIT
1.394,109,0002.114,109,0003.21549,457DEPRECIATION and AMORTIZATION
0.18520,8800.17335,2770.1628,103ADMINISTRATIVE EXPENSE
1.153,390,3460.38739,939(0.86)(146,882)INCOME BEFORE DEBT SERVICE
0.0000.0000.000INTEREST COST
1.153,390,3460.38739,939(0.86)(146,882)INCOME BEFORE INCOME TAXES
0.0000.0000.000INCOME TAXES
0.0000.0000.000TAX CREDITS
0.17501,0330.22423,6990.78134,406MUSA CONTRIBUTIONS
1.15$2,889,3130.38$316,240(0.86)($281,289)NET INCOME
CASH FLOW
OPERATIONS
0.98$2,889,3130.16$316,240(1.64)($281,289) NET INCOME
ADD BACK:
1.394,109,0002.114,109,0003.21549,457 DEPRECIATION and AMORTIZATION
0.0000.0000.000 INTEREST COSTS
2.376,998,3132.274,425,2401.57268,168 CASH FLOW AVAILABLE FOR DEBT SERVICE
DEBT SERVICE
0.0000.0000.000 PRINCIPAL PAYMENTS
0.0000.0000.000 INTEREST COSTS
0.0000.0000.000 TOTAL DEBT SERVICE
2.376,998,3132.274,425,2401.57268,168 CASH FLOW AFTER DEBT SERVICE
INVESTMENT
(1.39)(4,109,000)(2.11)(4,109,000)(23.99)(4,109,000) CAPITAL EXPENDITURES
0.0000.0000.000 EXISTING EQUITY IN GCCS
(1.39)(4,109,000)(2.11)(4,109,000)(23.99)(4,109,000) NET NEW CAPITAL EXPENDITURES
0.0000.0000.000 PROCEEDS OF FINANCING
(1.39)(4,109,000)(2.11)(4,109,000)(23.99)(4,109,000) NET INVESTMENT REQUIREMENTS
0.98$2,889,3120.16$316,240(22.43)($3,840,832)CASH AVAILABLE (REQUIRED)
FINANCIAL ANALYSIS
8.3%3.0%INTERNAL RATE OF RETURN
9.0SIMPLE PAYBACK in YEARS
NANADEBT COVERAGE RATIO
NPV of AFTER TAX CASH FLOWS
$959,456($381,380)($3,548,186)5.00% DISCOUNT RATE
($374,839)($1,078,119)($3,402,748)10.00% DISCOUNT RATE
($729,465)($1,277,845)($3,347,820)12.00% DISCOUNT RATE
$3,390,346$739,939($146,882)EARNINGS BEFORE INTEREST & TAXES (EBIT)
EARNINGS BEFORE INTEREST, TAXES,
$7,499,346$4,848,939$402,575 DEPRECIATION & AMORTIZATION (EBITDA)
N:\PROJ\GASRECOV\Anchorage Alaska\Anchorage_2.4MW_Triton_GCCS_15yr.qpw 05-May-04 05:23:55 PM
APPENDIX 4
TOPOGRAPHIC MAP FOR OPTION 2
(ENSTAR)
Copyright (C) 1997, Maptech, Inc.
Enstar Pipeline
Enstar Pipeline
Anchorage Landfill
LFG Pipeline
0450
500
550
600
650
700
750
Miles
Total distance:990 feet
Ground distance:990 feet
Climbing:0 feet
Descending:-10 feet
Elevation change:-9 feet
Min/Max:462/472
Latitude: 000° 00' 00.0'' N
Longitude: 000° 00' 00.0'' E
Elevation:
Grade:
APPENDIX 5
FINANCIAL PRO FORMA FOR OPTION 2
(ENSTAR)
Assumptions
MG Price $4.321 per mmBtu
MG Price Escalation 2.0%
Capital Cost 2,994,800$
Loan Amount $0
Gas Cost $0.0000
Gas Cost Escalation 2.0% Annual Btu
Gas Quantity SCFM 826 208,631
Ratio of Saleable BTUs to Input LFG BTUs 77% 159,970
Financing
Principal No Debt
Term n/a
Interest Rate n/a
Financial Returns 10 Years
Total Cash Flow from Operations 3,630,259$
Investment 2,994,800$
Net Cash Flow 635,459$
Project IRR 3.0%
NPV at rate = 2.000% 191,961$
NPV at rate = 2.500% 94,658$
NPV at rate = 2.750% 47,845$
NPV at rate = 3.000% 2,212$
Pre Tax Profits 970,640$
Average % 6.2%
Minimum % -26.6%
Net Income 635,459$
Average % 2.3%
Minimum % -34.8%
MUSA Contributions (Municipal Utility Service Assessment)
Rate 10 Year Totals
Rate on Net Book Value of Assets - in mils 16 215,542$
Gross Revenue contribution % of Revenue 1.25% 119,639$
335,181$
Depreciation per GASB 34 Method Life in Years
Vehicles St. Line 5
Support Equipment St. Line 4
Machinery & Equipment St. Line 7
GCCS & Pipeline St. Line 10
Summary of Assumptions & Financials
Anchorage Medium BTU Gas Project
Pipeline Injection of High BTU Gas
Assumes ENSTAR will use all gas available
Project Proforma
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage ENSTAR Pipelineapdx5.xls]Dep
5/18/2004 1:49 PM Anchorage ENSTAR Pipelineapdx5
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage ENSTAR Pipelineapdx5.xls]Dep
Description Value Unit
Financial Information
Project Capital Costs $2,994,800
Equity Contribution 100.00% $2,994,800
Loan 0.00%
Principal $0
Term 10 years
Interest Rate 0.0%
Interest Payments monthly during construction
Loan Fees 0.0%
MG Quantity 826 SCFM 208,631 mmBTU/Yr
50.00% Methane %
On-Stream Factors
Utilization %95.0%
LFG to High BTU Conversion Ratio (Btu basis) 76.7%
MG Price $4.321
MG Price escalator 2.0%
Cost of Sales
Cost of Methane Gas $0.0000 per mmBTU
Cost Escalator 2.0%
Electric Cost - Blower and Compressor @ .09 cents / kwh $80,000 Annually
Electric Escalator 2.0%
Operating Costs Annually
O&M Compressor/Pipeline per year 275,000$
Allow of $100,000 for high
pressure compressors
& condensate handling
O&M Escalator 3.0%
Gas Separation System O&M 0.35$ per mmBtu
Property Insurance 1.00% % of Value
General Liability Insurance 1.00% % of Revenue
Administration $25,000
Income Taxes Is project subject to income taxes NO
Federal Tax Rate 0%
State Tax Rate 0.0% Incl. In Federal
Questions 1 When do we anticipate project completion / start-up?2006
2 Verity Gas curve to use and recovery rate Avg LFG at 75%
3 Does gas curve assume 50 or 50+23 acres 73 acres
4 Does the $15,000 include flare, blower and electrical Includes all components of GCCS
5 Tony had an estimate of $75/ft for pipeline. What does this include?As per Jim use Kevin's $60
6 No Federal Tax
Pipeline Injection of High BTU Gas
Anchorage Medium BTU Gas Project
ASSUMPTIONS to PRO FORMA
5/18/2004 1:50 PM Anchorage ENSTAR Pipelineapdx5
0Pipeline Injection of High BTU Gas Annual ProformaMethane Gas Price (MG) = 4.32$ Escalation Year012345678910 YearAssumptionsCalendarYear 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TotalGas Curve LFG Generation - Avg 1,101 1,170 1,237 1,302 1,364 1,423 1,479 1,533 1,584 1,632 Lfg Recoverable Rate 75.0% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%Landfill Gas Available 826 878 928 977 1,023 1,067 1,109 1,150 1,188 1,224 Average MMBTU @ 50% Methane & 95% Utilization 208,631 221,706 234,402 246,719 258,467 269,647 280,259 290,491 300,155 309,251 High Btu Gas SalesLFG to High BTU Conversion Ratio 76.68% 76.7% 76.7% 76.7% 76.7% 76.7% 76.7% 76.7% 76.7% 76.7% 76.7% 7.667594347High Btu Sales mmBtus 159,970 169,995 179,730 189,174 198,182 206,754 214,891 222,737 230,147 237,121 2,008,701 EscalatorAssumed Methane Gas Price 2% 4.32$ 4.41$ 4.50$ 4.59$ 4.68$ 4.77$ 4.87$ 4.96$ 5.06$ 5.16$ IncomeEscalatorMG Sales - Landfill Gas Production 2.0% $691,229 $749,679 $808,785 $868,309 $927,492 $986,218 $1,046,520 $1,104,774 $1,164,542 $1,223,545 $9,571,094Total Revenues 691,229 749,679 808,785 868,309 927,492 986,218 1,046,520 1,104,774 1,164,542 1,223,545 9,571,094 Costs of SalesPurchased Electricity - Blower/Compressor 2.0% 80,000 81,600 83,232 84,897 86,595 88,326 90,093 91,895 93,733 95,607 875,978 Purchased Methane Gas -$ 2.0% - - - - - - - - - - - Costs of Sales 80,000 81,600 83,232 84,897 86,595 88,326 90,093 91,895 93,733 95,607 875,978 Gross Profit611,229 668,079 725,553 783,413 840,897 897,892 956,427 1,012,879 1,070,809 1,127,938 8,695,116 Expenses - PipelineO&M - Wellfield/Comp/Pipeline - per year 2.0% 275,000 280,500 286,110 291,832 297,669 303,622 309,695 315,889 322,206 328,650 3,011,173 Gas Separation System O&M 0.35$ 2.0% 73,021 79,149 85,355 91,637 97,921 104,199 110,466 116,789 123,088 129,354 1,010,979 Property Insur. - (% of value) 1.00% 2.0% 29,948 30,547 31,158 31,781 32,417 33,065 33,726 34,401 35,089 35,791 327,922 General Liability Insur. (% of revenue) 1.00% 2.0% 6,912 7,647 8,415 9,215 10,039 10,889 11,786 12,690 13,644 14,622 105,859 Administration 2.0% 25,000 25,500 26,010 26,530 27,061 27,602 28,154 28,717 29,291 29,877 273,743 Personal Property Tax - n/a - assume Pollution Control Exemp.0000000000 - Interest0000000000 - Total Expenses 409,881 423,343 437,048 450,995 465,106 479,377 493,827 508,486 523,319 538,295 4,729,677 Net Operating Profit 201,348 244,736 288,505 332,417 375,791 418,515 462,601 504,393 547,491 589,642 3,965,440 LessDepreciation/Amort Finance Fees (Pipeline Only) 385,194 385,194 385,194 385,194 385,194 385,194 385,194 99,480 99,480 99,480 2,994,800 Net Profit Before Tax (183,846) (140,458) (96,689) (52,777) (9,403) 33,321 77,406 404,913 448,011 490,162 970,640 -26.6% -18.7% -12.0% -6.1% -1.0% 3.4% 7.4% 36.7% 38.5% 40.1% 10.1%MUSA ContributionsMillage Rate on NBV of PPE x Prev EOY47,917 41,754 35,591 29,427 23,264 17,101 10,938 4,775 3,183 1,592 215,542 Gross Revenue Rate 1.25% 8,640 9,371 10,110 10,854 11,594 12,328 13,082 13,810 14,557 15,294 119,639 Total Taxes 56,557 51,125 45,700 40,281 34,858 29,429 24,020 18,585 17,740 16,886 335,181 Net Income(240,403) (191,583) (142,390) (93,058) (44,261) 3,892 53,387 386,329 430,270 473,276 635,459 -34.8% -25.6% -17.6% -10.7% -4.8% 0.4% 5.1% 35.0% 36.9% 38.7% 6.6%Anchorage Medium BTU Gas Project5/18/2004 1:50 PMAnchorage ENSTAR Pipelineapdx5
Pipeline Injection of High BTU Gas Annual ProformaMethane Gas Price (MG) = 4.32$ Anchorage Medium BTU Gas ProjectConstructionCash Flow - Total Project2005Capital Expenditures (2,994,800) Loan - Add Depreciation/Amort (Pipeline & Related Costs) 385,194 385,194 385,194 385,194 385,194 385,194 385,194 99,480 99,480 99,480 2,994,800 Less Principal Payment 0000000000 0Net After Tax Cash Flow(2,994,800) 144,791 193,611 242,805 292,136 340,933 389,086 438,581 485,809 529,750 572,756 3,630,259 Cumulative After Tax Cash @ (2,994,800) (2,850,009) (2,656,398) (2,413,593) (2,121,457) (1,780,524) (1,391,438) (952,857) (467,048) 62,702 635,459 Net Present Value (NPV)2.000%$191,961Bank Principal Balance (Yr End) - - - - - - - - 2,012 - 10 YEARInvestment Analysis - Total ProjectConst. Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TOTAL% Ownership 100.00%Capital Expenditures (2,994,800) (2,994,800) Construction Interest- Bond - - Cash Flow 144,791 193,611 242,805 292,136 340,933 389,086 438,581 485,809 529,750 572,756 3,630,259 - After Tax Cash Flow - Year (2,994,800) 144,791 193,611 242,805 292,136 340,933 389,086 438,581 485,809 529,750 572,756 635,459 After Tax Cash Flow - Cum. (2,994,800) (2,850,009) (2,656,398) (2,413,593) (2,121,457) (1,780,524) (1,391,438) (952,857) (467,048) 62,702 635,459 Project IRR - on Cash Investment 3.01%NPV - After tax - Discount @ 2.00% $191,9612.50% $94,6582.75% $47,845Discount = to IRR 3.00% $2,212NPV and IRR reconcileReturn on Revenues Average MinimumPre Tax 6.16% -26.60%After Tax 2.27% -34.78%5/18/2004 1:50 PMAnchorage ENSTAR Pipelineapdx5
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage ENSTAR Pipelineapdx5.xls]Dep
Description
Sub-Total Total
Gas Collection System / Compressor Facility
Wellfield based on $12,000 per acre asuming 73 acres $876,000
Gas Separation System 1,350,000
Compressor 650,000 2,000,000
Contingency $0 Included in above
$2,876,000
Pipeline and Related Costs
Blower Upgrade $0 Included in GCCS
Pipeline 990 feet @ $120 per foot $118,800 Includes 2x factor for high
pressure specifications
D.O.T. Pipeline Safety Standards Design & Compliance $0 Included in Pipeline estimate
Air Compressor $0 Included in Pipeline estimate
Surveying $0 Included in Pipeline estimate
Geotechnical $0 Included in Pipeline estimate
Planning/Coordination/Legal $0 Included in Pipeline estimate
Construction Interest $0 None assumed
Right of Way Payment $0 None assumed
Wetlands Investigation $0 Included in Pipeline estimate
End User Upgrades $0 Allowance
Contingency - 10% $0 Included in above
$118,800
Project Total $2,994,800
Pipeline Injection of High BTU Gas
Anchorage Medium BTU Gas Project
Capital Estimate Detail
5/18/2004 1:51 PM Anchorage ENSTAR Pipelineapdx5
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage ENSTAR Pipelineapdx5.xls]Dep
Depreciation Amounts Amount
Gas Treatment and Processing System 2,876,000
Pipeline and Related Costs 118,800
Construction Interest -
Sub-Total 2,994,800
Year Depreciation
1 2006 $385,194
2 2007 $385,194
3 2008 $385,194
4 2009 $385,194
5 2010 $385,194
6 2011 $385,194
7 2012 $385,194
8 2013 $99,480
9 2014 $99,480
10 2015 $99,480
$2,994,800
Pipeline Injection of High BTU Gas
Anchorage Medium BTU Gas Project
Depreciation & Amortization Schedules
APPENDIX 6
PROPOSED BOILER SPECIFICATIONS FOR EAGLE RIVER SCHOOL
GAS FIRED WATER HEATER
Division 15 - Section 15451
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15451 - 1
SECTION 15451
GAS FIRED WATER HEATER
PART 1 - GENERAL
1.01 SUMMARY
A. SECTION INCLUDES
1. Gas fired water heaters.
B. RELATED SECTIONS
1. 15010 – Mechanical General Requirements.
2. 15400 – Plumbing.
3. 15450 – Plumbing Equipment.
4. 15910 – Control System Sequences of Operation.
1.02 REFERENCES
A. ASHRAE Standard 90.1 Energy Efficient Design of New Buildings Except New Low-
Rise Residential Buildings.
B. ANSI Z21.10.3 - Gas Water Heaters.
C. ASME Section 8D - Pressure Vessels.
D. NFPA 54 - National Fuel Gas Code.
1.03 SUBMITTALS
A. Submit under provisions of Section 15010 – Mechanical General Requirements and
Division 1.
B. Product Data:
1. Provide dimension drawings of water heaters indicating components and
connections to other equipment and piping.
2. Provide gas connection requirements.
3. Provide product data of components and dimension drawings of water heater
stack layout.
C. Calculations:
1. Provide water heater stack sizing calculations with product data to verify sizes
shown on the drawings are appropriately sized for the necessary performance of
the installed water heaters.
GAS FIRED WATER HEATER
Division 15 - Section 15451
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15451 - 2
D. Closeout Submittals:
1. Project Record Documents: Record actual locations of components and piping
configurations.
2. Operation and Maintenance Data: Include operation, maintenance, and
inspection data, replacement part numbers and availability, and service depot
location and telephone number.
3. Warranty: Submit manufacturer’s warranty and ensure forms have been
completed in Owner's name and registered with manufacturer.
1.04 QUALITY ASSURANCE
A. Manufacturer Qualifications: Company specializing in manufacturing the Products
specified in this section with minimum three years documented experience.
B. Ensure products and installation of specified products are in conformance with
recommendations and requirements of the following organizations:
1. American Gas Association (AGA).
2. American National Standards Institute (ANSI Z21.10.3).
3. American Society of Mechanical Engineers (ASME).
4. National Electrical Manufacturers' Association (NEMA).
5. National Sanitation Foundation (NSF).
6. Underwriters Laboratories (UL).
1.05 COMMISSIONING
A. Provide labor, materials, and equipment as required to facilitate the start up and
commissioning of systems and equipment within this scope of work by factory trained
service technician.
B. Provide Owner with a copy of the Start-Up Certificate as part of the Operations &
Maintenance Manual.
PART 2 - PRODUCTS
2.01 POWER GAS WATER HEATER (WH-1, WH-2)
A. Provide a non-condensing, submerged fire-tube, power gas type water heater of the
size and capacity shown on the drawings. Certify that the heater complies with the
requirements of ASHRAE 90.1. Minimum fuel to water efficiency is 83 percent.
B. Tank:
1. ASME construction and stamp for 188 psig test pressure and National Board
registered 125 psig working pressure.
GAS FIRED WATER HEATER
Division 15 - Section 15451
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15451 - 3
2. Lining: After tank is completely fabricated and welding is complete, abrasively
clean vessel to white metal, chemically clean, and line tank with a continuous,
non-porous thermosetting plastic liner.
3. Provide holiday-free tank lining construction to protect tank from corrosion due to
electrolytic action in water.
4. Pure, solid copper flue tubes, with PTFE coated boiler grade steel combustion
chamber.
5. Accessories; ASME and AGA rated temperature and pressure relief valve,
cleanout hand hole/inspection opening, drain valve with hose end fitting.
6. Tank design to allow manway-size access to enter tank for inspection and
maintenance.
7. Factory installed seismic restraint eyes mounted to tank prior to application of
coating. Eyes serve as bracing points for seismic zone 4 restraint.
C. Enameled sheet steel jacket over glass fiber or foam insulation. Heavy density
insulation thickness and efficiency shall be as required to meet energy efficiency
requirements of ASHRAE 90.1.
D. Burner: Sized and furnished by heater manufacturer for system capacity; continuous
duty overload protected motor, complete gas train as indicated, manual gas shutoff
valve, UL labeled. Provide: UL/IRI gas train designed for 8.0 inches to 14.0 inches
range of natural gas pressure. Gas train assembled and shipped loose for field
installation.
E. Controls: Provide a complete and operating control system, including the following
features:
1. Upper and lower operating thermostats.
2. High temperature limiting device.
3. Flame ignition control.
4. Flame failure control.
5. Chamber pre-purging sequence.
6. Automatic gas valve(s).
7. High temperature limiting device, manual reset (Listed over-temperature gas
cutoff).
8. Low water cutoff.
9. Controls UL approved, factory wired.
10. Provide control wiring diagram.
11. Operating controls shall not also be used as safety devices. Reference ASME,
CSD-1.
F. Miscellaneous Features: Flame inspection port, draft regulator per manufacturer's
instructions, dial thermometer, and pressure gauge mounting base, insulated sub-
base when required for installation on combustible floor.
GAS FIRED WATER HEATER
Division 15 - Section 15451
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15451 - 4
G. Warranty: 15 year tank warranty; three year heat exchanger/burner module warranty;
one year cost free (labor and parts) warranty.
H. Manufacturer: PVI, or equal.
2.02 CHIMNEY (STACK)
A. Provide a complete, engineered chimney system for fired equipment, including
connections and adapters to smoke outlets.
B. Provide prefabricated chimney system of the configuration shown on drawings, UL
listed for the application, with the following features:
1. Listed for pressurized systems.
2. Stainless steel liner, and stainless steel outer jacket where exposed to outdoor
weather.
3. Terminate stack with an exit cone.
4. Clearances from building elements in accordance with the chimney listing.
C. Provide clean-out tees, insulating roof support, drains at bottom of risers, and other
appropriate items required for proper installation and/or recommended by
manufacturer. Stainless steel flashing and counter-flashing.
D. Provide supports and seismic restraints in accordance with the manufacturer’s UL
listing.
E. Submit product data, shop drawings, and calculations of proposed layout, as required
in Part 1.
F. Manufacturer: Metalbestos, American Metal Products, Van Packer.
PART 3 - EXECUTION
3.01 INSTALLATION
A. Install water heaters in accordance with manufacturer's instructions and to AGA
requirements.
B. Coordinate with plumbing piping and related fuel piping, flue gas venting and
electrical work to achieve properly operating system.
C. Coordinate water heater venting with clearances to combustibles.
3.02 SEISMIC RESTRAINT
A. Provide seismic restraint of heater appropriate for Seismic Zone 4. See Section
15240 – Mechanical Sound, Vibration and Seismic Control.
GAS FIRED WATER HEATER
Division 15 - Section 15451
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15451 - 5
3.03 COMMISSIONING
A. Perform tests and verification procedures required for the commissioning process as
requested by the Owner and directed by the Owner's Commissioning Authority.
END OF SECTION 15451
HEAT GENERATION
Division 15 - Section 15550
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15550 - 1
SECTION 15550
HEAT GENERATION
PART 1 - GENERAL
1.01 SUMMARY
A. Section Includes:
1. This section describes specific requirements, products and methods of execution
for heat generation throughout the project.
B. Related Sections:
1. 15010 – Mechanical General Requirements.
2. 15050 – Basic Mechanical Materials and Methods.
3. 15510 – Hydronic Piping and Specialties.
4. 15910 – Control System Sequences of Operation.
1.02 DESCRIPTION
A. This section describes specific requirements, products and methods of execution for
interrelated systems necessary for the generation of heat which will be distributed to
the locations shown. The method of distribution of this heat is specified elsewhere.
1.03 CODES
A. International Mechanical Code (IMC).
B. ASME Boilers and Pressure Vessel Code, Sections IV & VI.
C. In addition to devices mentioned specifically herein, provide automatic boiler controls
listed in Table 10-C of the International Mechanical Code, and in ASME CSD-1, latest
edition, together with addenda and interpretations.
1.04 SUBMITTALS
A. Product Data:
1. Submit product submittals for approval showing boiler physical and performance
characteristics. Data shall include manufacturer's catalog cut sheets, and shall
clearly indicate which model is being submitted on, and features and
appurtenances being provided.
2. Submittals shall be in accordance with the requirements of Section 15010 –
Mechanical General Requirements and Division 1.
HEAT GENERATION
Division 15 - Section 15550
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15550 - 2
B. Shop Drawings:
1. Submitted boiler shall be dimensionally equal to scheduled product within six
inches in each dimension. Maintain clearances shown on drawings. Submit fully
dimensioned shop drawings of boiler room(s) at drawing scale of 1/4 inch equals
one foot zero inches or larger, showing entire boiler room, equipment and clear
callouts of deviations from layout shown. Provide boiler room modifications
required due to dimensional and technical deviation at no additional cost to the
Contract. Submit shop drawings of proposed equipment layout and base or pad
for each piece of equipment.
2. If equipment to be provided exceeds the weight of the specified equipment by
more than 20 percent, or if the location is to be altered, submit shop drawings of
revised structural loading, noting location of pertinent loads, and obtain approval
prior to providing equipment.
1.05 WARRANTY
A. Warranty workmanship, labor, and materials for a period of one year from the date of
final acceptance, without limitation, except where longer warranty periods are
specified in the General Conditions of the Contract. Warranty work shall be promptly
coordinated and performed at the Contractor’s sole expense.
PART 2 - PRODUCTS
2.01 HOT WATER BOILER - CAST IRON (BLR-1, BLR-2)
A. Provide factory assembled, sectional wet base, water walled cast iron boilers suitable
for forced draft firing. The output of each boiler shall not be less than that noted on
drawings. Required capacity shall be the gross I=B=R water rating unless otherwise
indicated. Provide boilers having gross outputs greater than 4700 MBH with 5
square feet of heating surface per boiler horsepower.
B. Provide the following features: Insulated metal jacket, burner mounting plate, gas
tight seal between sections, flue damper assembly, ASME safety relief valve (piped
down to six inches above floor), instrument panel as specified below, drain valve,
flange mounted gas burner, and other items required to make boiler complete.
C. Refractory based or walled boilers are not acceptable.
D. Manufacturer: Weil-McLain, Burnham.
1. Submitted boiler shall be dimensionally equal to scheduled product within six
inches in each dimension. Maintain clearances shown on drawings. Submit fully
dimensioned shop drawings of boiler showing entire boiler room, equipment and
clear callouts of deviations from layout shown. Provide boiler room modifications
required due to dimensional and technical deviation at no additional cost to the
Contract.
HEAT GENERATION
Division 15 - Section 15550
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15550 - 3
2.02 GAS BURNER (FOR BOILERS BLR-1, BLR-2)
A. Provide forced draft gas burner sized to match boiler rating and furnished by boiler
manufacturer as part of the required complete boiler package.
B. Burner shall be fully packaged and burner mounted and wired to boiler controls.
C. Provide burner controls as follows:
1. Firing control shall be fully modulating type with a turn down capability of not less
than two to one (2:1) as limited by a minimum exhaust gas temperature of 280
degrees F., with proven low-fire start.
2. Combustion and firing controls including Honeywell Model RM-7800 Flame
Safeguard System with self-diagnostic capabilities and digital display readout.
3. Gas train shall be UL/IRI and designed for 13.2 inches to 27.7 inches range of
natural gas pressure. Gas train assembled and shipped loose for field
installation.
4. Peripheral controls including reset operating temperature controller, a high limit
manually reset control, auxiliary Honeywell L4006E high limit control and a low
water safety shut off control as specified later in this Section.
5. Indicators and alarms shall include: Power on, run, lock out, low gas pressure,
high gas pressure and other indicating lights as applicable. Lock out indicator
shall have provision for connection to a remote alarm or monitoring device.
6. Provide wiring between burner cabinet, controls and safety devices in
accordance with applicable provisions of Division 16.
7. Provide panel mounted toggle switch to allow operator to manually switch
between DDC and local control. The boiler controls specified in this section shall
be fully coordinated with the DDC system sequences specified in Section 15910
– Control System Sequences of Operation. Burner shall be capable of accepting
a 4-20 mA remote signal from DDC system.
D. Burner System shall be UL/IRI listed as a unit.
E. Manufacturer: Weishaupt, no substitutions.
2.03 LOW WATER CUTOFF
A. Provide for each boiler an automatic resetting McDonnell Miller #63 series, approved,
low water cut-off wired in series with burner controls. Working pressure 50 psig.
UL/FM approved. Provide for each boiler a McDonnell Miller TC-4 test and check
assembly.
B. Provide for each boiler a second, manual reset McDonnell Miller #63M series,
approved, low water cut-off wired in series with burner controls. Working pressure 50
psig. UL/FM approved.
C. Pipe LWCO drain down to six inches above floor.
HEAT GENERATION
Division 15 - Section 15550
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15550 - 4
2.04 AUXILIARY HIGH LIMIT
A. Provide a Honeywell Model L4006-E auxiliary high limit sensor for each boiler, wired
to the boiler energy management system.
2.05 CHIMNEY (STACK)
A. Provide a complete, engineered chimney system for fired equipment, including
connections and adapters to smoke outlets.
B. Provide prefabricated chimney system of the size and configuration shown on
drawings, UL listed for the application, with the following features:
1. Listed for pressurized systems.
2. Stainless steel liner, and stainless steel outer jacket where exposed to outdoor
weather.
3. Terminate stack with an exit cone.
4. Clearances from building elements in accordance with the chimney listing.
C. Provide clean-out tees, insulating roof support, drains at bottom of risers, and other
appropriate items required for proper installation and/or recommended by
manufacturer. Stainless steel flashing and counterflashing.
D. Provide supports and seismic restraints in accordance with the manufacturer’s UL
listing.
E. Submit shop drawings of proposed layout.
F. Manufacturer: Metalbestos, American Metal Products, Van Packer.
PART 3 - EXECUTION
3.01 SETTING OF EQUIPMENT
A. Set equipment on a proper base or pad as recommended by the equipment
manufacturer, compatible with the building structural system. Level equipment to
within recommended tolerances. Submit shop drawings of proposed equipment
layout and base.
3.02 ANCHORING
A. Anchor equipment to building structure using appropriately sized bolts. Provide
seismic restraint per Section 15240 – Mechanical Sound, Vibration and Seismic
Control.
HEAT GENERATION
Division 15 - Section 15550
____________________________________________________________________________________
Eagle River Area High School
03-017-RFP 15550 - 5
3.03 RELIEF VENTING
A. Pipe gas train and pressure regulator vent lines to the outside of the building.
Multiple gas train vents from a single boiler may be manifolded together. Do not
combine with any of the following venting:
1. Pipe safety valve vent lines to the outside of the building. Safety valve vents for
a single boiler may be manifolded together.
2. Pipe pressure relief valve vent lines to the outside of the building.
3. Pipe ignition or main burner vent lines to the outside of the building.
4. Do not combine any vents with vents from other boilers.
3.04 STRUCTURAL LOAD
A. Verify that building structure is adequately designed to support the entire operating
weight of the equipment to be installed. If equipment to be provided exceeds the
weight of the specified equipment by more than 20 percent, or if the location is to be
altered, submit shop drawings of revised structural loading, noting location of
pertinent loads, and obtain approval prior to providing equipment. Provide structural
building modifications to accommodate proposed substitute equipment.
3.05 START-UP SERVICE
A. After completion of the installation, start-up the heating plant by a qualified factory
representative of the boiler manufacturer, furnished by the manufacturer's Alaska
sales office, and provide a start-up report by this representative, including control
settings, and a performance chart of the control system furnished. Submit a letter of
certification with start-up report from this representative stating that the boilers are in
perfect operating order and are properly adjusted. Test safety devices and record
settings. Test and record oxygen, carbon dioxide, smoke stack temperature and
calculate excess air and steady state efficiency. Coordinate with lead/lag control
installer, and make final lead/lag setpoint adjustments. Note set points in report.
Submit final data for review. Provide two hours operating instruction to authorized
owner representative by this factory start-up man.
3.06 THERMAL EXPANSION
A. Install piping to allow for normal thermal expansion and contraction. Provide anchors
where necessary and as shown. Provide expansion loops, and alignment guides to
suit conditions and as shown on drawings.
3.07 COMMISSIONING
A. Perform tests and verification procedures required for the commissioning process as
requested by the Owner and directed by the Owner's Commissioning Authority.
END OF SECTION 15550
APPENDIX 7
TOPOGRAPHIC MAP FOR OPTION 3
(EAGLE RIVER SCHOOL)
Copyright (C) 1997, Maptech, Inc.
Anchorage Landfill
Eagle River H.S.
0
450
500
550
600
650
700
Miles
Total distance:3236 feet
Ground distance:3237 feet
Climbing:10 feet
Descending:-43 feet
Elevation change:-33 feet
Min/Max:428/471
Latitude: 000° 00' 00.0'' N
Longitude: 000° 00' 00.0'' E
Elevation:
Grade:
APPENDIX 8
FINANCIAL PRO FORMA FOR OPTION 3
(EAGLE RIVER SCHOOL)
Assumptions
MG Price $18.870
MG Price Escalation 2.0%
Capital Cost 2,186,031$
Loan Amount $0
Gas Cost $0.0000
Gas Cost Escalation 2.0%
Gas Quantity 105 SCFM
Financing
Principal No Debt
Term n/a
Interest Rate n/a
Financial Returns 10 Years
Total Cash Flow from Operations 2,584,988$
Investment 2,186,031$
Net Cash Flow 398,957$
Project IRR 3.0%
NPV at rate = 2.000% 120,252$
NPV at rate = 2.500% 58,746$
NPV at rate = 2.750% 29,102$
NPV at rate = 3.000% 173$
Pre Tax Profits 644,279$
Average % 11.3%
Minimum % 2.5%
Net Income 398,957$
Average % 6.7%
Minimum % -5.7%
MUSA Contributions (Municipal Utility Service Assessment)
Rate 10 Year Totals
Rate on Net Book Value of Assets - in mils 16 176,771$
Gross Revenue contribution % of Revenue 1.25% 68,551$
245,322$
Depreciation per GASB 34 Method Life in Years
Vehicles St. Line 5
Support Equipment St. Line 4
Machinery & Equipment St. Line 7
GCCS & Pipeline St. Line 10
Summary of Assumptions & Financials
Anchorage Medium BTU Gas Project
Gas Sales to Eagle River High School (under construction)
Annual Gas Demand (flow of 105 scfm) Based on Existing School Building
Project Proforma
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Description Value Unit
Financial Information
Project Capital Costs 2.08 mile pipeline, 8" dia. $2,186,031
Equity Contribution 100.00% $2,186,031
Loan 0.00%
Principal $0
Term 10 years
Interest Rate 0.0%
Interest Payments monthly during construction
Loan Fees 0.0%
MG Quantity 105 SCFM 26,542 mmBTU/Yr
50.00% Methane %
On-Stream Factors
Utilization %95.0%
MG Price $18.870
MG Price escalator 2.0%
Cost of Sales
Cost of Methane Gas $0.0000 per mmBTU
Cost Escalator 2.0%
Electric Cost - Blower and Compressor @ .09 cents / kwh $40,000 Annually
Electric Escalator 2.0%
Operating Costs Annually
O&M Wellfield/Compressor/Pipeline per year 150,000$
O&M Escalator 3.0%
Property Insurance 1.00% % of Value
General Liability Insurance 1.00% % of Revenue
Administration $25,000
Income Taxes Is project subject to income taxes NO
Federal Tax Rate 0%
State Tax Rate 0.0% Incl. In Federal
Gas Sales to Eagle River High School (under construction)
Anchorage Medium BTU Gas Project
ASSUMPTIONS to PRO FORMA
5/18/2004 1:46 PM Anchorage EagleRiverSchool Pipeline apdx 8
Gas Sales to Eagle River High School (under construAnnual ProformaMethane Gas Price (MG) = 18.87$ Escalation Year012345678910 YearAssumptionsCalendarYear 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TotalGas Curve LFG Generation - Avg 1,101 1,170 1,237 1,302 1,364 1,423 1,479 1,533 1,584 1,632 Lfg Recoverable Rate 75.0% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%Landfill Gas Available 826 878 928 977 1,023 1,067 1,109 1,150 1,188 1,224 Average MMBTU @ 50% Methane & 95% Utilization 208,631 221,706 234,402 246,719 258,467 269,647 280,259 290,491 300,155 309,251 School Gas DemandAverage SCFM 105 105 105 105 105 105 105 105 105 105 1050.502054Average MMBTU @ 50% Methane & 95% Utilization 26,542 26,542 26,542 26,542 26,542 26,542 26,542 26,542 26,542 26,542 265,420 EscalatorAssumed Methane Gas Price 2% 18.87$ 19.25$ 19.63$ 20.02$ 20.43$ 20.83$ 21.25$ 21.68$ 22.11$ 22.55$ IncomeEscalatorMG Sales - Landfill Gas Production 2.0% $500,848 $510,934 $521,019 $531,371 $542,253 $552,870 $564,018 $575,431 $586,844 $598,522 $5,484,108Total Revenues 500,848 510,934 521,019 531,371 542,253 552,870 564,018 575,431 586,844 598,522 5,484,108 Costs of SalesPurchased Electricity - Blower/Compressor 2.0% 40,000 40,800 41,616 42,448 43,297 44,163 45,046 45,947 46,866 47,804 437,989 Purchased Methane Gas -$ 2.0% - - - - - - - - - - - Costs of Sales 40,000 40,800 41,616 42,448 43,297 44,163 45,046 45,947 46,866 47,804 437,989 Gross Profit460,848 470,134 479,403 488,923 498,956 508,707 518,971 529,483 539,977 550,718 5,046,119 Expenses - PipelineO&M - Wellfield/Comp/Pipeline - per year 2.0% 150,000 153,000 156,060 159,181 162,365 165,612 168,924 172,303 175,749 179,264 1,642,458 Property Insur. - (% of value) 1.00% 2.0% 21,860 22,298 22,743 23,198 23,662 24,136 24,618 25,111 25,613 26,125 239,364 General Liability Insur. (% of revenue) 1.00% 2.0% 5,008 5,212 5,421 5,639 5,870 6,104 6,352 6,610 6,876 7,153 60,244 Administration 2.0% 25,000 25,500 26,010 26,530 27,061 27,602 28,154 28,717 29,291 29,877 273,743 Personal Property Tax - n/a - assume Pollution Control Exemp.0000000000 - Interest0000000000 - Total Expenses 201,869 206,009 210,234 214,549 218,957 223,454 228,048 232,741 237,529 242,419 2,215,809 Net Operating Profit 258,979 264,124 269,169 274,374 279,998 285,253 290,923 296,743 302,448 308,299 2,830,310 LessDepreciation/Amort Finance Fees (Pipeline Only) 246,460 246,460 246,460 246,460 246,460 246,460 246,460 153,603 153,603 153,603 2,186,031 Net Profit Before Tax 12,519 17,664 22,709 27,914 33,538 38,793 44,462 143,140 148,845 154,696 644,279 2.5% 3.5% 4.4% 5.3% 6.2% 7.0% 7.9% 24.9% 25.4% 25.8% 11.7%MUSA ContributionsMillage Rate on NBV of PPE 1.60% 34,976 31,033 27,090 23,146 19,203 15,260 11,316 7,373 4,915 2,458 176,771 Gross Revenue Rate 1.25% 6,261 6,387 6,513 6,642 6,778 6,911 7,050 7,193 7,336 7,482 68,551 Total Taxes 41,237 37,420 33,603 29,789 25,981 22,171 18,367 14,566 12,251 9,939 245,322 Net Income(28,719) (19,756) (10,893) (1,875) 7,557 16,622 26,096 128,574 136,594 144,757 398,957 -5.7% -3.9% -2.1% -0.4% 1.4% 3.0% 4.6% 22.3% 23.3% 24.2% 7.3%Anchorage Medium BTU Gas Project5/18/2004 1:47 PMAnchorage EagleRiverSchool Pipeline apdx 8
Gas Sales to Eagle River High School (under construAnnual ProformaMethane Gas Price (MG) = 18.87$ Anchorage Medium BTU Gas ProjectConstructionCash Flow - Total Project2005Capital Expenditures (2,186,031) Loan - Add Depreciation/Amort (Pipeline & Related Costs) 246,460 246,460 246,460 246,460 246,460 246,460 246,460 153,603 153,603 153,603 2,186,031 Less Principal Payment 0000000000 0Net After Tax Cash Flow(2,186,031) 217,742 226,705 235,567 244,585 254,017 263,082 272,556 282,177 290,197 298,360 2,584,988 Cumulative After Tax Cash @ (2,186,031) (1,968,289) (1,741,585) (1,506,018) (1,261,433) (1,007,415) (744,333) (471,777) (189,600) 100,597 398,957 Net Present Value (NPV)2.000%$120,252Bank Principal Balance (Yr End) - - - - - - - - 2,012 - 10 YEARInvestment Analysis - Total ProjectConst. Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TOTAL% Ownership 100.00%Capital Expenditures (2,186,031) (2,186,031) Construction Interest- Bond - - Cash Flow 217,742 226,705 235,567 244,585 254,017 263,082 272,556 282,177 290,197 298,360 2,584,988 - After Tax Cash Flow - Year (2,186,031) 217,742 226,705 235,567 244,585 254,017 263,082 272,556 282,177 290,197 298,360 398,957 After Tax Cash Flow - Cum. (2,186,031) (1,968,289) (1,741,585) (1,506,018) (1,261,433) (1,007,415) (744,333) (471,777) (189,600) 100,597 398,957 Project IRR - on Cash Investment 3.00%NPV - After tax - Discount @ 2.00% $120,2522.50% $58,7462.75% $29,102Discount = to IRR 3.00% $173NPV and IRR reconcileReturn on Revenues Average MinimumPre Tax 11.27% 2.50%After Tax 6.68% -5.73%5/18/2004 1:47 PMAnchorage EagleRiverSchool Pipeline apdx 8
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Description
Sub-Total Total
Gas Collection System / Compressor Facility
Wellfield based on $12,000 per acre asuming 73 acres $876,000
Compressor $650,000
Contingency $0 Included in above
$1,526,000
Pipeline and Related Costs
Blower Upgrade $0 Included in GCCS
Pipeline 2.0797 miles @ $51 per foot - 8'' pipeline $560,031
D.O.T. Pipeline Safety Standards Design & Compliance $0 Included in Pipeline estimate
Air Compressor $0 Included in Pipeline estimate
Surveying $0 Included in Pipeline estimate
Geotechnical $0 Included in Pipeline estimate
Planning/Coordination/Legal $0 Included in Pipeline estimate
Construction Interest $0 None assumed
Right of Way Payment $0 None assumed
Wetlands Investigation $0 Included in Pipeline estimate
End User Upgrades $100,000 Allowance
Contingency - 10% $0 Included in above
$660,031
Project Total $2,186,031
Gas Sales to Eagle River High School (under construction)
Anchorage Medium BTU Gas Project
Capital Estimate Detail
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Depreciation Amounts Amount
Gas Treatment and Processing System 1,526,000
Pipeline and Related Costs 660,031
Construction Interest -
Sub-Total 2,186,031
Year Depreciation
1 2006 $246,460
2 2007 $246,460
3 2008 $246,460
4 2009 $246,460
5 2010 $246,460
6 2011 $246,460
7 2012 $246,460
8 2013 $153,603
9 2014 $153,603
10 2015 $153,603
$2,186,031
Gas Sales to Eagle River High School (under construction)
Anchorage Medium BTU Gas Project
Depreciation & Amortization Schedules
APPENDIX 9
TOPOGRAPHIC MAP FOR OPTION 4
(NATIONAL GUARD)
Copyright (C) 1997, Maptech, Inc.
Anchorage Landfill
National Guard Armory
012400
450
500
550
600
650
Miles
Total distance:2 miles, 3875 feet
Ground distance:2 miles, 3883 feet
Climbing:118 feet
Descending:-185 feet
Elevation change:-66 feet
Min/Max:396/536
Latitude: 000° 00' 00.0'' N
Longitude: 000° 00' 00.0'' E
Elevation:
Grade:
APPENDIX 10
FINANCIAL PRO FORMA FOR OPTION 4
(NATIONAL GUARD)
Assumptions
MG Price $3.445
MG Price Escalation 2.0%
Capital Cost 2,492,131$
Loan Amount $0
Gas Cost $0.0000
Gas Cost Escalation 2.0%
Gas Quantity 650 SCFM
Financing
Principal No Debt
Term n/a
Interest Rate n/a
Financial Returns 10 Years
Total Cash Flow from Operations 2,948,009$
Investment 2,492,131$
Net Cash Flow 455,878$
Project IRR 3.0%
NPV at rate = 2.000% 137,924$
NPV at rate = 2.500% 67,757$
NPV at rate = 2.750% 33,940$
NPV at rate = 3.000% 937$
Pre Tax Profits 737,061$
Average % 11.5%
Minimum % 3.2%
Net Income 455,878$
Average % 6.8%
Minimum % -5.1%
MUSA Contributions (Municipal Utility Service Assessment)
Rate 10 Year Totals
Rate on Net Book Value of Assets - in mils 16 203,708$
Gross Revenue contribution % of Revenue 1.25% 77,476$
281,184$
Depreciation per GASB 34 Method Life in Years
Vehicles St. Line 5
Support Equipment St. Line 4
Machinery & Equipment St. Line 7
GCCS & Pipeline St. Line 10
Summary of Assumptions & Financials
Anchorage Medium BTU Gas Project
Gas Sales to National Guard Armory
Assumes National Guard Armory Usage is Based on Historical Demand
Project Proforma
April 12, 2004
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April 12, 2004
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Description Value Unit
Financial Information
Project Capital Costs $2,492,131
Equity Contribution 100.00% $2,492,131
Loan 0.00%
Principal $0
Term 10 years
Interest Rate 0.0%
Interest Payments monthly during construction
Loan Fees 0.0%
MG Quantity 650 SCFM 164,297 mmBTU/Yr
50.00% Methane %
On-Stream Factors
Utilization %95.0%
MG Price $3.445
MG Price escalator 2.0%
Cost of Sales
Cost of Methane Gas $0.0000 per mmBTU
Cost Escalator 2.0%
Electric Cost - Blower and Compressor @ .09 cents / kwh $40,000 Annually
Electric Escalator 2.0%
Operating Costs Annually
O&M Compressor/Pipeline per year 175,000$
O&M Escalator 3.0%
Property Insurance 1.00% % of Value
General Liability Insurance 1.00% % of Revenue
Administration $25,000
Income Taxes Is project subject to income taxes NO
Federal Tax Rate 0%
State Tax Rate 0.0% Incl. In Federal
Questions 1 When do we anticipate project completion / start-up?2006
2 Verity Gas curve to use and recovery rate Avg LFG at 75%
3 Does gas curve assume 50 or 50+23 acres 73 acres
4 Does the $15,000 include flare, blower and electrical Includes all components of GCCS
5 Tony had an estimate of $75/ft for pipeline. What does this include?As per Jim use Kevin's $60
6 No Federal Tax
Gas Sales to National Guard Armory
Anchorage Medium BTU Gas Project
ASSUMPTIONS to PRO FORMA
5/18/2004 2:08 PM Anchorage NatGuard Pipeline_1 1 apdx 10
Gas Sales to National Guard Armory Annual ProformaMethane Gas Price (MG) = 3.45$ Escalation Year012345678910 YearAssumptionsCalendarYear 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TotalGas Curve LFG Generation - Avg 1,101 1,170 1,237 1,302 1,364 1,423 1,479 1,533 1,584 1,632 Lfg Recoverable Rate 75.0% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%Landfill Gas Available 826 878 928 977 1,023 1,067 1,109 1,150 1,188 1,224 Average MMBTU @ 50% Methane & 95% Utilization 208,631 221,706 234,402 246,719 258,467 269,647 280,259 290,491 300,155 309,251 National Guard Gas DemandAverage mmBtu 164,297 164,297 164,297 164,297 164,297 164,297 164,297 164,297 164,297 164,297 164,297 1,642,968 Average SCFM 650 650 650 650 650 650 650 650 650 650 EscalatorAssumed Methane Gas Price 2% 3.45$ 3.51$ 3.58$ 3.66$ 3.73$ 3.80$ 3.88$ 3.96$ 4.04$ 4.12$ IncomeEscalatorMG Sales - Landfill Gas Production 2.0% $566,002 $576,682 $588,182 $601,326 $612,827 $624,328 $637,471 $650,615 $663,759 $676,903 $6,198,095Total Revenues 566,002 576,682 588,182 601,326 612,827 624,328 637,471 650,615 663,759 676,903 6,198,095 Costs of SalesPurchased Electricity - Blower/Compressor 2.0% 40,000 40,800 41,616 42,448 43,297 44,163 45,046 45,947 46,866 47,804 437,989 Purchased Methane Gas -$ 2.0% - - - - - - - - - - - Costs of Sales 40,000 40,800 41,616 42,448 43,297 44,163 45,046 45,947 46,866 47,804 437,989 Gross Profit526,002 535,882 546,566 558,878 569,530 580,164 592,425 604,668 616,893 629,099 5,760,107 Expenses - PipelineO&M - Wellfield/Comp/Pipeline - per year 2.0% 175,000 178,500 182,070 185,711 189,426 193,214 197,078 201,020 205,040 209,141 1,916,201 Property Insur. - (% of value) 1.00% 2.0% 24,921 25,420 25,928 26,447 26,976 27,515 28,065 28,627 29,199 29,783 272,881 General Liability Insur. (% of revenue) 1.00% 2.0% 5,660 5,882 6,119 6,381 6,633 6,893 7,179 7,474 7,777 8,090 68,089 Administration 2.0% 25,000 25,500 26,010 26,530 27,061 27,602 28,154 28,717 29,291 29,877 273,743 Personal Property Tax - n/a - assume Pollution Control Exemp.0000000000 - Interest0000000000 - Total Expenses 230,581 235,302 240,128 245,070 250,095 255,224 260,477 265,837 271,308 276,891 2,530,914 Net Operating Profit 295,421 300,580 306,439 313,808 319,434 324,940 331,948 338,830 345,584 352,208 3,229,192 LessDepreciation/Amort Finance Fees (Pipeline Only) 277,070 277,070 277,070 277,070 277,070 277,070 277,070 184,213 184,213 184,213 2,492,131 Net Profit Before Tax 18,351 23,509 29,369 36,738 42,364 47,870 54,878 154,617 161,371 167,994 737,061 3.2% 4.1% 5.0% 6.1% 6.9% 7.7% 8.6% 23.8% 24.3% 24.8% 11.9%MUSA ContributionsMillage Rate on NBV of PPE 1.60% 39,874 35,441 31,008 26,575 22,142 17,708 13,275 8,842 5,895 2,947 203,708 Gross Revenue Rate 1.25% 7,075 7,209 7,352 7,517 7,660 7,804 7,968 8,133 8,297 8,461 77,476 Total Taxes 46,949 42,649 38,360 34,091 29,802 25,513 21,244 16,975 14,192 11,409 281,184 Net Income(28,598) (19,140) (8,992) 2,647 12,562 22,357 33,634 137,642 147,179 156,586 455,878 -5.1% -3.3% -1.5% 0.4% 2.0% 3.6% 5.3% 21.2% 22.2% 23.1% 7.4%Anchorage Medium BTU Gas Project5/18/2004 2:08 PMAnchorage NatGuard Pipeline_1 1 apdx 10
Gas Sales to National Guard Armory Annual ProformaMethane Gas Price (MG) = 3.45$ Anchorage Medium BTU Gas ProjectConstructionCash Flow - Total Project2005Capital Expenditures (2,492,131) Loan - Add Depreciation/Amort (Pipeline & Related Costs) 277,070 277,070 277,070 277,070 277,070 277,070 277,070 184,213 184,213 184,213 2,492,131 Less Principal Payment 0000000000 0Net After Tax Cash Flow(2,492,131) 248,472 257,930 268,079 279,717 289,632 299,428 310,704 321,855 331,393 340,799 2,948,009 Cumulative After Tax Cash @ (2,492,131) (2,243,659) (1,985,729) (1,717,650) (1,437,933) (1,148,301) (848,874) (538,169) (216,314) 115,079 455,878 Net Present Value (NPV)2.000%$137,924Bank Principal Balance (Yr End) - - - - - - - - 2,012 - 10 YEARInvestment Analysis - Total ProjectConst. Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TOTAL% Ownership 100.00%Capital Expenditures (2,492,131) (2,492,131) Construction Interest- Bond - - Cash Flow 248,472 257,930 268,079 279,717 289,632 299,428 310,704 321,855 331,393 340,799 2,948,009 - After Tax Cash Flow - Year (2,492,131) 248,472 257,930 268,079 279,717 289,632 299,428 310,704 321,855 331,393 340,799 455,878 After Tax Cash Flow - Cum. (2,492,131) (2,243,659) (1,985,729) (1,717,650) (1,437,933) (1,148,301) (848,874) (538,169) (216,314) 115,079 455,878 Project IRR - on Cash Investment 3.01%NPV - After tax - Discount @ 2.00% $137,9242.50% $67,7572.75% $33,940Discount = to IRR 3.00% $937NPV and IRR reconcileReturn on Revenues Average MinimumPre Tax 11.45% 3.24%After Tax 6.79% -5.05%5/18/2004 2:08 PMAnchorage NatGuard Pipeline_1 1 apdx 10
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Description
Sub-Total Total
Gas Collection System / Compressor Facility
Wellfield based on $12,000 per acre asuming 73 acres $876,000
Compressor $650,000
Contingency $0 Included in above
$1,526,000
Pipeline and Related Costs
Blower Upgrade $0 Included in GCCS
Pipeline 2.734 miles @ $60 per foot $866,131
D.O.T. Pipeline Safety Standards Design & Compliance $0 Included in Pipeline estimate
Air Compressor $0 Included in Pipeline estimate
Surveying $0 Included in Pipeline estimate
Geotechnical $0 Included in Pipeline estimate
Planning/Coordination/Legal $0 Included in Pipeline estimate
Construction Interest $0 None assumed
Right of Way Payment $0 None assumed
Wetlands Investigation $0 Included in Pipeline estimate
End User Upgrades $100,000 Allowance
Contingency - 10% $0 Included in above
$966,131
Project Total $2,492,131
Gas Sales to National Guard Armory
Anchorage Medium BTU Gas Project
Capital Estimate Detail
5/18/2004 2:09 PM Anchorage NatGuard Pipeline_1 1 apdx 10
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Depreciation Amounts Amount
Gas Treatment and Processing System 1,526,000
Pipeline and Related Costs 966,131
Construction Interest -
Sub-Total 2,492,131
Year Depreciation
1 2006 $277,070
2 2007 $277,070
3 2008 $277,070
4 2009 $277,070
5 2010 $277,070
6 2011 $277,070
7 2012 $277,070
8 2013 $184,213
9 2014 $184,213
10 2015 $184,213
$2,492,131
Gas Sales to National Guard Armory
Anchorage Medium BTU Gas Project
Depreciation & Amortization Schedules
APPENDIX 11
TOPOGRAPHIC MAP FOR OPTION 5
(FT. RICHARDSON)
Copyright (C) 1997, Maptech, Inc.
Ft. Richardson Building #726
Anchorage Landfill
012345
400
450
500
550
600
650
Miles
Total distance:5 miles, 1446 feet
Ground distance:5 miles, 1454 feet
Climbing:108 feet
Descending:-208 feet
Elevation change:-100 feet
Min/Max:371/534
Latitude: 061° 16' 10.1'' N
Longitude: 149° 40' 20.4'' W
Elevation:396 feet
Grade:0%
APPENDIX 12
LIST OF NATURAL GAS BURNING EQUIPMENT AT FT. RICHARDSON
BLDG Boiler Startup Heat Burner MBHMFG Date Model Serial No Type MFG Model Serial No Max Input726Cleaver Brooks 5/15/2003 CBI700-200LE L-101427 Steam Cleaver Brooks CBI700-200LE L-101427 8,165 726Cleaver Brooks 5/15/2003 CBI700-200LE L-101428 Steam Cleaver Brooks CBI700-200LE L-101428 8,165 726Cleaver Brooks 5/15/2003 CBI700-200LE L-101429 Steam Cleaver Brooks CBI700-200LE L-101429 8,165 726Cleaver Brooks 5/15/2003 CBI700-200LE L-101430 Steam Cleaver Brooks CBI700-200LE L-101430 8,165 MBH32,660 MMBtu/hr33 LFG to Energy Cleaver Brooks 1
BLDG Boiler
Start Date Boiler MFG Model Heat Type Burner Model
Burner
Make
MBH Max
Input
MMBtu Max
Input
27000 Unknown Not Avail Not Avail Gas Not Avail Not Avail 790 0.79
27004 Unknown Not Avail Not Avail Gas Not Avail Not Avail 150 0.15
27004 Unknown Not Avail Not Avail Gas Not Avail Not Avail 150 0.15
27004 Unknown Not Avail Not Avail Gas Not Avail Not Avail 150 0.15
28008 1988 Not Avail Not Avail Gas Not Avail Not Avail 4000 4.00
28008 1988 Not Avail Not Avail Gas Not Avail Not Avail 4000 4.00
45100 Unknown Not Avail Not Avail Gas Not Avail Not Avail 250 0.25
45125 Unknown Not Avail Not Avail Gas Not Avail Not Avail 430 0.43
45580 Unknown Not Avail Not Avail Gas Not Avail Not Avail 3230 3.23
45594 Unknown Not Avail Not Avail Gas Not Avail Not Avail 540 0.54
45726 Unknown Not Avail Not Avail Gas Not Avail Not Avail 2170 2.17
45727 Unknown Not Avail Not Avail Gas Not Avail Not Avail 150 0.15
45730 Unknown Not Avail Not Avail Gas Not Avail Not Avail 250 0.25
47645 Unknown Not Avail Not Avail Gas Not Avail Not Avail 100 0.10
47811 Unknown Not Avail Not Avail Gas Not Avail Not Avail 140 0.14
47812 Unknown Not Avail Not Avail Gas Not Avail Not Avail 100 0.10
47813 Unknown Not Avail Not Avail Gas Not Avail Not Avail 100 0.10
48010 Unknown Not Avail Not Avail Gas Not Avail Not Avail 350 0.35
55804 1988 Not Avail Not Avail Gas Not Avail Not Avail 790 0.79
59000 Unknown Not Avail Not Avail Gas Not Avail Not Avail 390 0.39
59002 Unknown Not Avail Not Avail Gas Not Avail Not Avail 230 0.23
8 9/7/2003 Burnham IN6 Hydronic KIN6LNC-LE2 NA 175 0.18
53 9/3/2003 Burnham V904A Hydronic BCJR30A-10 080146944 606 0.61
54 9/3/2003 Burnham V904A Hydronic BCJR30A-10 080146954 606 0.61
55 7/16/2003 Burnham V904A Hydronic BCJR30A-10 090147129 606 0.61
57 7/23/2003 Burnham V904A Hydronic BCJR30A-10 080146949 606 0.61
58 7/23/2003 Burnham V904A Hydronic BCJR30A-10 080146945 606 0.61
201 5/7/2003 Burnham V904A Hydronic BCJR30A-10 090147143 606 0.61
202 5/7/2003 Burnham V904A Hydronic BCJR30A-10 090147139 606 0.61
203 5/1/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
204 5/5/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
206 5/5/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
207 5/5/2003 Burnham IN11 Hydronic KIN11LNI-LL2 NA 349 0.35
208 5/6/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
209 5/6/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
210 5/5/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
221 9/3/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
222 5/12/2003 Burnham IN11 Hydronic KIN11LNI-LL2 NA 349 0.35
223 5/8/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
224 5/12/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
225 5/8/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
227 5/8/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
228 5/8/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
230 5/6/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
231 5/6/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
241 5/12/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
243 11/22/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
244 5/13/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
245 5/16/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
247 5/14/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
249 5/14/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
LFG to Energy Misc Boilers Burners 1
BLDG Boiler
Start Date Boiler MFG Model Heat Type Burner Model
Burner
Make
MBH Max
Input
MMBtu Max
Input
250 5/16/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
252 5/12/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
261 5/19/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
262 5/19/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
264 5/15/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
265 5/14/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
266 5/15/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
268 5/15/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
269 5/15/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
270 5/14/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
272 5/19/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
273 5/19/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
281 5/20/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
282 5/21/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
284 5/21/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
285 5/20/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
287 7/31/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
288 5/22/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
289 7/31/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
290 5/22/2003 Burnham IN11 Hydronic KIN11LNI-LL2 NA 349 0.35
291 7/31/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
292 5/20/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
293 7/9/2003 Burnham IN5 Hydronic KIN5LNS-LE2 NA 140 0.14
300 5/28/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
301 5/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
302 5/30/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
303 5/21/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
304 5/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
305 5/20/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
306 5/27/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
310 5/27/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
311 5/22/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
312 5/22/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
313 5/21/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
314 5/30/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
315 5/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
320 6/4/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
321 6/4/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
322 6/9/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
323 6/3/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
324 6/5/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
325 6/5/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
326 6/6/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
331 6/5/2003 Burnham IN6 Hydronic KIN6LNC-LE2 NA 175 0.18
332 6/3/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
333 5/28/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
334 6/6/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
335 6/6/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
340 8/4/2003 Burnham V904A Hydronic BCJR30A-10 090147115 606 0.61
341 8/5/2003 Burnham V904A Hydronic BCJR30A-10 090147132 606 0.61
342 6/9/2003 Burnham V904A Hydronic BCJR30A-10 090147118 606 0.61
LFG to Energy Misc Boilers Burners 2
BLDG Boiler
Start Date Boiler MFG Model Heat Type Burner Model
Burner
Make
MBH Max
Input
MMBtu Max
Input
343 6/9/2003 Burnham V904A Hydronic BCJR30A-10 090147136 606 0.61
344 6/10/2003 Burnham V904A Hydronic BCJR30A-10 090147140 606 0.61
346 6/10/2003 Burnham V904A Hydronic BCJR30A-10 090147128 606 0.61
348 8/4/2003 Burnham V904A Hydronic BCJR30A-10 090147126 606 0.61
349 6/10/2003 Burnham V904A Hydronic BCJR30A-10 090147144 606 0.61
350 6/11/2003 Burnham V904A Hydronic BCJR30A-10 090147138 606 0.61
351 8/5/2003 Burnham V904A Hydronic BCJR30A-10 090147137 606 0.61
352 8/4/2003 Burnham V904A Hydronic BCJR30A-10 090147120 606 0.61
353 6/17/2003 Burnham V904A Hydronic BCJR30A-10 090147131 606 0.61
355 6/11/2003 Burnham V904A Hydronic BCJR30A-10 090147141 606 0.61
356 6/11/2003 Burnham V904A Hydronic BCJR30A-10 090147117 606 0.61
358 6/12/2003 Burnham V904A Hydronic BCJR30A-10 080146946 606 0.61
360 8/4/2003 Burnham V904A Hydronic BCJR30A-10 090147134 606 0.61
361 6/13/2003 Burnham V904A Hydronic BCJR30A-10 090147130 606 0.61
362 6/13/2003 Burnham V904A Hydronic BCJR30A-10 090147122 606 0.61
363 6/16/2003 Burnham V904A Hydronic BCJR30A-10 090147123 606 0.61
364 6/16/2003 Burnham V904A Hydronic BCJR30A-10 090147142 606 0.61
366 6/18/2003 Burnham V904A Hydronic BCJR30A-10 090147145 606 0.61
367 6/18/2003 Burnham V904A Hydronic BCJR30A-10 090147125 606 0.61
369 6/20/2003 Burnham V904A Hydronic BCJR30A-10 090147112 606 0.61
371 6/26/2003 Burnham V904A Hydronic BCJR30A-10 090147113 606 0.61
372 6/17/2003 Burnham V904A Hydronic BCJR30A-10 090147121 606 0.61
373 6/20/2003 Burnham V904A Hydronic BCJR30A-10 090147114 606 0.61
380 6/20/2003 Burnham V904A Hydronic BCJR30A-10 090147127 606 0.61
381 6/19/2003 Burnham V904A Hydronic BCJR30A-10 090147119 606 0.61
382 7/31/2003 Burnham V905A Hydronic BCJR30A-12 080147088 668 0.67
383 7/29/2003 Burnham V905A Hydronic BCJR30A-12 080147085 668 0.67
384 7/23/2003 Burnham V904A Hydronic BCJR30A-10 080146947 606 0.61
385 7/28/2003 Burnham V905A Hydronic BCJR30A-12 80147083 668 0.67
386 7/18/2003 Burnham V905A Hydronic BCJR30A-12 080147087 668 0.67
387 7/17/2003 Burnham V904A Hydronic BCJR30A-10 090147133 606 0.61
388 7/16/2003 Burnham V905A Hydronic BCJR30A-12 080147086 668 0.67
389 7/14/2003 Burnham V905A Hydronic BCJR30A-12 080147089 668 0.67
390 7/7/2003 Burnham V904A Hydronic BCJR30A-10 090147124 606 0.61
391 7/8/2003 Burnham V905A Hydronic BCJR30A-12 080147080 668 0.67
392 8/4/2003 Burnham V905A Hydronic BCJR30A-12 080147084 668 0.67
393 7/2/2003 Burnham V905A Hydronic BCJR30A-12 080147082 668 0.67
394 7/3/2003 Burnham V905A Hydronic BCJR30A-12 080147081 668 0.67
403 4/21/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
404 4/21/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
405 4/21/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
406 4/22/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
408 4/22/2003 Burnham IN11 Hydronic KIN11LNI-LL2 NA 349 0.35
409 4/22/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
410 4/24/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
411 4/24/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
413 4/23/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
414 4/23/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
415 4/24/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
416 4/23/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
417 4/23/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
LFG to Energy Misc Boilers Burners 3
BLDG Boiler
Start Date Boiler MFG Model Heat Type Burner Model
Burner
Make
MBH Max
Input
MMBtu Max
Input
418 4/22/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
421 4/28/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
422 4/28/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
423 4/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
424 4/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
425 4/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
426 4/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
427 4/28/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
428 4/25/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
429 4/25/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
430 4/25/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
431 4/28/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
432 4/25/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
433 7/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
434 7/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
435 7/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
436 4/30/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
437 7/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
438 7/30/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
439 4/30/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
440 7/30/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
441 7/30/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
442 7/31/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
443 7/31/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
455 4/30/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
456 4/30/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
457 5/1/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
458 5/1/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
501 4/14/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
503 4/14/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
504 4/16/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
505 4/15/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
506 4/15/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
508 4/16/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
509 4/15/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
510 4/17/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
511 4/17/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
514 4/18/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
515 4/17/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
516 4/16/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
517 4/16/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
520 4/21/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
521 7/28/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
522 7/28/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
523 7/28/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
524 6/23/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
529 5/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
530 5/29/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
531 6/4/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
533 6/4/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
537 4/18/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
LFG to Energy Misc Boilers Burners 4
BLDG Boiler
Start Date Boiler MFG Model Heat Type Burner Model
Burner
Make
MBH Max
Input
MMBtu Max
Input
538 4/18/2003 Burnham IN10 Hydronic KIN10LNI-LL2 NA 315 0.32
604 9/9/2003 Burnham V905A Hydronic BCJR30A-12 080147110 668 0.67
618 7/16/2003 Burnham IN11 Hydronic BCJR30A-10 N/A 606 0.61
656 6/24/2003 Burnham V903A Hydronic BCJR30A-10 090147090 447 0.45
672 7/29/2003 Burnham V904A Hydronic BCJR30A-10 080146956 606 0.61
730 7/30/2003 Burnham V905A Hydronic BCJR30A-12 120253415 668 0.67
794 6/1/2003 Burnham V905A Hydronic BCJR30A-12 80147111 668 0.67
976 5/28/2003 Burnham V1111 Hydronic BCCR3-G-21 090100872 2,656 2.66
977 5/15/2003 Burnham V1109 Hydronic BCC2-G-15 080100647 2,136 2.14
1107 9/4/2003 Burnham V905A Hydronic BCJR30A-12 080147147 668 0.67
1114 9/4/2003 Burnham V904A Hydronic BCJR30A-10 080146952 606 0.61
M108 8/7/2003 Burnham V1112 Hydronic BCCR3-G-20 120206855 2,887 2.89
M108 8/7/2003 Burnham V1112 Hydronic BCCR3-G-20 120206856 2,887 2.89
M124 7/15/2003 Burnham V1115 Hydronic BCCR3-G-20 120206852 3,680 3.68
M124 7/15/2003 Burnham V1115 Hydronic BCCR3-G-20 120206853 3,680 3.68
M143 7/18/2003 Burnham V1113 Hydronic BCCR3-G-20 120206857 3,103 3.10
M143 7/18/2003 Burnham V1113 Hydronic BCCR3-G-20 120206858 3,103 3.10
47433 ? NA NA Infared CRV B-10 NA 100 0.10
47433 ? NA NA Infared CRV B-10 NA 100 0.10
47433 ? NA NA Infared CRV B-10 NA 100 0.10
47433 ? NA NA Infared CRV B-10 NA 100 0.10
1 9/7/2003 Burnham V1112 Steam BCCR3-G-25B 010307155 2,887 2.89
1 9/1/2003 Burnham V1112 Steam BCCR3-G-20 0101307156 2,887 2.89
2 8/14/2003 Burnham V1113 Steam BCCR3-G-20 090100881 3,103 3.10
3 9/6/2003 Burnham V1106 Steam BCJR50A-15 080147156 1,328 1.33
5 8/12/2003 Burnham V1107 Steam BCJR50A-15 080147069 1,586 1.59
5 8/12/2003 Burnham V1107 Steam BCJR50A-15 080147067 1,586 1.59
6 6/19/2003 Burnham V1104 Steam BCJR30A-10 080147102 836 0.84
9 8/12/2003 Burnham V1110 Steam BCCR2-G-20A 080100635 2,396 2.40
9 8/12/2003 Burnham V1110 Steam BCCR2-G-20A 080100636 2,396 2.40
56 9/12/2003 Burnham V1112 Steam BCCR3-G-20 090101367 2,887 2.89
297 7/21/2003 Burnham V909A Steam BCJR50A-15 020354252 1,357 1.36
337 8/5/2003 Burnham V911A Steam BCC2G-20B 020307764 1,323 1.32
337 8/5/2003 Burnham V911A Steam BCC2G-20B 020307763 1,323 1.32
600 7/14/2003 Burnham V1116 Steam BCCR3-G-25 100100916 3,897 3.90
600 7/14/2003 Burnham V1116 Steam BCCR3-G-25 100100913 3,897 3.90
600 7/14/2003 Burnham V1116 Steam BCCR3-G-25 100100912 3,897 3.90
602 9/10/2003 Burnham V1118 Steam BCCR3-G-25B 100100899 4,470 4.47
602 9/10/2003 Burnham V1118 Steam BCCR3-G-25B 100100907 4,470 4.47
602 9/10/2003 Burnham V1118 Steam BCCR3-G-25B 100100906 4,470 4.47
606 9/10/2003 Burnham V904A Steam BCJR30A-10 080146948 606 0.61
620 6/30/2003 Burnham V1115 Steam BCCR3-G-20 090100890 3,680 3.68
620 6/30/2003 Burnham V1115 Steam BCCR3-G-20 090100892 3,680 3.68
622 7/2/2003 Burnham V1115 Steam BCCR3-G-20 090100896 3,680 3.68
622 7/7/2003 Burnham V1115 Steam BCCR3-G-20 090100895 3,680 3.68
624 7/7/2003 Burnham V1115 Steam BCCR3-G-20 120206900 3,680 3.68
624 7/7/2003 Burnham V1115 Steam BCCR3-G-20 120206893 3,680 3.68
626 7/8/2003 Burnham V1115 Steam BCCR3-G-20 120206897 3,680 3.68
626 7/8/2003 Burnham V1115 Steam BCCR3-G-20 120206894 3,680 3.68
628 9/3/2003 Burnham V1115 Steam BCCR3-G-20 120206892 3,680 3.68
628 9/3/2003 Burnham V1115 Steam BCCR3-G-20 120206890 3,680 3.68
LFG to Energy Misc Boilers Burners 5
BLDG Boiler
Start Date Boiler MFG Model Heat Type Burner Model
Burner
Make
MBH Max
Input
MMBtu Max
Input
630 9/3/2003 Burnham V1115 Steam BCCR3-G-20 120206896 3,680 3.68
630 9/3/2003 Burnham V1115 Steam BCCR3-G-20 120206901 3,680 3.68
632 9/4/2003 Burnham V1115 Steam BCCR3-G-20 090100891 3,680 3.68
632 9/4/2003 Burnham V1115 Steam BCCR3-G-20 090100894 3,680 3.68
634 6/11/2003 Burnham V904A Steam BCJR30A-10 080147070 606 0.61
652 7/31/2003 Burnham V1104 Steam BCJR30A-10 080147101 836 0.84
654 6/17/2003 Burnham V1107 Steam BCJR50A-15 080147068 1,586 1.59
655 6/16/2003 Burnham V1114 Steam BCCR3-G-20 090100874 3,392 3.39
658 7/31/2003 Burnham V1115 Steam BCCR3-G-20 090100893 3,680 3.68
658 7/31/2003 Burnham V1115 Steam BCCR3-G-20 090100889 3,680 3.68
662 6/12/2003 Burnham V1115 Steam BCCR3-G-20 120206888 3,680 3.68
662 6/12/2003 Burnham V1115 Steam BCCR3-G-20 120206895 3,680 3.68
664 6/13/2003 Burnham V1115 Steam BCCR3-G-20 120206898 3,680 3.68
664 6/13/2003 Burnham V1115 Steam BCCR3-G-20 120206887 3,680 3.68
667 7/28/2003 Burnham V1115 Steam BCCR3-G-20 120206891 3,680 3.68
667 7/28/2003 Burnham V1115 Steam BCCR3-G-20 120206889 3,680 3.68
668 7/28/2003 Burnham V1115 Steam BCCR3-G-20 090100898 3,680 3.68
668 7/28/2003 Burnham V1115 Steam BCCR3-G-20 090100897 3,680 3.68
670 8/14/2003 Burnham V1115 Steam BCCR3-G-20 120206899 3,680 3.68
670 8/14/2003 Burnham V1115 Steam BCCR3-G-20 120206886 3,680 3.68
690 7/9/2003 Burnham V1121 Steam BCCR3-G-25B 100100910 5,268 5.27
690 7/9/2003 Burnham V1121 Steam BCCR3-G-25B 100100911 5,268 5.27
700 6/9/2003 Burnham V1118 Steam BCCR3-G-25B 100100908 4,470 4.47
704 7/9/2003 Burnham V1106 Steam BCJR50A-15 080147157 1,328 1.33
710 7/15/2003 Burnham IN10 Steam KIN10LNI-LL2 64360390 315 0.32
724 6/11/2003 Burnham V1113 Steam BCCR3-G-20 090100880 3,103 3.10
724 6/11/2003 Burnham V1113 Steam BCCR3-G-20 090100875 3,103 3.10
733 4/27/2003 Burnham V1106 Steam BCJR50A-15 080147160 1,328 1.33
740 9/30/2003 Burnham V1113 Steam BCCR3-G-20 090100879 3,103 3.10
750 4/7/2003 Burnham V1113 Steam BCCR3-G-20 090100877 3,103 3.10
754 4/30/2003 Burnham V1106 Steam BCJR50A-15 080147159 1,328 1.33
755 7/3/2003 Burnham V1104 Steam BCJR30A-10 080147103 836 0.84
756 4/25/2003 Burnham V1113 Steam BCCR3-G-20 090100876 3,103 3.10
772 5/19/2003 Burnham V1106 Steam BCJR50A-15 120253416 1,328 1.33
778 4/29/2003 Burnham V1113 Steam BCCR3-G-20 090100878 3,103 3.10
784 4/28/2003 Burnham V1113 Steam BCCR3-G-20 090100883 3,103 3.10
789 5/1/2003 Burnham V1106 Steam BCJR50A-15 080147158 1,328 1.33
796 7/31/2003 Burnham V1112 Steam BCCR3-G-20 090101368 2,887 2.89
796 7/31/2003 Burnham V1112 Steam BCCR3-G-20 090101370 2,887 2.89
798 5/7/2003 Burnham V1115 Steam BCCR3-G-20 090100888 3,680 3.68
800 8/20/2003 Burnham V1116 Steam BCCR3-G-25 100100915 3,897 3.90
800 8/20/2003 Burnham V1116 Steam BCCR3-G-25 100100914 3,897 3.90
802 5/20/2003 Burnham V1118 Steam BCCR3-G-25B 100100902 4,470 4.47
802 5/20/2003 Burnham V1118 Steam BCCR3-G-25B 100100900 4,470 4.47
804 8/20/2003 Burnham V1118 Steam BCCR3-G-25B 100100905 4,470 4.47
804 8/20/2003 Burnham V1118 Steam BCCR3-G-25B 100100904 4,470 4.47
806 8/25/2003 Burnham V1118 Steam BCCR3-G-25B 100100901 4,470 4.47
806 8/25/2003 Burnham V1118 Steam BCCR3-G-25B 100100909 4,470 4.47
812 5/19/2003 Burnham V1106 Steam BCJR50A-15 080147155 1,328 1.33
974 8/26/2003 Burnham V1118 Steam BCCR3-G-25B 100100903 4,470 4.47
975 5/12/2003 Burnham V1113 Steam BCCR3-G-20 090100882 3,103 3.10
LFG to Energy Misc Boilers Burners 6
BLDG Boiler
Start Date Boiler MFG Model Heat Type Burner Model
Burner
Make
MBH Max
Input
MMBtu Max
Input
984 5/7/2003 Burnham V1104 Steam BCJR30A-12 080147146 1,068 1.07
986 5/8/2003 Burnham V905A Steam BCJR30A-12 080147148 668 0.67
1101 7/16/2003 Burnham V904A Steam BCJR30A-10 080146957 606 0.61
1102 9/11/2003 Burnham V904A Steam BCJR30A-10 090147116 606 0.61
1106 9/9/2003 Burnham V904A Steam BCJR30A-10 080146950 606 0.61
1108 9/11/2003 Burnham V904A Steam BCJR30A-10 090147135 606 0.61
1113 9/12/2003 Burnham V904A Steam BCJR30A-10 080146955 606 0.61
47430 5/20/2003 Burnham V1111 Steam BCCR3-G-20 9100893 2,656 2.66
47431 6/9/2003 Burnham V1107 Steam BCJR50A-15 N/A 1,586 1.59
47436 5/21/2003 Burnham V904A Steam BCJR30A-10 080146951 606 0.61
380,961 380.96
MBH MMBtu/hr
BLDG Boiler
Start Date Boiler MFG Model Heat Type Burner Model
Burner
Make
MBH Max
Input
MMBtu Max
Input
36012 1952
Eric City Water
Tube Boilers NA Gas NA NA 187
36012 1952
Eric City Water
Tube Boilers NA Gas NA NA 187
36012 1952
Eric City Water
Tube Boilers NA Gas NA NA 187
36012 1952
Eric City Water
Tube Boilers NA Gas NA NA 187
748.00
MMBtu/hr
LFG to Energy Misc Boilers Burners 7
BLDG
Hot Water
Heater
Start Date
Hot Water
Heater MFG Model Heat Type
Burner
Model Burner Make
MBH
Max
Input
MMBtu
Max
Input
T2 7/9/2003 NA NA Air 43536 200211-AKGH43018 351 0.35
53 9/3/2003 Bock 241PGES Gas NA NA 200 0.20
53 9/3/2003 Bock 241PGES Gas NA NA 200 0.20
54 9/3/2003 Lochinvar RWN199PM Gas RJS080 XJ0067118 200 0.20
54 9/3/2003 Lochinvar RWN199PM Gas RJS080 XJ0117314 200 0.20
55 7/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0117328 200 0.20
55 7/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0117324 200 0.20
57 7/23/2003 Bock 241PGES Gas NA NA 200 0.20
57 7/23/2003 Bock 241PGES Gas NA NA 200 0.20
58 7/23/2003 Lochinvar RWN199PM Gas RJS080 XJ0117327 200 0.20
58 7/23/2003 Lochinvar RWN199PM Gas RJS080 XJ0117305 200 0.20
201 5/7/2003 Lochinvar RWN199PM Gas RJS080 XJ0117330 200 0.20
202 5/7/2003 Lochinvar RWN199PM Gas RJS080 XJ0117331 200 0.20
203 5/1/2003 Lochinvar RWN199PM Gas RJS080 XJ0067085 200 0.20
204 5/5/2003 Lochinvar RWN199PM Gas RJS080 XJ0067105 200 0.20
206 5/5/2003 Lochinvar RWN199PM Gas RJS080 XJ0067082 200 0.20
207 5/5/2003 Lochinvar RWN199PM Gas RJS080 XJ0117338 200 0.20
208 5/6/2003 Lochinvar RWN199PM Gas RJS080 XJ0067104 200 0.20
209 5/6/2003 Lochinvar RWN199PM Gas RJS080 XJ0067083 200 0.20
210 5/5/2003 Lochinvar RWN199PM Gas RJS080 XJ0067099 200 0.20
221 9/3/2003 Lochinvar RWN199PM Gas RJS080 XJ0067107 200 0.20
222 5/12/2003 Lochinvar RWN199PM Gas RJS080 XJ0067116 200 0.20
223 5/8/2003 Lochinvar RWN199PM Gas RJS080 XJ0067114 200 0.20
224 5/12/2003 Lochinvar RWN199PM Gas RJS080 XJ0067111 200 0.20
225 5/8/2003 Lochinvar RWN199PM Gas RJS080 XJ0067108 200 0.20
227 5/8/2003 Lochinvar RWN199PM Gas RJS080 XJ0067109 200 0.20
228 5/8/2003 Lochinvar RWN199PM Gas RJS080 XJ0067110 200 0.20
230 5/6/2003 Lochinvar RWN199PM Gas RJS080 XJ0067117 200 0.20
231 5/6/2003 Lochinvar RWN199PM Gas RJS080 XJ0067115 200 0.20
241 5/12/2003 Lochinvar RWN199PM Gas RJS080 XJ0067074 200 0.20
243 11/22/2003 Lochinvar RWN199PM Gas RJS080 XJ0067095 200 0.20
244 5/13/2003 Lochinvar RWN199PM Gas RJS080 XJ0067103 200 0.20
245 5/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0067098 200 0.20
247 5/14/2003 Lochinvar RWN199PM Gas RJS080 XJ0067080 200 0.20
249 5/14/2003 Lochinvar RWN199PM Gas RJS080 XJ0067081 200 0.20
250 5/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0067079 200 0.20
252 5/12/2003 Lochinvar RWN199PM Gas RJS080 XJ0067075 200 0.20
261 5/19/2003 Lochinvar RWN199PM Gas RJS080 XJ0117372 200 0.20
262 5/19/2003 Lochinvar RWN199PM Gas RJS080 XJ0067087 200 0.20
264 5/15/2003 Lochinvar RWN199PM Gas RJS080 XJ0067078 200 0.20
265 5/14/2003 Lochinvar RWN199PM Gas RJS080 XJ0067096 200 0.20
266 5/15/2003 Lochinvar RWN199PM Gas RJS080 XJ0067106 200 0.20
268 5/15/2003 Lochinvar RWN199PM Gas RJS080 XJ0067113 200 0.20
269 5/15/2003 Lochinvar RWN199PM Gas RJS080 XJ0067076 200 0.20
270 5/14/2003 Lochinvar RWN199PM Gas RJS080 XJ0067097 200 0.20
272 5/19/2003 Lochinvar RWN199PM Gas RJS080 XJ0067089 200 0.20
273 5/19/2003 Lochinvar RWN199PM Gas RJS080 XJ0117375 200 0.20
281 5/20/2003 Lochinvar RWN199PM Gas RJS080 XJ0117371 200 0.20
282 5/21/2003 Lochinvar RWN199PM Gas RJS080 XJ0117381 200 0.20
284 5/21/2003 Lochinvar RWN199PM Gas RJS080 XJ0067088 200 0.20
LFG to Energy Hot H20 Heaters 1
BLDG
Hot Water
Heater
Start Date
Hot Water
Heater MFG Model Heat Type
Burner
Model Burner Make
MBH
Max
Input
MMBtu
Max
Input
285 5/20/2003 Lochinvar RWN199PM Gas RJS080 XJ0067086 200 0.20
287 7/31/2003 Lochinvar RWN199PM Gas RJS080 XJ0067062 200 0.20
288 5/22/2003 Lochinvar RWN199PM Gas RJS080 XJ0067093 200 0.20
289 7/31/2003 Lochinvar RWN199PM Gas RJS080 XJ0067064 200 0.20
290 5/22/2003 Lochinvar RWN199PM Gas RJS080 XJ0067119 200 0.20
291 7/31/2003 Lochinvar RWN199PM Gas RJS080 XJ0067091 200 0.20
292 5/20/2003 Lochinvar RWN199PM Gas RJS080 XJ0067070 200 0.20
300 5/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0067066 200 0.20
301 5/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067067 200 0.20
302 5/30/2003 Lochinvar RWN199PM Gas RJS080 XJ0067068 200 0.20
303 5/21/2003 Lochinvar RWN199PM Gas RJS080 XJ0067092 200 0.20
304 5/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067090 200 0.20
305 5/20/2003 Lochinvar RWN199PM Gas RJS080 XJ0067060 200 0.20
306 5/27/2003 Lochinvar RWN199PM Gas RJS080 XJ0067063 200 0.20
310 5/27/2003 Lochinvar RWN199PM Gas RJS080 XJ0067069 200 0.20
311 5/22/2003 Lochinvar RWN199PM Gas RJS080 XJ0067073 200 0.20
312 5/22/2003 Lochinvar RWN199PM Gas RJS080 XJ0067077 200 0.20
313 5/21/2003 Lochinvar RWN199PM Gas RJS080 XJ0067065 200 0.20
314 5/30/2003 Lochinvar RWN199PM Gas RJS080 XJ0067072 200 0.20
315 5/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067061 200 0.20
320 6/4/2003 Lochinvar RWN199PM Gas RJS080 XJ0117307 200 0.20
321 6/4/2003 Lochinvar RWN199PM Gas RJS080 XJ0067071 200 0.20
322 6/9/2003 Lochinvar RWN199PM Gas RJS080 XJ0117306 200 0.20
323 6/3/2003 Lochinvar RWN199PM Gas RJS080 XJ0117303 200 0.20
324 6/5/2003 Lochinvar RWN199PM Gas RJS080 XJ0117298 200 0.20
325 6/5/2003 Lochinvar RWN199PM Gas RJS080 XJ0067059 200 0.20
326 6/6/2003 Lochinvar RWN199PM Gas RJS080 XJ0117302 200 0.20
331 6/5/2003 Lochinvar RWN199PM Gas RJS080 ZB2755937 200 0.20
332 6/3/2003 Lochinvar RWN199PM Gas RJS080 XJ0117296 200 0.20
333 5/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0117301 200 0.20
334 6/6/2003 Lochinvar RWN199PM Gas RJS080 XJ0117300 200 0.20
335 6/6/2003 Lochinvar RWN199PM Gas RJS080 XJ0067057 200 0.20
340 8/4/2003 Lochinvar RWN199PM Gas RJS080 XJ0117337 200 0.20
341 8/5/2003 Lochinvar RWN199PM Gas RJS080 XJ0117344 200 0.20
342 6/9/2003 Lochinvar RWN199PM Gas RJS080 XJ0067034 200 0.20
343 6/9/2003 Lochinvar RWN199PM Gas RJS080 XJ0117356 200 0.20
344 6/10/2003 Lochinvar RWN199PM Gas RJS080 XJ0117322 200 0.20
346 6/10/2003 Lochinvar RWN199PM Gas RJS080 XJ0117310 200 0.20
348 8/4/2003 Lochinvar RWN199PM Gas RJS080 XJ0117317 200 0.20
349 6/10/2003 Lochinvar RWN199PM Gas RJS080 XJ0117311 200 0.20
350 6/11/2003 Lochinvar RWN199PM Gas RJS080 XJ0117336 200 0.20
351 8/5/2003 Lochinvar RWN199PM Gas RJS080 XJ0117297 200 0.20
352 8/4/2003 Lochinvar RWN199PM Gas RJS080 XJ0117299 200 0.20
353 6/17/2003 Lochinvar RWN199PM Gas RJS080 XJ0117329 200 0.20
355 6/11/2003 Lochinvar RWN199PM Gas RJS080 XJ0117318 200 0.20
356 6/11/2003 Lochinvar RWN199PM Gas RJS080 XJ0117312 200 0.20
358 6/12/2003 Lochinvar RWN199PM Gas RJS080 XJ0117309 200 0.20
360 8/4/2003 Lochinvar RWN199PM Gas RJS080 XJ0117304 200 0.20
361 6/13/2003 Lochinvar RWN199PM Gas RJS080 XJ0117333 200 0.20
362 6/13/2003 Lochinvar RWN199PM Gas RJS080 XJ0117335 200 0.20
LFG to Energy Hot H20 Heaters 2
BLDG
Hot Water
Heater
Start Date
Hot Water
Heater MFG Model Heat Type
Burner
Model Burner Make
MBH
Max
Input
MMBtu
Max
Input
363 6/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0117346 200 0.20
364 6/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0117334 200 0.20
366 6/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0117308 200 0.20
367 6/18/2003 Lochinvar RWN199PM Gas RJS080 XJ0117319 200 0.20
369 6/20/2003 Lochinvar RWN199PM Gas RJS080 XJ0117316 200 0.20
371 6/26/2003 Lochinvar RWN199PM Gas RJS080 XJ0117320 200 0.20
372 6/17/2003 Lochinvar RWN199PM Gas RJS080 XJ0117321 200 0.20
373 6/20/2003 Lochinvar RWN199PM Gas RJS080 XJ0117357 200 0.20
380 6/20/2003 Lochinvar RWN199PM Gas RJS080 XJ0117354 200 0.20
381 6/19/2003 Lochinvar RWN199PM Gas RJS080 XJ0117112 200 0.20
382 7/31/2003 Lochinvar RWN199PM Gas RJS080 XJ0067038 200 0.20
383 7/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067124 200 0.20
384 7/23/2003 Lochinvar RWN199PM Gas RJS080 XJ0117313 200 0.20
385 7/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0117315 200 0.20
386 7/18/2003 Lochinvar RWN199PM Gas RJS080 ZB2755940 200 0.20
387 7/17/2003 Lochinvar RWN199PM Gas RJS080 ZB2755941 200 0.20
388 7/16/2003 Lochinvar RWN199PM Gas RJS080 ZB2755934 200 0.20
389 7/14/2003 Lochinvar RWN199PM Gas RJS080 ZB2755936 200 0.20
390 7/7/2003 Lochinvar RWN199PM Gas RJS080 ZA2585388 200 0.20
391 7/8/2003 Lochinvar RWN199PM Gas RJS080 ZB2755944 200 0.20
392 8/4/2003 Lochinvar RWN199PM Gas RJS080 XJ0117339 200 0.20
393 7/2/2003 Lochinvar RWN199PM Gas RJS080 ZB2755935 200 0.20
394 7/3/2003 Lochinvar RWN199PM Gas RJS080 ZB2755942 200 0.20
403 4/21/2003 Lochinvar RWN199PM Gas RJS080 XJ0117373 200 0.20
404 4/21/2003 Lochinvar RWN199PM Gas RJS080 XJ0117380 200 0.20
405 4/21/2003 Lochinvar RWN199PM Gas RJS080 XJ0117374 200 0.20
406 4/22/2003 Lochinvar RWN199PM Gas RJS080 XJ0117376 200 0.20
408 4/22/2003 Lochinvar RWN199PM Gas RJS080 XJ0067029 200 0.20
409 4/22/2003 Lochinvar RWN199PM Gas RJS080 XJ0117377 200 0.20
410 4/24/2003 Lochinvar RWN199PM Gas RJS080 XJ0117366 200 0.20
411 4/24/2003 Lochinvar RWN199PM Gas RJS080 XJ0117362 200 0.20
413 4/23/2003 Lochinvar RWN199PM Gas RJS080 XJ0117385 200 0.20
414 4/23/2003 Lochinvar RWN199PM Gas RJS080 XJ0117367 200 0.20
415 4/24/2003 Lochinvar RWN199PM Gas RJS080 XJ0117389 200 0.20
416 4/23/2003 Lochinvar RWN199PM Gas RJS080 XJ0067084 200 0.20
417 4/23/2003 Lochinvar RWN199PM Gas RJS080 XJ0117384 200 0.20
418 4/22/2003 Lochinvar RWN199PM Gas RJS080 XJ0117370 200 0.20
421 4/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0117378 200 0.20
422 4/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0067031 200 0.20
423 4/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067047 200 0.20
424 4/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0117394 200 0.20
425 4/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067048 200 0.20
426 4/29/2003 Lochinvar RWN199PM Gas RJS080 XJ00670451 200 0.20
427 4/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0117369 200 0.20
428 4/25/2003 Lochinvar RWN199PM Gas RJS080 XJ0067053 200 0.20
429 4/25/2003 Lochinvar RWN199PM Gas RJS080 XJ0117364 200 0.20
430 4/25/2003 Lochinvar RWN199PM Gas RJS080 XJ0117361 200 0.20
431 4/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0117388 200 0.20
432 4/25/2003 Lochinvar RWN199PM Gas RJS080 XJ0117393 200 0.20
433 7/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0117363 200 0.20
LFG to Energy Hot H20 Heaters 3
BLDG
Hot Water
Heater
Start Date
Hot Water
Heater MFG Model Heat Type
Burner
Model Burner Make
MBH
Max
Input
MMBtu
Max
Input
434 7/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0117368 200 0.20
435 7/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067056 200 0.20
436 4/30/2003 Lochinvar RWN199PM Gas RJS080 XJ0067058 200 0.20
437 7/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067055 200 0.20
438 7/30/2003 Lochinvar RWN199PM Gas RJS080 XJ0067052 200 0.20
439 4/30/2003 Lochinvar RWN199PM Gas RJS080 XJ0117395 200 0.20
440 7/30/2003 Lochinvar RWN199PM Gas RJS080 XJ0067049 200 0.20
441 7/30/2003 Lochinvar RWN199PM Gas RJS080 XJ0067054 200 0.20
442 7/31/2003 Lochinvar RWN199PM Gas RJS080 XJ0117379 200 0.20
443 7/31/2003 Lochinvar RWN199PM Gas RJS080 XJ0117360 200 0.20
455 4/30/2003 Lochinvar RWN199PM Gas RJS080 XJ0067046 200 0.20
456 4/30/2003 Lochinvar RWN199PM Gas RJS080 XJ0117383 200 0.20
457 5/1/2003 Lochinvar RWN199PM Gas RJS080 XJ0117382 200 0.20
458 5/1/2003 Lochinvar RWN199PM Gas RJS080 XJ0117392 200 0.20
501 4/14/2003 Lochinvar RWN199PM Gas RJS080 XJ0117387 200 0.20
503 4/14/2003 Lochinvar RWN199PM Gas RJS080 XJ0067050 200 0.20
504 4/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0117386 200 0.20
505 4/15/2003 Lochinvar RWN199PM Gas RJS080 XJ0067045 200 0.20
506 4/15/2003 Lochinvar RWN199PM Gas RJS080 XJ0067039 200 0.20
508 4/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0117390 200 0.20
509 4/15/2003 Lochinvar RWN199PM Gas RJS080 XJ0067041 200 0.20
510 4/17/2003 Lochinvar RWN199PM Gas RJS080 XJ0117391 200 0.20
511 4/17/2003 Lochinvar RWN199PM Gas RJS080 XJ0067102 200 0.20
514 4/18/2003 Lochinvar RWN199PM Gas RJS080 XJ0067032 200 0.20
515 4/17/2003 Lochinvar RWN199PM Gas RJS080 XJ0067100 200 0.20
516 4/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0067033 200 0.20
517 4/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0067037 200 0.20
520 4/21/2003 Lochinvar RWN199PM Gas RJS080 XJ0117359 200 0.20
521 7/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0117358 200 0.20
522 7/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0067042 200 0.20
523 7/28/2003 Lochinvar RWN199PM Gas RJS080 XJ0067101 200 0.20
524 6/23/2003 Lochinvar RWN199PM Gas RJS080 XJ0067094 200 0.20
529 5/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067123 200 0.20
530 5/29/2003 Lochinvar RWN199PM Gas RJS080 XJ0067120 200 0.20
531 6/4/2003 Lochinvar RWN199PM Gas RJS080 ZB2755938 200 0.20
533 6/4/2003 Lochinvar RWN199PM Gas RJS080 ZB2755933 200 0.20
537 4/18/2003 Lochinvar RWN199PM Gas RJS080 XJ0067028 200 0.20
538 4/18/2003 Lochinvar RWN199PM Gas RJS080 XJ0117365 200 0.20
706 Unknown Not Avail Not Avail Gas Not Avail Not Avail 140 0.14
721 Unknown Not Avail Not Avail Gas Not Avail Not Avail 100 0.10
721 Unknown Not Avail Not Avail Gas Not Avail Not Avail 300 0.30
722 Unknown Not Avail Not Avail Gas Not Avail Not Avail 100 0.10
723 Unknown Not Avail Not Avail Gas Not Avail Not Avail 120 0.12
732 Unknown Not Avail Not Avail Gas Not Avail Not Avail 930 0.93
755 Unknown Not Avail Not Avail Gas Not Avail Not Avail 600 0.60
809 Unknown Not Avail Not Avail Gas Not Avail Not Avail 150 0.15
809 Unknown Not Avail Not Avail Gas Not Avail Not Avail 150 0.15
809 Unknown Not Avail Not Avail Gas Not Avail Not Avail 150 0.15
809 Unknown Not Avail Not Avail Gas Not Avail Not Avail 150 0.15
974 Unknown Not Avail Not Avail Gas Not Avail Not Avail 4320 4.32
LFG to Energy Hot H20 Heaters 4
BLDG
Hot Water
Heater
Start Date
Hot Water
Heater MFG Model Heat Type
Burner
Model Burner Make
MBH
Max
Input
MMBtu
Max
Input
974 Unknown Not Avail Not Avail Gas Not Avail Not Avail 4320 4.32
992 Unknown Not Avail Not Avail Gas Not Avail Not Avail 300 0.30
1101 7/16/2003 Lochinvar RWN199PM Gas RJS080 XJ0117326 200 0.20
1101 7/16/2003 Lochinvar RWN199PM Gas RJS081 XJ0067036 200 0.20
1102 9/11/2003 Lochinvar RWN199PM Gas RJS080 XJ0117323 200 0.20
1102 9/11/2003 Lochinvar RWN199PM Gas RJS080 XJ0067044 200 0.20
1104 Unknown Not Avail Not Avail Gas Not Avail Not Avail 300 0.30
1106 9/9/2003 Lochinvar RWN199PM Gas RJS080 XJ0117332 200 0.20
1106 9/9/2003 Lochinvar RWN199PM Gas RJS080 XJ0117325 200 0.20
1107 9/4/2003 Bock 241PGES Gas NA NA 200 0.20
1107 9/4/2003 Bock 241PGES Gas NA NA 200 0.20
1108 9/11/2003 Lochinvar RWN199PM Gas RJS080 XJ0117345 200 0.20
1108 9/11/2003 Lochinvar RWN199PM Gas RJS080 XJ0117352 200 0.20
1113 9/12/2003 Lochinvar RWN199PM Gas RJS080 XJ0067026 200 0.20
1113 9/12/2003 Lochinvar RWN199PM Gas RJS080 XJ0067026 200 0.20
1114 9/4/2003 Bock 241PGES Gas NA NA 200 0.20
1114 9/4/2003 Bock 241PGES Gas NA NA 200 0.20
52,681 53
MBH MMBtu/hr
LFG to Energy Hot H20 Heaters 5
APPENDIX 13
FINANCIAL PRO FORMA FOR OPTION 5
(FT. RICHARDSON)
Assumptions
MG Price $2.721
MG Price Escalation 2.0%
Capital Cost 3,256,063$
Loan Amount $0
Gas Cost $0.0000
Gas Cost Escalation 2.0%
Gas Quantity 826 SCFM
Financing
Principal No Debt
Term n/a
Interest Rate n/a
Financial Returns 10 Years
Total Cash Flow from Operations 3,927,864$
Investment 3,256,063$
Net Cash Flow 671,801$
Project IRR 3.0%
NPV at rate = 2.000% 200,794$
NPV at rate = 2.500% 97,378$
NPV at rate = 2.750% 47,612$
NPV at rate = 3.000% (906)$
Pre Tax Profits 1,041,000$
Average % 10.1%
Minimum % -19.2%
Net Income 671,801$
Average % 4.9%
Minimum % -29.6%
MUSA Contributions (Municipal Utility Service Assessment)
Rate 10 Year Totals
Rate on Net Book Value of Assets - in mils 16 270,934$
Gross Revenue contribution % of Revenue 1.25% 98,265$
369,199$
Depreciation per GASB 34 Method Life in Years
Vehicles St. Line 5
Support Equipment St. Line 4
Machinery & Equipment St. Line 7
GCCS & Pipeline St. Line 10
Summary of Assumptions & Financials
Anchorage Medium BTU Gas Project
Gas Sales to Ft. Richardson Building #726
Assumes Ft. Richardson will use all gas available
Project Proforma
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage FtRichardson Pipeline apdx13.xls]Dep
5/18/2004 2:01 PM Anchorage FtRichardson Pipeline apdx13
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage FtRichardson Pipeline apdx13.xls]Dep
Description Value Unit
Financial Information
Project Capital Costs $3,256,063
Equity Contribution 100.00% $3,256,063
Loan 0.00%
Principal $0
Term 10 years
Interest Rate 0.0%
Interest Payments monthly during construction
Loan Fees 0.0%
MG Quantity 826 SCFM 208,631 mmBTU/Yr
50.00% Methane %
On-Stream Factors
Utilization %95.0%
MG Price $2.721
MG Price escalator 2.0%
Cost of Sales
Cost of Methane Gas $0.0000 per mmBTU
Cost Escalator 2.0%
Electric Cost - Blower and Compressor @ .09 cents / kwh $60,000 Annually
Electric Escalator 2.0%
Operating Costs Annually
O&M Compressor/Pipeline per year 200,000$
O&M Escalator 3.0%
Property Insurance 1.00% % of Value
General Liability Insurance 1.00% % of Revenue
Administration $25,000
Income Taxes Is project subject to income taxes NO
Federal Tax Rate 0%
State Tax Rate 0.0% Incl. In Federal
Questions 1 When do we anticipate project completion / start-up?2006
2 Verity Gas curve to use and recovery rate Avg LFG at 75%
3 Does gas curve assume 50 or 50+23 acres 73 acres
4 Does the $15,000 include flare, blower and electrical Includes all components of GCCS
5 Tony had an estimate of $75/ft for pipeline. What does this include?As per Jim use Kevin's $60
6 No Federal Tax
Gas Sales to Ft. Richardson Building #726
Anchorage Medium BTU Gas Project
ASSUMPTIONS to PRO FORMA
5/18/2004 2:02 PM Anchorage FtRichardson Pipeline apdx13
Gas Sales to Ft. Richardson Building #726 Annual ProformaMethane Gas Price (MG) = 2.72$ Escalation Year012345678910 YearAssumptionsCalendarYear 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TotalGas Curve LFG Generation - Avg 1,101 1,170 1,237 1,302 1,364 1,423 1,479 1,533 1,584 1,632 Lfg Recoverable Rate 75.0% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%Landfill Gas Available 826 878 928 977 1,023 1,067 1,109 1,150 1,188 1,224 Average MMBTU @ 50% Methane & 95% Utilization 208,631 221,706 234,402 246,719 258,467 269,647 280,259 290,491 300,155 309,251 School Gas DemandAverage SCFM - - - - - - - - - - 0Average MMBTU @ 50% Methane & 95% Utilization - - - - - - - - - - - EscalatorAssumed Methane Gas Price 2% 2.72$ 2.78$ 2.83$ 2.89$ 2.95$ 3.00$ 3.06$ 3.13$ 3.19$ 3.25$ IncomeEscalatorMG Sales - Landfill Gas Production 2.0% $567,685 $616,343 $663,358 $713,018 $762,478 $808,941 $857,593 $909,237 $957,494 $1,005,066 $7,861,211Total Revenues 567,685 616,343 663,358 713,018 762,478 808,941 857,593 909,237 957,494 1,005,066 7,861,211 Costs of SalesPurchased Electricity - Blower/Compressor 2.0% 60,000 61,200 62,424 63,672 64,946 66,245 67,570 68,921 70,300 71,706 656,983 Purchased Methane Gas -$ 2.0% - - - - - - - - - - - Costs of Sales 60,000 61,200 62,424 63,672 64,946 66,245 67,570 68,921 70,300 71,706 656,983 Gross Profit507,685 555,143 600,934 649,345 697,532 742,696 790,023 840,316 887,195 933,360 7,204,228 Expenses - PipelineO&M - Wellfield/Comp/Pipeline - per year 2.0% 200,000 204,000 208,080 212,242 216,486 220,816 225,232 229,737 234,332 239,019 2,189,944 Property Insur. - (% of value) 1.00% 2.0% 32,561 33,212 33,876 34,554 35,245 35,950 36,669 37,402 38,150 38,913 356,530 General Liability Insur. (% of revenue) 1.00% 2.0% 5,677 6,287 6,902 7,567 8,253 8,931 9,658 10,444 11,219 12,011 86,949 Administration 2.0% 25,000 25,500 26,010 26,530 27,061 27,602 28,154 28,717 29,291 29,877 273,743 Personal Property Tax - n/a - assume Pollution Control Exemp.0000000000 - Interest0000000000 - Total Expenses 263,237 268,999 274,868 280,892 287,045 293,299 299,713 306,300 312,992 319,820 2,907,166 Net Operating Profit 244,447 286,144 326,066 368,453 410,487 449,397 490,310 534,015 574,203 613,540 4,297,063 LessDepreciation/Amort Finance Fees (Pipeline Only) 353,463 353,463 353,463 353,463 353,463 353,463 353,463 260,606 260,606 260,606 3,256,063 Net Profit Before Tax (109,016) (67,319) (27,397) 14,990 57,023 95,934 136,846 273,409 313,597 352,934 1,041,000 -19.2% -10.9% -4.1% 2.1% 7.5% 11.9% 16.0% 30.1% 32.8% 35.1% 13.2%MUSA ContributionsMillage Rate on NBV of PPE 1.60% 52,097 46,442 40,786 35,131 29,475 23,820 18,165 12,509 8,339 4,170 270,934 Gross Revenue Rate 1.25% 7,096 7,704 8,292 8,913 9,531 10,112 10,720 11,365 11,969 12,563 98,265 Total Taxes 59,193 54,146 49,078 44,043 39,006 33,932 28,884 23,875 20,308 16,733 369,199 Net Income(168,209) (121,465) (76,476) (29,053) 18,017 62,002 107,962 249,534 293,289 336,201 671,801 -29.6% -19.7% -11.5% -4.1% 2.4% 7.7% 12.6% 27.4% 30.6% 33.5% 8.5%Anchorage Medium BTU Gas Project5/18/2004 2:02 PMAnchorage FtRichardson Pipeline apdx13
Gas Sales to Ft. Richardson Building #726 Annual ProformaMethane Gas Price (MG) = 2.72$ Anchorage Medium BTU Gas ProjectConstructionCash Flow - Total Project2005Capital Expenditures (3,256,063) Loan - Add Depreciation/Amort (Pipeline & Related Costs) 353,463 353,463 353,463 353,463 353,463 353,463 353,463 260,606 260,606 260,606 3,256,063 Less Principal Payment 0000000000 0Net After Tax Cash Flow(3,256,063) 185,254 231,998 276,988 324,410 371,480 415,465 461,425 510,141 553,895 596,807 3,927,864 Cumulative After Tax Cash @ (3,256,063) (3,070,808) (2,838,810) (2,561,822) (2,237,412) (1,865,932) (1,450,467) (989,041) (478,901) 74,994 671,801 Net Present Value (NPV)2.000%$200,794Bank Principal Balance (Yr End) - - - - - - - - 2,012 - 10 YEARInvestment Analysis - Total ProjectConst. Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TOTAL% Ownership 100.00%Capital Expenditures (3,256,063) (3,256,063) Construction Interest- Bond - - Cash Flow 185,254 231,998 276,988 324,410 371,480 415,465 461,425 510,141 553,895 596,807 3,927,864 - After Tax Cash Flow - Year (3,256,063) 185,254 231,998 276,988 324,410 371,480 415,465 461,425 510,141 553,895 596,807 671,801 After Tax Cash Flow - Cum. (3,256,063) (3,070,808) (2,838,810) (2,561,822) (2,237,412) (1,865,932) (1,450,467) (989,041) (478,901) 74,994 671,801 Project IRR - on Cash Investment 3.00%NPV - After tax - Discount @ 2.00% $200,7942.50% $97,3782.75% $47,612Discount = to IRR 3.00%($906)NPV and IRR reconcileReturn on Revenues Average MinimumPre Tax 10.11% -19.20%After Tax 4.92% -29.63%5/18/2004 2:02 PMAnchorage FtRichardson Pipeline apdx13
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage FtRichardson Pipeline apdx13.xls]Dep
Description
Sub-Total Total
Gas Collection System / Compressor Facility
Wellfield based on $12,000 per acre asuming 73 acres $876,000
Compressor $650,000
Contingency $0 Included in above
$1,526,000
Pipeline and Related Costs
Blower Upgrade $0 Included in GCCS
Pipeline 5.1454 miles (27,168 feet) @ $60 per foot $1,630,063
D.O.T. Pipeline Safety Standards Design & Compliance $0 Included in Pipeline estimate
Air Compressor $0 Included in Pipeline estimate
Surveying $0 Included in Pipeline estimate
Geotechnical $0 Included in Pipeline estimate
Planning/Coordination/Legal $0 Included in Pipeline estimate
Construction Interest $0 None assumed
Right of Way Payment $0 None assumed
Wetlands Investigation $0 Included in Pipeline estimate
End User Upgrades $100,000 Allowance
Contingency - 10% $0 Included in above
$1,730,063
Project Total $3,256,063
N:\Document Control\project for jim bier\[Anchorage FtRichardson Pipeline apdx13.xls]Dep
Gas Sales to Ft. Richardson Building #726
Anchorage Medium BTU Gas Project
Capital Estimate Detail
5/18/2004 2:02 PM Anchorage FtRichardson Pipeline apdx13
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage FtRichardson Pipeline apdx13.xls]Dep
Depreciation Amounts Amount
Gas Treatment and Processing System 1,526,000
Pipeline and Related Costs 1,730,063
Construction Interest -
Sub-Total 3,256,063
Year Depreciation
1 2006 $353,463
2 2007 $353,463
3 2008 $353,463
4 2009 $353,463
5 2010 $353,463
6 2011 $353,463
7 2012 $353,463
8 2013 $260,606
9 2014 $260,606
10 2015 $260,606
$3,256,063
Gas Sales to Ft. Richardson Building #726
Anchorage Medium BTU Gas Project
Depreciation & Amortization Schedules
APPENDIX 14
TOPOGRAPHIC MAP FOR OPTION 6
(ML&P GEORGE M. SULLIVAN POWER PLANT)
Copyright (C) 1997, Maptech, Inc.
Anchorage Landfill
George M. Sullivan Power Plant
0123456
350
400
450
500
550
600
Miles
Total distance:6 miles, 3977 feet
Ground distance:6 miles, 3984 feet
Climbing:115 feet
Descending:-247 feet
Elevation change:-132 feet
Min/Max:333/535
Latitude: 000° 00' 00.0'' N
Longitude: 000° 00' 00.0'' E
Elevation:
Grade:
APPENDIX 15
FINANCIAL PRO FORMA FOR OPTION 6
(ML&P GEORGE M. SULLIVAN POWER PLANT)
Assumptions
MG Price $2.858
MG Price Escalation 2.0%
Capital Cost 3,526,800$
Loan Amount $0
Gas Cost $0.0000
Gas Cost Escalation 2.0%
Gas Quantity 826 SCFM
Financing
Principal No Debt
Term n/a
Interest Rate n/a
Financial Returns 10 Years
Total Cash Flow from Operations 4,260,397$
Investment 3,526,800$
Net Cash Flow 733,597$
Project IRR 3.0%
NPV at rate = 2.000% 224,059$
NPV at rate = 2.500% 112,166$
NPV at rate = 2.750% 58,319$
NPV at rate = 3.000% 5,820$
Pre Tax Profits 1,131,562$
Average % 10.6%
Minimum % -18.5%
Net Income 733,597$
Average % 5.3%
Minimum % -29.2%
MUSA Contributions (Municipal Utility Service Assessment)
Rate 10 Year Totals
Rate on Net Book Value of Assets - in mils 16 294,758$
Gross Revenue contribution % of Revenue 1.25% 103,207$
397,965$
Depreciation per GASB 34 Method Life in Years
Vehicles St. Line 5
Support Equipment St. Line 4
Machinery & Equipment St. Line 7
GCCS & Pipeline St. Line 10
Summary of Assumptions & Financials
Anchorage Medium BTU Gas Project
Gas Sales to George M. Sullivan Power Plant
Assumes Power Plant will use all gas available
Project Proforma
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage SullivanPlant Pipeline apdx15.xls]Dep
5/18/2004 2:10 PM Anchorage SullivanPlant Pipeline apdx15
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage SullivanPlant Pipeline apdx15.xls]Dep
Description Value Unit
Financial Information
Project Capital Costs $3,526,800
Equity Contribution 100.00% $3,526,800
Loan 0.00%
Principal $0
Term 10 years
Interest Rate 0.0%
Interest Payments monthly during construction
Loan Fees 0.0%
MG Quantity 826 SCFM 208,631 mmBTU/Yr
50.00% Methane %
On-Stream Factors
Utilization %95.0%
MG Price $2.858
MG Price escalator 2.0%
Cost of Sales
Cost of Methane Gas $0.0000 per mmBTU
Cost Escalator 2.0%
Electric Cost - Blower and Compressor @ .09 cents / kwh $60,000 Annually
Electric Escalator 2.0%
Operating Costs Annually
O&M Compressor/Pipeline per year 200,000$
O&M Escalator 3.0%
Property Insurance 1.00% % of Value
General Liability Insurance 1.00% % of Revenue
Administration $25,000
Income Taxes Is project subject to income taxes NO
Federal Tax Rate 0%
State Tax Rate 0.0% Incl. In Federal
Questions 1 When do we anticipate project completion / start-up?2006
2 Verity Gas curve to use and recovery rate Avg LFG at 75%
3 Does gas curve assume 50 or 50+23 acres 73 acres
4 Does the $15,000 include flare, blower and electrical Includes all components of GCCS
5 Tony had an estimate of $75/ft for pipeline. What does this include?As per Jim use Kevin's $60
6 No Federal Tax
Gas Sales to George M. Sullivan Power Plant
Anchorage Medium BTU Gas Project
ASSUMPTIONS to PRO FORMA
5/18/2004 2:10 PM Anchorage SullivanPlant Pipeline apdx15
Gas Sales to George M. Sullivan Power Plant Annual ProformaMethane Gas Price (MG) = 2.86$ Escalation Year012345678910 YearAssumptionsCalendarYear 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TotalGas Curve LFG Generation - Avg 1,101 1,170 1,237 1,302 1,364 1,423 1,479 1,533 1,584 1,632 Lfg Recoverable Rate 75.0% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%Landfill Gas Available 826 878 928 977 1,023 1,067 1,109 1,150 1,188 1,224 Average MMBTU @ 50% Methane & 95% Utilization 208,631 221,706 234,402 246,719 258,467 269,647 280,259 290,491 300,155 309,251 School Gas DemandAverage SCFM - - - - - - - - - - 0Average MMBTU @ 50% Methane & 95% Utilization - - - - - - - - - - - EscalatorAssumed Methane Gas Price 2% 2.86$ 2.92$ 2.97$ 3.03$ 3.09$ 3.16$ 3.22$ 3.28$ 3.35$ 3.42$ IncomeEscalatorMG Sales - Landfill Gas Production 2.0% $596,267 $647,382 $696,174 $747,559 $798,663 $852,085 $902,434 $952,810 $1,005,519 $1,057,638 $8,256,531Total Revenues 596,267 647,382 696,174 747,559 798,663 852,085 902,434 952,810 1,005,519 1,057,638 8,256,531 Costs of SalesPurchased Electricity - Blower/Compressor 2.0% 60,000 61,200 62,424 63,672 64,946 66,245 67,570 68,921 70,300 71,706 656,983 Purchased Methane Gas -$ 2.0% - - - - - - - - - - - Costs of Sales 60,000 61,200 62,424 63,672 64,946 66,245 67,570 68,921 70,300 71,706 656,983 Gross Profit536,267 586,182 633,750 683,886 733,717 785,840 834,864 883,889 935,220 985,933 7,599,548 Expenses - PipelineO&M - Wellfield/Comp/Pipeline - per year 2.0% 200,000 204,000 208,080 212,242 216,486 220,816 225,232 229,737 234,332 239,019 2,189,944 Property Insur. - (% of value) 1.00% 2.0% 35,268 35,973 36,693 37,427 38,175 38,939 39,717 40,512 41,322 42,149 386,175 General Liability Insur. (% of revenue) 1.00% 2.0% 5,963 6,603 7,243 7,933 8,645 9,408 10,163 10,945 11,781 12,640 91,323 Administration 2.0% 25,000 25,500 26,010 26,530 27,061 27,602 28,154 28,717 29,291 29,877 273,743 Personal Property Tax - n/a - assume Pollution Control Exemp.0000000000 - Interest0000000000 - Total Expenses 266,231 272,077 278,026 284,132 290,367 296,765 303,267 309,911 316,727 323,684 2,941,185 Net Operating Profit 270,037 314,105 355,724 399,754 443,350 489,075 531,597 573,978 618,493 662,249 4,658,362 LessDepreciation/Amort Finance Fees (Pipeline Only) 380,537 380,537 380,537 380,537 380,537 380,537 380,537 287,680 287,680 287,680 3,526,800 Net Profit Before Tax (110,500) (66,432) (24,813) 19,217 62,813 108,538 151,060 286,298 330,813 374,569 1,131,562 -18.5% -10.3% -3.6% 2.6% 7.9% 12.7% 16.7% 30.0% 32.9% 35.4% 13.7%MUSA ContributionsMillage Rate on NBV of PPE 1.60% 56,429 50,340 44,252 38,163 32,074 25,986 19,897 13,809 9,206 4,603 294,758 Gross Revenue Rate 1.25% 7,453 8,092 8,702 9,344 9,983 10,651 11,280 11,910 12,569 13,220 103,207 Total Taxes 63,882 58,432 52,954 47,507 42,058 36,637 31,178 25,719 21,775 17,823 397,965 Net Income(174,383) (124,865) (77,767) (28,290) 20,755 71,901 119,883 260,580 309,038 356,745 733,597 -29.2% -19.3% -11.2% -3.8% 2.6% 8.4% 13.3% 27.3% 30.7% 33.7% 8.9%Anchorage Medium BTU Gas Project5/18/2004 2:11 PMAnchorage SullivanPlant Pipeline apdx15
Gas Sales to George M. Sullivan Power Plant Annual ProformaMethane Gas Price (MG) = 2.86$ Anchorage Medium BTU Gas ProjectConstructionCash Flow - Total Project2005Capital Expenditures (3,526,800) Loan - Add Depreciation/Amort (Pipeline & Related Costs) 380,537 380,537 380,537 380,537 380,537 380,537 380,537 287,680 287,680 287,680 3,526,800 Less Principal Payment 0000000000 0Net After Tax Cash Flow(3,526,800) 206,155 255,672 302,770 352,247 401,292 452,438 500,420 548,260 596,718 644,425 4,260,397 Cumulative After Tax Cash @ (3,526,800) (3,320,645) (3,064,973) (2,762,203) (2,409,956) (2,008,664) (1,556,226) (1,055,806) (507,546) 89,172 733,597 Net Present Value (NPV)2.000%$224,059Bank Principal Balance (Yr End) - - - - - - - - 2,012 - 10 YEARInvestment Analysis - Total ProjectConst. Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TOTAL% Ownership 100.00%Capital Expenditures (3,526,800) (3,526,800) Construction Interest- Bond - - Cash Flow 206,155 255,672 302,770 352,247 401,292 452,438 500,420 548,260 596,718 644,425 4,260,397 - After Tax Cash Flow - Year (3,526,800) 206,155 255,672 302,770 352,247 401,292 452,438 500,420 548,260 596,718 644,425 733,597 After Tax Cash Flow - Cum. (3,526,800) (3,320,645) (3,064,973) (2,762,203) (2,409,956) (2,008,664) (1,556,226) (1,055,806) (507,546) 89,172 733,597 Project IRR - on Cash Investment 3.03%NPV - After tax - Discount @ 2.00% $224,0592.50% $112,1662.75% $58,319Discount = to IRR 3.00% $5,820NPV and IRR reconcileReturn on Revenues Average MinimumPre Tax 10.59% -18.53%After Tax 5.26% -29.25%5/18/2004 2:11 PMAnchorage SullivanPlant Pipeline apdx15
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage SullivanPlant Pipeline apdx15.xls]Dep
Description
Sub-Total Total
Gas Collection System / Compressor Facility
Wellfield based on $12,000 per acre asuming 73 acres $876,000
Compressor $650,000
Contingency $0 Included in above
$1,526,000
Pipeline and Related Costs
Blower Upgrade $0 Included in GCCS
Pipeline 31,680 feet @ $60 per foot $1,900,800
D.O.T. Pipeline Safety Standards Design & Compliance $0 Included in Pipeline estimate
Air Compressor $0 Included in Pipeline estimate
Surveying $0 Included in Pipeline estimate
Geotechnical $0 Included in Pipeline estimate
Planning/Coordination/Legal $0 Included in Pipeline estimate
Construction Interest $0 None assumed
Right of Way Payment $0 None assumed
Wetlands Investigation $0 Included in Pipeline estimate
End User Upgrades $100,000 Allowance
Contingency - 10% $0 Included in above
$2,000,800
Project Total $3,526,800
N:\Document Control\project for jim bier\[Anchorage SullivanPlant Pipeline apdx15.xls]Dep
Gas Sales to George M. Sullivan Power Plant
Anchorage Medium BTU Gas Project
Capital Estimate Detail
5/18/2004 2:11 PM Anchorage SullivanPlant Pipeline apdx15
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage SullivanPlant Pipeline apdx15.xls]Dep
Depreciation Amounts Amount
Gas Treatment and Processing System 1,526,000
Pipeline and Related Costs 2,000,800
Construction Interest -
Sub-Total 3,526,800
Year Depreciation
1 2006 $380,537
2 2007 $380,537
3 2008 $380,537
4 2009 $380,537
5 2010 $380,537
6 2011 $380,537
7 2012 $380,537
8 2013 $287,680
9 2014 $287,680
10 2015 $287,680
$3,526,800
Gas Sales to George M. Sullivan Power Plant
Anchorage Medium BTU Gas Project
Depreciation & Amortization Schedules
APPENDIX 16
TOPOGRAPHIC MAP FOR OPTION 7
(ML&P FOSSIL CREEK)
Copyright (C) 1997, Maptech, Inc.
Fossil Creek Power Plant
Anchorage Landfill
012400
450
500
550
600
650
Miles
Total distance:2 miles, 414 feet
Ground distance:2 miles, 421 feet
Climbing:112 feet
Descending:-187 feet
Elevation change:-75 feet
Min/Max:396/535
Latitude: 000° 00' 00.0'' N
Longitude: 000° 00' 00.0'' E
Elevation:
Grade:
APPENDIX 17
FINANCIAL PRO FORMA FOR OPTION 7
(ML&P FOSSIL CREEK)
Assumptions
MG Price $2.145
MG Price Escalation 2.0%
Capital Cost 2,284,849$
Loan Amount $0
Gas Cost $0.0000
Gas Cost Escalation 2.0%
Gas Quantity 826 SCFM
Financing
Principal No Debt
Term n/a
Interest Rate n/a
Financial Returns 10 Years
Total Cash Flow from Operations 2,766,265$
Investment 2,284,849$
Net Cash Flow 481,416$
Project IRR 3.0%
NPV at rate = 2.000% 145,694$
NPV at rate = 2.500% 72,018$
NPV at rate = 2.750% 36,569$
NPV at rate = 3.000% 2,012$
Pre Tax Profits 744,317$
Average % 8.7%
Minimum % -21.5%
Net Income 481,416$
Average % 4.0%
Minimum % -30.9%
MUSA Contributions (Municipal Utility Service Assessment)
Rate 10 Year Totals
Rate on Net Book Value of Assets - in mils 16 185,467$
Gross Revenue contribution % of Revenue 1.25% 77,435$
262,902$
Depreciation per GASB 34 Method Life in Years
Vehicles St. Line 5
Support Equipment St. Line 4
Machinery & Equipment St. Line 7
GCCS & Pipeline St. Line 10
Summary of Assumptions & Financials
Anchorage Medium BTU Gas Project
Gas Sales to Proposed Fossil Creek Powerplant
Assumes Fossil Creek will use all gas available
Project Proforma
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage FossilCreek Pipelineapdx17.xls]Dep
5/18/2004 1:53 PM Anchorage FossilCreek Pipelineapdx17
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage FossilCreek Pipelineapdx17.xls]Dep
Description Value Unit
Financial Information
Project Capital Costs $2,284,849
Equity Contribution 100.00% $2,284,849
Loan 0.00%
Principal $0
Term 10 years
Interest Rate 0.0%
Interest Payments monthly during construction
Loan Fees 0.0%
MG Quantity 826 SCFM 208,631 mmBTU/Yr
50.00% Methane %
On-Stream Factors
Utilization %95.0%
MG Price $2.145
MG Price escalator 2.0%
Cost of Sales
Cost of Methane Gas $0.0000 per mmBTU
Cost Escalator 2.0%
Electric Cost - Blower and Compressor @ .09 cents / kwh $60,000 Annually
Electric Escalator 2.0%
Operating Costs Annually
O&M Compressor/Pipeline per year 175,000$
O&M Escalator 3.0%
Property Insurance 1.00% % of Value
General Liability Insurance 1.00% % of Revenue
Administration $25,000
Income Taxes Is project subject to income taxes NO
Federal Tax Rate 0%
State Tax Rate 0.0% Incl. In Federal
Gas Sales to Proposed Fossil Creek Powerplant
Anchorage Medium BTU Gas Project
ASSUMPTIONS to PRO FORMA
5/18/2004 1:53 PM Anchorage FossilCreek Pipelineapdx17
Gas Sales to Proposed Fossil Creek Powerplant Annual ProformaMethane Gas Price (MG) = 2.14$ Escalation Year012345678910 YearAssumptionsCalendarYear 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TotalGas Curve LFG Generation - Avg 1,101 1,170 1,237 1,302 1,364 1,423 1,479 1,533 1,584 1,632 Lfg Recoverable Rate 75.0% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%Landfill Gas Available 826 878 928 977 1,023 1,067 1,109 1,150 1,188 1,224 Average MMBTU @ 50% Methane & 95% Utilization 208,631 221,706 234,402 246,719 258,467 269,647 280,259 290,491 300,155 309,251 School Gas DemandAverage SCFM - - - - - - - - - - 0Average MMBTU @ 50% Methane & 95% Utilization - - - - - - - - - - - EscalatorAssumed Methane Gas Price 2% 2.14$ 2.19$ 2.23$ 2.28$ 2.32$ 2.37$ 2.42$ 2.46$ 2.51$ 2.56$ IncomeEscalatorMG Sales - Landfill Gas Production 2.0% $447,409 $485,536 $522,716 $562,519 $599,643 $639,063 $678,227 $714,608 $753,389 $791,683 $6,194,794Total Revenues 447,409 485,536 522,716 562,519 599,643 639,063 678,227 714,608 753,389 791,683 6,194,794 Costs of SalesPurchased Electricity - Blower/Compressor 2.0% 60,000 61,200 62,424 63,672 64,946 66,245 67,570 68,921 70,300 71,706 656,983 Purchased Methane Gas -$ 2.0% - - - - - - - - - - - Costs of Sales 60,000 61,200 62,424 63,672 64,946 66,245 67,570 68,921 70,300 71,706 656,983 Gross Profit387,409 424,336 460,292 498,847 534,698 572,819 610,657 645,687 683,089 719,977 5,537,811 Expenses - PipelineO&M - Wellfield/Comp/Pipeline - per year 2.0% 175,000 178,500 182,070 185,711 189,426 193,214 197,078 201,020 205,040 209,141 1,916,201 Property Insur. - (% of value) 1.00% 2.0% 22,848 23,305 23,772 24,247 24,732 25,227 25,731 26,246 26,771 27,306 250,185 General Liability Insur. (% of revenue) 1.00% 2.0% 4,474 4,952 5,438 5,970 6,491 7,056 7,638 8,209 8,827 9,461 68,516 Administration 2.0% 25,000 25,500 26,010 26,530 27,061 27,602 28,154 28,717 29,291 29,877 273,743 Personal Property Tax - n/a - assume Pollution Control Exemp.0000000000 - Interest0000000000 - Total Expenses 227,323 232,258 237,290 242,458 247,709 253,099 258,602 264,191 269,930 275,786 2,508,645 Net Operating Profit 160,087 192,078 223,003 256,389 286,988 319,720 352,056 381,495 413,160 444,191 3,029,166 LessDepreciation/Amort Finance Fees (Pipeline Only) 256,342 256,342 256,342 256,342 256,342 256,342 256,342 163,485 163,485 163,485 2,284,849 Net Profit Before Tax (96,255) (64,264) (33,339) 47 30,646 63,378 95,713 218,010 249,675 280,706 744,317 -21.5% -13.2% -6.4% 0.0% 5.1% 9.9% 14.1% 30.5% 33.1% 35.5% 12.0%MUSA ContributionsMillage Rate on NBV of PPE 1.60% 36,558 32,456 28,355 24,253 20,152 16,050 11,949 7,847 5,232 2,616 185,467 Gross Revenue Rate 1.25% 5,593 6,069 6,534 7,031 7,496 7,988 8,478 8,933 9,417 9,896 77,435 Total Taxes 42,150 38,525 34,889 31,285 27,647 24,039 20,427 16,780 14,649 12,512 262,902 Net Income(138,406) (102,789) (68,228) (31,238) 2,999 39,339 75,287 201,230 235,026 268,194 481,416 -30.9% -21.2% -13.1% -5.6% 0.5% 6.2% 11.1% 28.2% 31.2% 33.9% 7.8%Anchorage Medium BTU Gas Project5/18/2004 1:54 PMAnchorage FossilCreek Pipelineapdx17
Gas Sales to Proposed Fossil Creek Powerplant Annual ProformaMethane Gas Price (MG) = 2.14$ Anchorage Medium BTU Gas ProjectConstructionCash Flow - Total Project2005Capital Expenditures (2,284,849) Loan - Add Depreciation/Amort (Pipeline & Related Costs) 256,342 256,342 256,342 256,342 256,342 256,342 256,342 163,485 163,485 163,485 2,284,849 Less Principal Payment 0000000000 0Net After Tax Cash Flow(2,284,849) 117,936 153,553 188,114 225,104 259,341 295,682 331,629 364,715 398,511 431,679 2,766,265 Cumulative After Tax Cash @ (2,284,849) (2,166,913) (2,013,360) (1,825,246) (1,600,142) (1,340,800) (1,045,119) (713,490) (348,775) 49,736 481,416 Net Present Value (NPV)2.000%$145,694Bank Principal Balance (Yr End) - - - - - - - - 2,012 - 10 YEARInvestment Analysis - Total ProjectConst. Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TOTAL% Ownership 100.00%Capital Expenditures (2,284,849) (2,284,849) Construction Interest- Bond - - Cash Flow 117,936 153,553 188,114 225,104 259,341 295,682 331,629 364,715 398,511 431,679 2,766,265 - After Tax Cash Flow - Year (2,284,849) 117,936 153,553 188,114 225,104 259,341 295,682 331,629 364,715 398,511 431,679 481,416 After Tax Cash Flow - Cum. (2,284,849) (2,166,913) (2,013,360) (1,825,246) (1,600,142) (1,340,800) (1,045,119) (713,490) (348,775) 49,736 481,416 Project IRR - on Cash Investment 3.01%NPV - After tax - Discount @ 2.00% $145,6942.50% $72,0182.75% $36,569Discount = to IRR 3.00% $2,012NPV and IRR reconcileReturn on Revenues Average MinimumPre Tax 8.71% -21.51%After Tax 4.03% -30.93%5/18/2004 1:54 PMAnchorage FossilCreek Pipelineapdx17
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage FossilCreek Pipelineapdx17.xls]Dep
Description
Sub-Total Total
Gas Collection System / Compressor Facility
Wellfield based on $12,000 per acre asuming 73 acres $876,000
Compressor $650,000
Contingency $0 Included in above
$1,526,000
Pipeline and Related Costs
Blower Upgrade $0 Included in GCCS
Pipeline 2.0797 miles (10,981 feet) @ $60 per foot $658,849
D.O.T. Pipeline Safety Standards Design & Compliance $0 Included in Pipeline estimate
Air Compressor $0 Included in Pipeline estimate
Surveying $0 Included in Pipeline estimate
Geotechnical $0 Included in Pipeline estimate
Planning/Coordination/Legal $0 Included in Pipeline estimate
Construction Interest $0 None assumed
Right of Way Payment $0 None assumed
Wetlands Investigation $0 Included in Pipeline estimate
End User Upgrades $100,000 Allowance
Contingency - 10% $0 Included in above
$758,849
Project Total $2,284,849
Gas Sales to Proposed Fossil Creek Powerplant
Anchorage Medium BTU Gas Project
Capital Estimate Detail
5/18/2004 1:54 PM Anchorage FossilCreek Pipelineapdx17
April 5, 2004
N:\Document Control\project for jim bier\[Anchorage FossilCreek Pipelineapdx17.xls]Dep
Depreciation Amounts Amount
Gas Treatment and Processing System 1,526,000
Pipeline and Related Costs 758,849
Construction Interest -
Sub-Total 2,284,849
Year Depreciation
1 2006 $256,342
2 2007 $256,342
3 2008 $256,342
4 2009 $256,342
5 2010 $256,342
6 2011 $256,342
7 2012 $256,342
8 2013 $163,485
9 2014 $163,485
10 2015 $163,485
$2,284,849
Gas Sales to Proposed Fossil Creek Powerplant
Anchorage Medium BTU Gas Project
Depreciation & Amortization Schedules
APPENDIX 18
FINANCIAL PRO FORMA FOR OPTION 8
(TREATMENT OF LIQUID COLLECTED
AT THE ANCHORAGE REGIONAL LANDFILL)
Assumptions
Input Volume - Glycol / Water /? Mix 55,000 Assumed for preliminary analysis, need actual.
Glycol Recovery % 50.0%Assumed for preliminary analysis, need actual.
Glycol Sales Price per gallon $2.50 Assumed for preliminary analysis, need actual.
Glycol Price Escalation 2.0%
Glycol Sales Volume 27,500 gallons
Avoided Cost of Glycol Disposal 35,000$ per year
Capital Cost 350,000$ Assumed for preliminary analysis, need actual.
Loan Amount $0
Gas Cost $0.0000
Gas Cost Escalation 2.0%
Gas Quantity 1,500 per pound of input
Assumed for preliminary analysis, need actual.
Financing
Principal No Debt
Term n/a
Interest Rate n/a
Financial Returns 10 Years
Total Cash Flow from Operations 432,669$
Investment 350,000$
Net Cash Flow 82,669$
Project IRR 3.3%
NPV at rate = 2.000% 29,747$
NPV at rate = 2.500% 18,152$
NPV at rate = 2.750% 12,576$
NPV at rate = 3.000% 7,141$
Pre Tax Profits 120,827$
Average % 5.6%
Minimum % -17.5%
Net Income 82,669$
Average % 2.4%
Minimum % -24.1%
MUSA Contributions (Municipal Utility Service Assessment)
Rate 10 Year Totals
Rate on Net Book Value of Assets - in mils 16 22,400$
Gross Revenue contribution % of Revenue 1.25% 15,759$
38,159$
Depreciation per GASB 34 Method Life in Years
Vehicles St. Line 5
Support Equipment St. Line 4
Machinery & Equipment St. Line 7
GCCS & Pipeline St. Line 10
Summary of Assumptions & Financials
Anchorage Medium BTU Gas Project
Glycol Distillation
Glycol Sales Gallons Needed to Breakeven at $2.50 per Gallon Sales Price
Project Proforma
April 6, 2004
N:\Document Control\project for jim bier\[Anchorage Glycol$2 50 apdx18 1.xls]Dep
5/18/2004 2:03 PM PRELIMINARY Anchorage Glycol$2 50 apdx18 1
April 6, 2004
N:\Document Control\project for jim bier\[Anchorage Glycol$2 50 apdx18 1.xls]Dep
Description Value Unit
Financial Information
Project Capital Costs $350,000
Equity Contribution 100.00% $350,000
Loan 0.00%
Principal $0
Term 10 years
Interest Rate 0.0%
Interest Payments monthly during construction
Loan Fees 0.0%
MG Quantity 1,500 Btus per pound of input 660 mmBTU/Yr
50.00% Methane %
On-Stream Factors
Utilization %100.0%
MG Price $0.000
MG Price escalator 2.0%
Glycol Assumptions
Input weight per gallon 8
Input Volume - Glycol / Water /? Mix 55,000
Glycol Recovery %50.0%
Glycol Sales Price $2.50 per gallon
Glycol Recovery and Sales 27,500 gallons
Avoided Cost of Glycol Disposal 35,000$ per year
Cost of Sales
Cost of Methane Gas $0.0000 per mmBTU
Cost Escalator 2.0%
Electric Cost - Blower and Compressor @ .09 cents / kwh $5,000 Annually
Electric Escalator 2.0%
Operating Costs Annually
Glycol Distillation O&M per year 56,363$
O&M Escalator 3.0%
Property Insurance 1.00% % of Value
General Liability Insurance 1.00% % of Revenue
Administration $6,000
Income Taxes Is project subject to income taxes NO
Federal Tax Rate 0%
State Tax Rate 0.0% Incl. In Federal
Glycol Distillation
Anchorage Medium BTU Gas Project
ASSUMPTIONS to PRO FORMA
5/18/2004 2:04 PM PRELIMINARY Anchorage Glycol$2 50 apdx18 1
PRELIMINARYGlycol Distillation Annual ProformaGlycol Price$2.50Glycol Sales27,500 GallonsMethane Gas Price (MG) = -$ Escalation Year012345678910 YearAssumptionsCalendarYear 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TotalGas Curve LFG Generation - Avg 1,101 1,170 1,237 1,302 1,364 1,423 1,479 1,533 1,584 1,632 Lfg Recoverable Rate 75.0% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%Landfill Gas Available 826 878 928 977 1,023 1,067 1,109 1,150 1,188 1,224 Average MMBTU @ 50% Methane & 95% Utilization 208,631 221,706 234,402 246,719 258,467 269,647 280,259 290,491 300,155 309,251 Gas DemandAverage SCFM 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 24.81635894Average MMBTU @ 50% Methane 660 660 660 660 660 660 660 660 660 660 6,600 Glycol Sales Volumegallons/yr 27,500 27,500 27,500 27,500 27,500 27,500 27,500 27,500 27,500 27,500 275,000 EscalatorAssumed Methane Gas Price 2% -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ Assumed Glycol Price 2% $2.50 2.55$ 2.60$ 2.65$ 2.71$ 2.76$ 2.82$ 2.87$ 2.93$ 2.99$ Income & SavingsEscalatorMG Sales - Landfill Gas Production 2.0% $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Glycol Sales 2.0% $68,750 $70,125 $71,500 $72,875 $74,525 $75,900 $77,550 $78,925 $80,575 $82,225 $752,950Avoided Cost of Glycol Disposal 2.0% $35,000 $35,700 $37,142 $39,416 $42,665 $47,105 $53,048 $60,936 $71,396 $85,325 $507,733Total Revenues 103,750 105,825 108,642 112,291 117,190 123,005 130,598 139,861 151,971 167,550 1,260,683 Costs of SalesPurchased Electricity - Blower/Compressor 2.0% 5,000 5,100 5,202 5,306 5,412 5,520 5,631 5,743 5,858 5,975 54,749 Purchased Methane Gas -$ 2.0% - - - - - - - - - - - Costs of Sales 5,000 5,100 5,202 5,306 5,412 5,520 5,631 5,743 5,858 5,975 54,749 Gross Profit98,750 100,725 103,440 106,985 111,778 117,485 124,968 134,117 146,113 161,574 1,205,935 Expenses - OperationsDistillation O&M 2.0% 56,363 57,490 58,640 59,813 61,009 62,229 63,474 64,743 66,038 67,359 617,159 Property Insur. - (% of value) 1.00% 2.0% 3,500 3,570 3,641 3,714 3,789 3,864 3,942 4,020 4,101 4,183 38,324 General Liability Insur. (% of revenue) 1.00% 2.0% 1,038 1,079 1,130 1,192 1,269 1,358 1,471 1,607 1,781 2,002 13,926 Administration 2.0% 6,000 6,120 6,242 6,367 6,495 6,624 6,757 6,892 7,030 7,171 65,698 Personal Property Tax - n/a - assume Pollution Control Exemp. 0 0 00000000 - Interest0000000000 - Total Expenses 66,901 68,260 69,654 71,086 72,561 74,076 75,643 77,262 78,950 80,715 735,107 Net Operating Profit 31,850 32,465 33,786 35,899 39,217 43,409 49,324 56,855 67,163 80,860 470,827 LessDepreciation/Amort Finance Fees (Pipeline Only) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 - - - 350,000 Net Profit Before Tax (18,151) (17,535) (16,214) (14,101) (10,783) (6,591) (676) 56,855 67,163 80,860 120,827 -17.5% -16.6% -14.9% -12.6% -9.2% -5.4% -0.5% 40.7% 44.2% 48.3% 9.6%MUSA ContributionsMillage Rate on NBV of PPE 1.60% 5,600 4,800 4,000 3,200 2,400 1,600 800 - - - 22,400 Gross Revenue Rate 1.25% 1,297 1,323 1,358 1,404 1,465 1,538 1,632 1,748 1,900 2,094 15,759 Total Taxes 6,897 6,123 5,358 4,604 3,865 3,138 2,432 1,748 1,900 2,094 38,159 Net Income(25,047) (23,657) (21,572) (18,705) (14,648) (9,729) (3,108) 55,107 65,264 78,765 82,669 -24.1% -22.4% -19.9% -16.7% -12.5% -7.9% -2.4% 39.4% 42.9% 47.0% 6.6%Anchorage Medium BTU Gas Project5/18/2004 2:04 PMAnchorage Glycol$2 50 apdx18 1
PRELIMINARYGlycol Distillation Annual ProformaGlycol Price$2.50Glycol Sales27,500 GallonsMethane Gas Price (MG) = -$ Anchorage Medium BTU Gas ProjectConstructionCash Flow - Total Project2005Capital Expenditures (350,000) Loan - Add Depreciation/Amort (Pipeline & Related Costs) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 - - - 350,000 Less Principal Payment 0000000000 0Net After Tax Cash Flow(350,000) 24,953 26,343 28,428 31,295 35,352 40,271 46,892 55,107 65,264 78,765 432,669 Cumulative After Tax Cash @ (350,000) (325,047) (298,705) (270,277) (238,982) (203,630) (163,358) (116,467) (61,360) 3,904 82,669 Net Present Value (NPV)2.000%$29,747Bank Principal Balance (Yr End) - - - - - - - - 2,012 - 10 YEARInvestment Analysis - Total ProjectConst. Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TOTAL% Ownership 100.00%Capital Expenditures (350,000) (350,000) Construction Interest- Bond - - Cash Flow 24,953 26,343 28,428 31,295 35,352 40,271 46,892 55,107 65,264 78,765 432,669 - After Tax Cash Flow - Year (350,000) 24,953 26,343 28,428 31,295 35,352 40,271 46,892 55,107 65,264 78,765 82,669 After Tax Cash Flow - Cum. (350,000) (325,047) (298,705) (270,277) (238,982) (203,630) (163,358) (116,467) (61,360) 3,904 82,669 Project IRR - on Cash Investment 3.34%NPV - After tax - Discount @ 2.00% $29,7472.50% $18,1522.75% $12,576Discount = to IRR 3.00% $7,141NPV and IRR reconcileReturn on Revenues Average MinimumPre Tax 5.65% -17.49%After Tax 2.36% -24.14%5/18/2004 2:04 PMAnchorage Glycol$2 50 apdx18 1
April 6, 2004
N:\Document Control\project for jim bier\[Anchorage Glycol$2 50 apdx18 1.xls]Dep
Description
Sub-Total Total
Gas Collection System / Compressor Facility
Wellfield based on $12,000 per acre asuming xx acres $0
Compressor $0
Glycol Distillation Equipment $350,000
Contingency $0 Included in above
$350,000
Pipeline and Related Costs
Blower Upgrade $0 Included in GCCS
Pipeline 0 miles @ $60 per foot $0
D.O.T. Pipeline Safety Standards Design & Compliance $0 Included in Pipeline estimate
Air Compressor $0 Included in Pipeline estimate
Surveying $0 Included in Pipeline estimate
Geotechnical $0 Included in Pipeline estimate
Planning/Coordination/Legal $0 Included in Pipeline estimate
Construction Interest $0 None assumed
Right of Way Payment $0 None assumed
Wetlands Investigation $0 Included in Pipeline estimate
End User Upgrades $0 Allowance
Contingency - 10% $0 Included in above
$0
Project Total $350,000
Glycol Distillation
Anchorage Medium BTU Gas Project
Capital Estimate Detail
5/18/2004 2:05 PM Anchorage Glycol$2 50 apdx18 1
April 6, 2004
N:\Document Control\project for jim bier\[Anchorage Glycol$2 50 apdx18 1.xls]Dep
Depreciation Amounts Amount
Gas Treatment and Processing System 350,000
Pipeline and Related Costs -
Construction Interest -
Sub-Total 350,000
Year Depreciation
1 2006 $50,000
2 2007 $50,000
3 2008 $50,000
4 2009 $50,000
5 2010 $50,000
6 2011 $50,000
7 2012 $50,000
8 2013 $0
9 2014 $0
10 2015 $0
$350,000
Glycol Distillation
Anchorage Medium BTU Gas Project
Depreciation & Amortization Schedules
Assumptions
Input Volume - Glycol / Water /? Mix 29,400 Assumed for preliminary analysis, need actual.
Glycol Recovery % 50.0%Assumed for preliminary analysis, need actual.
Glycol Sales Price per gallon $4.50 Assumed for preliminary analysis, need actual.
Glycol Price Escalation 2.0%
Glycol Sales Volume 14,700 gallons
Avoided Cost of Glycol Disposal 35,000$ per year
Capital Cost 350,000$ Assumed for preliminary analysis, need actual.
Loan Amount $0
Gas Cost $0.0000
Gas Cost Escalation 2.0%
Gas Quantity 1,500 per pound of input
Assumed for preliminary analysis, need actual.
Financing
Principal No Debt
Term n/a
Interest Rate n/a
Financial Returns 10 Years
Total Cash Flow from Operations 432,836$
Investment 350,000$
Net Cash Flow 82,836$
Project IRR 3.3%
NPV at rate = 2.000% 29,901$
NPV at rate = 2.500% 18,303$
NPV at rate = 2.750% 12,725$
NPV at rate = 3.000% 7,290$
Pre Tax Profits 120,638$
Average % 5.7%
Minimum % -18.0%
Net Income 82,836$
Average % 2.4%
Minimum % -24.7%
MUSA Contributions (Municipal Utility Service Assessment)
Rate 10 Year Totals
Rate on Net Book Value of Assets - in mils 16 22,400$
Gross Revenue contribution % of Revenue 1.25% 15,402$
37,802$
Depreciation per GASB 34 Method Life in Years
Vehicles St. Line 5
Support Equipment St. Line 4
Machinery & Equipment St. Line 7
GCCS & Pipeline St. Line 10
Summary of Assumptions & Financials
Anchorage Medium BTU Gas Project
Glycol Distillation
Glycol Sales Gallons Needed to Breakeven at $4.50 per Gallon Sales Price
Project Proforma
April 19, 2004
N:\Document Control\project for jim bier\[Anchorage Glycol$4 50 apdx 18 2.xls]Dep
5/18/2004 2:05 PM PRELIMINARY Anchorage Glycol$4 50 apdx 18 2
April 19, 2004
N:\Document Control\project for jim bier\[Anchorage Glycol$4 50 apdx 18 2.xls]Dep
Description Value Unit
Financial Information
Project Capital Costs $350,000
Equity Contribution 100.00% $350,000
Loan 0.00%
Principal $0
Term 10 years
Interest Rate 0.0%
Interest Payments monthly during construction
Loan Fees 0.0%
MG Quantity 1,500 Btus per pound of input 353 mmBTU/Yr
50.00% Methane %
On-Stream Factors
Utilization %100.0%
MG Price $0.000
MG Price escalator 2.0%
Glycol Assumptions
Input weight per gallon 8
Input Volume - Glycol / Water /? Mix 29,400
Glycol Recovery %50.0%
Glycol Sales Price $4.50 per gallon
Glycol Recovery and Sales 14,700 gallons
Avoided Cost of Glycol Disposal 35,000$ per year
Cost of Sales
Cost of Methane Gas $0.0000 per mmBTU
Cost Escalator 2.0%
Electric Cost - Blower and Compressor @ .09 cents / kwh $5,000 Annually
Electric Escalator 2.0%
Operating Costs Annually
Glycol Distillation O&M per year 53,803$
O&M Escalator 3.0%
Property Insurance 1.00% % of Value
General Liability Insurance 1.00% % of Revenue
Administration $6,000
Income Taxes Is project subject to income taxes NO
Federal Tax Rate 0%
State Tax Rate 0.0% Incl. In Federal
Glycol Distillation
Anchorage Medium BTU Gas Project
ASSUMPTIONS to PRO FORMA
5/18/2004 2:06 PM PRELIMINARY Anchorage Glycol$4 50 apdx 18 2
PRELIMINARYGlycol Distillation Annual ProformaGlycol Price$4.50Glycol Sales14,700 GallonsMethane Gas Price (MG) = -$ Escalation Year012345678910 YearAssumptionsCalendarYear 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TotalGas Curve LFG Generation - Avg 1,101 1,170 1,237 1,302 1,364 1,423 1,479 1,533 1,584 1,632 Lfg Recoverable Rate 75.0% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75%Landfill Gas Available 826 878 928 977 1,023 1,067 1,109 1,150 1,188 1,224 Average MMBTU @ 50% Methane & 95% Utilization 208,631 221,706 234,402 246,719 258,467 269,647 280,259 290,491 300,155 309,251 Gas DemandAverage SCFM 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 13.26547187Average MMBTU @ 50% Methane 353 353 353 353 353 353 353 353 353 353 3,530 Glycol Sales Volumegallons/yr 14,700 14,700 14,700 14,700 14,700 14,700 14,700 14,700 14,700 14,700 147,000 EscalatorAssumed Methane Gas Price 2% -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ Assumed Glycol Price 2% $4.50 4.59$ 4.68$ 4.78$ 4.87$ 4.97$ 5.07$ 5.17$ 5.27$ 5.38$ Income & SavingsEscalatorMG Sales - Landfill Gas Production 2.0% $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Glycol Sales 2.0% $66,150 $67,473 $68,796 $70,266 $71,589 $73,059 $74,529 $75,999 $77,469 $79,086 $724,416Avoided Cost of Glycol Disposal 2.0% $35,000 $35,700 $37,142 $39,416 $42,665 $47,105 $53,048 $60,936 $71,396 $85,325 $507,733Total Revenues 101,150 103,173 105,938 109,682 114,254 120,164 127,577 136,935 148,865 164,411 1,232,149 Costs of SalesPurchased Electricity - Blower/Compressor 2.0% 5,000 5,100 5,202 5,306 5,412 5,520 5,631 5,743 5,858 5,975 54,749 Purchased Methane Gas -$ 2.0% - - - - - - - - - - - Costs of Sales 5,000 5,100 5,202 5,306 5,412 5,520 5,631 5,743 5,858 5,975 54,749 Gross Profit96,150 98,073 100,736 104,376 108,842 114,644 121,947 131,191 143,007 158,435 1,177,401 Expenses - OperationsDistillation O&M 2.0% 53,803 54,879 55,977 57,096 58,238 59,403 60,591 61,803 63,039 64,300 589,128 Property Insur. - (% of value) 1.00% 2.0% 3,500 3,570 3,641 3,714 3,789 3,864 3,942 4,020 4,101 4,183 38,324 General Liability Insur. (% of revenue) 1.00% 2.0% 1,012 1,052 1,102 1,164 1,237 1,327 1,437 1,573 1,744 1,965 13,612 Administration 2.0% 6,000 6,120 6,242 6,367 6,495 6,624 6,757 6,892 7,030 7,171 65,698 Personal Property Tax - n/a - assume Pollution Control Exemp. 0 0 00000000 - Interest0000000000 - Total Expenses 64,315 65,621 66,963 68,342 69,758 71,218 72,726 74,288 75,914 77,618 706,762 Net Operating Profit 31,836 32,452 33,774 36,034 39,084 43,426 49,220 56,903 67,093 80,818 470,638 LessDepreciation/Amort Finance Fees (Pipeline Only) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 - - - 350,000 Net Profit Before Tax (18,165) (17,548) (16,226) (13,966) (10,916) (6,574) (780) 56,903 67,093 80,818 120,638 -18.0% -17.0% -15.3% -12.7% -9.6% -5.5% -0.6% 41.6% 45.1% 49.2% 9.8%MUSA ContributionsMillage Rate on NBV of PPE 1.60% 5,600 4,800 4,000 3,200 2,400 1,600 800 - - - 22,400 Gross Revenue Rate 1.25% 1,264 1,290 1,324 1,371 1,428 1,502 1,595 1,712 1,861 2,055 15,402 Total Taxes 6,864 6,090 5,324 4,571 3,828 3,102 2,395 1,712 1,861 2,055 37,802 Net Income(25,029) (23,638) (21,551) (18,537) (14,744) (9,676) (3,174) 55,192 65,232 78,762 82,836 -24.7% -22.9% -20.3% -16.9% -12.9% -8.1% -2.5% 40.3% 43.8% 47.9% 6.7%Anchorage Medium BTU Gas Project5/18/2004 2:06 PMAnchorage Glycol$4 50 apdx 18 2
PRELIMINARYGlycol Distillation Annual ProformaGlycol Price$4.50Glycol Sales14,700 GallonsMethane Gas Price (MG) = -$ Anchorage Medium BTU Gas ProjectConstructionCash Flow - Total Project2005Capital Expenditures (350,000) Loan - Add Depreciation/Amort (Pipeline & Related Costs) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 - - - 350,000 Less Principal Payment 0000000000 0Net After Tax Cash Flow(350,000) 24,971 26,362 28,449 31,463 35,256 40,324 46,826 55,192 65,232 78,762 432,836 Cumulative After Tax Cash @ (350,000) (325,029) (298,667) (270,218) (238,755) (203,499) (163,175) (116,350) (61,158) 4,074 82,836 Net Present Value (NPV)2.000%$29,901Bank Principal Balance (Yr End) - - - - - - - - 2,012 - 10 YEARInvestment Analysis - Total ProjectConst. Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 TOTAL% Ownership 100.00%Capital Expenditures (350,000) (350,000) Construction Interest- Bond - - Cash Flow 24,971 26,362 28,449 31,463 35,256 40,324 46,826 55,192 65,232 78,762 432,836 - After Tax Cash Flow - Year (350,000) 24,971 26,362 28,449 31,463 35,256 40,324 46,826 55,192 65,232 78,762 82,836 After Tax Cash Flow - Cum. (350,000) (325,029) (298,667) (270,218) (238,755) (203,499) (163,175) (116,350) (61,158) 4,074 82,836 Project IRR - on Cash Investment 3.35%NPV - After tax - Discount @ 2.00% $29,9012.50% $18,3032.75% $12,725Discount = to IRR 3.00% $7,290NPV and IRR reconcileReturn on Revenues Average MinimumPre Tax 5.71% -17.96%After Tax 2.37% -24.74%5/18/2004 2:06 PMAnchorage Glycol$4 50 apdx 18 2
April 19, 2004
N:\Document Control\project for jim bier\[Anchorage Glycol$4 50 apdx 18 2.xls]Dep
Description
Sub-Total Total
Gas Collection System / Compressor Facility
Wellfield based on $12,000 per acre asuming xx acres $0
Compressor $0
Glycol Distillation Equipment $350,000
Contingency $0 Included in above
$350,000
Pipeline and Related Costs
Blower Upgrade $0 Included in GCCS
Pipeline 0 miles @ $60 per foot $0
D.O.T. Pipeline Safety Standards Design & Compliance $0 Included in Pipeline estimate
Air Compressor $0 Included in Pipeline estimate
Surveying $0 Included in Pipeline estimate
Geotechnical $0 Included in Pipeline estimate
Planning/Coordination/Legal $0 Included in Pipeline estimate
Construction Interest $0 None assumed
Right of Way Payment $0 None assumed
Wetlands Investigation $0 Included in Pipeline estimate
End User Upgrades $0 Allowance
Contingency - 10% $0 Included in above
$0
Project Total $350,000
Glycol Distillation
Anchorage Medium BTU Gas Project
Capital Estimate Detail
5/18/2004 2:06 PM Anchorage Glycol$4 50 apdx 18 2
April 19, 2004
N:\Document Control\project for jim bier\[Anchorage Glycol$4 50 apdx 18 2.xls]Dep
Depreciation Amounts Amount
Gas Treatment and Processing System 350,000
Pipeline and Related Costs -
Construction Interest -
Sub-Total 350,000
Year Depreciation
1 2006 $50,000
2 2007 $50,000
3 2008 $50,000
4 2009 $50,000
5 2010 $50,000
6 2011 $50,000
7 2012 $50,000
8 2013 $0
9 2014 $0
10 2015 $0
$350,000
Glycol Distillation
Anchorage Medium BTU Gas Project
Depreciation & Amortization Schedules