LANDFILL GAS TO ENERGY FEASIBILITY STUDY CITY OF LEE S SUMMIT. Prepared for: City of Lee s Summit 207 S.W. Market P.O. Box 1600 Lee s Summit, MO 64063

Transcription

1 LANDFILL GAS TO ENERGY FEASIBILITY STUDY CITY OF LEE S SUMMIT Prepared for: City of Lee s Summit 207 S.W. Market P.O. Box 1600 Lee s Summit, MO Prepared by: SCS ENGINEERS El Monte, Suite 100 Overland Park, Kansas (913) March 2006 File No

2 CONTENTS Section Page 1 Introduction Objectives Landfill Gas Overview Landfill Gas Generation and Recovery Model Description Model Application Estimated LFG Recovery Potential Model Results LFG to Energy Technologies for Consideration Technically Feasible End Uses at the Lee s Summit Sanitary Landfill Electricity Power Generation Reciprocating Engines Microturbines Cogeneration Medium Btu Gas Utilization Potential End Users of LFG Energy Existing and Planned Facilities Maintenance Facility Proposed Animal Control Building Proposed Water Department Building Total Energy Needs Offsite Energy Needs Economic Evaluation of End Use Options Microturbine Applications Financial Analyses Reciprocating Engine and Medium BTU Applications i

3 CONTENTS (Continued) Section Page 6 Regulatory Considerations Applicable Federal Energy Regulations Energy Policy Act of 2005 Public Utility Regulatory Policies Act of 1978 (PURPA) Applicable State Energy Regulations CSR Cogeneration CSR Net Metering Applicable Utility Policies Environmental Benefits Direct Environmental Benefits Indirect Environmental Benefits Electricity Generation Direct Use Findings and Conclusions Findings Conclusions Appendices A B C D E Financial Analyses of Technology Options Applicable Regulations and Policies FERC Missouri PSC Aquila Operating Standards for Generators, Small, Paralleling (Missouri) Technology Information Capstone C30 Roberts Gordon Vantage II Photographs ii

4 CONTENTS (Continued) Figures 1 LFG Recovery Projection 2 Site Map Tables 1 LFG Recovery Projection 2 Maintenance Building Energy Usage 3 Annual Energy Needs at Resource Recovery Park 4 Base Electric Capacity 5 Potential Energy Users in the Area 6 Energy Generation and Usage to Microturbine Scenarios 7 Capital Cost and Net Present Value Summary for Microturbine Scenarios 8 Capital Cost and Net Present Value Summary for Reciprocating Engine and Medium Btu iii

5 SECTION 1 INTRODUCTION OBJECTIVES SCS Engineers (SCS) has performed this feasibility assessment for the potential utilization of landfill gas (LFG) from the Lee s Summit Sanitary Landfill (Site). The purpose of this study is to evaluate the LFG generation and recovery potential at the landfill, and to provide a preliminary evaluation of the technology options and costs for utilizing LFG from the Site for energy recovery. LANDFILL GAS OVERVIEW Landfills produce LFG as organic materials decompose under anaerobic conditions. LFG is composed of approximately equal parts of methane (CH 4 ) and carbon dioxide (CO 2 ) with trace concentrations of other gases, including non-methane organic compounds (NMOCs). The combustibility of methane can be both an asset and a liability to a landfill owner: an asset when the gas becomes a source of energy recovered from LFG; and a liability because of the potential for fire or explosion when subsurface migration of LFG results in off-site contamination or the accumulation of methane in on-site buildings and underground structures. Methane released to the atmosphere is capable of retaining heat, and because LFG is approximately 50 percent methane, landfills have been recognized as significant sources of greenhouse gas emissions. Therefore, LFG emissions may increase the potential for global warming, or the greenhouse effect. Depending on the application, LFG can often be used in place of conventional fossil fuels. One pound of landfill refuse can produce about 3.6 standard cubic feet (scf) of LFG. The resulting fuel is classified as a medium-btu gas with a heating value of about 500 Btu/scf, which is approximately one-half the heating value of natural gas. Landfill gas is saturated with water vapor when extracted from a landfill and entrained moisture is usually removed prior to utilization. Other minor constituents of LFG include hydrogen sulfide (H 2 S) and chloride compounds. These compounds typically account for less than one percent of the gas and generally do not cause a hindrance to LFG utilization. Landfill gas is a low-polluting fuel with respect to NOx, CO, unburned hydrocarbons (HC) and volatile organic emissions. Flame temperatures from the burning LFG are relatively low and the resulting NOx emissions are generally about 70 percent less than for natural gas combustion. However, flame temperatures are not so low as to increase HC or CO emissions. Emissions using LFG as the primary fuel can be as low as 22 ppm for NOx and 5 ppm for CO and HCs, depending on the technology used to combust LFG. 1-1

6 SECTION 2 LANDFILL GAS GENERATION AND RECOVERY MODEL DESCRIPTION The LFG generation model requires that the site s waste disposal history (or, at a minimum, the amount of waste in place and opening date) be known. The landfill gas model used by SCS is a first-order model, similar to the U.S. Environmental Protection Agency (EPA) Landfill Gas Emissions Model (LandGEM). The model developed by SCS calculates gas collection, not gas generation. The model uses input variables for methane generation potential (L o ) and annual gas generation rate (k) that have been developed specifically by SCS based on a database of over 150 operational LFG collection systems. MODEL APPLICATION Application of the LFG generation model to the Site required developing a disposal history and estimating appropriate values for other model input parameters (k and L o ). To estimate historical disposal, SCS obtained available records from landfill personnel and the Missouri Department of Natural Resources (MDNR). These records provided the following information: Year landfill opened: Year landfill closes: Estimated disposal rates from (based on amount of total airspace calculated in SWD 2004 Model given to SCS by the City of Lee s Summit landfill personnel). Actual annual disposal rates from (From MDNR files). Projected annual disposal rates (based on past population increase, recorded waste history, and projected population increase). SCS developed an approximate disposal history using this information. The tonnages are presented in Table 1. Remaining input parameters required for model application include the methane generation rate constant, k, and the methane generation potential, L o. These were determined by entering the annual precipitation for the City into SCS landfill gas model. 2-1

7 Table 1. LFG RECOVERY PROJECTION City of Lee's Summit, Missouri - LFGTE Disposal Refuse LFG Recovery System LFG Recovery from Rate In-Place Potential Coverage Existing and Planned System Year (tons/yr) (tons) (scfm) (mmcf/day) (mmbtu/yr) (%) (scfm) (mmcf/day) (mmbtu/yr) ,735 21, % ,735 43, ,506 0% ,735 65, ,693 0% ,735 86, ,584 0% , , ,198 0% , , ,557 0% , , ,677 0% , , ,577 0% , , ,271 0% , , ,212 0% , , ,116 0% , , ,494 0% , , ,858 0% , , ,628 0% , , ,915 0% , , ,119 0% , , ,721 0% , , ,680 0% ,213 1,020, ,940 0% ,067 1,140, ,270 0% ,318 1,220, ,799 0% ,797 1,302, ,849 49% , ,911 1,385, ,055 52% , ,482 1,473, ,331 55% , ,204 1,564, ,974 58% , ,085 1,659, ,988 59% , ,132 1,758, ,381 59% , ,350 1,862, ,159 60% , ,748 1,969, ,332 60% , ,333 2,082, ,909 60% , ,113 2,199, ,899 60% , ,097 2,321, ,314 61% , ,292 2,448, ,166 61% , ,448, ,468 81% , ,448, ,719 90% , ,448, ,228 90% , ,448, ,905 90% , ,448, ,668 90% , ,448, ,440 90% , ,448, ,149 90% , ,448, ,730 90% , ,448, ,119 90% , ,448, ,261 90% , ,448, ,101 90% , ,448, ,590 90% , ,448, ,682 90% , ,448, ,335 90% , ,448, ,508 90% , ,448, ,165 90% ,

8 ESTIMATED LFG RECOVERY POTENTIAL The potential LFG recovery rates are estimated based on the projected LFG generation rates provided by the model and the estimated current and future collection system recovery efficiency ( collection efficiency ). Current collection efficiency is approximately 23 percent with 25 wells covering approximately 5 of the 80 acres of landfilled footprint. This implies that the Site could be producing beyond modeled potential recovery values or that SCS model predictions may be conservative relative to actual gas recovery. LFG is collected in a network of wells that are located close to the perimeter of the waste. A 500 cfm blower applies a vacuum to the collection system. The extracted LFG is flared in an 800 cfm capacity flare. The maximum potential collection efficiency for the site is estimated to be 80 percent while the landfill is accepting waste because of no final cover. This recovery level assumes periodic expansion of the LFG collection system between now and closure in Without final cover, some of the LFG will escape through the landfill surface. Upon placement of final cover, the potential collection efficiency is estimated to be approximately 90 percent, as there should be a significant decrease in LFG that will escape through the surface of the landfill. MODEL RESULTS Table 1 and Figure 1 show the historical and projected future LFG generation and recovery potential for the Site. The resulting projections can be summarized as follows: Site wide LFG generation potential is estimated to reach a maximum of 942 cfm (50 percent methane) in 2015 and decline thereafter. The site wide LFG recovery potential was estimated to reach a maximum of 788 cfm in 2016 and decline thereafter. 1,000 Figure 1. LFG Recovery Projection City of Lee's Summit Sanitary Landfill LFG Flow at 50% Methane (cfm) Recovery Potential Recovery from Existing and Planned System Actual Recovery 2-3

9 SECTION 3 LFG TO ENERGY TECHNOLOGIES FOR CONSIDERATION In this section we present proven technologies currently available for consideration in the application of LFG to Energy at the Lee s Summit Resource Recovery Park. The preferred alternative for the Site will be dependent on several factors, including amounts of recoverable LFG, availability of customers for the gas or energy, supply and demand for gas and electricity, and environmental benefits associated with each of these options. TECHNICALLY FEASIBLE END USES AT THE LEE S SUMMIT SANITARY LANDFILL Electric Power Generation This study considered the option of generating electricity using LFG via several different technologies. The feasibility of this LFG utilization option depends on the electricity generated by the LFG for the Lee s Summit Maintenance Facility and the purchase price that is negotiated with the local electric utility. The average avoided cost rate that the local utility, Aquila, Incorporated (Aquila) currently pays for the electricity is $0.032/kWh, which is less than half of the average retail price to commercial and industrial customers. This avoided cost rate is the price that a utility must pay to an independent power producer for a unit of electricity that it then sells to customers through its power grid. The avoided cost rate is the lowest cost (per kwh) the utility would incur to either produce the same amount of electricity or buy it from another alternate producer. Since the cost to develop and market electricity from LFG can be between 6-8 cents per kwh, an electricity project may be difficult at this Site. Some utilities currently pay a premium for green power, which is power generated from renewable energy sources. SCS is aware of one Missouri utility currently paying over 40 per kwh for LFG generated electricity. LFG qualifies as such a source and is currently being added to the base of both national and Midwest electric utilities. Reciprocating Engines The reciprocating engine is the most frequently used conversion technology for LFG to energy projects. The capacity of the individual engines proven in LFG service varies from 0.5 MW to 3 MW. Reciprocating engines are manufactured in capacities larger than 3 MW; however, the larger units have not been proven in LFG service. It is believed that the largest LFG-fired reciprocating engine-based power plant is in the United States, and has a net power output of 12 MW. There are more than 200 LFG-fired reciprocating engine power plants operating worldwide. The principal advantage of reciprocating engines as compared to other power generation technologies is a better heat rate at lower capacities. An additional advantage of reciprocating engines is that the units are available in incremental capacities, which makes it easy to tailor the size of small plants to the specific rate of gas production at a landfill. Most small LFG power plants employ reciprocating engines. 3-1

10 In non-attainment air districts, an important disadvantage to reciprocating engines is that they produce higher emissions of NOx, CO, and NMOCs than other electric power generation technologies. Significant progress has, however, been made in reducing NOx emissions in recent years. A second disadvantage to reciprocating engines is that their operation/maintenance costs on a per kwh basis are higher than for other power generation technologies. Station load for a reciprocating engine plant is about seven percent of gross power output. The net heat rate for a typical reciprocating engine plant is 10,600 Btu/kWh. Reciprocating engines generally require a relatively simple LFG pretreatment process consisting of compression and removal of free moisture. Free moisture (water droplets) is removed by use of simple moisture separators (knockout drums), cooling of the LFG in ambient air-to-lfg heat exchangers, and coalescing-type filters. Moisture removal also removes particulates; however, LFG is generally fairly particulate free. Some of the NMOCs in the LFG are removed as a result of compression and cooling. Compression is usually provided by flooded screw-type blowers or centrifugal blowers. The reciprocating engines can require between 3 psig and 60 psig of fuel pressure. Engine manufacturers place restrictions on the amount of sulfur bearing compounds and the total organic halide content that they will tolerate in the LFG. Hydrogen sulfide is the principal sulfur-bearing compound in LFG. Chlorine is present in some of the NMOCs found in LFG. Chlorinated compounds are responsible for virtually all of the organic halides in LFG. A pretreatment scheme consisting of compression and simple moisture separation (knockout drum, air-to-lfg heat exchanger and coalescing filter) is virtually always the extent of LFG processing at a reciprocating engine plant. The total installed cost of a LFG fired reciprocating engine power plant is in the range of $1,100 to $1,300/kW. The scope of the installation would begin with a LFG booster blower and end with a step-up transformer. The variability in price relates to differences in plant size, site conditions, and whether or not the equipment is installed in a building or is supplied in its factory-shipped containers. Larger plants and containerized installations would fall in the lower end of the price range. The price range quoted assumes a minimum plant size of 800 kw. The operation/maintenance cost of a LFG fired reciprocating engine power plant, exclusive of LFG recovery cost, is in the range of 1.6 to 2.0 per kwh. The lower cost is associated with larger plants (3 to 6 MW) and the higher cost is associated with smaller plants. Microturbines The microturbine is a recently commercialized distributed generation technology. The microturbine is a derivative of the much larger combustion turbines employed in the electric power and aviation industries. Combustion air and fuel are mixed in a combustor section, and the release of heat causes the expansion of the gas. The hot gas is sent through a gas turbine that is connected to a generator. The units are normally equipped with a recuperator, which heats the combustion air using turbine exhaust gas in order to increase the unit s overall efficiency. 3-2

11 The combustion air is compressed using a compressor that is driven by the gas turbine. The fuel must be supplied to the combustor at 70 psig to 80 psig. In some natural gas fired applications, the gas is available at this pressure from the pipeline. In LFG applications, a gas compressor is required. The microturbine differs from traditional combustion turbines in that the microturbine spins at a much faster speed. The microturbines that are now on the market are equipped with air bearings rather than traditional mechanical bearings in order to reduce wear. Microturbines are small combustion turbines that produce 25 kw to 500 kw of power. They produce fewer emissions and are more resistant to corrosion than a typical IC engine; however, they typically have lower thermal efficiencies than IC engines. Microturbines were derived from turbocharger technologies found in large trucks and require little maintenance. Most microturbines are single-stage and have thermal efficiencies ranging from 20 to 30 percent. Thermal efficiencies of 85 percent can be reached if microturbines are used for cogeneration. A typical LFG fired microturbine installation would have the following components: LFG compressor(s), LFG pretreatment equipment, microturbine(s), motor control center, switchgear, and step-up transformer. Microturbines require about 13,900 Btu/kWh of fuel on a gross power output basis. Station load is about 15 percent, resulting in a net power output of about 16,350 Btu/kWh. Microturbines are most applicable where the following circumstances exist: low quantities of LFG are available; the LFG has a low methane content; air emissions are of great concern; emphasis is being placed on satisfaction of on-site power requirements, rather than exporting power; and/or a requirement for hot water exists at or near the landfill. Microturbines can operate on LFG with a methane content of 35 percent (and perhaps as low as 30 percent). A 75 kw unit requires less than 50 scfm of LFG (at 35 percent methane content). Microturbines can be used at small landfills and at old landfills where LFG quality and quantity would not support more traditional LFG electric power generation technologies. The total installed cost of a LFG fired microturbine power plant can range from $2,100 to $4,000/kW. For the smaller plants, the costs of the pretreatment package and skid can be disproportionally high. The cost of a 300 kw installation is in the range of $2,100/kW. Above 300 kw, there is little reduction in cost on a $/kw basis. When and if larger microturbines become available, the cost of a microturbine installation over 300 kw may decrease on a $/kw basis. The operation/maintenance cost of a LFG fired microturbine power plant, exclusive of LFG recovery cost, is in the range of $1.8 to $2.2 per kwh. Cogeneration Cogeneration is the combined production of electrical energy and heat from the same source. This heat that is produced in the generation of electricity is captured and used to produce thermal energy. Common uses of thermal energy include: heating requirements, provide cooling through absorption technology, and further electric production through another generating process. 3-3

12 Cogeneration produces approximately 10 percent of the United States electricity. It can increase the application thermal efficiency of the LFG to energy cycle to approximately percent. If the City opts for electricity generation, the waste heat from both the IC engine and the microturbine could be potential methods for heating the existing and planned City buildings. The waste heat would act as the heat (energy) through a heat exchanger, and ambient air would travel through (separately) this heat via blower into the building as heat. The ambient air would gain heating levels based on the time spent and length traveled in the heat exchanger. Medium Btu Gas Utilization If the City has an opportunity to send the LFG to an off site end-user, it can be supplied as either a dry LFG or as an unprocessed, wet LFG. The success of a direct use project depends on the ability of the project to produce cost savings for natural gas customers. Thus, if the energy project could supply LFG to current natural gas users below the market rate, a project is likely to be economically viable. When LFG is used as a medium-btu gas, it is directly used as a substitute for fossil fuel with very little treatment. The LFG seen at the landfill s flare fluctuates between 40 to 55 percent methane. The LFG has an energy value of 400 to 550 Btu/cf. It can be blended with natural gas, which has an energy value of 1,000 Btu/cf or it can be fired separately. The principal advantage associated with medium-btu gas utilization is that capital investments are not required to remove the carbon dioxide prior to LFG utilization or to convert the energy to electric energy. These cost savings are partially offset by the need to construct a dedicated pipeline direct to the gas user and/or the need to modify the user's piping and fuel burning equipment to accommodate LFG firing. The cost of a dedicated pipeline delivery system is a function of size and distance to the LFG user. Historically medium btu projects targeted sites within several (unobstructed) miles of a landfill but larger energy needs combined with rising natural gas prices are making more projects at greater distances economical. The key element of a successful medium-btu gas project is identifying a year-round user of fossil fuel near the landfill. Direct use (medium-btu) projects have three components: the compressor plant; the pipeline to deliver the LFG to the end user; and end user modifications to support LFG firing or LFG co-firing. The cost of the compressor plant is a function of its design flow rate and design pressure. Construction costs and operation/maintenance costs are primarily a function of flow rate. Flow rates for larger projects are typically quoted in million standard cubic feet per day (mmscfd). The total installed cost of a medium-btu compressor plant is in the range of $600,000 to $700,000/mmscfd. Operation/maintenance costs vary with energy costs but for planning purposes are approximately $400 to $500/mmscf. 3-4

13 Specific applications of medium Btu projects for LFG have included the following: Co-firing or dedicated industrial and institutional boilers Distillation of ethanol Co-firing in coal/natural gas burning electric generating plant Co-firing cement kiln Aggregate dryers and asphalt plants Heating via infra red heaters The economics and application of these technologies are highly site specific. The standard process for production of medium-btu gas is compression and refrigeration. Compression is employed in order to: (1) reduce the diameter of the conveyance pipeline; (2) to overcome pressure losses as the gas moves through the conveyance pipeline; and (3) to supply an end point pressure suitable for the user s needs. Refrigeration is employed for advanced moisture removal to assure that no condensate is formed in the conveyance pipeline and to produce a moisture-free gas for the end user. If the end user s fuel specification is particularly demanding, then hydrogen sulfide and/or non-methane organic compound (NMOC) removal can be added to the treatment process; however, the addition of such steps is unusual. Infrared heating with LFG. The seasonal heating needs of the Maintenance Facility and planned Animal Control and Water Maintenance Buildings will be investigated further in the Economic Feasibility Analysis. Infrared heating, low intensity continuous infrared heating systems fueled by LFG have been successfully utilized at a handful of sites to meet spaceheating requirements near landfills while requiring only minimal LFG flow. Infrared radiant heating is a proven, energy efficient method of heating that heats objects in a space rather that the air contained in the space. The infrared rays heat objects such as the floor, cars, machines and people. The warm objects in turn heat the air. The custom-designed system of heaters can be sized with input firing rates from 40,000 to 200,000 Btu/hr. Pretreatment of the LFG through moisture removal and activated carbon treatment may benefit the operation and maintenance of an infrared heating system and should be considered. 3-5

14 SECTION 4 POTENTIAL END USERS OF LFG ENERGY The discussion from the previous section suggests that the application of LFG to energy technology can be highly site specific. The technologies are proven and can be applied at various sites. It is the economics of building out each technology to match it with the specific customer s needs which determines whether various technologies are feasible in this study. The City is interested in identifying not only applicable technologies but also the most economical application. It is important, therefore, to exhaustively search for applications for each of the technologies. EXISTING AND PLANNED FACILITIES There are several new and planned structures in the immediate proximity of the Landfill that are candidates for end-use of LFG in various forms. Maintenance Facility The Maintenance Facility is located north of the landfill. It has been occupied since early Approximately 2,500 linear feet of piping would be required to connect LFG from the blower/flare with the building. This building is currently utilizes electricity for heating and cooling applications. A summary of electric bills for this building for 12 consecutive months is presented in Table 2. TABLE 2. MAINTENANCE BUILDING ENERGY USAGE Month Kilowatt-hours Dollars Dollars / kwh Apr-04 76,320 $ 6, $ May-04 63,250 7, Jun-04 68,000 7, Jul-04 65,920 7, Aug-04 66,320 7, Sep-04 74,880 4, Oct-04 78,080 4, Nov ,520 7, Dec ,320 9, Jan ,840 8, Feb ,520 6, Mar ,960 5, Totals 1,332,930 $84, $0.063 From this data we see that recent electricity energy usage has totaled 1,332,930 kwh (April 04 March 05) and charges have averaged $0.063 per kwh. This calculates to an annual Energy usage charge of 33.3 kwh per square foot and $2.10 per square foot per year for this building. 4-1

15 Proposed Animal Control Building The City plans to construct a 10,000 square foot Animal Control building north of the Landfill. This building, which is in the early planning stages, is anticipated to have incineration capabilities. Using the energy consumption data from the Maintenance Facility above, if this building is also to be an all-electric facility, like the existing building we roughly estimate its annual electric usage at 333,000 kwh. Proposed Water Department Building The Water Department is interested in placing a building similar to the Maintenance Facility in size and function, between the landfill and the Maintenance Facility. Using the energy consumption data from the Maintenance Facility above, if the Water Department building is also to be an all-electric facility we estimate annual electric usage at 1,300,000 kwh. TOTALED ENERGY NEEDS The City recently engaged Ameresco to complete an energy audit for City buildings. As part of that study, they calculated that 36 percent of the Maintenance Facility s energy needs were a base load electric demand, 54 percent was attributed to seasonal heating and 10 percent was attributed to seasonal cooling. Below we show Ameresco s values for the Maintenance Building and estimate the total energy for the proposed buildings using the same annual energy usage and seasonal allocations for heating and cooling experienced in the Maintenance Building. TABLE 3. ANNUAL ENERGY NEEDS AT RESOURCE RECOVERY PARK Base (kwh) Heating (kwh) Cooling (kwh) Total (kwh) Maintenance Building 480, , ,000 1,333,000 Proposed Animal Control Building 120, ,000 34, ,000 Proposed Water Department Building 480, , ,000 1,333,000 Totals 1,080,000 1,609, ,500 2,999,000 Sizing an electric generating facility to meet these electrical needs could take one of several directions. Sizing can be targeted for the base electric need for the three buildings or to meet the total annual needs. Below we present a matrix for the various all-electric sizing needs for consideration. TABLE 4. BASE ELECTRIC CAPACITY Targeted Facility Base Load Total Annual Capacity Capacity Existing Building 55 kw 152 kw Existing and Proposed Buildings 123 W 342 kw These estimated values show that generation from 55 kw to 350 kw could be used to provide energy to this site depending upon if existing or future facilities are targeted. In actuality some of the heating load may best be met by utilization of waste heat from a LFGTE process. The 4-2

16 application of this method of cogeneration will be considered. Additionally, direct use of the medium-btu LFG in infrared heating of the space is another application that will be considered in the feasibility analysis in the next chapter. OFFSITE ENERGY NEEDS SCS performed a local business search within five miles of the landfill to determine if there may be any potential end users for the LFG. When looking for offsite potential end users for LFG utilization, the end user needs to require large amounts of electricity for operation, or have a manufacturer that uses significant amounts of thermal energy for their production process. The most efficient application of offsite LFG usage is a medium-btu project if there is a facility with a large thermal need. These projects often pay for themselves and provide cost savings more quickly than LFG to electricity conversion because there is no energy loss associated with the direct use of LFG. SCS started with an initial list of 25 potential end users within 5 miles of the landfill that may have a feasible end use option. This list was then condensed based on Standard Industrial Classification (SIC) Codes to 14 potential end users. Of these 14 potential end users, it is likely that most will not be able to utilize the LFG in a cost effective manner. The following 14 potential end users are included for consideration of a LFG project: TABLE 5. POTENTIAL ENERGY USES IN THE AREA Facility Name Distance To Landfill (miles) SIC Code Lawler Gear Corp Precision Crankshaft Pfizer Inc Dupuis Redi-Mix Concrete Inc Old Mill Grain & Seed Co Longview Community College Saint Luke s Family Practice Lee s Summit Hospital Pain Center Corporate Travel Professionals Fabtech Inc Central Missouri State Univ Lucent Technologies American Foods Following presentation of this list to Lee s Summit officials, preliminary discussions were held with American Foods. They are a large energy user ($20,000/month electric bill and $10,000/ month diesel fuel bill). Their electric needs are fairly constant throughout the day and the year, for cooling of their warehouse. Their plant design includes a 300 kw circuit on a backup diesel generator for their principal cooling needs. Their owners are interested in discussing a proposal for LFGTE electric generation. SCS discussed with them the challenges of selling electricity offsite. They remain interested in exploring a more costly option of pipeline transport of LFG for their onsite generation of electricity or even the economics of converting their truck fleet to methane powered vehicles. 4-3

17 The cost to transport LFG to American Food s site would add over $1,000,000 in capital cost for a reciprocating engine project. Increasing the operating cost for a reciprocating engine project would increase costs several cents per kwh. Large-scale conversion of fleets to methane fuel remains experimental and marginally feasible at this time. Conversion of a small private fleet can be dismissed as not feasible. A detailed analysis of such projects is outside the scope of this project. Based on our experience however, SCS can say either project with American Foods, as discussed, would not be financially feasible. 4-4

18 SECTION 5 ECONOMIC EVALUATION OF END USE OPTIONS The previous sections have identified the technologies that are appropriate for consideration by the City at Resource Recovery Park. Section 4 developed some sizing parameters based on current and planned municipal facilities and the associated energy needs near the site. It this section we will present several of these technologies for further development and provide associated feasibility analyses. The concepts to be developed and analyzed are: Microturbine Applications 60 kw Microturbines 90 kw Microturbines 120 kw Microturbines 150 kw Microturbines 60 kw Microturbines with Heat Recovery 90 kw Microturbines with Heat Recovery 120 kw Microturbines with Heat Recovery Reciprocating Engine 500 MW Reciprocating Engine Medium Btu Applications Infra-red heaters in Maintenance Building End of Pipe Energy Source in Resource Recovery Park MICROTURBINE APPLICATIONS In Section 4 we discussed that a 55 kw generator could meet the base electric load at the Maintenance Facility. The seasonal low electric load coincides with approximately 90 kw of capacity and 150 kw of generating capacity would meet the entire facility s annualized load. Microturbine units as supplied by the two proven manufacturer s Capstone and Ingersol Rand currently are available in 30 and 70 kw units from these manufacturers, respectively. The economic analyses considered the economics associated with the microturbines with four different generating capacity arrangements. In the pro-formas presented in Appendix A, it is assumed that the generating plants will run near capacity. Revenues for onsite usage are shown at the inflated average cost ($0.065 per kwh in 2006 with 3 percent annual increases. Sales above the onsite electric demand receive revenues at Aquila s currently stated avoided cost rate of $0.032 per kwh. (No annual adjustments assumed.) SCS analyzed the recent 12 consecutive months of electric bills and was able to determine the portion of these bills that would be able to be met by onsite power of varying capacity. The 5-1

19 generated power that will be in excess of monthly usage was calculated for each of the seven microturbine scenarios from these electric bills. Table 6 presents this analysis of electric usage on an annual basis for different levels of generating capacity. Financial Analyses Financial cash flow projections have been developed for the most feasible technical scenarios. Each of the seven microturbine scenarios show annual energy consumed of 1,324,530 kwh, energy produced varies according to the capacity of the plants. Energy is then split between that which is consumed onsite (at 6.5 /kwh) and that which is sold to Aquila (at 3.2 /kwh) based on the historical energy use. The cogeneration options add a revenue stream associated with the winter season heating savings (at 6.5 /kwh) to this mix of revenue sources. Operating costs include only those costs associated with operating the microturbines (2 /kwh) and those costs are escalated at 2 percent per year. Revenues less operating costs result in earnings before interest, taxes, depreciation and amortization (EBITDA). Estimated capital costs have been developed for each scenario which include the cost of microturbine(s), compressor, filtering, transmission, piping (or wiring if the mircroturbines can be located at the flare) and an allowance for the utility interconnection. These costs are summarized on the bottom of each page in Appendix A. Capital costs are then amortized over a 10-year period. Cash flow projections for each project follow by subtracting the annualized capital costs from EBITDA. Table 7 presents a summary of all seven of the scenarios. The table shows the estimated capital cost and net present value (NPV) calculation of the initial capital investment combined with the resulting EBITDA. Only scenario 7, the 120 kw microturbine with cogenerated heat recovery shows a positive NPV. For further comparison of options, Table 7 also shows the payback period associated with each technology. TABLE 7. CAPITAL COST AND NET PRESENT VALUE SUMMARY FOR MICROTURBINE SCENARIOS 60kW 90kW 120 kw 150 kw Microturbine Capital Cost $ 392,500 $ 420,000 $ 482,500 $522,500 NPV $-185,406 $-275,847 $-107,110 $ -96,169 Payback period 8.0 years 10+ years 10.4 years 9.9 years Microturbine With Heat Recovery Capital Cost $492,500 $582,500 $622,500 NPV $ -74,402 $ -15,610 $ 43,691 Payback period 10.3 years 8.5 years 8.7 years 5-2

20 RECIPROCATING ENGINE AND MEDIUM BTU APPLICATIONS During our search for offsite direct use costumers, SCS had conversations with one end user with baseload electric needs of approximately 300 kw. The regulatory aspects of providing power to such an end user are significant and a technical solution for offsite production of electricity would be outside of the current scope of analysis so no cashflow projection has been developed at this time. At this time an offsite medium-btu application has not yet been identified. SCS has developed proformas showing that LFG can be available for $5.00 to $7.00 per mmbtu. The market cost for fuel is currently approximately $7 per mmbtu after having been as high as $13 per mmbtu in the 4 th quarter of A site-specific proforma (with a positive NPV) could be developed if a medium-btu energy user is identified. Exhibit A-8 in Appendix A presents the cashflow associated with the installation of 22 infared heaters in the Maintenance Facility. For revenue, this scenario recognizes the electric savings that will be realized when winter heating is reduced by the 50 percent that was going to heating the maintenance bays. Table 8 summarizes the capital cost and the NPV of these final three technologies. TABLE 8. CAPITAL COSTS AND NET PRESENT VALUE SUMMARY FOR RECIPROCATING ENGINE AND MEDIUM BTU 500 kw Direct Use Infrared Heat Capital Cost $1,000,000± $1,000,000+ $186,000 NPV negative positive $4,845 Payback Period 8.4 years 5-3

21 SECTION 6 REGULATORY CONSIDERATIONS The following policies and regulations impact LFGTE projects. The Energy Policy Act of 2005 and Public Utility Regulatory Policies Act of 1978 were implemented on a national level. The State of Missouri adopted 4 CSR governing electric utilities. There is a discussion at the end of this section about regulatory constraints. These policies impact the economics, and ultimately, the selection and configuration of a LFGTE project. APPLICABLE FEDERAL ENERGY REGULATIONS Energy Policy Act of 2005 Section 1303 of the Energy Policy Act of 2005 allows for Clean Renewable Energy Bonds (CREB) in section 54 to the tax code (26 USC). Bonds may be issued to pay for LFGTE projects. The owners of these bonds receive federal tax credits instead of interest payments from the bond issuer. CREBS provide an issuer with the ability to borrow at a zero percent interest rate, but there is 1-2 percent issuance costs associated with the bonds. The bonds will be issued from December 31, 2005 through December 31, Within 5 years of the date of issuance, 95 percent of the bond proceeds are required to be spent on eligible projects. There will be a ceiling of $800 million available in bonds, $500 million of which will be available to government bodies. Public Utility Regulatory Policies Act of 1978 (PURPA) The goal of PURPA was to promote conservation of electric energy. It requires utilities to purchase the electricity from small power producers, non-utility generators, and cogenerators if they are located within the utility s coverage area and they are qualifying facilities. The utility is required to buy the electricity at avoided cost from the qualifying facilities. It is under this regulation that Aquila offers to buyback excess power at 3.2 per kwh. APPLICABLE STATE ENERGY REGULATIONS 4 CSR Cogeneration This section applies to qualifying cogeneration and small power production facilities. It places liability on the qualifying facility as well as the utility, terms and conditions regarding the system, and the connection to the power grid. A qualifying facility is defined as a cogeneration facility or a small power production facility that satisfies Subpart B of Part 292 of the Federal Energy Regulatory Commission s (FERC) regulations. The facility would be considered a topping-cycle cogeneration facility, which is a qualifying facility, if the City of Lee s Summit elected to produce electricity with a network of microturbines and utilize the waste heat for heating the building. It would be considered a small power production facility, which is also a qualifying facility, if it did not utilize the waste heat from the electric generating process. 6-1

22 4 CSR Net Metering This section applies to a customer-generator (purchases electric energy from a retail electric power supplier and is the owner of a qualified net metering unit). A qualified net metering unit will need to be all of the following: Owned by the consumer-generator Fuel must be hydrogen, sun, wind, or biomass (i.e. LFG) The electrical generating system must have a capacity that does not exceed 100 kw Located on City of Lee s Summit - owned or leased property Interconnected, operating in parallel, and in synchronization with a retail electric power supplier (utility company that sells electricity to the ultimate consumer) Intended to offset customer-generators electric power requirements. The retail electric supplier calculates the net value of energy for a customer-generator in the following manner: 1. The retail electric power supplier shall individually measure both the electric energy from the customer-generator and the energy provided to the customergenerator. 2. If the value of the electric energy supplied by the retail electric power supplier exceeds that of the value produced by the customer-generator then the customergenerator will be billed for the net value of energy supplied to them by the retail electric power supplier (net = retail energy customer generator energy). 3. If the value of the electric energy supplied by the customer-generator exceeds that of the value consumed by the customer-generator then the retail electric power supplier will credit the customer-generator s account using the power supplier s avoided cost for the excess energy produced. APPLICABLE UTILITY POLICIES Aquila s avoided costs for the excess energy are $0.0316/kWh. Aquila recognizes that it is required to purchase back all power provided from generators under 100 kw according to both state and federal regulations. Copies of these policies are included in Appendix B. 6-2

23 SECTION 7 ENVIRONMENTAL BENEFITS In addition to being a potentially valuable resource for energy production, LFG also is considered an air pollutant. LFG gas contains methane, carbon dioxide, and lesser concentrations of other organic compounds, some of which are classified as hazardous or toxic air pollutants. As our society continues to be concerned about the possibility that human and industrial activities could accelerate global warming, attention has been focused on ways to reduce emissions. Landfill gas recovery projects provide a decrease in overall greenhouse gas emissions from landfills whether the LFG is combusted by a flare, electricity generation equipment, or off-site end uses. In terms of its heat retention capacity, methane is approximately 21 times more potent than carbon dioxide. In other words, one unit of methane can retain 21 times more heat than the same unit of carbon dioxide. The LFG end uses reviewed in this report (electricity generation and direct gas use) would also destroy most of the hazardous organic compounds. DIRECT ENVIRONMENTAL BENEFITS Both direct and indirect emissions benefits are associated with LFG projects. Direct benefits relate to the actual physical reduction in methane emissions and volatile organic compounds from the combustion of gas. INDIRECT ENVIRONMENTAL BENEFITS The use of methane in LFG to create energy offsets the use of non-renewable energy sources such as coal and oil, and thereby reduces the emissions of air pollutants from these fuels. The amount of fossil fuel emissions that are avoided by using LFG instead of non-renewable fuels will depend on the type of energy technology used, and is discussed below. Electricity Generation By utilizing the otherwise wasted methane contained in the collected LFG to generate electricity, fuels such as oil and coal that typically provide fuel for electricity generation are displaced. Direct Use LFG used at a facility could substitute for a number of fuels such as oil, natural gas, or propane. LFG could replace natural gas if utilized by a nearby industry, or fuel infrared heaters to reduce seasonal heating needs otherwise met by fossil fuel powered electrical generation. 7-1

24 SECTION 8 FINDINGS AND CONCLUSIONS FINDINGS Based on current records and LFG model runs, recoverable LFG is currently and will continue to be available at the Lee s Summit Sanitary Landfill to levels which would support various technologies. The current collection system recovery levels of 200 scfm will support the scenarios considered in this study listed below. Microturbine Applications 60 kw Microturbines 90 kw Microturbines 120 kw Microturbines 150 kw Microturbines 60 kw Microturbines with Heat Recovery 90 kw Microturbines with Heat Recovery 120 kw Microturbines with Heat Recovery Medium-Btu Applications Infra-red heaters in Maintenance Building Expansions to the well field would be required to fuel the 500 kw reciprocating engine application or a dedicated medium-btu end use project. Only the 120 kw microturbine with heat recovery and the infra-red heater projects show a positive NPV when analyzed for ten year periods so these two projects should top of the list for further consideration. American Foods is interested in further discussions of LFG powering of a dedicated generator to meet their 300 kw base load. The regulatory limitations on providing offsite power could prohibit such a project and the financial limitations on compressing and sending LFG offsite to a dedicated generator would also be significant. Non-economic related benefits should also be considered on these projects. Additional incentives that can make LFG recovery projects desirable include: Good Public Relations and Environmental Control - Because they utilize an otherwise wasted resource, and also help to prevent air pollution, LFG utilization projects can provide positive public relations for the landfill owner. Even if the economics are not favorable, this non-fiscal incentive may be enough reason to pursue a LFG utilization project. 8-1

25 LFG as a source of Green Power - Growth in the market for renewable energy, or "green power", is generating increasing interest in cost-effective and accepted sources such as LFG. The demand for green power offers a number of opportunities to develop environmentally beneficial landfill gas-to-energy projects that reduce emissions of greenhouse gas and other air pollutants from landfills while providing a cost-effective and readily available source of clean energy. LFG is a valuable green power source as it directly reduces greenhouse gas emissions, causes additional reductions in greenhouse gas emissions and air pollution by offsetting the use of non-renewable resources, and directly improves local air quality. Opportunities to generate financing or additional income from green power projects include utility green pricing schemes, selling power directly into the grid at market prices, selling tradable renewable energy certificates ( green tags), and trading emissions reduction credits either directly or through brokerages. In Hawaii, for example, the Hawaiian Electric Company and its subsidiaries offers a Sun Power for Schools green pricing program for solar power use in public schools. Tax Credits or Grants - If tax credits are available from the government, the economics for LFG recovery can improve substantially. An example of these are tax credits for generating power from clean or renewable fuels, or for installing environmental controls that are more stringent than those required by law. In addition to credits, the federal government, states, and foundations provide grants of fixed amounts to help fund projects that have a public benefit. Grant programs applicable to LFG projects are increasingly available, especially in states that have restructured their electricity markets. Renewable Energy Portfolio Standards for Power Marketers In some states, retail sellers of electricity are required to include a specific percentage of renewable energy as part of their power portfolio. Such requirements include utilities that may also be direct electricity marketers. Under such a standard, the power marketer can either own and generate renewable energy or purchase it from another renewable energy generating facility. A Missouri municipal electric utility is currently paying over $0.40 per kwh to help it reach its portfolio s green power goal. CONCLUSIONS This study finds that LFGTE applications at the Lee s Summit Sanitary Landfill are feasible in several different forms and capital commitment levels. Specifically, three projects with net present value were identified: Direct use medium BTU fuel 120 kw microturbine plant with heat recovery Infrared heating of the Maintenance Facility 8-2

26 The direct use medium BTU fuel option offers the greatest economic benefit, but unfortunately it lacks a local energy end user. This project cannot occur without an end user whose usage closely corresponds with the landfill s LFG output. There are several other potential projects in the Kansas City metro area that lack such appropriate end users. The 120 kw microturbine with heat recovery project is viable technically and economically, but the 120 kw may need to be downsized to under 100 kw to ensure the acceptability by Aquila according to their literature on qualifying facilities. The 90 kw microturbine with heat recovery project is marginal, but at 8.5 years, it does show one of the shorter payback periods. An investment of approximately $600,000 would be required for this high visibility green project. The infrared heating project requires a capital investment of under $200,000. This project shows a positive return on a creative, yet proven technology. SCS recommends that the City consider implementing either the 90 kw microturbine project with heat recovery or the LFG-fired infrared heaters to heat the Maintenance Facility. 8-3

27

28 APPENDIX A FINANCIAL ANALYSES OF TECHNOLOGY OPTIONS

29 TABLE A-7: 120 kw MICROTURBINE w/ HEAT-- CASH FLOW POTENTIAL ENERGY CONSUMED (kwh/yr) 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 ACTUAL ENERGY PURCHASED (kwh/yr) 23,465 23,465 23,465 23,465 23,465 23,465 23,465 23,465 23,465 23,465 ENERGY PRODUCED (kwh/yr) 963, , , , , , , , , ,600 SAVINGS w/ cogen (kwh/yr) 1,301,065 1,301,065 1,301,065 1,301,065 1,301,065 1,301,065 1,301,065 1,301,065 1,301,065 1,301,065 OFFSITE ENERGY SALES (kwh/yr) 228, , , , , , , , , ,715 ONSITE ENERGY SALES RATE ($/kwh) $0.065 $0.067 $0.069 $0.071 $0.073 $0.075 $0.078 $0.080 $0.082 $0.085 OFFSITE ENERGY SALES RATE ($/kwh) $0.032 $0.033 $0.034 $0.035 $0.036 $0.037 $0.038 $0.039 $0.040 $ ANNUAL UTILITY REVENUE $7,227 $7,444 $7,668 $7,898 $8,134 $8,379 $8,630 $8,889 $9,155 $9,430 COGENERATION SAVINGS $84,569 $87,106 $89,719 $92,411 $95,183 $98,039 $100,980 $104,009 $107,130 $110,344 ANNUAL REVENUES/SAVINGS $91,797 $94,551 $97,387 $100,309 $103,318 $106,417 $109,610 $112,898 $116,285 $119,774 LFG CONSUMED (scfm) LFG RATE ($/MMBtu) ANNUAL LFG COST $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ANNUAL NON-FUEL O&M COST $19,272 $19,850 $20,446 $21,059 $21,691 $22,342 $23,012 $23,702 $24,413 $25,146 TOTAL ANNUAL OPERATING COST $19,272 $19,850 $20,446 $21,059 $21,691 $22,342 $23,012 $23,702 $24,413 $25,146 EBITDA $72,525 $74,700 $76,941 $79,250 $81,627 $84,076 $86,598 $89,196 $91,872 $94,628 PRINCIPAL EXPENSE $51,849 $53,923 $56,079 $58,323 $60,656 $63,082 $65,605 $68,229 $70,958 $73,797 INTEREST EXPENSE $24,900 $22,826 $20,669 $18,426 $16,093 $13,667 $11,144 $8,519 $5,790 $2,952 $76,749 $76,749 $76,749 $76,749 $76,749 $76,749 $76,749 $76,749 $76,749 $76, CASH FLOW PROJECTION ($4,224) ($2,048) $193 $2,501 $4,878 $7,327 $9,850 $12,448 $15,123 $17,880 KEY ASSUMPTIONS: NET PLANT CAPACITY (kw) 55 RETAIL ENERGY RATE ($/kwh) $0.065 ANNUAL ENERGY SALES (kwh/yr) 23,465 UTILITY AVOIDED COST ($/kwh) $0.032 ENERGY PRICE ESCALATION 3.0% STANDBY/BACK-UP CHARGE $0 RENEWABLE ENERGY CREDIT $0.000 NET PLANT HEAT RATE (Btu/kWh)(HHV) 15,400 BASE YEAR NON-FUEL O&M ($/kwh) $0.02 FUEL CONSUMPTION (MMBtu/hr) 0.8 NON-FUEL COST ESCALATION 3.0% FUEL CONSUMPTION (scfm at 50% CH4) 28 FUEL PURCHASE RATE $0.00 FUEL ESCALATION RATE 0.0% PLANT COST $485,000 INTEREST RATE ON DEBT 4% PIPELINE COST $137,500 $622,500 CAPITAL GRANT $0 DEBT SERVICE (years) 10 NET CAPITAL COST $622,500 NET PRESENT VALUE (NPV) $43,691 CAPITAL INVESTMENT $0 DEBT FINANCED $622,500

30 TABLE A-6: 90 kw MICROTURBINE w/ HEAT-- CASH FLOW POTENTIAL ENERGY CONSUMED (kwh/yr) 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 ACTUAL ENERGY PURCHASED (kwh/yr) 186, , , , , , , , , ,457 ENERGY PRODUCED (kwh/yr) 722, , , , , , , , , ,700 SAVINGS w/ cogen (kwh/yr) 1,138,073 1,138,073 1,138,073 1,138,073 1,138,073 1,138,073 1,138,073 1,138,073 1,138,073 1,138,073 OFFSITE ENERGY SALES (kwh/yr) 62,160 62,160 62,160 62,160 62,160 62,160 62,160 62,160 62,160 62,160 ONSITE ENERGY SALES RATE ($/kwh) $0.065 $0.067 $0.069 $0.071 $0.073 $0.075 $0.078 $0.080 $0.082 $0.085 OFFSITE ENERGY SALES RATE ($/kwh) $0.032 $0.033 $0.034 $0.035 $0.036 $0.037 $0.038 $0.039 $0.040 $ ANNUAL UTILITY REVENUE $1,964 $2,023 $2,084 $2,146 $2,211 $2,277 $2,345 $2,416 $2,488 $2,563 COGENERATION SAVINGS $73,975 $76,194 $78,480 $80,834 $83,259 $85,757 $88,330 $90,980 $93,709 $96,520 ANNUAL REVENUES/SAVINGS $75,939 $78,217 $80,564 $82,981 $85,470 $88,034 $90,675 $93,395 $96,197 $99,083 LFG CONSUMED (scfm) LFG RATE ($/MMBtu) ANNUAL LFG COST $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ANNUAL NON-FUEL O&M COST $14,454 $14,888 $15,334 $15,794 $16,268 $16,756 $17,259 $17,777 $18,310 $18,859 TOTAL ANNUAL OPERATING COST $14,454 $14,888 $15,334 $15,794 $16,268 $16,756 $17,259 $17,777 $18,310 $18,859 EBITDA $61,485 $63,330 $65,229 $67,186 $69,202 $71,278 $73,416 $75,619 $77,887 $80,224 PRINCIPAL EXPENSE $48,517 $50,458 $52,476 $54,575 $56,758 $59,028 $61,389 $63,845 $66,399 $69,055 INTEREST EXPENSE $23,300 $21,359 $19,341 $17,242 $15,059 $12,789 $10,428 $7,972 $5,418 $2,762 $71,817 $71,817 $71,817 $71,817 $71,817 $71,817 $71,817 $71,817 $71,817 $71, CASH FLOW PROJECTION ($10,332) ($8,487) ($6,588) ($4,631) ($2,615) ($539) $1,599 $3,802 $6,070 $8,407 KEY ASSUMPTIONS: NET PLANT CAPACITY (kw) 55 RETAIL ENERGY RATE ($/kwh) $0.065 ANNUAL ENERGY SALES (kwh/yr) 186,457 UTILITY AVOIDED COST ($/kwh) $0.032 ENERGY PRICE ESCALATION 3.0% STANDBY/BACK-UP CHARGE $0 RENEWABLE ENERGY CREDIT $0.000 NET PLANT HEAT RATE (Btu/kWh)(HHV) 15,400 BASE YEAR NON-FUEL O&M ($/kwh) $0.02 FUEL CONSUMPTION (MMBtu/hr) 0.8 NON-FUEL COST ESCALATION 3.0% FUEL CONSUMPTION (scfm at 50% CH4) 28 FUEL PURCHASE RATE $0.00 FUEL ESCALATION RATE 0.0% PLANT COST $445,000 INTEREST RATE ON DEBT 4% PIPELINE COST $137,500 $582,500 CAPITAL GRANT $0 DEBT SERVICE (years) 10 NET CAPITAL COST $582,500 NET PRESENT VALUE (NPV) -$15,610 CAPITAL INVESTMENT $0 DEBT FINANCED $582,500

31 TABLE A-5: 60 kw MICROTURBINE w/ HEAT-- CASH FLOW POTENTIAL ENERGY CONSUMED (kwh/yr 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 ACTUAL ENERGY PURCHASED (kwh/yr 483, , , , , , , , , ,735 ENERGY PRODUCED (kwh/yr) 481, , , , , , , , , ,800 SAVINGS w/ cogen (kwh/yr) 840, , , , , , , , , ,795 OFFSITE ENERGY SALES (kwh/yr) 1,840 1,840 1,840 1,840 1,840 1,840 1,840 1,840 1,840 1,840 ONSITE ENERGY SALES RATE ($/kwh $0.065 $0.067 $0.069 $0.071 $0.073 $0.075 $0.078 $0.080 $0.082 $0.085 OFFSITE ENERGY SALES RATE ($/kwh) $0.032 $0.033 $0.034 $0.035 $0.036 $0.037 $0.038 $0.039 $0.040 $ ANNUAL UTILITY REVENUE $58 $60 $62 $64 $65 $67 $69 $72 $74 $76 COGENERATION SAVINGS $54,652 $56,291 $57,980 $59,719 $61,511 $63,356 $65,257 $67,215 $69,231 $71,308 ANNUAL REVENUES/SAVINGS $54,710 $56,351 $58,042 $59,783 $61,576 $63,424 $65,326 $67,286 $69,305 $71,384 LFG CONSUMED (scfm) LFG RATE ($/MMBtu) ANNUAL LFG COST $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ANNUAL NON-FUEL O&M COST $9,636 $9,925 $10,223 $10,530 $10,845 $11,171 $11,506 $11,851 $12,207 $12,573 TOTAL ANNUAL OPERATING COST $9,636 $9,925 $10,223 $10,530 $10,845 $11,171 $11,506 $11,851 $12,207 $12,573 EBITDA $45,074 $46,426 $47,819 $49,253 $50,731 $52,253 $53,820 $55,435 $57,098 $58,811 PRINCIPAL EXPENSE $41,021 $42,662 $44,368 $46,143 $47,989 $49,908 $51,904 $53,981 $56,140 $58,385 INTEREST EXPENSE $19,700 $18,059 $16,353 $14,578 $12,732 $10,813 $8,816 $6,740 $4,581 $2,335 $60,721 $60,721 $60,721 $60,721 $60,721 $60,721 $60,721 $60,721 $60,721 $60, CASH FLOW PROJECTION ($15,647) ($14,295) ($12,902) ($11,467) ($9,990) ($8,468) ($6,900) ($5,286) ($3,623) ($1,910) KEY ASSUMPTIONS: NET PLANT CAPACITY (kw 55 RETAIL ENERGY RATE ($/kwh $0.065 ANNUAL ENERGY SALES (kwh/yr 483,735 UTILITY AVOIDED COST ($/kwh $0.032 ENERGY PRICE ESCALATION 3.0% STANDBY/BACK-UP CHARGE $0 RENEWABLE ENERGY CREDIT $0.000 NET PLANT HEAT RATE (Btu/kWh)(HHV 15,400 BASE YEAR NON-FUEL O&M ($/kwh) $0.02 FUEL CONSUMPTION (MMBtu/hr) 0.8 NON-FUEL COST ESCALATION 3.0% FUEL CONSUMPTION (scfm at 50% CH4 28 FUEL PURCHASE RATE $0.00 FUEL ESCALATION RATE 0.0% PLANT COST $355,000 INTEREST RATE ON DEBT 4% PIPELINE COST $137,500 $492,500 CAPITAL GRANT $0 DEBT SERVICE (years) 10 NET CAPITAL COST $492,500 NET PRESENT VALUE (NPV) -74,402 CAPITAL INVESTMENT $0 DEBT FINANCED $492,500

32 TABLE A-4: 150 kw MICROTURBINE-- CASH FLOW PROJECTION POWER CONSUMED (kwh/yr) 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 POWER PRODUCED (kwh/yr) 1,204,500 1,204,500 1,204,500 1,204,500 1,204,500 1,204,500 1,204,500 1,204,500 1,204,500 1,204,500 ONSITE POWER SALES (kwh/yr) 975, , , , , , , , , ,890 OFFSITE POWER SALES (kwh/yr) 228, , , , , , , , , ,610 ONSITE POWER SALES RATE ($/kwh) $0.065 $0.067 $0.069 $0.071 $0.073 $0.075 $0.078 $0.080 $0.082 $0.085 OFFSITE POWER SALES RATE ($/kwh) $0.032 $0.033 $0.033 $0.033 $0.033 $0.033 $0.033 $0.033 $0.033 $ ANNUAL UTILITY REVENUE $70,657 $72,777 $74,737 $76,756 $78,835 $80,977 $83,183 $85,455 $87,796 $90,206 LFG CONSUMED (scfm) LFG RATE ($/MMBtu) ANNUAL LFG COST $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ANNUAL NON-FUEL O&M COST $24,090 $24,813 $25,557 $26,324 $27,114 $27,927 $28,765 $29,628 $30,516 $31,432 TOTAL ANNUAL OPERATING COST $24,090 $24,813 $25,557 $26,324 $27,114 $27,927 $28,765 $29,628 $30,516 $31,432 EBITDA $46,567 $47,964 $49,180 $50,432 $51,722 $53,050 $54,418 $55,828 $57,279 $58,774 PRINCIPAL EXPENSE $43,520 $45,260 $47,071 $48,954 $50,912 $52,948 $55,066 $57,269 $59,559 $61,942 INTEREST EXPENSE $20,900 $19,159 $17,349 $15,466 $13,508 $11,471 $9,353 $7,151 $4,860 $2,478 $64,420 $64,420 $64,420 $64,420 $64,420 $64,420 $64,420 $64,420 $64,420 $64, CASH FLOW PROJECTION ($17,853) ($16,456) ($15,240) ($13,988) ($12,698) ($11,370) ($10,001) ($8,592) ($7,140) ($5,645) KEY ASSUMPTIONS: NET PLANT CAPACITY (kw) 138 RETAIL POWER RATE ($/kwh) $0.065 ANNUAL POWER SALES (kwh/yr) 1,324,530 UTILITY AVOIDED COST ($/kwh) $0.032 POWER PRICE ESCALATION 3.0% STANDBY/BACK-UP CHARGE $0 RENEWABLE ENERGY CREDIT $0.000 NET PLANT HEAT RATE (Btu/kWh)(HHV) 15,400 BASE YEAR NON-FUEL O&M ($/kwh) $0.02 FUEL CONSUMPTION (MMBtu/hr) 2.1 NON-FUEL COST ESCALATION 3.0% FUEL CONSUMPTION (scfm at 50% CH4) 71 FUEL PURCHASE RATE $0.00 FUEL ESCALATION RATE 0.0% SKID AND PLANT COST $435,000 INTEREST RATE ON DEBT 4% TRANSMISSION COST $87,500 $522,500 CAPITAL GRANT $0 DEBT SERVICE (years) 10 NET CAPITAL COST $522,500 NET PRESENT VALUE (NPV) -$96,169 CAPITAL INVESTMENT $0 DEBT FINANCED $522,500

33 TABLE A-3: 120 kw MICROTURBINE-- CASH FLOW PROJECTION POWER CONSUMED (kwh/yr) 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 POWER PRODUCED (kwh/yr) 963, , , , , , , , , ,600 ONSITE POWER SALES (kwh/yr) 879, , , , , , , , , ,410 OFFSITE POWER SALES (kwh/yr) 84,190 84,190 84,190 84,190 84,190 84,190 84,190 84,190 84,190 84,190 ONSITE POWER SALES RATE ($/kwh) $0.065 $0.067 $0.069 $0.071 $0.073 $0.075 $0.078 $0.080 $0.082 $0.085 OFFSITE POWER SALES RATE ($/kwh) $0.032 $0.033 $0.033 $0.033 $0.033 $0.033 $0.033 $0.033 $0.033 $ ANNUAL UTILITY REVENUE $59,822 $61,617 $63,383 $65,202 $67,076 $69,006 $70,994 $73,042 $75,151 $77,323 LFG CONSUMED (scfm) LFG RATE ($/MMBtu) ANNUAL LFG COST $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ANNUAL NON-FUEL O&M COST $19,272 $19,850 $20,446 $21,059 $21,691 $22,342 $23,012 $23,702 $24,413 $25,146 TOTAL ANNUAL OPERATING COST $19,272 $19,850 $20,446 $21,059 $21,691 $22,342 $23,012 $23,702 $24,413 $25,146 EBITDA $40,550 $41,767 $42,937 $44,143 $45,385 $46,665 $47,982 $49,340 $50,738 $52,178 PRINCIPAL EXPENSE $40,188 $41,795 $43,467 $45,206 $47,014 $48,895 $50,850 $52,885 $55,000 $57,200 INTEREST EXPENSE $19,300 $17,692 $16,021 $14,282 $12,474 $10,593 $8,637 $6,603 $4,488 $2,288 $59,488 $59,488 $59,488 $59,488 $59,488 $59,488 $59,488 $59,488 $59,488 $59, CASH FLOW PROJECTION ($18,938) ($17,721) ($16,551) ($15,345) ($14,103) ($12,823) ($11,505) ($10,148) ($8,750) ($7,310) KEY ASSUMPTIONS: NET PLANT CAPACITY (kw 110 RETAIL POWER RATE ($/kwh) $0.065 ANNUAL POWER SALES (kwh/yr 1,324,530 UTILITY AVOIDED COST ($/kwh $0.032 POWER PRICE ESCALATION 3.0% STANDBY/BACK-UP CHARGE $0 RENEWABLE ENERGY CREDIT $0.000 NET PLANT HEAT RATE (Btu/kWh)(HHV 15,400 BASE YEAR NON-FUEL O&M ($/kwh) $0.02 FUEL CONSUMPTION (MMBtu/hr) 1.7 NON-FUEL COST ESCALATION 3.0% FUEL CONSUMPTION (scfm at 50% CH4 56 FUEL PURCHASE RATE $0.00 FUEL ESCALATION RATE 0.0% SKID AND PLANT COST $395,000 INTEREST RATE ON DEBT 4% TRANSMISSION COST $87,500 $482,500 CAPITAL GRANT $0 DEBT SERVICE (years) 10 NET CAPITAL COST $482,500 NET PRESENT VALUE (NPV) -$107,110 CAPITAL INVESTMENT $0 DEBT FINANCED $482,500

34 TABLE A-2: 90 kw MICROTURBINE-- CASH FLOW PROJECTION ENERGY CONSUMED (kwh/yr) 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 ENERGY PRODUCED (kwh/yr) 722, , , , , , , , , ,700 ONSITE ENERGY SALES (kwh/yr) 722, , , , , , , , , ,700 OFFSITE ENERGY SALES (kwh/yr) ONSITE ENERGY SALES RATE ($/kw $0.065 $0.067 $0.069 $0.071 $0.074 $0.076 $0.078 $0.081 $0.083 $0.086 OFFSITE ENERGY SALES RATE ($/kw $0.032 $0.032 $0.032 $0.032 $0.032 $0.032 $0.032 $0.032 $0.032 $ ANNUAL UTILITY REVENUE $46,976 $48,455 $49,982 $51,556 $53,180 $54,855 $56,583 $58,365 $60,204 $62,100 LFG CONSUMED (scfm) LFG RATE ($/MMBtu) ANNUAL LFG COST $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ANNUAL NON-FUEL O&M COST $14,454 $14,888 $15,334 $15,794 $16,268 $16,756 $17,259 $17,777 $18,310 $18,859 TOTAL ANNUAL OPERATING COST $14,454 $14,888 $15,334 $15,794 $16,268 $16,756 $17,259 $17,777 $18,310 $18,859 EBITDA $32,522 $33,568 $34,647 $35,762 $36,912 $38,099 $39,324 $40,589 $41,894 $43,241 PRINCIPAL EXPENSE $34,982 $36,381 $37,837 $39,350 $40,924 $42,561 $44,264 $46,034 $47,876 $49,791 INTEREST EXPENSE $16,800 $15,401 $13,945 $12,432 $10,858 $9,221 $7,519 $5,748 $3,907 $1,992 $51,782 $51,782 $51,782 $51,782 $51,782 $51,782 $51,782 $51,782 $51,782 $51, CASH FLOW PROJECTION ($19,261) ($18,215) ($17,135) ($16,020) ($14,870) ($13,683) ($12,458) ($11,193) ($9,888) ($8,541) KEY ASSUMPTIONS: NET PLANT CAPACITY (kw) 83 RETAIL ENERGY RATE ($/kwh) $0.065 ANNUAL ENERGY SALES (kwh/yr) 722,700 UTILITY AVOIDED COST ($/kwh) $0.032 ENERGY PRICE ESCALATION 3.0% STANDBY/BACK-UP CHARGE $0 RENEWABLE ENERGY CREDIT $0.000 NET PLANT HEAT RATE (Btu/kWh)(HHV) 15,400 BASE YEAR NON-FUEL O&M ($/kwh) $0.02 FUEL CONSUMPTION (MMBtu/hr) 1.3 NON-FUEL COST ESCALATION 3.0% FUEL CONSUMPTION (scfm at 50% CH4) 42 FUEL PURCHASE RATE $0.00 FUEL ESCALATION RATE 0.0% SKID AND PLANT COST $345,000 INTEREST RATE ON DEBT 4% TRANSMISSION COST $75,000 $420,000 CAPITAL GRANT $0 DEBT SERVICE (years) 10 NET CAPITAL COST $420,000 NET PRESENT VALUE (NPV) -$275,847 CAPITAL INVESTMENT $0 DEBT FINANCED $420,000

35 TABLE A-1: 60 kw MICROTURBINE-- CASH FLOW PROJECTION ENERGY CONSUMED (kwh/yr) 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 ENERGY PRODUCED (kwh/yr) 481, , , , , , , , , ,800 ONSITE ENERGY SALES (kwh/yr) 481, , , , , , , , , ,800 OFFSITE ENERGY SALES (kwh/yr) ONSITE ENERGY SALES RATE ($/kwh) $0.065 $0.067 $0.069 $0.071 $0.073 $0.075 $0.078 $0.080 $0.082 $0.085 OFFSITE ENERGY SALES RATE ($/kwh) $0.032 $0.032 $0.032 $0.032 $0.032 $0.032 $0.032 $0.032 $0.032 $ ANNUAL UTILITY REVENUE $31,317 $32,257 $33,224 $34,221 $35,248 $36,305 $37,394 $38,516 $39,671 $40,862 LFG CONSUMED (scfm) LFG RATE ($/MMBtu) ANNUAL LFG COST $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ANNUAL NON-FUEL O&M COST $9,636 $9,925 $10,223 $10,530 $10,845 $11,171 $11,506 $11,851 $12,207 $12,573 TOTAL ANNUAL OPERATING COST $9,636 $9,925 $10,223 $10,530 $10,845 $11,171 $11,506 $11,851 $12,207 $12,573 EBITDA $21,681 $22,331 $23,001 $23,691 $24,402 $25,134 $25,888 $26,665 $27,465 $28,289 PRINCIPAL EXPENSE $32,692 $33,999 $35,359 $36,774 $38,245 $39,774 $41,365 $43,020 $44,741 $46,530 INTEREST EXPENSE $15,700 $14,392 $13,032 $11,618 $10,147 $8,617 $7,026 $5,372 $3,651 $1,861 $48,392 $48,392 $48,392 $48,392 $48,392 $48,392 $48,392 $48,392 $48,392 $48, CASH FLOW PROJECTION ($26,711) ($26,060) ($25,390) ($24,700) ($23,990) ($23,257) ($22,503) ($21,727) ($20,927) ($20,103) KEY ASSUMPTIONS: NET PLANT CAPACITY (kw) 55 RETAIL ENERGY RATE ($/kwh) $0.065 ANNUAL ENERGY SALES (kwh/yr) 481,800 UTILITY AVOIDED COST ($/kwh) $0.032 ENERGY PRICE ESCALATION 3.0% STANDBY/BACK-UP CHARGE $0 RENEWABLE ENERGY CREDIT $0.000 NET PLANT HEAT RATE (Btu/kWh)(HHV) 15,400 BASE YEAR NON-FUEL O&M ($/kwh) $0.02 FUEL CONSUMPTION (MMBtu/hr) 0.8 NON-FUEL COST ESCALATION 3.0% FUEL CONSUMPTION (scfm at 50% CH4) 28 FUEL PURCHASE RATE $0.00 FUEL ESCALATION RATE 0.0% SKID AND PLANT COST $305,000 INTEREST RATE ON DEBT 4% TRANSMISSION COST $87,500 $392,500 CAPITAL GRANT $0 DEBT SERVICE (years) 10 NET CAPITAL COST $392,500 NET PRESENT VALUE (NPV) -$185,406 CAPITAL INVESTMENT $0 DEBT FINANCED $392,500

36 TABLE A-8: INFRARED HEATING -- CASH FLOW POTENTIAL ENERGY CONSUMED 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 1,324,530 ACTUAL ENERGY PURCHASED (kw 974, , , , , , , , , ,396 SAVINGS w/ Infrared (kwh/yr) 350, , , , , , , , , ,134 ONSITE ENERGY SALES RATE ($/k $0.065 $0.067 $0.069 $0.071 $0.073 $0.075 $0.078 $0.080 $0.082 $0.085 OFFSITE ENERGY SALES RATE ($/ $0.032 $0.033 $0.034 $0.035 $0.036 $0.037 $0.038 $0.039 $0.040 $ ANNUAL REVENUES /SAVINGS $22,759 $23,441 $24,145 $24,869 $25,615 $26,384 $27,175 $27,990 $28,830 $29,695 LFG CONSUMED (scfm) LFG RATE ($/MMBtu) ANNUAL LFG COST $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 ANNUAL NON-FUEL O&M COST $2,000 $2,060 $2,122 $2,185 $2,251 $2,319 $2,388 $2,460 $2,534 $2,610 TOTAL ANNUAL OPERATING CO $2,000 $2,060 $2,122 $2,185 $2,251 $2,319 $2,388 $2,460 $2,534 $2,610 EBITDA $20,759 $21,381 $22,023 $22,684 $23,364 $24,065 $24,787 $25,531 $26,297 $27,085 PRINCIPAL EXPENSE $15,504 $16,124 $16,769 $17,440 $18,138 $18,863 $19,618 $20,402 $21,219 $22,067 INTEREST EXPENSE $7,446 $6,826 $6,181 $5,510 $4,812 $4,087 $3,332 $2,548 $1,731 $883 $22,950 $22,950 $22,950 $22,950 $22,950 $22,950 $22,950 $22,950 $22,950 $22, CASH FLOW PROJECTION ($2,191) ($1,569) ($927) ($266) $414 $1,115 $1,837 $2,581 $3,347 $4,135 KEY ASSUMPTIONS: NET PLANT CAPACITY (kw) 55 RETAIL ENERGY RATE ($/kwh) $0.065 ANNUAL ENERGY SALES (kwh/yr) 974,396 UTILITY AVOIDED COST ($/kwh) $0.032 ENERGY PRICE ESCALATION 3.0% STANDBY/BACK-UP CHARGE $0 RENEWABLE ENERGY CREDIT $0.000 NET PLANT HEAT RATE (Btu/kWh) 15,400 BASE YEAR NON-FUEL O&M ($/kwh) $0.02 FUEL CONSUMPTION (MMBtu/hr) 0.8 NON-FUEL COST ESCALATION 3.0% FUEL CONSUMPTION (scfm at 50% 28 FUEL PURCHASE RATE $0.00 FUEL ESCALATION RATE 0.0% INTEREST RATE ON DEBT 4% COST $186,145 CAPITAL GRANT $0 DEBT SERVICE (years) 10 NET CAPITAL COST $186,145 NET PRESENT VALUE (NPV) $4,845 CAPITAL INVESTMENT $0 DEBT FINANCED $186,145

37 APPENDIX B APPLICABLE REGULATIONS AND POLICIES

38 FERC

39 MISSOURI PSC

40 APPENDIX C AQUILA OPERATING STANDARDS FOR GENERATORS, SMALL, PARALLELING

41 APPENDIX D TECHNOLOGY INFORMATION

42 CAPSTONE C30

43

44

45 ROBERTS GORDON VANTAGE II

46 APPENDIX E PHOTOGRAPHS

47 Photograph 1. Potential Energy User: Maintenance Facility. Photograph 2. Blower Flare Location of Future Compressor Skid.

48 Photograph 3. AHU-1 Mezzanine Level. Photograph 4. Heating ducts from AHU-3 serves West Floor.

49 Photograph 5. AHU-3. Photograph 6. Heating ducts from AHU-2. serves East Floor.