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AEEC - CPL Landfill Gas CHP Project REF Round 14 Application Final SIGNED
Alaska Electric & Energy Cooperative, Inc. 3977 Lake Street Homer, Alaska 99603 (907) 235-8551 Alaska Electric & Energy Cooperative, Inc. (907) 235-8551 January 17, 2022 AEA 15003 Renewable Energy Grant Application Alaska Energy Authority 813 W. Northern Lights Blvd. Anchorage, AK 99503 Dear Alaska Energy Authority: RE: Renewable Energy Fund Round XIV Grant Application Homer Electric Association, Inc. (HEA) through its generation subsidiary, Alaska Electric and Energy Cooperative, Inc. (AEEC) appreciates the opportunity to present the enclosed Renewable Energy Fund Round XIV Grant Application for final design and permitting for the AEEC – CPL Landfill Gas CHP Project on the Kenai Peninsula. This project is an important step towards Homer Electric Association’s and the State of Alaska’s goals to reach 50% renewable energy and it has the potential to do so while reducing electrical costs and save the Borough money. The project will collect landfill gas, a potent greenhouse gas, and generate electricity. Further the waste heat from the engine generator set will be captured and utilized to run the landfill’s leachate evaporator, saving the Kenai Peninsula Borough over a million dollars in natural gas costs per year. This project is beneficial to HEA’s owner-members, the residents of the Kenai Peninsula Borough and the environment. Thank you for this opportunity. Please feel free to contact me with questions at (907) 283-2375. Sincerely, Mikel Salzetti Manager of Renewable Energy Development Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 1 of 33 11/16/2021 Application Forms and Instructions This instruction page and the following grant application constitutes the Grant Application Form for Round 14 of the Renewable Energy Fund (REF). A separate application form is available for projects with a primary purpose of producing heat (see Request for Applications (RFA) Section 1.5). This is the standard form for all other projects, including projects that will produce heat and electricity. An electronic version of the RFA and both application forms is available online at: https://www.akenergyauthority.org/What-We-Do/Grants-Loans/Renewable-Energy-Fund/2021- REF-Application. What follows are some basic information and instructions for this application: •The Alaska Energy Authority (AEA) expects this application to be used as part of a two-year solicitation cycle with an opt-out provision in the second year of the cycle. •If you are applying for grants for more than one project, provide separate application forms for each project. •Multiple phases (e.g. final design, construction) for the same project may be submitted as one application. •If you are applying for grant funding for more than one phase of a project, provide milestones and grant budget for each phase of the project (see Sections 3.1 and 3.2.2). •In order to ensure that grants provide sufficient benefit to the public, AEA may limit recommendations for grants to preliminary development phases in accordance with 3 Alaska Administrative Code (ACC) 107.605(1). •If some work has already been completed on your project and you are requesting funding for an advanced phase, submit information sufficient to demonstrate that the preceding phases are completed and funding for an advanced phase is warranted. Supporting documentation may include, but is not limited to, reports, conceptual or final designs, models, photos, maps, proof of site control, utility agreements, business and operation plans, power sale agreements, relevant data sets, and other materials. Please provide a list of supporting documents in Section 11 of this application and attach the documents to your application. •If you have additional information or reports you would like the Authority to consider in reviewing your application, either provide an electronic version of the document with your submission or reference a web link where it can be downloaded or reviewed. Please provide a list of additional information; including any web links, in Section 12 of this application and attach the documents to your application. For guidance on application best practices please refer to the resource-specific Best Practices Checklists; links to the checklists can be found in the appendices list at the end of the accompanying REF Round 14 RFA. •In the Sections below, please enter responses in the spaces provided. You may add additional rows or space to the form to provide sufficient space for the information, or attach additional sheets if needed. •If you need assistance with your application, please contact AEA’s Grants Coordinator by email at grants@akenergyauthority.org or by phone at (907) 771-3081. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 2 of 33 11/16/2021 REMINDER: •AEA is subject to the Public Records Act AS 40.25, and materials submitted to AEA may be subject to disclosure requirements under the act if no statutory exemptions apply. •All applications received will be posted on the Authority web site after final recommendations are made to the legislature. Please submit resumes as separate PDFs if the applicant would like those excluded from the web posting of this application. •In accordance with 3 AAC 107.630 (b) Applicants may request trade secrets or proprietary company data be kept confidential subject to review and approval by AEA. If you want information to be kept confidential the applicant must: o Request the information be kept confidential. o Clearly identify the information that is the trade secret or proprietary in their application. o Receive concurrence from the Authority that the information will be kept confidential. If the Authority determines it is not confidential, it will be treated as a public record in accordance with AS 40.25 or returned to the applicant upon request. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 3 of 33 11/16/2021 SECTION 1 – APPLICANT INFORMATION Please specify the legal grantee that will own, operate, and maintain the project upon completion. Name (Name of utility, IPP, local government, or other government entity) Alaska Electric & Energy Cooperative, Inc. Tax ID # 92-0177236 Date of last financial statement audit: December 31, 2020 Mailing Address: Physical Address: 3977 Lake Street, Homer, AK 99603 Same Telephone: Fax: Email: 907-283-2375 msalzetti@homerelectric.com 1.1 Applicant Point of Contact / Grants Coordinator Name: Mikel Salzetti Title: Manager of Renewable Energy Development Mailing Address: 3977 Lake Street, Homer, AK 99603 Telephone: Fax: Email: 907-283-2375 msalzetti@homerelectric.com 1.1.1 Applicant Signatory Authority Contact Information Name: Bradley P. Janorschke Title: General Manager Mailing Address: 3977 Lake Street, Homer, AK 99603 Telephone: Fax: Email: 907-283-2312 907-283-7122 bjanorschke@homerelectric.com 1.1.2 Applicant Alternate Points of Contact Name Telephone: Fax: Email: David Thomas 907-283-2364 dthomas@homerelectric.com Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 4 of 33 11/16/2021 1.2 Applicant Minimum Requirements Please check as appropriate. If applicants do not meet the minimum requirements, the application will be rejected. 1.2.1 Applicant Type ☒ An electric utility holding a certificate of public convenience and necessity under AS 42.05 CPCN #_640__, or ☐ An independent power producer in accordance with 3 AAC 107.695 (a) (1) CPCN #______, or ☐ A local government, or ☐ A governmental entity (which includes tribal councils and housing authorities) Additional minimum requirements ☒ 1.2.2 Attached to this application is formal approval and endorsement for the project by the applicant’s board of directors, executive management, or other governing authority. If the applicant is a collaborative grouping, a formal approval from each participant’s governing authority is necessary. (Indicate yes by checking the box) ☒ 1.2.3 As an applicant, we have administrative and financial management systems and follow procurement standards that comply with the standards set forth in the grant agreement (Section 3 of the RFA). (Indicate yes by checking the box) ☒ 1.2.4 If awarded the grant, we can comply with all terms and conditions of the award as identified in the Standard Grant Agreement template at https://www.akenergyauthority.org/What-We-Do/Grants-Loans/Renewable-Energy- Fund/2021-REF-Application (Any exceptions should be clearly noted and submitted with the application.) (Indicate yes by checking the box) ☒ 1.2.5 We intend to own and operate any project that may be constructed with grant funds for the benefit of the general public. If no please describe the nature of the project and who will be the primary beneficiaries. (Indicate yes by checking the box) Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 5 of 33 11/16/2021 SECTION 2 – PROJECT SUMMARY 2.1 Project Title Provide a 4 to 7 word title for your project. Type in the space below. AEEC / KPB CPL Landfill Gas CHP Project 2.2 Project Location 2.2.1 Location of Project – Latitude and longitude (preferred), street address, or community name. Latitude and longitude coordinates may be obtained from Google Maps by finding you project’s location on the map and then right clicking with the mouse and selecting “What is here? The coordinates will be displayed in the Google search window above the map in a format as follows: 61.195676.-149.898663. If you would like assistance obtaining this information, please contact AEA’s Grants Coordinator by email at grants@akenergyauthority.org or by phone at (907) 771- 3081. Latitude 60º26’39”N Longitude -151º06’40”W The Project would be located at the Kenai Peninsula Borough’s Central Peninsula Landfill near the existing Leachate Evaporator. 2.2.2 Community benefiting – Name(s) of the community or communities that will be the beneficiaries of the project. Kenai Peninsula Borough residence and Homer Electric Association members 2.3 Project Type Please check as appropriate. 2.3.1 Renewable Resource Type ☐Wind ☒Biomass or Biofuels (excluding heat-only) ☐Hydro, Including Run of River ☐Hydrokinetic ☐Geothermal, Excluding Heat Pumps ☐Transmission of Renewable Energy ☐Solar Photovoltaic ☐Storage of Renewable ☐Other (Describe)☐Small Natural Gas 2.3.2 Proposed Grant Funded Phase(s) for this Request (Check all that apply) Pre-Construction Construction ☐Reconnaissance ☒Final Design and Permitting ☐Feasibility and Conceptual Design ☐Construction Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 6 of 33 11/16/2021 2.4 Project Description Provide a brief, one-paragraph description of the proposed project. Homer Electric Association, Inc. (HEA) through its generation subsidiary Alaska Electric & Energy Cooperative, Inc. (AEEC) and in cooperation with the Kenai Peninsula Borough (KPB) propose the installation of a Combined Heat & Power Project at the KPB’s Central Peninsula Landfill (CPL). The proposed Project would generate electricity from collected landfill gas and initially supplemented with pipeline natural gas to generate up to 1.6 MW of power. The waste heat from the electric reciprocating engine generator would be captured and utilized to operate the CPL’s leachate evaporator which is currently fueled by natural gas from the ENSTAR system. Thus, eliminating or significantly reducing the CPL’s natural gas bill required to evaporate leachate. 2.5 Scope of Work Provide a short narrative for the scope of work detailing the tasks to be performed under this funding request. This should include work paid for by grant funds and matching funds or performed as in-kind match. AEEC in conjunction with the KPB has completed the feasibility analysis for the project which included a 25% drawing package, a Class 3 AACE Cost Estimate, a financial feasibility analysis, a fire code analysis and an electrical grid interconnect study. This funding request would fund the Final Design and Permitting Requirements (Phase III) for the Project. An engineering design firm would be competitively selected that would provide the final design drawings and specifications required to construct the Project. The funding request would also provide funding to refine project costs, develop required contracts with the Kenai Peninsula Borough and peruse required permits for Project construction. 2.6 Previous REF Applications for the Project See Section 1.15 of the RFA for the maximum per project cumulative grant award amount Round Submitted Title of application Application #, if known Did you receive a grant? Y/N Amount of REF grant awarded ($) NA Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 7 of 33 11/16/2021 SECTION 3 – Project Management, Development, and Operation 3.1 Schedule and Milestones Please fill out the schedule below (or attach a similar sheet) for the work covered by this funding request. Be sure to identify key tasks and decision points, including go/no go decisions, in your project along with estimated start and end dates for each of the milestones and tasks. Please clearly identify the beginning and ending of all phases (I. Reconnaissance, II. Feasibility and Conceptual Design, III. Final Design and Permitting, and IV. Construction) of your proposed project. See the RFA, Sections 2.3-2.6 for the recommended milestones for each phase. Add additional rows as needed. Task # Milestones Tasks Start Date End Date Deliverables 1 Contractor Solicitation Develop Design RFP 7/22 8/22 Final Design RFP Package 2 Contractor Solicitation Select Design Firm 8/22 9/22 Final Design Contract 3 Final Design 60% Design Package 9/22 3/23 60% Design Package 4 Final Design 90% Design Package 3/23 6/23 90% Design Package 5 Final Design 100% Design Package 6/23 9/23 100% Design Package 6 Cost Estimate Develop Final Engineers Estimate 9/23 11/23 Engineer Final Cost Estimate 7 Business and Operational Plans Negotiate Construction Agreement with KPB 11/23 3/24 Construction Agreement 8 Business and Operational Plans Negotiate an O&M Agreement with KPB 11/23 3/24 O&M Agreement 9 Business and Operational Plans Negotiate Btu Exchange Agreement with KPB 11/23 3/24 Btu Exchange Agreement 10 Permitting Secure Required Construction Permits 9/23 3/24 Permits Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 8 of 33 11/16/2021 3.2 Budget 3.2.1 Funding Sources Indicate the funding sources for the phase(s) of the project applied for in this funding request. Grant funds requested in this application $884,986 Cash match to be provideda $221,247 In-kind match to be provideda $ Energy efficiency match providedb $ Total costs for project phase(s) covered in application (sum of above) $1,106,233 Describe your financial commitment to the project and the source(s) of match. Indicate whether these matching funds are secured or pending future approvals. Describe the impact, if any, that the timing of additional funds would have on the ability to proceed with the grant. Per the attached Board of Directors Resolution, the Board has authorized funding of the indicated matching funds for this application. Also attached is a certification by the AEEC General Manager, Bradley P. Janorschke, that the Cooperative will honor the match amounts and is in a financial condition to do so. Both documents are included as Attachment C. The indicated match is a cash match. Although we have not put an estimated value to it, HEA/AEEC will also be providing internal labor (both direct & indirect) at no cost, as an In-Kind contribution to the Project. a Attach documentation for proof (see Section 1.18 of the Request for Applications) b See Section 8.2 of this application and Section 1.18 of the RFA for requirements for Energy Efficiency Match. 3.2.2 Cost Overruns Describe the plan to cover potential cost increases or shortfalls in funding. Cost over-runs would need to be covered by AEEC member equity and depending upon the amount of over-run authorized per HEA Management Directives. 3.2.3 Total Project Costs Indicate the anticipated total cost by phase of the project (including all funding sources). Use actual costs for completed phases. Indicate if the costs were actual or estimated. Reconnaissance [Actual/Estimated] $ Feasibility and Conceptual Design [Actual/Estimated] $151,700 Final Design and Permitting [Actual/Estimated] $1,106,233 Construction [Actual/Estimated] $11,427,383 Total Project Costs (sum of above) Estimated $12,685,316 Metering/Tracking Equipment [not included in project cost] Estimated $ 3.2.4 Funding Subsequent Phases If subsequent phases are required beyond the phases being applied for in this application, describe the anticipated sources of funding and the likelihood of receipt of those funds. • State and/or federal grants Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 9 of 33 11/16/2021 • Loans, bonds, or other financing options • Additional incentives (i.e. tax credits) • Additional revenue streams (i.e. green tag sales or other renewable energy subsidies or programs that might be available) It is anticipated that the balance of funds will come from a combination of financing, Federal grants, State grants, private grants and possibly direct pay tax incentives. As with all large projects, HEA/AEEC would examine current interest rates and loan terms from its two primary lenders National Rural Utilities Cooperative Finance Corporation (CFC) – a not-for- profit lender set up by its member electrical utilities and the USDA Rural Utilities Service (RUS) to achieve attractive financing if need. HEA / AEEC will apply for applicable federal, state grants and private grants. HEA has been and will continue to track (and advocate for) a direct-pay provision for ITCs and PTCs to be distributed directly to cooperatives and government entities currently contained in the pending BBB federal infrastructure bill. Renewable Energy Certificates and Green House Gas Certificates would be pursued and monetized. 3.2.3 Budget Forms Applications MUST include a separate worksheet for each project phase that was identified in Section 2.3.2 of this application — I. Reconnaissance, II. Feasibility and Conceptual Design, III. Final Design and Permitting, and IV. Construction. Please use the tables provided below to detail your proposed project’s total budget. Be sure to use one table for each phase of your project, and delete any unnecessary tables. The milestones and tasks should match those listed in 3.1 above. If you have any question regarding how to prepare these tables or if you need assistance preparing the application please feel free to contact AEA’s Grants Coordinator by email at grants@akenergyauthority.org or by phone at (907) 771-3081. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 10 of 33 11/16/2021 Phase 3 — Final Design and Permitting Milestone or Task Anticipated Completion Date RE- Fund Grant Funds Grantee Matching Funds Source of Matching Funds: Cash/In- kind/Federal Grants/Other State Grants/Other TOTALS (List milestones based on phase and type of project. See Sections 2.3 thru 2.6 of the RFA ) $ $ $ Contractor Solicitation 9/22 $44,250 $11,062 Cash $55,312 Final Design 9/23 $707,988 $176,997 Cash $884,985 Cost Estimate 11/23 $44,250 $11,062 Cash $55,312 Business & Operational Plans 3/24 $44,250 $11,062 Cash $55,312 Permitting 3/24 $44,250 $11,062 Cash $55,312 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ TOTALS $884,988 $221,245 $1,106,233 Budget Categories: Direct Labor & Benefits $ $ $ Travel & Per Diem $ $ $ Equipment $ $ $ Materials & Supplies $ $ $ Contractual Services $884,988 $221,245 $1,106,233 Construction Services $ $ $ Other $ $ $ TOTALS $884,988 $221,245 $1,106,233 Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 11 of 33 11/16/2021 3.2.4 Cost Justification Indicate the source(s) of the cost estimates used for the project budget, including costs for future phases not included in this application. As part of the feasibility analysis, Jacobs Engineering Group was selected through a competitive process to complete a 25% Design, a Class 3 AACE Cost Estimate and provide a financial feasibility analysis. The cost estimates for this grant application come from the Class 3 AACE Cost Estimate that was based upon the 25% design and completed by Jacobs Engineering as part of the feasibility analysis conducted for this project. The Jacobs Engineering Class 3 AACE Cost Estimate is included as Attachment E. 3.3 Project Communications 3.3.1 Project Progress Reporting Describe how you plan to monitor the progress of the project and keep AEA informed of the status. Who will be responsible for tracking the progress? What tools and methods will be used to track progress? The Project Manager will conduct regularly scheduled meetings with the selected engineering design firm to track progress, schedule and budget. Additionally, the selected design engineering firm will be required to submit formal 60, 90 & 100 percent design review packages for review and formal comment. Project management and financial control will issue reports to AEA on a mutually agreeable schedule throughout the life of the grant. These reports can be customized to meet AEA needs. 3.3.2 Financial Reporting Describe the controls that will be utilized to ensure that only costs that are reasonable, ordinary and necessary will be allocated to this project. Also discuss the controls in place that will ensure that no expenses for overhead, or any other unallowable costs will be requested for reimbursement from the REF Grant Program. HEA has a dedicated financial controller. Ms. Clymer, HEA’s Controller has acted as financial control for several other AEA awarded grants. HEA uses South Eastern Data Corporation (SEDC) for our financial services software to assist with accounting and f inical control systems. Every year, HEA’s and AEEC’s financial statements and accounting procedures are audited by an outside firm (which in recent years has been BDO USA, Inc). Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 12 of 33 11/16/2021 SECTION 4 – QUALIFICATIONS AND EXPERIENCE 4.1 Project Team Include resumes for known key personnel and contractors, including all functions below, as an attachment to your application. In the electronic submittal, please submit resumes as separate PDFs if the applicant would like those excluded from the web posting of this application. 4.1.1 Project Manager Indicate who will be managing the project for the Grantee and include contact information. If the applicant does not have a project manager indicate how you intend to solicit project management support. If the applicant expects project management assistance from AEA or another government entity, state that in this section. HEA’s Manager of Renewable Energy Development, Mike Salzetti, will be the Project Manager for this Project. Mike has over 31 years of engineering experience with 21 of those years including Project Management responsibilities. Mr. Salzetti’s contact information in shown in Section 1.1 of this application and his professional qualifications are included in Attachment A. 4.1.2 Project Accountant Indicate who will be performing the accounting of this project for the grantee. If the applicant does not have a project accountant indicate how you intend to solicit financial accounting support. Katheryn Parke, HEA’s Plant Accounting Supervisor will be performing the accounting for this Project. 4.1.3 Expertise and Resources Describe the project team including the applicant, partners, and contractors. For each member of the project team, indicate: • the milestones/tasks in 3.1 they will be responsible for; • the knowledge, skills, and experience that will be used to successfully deliver the tasks; • how time and other resource conflicts will be managed to successfully complete the task. If contractors have not been selected to complete the work, provide reviewers with sufficient detail to understand the applicant’s capacity to successfully select contractors and manage complex contracts. HEA’s Manager of Renewable Energy Development, Mike Salzetti, will be the Project Manager for this Project. Mike has over 31 years of engineering experience with 21 of those years including Project Management responsibilities. Mr. Salzetti played an integral role in the design of Homer Electric’s new generation facilities and successfully shepherded the Grant Lake Hydroelectric Project through an original FERC licensing process. Mr. Salzetti has the guidance, support, staffing, and resources of Homer Electric Association to support him in all phases of this project. The professional biographies of HEA’s Executive Management Team are included as Attachment A. The final engineering design contractor will be selected on a competitive bid process per established HEA policies. In the last decade HEA has successfully selected contractors to design and build several large generation projects. These projects include the addition of a 40 MW steam Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 13 of 33 11/16/2021 turbine at the Nikiski power plant to convert the facility to combined cycle, the installation of a 48 MW GE LM6000 aeroderivative gas turbine generation facility and the recent installation of a 93 MWh Tesla Battery Energy Storage System. 4.2 Local Workforce Describe how the project will use local labor or train a local labor workforce. HEA Management Directives governing contracting and procurement include considerations for such things as material procurement from pre-qualified businesses operating on the Kenai Peninsula, possession of an Alaska Business license, maintenance of an office and staff within Alaska and advertisements in general circulation publications as defined by Alaska State Statutes that promote local contracting and procurement. Pursuit to Board Policy 401 – Contracting and Purchasing, Section II, part H, HEA and AEEC give a 5% preference to vendors maintaining an office or place of business in the cooperative’s service area (unless prohibited by statute, regulation or grant). SECTION 5 – TECHNICAL FEASIBILITY 5.1 Resource Availability 5.1.1 Assessment of Proposed Energy Resource Describe the potential extent/amount of the energy resource that is available, including average resource availability on an annual basis. For pre-construction applications, describe the resource to the extent known. For design and permitting or construction projects, please provide feasibility documents, design documents, and permitting documents (if applicable) as attachments to this application (See Section 11). Likelihood of the resource being available over the life of the project. See the “Resource Assessment” section of the appropriate Best Practice Checklist for additional guidance. As part of a KPB Central Peninsula Landfill Gas Utilization Feasibility Study, CH2M Hill Engineering estimated the energy that could be produced and utilized by a landfill gas to power project. The results were based upon landfill gas generation estimates developed by the U.S. Environmental Protection Agency’s (EPA) LandGem model. The results were then discounted to adjust for a 60% collection efficiency and a 50% methane content of the landfill gas. Based upon the engine efficiency of a representative reciprocating gas generator the landfill gas to energy calculations indicated available power of 1 to 1.6 MW, increasing over time as more and more landfill gas is generated. 5.1.2 Alternatives to Proposed Energy Resource Describe the pros and cons of your proposed energy resource vs. other alternatives that may be available for the market to be served by your project. Homer Electric Association’s Board of Directors has developed a Board Policy (505 - Renewable Portfolio Goal) that states, “It is the policy of the Cooperative to use best efforts to meet a renewable portfolio goal of 50% of its annual energy needs by the end of 2025.” HEA staff is in the process of analyzing and developing a suit of firm and non-firm renewable energy projects to meet this goal. It is anticipated that a mix of renewable energy projects will be needed to cost effectively achieve this goal. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 14 of 33 11/16/2021 AEEC / KPB CPL Landfill Gas CHP Project Pros: 1. It is a firm (non-intermittent) renewable energy resource with an anticipated 95% availability 2. The heat rate of the generator set is commensurate with existing HEA fleet heat rates 3. It is anticipated that the cost of the landfill gas will be significantly lower than existing gas costs 4. Gas costs can be off-set or exchanged for recovered waste heat BTUs to operate the landfill’s leachate evaporator, which would essentially eliminate the leachate evaporator gas bill. 5. The project would capture 234 MMCF per year of landfill gas emissions currently going straight to the atmosphere. Methane is approximately 25 times more damaging to the atmosphere than CO2. 6. Between the displaced generation from current thermal power production and natural gas offset by waste heat in the leachate evaporator, 11.9 metric tons of CO2 are offset annually 7. The project installs landfill gas collection infrastructure that will eventually be required of the CPL to meet EPA regulations once the landfill mass exceeds threshold requirements. This eliminates a future cost for the Landfill. 8. As a not for profit entity, HEA has the following advantages over an IPP executing a similar project: a. No profit margin required b. Access to lower financing rates c. No property taxes d. Access to an existing work force and remote dispatch system This project is beneficial for HEA owner-member, citizens of the Kenai Peninsula Borough and the environment. AEEC / KPB CPL Landfill Gas CHP Project Cons: 1. Landfill gas generation units typically require more maintenance than other thermal generation assets. 2. As a not for profit entity, HEA does not currently qualify for tax credits, although there is proposed Federal legislation that would provide direct incentives to non profit entities in lieu of tax credits. 5.1.3 Permits Provide the following information as it may relate to permitting and how you intend to address outstanding permit issues. See the “Environmental and Permitting Risks” section of the appropriate Best Practice Checklist for additional guidance. • List of applicable permits • Anticipated permitting timeline • Identify and describe potential barriers including potential permit timing issues, public opposition that may result in difficulty obtaining permits, and other permitting barriers As part of the feasibility analysis, Jacobs Engineering prepared a list of anticipated permits that will be required for the project. The listed permits included: Title V Air Emissions Permit: This may not be needed until Cell 5 is permitted (approximately 2035). The CPL’s landfill mass is currently below the EPA thresholds that requires a Title V Emissions Permit and the requirement to capture landfill gas and flare it. When needed, it is estimated that this permit will take 6 to 8 months to develop and process. No significant barriers are anticipated to obtaining this permit. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 15 of 33 11/16/2021 Building Construction Permit: This permit will take 4 to 6 weeks to obtain. No significant barriers are anticipated to obtaining this permit. The Jacobs Engineering Permit Requirements Memorandum is included as Attachment F. 5.2 Project Site Describe the availability of the site and its suitability for the proposed energy system. Identify potential land ownership issues, including whether site owners have agreed to the project or how you intend to approach land ownership and access issues. See the “Site control” section of the appropriate Best Practice Checklist for additional guidance. The project will be constructed within the boundaries of the KPB Central Peninsula Landfill on land owned by the Borough. No land issues are anticipated. 5.3 Project Technical & Environmental Risk 5.3.1 Technical Risk Describe potential technical risks and how you would address them. • Which tasks are expected to be most challenging? • How will the project team reduce the risk of these tasks? • What internal controls will be put in place to limit and deal with technical risks? See the “Common Planning Risks” section of the appropriate Best Practice Checklist for additional guidance. AEEC is encouraged by the results of the preliminary feasibility analysis, the proximity of the resource to existing, power and gas infrastructure, our ability to interconnect the resource, the financial feasibility coming out of the feasibility analysis and the benefit to the environment. The technology to capture landfill gas, covert it to power is well established and operating at numerous landfills throughout the world including at the Municipality of Anchorage. The Project has no know technical risks at this time. However, the design process with required submissions at the 60, 90 and 100 percent design stages will allow AEEC to evaluate risks and costs in a stage gate approach to the project. 5.3.2 Environmental Risk Explain whether the following environmental and land use issues apply, and if so which project team members will be involved and how the issues will be addressed. See the “Environmental and Permitting Risks” section of the appropriate Best Practice Checklist for additional guidance. • Threatened or endangered species • Habitat issues • Wetlands and other protected areas • Archaeological and historical resources • Land development constraints • Telecommunications interference • Aviation considerations • Visual, aesthetics impacts • Identify and describe other potential barriers Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 16 of 33 11/16/2021 The project will be constructed within the boundaries of the KPB Central Peninsula Landfill on land owned by the Borough. An environmental impact assessment was completed in for development of the landfill. No issues with threatened or endangered species, habitat, wetlands, or archeological or historical significance were identified. The landfill is a developed industrial site, visually screened, with no adjacent development. No adverse environmental impacts or other barriers to development are anticipated. 5.4 Technical Feasibility of Proposed Energy System In this section you will describe and give details of the existing and proposed systems. The information for existing system will be used as the baseline the proposal is compared to and also used to make sure that proposed system can be integrated. Only complete sections applicable to your proposal. If your proposal only generates electricity, you can remove the sections for thermal (heat) generation. 5.4.1 Basic Operation of Existing Energy System Describe the basic operation of the existing energy system including: description of control system; spinning reserve needs and variability in generation (any high loads brought on quickly); and current voltage, frequency, and outage issues across system. See the “Understanding the Existing System” section of the appropriate Best Practice Checklist for additional guidance. AEEC owns and operates three plants that are fueled by natural gas. The Nikiski Plant is an 80 MW baseload generating plant fueled by natural gas and recovered heat. HEA has two backup generating plants: the Soldotna Plant, a 48 MW generating plant; and the Bernice Lake Plant, a 73 MW generating plant that are used for backup, peaking, and reserve capacity. Additionally, AEEC has access to 14 MW of purchased power capacity at the State’s Bradley Lake Hydroelectric facility. 5.4.2.1 Existing Power Generation Units Include for each unit include: resource/fuel, make/model, design capacity (kW), minimum operational load (kW), RPM, electronic/mechanical fuel injection, make/model of genset controllers, hours on genset Unit 1: Nikiski Combined Cycle Plant: Natural Gas/ Steam, CT GE Frame 6B Combustion Turbine, ST GE SC2-22, HRSG Deltak Dino 4128 Heat Recovery Steam Generator, NCC design capacity 80 MW, NCC minimum operational load 20 MW, CT RPM 5105, ST RPM 3600, Emerson Ovation DCS Unit 2: Soldotna Combustion Turbine Plant: Natural Gas, GE LM6000 Combustion Turbine Generator, design capacity 48 MW, minimum operational load 3 MW, RPM 3600, Emerson Ovation DCS Unit 3: Bernice Lake Combustion Turbine Plant: Natural Gas, GE Frame 5 Combustion Turbine, design capacity 19 MW, design capacity 27 MW, design capacity 27 MW, minimum operational load 3 MW, minimum operational load 6 MW, minimum operational load 6 MW, RPM 3600, Emerson Ovation DCS 5.4.2 Existing Energy Generation Infrastructure and Production In the following tables, only fill in areas below applicable to your project. You can remove extra tables. If you have the data below in other formats, you can attach them to the application (see Section 11). Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 17 of 33 11/16/2021 Unit 4: Bradley Lake Hydroelectric Project (Hydro), Fuji generators, Andritz hydro runners, design capacity 64 MW per unit (HEA 14 MW share), no minimum operational load, RPM 300, Emerson Ovation DCS Unit 5: Unit 6: 5.4.2.2 Existing Distribution System Describe the basic elements of the distribution system. Include the capacity of the step-up transformer at the powerhouse, the distribution voltage(s) across the community, any transmission voltages, and other elements that will be affected by the proposed project. The HEA system has a total of 2,491 miles of energized line that distributes power to 35,599 meters in a 3,166 square-mile service area on the Kenai Peninsula. One of the advantages of the Landfill Gas Project is its proximity to both transmission and distribution lines. As part of the feasibility analysis, Leidos, Inc was commissioned to complete an Interconnection Impact Study. The study concluded that the 1.6 MW landfill gas generator could be connected into HEA’s existing 24.9 KV, four-wire distribution system fed from the Billy Thompson substation. The Leidos Interconnection Impact Study is included as Attachment G 5.4.2.3 Existing Thermal Generation Units (if applicable to your project) Generation unit Resource/ Fuel type Design capacity (MMBtu/hr) Make Model Average annual efficiency Year Installed Hours Nikiski Combined Cycle Plant Natural Gas/ Steam CT 40 MW, ST 40 MW CT GE, ST GE, HRSG Deltak CT Frame 6B, ST SC2-22, Combustion Turbine, HRSG Dino 4128 Heat Recovery Steam Generator CT 35- 42%, NCC 60% CT 1986, HRSG 2001, ST 2014 CT 168,983 hours (as of EOY 2019) Soldotna Combustion Turbine Plant Natural Gas CT 48 MW CT GE CT LM6000 Combustion Turbine Generator Peak CT 2014 CT 13,326 hours (as of EOY 2019) Bernice Lake Combustion Turbine Plant Natural Gas CT 19 MW, CT 27.5, CT 27.5 CT GE CT Frame 5 Combustion Turbine Peak CT 1971, CT 1978, Is there operational heat recovery? (Y/N) If yes estimated annual displaced heating fuel (gallons) N/A The Combined cycle plan at Nikiski generates steam that is converted to electricity not heat. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 18 of 33 11/16/2021 CT 1981 5.4.2.5 Annual Electricity Production and Fuel Consumption (Existing System) Use most recent year. Replace the section (Type 1), (Type 2), and (Type 3) with generation sources Month Generation Nikiski Combined Cycle Plant (kWh) Generation Soldotna Combustion Turbine Plant (kWh) Generation Bernice Lake Combustion Plant (kWh) Fuel Consumptio n (Diesel- Gallons) Fuel Consumption Natural Gas (Mcf) Peak Load MWh Minimum Load (MWh) January 41,899,405 2,097 1,256 368,042 1,553 1,319 February 37,527,357 109,052 1,526 334,878 1,563 1,351 March 39,496,815 1,000,229 203,136 365,365 1,572 1,323 April 35,481,301 2,767 151,421 319,225 1,456 1,201 May 17,186,990 13,800,750 344,021 305,346 1,303 1,182 June 26,701,127 4,402,566 200,985 292,899 1,288 1,071 July 32,859,596 0 3 298,043 1,386 1,209 August 32,356,522 14,203 1,764 296,783 1,388 1,044 Septembe r 20,007,288 10,537,928 321,433 286,838 1,443 1,182 October 39,997,133 2,714,565 10,067 392,830 1,437 1,277 November 42,267,368 18,194 2,385 380,941 1,683 1,348 December 41,720,850 685,731 1,376 380,057 1,810 1,479 Total 407,501,750 33,288,083 1,239,373 4,021,248 5.4.2.6 Annual Heating Fuel Consumption (Existing System) Use most recent year. Include only if your project affects the recovered heat off the diesel genset or will include electric heat loads. Only include heat loads affected by the project. Month Diesel (Gallons) Electricity Propane (Gallons) Coal (Tons) Wood (Cords, green tons, dry tons) Other January February March April 5.4.2.4 O&M and replacement costs for existing units Power Generation Thermal Generation i.Annual O&M cost for labor AEEC does not track labor & non-labor separately so O&M cost are below. This excludes natural gas costs. ii.Annual O&M cost $7,975,397 iii.Replacement schedule and cost for existing units NCC retirement 2043, SCT retirement 2054, BCT retirement 2034 Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 19 of 33 11/16/2021 May June July August September October November December Total 5.4.3 Future Trends Describe the anticipated energy demand in the community, or whatever will be affected by the project, over the life of the project. Explain how the forecast was developed and provide year by year forecasts. As appropriate, include expected changes to energy demand, peak load, seasonal variations, etc. that will affect the project. HEA has 24,613 member-owners and provides power to 35,599 meters located throughout the Kenai Peninsula. HEA sold 452 million kilowatt-hours of electricity in 2020. HEA’S latest published Equity Management Plan indicates a 1% per year growth rate over the next 15 years but actual results indicate flat to a slight decline in load due to member efficiency and conservation efforts. Predicting the future is very difficult but HEA is hopeful that the adoption of electric vehicles along with other beneficial electrification technologies will result in a return to a 1% per year load growth for the life of this project. Additionally, HEA is interconnected to a regional Alaskan grid known as the “Railbelt” via a three phase, 115 kV transmission line. The Railbelt is generally defined as the service areas of five regulated public utilities: Chugach Electric Association (Chugach), Golden Valley Electric Association (GVEA), HEA, Matanuska Electric Association (MEA), and the City of Seward Electric System (SES). This region grid covers a significant area of the state and contains the majority of the state’s population and economic activity; it extends from Homer to Fairbanks and includes areas such as Anchorage, Fairbanks, and the Matanuska-Susitna Valley. HEA can and has regularly provided power to Alaskan residents from Anchorage to Fairbanks via wholesale and economy energy sales to the other four interconnected electric utilities. It is important to know that the Landfill Gas Project is not proposed to meet load growth. The intent of the Project is to meet the Boards Directors and the State of Alaska’s renewable energy goals and save the costs to the CPL. 5.4.4 Proposed System Design Provide the following information for the proposed renewable energy system: •A description of renewable energy technology specific to project location •The total proposed capacity and a description of how the capacity was determined •Integration plan, including upgrades needed to existing system(s) to integrate renewable energy system: Include a description of the controls, storage, secondary loads, distribution upgrades that will be included in the project •Civil infrastructure that will be completed as part of the project—buildings, roads, etc. •Include what backup and/or supplemental system will be in place Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 20 of 33 11/16/2021 See the “Proposed System Design” section of the appropriate Best Practice Checklist for additional guidance. The project is expected to utilize a 1.6 MW CAT or GE Jenbacher engine /generator package. The generator will generate three phase power at 4160 V that will be stepped up 24.9 KV by a 2000 / 2500 KVA step up transformer and interconnected to an existing HEA distribution line fed from the Billy Thompson substation. Equipment will be installed on the engine, the exhaust gas, intercooler, and lube oil systems to recover waste heat to replace the natural gas currently used to operate the leachate evaporator. The engine / generator is purposely oversized to accommodate for the modelled increase in landfill gas in future years and to allow for additional heat recovery by generating additional power with supplemental pipeline natural gas to evaporate landfill leachate. To maximize facility performance, uptime and account for the cold weather climate, the facility equipment will be housed in a climate-controlled, pre-engineered metal building. The building will include four separate compartmentalized areas: engine/generator room, LFG compression skid/oil storage/coolant storage room, electric switchgear room, and office/tool storage room. The facility will be designed to accommodate hydrogen sulfide and siloxane removal systems if it is ever needed. The CHP plant will be located in close proximity to the existing leachate evaporator system so as to limit exhaust piping runs. The existing leachate evaporator will be modified/repurposed for utilization of exhaust gas to evaporate leachate. The existing Advanced Burner Technologies LLC leachate evaporator flare system would remain operational for use during CHP plant downtimes. Access to the new CHP Plant would be via the existing leachate evaporator road. The 25% design drawings are included as Attachment D 5.4.4.1 Proposed Power Generation Units Unit # Resource/ Fuel type Design capacity (kW) Make Model Expected capacity factor Expected life (years) Expected Availability 1 Landfill Gas 1600 Caterpillar G3520C 100% 30 95% 5.4.4.2 Proposed Thermal Generation Units (if applicable) Generation unit Resource/ Fuel type Design capacity (MMBtu/hr) Make Model Expected Average annual efficiency Expected life 1 Waste Heat & Supplemental Natural Gas 5.469 Caterpillar G3520C (with waste heat recovery equipment) 67% (Provided MMBtu is recoverable amount) 30 Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 21 of 33 11/16/2021 5.4.5 Basic Operation of Proposed Energy System •To the best extent possible, describe how the proposed energy system will operate: When will the system operate, how will the system integrate with the existing system, how will the control systems be used, etc. •When and how will the backup system(s) be expected to be used See the “Proposed System Design” section of the appropriate Best Practice Checklist for additional guidance. The CHP Plant would operate base loaded at full capacity during the days (215 to 272 days per year) when the leachate evaporator was required to operate. During those days when the leachate evaporator was not required, the facility would operate at a minimum level to utilize available landfill gas and up to max capacity (supplemented with pipeline natural gas) depending on the economic dispatch of the HEA system. During this mode of operation, the facility could be used for small amounts of spinning reserve or to assist in following intermittent renewable generation. 5.4.3.1 Expected Capacity Factor 100% 5.4.5.2 Annual Electricity Production and Fuel Consumption (Proposed System) Month Generation (Proposed System) (kWh) Generation (Type 2) (kWh) Generation (Type 3) (kWh) Fuel Consumption Landfill Gas 50% Methane (Mcf) Fuel Consumption Natural Gas (Mcf) Secondary load (kWh) Storage (kWh) January 1,047,552 19,852 2,127 February 946,176 17,931 1,921 March 1,047,552 19,852 2,127 April 1,013,760 19,212 2,058 May 1,047,552 19,852 2,127 June 1,013,760 19,212 2,058 July 1,047,552 19,852 2,127 August 1,047,552 19,852 2,127 September 1,013,760 19,212 2,058 October 1,047,552 19,852 2,127 November 1,013,760 19,212 2,058 December 1,047,552 19,852 2,127 Total 12,334,080 233,743 25,041 5.4.5.3 Annual Heating Fuel Consumption (Proposed System) Month Diesel (Gallons) Electricity Propane (Gallons) Coal (Tons) Wood (Cords, green tons, dry tons) Other January Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 22 of 33 11/16/2021 February March April May June July August September October November December Total 5.4.6 Proposed System Operating and Maintenance (O&M) Costs O&M costs can be estimated in two ways for the standard application. Most proposed renewable energy projects will fall under Option 1 because the new resource will not allow for diesel generation to be turned off. Some projects may allow for diesel generation to be turned off for periods of time; these projects should choose Option 2 for estimating O&M. Option 1: Diesel generation ON For projects that do not result in shutting down diesel generation there is assumed to be no impact on the base case O&M. Please indicate the estimated annual O&M cost associated with the proposed renewable project. $ Option 2: Diesel generation OFF For projects that will result in shutting down diesel generation please estimate: 1. Annual non-fuel savings of shutting off diesel generation 2. Estimated hours that diesel generation will be off per year. 3. Annual O&M costs associated with the proposed renewable project. 1. $ 2. Hours diesel OFF/year: 3. $0.045 / KWh 5.4.7 Fuel Costs Estimate annual cost for all applicable fuel(s) needed to run the proposed system (Year 1 of operation) Diesel (Gallons) Electricity Propane (Gallons) Coal (Tons) Wood Other Unit cost ($) Annual Units Total Annual cost ($) 5.5 Performance and O&M Reporting Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 23 of 33 11/16/2021 For construction projects only 5.5.1 Metering Equipment Please provide a short narrative, and cost estimate, identifying the metering equipment that will be used to comply with the operations reporting requirement identified in Section 3.15 of the Request for Applications. NA 5.5.2 O&M reporting Please provide a short narrative about the methods that will be used to gather and store reliable operations and maintenance data, including costs, to comply with the operations reporting requirement identified in Section 3.15 of the Request for Applications NA SECTION 6 – ECONOMIC FEASIBILITY AND BENEFITS 6.1 Economic Feasibility 6.1.1 Economic Benefit Annual Lifetime Anticipated Diesel Fuel Displaced for Power Generation (gallons) Anticipated Fuel Displaced for Heat (gallons) Total Fuel displaced (gallons) Anticipated Diesel Fuel Displaced for Power Generation ($) Anticipated Fuel Displaced for Heat ($) Anticipated Power Generation O&M Cost Savings Anticipated Thermal Generation O&M Cost Savings Total Other costs savings (taxes, insurance, etc.) Total Fuel, O&M, and Other Cost Savings $15,510,000 6.1.2 Economic Benefit Explain the economic benefits of your project. Include direct cost savings and other economic benefits, and how the people of Alaska will benefit from the project. Note that additional revenue sources (such as tax credits or green tags) to pay for operations and/or financing, will not be included as economic benefits of the project. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 24 of 33 11/16/2021 Where appropriate, describe the anticipated energy cost in the community, or whatever will be affected by the project, over the life of the project. Explain how the forecast was developed and provide year-by-year forecasts The economic model used by AEA is available at https://www.akenergyauthority.org/What-We- Do/Grants-Loans/Renewable-Energy-Fund/2021-REF-Application. This economic model may be used by applicants but is not required. The final benefit/cost ratio used will be derived from the AEA model to ensure a level playing field for all applicants. If used, please submit the model with the application. Based upon a 30-year project life, a 2% discount rate, $12,534,000 capital cost, a 95% availability, a 2%-line loss, a 5% parasitic loss, current HEA gas costs escalated at 2%, 50% methane content of the landfill gas, an O&M expense of $0.045 / KWh and a cost of power based upon HEA’s current Small Facility Power Purchase Rate (essentially an avoided cost of gas) the model predicts: A net savings to AEEC of $4,755,000 and a savings to the KPB of $10,755,00 for a net project savings of $15,510,000. Since the model run is based upon the SFPPR (the avoided cost of gas) for power cost this indicates the project could be constructed, operated and maintained without negatively impacting rate. It actually indicates downward pressure on rates plus the landfill sees a saving of over $10 Million. The economic further improve if grant funds are awarded to a net savings to AEEC of $5,640,000 and a savings to the KPB of $10,755,00 for a net project savings of $16,395,000. If a 30% direct pay ITC is received, the economic further improve to a net savings to AEEC of $9,401,000 and a savings to the KPB of $10,755,00 for a net project savings of $20,156,000. The Project Financial Feasibility Analysis Model is set up to exchange landfill gas for recovered waste heat at Cook Inlet natural gas prices. While the model accurately captures overall project costs and benefits, it does not proportionately distribute benefits according to capital investment. This can be addressed by appropriately structuring a waste heat for landfill gas contract and a projects construction cost agreement. Financial Feasibility Model runs for the three referenced scenarios discussed above are included as Attachment J. AEEC is very encouraged by the economics coming out of the Feasibility Analysis phase of the Project. 6.1.3 Economic Risks Discuss potential issues that could make the project uneconomic to operate and how the project team will address the issues. Factors may include: •Low prices for diesel and/or heating oil •Other projects developed in community •Reductions in expected energy demand: Is there a risk of an insufficient market for energy produced over the life of the project. •Deferred and/or inadequate facility maintenance Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 25 of 33 11/16/2021 • Other factors The current landfill mass will continue to generate methane for years to come and there is no indication that waste from the Kenia Peninsula Borough will not continue to be collected at the CPL which has expansion capacity. There is a low risk that there will not be sufficient landfill gas to operate the project through its 30-year life expectancy. The KPB commissioned a study to determine the most feasible use of landfill gas. The study examined a number of competing uses of the landfill gas and determined that the proposed project showed the most promise. The study is included as Attachment H. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 26 of 33 11/16/2021 6.1.4 Public Benefit for Projects with Direct Private Sector Sales For projects that include direct sales of power to private sector businesses (sawmills, cruise ships, mines, etc.), please provide a brief description of the direct and indirect public benefits derived from the project as well as the private sector benefits and complete the table below. See Section 1.6 in the Request for Applications for more information. NA Renewable energy resource availability (kWh per month) Estimated direct sales to private sector businesses (kWh) Revenue for displacing diesel generation for use at private sector businesses ($) Estimated sales for use by the Alaskan public (kWh) Revenue for displacing diesel generation for use by the Alaskan public ($) 6.2 Other Public Benefit Describe the non-economic public benefits to Alaskans over the lifetime of the project. For the purpose of evaluating this criterion, public benefits are those benefits that would be considered unique to a given project and not generic to any renewable resource. For example, decreased greenhouse gas emission, stable pricing of fuel source, won’t be considered under this category. Some examples of other public benefits include: • The project will result in developing infrastructure (roads, trails, pipes, power lines, etc.) that can be used for other purposes • The project will result in a direct long-term increase in jobs (operating, supplying fuel, etc.) • The project will solve other problems for the community (waste disposal, food security, etc.) • The project will generate useful information that could be used by the public in other parts of the state • The project will promote or sustain long-term commercial economic development for the community This project offers the following other Public Benefits: It converts a waste product (landfill gas) to electricity for the benefit of the community. The captured waste heat will eliminate or significantly reduce the landfill’s natural gas bill required to evaporate leachate. On average it is anticipated that it will save the KPB $1,295,564 per year in natural gas costs. It will convert methane emissions to CO2, 11 years in advance of what EPA regulations require. This will eliminate 117,000,000 cf of methane emissions per year. Methane is approximately 25 times more damaging to the atmosphere than CO2. The Project would construct a landfill gas collection system that would eventually be required to meet future EPA requirements. It is anticipated that the landfill mass will exceed this EPA requirement in the year 2035. This will save the KPB $1,366,000. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 27 of 33 11/16/2021 SECTION 7 – SUSTAINABILITY Describe your plan for operating the completed project so that it will be sustainable throughout its economic life. At a minimum for construction projects, a business and operations plan should be attached and the applicant should describe how it will be implemented. See Section 11. 7.1.1 Operation and Maintenance Demonstrate the capacity to provide for the long-term operation and maintenance of the proposed project for its expected life • Provide examples of success with similar or related long-term operations • Describe the key personnel that will be available for operating and maintaining the infrastructure. • Describe the training plan for existing and future employees to become proficient at operating and maintaining the proposed system. • Describe the systems that will be used to track necessary supplies • Describe the system will be used to ensure that scheduled maintenance is performed The facility will be remotely operated and monitored utilizing HEA’s existing SCADA infrastructure from the existing HEA Dispatch Center which is staffed 24 hours a day, 7 days a week, 365 days a year. Scheduled site inspections, planned and unplanned maintenance will be conducted by HEA’s exiting roving Operations & Maintenance crew that currently maintains and operates HEA’s unmanned thermal generation plants in Nikiski, Soldotna and Seldovia. Existing personnel will provide the labor needed to operate and maintain the facility. Existing company vehicles, tooling and equipment currently utilized by the roving operations and maintenance crew will be utilized to conduct onsite work. HEA would use its existing maintenance scheduling, inventory control, outage scheduling, warehousing and accounting procedures to coordinate and track scheduled and unscheduled maintenance on these new assets. HEA plans to use its own employees to operate and maintain any new generation assets. 7.1.2 Financial Sustainability • Describe the process used (or propose to use) to account for operational and capital costs. • Describe how rates are determined (or will be determined). What process is required to set rates? • Describe how you ensure that revenue is collected. • If you will not be selling energy, explain how you will ensure that the completed project will be financially sustainable for its useful life. This generation asset will be owned and operated by AEEC / HEA which will use established and existing utility accounting practices, procedures, financial systems, accounting personnel, and outside independent audits to account for operational and capital costs. HEA rates are set by the member-elected Board of Directors on an annual basis (and modified each mid-year). HEA develops its annual budget to cover all its operational expenses, debt service, fuel costs, and margins required to comply with lender’s loan covenants, HEA’s own capital-credits policy, and sufficient to fund system maintenance and upgrades. Those rates (tariffs) are then reviewed and approved by the Regulatory Commission of Alaska. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 28 of 33 11/16/2021 As part of the existing AEEC / HEA generation fleet revenues would be collected through HEA’s existing monthly billing process and systems. 7.1.2.1 Revenue Sources Briefly explain what if any effect your project will have on electrical rates in the proposed benefit area over the life of the project. If there is expected to be multiple rates for electricity, such as a separate rate for intermittent heat, explain what the rates will be and how they will be determined Collect sufficient revenue to cover operational and capital costs • What is the expected cost-based rate (as consistent with RFA requirements) • If you expect to have multiple rate classes, such as excess electricity for heat, explain what those rates are expected to be and how those rates account for the costs of delivering the energy (see AEA’s white paper on excess electricity for heat). • Annual customer revenue sufficient to cover costs • Additional incentives (i.e. tax credits) • Additional revenue streams (i.e. green tag sales or other renewable energy subsidies or programs that might be available) HEA / AEEC hopes to add this environmentally friendly beneficial renewable energy project to AEEC’s generation portfolio without impacting rates. This however will depend on the final actual cost of the project, grants, direct pay tax incentives, legislative appropriations, power production incentives, greenhouse gas, and / or renewable energy credits received, the terms of the landfill gas for waste heat BTU agreement and the capital financing terms of the project. Operational and capital costs will be covered form revenues received from the sale of power to HEA’s members. The purchased power rates are set by HEA’s member elected Board of Directors and regulated by the Regulatory Commission of Alaska. Since HEA is a not for profit entity, no rate of return is incorporated into the rates that HEA charges its members. HEA provides power at cost plus an allowed RCA specified operational margin. As mention above it is HEA’s hope that this project will not increase the HEA’s current rates (https://www.homerelectric.com/member-services/my-bill/rates/). In advance of Project construction, HEA anticipates pursuing landfill gas power production incentives and greenhouse gas, and / or renewable energy credits for the Project. 7.1.2.2 Power Purchase/Sale The power purchase/sale information should include the following: • Identification of potential power buyer(s)/customer(s) • Potential power purchase/sales price - at a minimum indicate a price range (consistent with the Section 3.16 of the RFA) Identify the potential power buyer(s)/customer(s) and anticipated power purchase/sales price range. Indicate the proposed rate of return from the grant-funded project. Include letters of support or power purchase agreement from identified customers. Since the generation asset will be owned and operated by AEEC / HEA which are RCA certificated utilities, no power purchase / sales agreement will be needed. The generation will be incorporated into AEEC’s existing generation portfolio that provides power to HEA members. Since HEA is a not for profit entity, no rate of return is incorporated into the rates that HEA charges its members. HEA provides power at cost plus an allowed RCA specified operational margin. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 29 of 33 11/16/2021 SECTION 8 – PROJECT READINESS 8.1 Project Preparation Describe what you have done to prepare for this award and how quickly you intend to proceed with work once your grant is approved. Specifically address your progress towards or readiness to begin, at a minimum, the following: •The phase(s) that must be completed prior to beginning the phase(s) proposed in this application •The phase(s) proposed in this application •Obtaining all necessary permits •Securing land access and use for the project •Procuring all necessary equipment and materials Refer to the RFA and/or the pre-requisite checklists for the required activities and deliverables for each project phase. Please describe below and attach any required documentation. The Phase II Feasibility and Conceptual Design work is complete and we are read to move into the Phase III Final Design and Permitting stage of the project once the requested grant funding has been awarded. AEEC can use the RFP and Contract associated with the Conceptual Design work as well as the existing bidders list to move quickly in accomplishing the Contractor Solicitation milestones identified in Section 3.1 (Schedule and Milestones). 8.2 Demand- or Supply-Side Efficiency Upgrades If you have invested in energy efficiency projects that will have a positive impact on the proposed project, and have chosen to not include them in the economic analysis, applicants should provide as much documentation as possible including: 1.Explain how it will improve the success of the RE project 2.Energy efficiency pre and post audit reports, or other appropriate analysis, 3.Invoices for work completed, 4.Photos of the work performed, and/or 5.Any other available verification such as scopes of work, technical drawings, and payroll for work completed internally. NA SECTION 9 – LOCAL SUPPORT AND OPPOSITION Describe local support and opposition, known or anticipated, for the project. Include letters, resolutions, or other documentation of local support from the community that would benefit from this project. Provide letters of support, memorandum of understandings, cooperative agreements between the applicant, the utility, local government and project partners. The documentation of support must be dated within one year of the RFA date of November 16, 2021. Please note that letters of support from legislators will not count toward this criterion. The proposed project has broad local support and no know opposition. Included as Attachment B are letters of support from Erin McKittrick, the Board President, Alaska Electric, and Energy Cooperative, Cook Inletkeeper, KPEDD, Senator Peter Micciche and a Resolution supporting the project from the Kenai Peninsula Borough Resilience and Security Advisory Commission. Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 30 of 33 11/16/2021 SECTION 10 – COMPLIANCE WITH OTHER AWARDS Identify other grants that may have been previously awarded to the Applicant by AEA for this or any other project. Describe the degree you have been able to meet the requirements of previous grants including project deadlines, reporting, and information requests. Homer Electric Association through its wholly own subsidiary Kenai Hydro, completed some Phase I Reconnaissance studies, which were completed in January 2009 and were partially funded by a $100,000 AEA grant. Kenai Hydro received partial funding for Phase II activities in the amount of $2,000,000 through two separate awards of $816,000 and of $1,184,400 through AEA Renewable Energy Grants. KHL complied with all terms of the grant agreements from previously award grants, which included timely quarterly progress reports, delivery of agreed upon deliverables and closeout of the grants. SECTION 11 – LIST OF SUPPORTING DOCUMENTATION FOR PRIOR PHASES In the space below, please provide a list of additional documents attached to support completion of prior phases. Attachment D: Jacobs Engineering 25% Feasibility Design Drawings Attachment E: Jacobs Engineering Class 3 AACE Cost Estimate Attachment F: Jacobs Engineering Permit Requirements Memorandum Attachment G: Executive Summary from the Leidos Interconnection Impact Study Attachment H: CH2M Hill Engineers CPL Landfill Gas Utilization Feasibility Study Attachment I: HDR CPL Landfill Gas Management Plan SECTION 12 – LIST OF ADDITIONAL DOCUMENTATION SUBMITTED FOR CONSIDERATION In the space below, please provide a list of additional information submitted for consideration. Attachment A: Resumes, submitted as a separate file Attachment C: Board Resolution & Authorization Attachment J: Project Financial Feasibility Model Runs Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 31 of 33 11/16/2021 SECTION 13 – AUTHORIZED SIGNERS FORM Community/Grantee Name: Regular Election is held: Date: Authorized Grant Signer(s): Printed Name Title Term Signature I authorize the above person(s) to sign Grant Documents: (Must be authorized by the highest ranking organization/community/municipal official) Printed Name Title Term Signature Grantee Contact Information: Mailing Address: Phone Number: Fax Number: Email Address: Federal Tax ID #: Please submit an updated form whenever there is a change to the above information. Bradley P. Janorschke General Manager N/A 907-235-8551 907-235-3323 Alaska Electric & Energy Cooperative, Inc June 92-0177236 Annually 3977 Lake Street, Homer, AK 99603 bjanorschke@homerelectric.com Bradley P. Janorschke General Manager N/A 907-235-8551 907-235-3323 Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 32 of 33 11/16/2021 SECTION 14 – ADDITIONAL DOCUMENTATION AND CERTIFICATION SUBMIT THE FOLLOWING DOCUMENTS WITH YOUR APPLICATION: A. Contact information and resumes of Applicant’s Project Manager, Project Accountant(s), key staff, partners, consultants, and suppliers per application form Section 3.1, 3.4 and 3.6. Applicants are asked to provide resumes submitted with applications in separate electronic documents if the individuals do not want their resumes posted to the project web site. B. Letters or resolutions demonstrating local support per application form Section 9. C. For projects involving heat: Most recent invoice demonstrating the cost of heating fuel for the building(s) impacted by the project. D. Governing Body Resolution or other formal action taken by the applicant’s governing body or management per RFA Section 1.4 that: • Commits the organization to provide the matching resources for project at the match amounts indicated in the application. • Authorizes the individual who signs the application has the authority to commit the organization to the obligations under the grant. • Provides as point of contact to represent the applicant for purposes of this application. • Certifies the applicant is in compliance with applicable federal, state, and local, laws including existing credit and federal tax obligations. E. An electronic version of the entire application on CD or other electronic media, per RFA Section 1.7. F. CERTIFICATION The undersigned certifies that this application for a renewable energy grant is truthful and correct, and that the applicant is in compliance with, and will continue to comply with, all federal and state laws including existing credit and federal tax obligations and that they can indeed commit the entity to these obligations. Print Name Signature Title Date Bradley P. Janorschke General Manager January 18, 2022 Renewable Energy Fund Round 14 Grant Application – Standard Form AEA 23001 Page 33 of 33 11/16/2021 AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment A: Resumes (attached as a separate file) AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment B: Letters of Local Support To whom it may concern, Homer Electric Association (HEA) is a member-owned electric cooperative serving customers on the Kenai Peninsula, governed by a nine member board. As a democratically elected body, our board represents the interests of HEA’s more than 24,000 members, and speaks on their behalf. In our commitment to providing affordable and reliable electricity, we regularly review the cooperative’s finances, analyzing cost drivers, risks, and opportunities. Natural gas costs are responsible for around a third of members’ bills. This gas is only available from a single source, and at the time of our last contract negotiation, only from a single provider. The board has determined that this reliance on a single energy source is a substantial risk to our members. We have created an ambitious renewable energy policy to address this issue, seeking 50% renewable energy by 2025. We have determined that incorporating diverse renewable sources of energy into our energy portfolio will benefit HEA members, reduce our vulnerability to price or supply shocks, and reduce upward pressure on electric rates. For the past several years, HEA has been collaborating with the Kenai Peninsula Borough on a landfill gas to energy project at the Central Peninsula Landfill. This project will solve expensive pollution problems at the landfill while providing a new and economically competitive source of energy. Since all HEA members are also citizens of the Kenai Peninsula Borough, our members benefit from both dimensions. The Kenai Peninsula Borough has significant problems managing leachate at the landfill, which costs more than $1.2 million per year. The methane produced by the landfill enters the atmosphere directly, acting as a much more powerful greenhouse gas than CO2. This methane is a valuable source of energy, which is currently being wasted. Our landfill gas project will capture the methane, burn it to create electricity, and use the resulting waste heat to evaporate leachate at the landfill. This will reduce natural gas purchase expenses for both HEA and the Borough, saving our residents money on electric bills and property taxes. I encourage AEA to fund this request towards final engineering design and construction of the landfill gas to energy project at the Central Peninsula landfill. Sincerely, Erin McKittrick Board President, Alaska Electric and Energy Cooperative (Alaska Electric and Energy Cooperative is a generation and transmission cooperative with HEA as it’s sole member, sharing a governing body. AEEC is responsible for generating and providing all the energy to HEA) Grants Administrator Alaska Energy Authority 813 West Northern Lights Blvd. Anchorage, AK 99503 January 15, 2022 Dear Alaska Energy Authority Grants Administrator: Cook Inletkeeper is a community-based organization that formed in 1995 due to public concern around pollution violations in Cook Inlet. As it directly aligns with our mission to protect the Cook Inlet watershed and the life it sustains, we fully support Homer Electric Association (HEA)’s Renewable Energy Fund grant application for the timely and beneficial Central Peninsula Landfill (CPL) Gas Capture and Utilization project. Capturing CPL’s methane, a greenhouse gas roughly 25 times more potent than carbon dioxide, could significantly contribute to the goal held by both HEA and the state of Alaska of achieving 50% renewable energy by 2025. The Central Peninsula Landfill serves the majority of residents on the Kenai Peninsula, and costs Kenai Peninsula Borough taxpayers on average over $7 million per year to operate. In addition, the Borough required $6 million in emergency Covid-relief funds last year to off-gas increased leachate. Investing in Landfill Gas to Energy (LFGTE) infrastructure at CPL would reduce costs for local residents and also reduce local emissions. By utilizing waste heat to evaporate leachate, the Borough would be able to eliminate the gas bill for current operations, and by converting methane to electricity, HEA would provide its ratepayers with cheap electricity. The project is a win-win-win: HEA members/KPB residents (significant overlap) will benefit electricity rate-wise, tax-wise, and climate-wise. According to the Environmental Protection Agency, CPL in 2020 emitted almost three times as much greenhouse gas as HEA's nearby natural gas-burning Soldotna Combustion Turbine Plant. About 97 percent of CPL's emissions were methane, which the gas capture project would burn into the less potent carbon dioxide, for a net decrease in climate-impacting emissions. A more diverse energy portfolio will help protect HEA members against rising Cook Inlet gas prices, which are often much higher than the national average. Having an inexpensive source of electricity produced by methane, which currently goes to waste and harms air quality, would address multiple issues at once. We support Homer Electric Association’s effort to derive more energy from renewable sources and encourage you to rank its Landfill Methane Capture project high in Round XIV of the Renewable Energy Grant Program. We are extremely supportive of this project not only for its ability to reduce emissions but for its many additional benefits to residents and the region at large. Thank you for your thoughtful consideration, Sue Mauger, Science & Executive Director Kaitlin Vadla, Central Peninsula Regional Director Ben Boettger, Energy Organizer Session Address: Alaska State Capitol, Rm. 111 Juneau, Alaska 99801-1182 Phone: (907) 465-2828 Toll Free: (800) 964-5733 Interim Address: 145 Main Street Loop, Ste. 226 Kenai, Alaska 99611-7771 Phone: (907) 283-7996 Fax: (907) 283-8127 Senator Peter A. Micciche Alaska State Legislature President of the Senate Senator.Peter.Micciche@akleg.gov January 17, 2022 Grants Administrator Alaska Energy Authority 813 West Northern Lights Blvd. Anchorage, AK 99503 Dear Administrator: I support Homer Electric Association’s (HEA) subsidiary, Alaska Electric & Energy Cooperative, Inc. (AEEC), in its request for grant funding for a joint project by and between the Kenai Peninsula Borough (KPB) and AEEC. The project is for the installation of a Combined Heat & Power Project at the KPB Landfill. The project would generate electricity from collected landfill gas from the KPB Central Peninsula Landfill (CPL). The waste heat from the electric reciprocating engine generator would be captured and utilized to operate the CPL’s leachate evaporator which is currently fueled by natural gas from the ENSTAR system. Thus, eliminating or significantly reducing the CPL’s natural gas bill required to evaporate leachate. The 1.6 MW project will capture landfill gas while generating electricity to power 1,818 households and providing 6.4 metric tons in CO2 offset. AEEC and KPB have completed the feasibility analysis for the project and is requesting funding for the Final Design and Permitting Requirements for the project. This project is consistent with the State of Alaska’s own renewable energy goal and the HEA’s Board of Director’s goal to produce 50 percent of their electrical energy from renewable resources by 2025. I am encouraged that these projects involve significant local labor and business Senator.Peter.Micciche@akleg.gov involvement for engineering and ecological studies followed by an on-going labor component for their maintenance. I appreciate the efforts of Homer Electric Association to bring long term renewable energy to the Kenai Peninsula and believe this project deserves favorable consideration in the Round XIV of the Alaska Energy Authority's Renewable Energy Grant Program. Thank you for your consideration of this funding request. Sincerely, Senator Peter Micciche District O AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment C: Board Resolution & Authorization Alaska Electric and Energy Cooperative, Inc. 3977 Lake Street Homer, Alaska 99603 (907) 235-8551 RESOLUTION 01.2022.05 GRANT FUNDING AUTHORIZATION FOR CENTRAL PENINSULA LANDFILL GAS PROJECT BE IT RESOLVED that Alaska Electric & Energy Cooperative, Inc. (AEEC) hereby authorizes the General Manager to proceed with the Alaska Energy Authority (AEA) application process to seek grant funding for the Central Peninsula Landfill Gas project. CERTIFICATION I, Jim Duffield, do hereby certify that I am the Secretary/Treasurer of Alaska Electric & Energy Cooperative, Inc., and that the foregoing resolution was adopted at a meeting of the Directors of Alaska Electric & Energy Cooperative, Inc., held on January 11, 2022, at which meeting a quorum was present. Jim Duffield, Secretary/Treasurer Alaska Electric and Energy Cooperative, Inc. 3977 Lake Street Homer, Alaska 99603 (907) 235-8551 CERTIFICATE OF GENERAL MANAGER OF ALASKA ELECTRIC AND ENERGY COOPERATIVE, INC. (AEEC) IN SUPPORT OF CENTRAL PENINSULA LANDFILL GAS PROJECT GRANT APPLICATION I am the General Manager of Alaska Electric and Energy Cooperative, Inc. (the “Cooperative”). I am authorized by the Board of Directors of the Cooperative pursuant to Board Policy 203, and by formal action of the Board of Directors of the Cooperative at a meeting held on January 11, 2022 to certify as follows: 1.The Board of Directors of the Cooperative has authorized the application for project funding and agrees that the Cooperative will honor the match amounts contained in the application to which this certificate is attached. 2.The Cooperative is in good standing with respect to any existing credit and federal tax obligations. Signed and dated in Kenai, Alaska, on January 11, 2022. ____________________________________ Bradley P. Janorschke General Manager AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment D: Jacobs Engineering 25% Feasibility Design Drawings PANEL 265.00 0 270.00 0 275.000280.000260.000 265.000 265.000 270.000 270.000 250.0002 5 5 . 0 0 0 2 6 0 . 0 0 0 2 6 5 . 0 0 0 255.000 25 5 . 0 0 0 26 0 . 0 0 0 26 5 . 0 0 0 270.0 0 0 275.000 230.000235.000240.000245.000250.000255.000260.00026 5 . 0 0 0 265.000265.000 270.000255.000260.000265.000260.0 0 0 265.0 0 0 270.00 0275.000280.00002030302HVLVX1X2X3X0H0H3H2 H15ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 N W E S 0 20 40 GRAPHIC SCALE IN FEET M M M LS M M M M M M M M M LS W PANEL E gm G E265.00 0 270.00 0 260.000 265.000 265.000 270.000 270.000 250.0002 5 5 . 0 0 0 2 6 0 . 0 0 0 2 6 5 . 0 0 0 255.000 25 5 . 0 0 0 26 0 . 0 0 0 26 5 . 0 0 0 270.0 0 0 275.000 260.00026 5 . 0 0 0 265.000265.000 275.0 0 0 280.0 0 0 285. 0 0 0 290. 0 0 0 2 9 5 . 0 0 0270.000270.000255.000260.000265.000235.00 0 240.000 245.00 0 250.000 255.00 0 260.0 0 0 265.0 0 0 270.00 0 02030302HVLVX1 X2X3X0 H0H3H2H1 5ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 N W E S 0 25 50 GRAPHIC SCALE IN FEET ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXX XXXXXXXXXXXXXXXXXX X X X X X X X X X X X X X X X X X X X X X X X X X X ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 LV HV X1 X2 X3 X0 H0 H3 H2 H1 5 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 HV LV X1 X2 X3 X0 H0 H3 H2 H1 5 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 NW ES 0 6 12 GRAPHIC SCALE IN FEET HV LV X1 X2 X3 X0 H0 H3 H2 H1 5 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 NW ES 0 6 12 GRAPHIC SCALE IN FEET HV LV X1 X2 X3 X0 H0 H3 H2 H1 5 ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 NW ES 0 4 8 GRAPHIC SCALE IN FEET P A N E L GAS GAS GAS GASGASGASUGEUGE02030302HV LV X1 X2 X3 X0 H0 H3 H2 H1 5 GAS GAS GAS GAS ALASKA ELECTRIC & ENERGY COOPERATIVE, INC. ® 15820 BARCLAY DRIVE SISTERS, OR 97759 PHONE: (541) 549-8766 FAX: (541) 549-1901 N W E S 0 8 16 GRAPHIC SCALE IN FEET ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 ALASKA ELECTRIC& ENERGYCOOPERATIVE, INC.®15820 BARCLAY DRIVE SISTERS, OR 97759PHONE: (541) 549-8766FAX: (541) 549-1901 AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment E: Jacobs Engineering Class 3 AACE Cost Estimate Basis of Estimate Project: Central Peninsula Landfills – Landfill Gas to Energy Project Client: Alaska Electric & Energy Cooperative Estimate Date: July 2, 2019 1. Scope of Work Build new CHP plant building, and install new engine-generator and associated equipment. 1. Prepare site for new CHP building 2. Build new CHP building. 3. Furnish and install new engine-generator and associated process equipment. 4. Startup and testing of process equipment. 2. Overall Costs Low Range High Range -10% Construction Cost +20% $ 11,280,000 $ 12,534,000 $15,040,000 3. Major Assumptions 1. Excavation spoils can be stockpiled (1/2) a mile away, round-trip. 4. Allowance 1. Plumbing costs 2. HVAC costs 3. Electrical / I&C costs 5. Excluded Cost The following items are not included in the estimate, but need to be considered for the overall project cost: 1) None of the following costs have been included in the estimate. a) Land acquisition b) Design 2) Costs to handle contaminated material not included in the estimate. 3) The estimate does not include costs for fire protection. Code analysis at this 25% design level indicates that fire protection is not required in the building. A decision on appropriate fire protection and associated costs will be made in consultation with AEEC risk managers during final design. . 6. Estimate Unit Key Guide to abbreviations for Takeoff Quantity Units. All measurement abbreviations are U.S equivalents. CY – Cubic Yards LS - Lump Sum SF – Square Feet LB – Pound Summary Report - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Job Size: Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Duration: Design Stage: 25%Estimate Class: 3 Facility Work Pkg Description Labor Hours Labor Amount Material Amount Sub Amount Equip Amount Other Amount Equip Hours Total Amount 006 SITEWORK 31.0 Earthwork 2,858 174,687 28,000 43,650 114,077 2,368 360,414 32.0 Exterior Improvements 37,500 37,500 33.0 Utilities 95,000 95,000 006 SITEWORK 2,858 174,687 28,000 176,150 114,077 2,368 492,914 060 CPL CHP BUILDING 03.0 Concrete Work 1,256 74,409 77,718 24,322 176,449 13.0 Special Construction 958 70,202 80,056 18,450 122 168,708 22.0 Plumbing 77,000 77,000 23.0 HVAC 220,000 220,000 26.0 Electrical Work 740 53,987 1,700,750 530,000 4,920 36 2,289,657 28.0 Electronic Safety and Security 36 2,626 25,000 10,000 37,626 40.0 Process Pipe 876 63,763 379,000 442,763 43.0 Process Gas and Liquid Handling Equipment 320 20,975 318,694 3,360 28 343,029 060 CPL CHP BUILDING 4,186 285,962 2,581,218 861,322 26,730 186 3,755,232 070 GCCS (Gas Collection and Control System) 43.0 Process Gas and Liquid Handling Equipment 2,283,500 2,283,500 070 GCCS (Gas Collection and Control System)2,283,500 2,283,500 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:07 AM Page 1 Summary Report - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Job Size: Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Duration: Design Stage: 25%Estimate Class: 3 Estimate Totals Description Amount Totals Hours Rate Cost / Unit % of Total Labor 460,649 7,043.766 hrs 3.68% Material 2,609,218 20.82% Subcontract 3,320,972 26.50% Equipment 140,807 2,554.251 hrs 1.12% Other Subtotal Raw Costs 6,531,646 6,531,646 52.11%52.11% Material Sales & Use Tax - % Construction Equip Tax - % Total Taxes 6,531,646 52.11% Startup Cost Allowance 164,149 2.513 %1.31% Permits 39,965 6.645 %0.32% Subtotal Adj. Factors 204,114 6,735,760 1.63%53.74% Existing Conditions I,OH&P 15.000 % Concrete W ork I,OH&P 26,467 15.000 %0.21% Masonry W ork I,OH&P 15.000 % Metals W ork I,OH&P 15.000 % Architectural (Div 6-12)I,OH&P 15.000 % Special Construction I,OH&P 25,306 15.000 %0.20% Mechanical W ork I,OH&P 59,400 20.000 %0.47% Electrical Work I,OH&P 232,728 10.000 %1.86% Site/Civil I,OH&P 39,791 10.000 %0.32% Buried Piping I,OH&P 14,250 15.000 %0.11% Process Piping I,OH&P 110,691 25.000 %0.88% Instruments & Controls I,OH&P 18.000 % Process Equipment I,OH&P 131,326 5.000 %1.05% Subtotal Subcontractor I,OH&P 639,959 7,375,719 5.11%58.85% Contractor Contingency Subtotal Contingency 7,375,719 58.85% Total Cost To Prime Contractor 7,375,719 58.85% General Conditions 590,058 8.000 %4.71% Mobilization/Demobilization 221,272 3.000 %1.77% Subtotal Indirect Costs 811,330 8,187,049 6.47%65.32% Prime Contractor Home OfficeOH 818,705 10.000 %6.53% Prime Contractor Profit 409,352 5.000 %3.27% Bonds & Insurance 204,308 2.170 %1.63% Subtotal OH&P 1,432,365 9,619,414 11.43%76.75% Engineering and Design Service 961,942 10.000 %7.67% 961,942 10,581,356 7.67%84.42% Design Contingency 1,587,203 15.000 %12.66% Subtotal Contingency 1,587,203 12,168,559 12.66%97.09% Escalation 365,057 3.000 %2.91% Subtotal Escalation 365,057 12,533,616 2.91%100.00% Total Construction Cost 12,533,616 100.00% Total 12,533,616 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:07 AM Page 2 DETAIL REPORT - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Design Stage: 25%Estimate Class: 3 Facility Work Pkg Trade Pkg WorkActiv Unit Price Description Takeoff Quantity Labor Amount Material Amount Sub Amount Equip Amount Other Amount Total Cost/Unit Total Amount 006 SITEWORK 31.0 Earthwork 31.15 Site Preparation FJC-0020 Earthworks 31.00.02.05 Site/Civil, General Survey 1.00 ls 10,000 10,000 /ls 10,000 Erosion Control 1.00 ls 8,000 8,000 /ls 8,000 31.00.02.05 Site/Civil, General 18,000 /LS 18,000 FJC-0020 Earthworks 18,000 18,000 31.15 Site Preparation 1.00 LS 18,000 18,000 /LS 18,000 31.23 Earthworks, Imported Fill FJC-0020 Earthworks 31.20.11.00 Earthworks, Sitework, Place Topsoil Topsoil - 12 CY dump trucks, 1 mile RT, load, haul and dump 2,700.00 cy 25,650 10 /cy 25,650 31.20.11.00 Earthworks, Sitework, Place Topsoil 25,650 /CY 25,650 FJC-0020 Earthworks 25,650 25,650 31.23 Earthworks, Imported Fill 25,650 /CY 25,650 31.25 Earthworks, Structural FJC-0020 Earthworks 31.25.01.00 Earthworks, Structural, Excavation Structural Excavation, Excavator and Trucks, Small Crew 20,000.00 cy 68,670 --49,677 -6 /cy 118,347 Grade for slabs / Scarify and Recompact, Dozer and Traxcavator or Loader, Small Crew 780.00 sy 2,321 --1,804 -5 /sy 4,125 Structural Backfill, Dozer and Traxcavator or Loader, Small Crew 500.00 cy 2,232 --1,735 -8 /cy 3,967 Load Excess for Hauling, Rubber Tire Loader, Cat 930 20,000.00 cy 34,741 --26,937 -3 /cy 61,677 Haul / Remove Excess, 12 yd capacity, 2.5 miles RT 20,000.00 cy 40,577 --33,925 -4 /cy 74,502 31.25.01.00 Earthworks, Structural, Excavation 1.00 LS 148,540 114,077 262,617 /LS 262,617 31.25.03.00 Earthworks, Structural, Backfill Fill, gravel subbase, under building slab on grade 1,000.00 cy 26,147 28,000 ---54 /cy 54,147 31.25.03.00 Earthworks, Structural, Backfill 1.00 LS 26,147 28,000 54,147 /LS 54,147 FJC-0020 Earthworks 174,687 28,000 114,077 316,764 31.25 Earthworks, Structural 1.00 LS 174,687 28,000 114,077 316,764 /LS 316,764 31.0 Earthwork 1.00 LS 174,687 28,000 43,650 114,077 360,414 /LS 360,414 32.0 Exterior Improvements 31.48 Retaining Wall FJC-0025 Retaining Wall 31.15.07.00 Site Preparation, Other Retaining Wall 100' x 5' high 500.00 sf 17,500 35 /sf 17,500 31.15.07.00 Site Preparation, Other 1.00 LS 17,500 17,500 /LS 17,500 FJC-0025 Retaining Wall 17,500 17,500 31.48 Retaining Wall 1.00 LS 17,500 17,500 /LS 17,500 32.31 Fencing FJC-0028 Fencing 31.00.02.05 Site/Civil, General Fence 1.00 ls 20,000 20,000 /ls 20,000 31.00.02.05 Site/Civil, General 1.00 LS 20,000 20,000 /LS 20,000 FJC-0028 Fencing 20,000 20,000 32.31 Fencing 1.00 LS 20,000 20,000 /LS 20,000 32.0 Exterior Improvements 1.00 LS 37,500 37,500 /LS 37,500 33.0 Utilities 33.00 Utilities General FJC-0030 Stormwater System 33.90.90.00 Buried Utilities Stormwater 1.00 ls 50,000 50,000 /ls 50,000 NG Line Allowance 1.00 ls 45,000 45,000 /ls 45,000 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:06 AM Page 1 DETAIL REPORT - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Design Stage: 25%Estimate Class: 3 Facility Work Pkg Trade Pkg WorkActiv Unit Price Description Takeoff Quantity Labor Amount Material Amount Sub Amount Equip Amount Other Amount Total Cost/Unit Total Amount 33.90.90.00 Buried Utilities 95,000 95,000 FJC-0030 Stormwater System 95,000 95,000 33.00 Utilities General 1.00 LS 95,000 95,000 /LS 95,000 33.0 Utilities 1.00 LS 95,000 95,000 /LS 95,000 006 SITEWORK 1.00 LS 174,687 28,000 176,150 114,077 492,914 /LS 492,914 060 CPL CHP BUILDING 03.0 Concrete Work 03.12 Cast-In-Place Concrete, Pad Footings FJC-0055 Spread Footings at Frame Columns 03.10.01.24 Cast-In-Place Concrete, Pad Footings, 24" thick Fine grade, for slab on grade, by hand 300.00 sf 110 9 ---0 /sf 119 Fill, gravel subbase, under building slab on grade 11.11 cy 291 311 ---54 /cy 602 Concrete pumping, subcontract, all inclusive price 22.22 cy --333 --15 /cy 333 Forms in place, column footings 480.00 sf 6,346 480 ---14 /sf 6,826 Reinforcing in place, A615 Gr 60, priced per lbs.4,444.44 lb -2,222 1,778 --1 /lb 4,000 Concrete, ready mix, 4500 psi 22.22 CY -2,911 ---131 /CY 2,911 Add for concrete waste, 4500 psi 1.11 cy -142 ---128 /cy 142 Placing concrete, concrete pump 22.22 cy 872 ----39 /cy 872 Finishing footings, screed finish 300.00 sf 276 ----1 /sf 276 Curing, membrane spray 300.00 sf 31 12 ---0 /sf 43 03.10.01.24 Cast-In-Place Concrete, Pad Footings, 24" thick 22.00 CY 7,925 6,088 2,111 733 /CY 16,124 FJC-0055 Spread Footings at Frame Columns 7,925 6,088 2,111 16,124 FJC-0060 Spread Footings at Wind Columns 03.10.01.12 Cast-In-Place Concrete, Pad Footings, 12" thick Fine grade, for slab on grade, by hand 36.00 sf 13 1 ---0 /sf 14 Fill, gravel subbase, under building slab on grade 1.33 cy 35 37 ---54 /cy 72 Concrete pumping, subcontract, all inclusive price 1.33 cy --20 --15 /cy 20 Forms in place, column footings 48.00 sf 635 48 ---14 /sf 683 Reinforcing in place, A615 Gr 60, priced per lbs.266.67 lb -133 107 --1 /lb 240 Concrete, ready mix, 4500 psi 1.33 CY -175 ---131 /CY 175 Add for concrete waste, 4500 psi 0.07 cy -9 ---128 /cy 9 Placing concrete, concrete pump 1.33 cy 52 ----39 /cy 52 Finishing footings, screed finish 36.00 sf 33 ----1 /sf 33 Curing, membrane spray 36.00 sf 4 1 ---0 /sf 5 03.10.01.12 Cast-In-Place Concrete, Pad Footings, 12" thick 1.30 CY 772 404 127 1,002 /CY 1,303 FJC-0060 Spread Footings at Wind Columns 772 404 127 1,303 03.12 Cast-In-Place Concrete, Pad Footings 24.00 CY 8,697 6,492 2,238 726 /CY 17,427 03.13 Cast-In-Place Concrete, Continuous Footings FJC-0050 Concrete Footing around Builiding Perimeter 03.10.02.24 Cast-In-Place Concrete, Continuous Footings, 24" thick Fine grade, for slab on grade, by hand 640.00 sf 234 19 ---0 /sf 253 Fill, gravel subbase, under building slab on grade 15.80 cy 413 442 ---54 /cy 856 Concrete pumping, subcontract, all inclusive price 23.70 cy --356 --15 /cy 356 Concrete pumping, subcontract, all inclusive price 7.90 cy --119 --15 /cy 119 Forms in place, continuous footing, sides 640.00 sf 4,231 640 ---8 /sf 4,871 Forms in place, structural walls, to 8' high, hand set 640.00 sf 6,346 640 ---11 /sf 6,986 Reinforcing in place, A615 Gr 60, priced per lbs.4,266.67 lb -2,133 1,707 --1 /lb 3,840 Reinforcing in place, A615 Gr 60, priced per lbs.1,777.78 lb -889 711 --1 /lb 1,600 Concrete, ready mix, 4500 psi 23.70 CY -3,105 ---131 /CY 3,105 Concrete, ready mix, 4500 psi 7.90 CY -1,035 ---131 /CY 1,035 Add for concrete waste, 4500 psi 1.19 cy -152 ---128 /cy 152 Add for concrete waste, 4500 psi 0.40 cy -51 ---128 /cy 51 Placing concrete, concrete pump 23.70 cy 930 ----39 /cy 930 Placing concrete, concrete pump, for structural wall to 12" thick 7.90 cy 351 ----44 /cy 351 Finishing footings, screed finish 640.00 sf 589 ----1 /sf 589 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:06 AM Page 2 DETAIL REPORT - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Design Stage: 25%Estimate Class: 3 Facility Work Pkg Trade Pkg WorkActiv Unit Price Description Takeoff Quantity Labor Amount Material Amount Sub Amount Equip Amount Other Amount Total Cost/Unit Total Amount 03.10.02.24 Cast-In-Place Concrete, Continuous Footings, 24" thick Patch & plug tieholes 640.00 sf 502 13 ---1 /sf 515 Stone rub 640.00 sf 1,673 19 ---3 /sf 1,693 Curing, membrane spray 640.00 sf 67 26 ---0 /sf 93 Curing, membrane spray 640.00 sf 67 26 ---0 /sf 93 03.10.02.24 Cast-In-Place Concrete, Continuous Footings, 24" thick 32.00 CY 15,403 9,190 2,892 859 /CY 27,485 FJC-0050 Concrete Footing around Builiding Perimeter 15,403 9,190 2,892 27,485 03.13 Cast-In-Place Concrete, Continuous Footings 32.00 CY 15,403 9,190 2,892 859 /CY 27,485 03.18 Cast-In-Place Concrete, Slabs on Grade FJC-0065 Building Concrete Slab on Grade 03.10.05.08 Cast-In-Place Concrete, Slabs on Grade, 8" thick Fine grade, for slab on grade, by hand 5,500.00 sf 2,013 165 ---0 /sf 2,178 Fill, gravel subbase, under building slab on grade 203.70 cy 5,326 5,704 ---54 /cy 11,030 Fill, sand subbase, under building slab on grade 101.85 cy 3,995 1,849 ---57 /cy 5,843 Concrete pumping, subcontract, all inclusive price 135.80 cy --2,037 --15 /cy 2,037 Slab on grade edge forms, 7" to 12"213.33 sf 2,538 213 ---13 /sf 2,752 Reinforcing in place, A615 Gr 60, priced per lbs.24,444.44 lb -12,222 9,778 --1 /lb 22,000 Concrete, ready mix, 4500 psi 135.80 CY -17,790 ---131 /CY 17,790 Add for concrete waste, 4500 psi 6.79 cy -869 ---128 /cy 869 Placing concrete, concrete pump 135.80 cy 5,326 ----39 /cy 5,326 Finishing floors, monolithic, trowel finish (machine)5,500.00 sf 6,746 110 ---1 /sf 6,856 Curing, membrane spray 5,500.00 sf 575 220 ---0 /sf 795 Polyethelene vapor barrier, 10 mil thick 55.00 sq 792 583 ---25 /sq 1,375 03.10.05.08 Cast-In-Place Concrete, Slabs on Grade, 8" thick 136.00 CY 27,312 39,725 11,815 580 /CY 78,852 FJC-0065 Building Concrete Slab on Grade 27,312 39,725 11,815 78,852 03.18 Cast-In-Place Concrete, Slabs on Grade 136.00 CY 27,312 39,725 11,815 580 /CY 78,852 03.20 Cast-In-Place Concrete, Straight Walls FJC-0085 Containment Area - Concrete Walls in Coolant Storage 03.10.06.06 Cast-In-Place Concrete, Straight Walls, 6" thick Concrete pumping, subcontract, all inclusive price 4.86 cy --73 --15 /cy 73 Forms in place, structural walls, to 8' high, hand set 525.00 sf 5,206 525 ---11 /sf 5,731 Waterstop, PVC, center bulb, 9" wide 75.00 lf 397 225 ---8 /lf 622 Reinforcing in place, A615 Gr 60, priced per lbs.1,215.28 lb -608 486 --1 /lb 1,094 Concrete, ready mix, 4500 psi 4.86 CY -637 ---131 /CY 637 Add for concrete waste, 4500 psi 0.24 cy -31 ---128 /cy 31 Placing concrete, concrete pump, for structural wall to 12" thick 4.86 cy 216 ----44 /cy 216 Patch & plug tieholes 525.00 sf 412 11 ---1 /sf 422 Stone rub 525.00 sf 1,373 16 ---3 /sf 1,388 Curing, membrane spray 525.00 sf 55 21 ---0 /sf 76 03.10.06.06 Cast-In-Place Concrete, Straight Walls, 6" thick 5.00 CY 7,658 2,073 559 2,058 /CY 10,290 FJC-0085 Containment Area - Concrete Walls in Coolant Storage 7,658 2,073 559 10,290 03.20 Cast-In-Place Concrete, Straight Walls 5.00 CY 7,658 2,073 559 2,058 /CY 10,290 03.27 Cast-In-Place Concrete, Equipment Pads FJC-0070 Isolated Equipment Pad in Engine Room 03.10.13.99 Cast-In-Place Concrete, Equipment Pads, Other Fine grade, for slab on grade, by hand 260.00 sf 95 8 ---0 /sf 103 Fill, gravel subbase, under building slab on grade 4.82 cy 126 135 ---54 /cy 261 Fill, sand subbase, under building slab on grade 4.82 cy 189 87 ---57 /cy 276 Concrete pumping, subcontract, all inclusive price 28.89 cy --433 --15 /cy 433 Base slab edge forms, 36" to 48"216.00 sf 3,570 292 ---18 /sf 3,861 Reinforcing in place, A615 Gr 60, priced per lbs.5,200.00 lb -2,600 2,080 --1 /lb 4,680 Concrete, ready mix, 4500 psi 28.89 CY -3,784 ---131 /CY 3,784 Add for concrete waste, 4500 psi 1.44 cy -185 ---128 /cy 185 Placing concrete, concrete pump, for base slab 24" to 36"28.89 cy 755 ----26 /cy 755 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:06 AM Page 3 DETAIL REPORT - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Design Stage: 25%Estimate Class: 3 Facility Work Pkg Trade Pkg WorkActiv Unit Price Description Takeoff Quantity Labor Amount Material Amount Sub Amount Equip Amount Other Amount Total Cost/Unit Total Amount 03.10.13.99 Cast-In-Place Concrete, Equipment Pads, Other Finishing floors, monolithic, trowel finish (machine)260.00 sf 319 5 ---1 /sf 324 Curing, membrane spray 260.00 sf 27 10 ---0 /sf 38 03.10.13.99 Cast-In-Place Concrete, Equipment Pads, Other 29.00 CY 5,081 7,107 2,513 507 /CY 14,701 FJC-0070 Isolated Equipment Pad in Engine Room 5,081 7,107 2,513 14,701 FJC-0075 Equipment Pad at LFG Blower Skid 03.10.13.06 Cast-In-Place Concrete, Equipment Pads, 6" thick Fine grade, for slab on grade, by hand 408.00 sf 149 12 ---0 /sf 162 Fill, gravel subbase, under building slab on grade 15.11 cy 395 423 ---54 /cy 818 Concrete pumping, subcontract, all inclusive price 7.56 cy --113 --15 /cy 113 Reinforcing in place, A615 Gr 60, priced per lbs.1,360.00 lb -680 544 --1 /lb 1,224 Concrete, ready mix, 4500 psi 7.56 CY -990 ---131 /CY 990 Add for concrete waste, 4500 psi 0.38 cy -48 ---128 /cy 48 Finishing floors, monolithic, trowel finish (machine)408.00 sf 500 8 ---1 /sf 509 Curing, membrane spray 408.00 sf 43 16 ---0 /sf 59 03.10.13.06 Cast-In-Place Concrete, Equipment Pads, 6" thick 8.00 CY 1,088 2,178 657 490 /CY 3,923 FJC-0075 Equipment Pad at LFG Blower Skid 1,088 2,178 657 3,923 FJC-0080 Equipment Pad at Oil Storage Tank 03.10.13.06 Cast-In-Place Concrete, Equipment Pads, 6" thick Fine grade, for slab on grade, by hand 192.00 sf 70 6 ---0 /sf 76 Fill, gravel subbase, under building slab on grade 3.56 cy 93 100 ---54 /cy 193 Fill, sand subbase, under building slab on grade 3.56 cy 139 65 ---57 /cy 204 Concrete pumping, subcontract, all inclusive price 3.56 cy --53 --15 /cy 53 Reinforcing in place, A615 Gr 60, priced per lbs.640.00 lb -320 256 --1 /lb 576 Concrete, ready mix, 4500 psi 3.56 CY -466 ---131 /CY 466 Add for concrete waste, 4500 psi 0.18 cy -23 ---128 /cy 23 Finishing floors, monolithic, trowel finish (machine)192.00 sf 235 4 ---1 /sf 239 Curing, membrane spray 192.00 sf 20 8 ---0 /sf 28 03.10.13.06 Cast-In-Place Concrete, Equipment Pads, 6" thick 4.00 CY 558 990 309 464 /CY 1,858 FJC-0080 Equipment Pad at Oil Storage Tank 558 990 309 1,858 FJC-0090 Housekeeping Pads (2 ea.) in Electrical Room 03.10.13.04 Cast-In-Place Concrete, Equipment Pads, 4" thick Fine grade, for slab on grade, by hand 255.00 sf 93 8 ---0 /sf 101 Fill, gravel subbase, under building slab on grade 3.15 cy 82 88 ---54 /cy 170 Fill, sand subbase, under building slab on grade 3.15 cy 123 57 ---57 /cy 181 Concrete pumping, subcontract, all inclusive price 3.15 cy --47 --15 /cy 47 Edge forms, housekeeping pads, up to 6"102.00 lf 357 27 ---4 /lf 384 Reinforcing in place, A615 Gr 60, priced per lbs.559.88 lb -280 224 --1 /lb 504 Concrete, ready mix, 4500 psi 3.15 CY -412 ---131 /CY 412 Add for concrete waste, 4500 psi 0.16 cy -20 ---128 /cy 20 Placing concrete, concrete pump 3.15 cy 123 ----39 /cy 123 Finish housekeeping pads 255.00 sf 625 8 ---2 /sf 633 Curing, membrane spray 255.00 sf 27 10 ---0 /sf 37 03.10.13.04 Cast-In-Place Concrete, Equipment Pads, 4" thick 3.00 CY 1,432 910 271 871 /CY 2,613 FJC-0090 Housekeeping Pads (2 ea.) in Electrical Room 1,432 910 271 2,613 FJC-0095 Equipment Pad for Engine Aftercooler 03.10.13.99 Cast-In-Place Concrete, Equipment Pads, Other Fine grade, for slab on grade, by hand 260.00 sf 95 8 ---0 /sf 103 Fill, gravel subbase, under building slab on grade 9.63 cy 252 270 ---54 /cy 521 Fill, sand subbase, under building slab on grade 4.82 cy 189 87 ---57 /cy 276 Concrete pumping, subcontract, all inclusive price 19.26 cy --289 --15 /cy 289 Base slab edge forms, 24" to 36"132.00 sf 2,182 165 ---18 /sf 2,347 Reinforcing in place, A615 Gr 60, priced per lbs.3,466.67 lb -1,733 1,387 --1 /lb 3,120 Concrete, ready mix, 4500 psi 19.26 CY -2,523 ---131 /CY 2,523 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:06 AM Page 4 DETAIL REPORT - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Design Stage: 25%Estimate Class: 3 Facility Work Pkg Trade Pkg WorkActiv Unit Price Description Takeoff Quantity Labor Amount Material Amount Sub Amount Equip Amount Other Amount Total Cost/Unit Total Amount 03.10.13.99 Cast-In-Place Concrete, Equipment Pads, Other Add for concrete waste, 4500 psi 0.96 cy -123 ---128 /cy 123 Placing concrete, concrete pump, for base slab 12" to 24"19.26 cy 604 ----31 /cy 604 Finishing floors, monolithic, trowel finish (machine)260.00 sf 319 5 ---1 /sf 324 Curing, membrane spray 260.00 sf 27 10 ---0 /sf 38 03.10.13.99 Cast-In-Place Concrete, Equipment Pads, Other 19.00 CY 3,668 4,925 1,676 540 /CY 10,268 FJC-0095 Equipment Pad for Engine Aftercooler 3,668 4,925 1,676 10,268 FJC-0100 Equipment Pad for Station Transformer 03.10.13.12 Cast-In-Place Concrete, Equipment Pads, 12" thick Fine grade, for slab on grade, by hand 40.00 sf 15 1 ---0 /sf 16 Fill, gravel subbase, under building slab on grade 0.74 cy 19 21 ---54 /cy 40 Fill, sand subbase, under building slab on grade 0.74 cy 29 13 ---57 /cy 43 Concrete pumping, subcontract, all inclusive price 1.48 cy --22 --15 /cy 22 Base slab edge forms, 12" to 24"26.00 sf 378 26 ---16 /sf 404 Reinforcing in place, A615 Gr 60, priced per lbs.266.67 lb -133 107 --1 /lb 240 Concrete, ready mix, 4500 psi 1.48 CY -194 ---131 /CY 194 Add for concrete waste, 4500 psi 0.07 cy -9 ---128 /cy 9 Placing concrete, concrete pump, for base slab 12" to 24"1.48 cy 46 ----31 /cy 46 Finishing floors, monolithic, trowel finish (machine)40.00 sf 49 1 ---1 /sf 50 Curing, membrane spray 40.00 sf 4 2 ---0 /sf 6 03.10.13.12 Cast-In-Place Concrete, Equipment Pads, 12" thick 1.50 CY 541 401 129 714 /CY 1,070 FJC-0100 Equipment Pad for Station Transformer 541 401 129 1,070 FJC-0105 Equipment Pad for Transformer 03.10.13.99 Cast-In-Place Concrete, Equipment Pads, Other Fine grade, for slab on grade, by hand 196.00 sf 72 6 ---0 /sf 78 Fill, gravel subbase, under building slab on grade 7.26 cy 190 203 ---54 /cy 393 Fill, sand subbase, under building slab on grade 3.63 cy 142 66 ---57 /cy 208 Concrete pumping, subcontract, all inclusive price 14.52 cy --218 --15 /cy 218 Base slab edge forms, 24" to 36"112.00 sf 1,851 140 ---18 /sf 1,991 Reinforcing in place, A615 Gr 60, priced per lbs.2,613.33 lb -1,307 1,045 --1 /lb 2,352 Concrete, ready mix, 4500 psi 14.52 CY -1,902 ---131 /CY 1,902 Add for concrete waste, 4500 psi 0.73 cy -93 ---128 /cy 93 Placing concrete, concrete pump, for base slab 12" to 24"14.52 cy 456 ----31 /cy 456 Finishing floors, monolithic, trowel finish (machine)196.00 sf 240 4 ---1 /sf 244 Curing, membrane spray 196.00 sf 21 8 ---0 /sf 28 03.10.13.99 Cast-In-Place Concrete, Equipment Pads, Other 14.50 CY 2,971 3,728 1,263 549 /CY 7,963 FJC-0105 Equipment Pad for Transformer 2,971 3,728 1,263 7,963 03.27 Cast-In-Place Concrete, Equipment Pads 79.00 CY 15,339 20,238 6,819 537 /CY 42,396 03.0 Concrete Work 275.00 CY 74,409 77,718 24,322 642 /CY 176,449 13.0 Special Construction 13.00 Special Construction FJC-0150 Pre-Engineered Metal Building 13.00.01.00 Metal Building Systems - Pre-Engineered Pre-eng stl bldg,clear span rigid frame,30 psf roof and 20 psf wind load,50'100' x 24'v h,incl 26ga colrd ribbd rfng&sidng,excl ftngs,slab,anchr bolts 5,500.00 flr 60,091 52,498 -18,398 -24 /flr 130,986 Pre-Eng Steel Bldg Access., doors, H.M. self framing, single leaf, economy, 3' x 7', incl. butts, lockset & trim 4.00 opng 1,117 3,013 ---1,032 /opng 4,130 Pre-Eng Steel Bldg Access., pre-eng. steel doors, double leaf, 6' x 7'2.00 opng 1,396 2,760 ---2,078 /opng 4,156 Pre-Eng Steel Bldg Access., framing only, for windows below, 4' x 3', (4030) 8.00 opng 2,234 2,236 ---559 /opng 4,470 Pre-Eng. Steel Bldg, vinyl faced, with steel banding, rated .6 lb density, R-30, 10" thick 8,000.00 sf 4,307 15,640 ---2 /sf 19,947 Pre-Eng Steel Bldg Access., sash, single slide, glazed, with screens, 4' x 3', (4030) 8.00 opng 1,057 3,910 -52 -627 /opng 5,019 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:06 AM Page 5 DETAIL REPORT - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Design Stage: 25%Estimate Class: 3 Facility Work Pkg Trade Pkg WorkActiv Unit Price Description Takeoff Quantity Labor Amount Material Amount Sub Amount Equip Amount Other Amount Total Cost/Unit Total Amount 13.00.01.00 Metal Building Systems - Pre-Engineered 5,500.00 SF 70,202 80,056 18,450 31 /SF 168,708 FJC-0150 Pre-Engineered Metal Building 70,202 80,056 18,450 168,708 13.00 Special Construction 70,202 80,056 18,450 /SF 168,708 13.0 Special Construction 5,500.00 SF 70,202 80,056 18,450 31 /SF 168,708 22.0 Plumbing 22.00 Plumbing FJC-0260 Plumbing 22.00.01.00 Mechanical, Plumbing Plumbing Allowance 5,500.00 sf 77,000 14 /sf 77,000 22.00.01.00 Mechanical, Plumbing 5,500.00 SF 77,000 14 /SF 77,000 FJC-0260 Plumbing 77,000 77,000 22.00 Plumbing 5,500.00 SF 77,000 14 /SF 77,000 22.0 Plumbing 5,500.00 SF 77,000 14 /SF 77,000 23.0 HVAC 23.00 HVAC FJC-0270 HVAC 23.00.02.00 Mechanical, HVAC HVAC Allowance 5,500.00 sf 220,000 40 /sf 220,000 23.00.02.00 Mechanical, HVAC 5,500.00 SF 220,000 40 /SF 220,000 FJC-0270 HVAC 220,000 220,000 23.00 HVAC 5,500.00 SF 220,000 40 /SF 220,000 23.0 HVAC 5,500.00 SF 220,000 40 /SF 220,000 26.0 Electrical Work 26.00 Electrical FJC-0340 Electrical 26.00.99.00 Electrical Electrical / I&C - 10% of Direct Cost 1.00 ls 0 0 380,000 0 0 380,000 /ls 380,000 26.00.99.00 Electrical 1.00 LS 380,000 380,000 /LS 380,000 FJC-0340 Electrical 380,000 380,000 26.00 Electrical 1.00 LS 380,000 380,000 /LS 380,000 26.25 Electrical Equipment FJC-0300 Genset 26.25.07.10 Electrical Equipment - Gensets Caterpillar 3520 Genset, 4160B, 1500 RPM, 1.6 Mw 1.00 ea 15,321 1,200,000 2,400 1,217,721 /ea 1,217,721 Radiators 1.00 ea 3,502 65,000 68,502 /ea 68,502 Silencers 1.00 ea 1,751 6,000 7,751 /ea 7,751 26.25.07.10 Electrical Equipment - Gensets 1.00 LS 20,573 1,271,000 2,400 1,293,973 /LS 1,293,973 FJC-0300 Genset 20,573 1,271,000 2,400 1,293,973 FJC-0320 Electrical Equipment 26.25.03.01 Electrical Equipment Step-Up Transformer 1.00 ea 8,025 80,000 1,200 89,225 /ea 89,225 Station Transformer 1.00 ea 4,377 25,000 600 29,977 /ea 29,977 Interconnection Breaker 1.00 ea 1,751 95,000 96,751 /ea 96,751 Electrical Other (Relay/Metering)1.00 ea 1,751 30,000 31,751 /ea 31,751 Neutral Ground Resistors 1.00 ea 584 3,750 4,334 /ea 4,334 Variable Frequency Drives 1.00 ea 1,167 25,000 26,167 /ea 26,167 Battery Systems / Inverter 1.00 ea 1,751 30,000 31,751 /ea 31,751 Lighting Panels / 120V XFMR / Circuit Breakers 1.00 ea 2,626 25,000 27,626 /ea 27,626 Switchgear 1.00 ea 3,502 16,000 19,502 /ea 19,502 Motor Control Center 1.00 ea 4,377 70,000 480 74,857 /ea 74,857 SCADA System 1.00 ea 150,000 150,000 /ea 150,000 BOP PLC Control Panels 1.00 ea 3,502 30,000 240 33,742 /ea 33,742 26.25.03.01 Electrical Equipment 1.00 LS 33,413 429,750 150,000 2,520 615,683 /LS 615,683 FJC-0320 Electrical Equipment 33,413 429,750 150,000 2,520 615,683 26.25 Electrical Equipment 1.00 LS 53,987 1,700,750 150,000 4,920 1,909,657 /LS 1,909,657 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:06 AM Page 6 DETAIL REPORT - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Design Stage: 25%Estimate Class: 3 Facility Work Pkg Trade Pkg WorkActiv Unit Price Description Takeoff Quantity Labor Amount Material Amount Sub Amount Equip Amount Other Amount Total Cost/Unit Total Amount 26.0 Electrical Work 1.00 LS 53,987 1,700,750 530,000 4,920 2,289,657 /LS 2,289,657 28.0 Electronic Safety and Security 28.00 Electronic Safety and Security FJC-0360 Electronic Safety and Security 28.35.01.00 Electronic Safety and Security Methane Detection System 1.00 ea 2,626 25,000 27,626 /ea 27,626 Fire Alarm System 1.00 ea 10,000 10,000 /ea 10,000 28.35.01.00 Electronic Safety and Security 1.00 LS 2,626 25,000 10,000 37,626 /LS 37,626 FJC-0360 Electronic Safety and Security 2,626 25,000 10,000 37,626 28.00 Electronic Safety and Security 1.00 LS 2,626 25,000 10,000 37,626 /LS 37,626 28.0 Electronic Safety and Security 1.00 LS 2,626 25,000 10,000 37,626 /LS 37,626 40.0 Process Pipe 40.00 Process Pipe General FJC-0230 Process Piping 40.00.01.01 Process Pipe, General Exhaust Piping 1.00 ls 8,729 80,000 88,729 /ls 88,729 LFG Piping (LFG Fuel Train)1.00 ls 8,729 30,000 38,729 /ls 38,729 Glycol Piping (Dehydration / Cooling)1.00 ls 11,639 60,000 71,639 /ls 71,639 Lube Oil Piping 1.00 ls 5,819 20,000 25,819 /ls 25,819 Natural Gas Piping 1.00 ls 6,547 20,000 26,547 /ls 26,547 Condensate Piping 1.00 ls 8,002 40,000 48,002 /ls 48,002 Crankcase Ventilation 1.00 ls 2,910 4,000 6,910 /ls 6,910 Compressed Air Piping 1.00 ls 4,365 20,000 24,365 /ls 24,365 40.00.01.01 Process Pipe, General 1.00 LS 56,740 274,000 330,740 /LS 330,740 FJC-0230 Process Piping 56,740 274,000 330,740 FJC-0250 GCCS Installation Costs 40.30.06.01 Process Valves Automated Valves and Gauges 1.00 ls 4,682 65,000 69,682 /ls 69,682 Manual Valves and Gauges 1.00 ls 2,341 40,000 42,341 /ls 42,341 40.30.06.01 Process Valves 1.00 LS 7,023 105,000 112,023 /LS 112,023 FJC-0250 GCCS Installation Costs 7,023 105,000 112,023 40.00 Process Pipe General 1.00 LS 63,763 379,000 442,763 /LS 442,763 40.0 Process Pipe 1.00 LS 63,763 379,000 442,763 /LS 442,763 43.0 Process Gas and Liquid Handling Equipment 43.01 Process Equipment - General Items FJC-0210 Process Equipment 43.00.99.00 Process Equipment, Other Landfill Gas Pressurization / Cooling Skid 1.00 ea 7,866 248,694 1,200 257,760 /ea 257,760 Oil Storage and Pumping System, Day Tanks, etc 1.00 ea 7,866 35,000 1,200 44,066 /ea 44,066 Condensate Sump & Pumping Station 1.00 ls 1,573 15,000 320 16,893 /ls 16,893 Crankcase Vent Blower 1.00 ls 1,573 8,000 320 9,893 /ls 9,893 Instrument Air Compressor 1.00 ls 2,098 12,000 320 14,418 /ls 14,418 43.00.99.00 Process Equipment, Other 1.00 LS 20,975 318,694 3,360 343,029 /LS 343,029 FJC-0210 Process Equipment 20,975 318,694 3,360 343,029 43.01 Process Equipment - General Items 1.00 LS 20,975 318,694 3,360 343,029 /LS 343,029 43.0 Process Gas and Liquid Handling Equipment 1.00 LS 20,975 318,694 3,360 343,029 /LS 343,029 060 CPL CHP BUILDING 1.00 LS 285,962 2,581,218 861,322 26,730 3,755,232 /LS 3,755,232 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:06 AM Page 7 DETAIL REPORT - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Design Stage: 25%Estimate Class: 3 Facility Work Pkg Trade Pkg WorkActiv Unit Price Description Takeoff Quantity Labor Amount Material Amount Sub Amount Equip Amount Other Amount Total Cost/Unit Total Amount 070 GCCS (Gas Collection and Control System) 43.0 Process Gas and Liquid Handling Equipment 43.01 Process Equipment - General Items FJC-0250 GCCS Installation Costs 43.00.99.00 Process Equipment, Other Cell 4 Upgradees 1.00 ls 142,000 142,000 /ls 142,000 Cell 5 Upgradees 1.00 ls 264,000 264,000 /ls 264,000 Vertical Expansion 1.00 ls 1,715,000 1,715,000 /ls 1,715,000 LFG Header to LFGTE Facility (w/ Condensate Sump)1.00 ls 112,500 112,500 /ls 112,500 Other / Miscellaneous 1.00 ls 50,000 50,000 /ls 50,000 43.00.99.00 Process Equipment, Other 1.00 LS 2,283,500 2,283,500 /LS 2,283,500 FJC-0250 GCCS Installation Costs 2,283,500 2,283,500 43.01 Process Equipment - General Items 1.00 LS 2,283,500 2,283,500 /LS 2,283,500 43.0 Process Gas and Liquid Handling Equipment 1.00 LS 2,283,500 2,283,500 /LS 2,283,500 070 GCCS (Gas Collection and Control System) 1.00 LS 2,283,500 2,283,500 /LS 2,283,500 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:06 AM Page 8 DETAIL REPORT - AEEC Central Landfills LFGTE Project Project type: LFG - CHP Project Name: D3196100_25Pct_AEEC_Landfill_Gas_Project Estimator: Frank Costanzo Project Number: D3196100 Revision/Date: 01 / 07-02-2019 Design Stage: 25%Estimate Class: 3 Estimate Totals Description Amount Totals Hours Rate Cost / Unit % of Total Labor 460,649 7,043.766 hrs 3.68% Material 2,609,218 20.82% Subcontract 3,320,972 26.50% Equipment 140,807 2,554.251 hrs 1.12% Other Subtotal Raw Costs 6,531,646 6,531,646 52.11%52.11% Material Sales & Use Tax - % Construction Equip Tax - % Total Taxes 6,531,646 52.11% Startup Cost Allowance 164,149 2.513 %1.31% Permits 39,965 6.645 %0.32% Subtotal Adj. Factors 204,114 6,735,760 1.63%53.74% Existing Conditions I,OH&P 15.000 % Concrete W ork I,OH&P 26,467 15.000 %0.21% Masonry W ork I,OH&P 15.000 % Metals W ork I,OH&P 15.000 % Architectural (Div 6-12)I,OH&P 15.000 % Special Construction I,OH&P 25,306 15.000 %0.20% Mechanical W ork I,OH&P 59,400 20.000 %0.47% Electrical W ork I,OH&P 232,728 10.000 %1.86% Site/Civil I,OH&P 39,791 10.000 %0.32% Buried Piping I,OH&P 14,250 15.000 %0.11% Process Piping I,OH&P 110,691 25.000 %0.88% Instruments & Controls I,OH&P 18.000 % Process Equipment I,OH&P 131,326 5.000 %1.05% Subtotal Subcontractor I,OH&P 639,959 7,375,719 5.11%58.85% Contractor Contingency Subtotal Contingency 7,375,719 58.85% Total Cost To Prime Contractor 7,375,719 58.85% General Conditions 590,058 8.000 %4.71% Mobilization/Demobilization 221,272 3.000 %1.77% Subtotal Indirect Costs 811,330 8,187,049 6.47%65.32% Prime Contractor Home OfficeOH 818,705 10.000 %6.53% Prime Contractor Profit 409,352 5.000 %3.27% Bonds & Insurance 204,308 2.170 %1.63% Subtotal OH&P 1,432,365 9,619,414 11.43%76.75% Engineering and Design Service 961,942 10.000 %7.67% 961,942 10,581,356 7.67%84.42% Design Contingency 1,587,203 15.000 %12.66% Subtotal Contingency 1,587,203 12,168,559 12.66%97.09% Escalation 365,057 3.000 %2.91% Subtotal Escalation 365,057 12,533,616 2.91%100.00% Total Construction Cost 12,533,616 100.00% Total 12,533,616 D3196100_25Pct_AEEC_Landfill_Gas_Project_03 7/2/2019 11:06 AM Page 9 AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment F: Jacobs Engineering Permit Requirements Memorandum 949 E. 36th Avenue Suite 500 Anchorage, AK 99508 907.762.1500 www.jacobs.com Document Tracking Number (JETT) 1 sor Subject Permit Requirements Project Name CPL Landfill Gas CHP Project Attention Mike Salzetti From Cory Hinds Date July 2, 2019 Copies to Jack Maryott/KPB Permit Estimated Cost Notes Title V Air Emission $20,000 Based on previous experience, required when Cell 5 permitted Construction $10,000 Building (electrical, mechanical, structural, architectural), land use/zoning, stormwater, air quality 1 1. This is a general list of permits. Specific permit requirements will be determined during detailed design AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment G: Executive Summary from the Leidos Interconnection Impact Study Final Report KPB 1.6 MW Generation Interconnection Impact Study Homer Electric Association, Inc. January 24, 2020 File: 331308 EXECUTIVE SUMMARY This report documents the Interconnection Impact Study that was performed for the distributed generation interconnection application submitted by Kenai Peninsula Borough (KPB) (Interconnecting Customer) for the 1.6 MW generation facility, which is located at 46915 Sterling Hwy, Soldotna, AK 99669. This project is proposed to be interconnected on circuit BTD South (BTD 614) out of Billy Thompson Substation. The study results show that the new customer and distributed generation (DG) system can connect to Homer Electric’s distribution system under the existing, normal system configuration based on applicable standards and consideration of the required facility upgrades identified in the study. The following summarizes required upgrades identified in the study: 1.The results indicate there is a risk of unintentional islanding. HEA will perform a detailed study to determine if they want to install induction generator or direct transfer trip (DTT) to mitigate the islanding issue. AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment H: Attachment H: CH2M Hill Engineers CPL Landfill Gas Utilization Feasibility Study CH2M HILL Engineers, Inc. • COMPANY PROPRIETARY F I NA L R E PO R T Central Peninsula Landfill Landfill Gas Utilization Feasibility Study Prepared for Kenai Peninsula Borough June 23, 2016 CH2M HILL Engineers, Inc. 949 E 36 Avenue, Suite 500 Anchorage, AK 99508 Contents Section Page Acronyms and Abbreviations .............................................................................................................. v 1. Introduction ....................................................................................................................... 1-1 2. Background ........................................................................................................................ 2-1 2.1 LFG Supply ........................................................................................................................ 2-2 2.2 Collection Efficiency of LFG Collection System ................................................................ 2-3 2.3 LFG Quality ....................................................................................................................... 2-3 2.4 Off-site Utilization Location ............................................................................................. 2-3 2.5 Energy Use ....................................................................................................................... 2-3 2.6 Bale Fills ........................................................................................................................... 2-4 3. Landfill Gas Utilization Options ........................................................................................... 3-1 3.1 Boiler ................................................................................................................................ 3-1 3.2 Engine Generator ............................................................................................................. 3-2 3.3 Combined Heat and Power .............................................................................................. 3-3 3.4 ENSTAR Pipeline ............................................................................................................... 3-3 3.5 Off-site Utilization ............................................................................................................ 3-4 3.6 Pipelines ........................................................................................................................... 3-5 4. Regulatory Review .............................................................................................................. 4-1 5. Landfill Gas-to-Energy Costs and Revenues .......................................................................... 5-1 6. Procurement Approaches .................................................................................................... 6-1 6.1 Internal Self-development Approach .............................................................................. 6-2 6.2 LFGTE Facility Ownership Considerations ........................................................................ 6-2 6.3 Outside Third-party Developer Approach ....................................................................... 6-3 6.4 Other Project Delivery Considerations ............................................................................ 6-3 7. Project Construction Approaches ........................................................................................ 7-1 7.1 Design-Bid-Build Approach .............................................................................................. 7-2 7.2 Design-Bid Approach ....................................................................................................... 7-2 7.3 Construction Management Approach ............................................................................. 7-2 7.4 Landfill Gas-to-Energy Facilities Operations and Maintenance ....................................... 7-2 7.5 Partnering Approaches for Agreement with Owner and Gas Supplier............................ 7-4 7.6 Example Business Model ................................................................................................. 7-5 8. Conclusions and Recommendations..................................................................................... 8-1 8.1 Conclusions ...................................................................................................................... 8-1 8.2 Recommendations ........................................................................................................... 8-1 9. References .......................................................................................................................... 9-1 EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY III CONTENTS Appendixes A LFGTE Calculation Sheet B CG13216 – Part A – Cut Sheet G3306 – Part B – Specifications C KPB Pipe Size and Compressor Calculations D Pro Forma and Cost Estimates Tables 4-1 Permits and Requirements ........................................................................................................... 4-2 5-1 Costs, Savings, and Net Present Value for the Options ................................................................ 5-1 7-1 Operations and Maintenance Highlights, Single Entity, Employees of Landfill Owner, CPL, or Third-party Developer ................................................................................................................... 7-3 7-2 Operations and Maintenance Highlights, Single Entity, Employees of Outsourced Subcontractor ............................................................................................................................... 7-3 7-3 Operations and Maintenance Highlights, Two Entities, Employees of Landfill, CPL, or Subcontractor ............................................................................................................................... 7-4 Figures 2-1 Site Layout of Central Peninsula Landfill ...................................................................................... 2-1 2-2 Estimated LFG Production at CPL.................................................................................................. 2-2 3-1 Pipeline or Electrical Transmission Line Alignment to Skyview Middle School ............................ 3-1 3-2 Pipeline from CPL LFG scrubbing skid to ENSTAR pipeline ........................................................... 3-4 3-3 Proposed Gen Set location at Skyview Middle School.................................................................. 3-5 6-1 Landfill Gas-to-Energy Project Delivery Approaches .................................................................... 6-1 IV CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY Acronyms and Abbreviations ADEC Alaska Department of Environmental Conservation BTU British Thermal Unit CCF Centum Cubic Feet (100 cubic feet) CF Cubic Feet CFM Cubic foot per minute CH2M CH2M HILL CH4 Methane CHP Combined Heat and Power CM Construction Management CNG Compressed Natural Gas CO2 Carbon Dioxide COI Conflict of Interest CPL Central Peninsula Landfill DB Design-Build DBB Design-Bid-Build EPA United States Environmental Protection Agency (USEPA) Gen set engine-generator set GCCS Gas Collection and Control System GHG Greenhouse Gas HAP Hazardous Air Pollutant HEA Homer Electric Authority HDPE High Density Polyethylene KPB Kenai Peninsula Borough kW kilowatt kWh kilowatt-hour LFG Landfill Gas LFGTE Landfill Gas to Energy LMOP Landfill Methane Outreach Program MW Megawatt NESHAP National Emission Standards for Hazardous Air Pollutants NDPES National Pollutant Discharge Elimination System NPV Net present value NSPS New Source Performance Standards EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY V ACRONYMS AND ABBREVIATIONS O&M Operations and Maintenance Psi pound per square inch RECs Renewable Energy Credits RICE Reciprocating Internal Combustion Engines SDR Standard Dimension Ratio tpy ton per year VI CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 1 Introduction This report summarizes CH2M HILL’s (CH2M) landfill gas utilization feasibility study for the Central Peninsula Landfill (CPL) which is owned and operated by the Kenai Peninsula Borough (KPB). CH2M evaluated the following landfill gas (LFG) utilization options: Option 1 – Direct use on-site – This option utilizes LFG with minimal processing in a boiler to provide heat for area heating and or to provide direct fuel heat for evaporating the leachate evaporator. Option 2a – Direct use on-site and off-site with transport via a pipeline. This option utilizes LFG in the boilers and evaporator at CPL as well as a boiler at an offsite location to provide heat. Under this option, the LFG is transported to the onsite and offsite locations via a pipeline, which would require a compressor station at the landfill. Option 2b – Direct use off-site with transport via truck – This option utilizes LFG in a boiler at an off-site location to provide heat. The trucking option would include the need for a compressor station, storage tanks at landfill and the off-site location, truck fill station at landfill, and tank fill station at off-site location. Option 3 – Convert LFG to electricity on-site for use on-site and offsite. This option utilizes LFG as a fuel for an engine generator set to produce electricity that can be used at CPL and Skyview Middle School with the remainder sold to HEA. Option 4- Convert LFG to electricity on-site for use on-site at CPL and offsite at Skyview Middle School and utilize waste heat via CHP from the engine generator set to evaporate leachate at the CPL. Option 5 – Clean the LFG to meet pipeline quality requirements and compress it to approximately 60 psi which is what is required for injection and sale into the ENSTAR pipeline that is adjacent to CPL. Option 6a – Transport the LFG via trucking to Skyview Middle School where it is used as fuel for an engine generator set to produce electricity. This option would require similar trucking infrastructure as Option 2b. Option 6b – Transport the LFG via a pipeline to CPL for use in boilers and evaporator and to Skyview Middle School where it is used as a fuel for an engine generator set to produce electricity, with excess electricity sold to HEA. This option would require similar pipeline infrastructure as Option 2a. This LFGTE evaluation assumed a 20-year project life that starts in 2019 (assuming 3 years for design and construction of a GCCS and utilization system) and therefore ends in 2039. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 1-1 SECTION 2 Background The basis for CH2M’s landfill gas evaluation for the CPL is HDR’s Landfill Gas Management Plan (November 2010). In that report, HDR prepared LFG generation estimates using the U.S. Environmental Protection Agency’s (EPA) LandGem model. We reviewed the input data (i.e. annual disposal tonnage, LFG generation constant, k; and landfill generation potential, Lo) and concluded the data, as well as the default values, were appropriate for conditions at CPL. We therefore used this data for estimating the energy that could be produced and utilized. HDR completed two LandGem models for the CPL, one for the unlined portion of the landfill and one for the lined portion of the landfill (Figure 2-1). We used this modeling data in our evaluation and assumed utilizing LFG from both the unlined and lined cells. Figure 2-1. Site Layout of Central Peninsula Landfill HDR stated that the economics of constructing a landfill gas collection and control system (GCCS) for the unlined portion of the landfill need to be carefully considered as part of LFGTE utilization evaluation before it is designed and constructed. We concur with this conclusion. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 2-1 SECTION 2 - BACKGROUND 2.1 LFG Supply The scope of work for this project was to consider utilizing LFG from the lined and unlined portions of the landfill. We did not consider the cost for designing and constructing a GCCS system for the unlined portion or for the lined portion; rather our evaluation considered utilizing LFG from the lined and unlined cells on the assumption that the LFG would be already captured and readily available for use. KPB should carefully consider the financial implications of constructing a GCCS system in the unlined cells given the unlined cells are closed and the quantity of LFG being produced is declining. If a GCCS system is constructed in the unlined cells, it could provide supplemental LFG until the mass of waste in the lined cells starts to produce larger quantities of LFG (Figure 2-2) that offset the LFG being produced from the unlined cells. As part of each of our evaluation scenarios, we used HDR’s LandGem outputs as the input to our LFGTE utilization evaluation (Appendix A). As noted in HDR’s report, the LandGem outputs are estimates of LFG production and there is no guarantee that the models are accurate for the amount of LFG that is produced. Figure 2-2. Estimated LFG Production at CPL (Source: EPA LandGEM modeling, CPL Landfill Gas Management Plan, November, 2010, HDR Alaska Inc.) During our project kickoff meeting with the KPB, the impact of the current practice of recirculating landfill leachate on LFG production was discussed. As part of that discussion, CH2M agreed to perform a background search on how recirculating leachate affects the performance of the landfill and the performance of LFG production as a part of the scope of this project. The United States Environmental Protection Agency (EPA) and its predecessor agencies have been sponsoring various research and demonstration studies for bioreactor landfills since 1959. Most of the studies were completed in the 1970s and early 1980s. These studies showed that a landfill using leachate recirculation can be designed and operated to increase the rate of waste stabilization. In a bioreactor landfill, controlled quantities of liquid amendments are added and circulated through the landfill to achieve a desired waste moisture content. This process significantly increases the rate of biodegradation of the waste (similar to anaerobic composting), thereby reducing the waste stabilization period from 5 to 10 years instead of 30 or more years for a conventional “dry tomb” designed facility. 0 50 100 150 200 250 300 350 400 450 500 20162019202220252028203120342037204020432046204920522055205820612064206720702073207620792082208520882091209420972100210321062109LFG Flow (cfm) Year Central Peninsula Landfill LFG Collection Potential Unlined Lined Cells 1-5 Combined LFG 2-2 CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 2 - BACKGROUND The enhanced biodegradation also increases the short term production (but not total volume) of landfill gas. Therefore, the active lined cells at CPL where leachate recirculation has been occurring may generate higher volumes of gas more quickly than standard dry landfills. However, at least some of the effects of recirculating leachate has already been captured in the gas generation constant (k) used in the EPA LandGEM model. Until more definitive testing of the LFG quantities and quality is completed, the current EPA LandGEM model estimates (Figure 2-1) continue to be the best available gas supply estimates for the purposes of evaluating the initial project feasibility. 2.2 Collection Efficiency of LFG Collection System For our evaluation, we assumed a collection efficiency of the available LFG at 60% for the unlined cells and 75% for the lined cells. The unlined portions of the landfill will likely have a lower collection efficiency than the lined cells because there is no bottom liner in place. This will likely allow some portion of the LFG generated to ‘leak’ out through the bottom and sides of the landfill. Also the unlined areas may allow the intrusion of air when the GCCS is ‘pulling’ a vacuum to draw the LFG from the waste, which dilutes the quality of the LFG. We assumed a higher collection efficiency for the lined cells because the presence of a bottom liner will eliminate ‘leaking’ through the bottom, and may reduce the intrusion of air into the captured LFG stream. The highest peak quantity of LFG generation produced by both the unlined and lined landfill cells is estimated to occur in the year 2035 at 435 CFM. For just the lined cells only, the amount of LFG generated is estimated to peak in the year 2025 at 362 CFM. 2.3 LFG Quality LFG produced from either the lined or unlined areas of the landfill has not been sampled for testing by laboratory analysis, but LFG quality data taken using hand held instruments was reviewed and is consistent with the default values used in the LandGem model. For a typical landfill, the LFG is comprised mainly of methane (CH4), carbon dioxide (CO2) and trace amounts of other gases. The CH4 and CO2 are typically close to 50% with the trace gases comprising less than 1%. If the GCCS system is optimally operated at CPL, the gas composition should be about 50% CH4. It is noted that some wells may produce CH4 greater than 60% and other wells will produce CH4 closer to 35 or 40%. The proper operation of the well field is critical to delivering a constant stable (i.e. 50%) supply of CH4 to utilization infrastructure. For purposes of our evaluation, we assumed the CH4 content in the LFG that is captured and utilized would be 50%. 2.4 Off-site Utilization Location Options 2a, 2b, 6a, and 6b evaluate utilization of LFG at an offsite location. CH2M, with assistance from KPB, evaluated potential off-site locations that could potentially use the LFG either directly or use the electricity that is produced at CPL and transported to their location. Based on our evaluation, the closest off-site facility that could utilize the LFG in the most optimal manner possible is Skyview Middle School, which is about 1.4 miles north of the landfill. The DOT Maintenance Facility was initially also considered due to its proximity to the landfill, however its energy usage was much lower than Skyview and therefore it was not evaluated further. 2.5 Energy Use KPB provided energy use or demand (electrical and natural gas) at CPL in 2015. CPL used 948,915 kWh/ year of electricity. Energy use or demand was also provided for Skyview Middle School. The school used an average of 1,597,000 kwh/year in 2014 and 2015. For our analysis, the amounts of electricity for these facilities was held constant at the 2015 level over the 20-year project life. It is possible that the EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 2-3 SECTION 2 - BACKGROUND amount of electricity needed by CPL or the school could increase or it could decrease over the life of the project. KPB provided CH2M with the amount of natural gas utilized over a two-year period (2014 and 2015) to evaporate leachate. We used the higher of the two years (219,592 CCF), which was 2015, for our evaluation of whether gen set engine waste heat is a viable option for replacing, or at least reducing, the amount of natural gas that is used to evaporate leachate. 2.6 Bale Fills The unlined landfill cells at CPL were filled with compacted, baled waste from 1992 through 2005. Prior to that, from 1969 to July 1992, the waste was placed as loose fill. There is not much research available on the impact of baled waste either positively or negatively on LFG generation or capture. However, we consulted with other senior technical consultants at CH2M (Tom Kraemer and Peter Woodfill, who have over 60 years of concentrated LFG related experience between them) to determine their opinions on the subject. Their comments are summarized below: • The waste located in the bales is potentially drier than non-baled waste due to the pre-compaction process. This reduction in moisture could potentially reduce the landfill gas generation constant (k). This in turn would reduce the rate at which LFG is generated (i.e. flatten out the LFG production curve). It would not decrease the total amount of LFG produced, but may indicate that LFG would be generated in smaller amounts over a longer time frame. • The space between the landfilled bales could potentially create chimneys for the LFG to move through and to collect. This physical configuration may have a potentially serious negative effect on LFG collection efforts. LFG extraction wells that were not located or installed near the ‘chimney’, may not be able to capture the LFG in these interstitial areas. Also, a poorly placed extraction well may not be able to induce a sufficient vacuum needed to draw the LFG from the center of the baled waste without also drawing in air from the surface of the site through these chimney features. The air entrained in the collected LFG would, in the short term, significantly impact the quality of the LFG captured. Additionally if this over drawn condition of air intrusion continued for a longer period, it may seriously reduce the amount of LFG that would be produced from the waste, since LFG has to be produced from waste under anaerobic not aerobic conditions. • Together, these potential areas of concern indicate more risk for the development of LFG collection systems the unlined landfill cells than in the lined areas. 2-4 CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 3 Landfill Gas Utilization Options 3.1 Boiler Options 1 (LFG use on-site), 2 (LFG use off-site) and 6 (LFG use on-site and off-site) evaluated the direct use of LFG in a boiler for heat either in a building; or to supplement or replace the currently used fuel source required to evaporate leachate at CPL. Direct use of LFG as a substitute for natural gas is common and often the most cost-effective use of LFG (LMOP, 2015). Under Option 2, the LFG is assumed to be used in an off-site boiler and CH2M evaluated two ways to transport the LFG to this off-site boiler, either via pipeline (Option 2a) or by truck (Option 2b). The alignment of a pipeline to convey LFG or a transmission line to convey electricity to the school from CPL is shown in Figure 3-1. Figure 3-1. Pipeline or Electrical Transmission Line Alignment to Skyview Middle School EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 3-1 SECTION 3 - LANDFILL GAS UTILIZATION OPTIONS As part of evaluation for Option 2, we looked at the relative costs of transporting the LFG via a pipeline or by truck. The USEPA has a program called the Landfill Methane Outreach Program (LMOP) that is intended to promote the use of LFG as a renewable energy. On the LMOP website, there is a tool for estimating costs for LFGTE utilization systems. Using the LMOP tools, we did a comparison between transporting LFG via a pipeline and by trucking. We found that trucking LFG to another location for use in an engine generator set would be cost prohibitive because of the extensive infrastructure that would be required for such a utilization system including: storage tanks located at KPB and the off-site location using the LFG; dedicated truck and trailer combinations; gas scrubbing systems to remove carbon dioxide and other gases; as well as the complex compression equipment needed to compress the pure methane to approximately 3,000 psi, which is what would be needed to transport and store the LFG at the off-site location. For this reason, trucking the LFG to an off-site location (Options 2b and 6a) was not further considered. For both direct use options (i.e., CPL and Skyview), the boiler would need to be retrofitted to process and burn LFG rather than natural gas. Since the heating value of LFG is half that of natural gas, the boiler will process twice the gas volume thus requiring capacity-related modifications. The fuel train and burners need to be retrofitted for the higher flow rates and, since LFG is typically a wet gas containing trace corrosive compounds, internal components should be replaced with corrosion-resistant materials such as stainless steel. The boiler controls would most likely also be modified to cope with variable heat content of LFG and to allow LFG/natural gas co-firing and fuel switching in the event of a loss in LFG pressure to the unit. Regular (annual) cleaning of the boiler is recommended to remove the accumulation of silicon dioxide resulting from siloxanes in the LFG. Alternatively, LFG can be further conditioned (siloxane removal, CO2 scrubbing) prior to injection and use such that boiler retrofits would not be required and the increased boiler maintenance is avoided. The specifics of the direct use boiler options will need to be further investigated to determine which approach would be ultimately more efficient, but for purpose of this evaluation, boiler retrofit and conversion to seamless controls was assumed to be representative for the option cost comparison. (LMOP, 2009) 3.2 Engine Generator Options 3 (on-site gen set and no waste heat capture), 4 (on-site gen set and waste heat capture) and 6 (off-site gen set) include the use of engine generator sets (gen sets). We evaluated engine gen sets manufactured by Caterpillar, Inc. It should be noted that there are other similar manufacturers and they have similar engine efficiencies to the ones we selected from Caterpillar. For Options 3, 4, and 6, we selected a Caterpillar gen set (CG132-16) that utilizes all of the LFG that CPL produces including the lined and unlined cells (See Appendix B for cut sheet). This gen set was selected because it could use all of the LFG that would be produced when the gen set came on line in 2019. For all of these options, the gen set would combust the LFG and convert it to electricity. Based on our evaluation, the quantity of LFG from the landfill would produce excess electricity (i.e. LFG is capable of producing more electricity than CPL currently uses). The excess electricity would then be sold to Homer Electric Authority (HEA), the local utility, for use elsewhere. The contractual relationship that would be required between KPB and HEA was not included as part of our evaluation. Based on our evaluation, the CG132-16 could use all of the LFG produced by CPL until about 2030 at which time CPL produces enough LFG to power a second gen set. The CG132-16 produces 800 kW of electrical power. KPB may consider a smaller gen set, like the G3306 which produces 160 kW of electrical power. We based our evaluation on LFG from the lined and unlined cells. If KPB decides against installing a GCCS in 3-2 CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 3 - LANDFILL GAS UTILIZATION OPTIONS the unlined the cells, then the CG132-16 would likely be too big, at least initially and a smaller gen set would be better suited to the amount of LFG produced from the lined cells. 3.3 Combined Heat and Power Option 4 also included an evaluation of utilizing a gen set on-site and utilizing the waste heat from the gen set exhaust to evaporate leachate, offsetting natural gas usage. KPB’s leachate evaporator (Heartland Technology Partners LLC, model LM-HT®) can operate on the existing natural gas flare or on waste exhaust heat from a gen set. To utilize the waste exhaust heat for leachate evaporation, the gen set would need to be located next to the evaporator. This option includes costs for a 900 linear foot gas pipeline from the vicinity of south Cell 1 (gas collection area) to the evaporator. Heartland estimates that the waste exhaust heat produced by an 800 kW power gen set like the Cat CG132-16, could evaporate approximately 4,000 gallons of leachate per day (Heartland presentation to SWANA, July 18, 2014). KPB’s requirement for leachate management at CPL is an average of 12,000 gallons of leachate per day (average for active use in October and November 2015). Although the waste exhaust heat from this gen set would not be sufficient to evaporate all CPL leachate during the early years of the project, it could be used to offset natural gas use. With the addition of other gen sets, the waste exhaust heat available to evaporate leachate would increase. 3.4 ENSTAR Pipeline Option 5 was an evaluation of cleaning and compressing LFG to compressed natural gas (CNG) that can be injected into ENSTAR natural gas pipeline. There is an ENSTAR natural gas pipeline adjacent to CPL that runs parallel to the Sterling Highway. The pipeline provides natural gas to residents and businesses on the Kenai Peninsula. Before the methane can be injected into the pipeline, it must be cleaned to pipeline quality and compressed to 60 psi. Pipeline quality normally means removal of carbon dioxide, trace gases, and moisture from the LFG before it is injected into the pipeline. A relatively short 0.2-mile-long pipeline would be needed to get the clean and compressed LFG to the ENSTAR pipeline. The alignment for the pipeline is shown in Figure 3-2. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 3-3 SECTION 3 - LANDFILL GAS UTILIZATION OPTIONS Figure 3-2. Pipeline from CPL LFG scrubbing skid to ENSTAR pipeline 3.5 Off-site Utilization Option 6 includes transporting LFG to the CPL boilers and evaporator and an offsite location (Skyview Middle School) where it is used a fuel in a Cat CG132-16 gen set). Two scenarios were evaluated as part of Option 6: a) transport the LFG via trucks to Skyview Middle School and b) transport the LFG through a pipeline to Skyview. As discussed earlier, the cost for the infrastructure to transport LFG using trucks would be cost prohibitive. Therefore, Option 6a was not carried forward in our evaluation. The proposed location of the gen set at Skyview is shown in Figure 3-3. 3-4 CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 3 - LANDFILL GAS UTILIZATION OPTIONS Figure 3-3. Proposed Gen Set location at Skyview Middle School 3.6 Pipelines Options 2a and 6b transport the LFG to Skyview through a pipeline where it is used in a boiler (Option 2a) or in a gen set (Option 6b). The pipeline to Skyview is 1.4 miles long and preliminary sizing is 6 inches in diameter (Appendix C). This diameter was determined as a compromise of minimizing head loss which could be accomplished by using a large diameter pipe and minimizing construction costs, which could be accomplished by using smaller diameter pipe. Option 5 utilizes a pipeline between the LFG cleaning and scrubbing skid at the landfill and the ENSTAR pipeline. Preliminary sizing is 4 inches in diameter (Appendix C). As with the pipeline to the school, the diameter was selected as a compromise between minimizing head loss and costs. For each of the pipelines, we assumed the pipeline would be HDPE SDR 11 and buried below frost depth. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 3-5 SECTION 4 Regulatory Review CH2M researched regulatory requirements applicable to each alternative option including: • Solid waste permit modifications • Air emission permits • Energy facility approvals • Power or gas transmission approvals • Net metering agreement and interconnection agreement with local power utility • See Table 4-1 for a brief description of necessary requirements and the options they pertain to. Internal construction permitting and approvals within the Kenai Peninsula Borough were not included in the review. It is recommended that KPB consult with the Alaska Department of Environmental Conservation (ADEC) to discuss and confirm the requirements for the selected option and also whether the landfill will meet the Clean Air Act’s Title V Permit applicability at the time of implementation. A Title V Air Quality Operating Permit is required for landfills with a design capacity equal to or greater than 2.5 million Mg and 2.5 million cubic meters of MSW. According to the KPB Central Peninsula Landfill (CPL) Landfill Gas Management Plan, the CPL’s design capacity is not forecasted to exceed the regulatory threshold until the Cell 5 expansion is permitted (HDR Alaska, 2010). Currently, the landfill has no air quality permits. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 4-1 SECTION 4 - REGULATORY REVIEW Table 4-1. Permits and Requirements Item Requirement Description Agency Applicable Options 1 Solid Waste Permit Modification Modify existing landfill permit to include additional onsite LFG infrastructure. Revise and update all applicable operations, monitoring, and closure plans. Estimated time for issuance of revised permit: 2 months ADEC - Solid Waste Program All 2 Title I Air Quality- Minor Source Permit A minor source permit is required for construction of a system that emits regulated air pollutants within the minor source thresholds (for details on thresholds, see the ADEC Division of Air Quality website). A minor source air permit would be required for any option that involves the construction of stationary LFG combustion equipment. The emissions of the selected control/utilization technology would need to be calculated to confirm that the permit is required and that the system does not exceed the thresholds for a minor source permit. Estimated time for issuance: 6-8 months ADEC Division of Air Quality 1, 2a, 2b, 3, 4, 6a, 6b 3 New Source Performance Standards (NSPS) Per NSPS Subpart WWW, if the landfill has a design capacity equal or greater than 2.5 million MG and 2.5 million cubic meters of MSW, it will require a Construction Permit under ADEC’s Title 1 program and also a Title V Operating Permit (under the EPA). Currently, the landfill does not meet the above design capacity thresholds so these permits do not apply. Once proceeding with a selected LFGTE technology, the project and landfill should be reassessed against NSPS for applicability. Estimated time for issuance: For Title V Operating Permit - 6 months, due 1 year after operation of a source commences. ADEC Division of Air Quality EPA Not required at this time. 4 National Emission Standards for Hazardous Air Pollutants (NESHAP) Subpart AAAA If the landfill is a major source, collocated with a major source, or has a design capacity equal or greater than 2.5 million MG and 2.5 million cubic meters of MSW and estimated uncontrolled emissions of NMOCs of at least 50 Mg per year, the landfill is required to collect and treat and control emissions of LFG. It is also a requirement to submit a compliance report every 6 months beginning 180 days after startup of an LFG combustion system. In addition, CPL will need to develop a written SSM Plan to minimize release of HAP’s when the control device is not operating. Currently the CPL does not meet the thresholds for NESHAP subpart AAAA. Once proceeding with a selected LFGTE technology, the project and landfill should be reassessed against NESHAP guidelines. EPA Not required at this time. 5 NESHAP for Stationary Reciprocating Internal Combustion Engines (RICE) Establishes national emission limitations and operating limitations for hazardous air pollutants emitted from stationary reciprocating engines located at major and area sources of HAP emissions. Also establishes requirements to demonstrate initial and continuous compliance with the emission limitations and operating limitations. EPA 3, 4 6 Greenhouse Gas (GHG) Management Reporting – Landfill currently reports methane emissions as required under the Greenhouse Gas Management Rule (40 CFR 98 Subpart HH). The installation of boilers and/or engines will ADEC Division of Air All 4-2 CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 4 - REGULATORY REVIEW Table 4-1. Permits and Requirements Item Requirement Description Agency Applicable Options GHG Rule require reporting of additional GHGs. Quality 7 National Pollutant Discharge Elimination System (NPDES) Permit Condensate is generated during LFG collection and conditioning. The discharge of this wastewater to surface waters requires a permit or should be included under the existing landfill’s discharge permit if applicable. ADEC Division of Water If applicable 8 Lane Closure Permit Required for construction crossing the Sterling highway in the right-of-way of the Alaska Department of Transportation and Public Facilities. Alaska Department of Transportation and Public Facilities 2a, 5, 6b 9 Utility Permit All utilities installed within the Alaska Department of Transportation and Public Facilities right-of-way require a permit. Permit cost is $600 plus 1$/lineal foot to a maximum of $10,000. This would include net metering agreements, and easements. Estimated time for issuance: 1-2 months Alaska Department of Transportation and Public Facilities ENSTAR 2a, 5, 6b 10 Net Metering Agreement Agreement with utility is required for any net metering application. ENSTAR HEA If applicable 11 Asbestos Disturbance Notification CPL will need to notify the Air Quality Division of ADEC 45 days prior to disturbance event. This is applicable if the LFGTE project construction would result in Asbestos Disturbance. ADEC Division of Air Quality If applicable EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 4-3 SECTION 5 Landfill Gas-to-Energy Costs and Revenues Cost and revenue results for each LFGTE option that was evaluated are summarized in Table 5-1. For each option, a construction cost estimate was prepared at a Class V (feasibility study) level in accordance with the AACE International (AACE) classification system. The precision range for this level of cost estimate is -50 to +100 percent of the actual value. O&M costs were estimated based on previous project experience, literature values, and vendor information. The annual grid power cost reduction for each option is the gross amount saved, before accounting for project costs, by replacing the electrical loads with electrical power from the project gen sets and from replacing the heating and leachate evaporation which use natural gas with waste heat from the CHP system. The grid electrical power cost used in this calculation was $0.22 per kWh, as provided by HEA. The NPV was computed using all project costs and savings over an assumed 20-year project life starting in 2019. Savings were counted as positive values and costs as negative values in the NPV calculations. A real discount rate (interest plus inflation) of 5 percent was assumed. Table 5-1. Costs, Savings, and Net Present Value for the Options Capital Cost Average Annual O&M Annual Revenue/ Savings NPV, 20-year life Option 1 - Direct Use On Site in a LFG Fired Boiler ($1,022,120) ($176,910) $190,606 ($851,443) Option 2a - LFG Piping to CPL Evaporator and Boilers and from CPL to Boiler at Skyview MS ($3,057,481) ($268,939) $252,136 ($3,266,886) Option 3 – Engine Gen Set at CPL Without Exhaust Heat ($3,486,593) ($362,353) $1,206,381 $7,031,857 Option 4 – Engine Gen Set at CPL, Utilize Exhaust Heat ($3,503,636) ($381,191) $1,260,381 $7,453,011 Option 5 – Remove CO2 and Trace Gases and Inject to ENSTAR Pipeline ($823,141) ($284,625) $376,178 $317,807 Option 6 – Transport LFG Off Site in Pipeline to Gen Set at Skyview MS ($4,724,551) ($496,420) $1,206,381 $4,123,128 Note: these costs do not include installation and operation of a landfill gas collection system at lined or unlined landfills Disclaimer: Cost estimates provided in this report have been prepared for guidance in project evaluation and implementation from the information available at the time of the estimate. They are intended only for comparison of alternatives and should not be used for project budgeting. The final costs of the project will depend on actual labor and material costs, competitive market conditions, implementation schedule, and other variable factors. As a result, the final project costs will vary from the estimates presented herein. Because of this, project feasibility and funding needs must be carefully reviewed prior to making specific financial decisions to help support a proper project evaluation and adequate funding. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 5-1 SECTION 6 Procurement Approaches As shown on Figure 6-1, and as described in this section, once the LFG resources (predicted quantity and quality) and utilization alternatives (including direct use or electrical power generation) have been preliminarily defined for any given potential project, there are typically two basic development approaches that must be first reviewed and agreed to before proceeding into full-scale project development: 1. Internal Self-Development: This approach essentially means that the ultimate end-user of the LFG resource (in this case, CPL) will provide, from internal or in-house resources, all of the required planning, direction, project oversight, and financial means and funding needed to design, build, and operate the new LFG utilization facility. 2. Outside Third-party Developer: In this approach, the ultimate end-user (CPL) identifies and then selects an independent outside firm or entity that, in turn, uses their own resources and funding to provide all of the required planning, direction, oversight, and, most importantly, the financial means and funding needed to design, build, and operate the new LFG utilization facility. It is possible to have some variation or combination of these basic approaches. For instance, the landfill owner may decide to proceed to install portions or all of the LFG collection and flaring systems in a self-development mode, prior to then issuing a request for participation in the project by an outside third-party. This level of participation by the outside third-party, in turn, may also vary, and can range from a simple non-equity or general contractor role to a full assignment of LFG rights, or a joint ownership scenario in the project. Figure 6-1. Landfill Gas-to-Energy Project Delivery Approaches EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 6-1 SECTION 6 - PROCUREMENT APPROACHES This is the decision point at which CPL, as the ultimate end-user of the LFG resource, currently finds itself in this potential project. They may have the opportunity to act in a completely Outside Third-party Developer role, or they may undertake a smaller, less complicated position and leave the initial project development almost entirely with EC Waste, or a contracted independent entity. The underlying consideration that CPL must evaluate when deciding which path to pursue revolves around the overall level of participation demanded in each of the various project development scenarios. There are several benefits and drawbacks associated with each approach, as discussed in the following subsections. 6.1 Internal Self-development Approach The more direct project participation, the greater the ability of the ultimate end-user to achieve desired outcomes. This means that CPL can place value or emphasis on certain elements of the project that may be of significant self-interest or commitment, such as long-term system reliability; as opposed to an outside third-party that may not value these interests to the same degree as, perhaps, generating short-term financial returns. However, this approach will also require a very significant commitment of dedicated resources to successfully undertake and accomplish an LFG utilization project. Usually, this effort and commitment to providing a highly specialized set of skills is generally outside the normal business practices of an ultimate end-user like CPL. At best, this can cause disruptions in the normal functions of the assigned personnel, and at worst, can lead to project failure to some extent or another. Another major consideration with self-development is that this entity is typically completely responsible for the entire project’s capital financing required to design, build, and operate the new LFG utilization facility. This means that the entire project risk exposure also rests entirely with CPL. 6.2 LFGTE Facility Ownership Considerations CPL owning and directly managing the new LFGTE facility assets, versus having them owned by a third-party developer, would simplify the overall project development and operations. It would also allow CPL to capture more of the financial benefits available from the LFGTE project, such as the revenue stream that otherwise would accrue to the third-party developer from the sale of the energy produced, and any marketable environmental attributes that may generate additional income. CPL could also then control the pricing and transactional details of the energy provided to itself for use in the facility. This gives CPL flexibility in setting cost structures for internal profit center allocations. Owning the new LFGTE assets also means that CPL can set the approach and framework for the O&M of the new facility that best suits its own purposes and needs. As opposed to being a passive buyer of energy, for example, CPL could proactively structure the LFGTE facilities O&M to be in close coordination with the CPL’s facility and take full advantage of downtime or off-peak hours in that facility to perform required activities at the LFGTE facility simultaneously. Direct ownership also means, literally, that CPL can dictate who actually manages and runs the LFGTE facility. So CPL, not an outside third-party, can capture any value or benefits associated with having their own in-house staff in charge of the LFGTE facility or from competitively procuring an independent operator that simply provides the required operations under contract to CPL. CPL, acting as a self-developer and owner of the new LFGTE facility, also has significant risks and issues associated with this course of action. One of the first issues is that of dedicated and committed staff resources. The development and oversight required to implement a facility such as the one proposed require the full-time assignment of several CPL staff resources almost immediately from the initiation of the project. These staff resources can be contracted staff as opposed to in-house staff, but that usually increases the cost of development. This commitment issue does not end with project startup but continues on through the life of the project with dedicated staff to operate and maintain the facility. 6-2 CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 6 - PROCUREMENT APPROACHES LFGTE facilities typically include gas compression, gas treatment, and possibly electrical generation equipment. The O&M these and other specialized gas measurement instrumentation require significant operator training and continuous effort to obtain the levels of facility on-stream time that would be needed to fully realize the value of the large capital investment required in a completely CPL-owned facility. To mitigate these issues of concern and share the risk, the new LFGTE project can be structured to include the landfill owner who supplies the LFG to the facility. Section 9 provides a discussion of this potential approach. 6.3 Outside Third-party Developer Approach By definition, this requires a much lower level of project participation and less commitment of dedicated resources by CPL. In fact, the minimal levels of oversight can be outsourced to an appropriate program management entity or company, which virtually eliminates dedicated commitments. But in the inverse of the self-development option, this path can significantly decrease CPL’s ability to achieve desired outcomes for the project. For instance, typically, the developer selects the LFG utilization process, such as production of liquefied natural gas as opposed to electrical generation, and this may not be what CPL would desire. A significant consideration with this option is that the third-party will normally require a long-term commitment (for example, 20 years) in order to amortize their capital investments, and this may lock CPL into a deal that may become less favorable over time. Another major decision that basically defines the roles and responsibilities of the developer and the ultimate end-user, like CPL, is the type of agreement executed. Is the basic agreement a Gas Purchase/Sale or a Gas Rights agreement? In either case, CPL should insist upon including specific, clear terms and conditions relating to critical issues, such as: • LFG measurement and metering, including where the meters are located and how the calibration and auditing is performed. • LFG quality and quantity, for which the landfill owner will want to explicitly provide “No Warranties” and will try to only agree to deliver LFG in a completely “as-is” condition without responsibilities for levels of constituents or contaminants. CPL should resist this language and at least insist upon minimum levels of LFG quality and quantity that would be delivered for sale. • Renewable energy credits (RECs), tax credits, and other green attributes can represent a significant stream of benefits over the life of a project. Accordingly, who owns these valuable benefits is an important issue to define and agree upon at the start of the project. 6.4 Other Project Delivery Considerations Other considerations include: • Internal development affords the ultimate end-user of the LFG resource maximum flexibility, which will be important as technology and energy values change. • Outside development is the simplest way forward if the contract basis of the project agreement is favorable to all parties’ interests and the developer has a proven record of successful projects. • If CPL selects internal self-development, it should immediately begin to discuss and explore project construction approaches as outlined herein, and not wait until final design and engineering is completed. • In any case, CPL should maintain flexibility in commitments made to outside developers so that it can continue to look at future viability of alternatives as markets and technologies change. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 6-3 SECTION 7 Project Construction Approaches The proposed new LFGTE facilities are currently in the preliminary feasibility phase of the project and will eventually be constructed in accordance with a finalized design and layout. Accordingly, this section discusses potential methods and approaches to the procurement of design and construction services needed to finalize the development of proposed site improvements, assuming that CPL is self-developing the project and is responsible for the construction of the LFGTE facilities. The following are qualitative comments, observations, and recommendations associated with potential methods and approaches to construction of the LFGTE facilities and related site improvements. The basic definitions of the methodologies reviewed include the following: • Design-Bid-Build (DBB) – This is the traditional approach where a complete (100 percent) set of design plans and specifications are prepared by an engineer, and then the project is bid through a normal procurement process. Typically, in a successful bid process, this results in the engagement of an appropriately qualified general contractor to construct the facilities in accordance with the final plans and specifications. Additionally, the project owner may engage a separate third-party firm to provide outsourced quality assurance (QA) oversight services and duties during the construction phase of the project. • Design-Build (DB) – This approach involves the initial preparation of a conceptual or preliminary (30 percent) set of design plans and specifications by an engineer to provide the general scope and basic requirements for the project. Using these preliminary project documents, the project is then put out to bid through a procurement process, which requires the successful bidder to complete the project documents to at least the level required to obtain all necessary permits for the project, and also accomplish all required construction activities needed to complete the project. Typically, a successful bid process results in the engagement of one appropriately qualified firm or team responsible for finalizing the required engineering design, obtaining permits, and constructing the facilities. • Construction Management (CM) – Typically, the project owner engages a firm with expertise in CM to assist or actually handle all aspects of the project on behalf of the owner. The CM has essentially the same project goals as the project owner under this method, and if implemented correctly, this approach can reduce or hopefully eliminate the inherent conflict or adversarial nature of a traditional general contractor and owner relationship. This approach can be further sub classified in to CM-Agency or CM-at-Risk. The CM-Agency approach essentially designates the CM as the agent of the owner, and all project activities are performed in this role. The CM agent does not directly subcontract any engineering or construction activities; rather, schedules, coordinates, and assists in procurement of these required resources as needed. As such, the CM agent typically does not have any direct responsibility for adherence to project cost or schedule commitments made by the various contractors working on the project. Under the CM-Agency approach, the project owner retains the responsibility and risk of successful project completion. Under the CM-at-Risk approach, the CM is responsible for all project activities. This approach specifically mandates that the required project resources be placed in a direct contractual role with the CM. This arrangement intentionally places the risk and responsibility of project schedule, scope, and budget directly with the CM. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 7-1 SECTION 7 - PROJECT CONSTRUCTION APPROACHES 7.1 Design-Bid-Build Approach This method of contracting is well-established and, historically, the typical approach. Under this method, CPL could separate out various design components, and solicit and obtain separate construction pricing bids based on individual project components (for example, the required schedule for implementation). However, the implementation of this particular project combines several widely diverse project components that will require entirely different types of construction expertise due to the varied nature of the individual site improvements and new facilities currently being designed. These construction activities include site civil and earthmoving (surface regrading, drainage, and new access roads). 7.2 Design-Bid Approach This method can provide the project owner with a single point of responsibility for the entire project implementation and may result in streamlined communications and enhanced dispute resolution between the engineering and construction aspects of the project team. It may, but not always, result in a potential project cost savings due to a possible reduced level of engineering required prior to starting construction activity. This approach is well-suited also to a fast-track or compressed implementation project schedule, due to the ability, in some cases, to proceed to the construction phase without the need to prepare detailed plans and specifications that would otherwise be required for a normal public bid process. 7.3 Construction Management Approach The CM-at-Risk variation of this approach is well-suited to project owners who want to avoid or reduce their involvement or risk in undertaking a complex project. The CM-at-Risk approach can be further refined in a collaborative scoping effort between the project owner and the CM to define and essentially share some of the project risks. This joint or collaborative approach can be used, for instance, in developing a mutual selection and approval process for key project subcontractors and vendors. This has the effect of further strengthening the sense of partnership and attainment of common goals between the CM and project owner. If CPL ultimately decides to undertake such a CM approach, then it is advisable to begin the selection process and engagement of the CM-Agency or CM–at-Risk contractor as soon as the final decision to proceed with the entire project is completed. The purpose of this accelerated engagement of the CM contractor is to be able to allow the CM sufficient time to be involved and positively contribute to the development of the preliminary plans and permitting process. This early involvement allows CPL to take full advantage of the CM’s ability to factor in creative schedule and phasing concepts that may significantly benefit overall project implementation. 7.4 Landfill Gas-to-Energy Facilities Operations and Maintenance Regardless of which methodology is used in developing and constructing the LFGTE facility, a second important decision about how the ongoing O&M of the completed facilities is undertaken also needs to be made. Assuming that the new LFGTE project will be an electrical power generating scheme, the basic elements of the overall facility typically include an LFG collection and delivery system, an LFG processing and compression station, a gen set station, and an electrical power interconnection directly into the end-user’s facility. All four elements are highly interconnected and are subject to changes in operating parameters of any one of the individual elements. For example, any changes in the operating conditions at the LFG processing and compression station have a direct effect on the quantity and quality of the LFG that is being collected and delivered. This, in turn, directly affects electrical power output capabilities of the gen set station. 7-2 CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 7 - PROJECT CONSTRUCTION APPROACHES Therefore, it is usually the best approach if a single entity provides O&M services for all four of these facility elements. However, as long as a high level of cooperation and communication is maintained between the parties, successful O&M of the overall project can be performed by two separate entities. Implementing to the maximum degree automatic data signal exchange and control agreements between systems under different parties will facilitate smooth operations. The division of O&M responsibility typically occurs between the first (LFG collection and delivery) and second (LFG processing and compression) elements. This scenario allows for the landfill owner and operator to be able to maintain control over the LFG collection and delivery system, which is usually critical to the landfill operations and regulatory requirements. In this split scenario, the CPL simply collects and delivers LFG to the input side of the LFG processing and compression station, which would be operated by CPL or their contracted representatives. The interaction and trust between the two parties has to remain at a high level so that issues with LFG quality and quantities delivered match requirements of the downstream compression and generating equipment. The methodology and approach to O&M is also greatly affected by the basic business model under which the new LFGTE project is formed. For instance, if the project is structured such that the landfill owner simply sells raw, unprocessed LFG via a designated measurement and monitoring point to CPL, the split responsibility described herein would be the best approach. However, in the case where the landfill owner or an outside third-party developed the complete LFGTE facilities with their own capital and resources, and then sold electrical power directly to CPL, a single O&M entity would be the best choice. In any of these cases, it is possible to not directly engage employees of any of the project’s key participants in the normal ongoing O&M activities; rather, completely subcontract out these required responsibilities to firms that have specialized experience in providing O&M of LFGTE facilities. Tables 7-1 through 7-3 provide highlights of the basic operating scenarios, along with some of the pros and cons of each approach. Table 7-1. Operations and Maintenance Highlights, Single Entity, Employees of Landfill Owner, CPL, or Third-party Developer Pros Cons Provides the best coordination between the LFG collection system and LFGTE facility operations None Maybe less costly than other options, since tasks are usually performed by existing project staff The operating staff may be already assigned to other duties that can cause conflict and improper prioritization of O&M activities Provides the best LFG system data collection and regulatory reporting scenario None Table 7-2. Operations and Maintenance Highlights, Single Entity, Employees of Outsourced Subcontractor Pros Cons Can provide good coordination between the LFG collection system and LFGTE facility operations Contracted staff maybe limited by scope, cost, or time constraints that negatively impact the operations of ether the LFG collection system or the LFGTE facility operations Can provide a simple, focused scope, direction, and structure for subcontracted staff May still need to provide oversight and management of the outside staff resources There are specialized firms that provide these services on a regular basis in many locations The services tend to be costlier than using in-house staff resources EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 7-3 SECTION 7 - PROJECT CONSTRUCTION APPROACHES Table 7-2. Operations and Maintenance Highlights, Single Entity, Employees of Outsourced Subcontractor Pros Cons Provides good LFG system data collection and regulatory reporting scenario None Table 7-3. Operations and Maintenance Highlights, Two Entities, Employees of Landfill, CPL, or Subcontractor Pros Cons Two sets of staff may provide a backup or additional coverage of required tasks if needed Can result in poor coordination between the LFG collection system and LFGTE facility operations Spilt of duties among multiple parties may be less costly than single, dedicated staff Typically results in costly disputes about which staff was supposed to undertake specific assignments and arguments about poor work quality Specialized and differently trained staff may increase efficiency of operations in LFG collection field and plant environments Because the staff have different skill sets, it becomes difficult to interchange them in assignments: a plant operator does not usually perform well as a field technician, and vice versa 7.5 Partnering Approaches for Agreement with Owner and Gas Supplier There is an inherent conflict of interest (COI) in the routine operation of LFGTE projects between the landfill owner and operator and the LFGTE developer. This inherent COI issue needs to be understood and dealt with upfront in the project development schedule while the project roles and relationships are being defined. Essentially, the landfill owner always desires to and is usually required by regulation to operate the LFG collection and delivery system in a manner that captures the maximum amount of LFG, to prevent issues like offsite migration of LFG or excess emissions of LFG to the atmosphere. This typically means that the quality of the recovered LFG (in terms of the amount of methane versus the amounts of oxygen and nitrogen per cubic foot of LFG) can be significantly lower than desired for the successful operation of an LFGTE facility. The conflict arises when the landfill owner attempts to maximize the amount of LFG captured, which usually lowers the percentage of methane recovered, and the LFGTE facility operator wants to maintain higher methane levels for maximum energy production. To minimize this inherent conflict, there are two basic methods of attempting to encourage the landfill owner to cooperate fully with the LFGTE developer in carrying out their particular obligations under the project agreements. The first approach is to structure the LFGTE project agreements in such a manner that there is direct and explicit content that acknowledges and discusses this issue, and then specifically defines the obligations of each party. This method can usually minimize future conflicts but will not eliminate them. The second approach is to have the landfill owner and collection system operator become an active participating partner in the new LFGTE project to the extent necessary to assure they will act in the overall best interests of the entire project team, as opposed to just their own self-interests. This means that the project business model is structured such that the landfill owner, along with CPL, would share in the profits, savings, or benefits that the LFGTE facility generates. This approach usually does minimize issues of cooperation and can provide a workable solution to COIs. 7-4 CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 7 - PROJECT CONSTRUCTION APPROACHES 7.6 Example Business Model The following example outlines the basic structure of a sample business model, as described in the second approach in the previous section: 1. The first task would be to set up a new joint venture entity (most probably, a corporation) where CPL and HEA were the owners of the new firm. For this example, let’s assume that the ownership was split on a 49 percent share for CPL and 51 percent share for HEA. Only for purposes of this example, we will designate this new firm as GENCO. 2. The assumption would also be that CPL and HEA would split the initial capital requirements of the new equipment and facilities needed to compress and process the raw LFG delivered from the landfill, as well as the gen sets needed to generate the electrical power along the same 49 and 51 percent ownership basis for GENCO. 3. In this example, CPL would sell raw, unprocessed LFG to the new GENCO entity as the fuel required for the gen sets. This transaction would be measured and recorded at a suitable Point of Sale between KPB’s CPL Landfill and the boundary of the new GENCO facility. The raw, unprocessed LFG would typically be sold to GENCO at cost per million BTU delivered. This price per million BTU is usually developed based upon a significant discount to other alternate fuels available. For purposes of this example only, let’s assume that the price is $1.00 per million BTUs sold. This means that KPB obtains a significant revenue stream; therefore, has an incentive to capture and deliver LFG suitable for sale to GENCO. This new revenue stream can be used to significantly offset the operating costs the landfill incurs routinely for capture and destruction of LFG mandated by regulations. Similar arrangements have been set up for many LFGTE projects; therefore, we understand they do not violate the requirements of the federal Public Utilities Regulatory Policy Act. 4. The new GENCO entity uses the compressed and processed LFG to fuel the gen sets, which, in turn, produces electrical power. This electrical power is put on the grid by HEA and sold to their customers. This transaction may generate revenue for GENCO, which is then used to maintain operations at the new plant, repay the owners (CPL and HEA) for their initial capital requirements, as well as produce an ongoing and unencumbered revenue stream for both owners. 5. In summary, a business arrangement similar to this example, with an underlying support structure of suitable project agreements (LFG sales agreement, facility lease agreement, and power purchase agreement) can serve to provide several powerful incentives for the landfill owner (KPB) and the ultimate end-user (HEA’s customers) to fully cooperate in not only the initial project development but also in the ongoing operations of a GENCO facility for a normally assumed project life of 20 years or more. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 7-5 SECTION 8 Conclusions and Recommendations 8.1 Conclusions CH2M provides the following conclusions: 1. Three options for utilizing CPL gas had positive net returns: onsite power generation (Option 3), onsite power generation with capture of waste exhaust heat (Option 4), and offsite power generation (Option 6b). The options with highest NPV are Option 3 and Option 4. These options should be given further evaluation. The amount of LFG produced by CPL can provide more than enough energy to supply its electrical needs via a gen set. To make the project economic, the surplus electricity would need to be sold to HEA. 2. There is enough energy in the LFG to replace the natural gas that is used at CPL in their offices and shops, and the leachate evaporator (Option 1), but it would be less expensive and more economic to simply clean the gas to pipeline quality and inject into the ENSTAR pipeline. Flaring would be needed to destroy excess LFG when heating demand/evaporation demand is low. 3. Waste exhaust heat from an 800 kW gen set sized for the early CPL gas supply could offset natural gas usage at the evaporator (Option 4). For this scenario, the gen set needs to be located at the evaporator. Locating the gen set here requires an approximate 900-foot-long pipeline from the proposed gas collection and treatment area south of Cell 1 to the vicinity of the evaporator. 4. Offsite options add cost but do not increase the revenue potential for CPL gas (Option 2, Option 6b). 5. The cost estimates developed for this study assume the internal self-development approach. Other project approaches such as a partnership with a local gas utility (ENSTAR) or electrical utility (HEA) may be feasible and balance KPB risk and reward. 6. The cost and NPV totals in Table 5-1 do not include costs for gas collection systems at either the lined or unlined landfills. Grant funding for the gas collection system(s), similar to the Anchorage Regional Landfill gas to energy project may be required for an economic project. 7. KPB needs to consider the costs vs. benefits for installing a GCCS in the unlined cells. 8. Actual gas production testing will be required to confirm the modeling. 8.2 Recommendations CH2M recommends the following: 1. Evaluate the feasibility of obtaining grant funding for installation of LFG collection systems at both the lined and unlined cells. If options for grant funding are increased because of a partnership between a local utility and KPB, then such a partnership should be given greater consideration. 2. Install landfill gas wells and conduct LFG testing and revise LFG generation curves to better understand how much LFG is being produced. 3. Similar to the Municipality of Anchorage, prepare an RFP for sale of CPL gas with projected gas generation curves. Offer locations on CPL property for development. Select LFG developer based on best value to KPB based on NPV for 20-year project. Based on this study, the LFG development option with highest NPV is likely to be on-site power generation. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 8-1 SECTION 8 - CONCLUSIONS AND RECOMMENDATIONS 4. Consider a phased development scenario for on-site power generation: a. Phase 1: Developer generates power on CPL property at location near the leachate evaporator. Waste heat from engines is used to evaporate leachate. KPB reduces costs by offset natural gas usage at evaporator. KPB provides BTU credits to developer for future landfill gas. b. Phase 2: After LFG collection system is installed, developer uses a mix of natural gas and landfill gas to generate power. KPB sells LFG to developer. Waste heat is used to evaporate leachate, offsetting natural gas usage. c. Phase 3: Developer generates power using LFG. KPB sells LFG to developer. Waste heat is used to evaporate leachate, offsetting natural gas usage. 8-2 CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY EN0530161146CGY SECTION 9 References Adapting Boilers to Utilize Landfill Gas: An Environmentally and Economically Beneficial Opportunity, Landfill Methane Outreach Program, USEPA, December 2009. Landfill Gas Management Plan, Central Peninsula Landfill, Soldotna, Alaska, HDR Alaska, November 2010. Complete LFG Energy Project Development Handbook, Landfill Methane Outreach Program, USEPA, Updated February 2015. EN0530161146CGY CH2M HILL ENGINEERS, INC. • COMPANY PROPRIETARY 9-1 Appendix A LFGTE Calculation Sheet Appendix A ‐ LFGTE CalculationsYearUnlined Cells60% CELined Cells 1‐575% CECombined LFG% contribution from unlined cellscfm is total so Btu is 500 Btu/min at 50% CH4Convert Btu to kwh (1kwh = 3412.14148 Btu)Convert kwh/min to kwh/dayConvert kwh/day to kwMax energy available based on engine efficiency (CG3216)Gen set power @ 75%Potential number of Gen sets that could be used2015 KPB Energy use(kwh/yr) converted to kwAvg (2014‐2015) Skyview High school use (kwh/yr converted to kwThermal output of CHP 1.1 of electrical (1 gen set) (kw)CHP available based on number of gen sets (kw)KPL NG use (ENSTAR 2015, 219592 CCF) convert to kWDoes the LFG provide sufficient heat to offset gas useCFM 60% CFM 75% CFM%Btu 3412.1415 kwh/daykw 43%800 ea 948915 1597000 1.1 2195922016 178.1 106.86 189 142 248.61 43% 124,305 36.4 52,459 2,186 940 800 1 108 1822017174.6104.76209 157261.51 40%130,75538.3 55,182 2,299 989 800 1 108 182 1088 1088 735 Yes2018 171.2 102.72 229 172 274.4737%137,23540.2 57,9162,413 1,038 800 1 108 182 1141 1141 735 Yes2019 167.8 100.68248 186286.6835%143,34042.060,493 2,521 1,084 800 1 108 182 1192 1192 735 Yes2020164.4 98.64 267200 298.89 33%149,44543.8 63,069 2,628 1,130800 1 108 182 1243 1243 735 Yes2021 161.2 96.72 285 214 310.4731%155,23545.5 65,513 2,7301,174 800 1 108 182 1291 1291 735 Yes2022 158 94.8 302 227321.3 30%160,65047.1 67,798 2,825 1,215 800 2 108 182 13362672 735 Yes2023 154.9 92.94 319 239 332.19 28%166,09548.770,0962,921 1,256800 2 108 182 1381 2763 735 Yes2024 151.8 91.08 336252 343.0827%171,54050.3 72,394 3,0161,297800 2 108 182 14272854 735 Yes2025 148.8 89.28 352 264 353.2825%176,64051.8 74,5463,1061,336800 2 108 182 1469 2938 735 Yes2026145.8 87.48 367275 362.73 24%181,36553.2 76,5403,189 1,371 800 2 108 182 1508 3017735 Yes2027143 85.8 382 287372.3 23%186,15054.678,559 3,273 1,408 800 2 108 182 1548 3097735 Yes2028 140 84 397298 381.75 22%190,87555.9 80,554 3,3561,443 800 2 108 182 1588 3175 735 Yes2029 137.4 82.44 411 308 390.69 21%195,34557.2 82,4403,435 1,477800 2 108 182 1625 3250735 Yes2030134.680.76424 318 398.7620%199,38058.4 84,143 3,5061,508 800 2 108 182 1658 3317735 Yes2031 132 79.2 437328 406.95 19%203,47559.685,871 3,578 1,539 800 2 108 182 1692 3385 735 Yes2032 129.4 77.64 450 338 415.14 19%207,57060.8 87,599 3,6501,569 800 2 108 182 17263453 735 Yes2033 126.8 76.08 462 347422.5818%211,29061.9 89,169 3,715 1,598 800 2 108 182 17573515 735 Yes2034 124.3 74.58 474 356430.0817%215,04063.090,752 3,781 1,626800 2 108 182 1789 3577735 Yes2035 121.8 73.08 483 362 435.33 17%217,66563.8 91,859 3,8271,646800 2 108 182 18103621 735 Yes2036119.4 71.64 464 348 419.64 17%209,82061.5 88,549 3,6901,586800 2 108 182 1745 3490735 Yes203711770.2 446335 404.717%202,35059.3 85,3963,558 1,530800 2 108 182 1683 3366735 Yes2038 114.7 68.82 428 321 389.82 18% 194,910 57.1 82,256 3,4271,474 800 2 108 182 1621 3242 735 Yes2039 112 67.2 412 309 376.2 18% 188,100 55.1 79,382 3,3081,422 800 2 108 182 1564 3129 735 Yes Appendix B CG13216 – Part A – Cut Sheet G3306 – Part B – Specifications Series Gas Generator Sets CAT ® CG132 CAT CG132 SMARTERENERGY SOLUTIONS COMMERCIAL AND INDUSTRIAL FACILITIES Facilities such as manufacturing plants, resorts, shopping centers, office or residential buildings, universities, data centers and hospitals reduce operating costs and carbon footprint simultaneously. ELECTRIC UTILITIES Caterpillar has led innovation to deliver stationary and containerized gas power plants to electric utilities and district energy facilities around the world for both continuous grid support and peak electricity demand. MINES Mining operators increase mine safety and reduce carbon emissions with coal gas, while many other mining operations are realizing the benefits of onsite gas power generation to support greenfield site development. AGRICULTURE AND FOOD / BEVERAGE PROCESSING Biogas, a useful byproduct of the anaerobic digestion of organic waste, is created by food processors, ethanol and biodiesel manufacturers, and farms around the world as a renewable fuel resource for Cat® powered electricity generation. LANDFILLS AND WASTEWATER TREATMENT PLANTS Landfill and sewage gases are is generated by communities around the world as part of sanitary process infrastructure. Instead of destroying or flaring the methane gas produced, communities make beneficial use of this fuel as part of a sustainable energy program. GREENHOUSES In greenhouses, Cat gas generator sets simultaneously deliver electricity for lighting or sale to the local grid, hot water for facility heating, and carbon dioxide as an organic fertilizer for increased crop production. ® Installed capacity of 1,438 MWel with 2,577 generator sets worldwide MEETING YOUR NEEDS HAS SHAPED OUR HISTORY At Caterpillar, we understand what it takes to deliver a successful gas power generation system, and it starts with a core machine that is designed for efficiency and reliability. Since the 1920s, Caterpillar has been designing and building engines for power production. Although the technology has changed over the years, the philosophy hasn’t: to deliver the most reliable power generation at the lowest possible cost of ownership and operation. Today, Caterpillar not only manufactures power generation equipment, but we also provide customized project financing and trade solutions via Cat Financial and Cat World Trade. THE COMPLETE SOLUTION Caterpillar is your complete gas solutions partner. From mechanical systems such as gas fuel train and heat recovery systems, to exhaust aftertreatment that complies with the world’s most stringent emission requirements, Cat Gas Solutions engineering works with your local Cat dealer to deliver a complete scope of supply. Caterpillar also provides electrical systems such as master controls and paralleling switchgear, electrical distribution switchgear and uninterruptible power supplies (UPS) that can meet either UL or IEC requirements. PRODUCT SUPPORT WORLDWIDE Your gas power system is supported by our factory trained global network of Cat dealers. Therefore, you can rest assured that your equipment will be ordered, delivered, installed and commissioned in consultation with a local expert. You’ll also have the confidence that Caterpillar will be there to keep you up and running. Cat dealers have over 1,600 dealer branch stores operating in 200 countries to provide the most extensive post-sales support including oil and fuel monitoring services, preventive maintenance and comprehensive customer support agreements. LOWER LIFE CYCLE COST With longer maintenance intervals, higher fuel efficiency and competitive repair options, Caterpillar delivers the lowest total owning and operating costs. When you design your facility within the Cat Application and Installation Guidelines, you can expect generator set availability up to 99 percent of planned operating hours annually. It all adds up to a strong return on your investment, year after year. 10 MWel 928 MWel 290 MWel 100 MWel 44 MWel 66 MWel 50 Hz PRODUCT PERFORMANCE NATURAL GAS BIOGAS ENGINE TYPE UNITS CG132-8 CG132-12 CG132-16 Bore/stroke mm in 132/160 5.2/6.3 132/160 5.2/6.3 132/160 5.2/6.3 Displacement l in3 17.5 1068 26.3 1605 35 2136 Speed rpm 1500 1500 1500 Mean piston speed m/s ft/s 8 26 8 26 8 26 Length 1) mm in 3,090 122 3,690 145 4,060 160 Width 1) mm in 1,490 59 1,490 59 1,490 59 Height 1) mm in 2,190 86 2,160 85 2,110 83 Dry weight genset kg lb 4,880 10,760 6,090 13,428 6,960 15,347 ENGINE TYPE UNITS CG132-8 CG132-12 CG132-16 Electrical power 2) kWe 400 600 800 Mean effective pressure bar psi 19.0 276 18.9 274 18.9 274 Thermal output (+/-8 %) 3) kW Btu/m 428 24362 654 37225 856 48723 Electrical efficiency 2) % 42.3 42.0 42.4 Thermal efficiency 3) % 45.2 45.9 45.3 Total efficiency % 87.5 87.9 87.7 ENGINE TYPE UNITS CG132-8 CG132-12 CG132-16 Electrical power 2) kWe 400 600 800 Mean effective pressure bar psi 19.0 276 19.0 274 18.9 274 Thermal output (+/-8%) 3) kW Btu/m 398 22654 608 34607 810 46105 Electrical efficiency 2) % 42.8 42.7 42.8 Thermal efficiency 3) % 42.1 42.3 42.3 Total efficiency % 84.9 85.0 85.1 1) Transport dimensions of genset. Components set up separately must be separately taken into account. 2) According to ISO 3046/1 at voltage = 400V, PF=1.0 at 50Hz, and a methane number of MN70 for natural gas, MN 130 for biogas. 3) Exhaust gas cooled to 120° C with natural gas and 150° C with biogas, plus engine jacket water heat. NOx emissions as NO2 dry exhaust gas @ 5% O2 Biogas fuels assumed to meet published engine-in contaminant limits with compositions: Sewage gas (65 % CH4 / 35 % CO2) Biogas (60 % CH4 / 32 % CO2, rest N2) Landfill gas (50 % CH4 / 27 % CO2, rest N2) Minimum heating value (LHV) = 18.0 MJ/mn3 or 457 Btu/scf. Specifications for special gases available. Engine configuration with dry exhaust manifolds. Data is representative and non-binding. Contact your Caterpillar dealer for site and fuel specific performance. NOX ≤ 500 mg/mn 3, 1 g/bhp-h NOX ≤ 500 mg/mn 3, 1 g/bhp-h 60 Hz PRODUCT PERFORMANCE NATURAL GAS BIOGAS ENGINE TYPE UNITS CG132-8 CG132-12 CG132-16 Bore/stroke mm in 132/160 5.2/6.3 132/160 5.2/6.3 132/160 5.2/6.3 Displacement l in3 17.5 1068 26.3 1605 35 2136 Speed rpm 1800 1800 1800 Mean piston speed m/s ft/s 9.6 31 9.6 31 9.6 31 Length 1) mm in 3,090 122 3,690 145 4,060 160 Width 1) mm in 1,490 59 1,490 59 1,490 59 Height 1) mm in 2,190 86 2,160 85 2,110 83 Dry weight genset kg lb 4,880 10,760 6,090 13,428 6,960 15,347 ENGINE TYPE UNITS CG132-8 CG132-12 CG132-16 Electrical power 2) kWe 400 600 800 Mean effective pressure bar psi 15.8 229 15.7 228 15.7 228 Thermal output (+/-8 %) 3) kW Btu/m 447 25443 681 38762 892 50772 Electrical efficiency 2) % 41.2 41.1 41.5 Thermal efficiency 3) % 46.1 46.6 46.3 Total efficiency % 87.3 87.7 87.8 ENGINE TYPE UNITS CG132-8 CG132-12 CG132-16 Electrical power 2) kWe 400 600 800 Mean effective pressure bar psi 15.8 229 15.7 228 15.7 228 Thermal output (+/-8%) 3) kW Btu/m 415 23622 645 36713 845 48097 Electrical efficiency 2) % 41.6 41.4 41.7 Thermal efficiency 3) % 43.2 43.7 43.3 Total efficiency % 84.8 85.1 85.0 1) Transport dimensions of genset. Components set up separately must be separately taken into account. 2) According to ISO 3046/1 at voltage = 480V, PF=1.0 at 60Hz, and a methane number of MN 80 for natural gas, MN 130 for biogas. 3) Exhaust gas cooled to 120° C with natural gas and 150° C with biogas, plus engine jacket water heat. NOx emissions as NO2 dry exhaust gas @ 5% O2 Biogas fuels assumed to meet published engine-in contaminant limits with compositions: Sewage gas (65 % CH4 / 35 % CO2) Biogas (60 % CH4 / 32 % CO2, rest N2) Landfill gas (50 % CH4 / 27 % CO2, rest N2) Minimum heating value (LHV) = 18.0 MJ/mn3 or 457 Btu/scf. Specifications for special gases available. Engine configuration with dry exhaust manifolds Data is representative and non-binding. Contact your Caterpillar dealer for site and fuel specific performance. NOX ≤ 500 mg/mn 3, 1 g/bhp-h NOX ≤ 500 mg/mn 3, 1 g/bhp-h CAT, CATERPILLAR, their respective logos, “Caterpillar Yellow,” the “Power Edge” trade dress, as well as corporate and product identity used herein, are trademarks of Caterpillar and may not be used without permission. © 2012 Caterpillar. All Rights Reserved. LEBE0015-01 June 2012 For more information and to contact your local Cat dealer, visit www.catelectricpowerinfo.com/gas NEW ELECTRIC POWER GENERATION G3306 < Back REQUEST A QUOTE BIOGAS PROJECT FINANCING See our Offers FIND YOUR DEALER COMPARE MODELS VIEW PRODUCT DOWNLOADS Thanks! Your product information is ready for download. Download Gas Generator Set Ratings Guide Download Gas Solutions Brochure Page 1 of 3Cat | G3306 Gas Generator Set | Caterpillar 5/20/2016http://www.cat.com/en_US/products/new/power-systems/electric-power-generation/gas-ge... G3306 GAS GENERATOR SETS SPECIFICATION UNITS:US METRIC OVERVIEW From natural gas-fueled combined heat and power (CHP) systems and emergency power for facilities, to renewable biogas energy to support the local grid, or electricity generated from coal mine gases, Caterpillar has a wide range of reliable gas power solutions. Maximum Continuous Rating 143 ekW Fuel Type Natural Gas, Biogas, Field Gas, Propane SPECIFICATIONS Page 2 of 3Cat | G3306 Gas Generator Set | Caterpillar 5/20/2016http://www.cat.com/en_US/products/new/power-systems/electric-power-generation/gas-ge... ENGINE SPECIFICATION GENERATOR SET DIMENSION Maximum Electrical Efficiency 31.9% Maximum Standby Rating 160 Frequency 50 or 60 Hz rpm 1500 or 1800 rpm Engine Model G3306 Bore 4.8 in Stroke 6.0 in Displacement 638.0 in3 Aspiration NA, TA, LE Length 126.0 in Width 52.0 in Height 68.0 in Dry weight genset 4400.0 lb Page 3 of 3Cat | G3306 Gas Generator Set | Caterpillar 5/20/2016http://www.cat.com/en_US/products/new/power-systems/electric-power-generation/gas-ge... Appendix C KPB Pipe Size and Compressor Calculations Appendix C ‐ KPB Pipe Size and Compressor Calculations ENSTAR Piping head loss and size Pipe size =4 Flow = 435 scfm Design for max LFG = 0.2053824 m3/s Pipe length = 1,056 ft DeltaP X 1.5 = 10.7025 PSI Pressure required at burner = 5 PSI Total pressure required = 15.7025 PSI = 1.0826493 bar Power requirements for LFG compressor SCFM = 435 scfm Delta P = 54 in.WC Efficiency = 0.65 (typical) Power required = 5.69 HP shaft HP electric motor efficiency = 0.9 Power required = 3.82 KW electric power Annual Power Requied = 33,427 kwH Price per khW = 0.09$ Annual cost = 2,918.17$ http://www.freecalc.com/gasdia.htm Chiller Power Spec Enthalpy at 95 F = 130.1 kj/kg Spec Enthalpy at 32 F = 9.5 kj/kg Difference = 120.6 kj/kg Specific volume at 32 F 0.778 m3/kg Flow = 1600 scfm = 2719.5467 m3/hr Energy req't = 421564.7 kj/hr = 399559.02 BTU/hr = 33.296585 tons Typical COP = 0.6 kw/ton Power = 19.977951 kw Annual Power = 175006.85 kwH 206,762 kwH http://www.engineeringtoolbox.com/moist‐air‐properties‐d_1256.html Total annual power (compressor + chiller) = EN0307161114SEA 1 of 2 Appendix C ‐ KPB Pipe Size and Compressor Calculations Skyview Middle School Piping head loss and size Pipe size =6 Flow = 435 scfm Design for max LFG = 0.20538244 m3/s five Cat 3520 CHPs Pipe length = 7,392 ft DeltaP X 1.5= 10.7025 PSI Pressure required at burner = 5 PSI Total pressure required = 15.7025 PSI = 1.08264926 bar Power requirements for LFG compressor SCFM = 435 scfm Delta P = 54 in.WC Efficiency= 0.65 (typical) Power required = 5.69 HP shaft HP electric motor efficiency = 0.9 Power required = 3.82 KW electric power Annual Power Requied = 33,427 kwH Price per khW = 0.09$ Annual cost = 2,914.83$ http://www.freecalc.com/gasdia.htm Chiller Power Spec Enthalpy at 95 F = 130.1 kj/kg Spec Enthalpy at 32 F = 9.5 kj/kg Difference = 120.6 kj/kg Specific volume at 32 F = 0.778 m3/kg Flow = 1600 scfm = 2719.54674 m3/hr Energy required = 421564.701 kj/hr = 399559.023 BTU/hr = 33.2965853 tons Typical COP =0.6 kw/ton Power = 19.9779512 kw Annual Powe 175006.852 kwH 206,762 kwH http://www.engineeringtoolbox.com/moist‐air‐properties‐d_1256.html Total annual power (compressor + chiller) = EN0307161114SEA 2 of 2 Appendix D Pro Forma and Cost Estimates CURRENT ENERGY USECapital Cost ($)Average Annual O&M ($)Annual Grid Power or Gas Cost Reduction ($)NPV, 20‐year life ($)Option 1 ‐ Direct Use On Site in a NG Fired Boiler($1,022,120) ($176,910)$190,606($851,443)Option 2a ‐ Natural Gas Piping to CPL Evaporator and Boilers and from CPL to Boiler at Skyview MS($3,057,481) ($268,939)$252,136($3,266,886)Option 3 – Engine Gen Set at CPL Without Exhaust Heat($3,486,593) ($362,353)$1,206,381 $7,031,857Option 4 – Engine Gen Set at CPL, Utilize Exhaust Heat, OH Power Line to Skyview MS($3,503,636) ($381,191)$1,260,381 $7,453,011Option 5 – Remove CO2 and Trace Gases and Inject to ENSTAR Pipeline($823,141) ($284,625)$376,178 $317,807Option 6b – Transport NG Off Site in Pipeline to Gen Set at Skyview MS($4,724,551) ($496,420)$1,206,381 $4,123,128Table 6. Costs, Savings and Net Present Value for the OptionsFor each option, a construction cost estimate was prepared at a Class V (feasibility study) level in accordance with the AACE International (AACE) classification system. The precision range for this level of cost estimate is ‐50 to +100 percent of the actual value. O&M costs were estimated based on previous project experience, literature values, and vendor information.Cost estimates provided in this report have been prepared for guidance in project evaluation and implementation from the information available at the time of the estimate. They are intended only for comparison of alternatives and should not be used for project budgeting. The final costs of the project will depend on actual labor and material costs, competitive market conditions, implementation schedule, and other variable factors. As a result, the final project costs will vary from the estimates presented herein. Because of this, project feasibility and funding needs must be carefully reviewed prior to making specific financial decisions to help support a proper project evaluation and adequate funding. CURRENT ENERGY USEOPTION 1Development StageAnnual CCF output 961,8792019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039KW output 01234567891011121314151617181920Capital CostsConstructionPreconstruction, Site Preparation$12,600Site Work and Pipe Line$147,953Prefabricated Buildings, Slab on Grade$8,000Equipment$465,960Fees and PermitsEngineering Design Fee$63,451Allowance for Permitting$47,588Mob/Demob$15,863Construction Management fee$31,726Project Management$31,726Quality Control$9,518Contingency, Bonds & Insurance$187,736Subtotal($1,022,120)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Equipment Replacement$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Subtotal$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Operations & Maintenance CostsEngine ‐ gen maintenance, $/kw$0.015$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0O&M Labor Costs($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500)Other O&M Costs (Boiler, Pipeline, Compressor, Blower)($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335) ($44,335)Contingency 15%($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075) ($23,075)Subtotal$0($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910)Revenues or Cost SavingsElectric Power Saved ‐ kwh/year‐ $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Gas Usage Saved219,592 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606Cost per kwh saved0.179$ Cost per CCF saved0.868$ Total Cost($1,022,120) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910) ($176,910)Total Revenues$190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606Annual Net($1,022,120)$13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,696 $13,69620 Year Project LifeAnnual AvgTotal Capital Spending($1,022,120)Costs and revenues presented herein are order of magnitude for comparison of alternatives only and not appropriate for budget developmentTotal Equipment Replacement$0 $0 Cost and revenue estimates prepared in this task should be expected to change significantly when the full business case is developed.Total Operating and Maintenance($3,538,205) ($176,910)Real Discount Rate 5%Net Present Value($851,443)Net Present Value of Costs($3,226,813)EUAC $258,928Levelized Cost of Power, per kWh‐$ Levelized Cost of Gas per CCF 0.00003$ Operational Stage CURRENT ENERGY USEOPTION 2aDevelopment StageAnnual CCF output 961,8792019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039KW output 01234567891011121314151617181920Capital CostsConstructionPreconstruction, Site Preparation$39,100Site Work and Gas Pipeline$1,346,865Prefabricated Buildings, Slab on Grade$8,000Equipment$504,060Fees and PermitsEngineering Design Fee$189,803Allowance for Permitting$142,352Mob/Demob$47,451Construction Management fee$94,901Project Management$94,901Quality Control$28,470Contingency, Bonds & Insurance$561,578Subtotal($3,057,481)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Equipment Replacement$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Subtotal$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Operations & Maintenance CostsEngine ‐ gen maintenance, $/kw$0.015$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0O&M Labor Costs($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500)Other O&M Costs (Boiler, Pipeline, Compressor, Blower)($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360) ($124,360)Contingency 15%($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079) ($35,079)Subtotal$0($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939)Revenues or Cost SavingsElectric Power Saved ‐ kwh/year‐ $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Gas Usage Saved (CPL + Skyview)290,479 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136 $252,136Cost per kwh saved0.179$ Cost per CCF saved0.868$ Total Cost($3,057,481) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939) ($268,939)Total Revenues$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136$252,136Annual Net($3,057,481) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803) ($16,803)20 Year Project LifeAnnual AvgTotal Capital Spending($3,057,481)Costs and revenues presented herein are order of magnitude for comparison of alternatives only and not appropriate for budget development.Total Equipment Replacement $0 $0 Cost and revenue estimates prepared in this task should be expected to change significantly when the full business case is developed.Total Operating and Maintenance($5,378,780) ($268,939)Real Discount Rate 5%Net Present Value($3,266,886)Net Present Value of Costs($6,409,055)EUAC $514,279Levelized Cost of Power, per kWh‐$ Levelized Cost of Gas per CCF 0.00006$ Operational Stage CURRENT ENERGY USEOPTION 3Development StageAnnual CCF output02019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039KW output 1,4141234567891011121314151617181920Capital CostsConstructionPreconstruction, Site Preparation$49,200Site work$610,180Prefabricated Buildings, Slab on Grade$98,940Equipment$1,406,089Fees and PermitsEngineering Design Fee$216,441Allowance for Permitting$162,331Mobilization/Demobilization$54,110Construction Management Fee$108,220Project Management$108,220Quality Control$32,466Contingency, Bonds & Insurance$640,395Subtotal($3,486,593)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Equipment Replacement$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Subtotal$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Operations & Maintenance CostsEngine ‐ gen maintenance, $/kw$0.015($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510)O&M Labor Costs($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500)Other O&M Costs (Boiler, Pipeline, Compressor, Blower)($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080) ($29,080)Contingency 15%($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263) ($47,263)Subtotal$0($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353)Revenues or Cost SavingsElectric Power Saved ‐ kwh/year2,489,866 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544Excess Electrical Generation sold to HEA (kwh/yr)9,836,517 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837Cost per kwh saved0.193$ Cost per CCF saved0.907$ HEA Payment for Excess Electrical0.0738$ Total Cost($3,486,593) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353) ($362,353)Total Revenues$1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381 $1,206,381Annual Net($3,486,593)$844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,028 $844,02820 Year Project LifeAnnual AvgTotal Capital Spending($3,486,593)Costs and revenues presented herein are order of magnitude for comparison of alternatives only and not appropriate for budget developmentTotal Equipment Replacement$0 $0 Cost and revenue estimates prepared in this task should be expected to change significantly when the full business case is developedTotal Operating and Maintenance($7,247,061) ($362,353)Real Discount Rate5%Net Present Value$7,031,857Net Present Value of Costs($8,002,313)EUAC $642,126Levelized Cost of Power, per kWh0.054569$ Levelized Cost of Gas per CCF‐$ Operational Stage CURRENT ENERGY USEOPTION 4Development StageAnnual CCF output 02019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039KW output 1,4141234567891011121314151617181920Capital CostsConstructionPreconstruction, Site Preparation$51,700Site Work and Overhead Power Line$598,880Prefabricated Buildings, Slab on Grade$97,340Equipment$1,427,069Fees and PermitsEngineering Design Fee$217,499Allowance for Permitting$163,124Mobilization/Demobilization$54,375Construction Management Fee$108,749Project Management$108,749Quality Control$32,625Contingency, Bonds & Insurance$643,525Subtotal($3,503,636)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Equipment Replacement$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Subtotal$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Operations & Maintenance CostsEngine ‐ gen maintenance, $/kw$0.015($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510)O&M Labor Costs($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500)Other O&M Costs (Boiler, Pipeline, Compressor, Blower)($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280) ($52,280)Contingency 15%($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901) ($42,901)Subtotal$0($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191)Revenues or Cost SavingsElectric Power Saved ‐ kwh/year2,489,866 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544Excess Electrical Generation sold to HEA9,836,517 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837Gas Usage Saved (CPL Evaporator) CCF/year62,212 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000 $54,000Cost per kwh saved0.193$ HEA Payment for Excess Electrical0.0738$ Cost per CCF saved0.868$ Total Cost($3,503,636) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191) ($381,191)Total Revenues $1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381$1,260,381Annual Net($3,503,636)$879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,190 $879,19020 Year Project LifeAnnual AvgTotal Capital Spending($3,503,636)Costs and revenues presented herein are order of magnitude for comparison of alternatives only and not appropriate for budget development.Total Equipment Replacement $0 $0 Cost and revenue estimates prepared in this task should be expected to change significantly when the full business case is developed.Total Operating and Maintenance($7,623,821)($381,191)Real Discount Rate 5%Net Present Value $7,453,011Net Present Value of Costs($8,254,119)EUAC $662,332Levelized Cost of Power, per kWh 0.056286$ Levelized Cost of Gas per CCF‐$ Operational Stage CURRENT ENERGY USEOPTION 5Development StageAnnual CCF output 961,8792019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039KW output 01234567891011121314151617181920Capital CostsConstructionPreconstruction, Site Preparation$11,300Site Work$140,385Prefabricated Buildings, Slab on Grade$26,000Equipment$333,305Fees and PermitsEngineering Design Fee$51,099Allowance for Permitting$38,324Mob/Demob$12,775Construction Management fee$25,550Project Management$25,550Quality Control$7,665Contingency, Bonds & Insurance$151,189Subtotal($823,141)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Equipment Replacement$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Subtotal$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Operations & Maintenance CostsEngine‐gen maintenance, $/kwh$0.015$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0O&M Labor Costs($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000) ($219,000)Other O&M Costs (Boiler, Pipeline, Compressor, Blower)($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500) ($28,500)Contingency 15%($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125) ($37,125)Subtotal$0($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625)Revenues or Cost SavingsElectric Power Saved ‐ kwh/year‐ $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Excess Gas Sold to ENSTAR (CCF)742,287 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572 $185,572Gas Usage Saved (CPL)219,592 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606 $190,606Cost per kwh saved0.193$ Cost per CCF saved0.868$ ENSTAR Wholesale Price: $2.50 per Thousand CF2.50$ Total Cost($823,141) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625) ($284,625)Total Revenues$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178$376,178Annual Net($823,141)$91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,553 $91,55320 Year Project LifeAnnual AvgTotal Capital Spending($823,141)Costs and revenues presented herein are order of magnitude for comparison of alternatives only and not appropriate for budget development.Total Equipment Replacement $0 $0 Cost and revenue estimates prepared in this task should be expected to change significantly when the full business case is developed.Total Operating and Maintenance($5,692,500) ($284,625)Real Discount Rate 5%Net Present Value $317,807Net Present Value of Costs($4,370,198)EUAC $350,676Levelized Cost of Power, per kWh‐$ Levelized Cost of Gas per CCF 0.00004$ Operational Stage CURRENT ENERGY USEOPTION 6bDevelopment StageAnnual CCF output 02016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036KW output 1,4141234567891011121314151617181920Capital CostsConstructionPreconstruction, Site Preparation$47,900Site Work$1,346,865Prefabricated Buildings, Slab on Grade$98,940Equipment$1,439,205Fees and PermitsEngineering Design Fee$293,291Allowance for Permitting$219,968Mob/Demob$73,323Construction Management fee$146,646Project Management$146,646Quality Control$43,994Contingency, Bonds & Insurance$867,775Subtotal($4,724,551)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Equipment Replacement$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Subtotal$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Operations & Maintenance CostsEngine‐gen maintenance, $/kwh$0.015($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510) ($176,510)O&M Labor Costs($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500) ($109,500)Other O&M Costs (Boiler, Pipeline, Compressor, Blower)($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660) ($145,660)Contingency 15%($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750) ($64,750)Subtotal$0($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420)Revenues or Cost SavingsElectric Power Saved ‐ kwh/year (CPL + Skyview)2,489,866 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544 $480,544Excess Electrical Generation Sold to HEA9,836,517 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837 $725,837Cost per kwh saved0.193$ Cost per CCF saved0.868$ HEA Payment for Excess Electrical0.0738$ Total Cost($4,724,551) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420) ($496,420)Total Revenues$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381$1,206,381Annual Net($4,724,551)$709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,961 $709,96120 Year Project LifeAnnual AvgTotal Capital Spending($4,724,551)Costs and revenues presented herein are order of magnitude for comparison of alternatives only and not appropriate for budget development.Total Equipment Replacement $0 $0 Cost and revenue estimates prepared in this task should be expected to change significantly when the full business case is developed.Total Operating and Maintenance($9,928,401)($496,420)Real Discount Rate 5%Net Present Value $4,123,128Net Present Value of Costs($10,911,043)EUAC $875,530Levelized Cost of Power, per kWh 0.074404$ Levelized Cost of Gas per CCF‐$ Operational Stage Kenai Peninsula Borough Landfill Gas Utilization 06/20/16 Alaska ACF Option 1 Natural Gas Piping at CPL to onsite boilers and evaporator 217% Concept Screening Level Costs (AACE Level 5, Accuracy ‐50% ‐ +100%) Description Qty Unit Unit Total Subtotals Notes Cost Cost 1010 Preconstruction, Site Preparation 12,600$ Survey ‐ Building Sites (CPL) 0 Days 3,800$ ‐$ Initial survey and support during construction Survey ‐ Natural Gas Piping Path 2 Days 3,800$ 7,600$ Contractor Plans & Submittals 1 LS 5,000$ 5,000$ Estimated Quantity 1020 Site Work 147,953$ Clear & Grub with Chipping (250 LF x 10 FT width) 0 Acres 7,000$ ‐$ MII 6" Dia. HDPE SDR 11 Natural Gas Piping, below ground 1,865 LF 57$ 106,305$ MII, From gas outlet to CPL evaporator and boilers Pipe Saddles (from blower to compressor) 5 EA 480$ 2,400$ MII Pipe Support Concrete Bases 10 EA 840$ 8,400$ MII Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 1,865 LF 3.50$ 6,528$ MII Pipe Bedding Material, 12" 104 CY 35$ 3,640$ MII, standard practice is backfill around HDPE pipe with gravel. Horizontal Boring Under Roads 0 LF 1,900$ ‐$ Historical costs for similar projects Jacking Pits for Horizontal Boring 0 EA 105,000$ ‐$ Historical costs for similar projects Piping from knockout to leachate collection 900 LF 18$ 16,200$ MII, 3" HDPE SDR 13.5 Leachate Collection Piping Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 900 LF 3.50$ 3,150$ MII Pipe Bedding Material, 9" 38 CY 35$ 1,330$ MII 1030 Prefabricated Buildings 8,000$ 6" Slab on Grade for Gen Set 0 SF 20$ ‐$ Timberline 12" Slab on Grade for Gen Set 0 SF 60$ ‐$ Timberline Excavation for slab on grade 0.0 CY 105$ ‐$ CalTrans, assume that excavated material can be used for daily cover at CPL Engine Generator Bldg, Prefabricated 0 SF 60$ ‐$ MII: Prefab 20 x 25 Compressor Bldg, Prefabricated 100 SF 60$ 6,000$ MII: Prefab 10 x 10 Utility Fitout (electric, lighting, HVAC) 100 SF 20$ 2,000$ Timberline 1040 Equipment 465,960$ Moisture Knockout Tank (100 Gal Expansion tank) 1 EA 5,040$ 5,040$ MII Greenhouse Gas (GHG) Monitoring Equipment 1 EA 11,105$ 11,105$ Vendor ‐ Equipco Services Natural Gas Metering Station 1 EA 79,000$ 79,000$ US EPA LFGcost‐Web Retrofit Natural Gas Fired Boiler (Seamless Controls) 1 EA 150,115$ 150,115$ US EPA LFGcost‐Web Generator Set (Cat C3306) at CPL or Skyview MS 0 EA 151,400$ ‐$ Vendor Quote for used. Added 40% factor for new gen set, includes sales tax Generator Set (Cat CG132‐16) at CPL or Skyview MS 0 EA 524,700$ ‐$ Vendor Quote, includes sales tax Gen Set Transport Anchorage to Soldotna 0 EA 750$ ‐$ Vendor Quote (Knight Flight Cargo Services) Generator Set Installation 0 EA 30,900$ ‐$ MII Transformer at Client Facility (13.8 kV primary) 0 EA 64,400$ ‐$ MII Switch Gear 1200 A, 13.8 kV, 750 MVA at Client Facility 0 EA 25,200$ ‐$ MII Vent chimney for Engine Generator 0 LF 140$ ‐$ MII Air compressor, electric, 5 HP (at CPL) 1 EA 9,380$ 9,380$ MII Compressor Air Dryer, 10 SCFM 1 EA 1,680$ 1,680$ MII Blower System, 163 SCFM, 15 HP, 15 psi 2 EA 19,320$ 38,640$ MII, one blower for each landfill cell 10.5 million BTU/hr Flare System (flare, piping, trenching, backfill) 1 EA 147,000$ 147,000$ MII, 026610106223 Startup & Testing 3 Days 8,000$ 24,000$ Estimated Quantity Subtotal 634,513$ 634,513$ 1050 Consultant and Subcontractor Fees 199,871$ Engineering Design Fee 1 PER 10.0% 63,451$ US EPA Allowance for Permitting 1 PER 7.5% 47,588$ US EPA Mobilization/Demobilization 1 PER 2.5% 15,863$ US EPA Construction Management 1 PER 5.0% 31,726$ US EPA Project Management 1 PER 5.0% 31,726$ US EPA Quality Control 1 PER 1.5% 9,518$ US EPA Subtotal 834,384$ 1060 Contingency, Bonds & Insurance 187,736$ Contingency 1 PER 20.0% 166,877$ Bonds & Insurance 1 PER 2.5% 20,860$ Total Construction Costs 1,022,120$ 1070 Operations & Maintenance Costs 153,835$ O&M Labor 730 HRS 150$ 109,500$ 2 hours/day, 365 Days/Year Engine Generator Repair & Maintenance 0 kWH 0.015$ ‐$ M. Lopez Caterpillar Electric Power Presentation January 2012. 600 kW Output Boiler O&M 1 LS 7,300$ 7,300$ Estimator Judgement Compressor O&M 1 LS 3,600$ 3,600$ MII Transformer Inspection & Maintenance 0 EA 550$ ‐$ MII, Assumes weekly inspections Pipeline inspection, 4"‐12" diameter 1,865 LF 15$ 27,975$ MII, Assumes annual inspection Blower O&M 2 LS 2,730$ 5,460$ MII PRESENT VALUE ANALYSIS 5.0% Discount Rate Year Cost Type Cost Rate (5%) Present Value 2019 0 Capital Cost $1,022,120 1.00 $1,022,120 2020 1 O&M Year $153,835 0.95 $146,510 2021 2 O&M Year $153,835 0.91 $139,533 2022 3 O&M Year $153,835 0.86 $132,888 2023 4 O&M Year $153,835 0.82 $126,560 2024 5 O&M Year $153,835 0.78 $120,534 2025 6 O&M Year $153,835 0.75 $114,794 2026 7 O&M Year $153,835 0.71 $109,328 2027 8 O&M Year $153,835 0.68 $104,122 2028 9 O&M Year $153,835 0.64 $99,163 2029 10 O&M Year $153,835 0.61 $94,441 2030 11 O&M Year $153,835 0.58 $89,944 2031 12 O&M Year $153,835 0.56 $85,661 2032 13 O&M Year $153,835 0.53 $81,582 2033 14 O&M Year $153,835 0.51 $77,697 2034 15 O&M Year $153,835 0.48 $73,997 2035 16 O&M Year $153,835 0.46 $70,474 2036 17 O&M Year $153,835 0.44 $67,118 2037 18 O&M Year $153,835 0.42 $63,922 2038 19 O&M Year $153,835 0.40 $60,878 2039 20 O&M Year $153,835 0.38 $57,979 TOTAL PRESENT VALUE ANALYSIS $2,939,000 Notes: As the design is at conceptual stage, the tie‐ins to existing equipment and facilities have not being identified. Escalation is not included The budget is based on 2nd quarter 2016 rates for Soldotna, Alaska. These AACE Classification Class 5 cost estimates are assumed to represent the actual total installed cost within the range of ‐50 percent to +100 percent (% based on AACE) of the cost indicated. It would appear prudent that internal budget allowances account for the highest cost indicated by this range as well as other site specific allowances. The cost estimate has been prepared for guidance in project evaluation and implementation from the information available at the time of the estimate. The final costs of the project will depend on actual labor and material costs, competitive market conditions, implementation schedule, and other variable factors. As a result, the final project costs will vary from the estimates presented herein. Because of this, project feasibility and funding needs must be carefully reviewed prior to making specific financial decisions to help ensure proper project evaluation and adequate funding. KPB (3%) and Soldotna (3%) sales tax included in unit rates. Municipal fees & Licenses have been estimated as a percentage of the total direct costs Exclusions: Only limited equipment specifications have been identified. Kenai Peninsula Borough Landfill Gas Utilization 06/20/16 Alaska ACF Option 2a Direct Use On and Off Site, Transport via Pipeline to Skyview MS 217% Concept Screening Level Costs (AACE Level 5, Accuracy ‐50% ‐ +100%) Description Qty Unit Unit Total Subtotals Notes Cost Cost 1010 Preconstruction, Site Preparation 39,100$ Survey ‐ Building Sites (CPL) 0 Days 3,800$ ‐$ Initial survey and support during construction Survey ‐ Natural Gas Piping Path 7 Days 3,800$ 26,600$ Contractor Plans & Submittals 1 LS 12,500$ 12,500$ Estimated Quantity 1020 Site Work 1,346,865$ Clear & Grub with Chipping (3,170 LF x 10 FT width) 0.73 Acres 7,000$ 5,110$ MII, Not all of the proposed path needs to be cleared. 6" Dia. HDPE SDR 11 Natural Gas Piping, below ground 6,960 LF 57$ 396,720$ MII, From gas outlet to CPL evaporator, CPL boilers and to Skyview MS Pipe Saddles (from blower to compressor) 5 EA 480$ 2,400$ MII Pipe Support Concrete Bases 10 EA 840$ 8,400$ MII Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 6,960 LF 3.50$ 24,360$ MII Pipe Bedding Material, 12" 387 CY 35$ 13,545$ MII, standard practice is backfill around HDPE pipe with gravel. Saw Cut Asphalt 45 LF 2.00$ 90$ Timberline Cold Patch Asphalt 16 SY 35.00$ 560$ Timberline Horizontal Boring Under Roads 350 LF 1,900$ 665,000$ Historical costs for similar projects Jacking Pits for Horizontal Boring 2 EA 105,000$ 210,000$ Historical costs for similar projects Piping from knockout to leachate collection 900 LF 18$ 16,200$ MII, 3" HDPE SDR 13.5 Leachate Collection Piping Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 900 LF 3.50$ 3,150$ MII Pipe Bedding Material, 9" 38 CY 35$ 1,330$ MII 1030 Prefabricated Buildings 8,000$ 6" Slab on Grade for Gen Set 0 SF 20$ ‐$ Timberline 12" Slab on Grade for Gen Set 0 SF 60$ ‐$ Timberline Excavation for slab on grade 0.0 CY 105$ ‐$ CalTrans, assume that excavated material can be used for daily cover at CPL Engine Generator Bldg, Prefabricated 0 SF 60$ ‐$ MII: Prefab 20 x 25 Compressor Bldg, Prefabricated 100 SF 60$ 6,000$ MII: 30‐FT x 15‐FT x 16‐FT building to enclose natural gas compressor. Utility Fitout (electric, lighting, HVAC) 100 SF 20$ 2,000$ Timberline 1040 Equipment 504,060$ Moisture Knockout Tank (100 Gal Expansion tank) 1 EA 5,040$ 5,040$ MII Greenhouse Gas (GHG) Monitoring Equipment 1 EA 11,105$ 11,105$ Vendor ‐ Equipco Services Natural Gas Metering Station 1 EA 79,000$ 79,000$ US EPA LFGcost‐Web Retrofit Natural Gas Fired Boiler (Seamless Controls) 1 EA 150,115$ 150,115$ US EPA LFGcost‐Web Generator Set (Cat C3306) at CPL or Skyview MS 0 EA 151,400$ ‐$ Vendor Quote for used. Added 40% factor for new gen set, includes sales tax Generator Set (Cat CG132‐16) at CPL or Skyview MS 0 EA 524,700$ ‐$ Vendor Quote, includes sales tax Gen Set Transport Anchorage to Soldotna 0 EA 750$ ‐$ Vendor Quote (Knight Flight Cargo Services) Generator Set Installation 0 EA 30,900$ ‐$ MII Transformer at Client Facility (13.8 kV primary) 0 EA 64,400$ ‐$ MII Switch Gear 1200 A, 13.8 kV, 750 MVA at Client Facility 0 EA 25,200$ ‐$ MII Vent chimney for Engine Generator 0 LF 140$ ‐$ MII Air compressor, electric, 5 HP (at CPL) 0 EA 9,380$ ‐$ MII Air compressor, 105 SCFM at 125 psi, 25 H.P. (at CPL) 1 EA 35,700$ 35,700$ MII 221519105690 Compressor Air Dryer, 100 SCFM 1 EA 5,460$ 5,460$ MII Blower System, 163 SCFM, 15 HP, 15 psi 2 EA 19,320$ 38,640$ MII, one blower for each landfill cell 10.5 million BTU/hr Flare System (flare, piping, trenching, backfill) 1 EA 147,000$ 147,000$ MII, 026610106223 Startup & Testing 4 Days 8,000$ 32,000$ Estimated Quantity Subtotal 1,898,025$ 1,898,025$ 1050 Consultant and Subcontractor Fees 597,878$ Engineering Design Fee 1 PER 10.0% 189,803$ US EPA Allowance for Permitting 1 PER 7.5% 142,352$ US EPA Mobilization/Demobilization 1 PER 2.5% 47,451$ US EPA Construction Management 1 PER 5.0% 94,901$ US EPA Project Management 1 PER 5.0% 94,901$ US EPA Quality Control 1 PER 1.5% 28,470$ US EPA Subtotal 2,495,903$ 1060 Contingency, Bonds & Insurance 561,578$ Contingency 1 PER 20.0% 499,181$ Bonds & Insurance 1 PER 2.5% 62,398$ Total Construction Costs 3,057,481$ 1070 Operations & Maintenance Costs 233,860$ O&M Labor 730 HRS 150$ 109,500$ 2 hours/day, 365 Days/Year Engine Generator Repair & Maintenance 0 kWH 0.015$ ‐$ M. Lopez Caterpillar Electric Power Presentation January 2012. 600 kW Output Boiler O&M 1 LS 7,300$ 7,300$ Estimator Judgement Compressor O&M 1 LS 7,200$ 7,200$ MII, for compressor at CPL to gas into pipeline Transformer Inspection & Maintenance 0 EA 550$ ‐$ MII, Assumes weekly inspections Pipeline inspection, 4"‐12" diameter 6,960 LF 15$ 104,400$ MII, Assumes annual inspection Blower O&M 2 LS 2,730$ 5,460$ MII PRESENT VALUE ANALYSIS 5.0% Discount Rate Year Cost Type Cost Rate (5%) Present Value 2019 0 Capital Cost $3,057,481 1.00 $3,057,481 2020 1 O&M Year $233,860 0.95 $222,724 2021 2 O&M Year $233,860 0.91 $212,118 2022 3 O&M Year $233,860 0.86 $202,017 2023 4 O&M Year $233,860 0.82 $192,397 2024 5 O&M Year $233,860 0.78 $183,235 2025 6 O&M Year $233,860 0.75 $174,510 2026 7 O&M Year $233,860 0.71 $166,200 2027 8 O&M Year $233,860 0.68 $158,286 2028 9 O&M Year $233,860 0.64 $150,748 2029 10 O&M Year $233,860 0.61 $143,570 2030 11 O&M Year $233,860 0.58 $136,733 2031 12 O&M Year $233,860 0.56 $130,222 2032 13 O&M Year $233,860 0.53 $124,021 2033 14 O&M Year $233,860 0.51 $118,115 2034 15 O&M Year $233,860 0.48 $112,491 2035 16 O&M Year $233,860 0.46 $107,134 2036 17 O&M Year $233,860 0.44 $102,032 2037 18 O&M Year $233,860 0.42 $97,174 2038 19 O&M Year $233,860 0.40 $92,546 2039 20 O&M Year $233,860 0.38 $88,139 TOTAL PRESENT VALUE ANALYSIS $5,972,000 Notes: As the design is at conceptual stage, the tie‐ins to existing equipment and facilities have not being identified. Escalation is not included The budget is based on 2nd quarter 2016 rates for Soldotna, Alaska.These AACE Classification Class 5 cost estimates are assumed to represent the actual total installed cost within the range of ‐50 percent to +100 percent (% based on AACE) of the cost indicated. It would appear prudent that internal budget allowances account for the highest cost indicated by this range as well as other site specific allowances. The cost estimate has been prepared for guidance in project evaluation and implementation from the information available at the time of the estimate. The final costs of the project will depend on actual labor and material costs, competitive market conditions, implementation schedule, and other variable factors. As a result, the final project costs will vary from the estimates presented herein. Because of this, project feasibility and funding needs must be carefully reviewed prior to making specific financial decisions to help ensure proper project evaluation and adequate funding. KPB (3%) and Soldotna (3%) sales tax included in unit rates. Municipal fees & Licenses have been estimated as a percentage of the total direct costs Exclusions: Only limited equipment specifications have been identified. Kenai Peninsula Borough Landfill Gas Utilization 06/20/16 Alaska ACF Option 3 Landfill Gas to Energy Power Plant at CPL OH power line from CPL, No 217% Utilization of Gen Set Exhaust Heat Concept Screening Level Costs (AACE Level 5, Accuracy ‐50% ‐ +100%) Description Qty Unit Unit Total Subtotals Notes Cost Cost 1010 Preconstruction, Site Preparation 49,200$ Survey ‐ Building Sites (CPL) 2 Days 3,800$ 7,600$ Initial survey and support during construction Survey ‐ OH Power Line 7 Days 3,800$ 26,600$ Contractor Plans & Submittals 1 LS 15,000$ 15,000$ Estimated Quantity 1020 Site Work 610,180$ Clear & Grub with Chipping (3,170 LF x 15 FT width) 1.1 Acres 7,000$ 7,700$ MII, Not all of the proposed path needs to be cleared. 6" Dia. HDPE SDR 11 Natural Gas Piping, below ground 0 LF 57$ ‐$ MII, From gas outlet to boiler Pipe Saddles (from blower to compressor) 5 EA 480$ 2,400$ MII Pipe Support Concrete Bases 10 EA 840$ 8,400$ MII Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 0 LF 3.50$ ‐$ MII Pipe Bedding Material, 12" 0 CY 35$ ‐$ MII, standard practice is backfill around HDPE pipe with gravel. Saw Cut Asphalt 0 LF 2.00$ ‐$ Timberline Cold Patch Asphalt 0 SY 35.00$ ‐$ Timberline Horizontal Boring Under Roads 0 LF 1,900$ ‐$ Historical costs for similar projects Jacking Pits for Horizontal Boring 0 EA 105,000$ ‐$ Historical costs for similar projects Overhead Power Line (poles, conductors, conduit) 6,960 LF 75$ 522,000$ MII, From gas outlet to CPL buildings and to Skyview MS Concrete Pole Bases with Anchor Bolts 14 EA 3,500$ 49,000$ CIP Concrete columns with 1‐1/2" x 14" screw anchor bolts Piping from knockout to leachate collection 900 LF 18$ 16,200$ MII, 3" HDPE SDR 13.5 Leachate Collection Piping Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 900 LF 3.50$ 3,150$ MII Pipe Bedding Material, 9" 38 CY 35$ 1,330$ MII 1030 Prefabricated Buildings 98,940$ 6" Slab on Grade for Gen Set 0 SF 20$ ‐$ Timberline 12" Slab on Grade for Gen Set 500 SF 60$ 30,000$ Timberline Excavation for slab on grade 28 CY 105$ 2,940$ CalTrans, assume that excavated material can be used for daily cover at CPL Engine Generator Bldgs, Prefabricated 500 SF 60$ 30,000$ MII: Two prefab buildings 20 x 25 Compressor Bldg, Prefabricated 100 SF 60$ 6,000$ MII: Prefab 10 x 10 Utility Fitout (electric, lighting, HVAC) 600 SF 20$ 12,000$ Timberline 6' Chain Link Fence with personnel and vehicle gates 240 LF 75$ 18,000$ MII 1040 Equipment 1,406,089$ Moisture Knockout Tank (100 Gal Expansion tank) 1 EA 5,040$ 5,040$ MII Greenhouse Gas (GHG) Monitoring Equipment 1 EA 11,105$ 11,105$ Vendor ‐ Equipco Services Natural Gas Metering Station 0 EA 79,000$ ‐$ US EPA LFGcost‐Web Retrofit Natural Gas Fired Boiler (Seamless Controls) 0 EA 150,115$ ‐$ US EPA LFGcost‐Web Generator Set (Cat CG132‐16) at CPL or Skyview MS 2 EA 524,700$ 1,049,400$ Vendor Quote, includes sales tax Generator Set (Cat C3306) at CPL or Skyview MS 0 EA 151,400$ ‐$ Vendor Quote for used. Added 40% factor for new gen set, includes sales tax Gen Set Transport Anchorage to Soldotna 2 EA 750$ 1,500$ Vendor Quote (Knight Flight Cargo Services) Generator Set Installation 2 EA 30,900$ 61,800$ MII Transformer at Client Facility (13.8 kV primary) 1 EA 64,400$ 64,400$ MII Switch Gear 1200 A, 13.8 kV, 750 MVA at Client Facility 1 EA 25,200$ 25,200$ MII Vent chimney for Engine Generator 50 LF 140$ 7,000$ MII Air compressor, electric, 5 HP (at CPL) 0 EA 9,380$ ‐$ MII Compressor Air Dryer, 10 SCFM 0 EA 1,680$ ‐$ MII Compressor Air Dryer, 100 SCFM 2 EA 5,460$ 10,920$ MII Blower System, 163 SCFM, 15 HP, 15 psi 2 EA 19,320$ 38,640$ MII, one blower for each landfill cell SCADA System ‐ Host Computer 1 EA 18,375$ 18,375$ MII, 230923103282 SCADA System ‐ Software 1 EA 17,782$ 17,782$ Trihedral VT Scada US Pricing Sheet SCADA System Remote Terminal Units 4 EA 2,367$ 9,468$ Moxa ioPAC 8500‐9‐RJ45‐C‐T Startup & Testing 10 Days 8,000$ 80,000$ Estimated Quantity Blower O&M 2 LS 2,730$ 5,460$ MII Subtotal 2,164,409$ 2,164,409$ 1050 Consultant and Subcontractor Fees 681,789$ Engineering Design Fee 1 PER 10.0% 216,441$ US EPA Allowance for Permitting 1 PER 7.5% 162,331$ US EPA Mobilization/Demobilization 1 PER 2.5% 54,110$ US EPA Construction Management 1 PER 5.0% 108,220$ US EPA Project Management 1 PER 5.0% 108,220$ US EPA Quality Control 1 PER 1.5% 32,466$ US EPA Subtotal 2,846,198$ 1060 Contingency, Bonds & Insurance 640,395$ Contingency 1 PER 20.0% 569,240$ Bonds & Insurance 1 PER 2.5% 71,155$ Total Construction Costs 3,486,593$ 1070 Operations & Maintenance Costs 324,380$ O&M Labor 730 HRS 150$ 109,500$ 2 hours/day, 365 Days/Year Engine Generator Repair & Maintenance 12,386,640 kWH 0.015$ 185,800$ M. Lopez Caterpillar Electric Power Presentation January 2012. Boiler O&M 0 LS 7,300$ ‐$ Estimator Judgement Compressor O&M 1 LS 3,600$ 3,600$ MII Transformer Inspection & Maintenance 26 EA 770$ 20,020$ MII, Assumes weekly inspections Pipeline inspection, 4"‐12" diameter 0 LF 15$ ‐$ MII, Assumes annual inspection Blower O&M 2 LS 2,730$ 5,460$ Estimator Judgement PRESENT VALUE ANALYSIS 5.0% Discount Rate Year Cost Type Cost Rate (5%) Present Value 2019 0 Capital Cost $3,486,593 1.00 $3,486,593 2020 1 O&M Year $324,380 0.95 $308,933 2021 2 O&M Year $324,380 0.91 $294,222 2022 3 O&M Year $324,380 0.86 $280,211 2023 4 O&M Year $324,380 0.82 $266,868 2024 5 O&M Year $324,380 0.78 $254,160 2025 6 O&M Year $324,380 0.75 $242,057 2026 7 O&M Year $324,380 0.71 $230,531 2027 8 O&M Year $324,380 0.68 $219,553 2028 9 O&M Year $324,380 0.64 $209,098 2029 10 O&M Year $324,380 0.61 $199,141 2030 11 O&M Year $324,380 0.58 $189,658 2031 12 O&M Year $324,380 0.56 $180,627 2032 13 O&M Year $324,380 0.53 $172,025 2033 14 O&M Year $324,380 0.51 $163,834 2034 15 O&M Year $324,380 0.48 $156,032 2035 16 O&M Year $324,380 0.46 $148,602 2036 17 O&M Year $324,380 0.44 $141,526 2037 18 O&M Year $324,380 0.42 $134,786 2038 19 O&M Year $324,380 0.40 $128,368 2039 20 O&M Year $324,380 0.38 $122,255 TOTAL PRESENT VALUE ANALYSIS $7,529,000 Notes: As the design is at conceptual stage, the tie‐ins to existing equipment and facilities have not being identified. Escalation is not included The budget is based on 2nd quarter 2016 rates for Soldotna, Alaska.These AACE Classification Class 5 cost estimates are assumed to represent the actual total installed cost within the range of ‐50 percent to +100 percent (% based on AACE) of the cost indicated. It would appear prudent that internal budget allowances account for the highest cost indicated by this range as well as other site specific allowances. The cost estimate has been prepared for guidance in project evaluation and implementation from the information available at the time of the estimate. The final costs of the project will depend on actual labor and material costs, competitive market conditions, implementation schedule, and other variable factors. As a result, the final project costs will vary from the estimates presented herein. Because of this, project feasibility and funding needs must be carefully reviewed prior to making specific financial decisions to help ensure proper project evaluation and adequate funding. KPB (3%) and Soldotna (3%) sales tax included in unit rates. Municipal fees & Licenses have been estimated as a percentage of the total direct costs Exclusions: Only limited equipment specifications have been identified. Kenai Peninsula Borough Landfill Gas Utilization 06/20/16 Alaska ACF Option 4 Landfill Gas to Energy Power Plant at CPL OH power line from CPL with 217% engine exhaust piped to evaporator Concept Screening Level Costs (AACE Level 5, Accuracy ‐50% ‐ +100%) Description Qty Unit Unit Total Subtotals Notes Cost Cost 1010 Preconstruction, Site Preparation 51,700$ Survey ‐ Building Sites (CPL) 2 Days 3,800$ 7,600$ Initial survey and support during construction Survey ‐ OH Power Line 7 Days 3,800$ 26,600$ Contractor Plans & Submittals 1 LS 17,500$ 17,500$ Estimated Quantity 1020 Site Work 598,880$ Clear & Grub with Chipping (3,170 LF x 15 FT width) 1.1 Acres 7,000$ 7,700$ MII, Not all of the proposed path needs to be cleared. 6" Dia. HDPE SDR 11 Natural Gas Piping, below ground 900 LF 57$ 51,300$ MII, From gas outlet to Gen Set Pipe Saddles (from blower to compressor) 5 EA 480$ 2,400$ MII Pipe Support Concrete Bases 10 EA 840$ 8,400$ MII Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 900 LF 3.50$ 3,150$ MII Pipe Bedding Material, 12" 50 CY 35$ 1,750$ MII, standard practice is backfill around HDPE pipe with gravel. Saw Cut Asphalt 0 LF 2.00$ ‐$ Timberline Cold Patch Asphalt 0 SY 35.00$ ‐$ Timberline Horizontal Boring Under Roads 0 LF 1,900$ ‐$ Historical costs for similar projects Jacking Pits for Horizontal Boring 0 EA 105,000$ ‐$ Historical costs for similar projects Overhead Power Line (poles, conductors, conduit) 6,060 LF 75$ 454,500$ MII, From gas outlet to CPL buildings and to Skyview MS Concrete Pole Bases with Anchor Bolts 14 EA 3,500$ 49,000$ CIP Concrete columns with 1‐1/2" x 14" screw anchor bolts Piping from knockout to leachate collection 900 LF 18$ 16,200$ MII, 3" HDPE SDR 13.5 Leachate Collection Piping Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 900 LF 3.50$ 3,150$ MII Pipe Bedding Material, 9" 38 CY 35$ 1,330$ MII 1030 Prefabricated Buildings 97,340$ 6" Slab on Grade for Gen Set 0 SF 20$ ‐$ Timberline 12" Slab on Grade for Gen Set 500 SF 60$ 30,000$ Timberline Excavation for slab on grade 28 CY 105$ 2,940$ CalTrans, assume that excavated material can be used for daily cover at CPL Engine Generator Bldg, Prefabricated 480 SF 60$ 28,800$ MII: Two prefab buildings 20 x 25 Compressor Bldg, Prefabricated 100 SF 60$ 6,000$ MII: Prefab 10 x 10 CHP Equipment Bldg, Pre‐Engineered Metal 0 SF 130$ ‐$ Not needed since engine exhaust heat will be piped directly to evaporator Utility Fitout (electric, lighting, HVAC) 580 SF 20$ 11,600$ Timberline 6' Chain Link Fence with personnel and vehicle gates 240 LF 75$ 18,000$ MII 1040 Equipment 1,427,069$ Moisture Knockout Tank (100 Gal Expansion tank) 1 EA 5,040$ 5,040$ MII Greenhouse Gas (GHG) Monitoring Equipment 1 EA 11,105$ 11,105$ Vendor ‐ Equipco Services Natural Gas Metering Station 0 EA 79,000$ ‐$ US EPA LFGcost‐Web Retrofit Natural Gas Fired Boiler (Seamless Controls) 0 EA 150,115$ ‐$ US EPA LFGcost‐Web Generator Set (Cat CG132‐16) at CPL or Skyview MS 2 EA 524,700$ 1,049,400$ Vendor Quote, includes sales tax Generator Set (Cat C3306) at CPL or Skyview MS 0 EA 151,400$ ‐$ Vendor Quote for used. Added 40% factor for new gen set, includes sales tax Gen Set Transport Anchorage to Soldotna 2 EA 750$ 1,500$ Vendor Quote (Knight Flight Cargo Services) Generator Set Installation 2 EA 30,900$ 61,800$ MII Transformer at Client Facility (13.8 kV primary) 1 EA 64,400$ 64,400$ MII Switch Gear 1200 A, 13.8 kV, 750 MVA at Client Facility 1 EA 25,200$ 25,200$ MII Vent chimney for Engine Generator to evaporator 100 LF 140$ 14,000$ MII: Two each 50‐ft runs from each generator to evaporator Pipe Saddles (from Gen Set exhaust to evaporator) 9 EA 480$ 4,320$ MII Pipe Support Concrete Bases 18 EA 840$ 15,120$ MII Air compressor, electric, 5 HP (at CPL) 0 EA 9,380$ ‐$ MII Compressor Air Dryer, 10 SCFM 0 EA 1,680$ ‐$ MII Air compressor, 105 SCFM at 125 psi, 25 H.P. (at CPL) 0 EA 35,700$ ‐$ MII 221519105690 Compressor Air Dryer, 100 SCFM 2 EA 5,460$ 10,920$ MII Absorption water chiller, 440 ton 0 EA 588,825$ ‐$ For CHP, Ingersoll Rand Quote +20% for AK shipment. Installation costs from MII CHP Equipment Transport Anchorage to Soldotna 0 EA 5,000$ ‐$ Adjusted from Knight Flight Cargo Services quote. 440 Ton CHP Equipment Installation 0 EA 48,900$ ‐$ MII, 500 ton chiller 40‐Ton crane crew for loading/unloading CHP equipment 0 Days 5,540$ ‐$ MII 015419500300 Blower System, 163 SCFM, 15 HP, 15 psi 2 EA 19,320$ 38,640$ MII, one blower for each landfill cell SCADA System ‐ Host Computer 1 EA 18,375$ 18,375$ MII, 230923103282 SCADA System ‐ Software 1 EA 17,782$ 17,782$ Trihedral VT Scada US Pricing Sheet SCADA System Remote Terminal Units 4 EA 2,367$ 9,468$ Moxa ioPAC 8500‐9‐RJ45‐C‐T Startup & Testing 10 Days 8,000$ 80,000$ Estimated Quantity Subtotal 2,174,989$ 2,174,989$ 1050 Consultant and Subcontractor Fees 685,122$ Engineering Design Fee 1 PER 10.0% 217,499$ US EPA Allowance for Permitting 1 PER 7.5% 163,124$ US EPA Mobilization/Demobilization 1 PER 2.5% 54,375$ US EPA Construction Management 1 PER 5.0% 108,749$ US EPA Project Management 1 PER 5.0% 108,749$ US EPA Quality Control 1 PER 1.5% 32,625$ US EPA Subtotal 2,860,111$ 1060 Contingency, Bonds & Insurance 643,525$ Contingency 1 PER 20.0% 572,022$ Bonds & Insurance 1 PER 2.5% 71,503$ Total Construction Costs 3,503,636$ 1070 Operations & Maintenance Costs 347,580$ O&M Labor 730 HRS 150$ 109,500$ 2 hours/day, 365 Days/Year Engine Generator Repair & Maintenance 12,386,640 kWH 0.015$ 185,800$ M. Lopez Caterpillar Electric Power Presentation January 2012. Boiler O&M 0 LS 7,300$ ‐$ Estimator Judgement Compressor O&M 1 LS 10,800$ 10,800$ MII Transformer Inspection & Maintenance 26 EA 770$ 20,020$ MII, Assumes weekly inspections Pipeline inspection, 4"‐12" diameter 0 LF 15$ ‐$ MII, Assumes annual inspection Chiller O&M 2 LS 8,000$ 16,000$ Estimator Judgement Blower O&M 2 LS 2,730$ 5,460$ MII PRESENT VALUE ANALYSIS 5.0% Discount Rate Year Cost Type Cost Rate (5%) Present Value 2019 0 Capital Cost $3,503,636 1.00 $3,503,636 2020 1 O&M Year $347,580 0.95 $331,028 2021 2 O&M Year $347,580 0.91 $315,265 2022 3 O&M Year $347,580 0.86 $300,252 2023 4 O&M Year $347,580 0.82 $285,955 2024 5 O&M Year $347,580 0.78 $272,338 2025 6 O&M Year $347,580 0.75 $259,369 2026 7 O&M Year $347,580 0.71 $247,018 2027 8 O&M Year $347,580 0.68 $235,256 2028 9 O&M Year $347,580 0.64 $224,053 2029 10 O&M Year $347,580 0.61 $213,384 2030 11 O&M Year $347,580 0.58 $203,223 2031 12 O&M Year $347,580 0.56 $193,545 2032 13 O&M Year $347,580 0.53 $184,329 2033 14 O&M Year $347,580 0.51 $175,551 2034 15 O&M Year $347,580 0.48 $167,192 2035 16 O&M Year $347,580 0.46 $159,230 2036 17 O&M Year $347,580 0.44 $151,648 2037 18 O&M Year $347,580 0.42 $144,427 2038 19 O&M Year $347,580 0.40 $137,549 2039 20 O&M Year $347,580 0.38 $130,999 TOTAL PRESENT VALUE ANALYSIS $7,835,000 Notes: As the design is at conceptual stage, the tie‐ins to existing equipment and facilities have not being identified. Escalation is not included The budget is based on 2nd quarter 2016 rates for Soldotna, Alaska. These AACE Classification Class 5 cost estimates are assumed to represent the actual total installed cost within the range of ‐50 percent to +100 percent (% based on AACE) of the cost indicated. It would appear prudent that internal budget allowances account for the highest cost indicated by this range as well as other site specific allowances. The cost estimate has been prepared for guidance in project evaluation and implementation from the information available at the time of the estimate. The final costs of the project will depend on actual labor and material costs, competitive market conditions, implementation schedule, and other variable factors. As a result, the final project costs will vary from the estimates presented herein. Because of this, project feasibility and funding needs must be carefully reviewed prior to making specific financial decisions to help ensure proper project evaluation and adequate funding. KPB (3%) and Soldotna (3%) sales tax included in unit rates. Municipal fees & Licenses have been estimated as a percentage of the total direct costs Exclusions: Only limited equipment specifications have been identified. Kenai Peninsula Borough Landfill Gas Utilization 06/20/16 Alaska ACF Option 5 Remove CO2 and Trace Gases and Inject to ENSTAR Pipeline 217% Concept Screening Level Costs (AACE Level 5, Accuracy ‐50% ‐ +100%) Description Qty Unit Unit Total Subtotals Notes Cost Cost 1010 Preconstruction, Site Preparation 11,300$ Survey ‐ Building Sites (CPL) 0 Days 3,800$ ‐$ Initial survey and support during construction Survey ‐ Pipeline 1 Days 3,800$ 3,800$ Contractor Plans & Submittals 1 LS 7,500$ 7,500$ Estimated Quantity 1020 Site Work 140,385$ Clear & Grub with Chipping (1056 LF x 10 FT width) 0.25 Acres 7,000$ 1,750$ MII 4" Dia. HDPE SDR 11 Natural Gas Piping, below ground 1,056 LF 49$ 51,744$ MII, From gas outlet to Enstar Pipeline Pipe Saddles (from blower to compressor) 5 EA 480$ 2,400$ MII Pipe Support Concrete Bases 10 EA 840$ 8,400$ MII Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 1,056 LF 4$ 3,696$ MII Pipe Bedding Material, 10" 49 CY 35$ 1,715$ MII, standard practice is backfill around HDPE pipe with gravel. Saw Cut Asphalt 0 LF 2$ ‐$ Timberline Cold Patch Asphalt 0 SY 35$ ‐$ Timberline Horizontal Boring Under Roads 0 LF 1,900$ ‐$ Historical costs for similar projects Jacking Pits for Horizontal Boring 0 EA 105,000$ ‐$ Historical costs for similar projects Overhead Power Line (poles, conductors, conduit) 0 LF 75$ ‐$ 1.4 Miles Concrete Pole Bases with Anchor Bolts 0 EA 3,500$ ‐$ CIP Concrete columns with 1‐1/2" x 14" screw anchor bolts Piping from knockout to leachate collection 900 LF 18$ 16,200$ MII, 3" HDPE SDR 13.5 Leachate Collection Piping Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 900 LF 3.50$ 3,150$ MII Pipe Bedding Material, 9" 38 CY 35$ 1,330$ MII Pipeline Connection Fee 1 LS 50,000$ 50,000$ Estimator Judgement 1030 Prefabricated Buildings 26,000$ 6" Slab on Grade for Gen Set 0 SF 20$ ‐$ Timberline 12" Slab on Grade for Gen Set 0 SF 60$ ‐$ Timberline Excavation for slab on grade 0.0 CY 105$ ‐$ CalTrans, assume that excavated material can be used for daily cover at CPL Engine Generator Bldg, Prefabricated 0 SF 60$ ‐$ MII: Prefab 20 x 25 Compressor Bldg, Prefabricated 100 SF 60$ 6,000$ MII: Prefab 10 x 10 Utility Fitout (electric, lighting, HVAC) 100 SF 20$ 2,000$ Timberline 6' Chain Link Fence with personnel and vehicle gates 240 LF 75$ 18,000$ MII 1040 Equipment 333,305$ Moisture Knockout Tank (100 Gal Expansion tank) 1 EA 5,040$ 5,040$ MII Greenhouse Gas (GHG) Monitoring Equipment 1 EA 11,105$ 11,105$ Vendor ‐ Equipco Services Natural Gas Metering Station 1 EA 79,000$ 79,000$ US EPA LFGcost‐Web Retrofit Natural Gas Fired Boiler (Seamless Controls) 0 EA 150,115$ ‐$ US EPA LFGcost‐Web Generator Set (Cat CG132‐16) at CPL or Skyview MS 0 EA 524,700$ ‐$ Vendor Quote, includes sales tax Generator Set (Cat C3306) at CPL or Skyview MS 0 EA 151,400$ ‐$ Vendor Quote for used. Added 40% factor for new gen set, includes sales tax Gen Set Transport Anchorage to Soldotna 0 EA 750$ ‐$ Vendor Quote (Knight Flight Cargo Services) Generator Set Installation 0 EA 30,900$ ‐$ MII Transformer at Client Facility (13.8 kV primary) 0 EA 64,400$ ‐$ MII Switch Gear 1200 A, 13.8 kV, 750 MVA at Client Facility 0 EA 25,200$ ‐$ MII Vent chimney for Engine Generator 0 LF 140$ ‐$ MII Air compressor, 105 SCFM at 125 psi, 25 H.P. (at CPL) 1 EA 35,700$ 35,700$ MII 221519105690 Compressor Air Dryer, 100 SCFM 1 EA 5,460$ 5,460$ MII Absorption water chiller, 10 ton 1 EA 46,400$ 46,400$ MII 236413133270 Absorption water chiller, 440 ton 0 EA 714,000$ ‐$ MII Landfill gas and leachate control systems, gas scrubber, 750 CFM 1 EA 71,960$ 71,960$ MII, Adjusted based on costs for 1500 to 7700 CFM scrubbers Landfill gas and leachate control systems, gas scrubber, 7700 CFM 0 EA 196,000$ ‐$ MII Blower System, 163 SCFM, 15 HP, 15 psi 2 EA 19,320$ 38,640$ MII, one blower for each landfill cell Startup & Testing 5 Days 8,000$ 40,000$ Estimated Quantity Subtotal 510,990$ 510,990$ 1050 Consultant and Subcontractor Fees 160,962$ Engineering Design Fee 1 PER 10.0% 51,099$ US EPA Allowance for Permitting 1 PER 7.5% 38,324$ US EPA Mobilization/Demobilization 1 PER 2.5% 12,775$ US EPA Construction Management 1 PER 5.0% 25,550$ US EPA Project Management 1 PER 5.0% 25,550$ US EPA Quality Control 1 PER 1.5% 7,665$ US EPA Subtotal 671,952$ 1060 Contingency, Bonds & Insurance 151,189$ Contingency 1 PER 20.0% 134,390$ Bonds & Insurance 1 PER 2.5% 16,799$ Total Construction Costs 823,141$ 1070 Operations & Maintenance Costs 247,500$ O&M Labor 1,460 HRS 150$ 219,000$ 4 hours/day, 365 Days/Year Engine Generator Repair & Maintenance 0 kWH 0.015$ ‐$ M. Lopez Caterpillar Electric Power Presentation January 2012 Boiler O&M 0 LS 7,300$ ‐$ Estimator Judgement Compressor O&M 1 LS 7,200$ 7,200$ MII Transformer Inspection & Maintenance 0 EA 770$ ‐$ MII, Assumes weekly inspections Pipeline inspection, 4"‐12" diameter 1,056 LF 15$ 15,840$ MII, Assumes annual inspection Blower O&M 2 LS 2,730$ 5,460$ MII PRESENT VALUE ANALYSIS 5.0% Discount Rate Year Cost Type Cost Rate (5%) Present Value 0 Capital Cost $823,141 1.00 $823,141 1 O&M Year $247,500 0.95 $235,714 2 O&M Year $247,500 0.91 $224,490 3 O&M Year $247,500 0.86 $213,800 4 O&M Year $247,500 0.82 $203,619 5 O&M Year $247,500 0.78 $193,923 6 O&M Year $247,500 0.75 $184,688 7 O&M Year $247,500 0.71 $175,894 8 O&M Year $247,500 0.68 $167,518 9 O&M Year $247,500 0.64 $159,541 10 O&M Year $247,500 0.61 $151,944 11 O&M Year $247,500 0.58 $144,708 12 O&M Year $247,500 0.56 $137,817 13 O&M Year $247,500 0.53 $131,255 14 O&M Year $247,500 0.51 $125,004 15 O&M Year $247,500 0.48 $119,052 16 O&M Year $247,500 0.46 $113,383 17 O&M Year $247,500 0.44 $107,983 18 O&M Year $247,500 0.42 $102,841 19 O&M Year $247,500 0.40 $97,944 20 O&M Year $247,500 0.38 $93,280 TOTAL PRESENT VALUE ANALYSIS $3,908,000 Notes: As the design is at conceptual stage, the tie‐ins to existing equipment and facilities have not being identified. Escalation is not included The budget is based on 2nd quarter 2016 rates for Soldotna, Alaska. These AACE Classification Class 5 cost estimates are assumed to represent the actual total installed cost within the range of ‐50 percent to +100 percent (% based on AACE) of the cost indicated. It would appear prudent that internal budget allowances account for the highest cost indicated by this range as well as other site specific allowances. The cost estimate has been prepared for guidance in project evaluation and implementation from the information available at the time of the estimate. The final costs of the project will depend on actual labor and material costs, competitive market conditions, implementation schedule, and other variable factors. As a result, the final project costs will vary from the estimates presented herein. Because of this, project feasibility and funding needs must be carefully reviewed prior to making specific financial decisions to help ensure proper project evaluation and adequate funding. KPB (3%) and Soldotna (3%) sales tax included in unit rates. Municipal fees & Licenses have been estimated as a percentage of the total direct costs Exclusions: Only limited equipment specifications have been identified. Kenai Peninsula Borough Landfill Gas Utilization 06/20/16 Alaska ACF Option 6b Transport to CPL Buildings and Offsite in Pipeline to Generator Set at 217% Skyview MS Concept Screening Level Costs (AACE Level 5, Accuracy ‐50% ‐ +100%) Description Qty Unit Unit Total Subtotals Notes Cost Cost 1010 Preconstruction, Site Preparation 47,900$ Survey ‐ Building Sites (Skyview MS) 1 Days 3,800$ 3,800$ Initial survey and support during construction Survey ‐ Natural Gas Piping Path 7 Days 3,800$ 26,600$ Contractor Design Plans & Submittals 1 LS 17,500$ 17,500$ Estimated Quantity 1020 Site Work 1,346,865$ Clear & Grub with Chipping (3,170 LF x 10 FT width) 0.73 Acres 7,000$ 5,110$ MII, Not all of the proposed path needs to be cleared. 6" Dia. HDPE SDR 11 Natural Gas Piping, below ground 6,960 LF 57$ 396,720$ MII, From gas outlet to CPL buildings and to Skyview MS Pipe Saddles (from blower to compressor) 5 EA 480$ 2,400$ MII Pipe Support Concrete Bases 10 EA 840$ 8,400$ MII Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 6,960 LF 3.50$ 24,360$ MII Pipe Bedding Material, 12" 387 CY 35$ 13,545$ MII, standard practice is backfill around HDPE pipe with gravel. Saw Cut Asphalt 45 LF 2.00$ 90$ Timberline Cold Patch Asphalt 16 SY 35.00$ 560$ Timberline Horizontal Boring Under Roads 350 LF 1,900$ 665,000$ Historical costs for similar projects Jacking Pits for Horizontal Boring 2 EA 105,000$ 210,000$ Historical costs for similar projects Piping from knockout to leachate collection 900 LF 18$ 16,200$ MII, 3" HDPE SDR 13.5 Leachate Collection Piping Chain Trencher Excavation for NG Piping, 18" Width, up to 6' Depth 900 LF 3.50$ 3,150$ MII Pipe Bedding Material, 9" 38 CY 35$ 1,330$ MII 1030 Prefabricated Buildings 98,940$ 6" Slab on Grade for Gen Set 0 SF 20$ ‐$ Timberline 12" Slab on Grade for Gen Set 500 SF 60$ 30,000$ Timberline Excavation for slab on grade 28 CY 105$ 2,940$ CalTrans, assume that excavated material can be used for daily cover at CPL Engine Generator Bldg, Prefabricated 500 SF 60$ 30,000$ MII: Two prefab buildings 20 x 25 Compressor Bldg, Prefabricated 100 SF 60$ 6,000$ MII: Prefab 10 x 10 Utility Fitout (electric, lighting, HVAC) 600 SF 20$ 12,000$ Timberline 6' Chain Link Fence with personnel and vehicle gates 240 LF 75$ 18,000$ MII 1040 Equipment 1,439,205$ Moisture Knockout Tank (100 Gal Expansion tank) 1 EA 5,040$ 5,040$ MII Greenhouse Gas (GHG) Monitoring Equipment 1 EA 11,105$ 11,105$ Vendor ‐ Equipco Services Natural Gas Metering Station 0 EA 79,000$ ‐$ US EPA LFGcost‐Web Retrofit Natural Gas Fired Boiler (Seamless Controls) 0 EA 150,115$ ‐$ US EPA LFGcost‐Web Generator Set (Cat CG132‐16) at CPL or Skyview MS 2 EA 524,700$ 1,049,400$ Vendor Quote, includes sales tax Generator Set (Cat C3306) at CPL or Skyview MS 0 EA 151,400$ ‐$ Vendor Quote for used. Added 40% factor for new gen set, includes sales tax Gen Set Transport Anchorage to Soldotna 2 EA 750$ 1,500$ Vendor Quote (Knight Flight Cargo Services) Generator Set Installation 2 EA 30,900$ 61,800$ MII Transformer at Client Facility (13.8 kV primary) 1 EA 64,400$ 64,400$ MII Switch Gear 1200 A, 13.8 kV, 750 MVA at Client Facility 1 EA 25,200$ 25,200$ MII Vent chimney for Engine Generator 25 LF 140$ 3,500$ MII Air compressor, electric, 5 HP (at CPL) 1 EA 9,380$ 9,380$ MII Compressor Air Dryer, 10 SCFM 1 EA 1,680$ 1,680$ MII Air compressor, 105 SCFM at 125 psi, 25 H.P. (at CPL) 1 EA 35,700$ 35,700$ MII 221519105690 Compressor Air Dryer, 100 SCFM 1 EA 5,460$ 5,460$ MII Absorption water chiller, 10 ton 1 EA 46,400$ 46,400$ MII 236413133270 Blower System, 163 SCFM, 15 HP, 15 psi 2 EA 19,320$ 38,640$ MII, one blower for each landfill cell Startup & Testing 10 Days 8,000$ 80,000$ Estimated Quantity Subtotal 2,932,910$ 2,932,910$ 1050 Consultant and Subcontractor Fees 923,867$ Engineering Design Fee 1 PER 10.0% 293,291$ US EPA Allowance for Permitting 1 PER 7.5% 219,968$ US EPA Mobilization/Demobilization 1 PER 2.5% 73,323$ US EPA Construction Management 1 PER 5.0% 146,646$ US EPA Project Management 1 PER 5.0% 146,646$ US EPA Quality Control 1 PER 1.5% 43,994$ US EPA Subtotal 3,856,777$ 1060 Contingency, Bonds & Insurance 867,775$ Contingency 1 PER 20.0% 771,355$ Bonds & Insurance 1 PER 2.5% 96,419$ Total Construction Costs 4,724,551$ 1070 Operations & Maintenance Costs 440,960$ O&M Labor 730 HRS 150$ 109,500$ 2 hours/day, 365 Days/Year Engine Generator Repair & Maintenance 12,386,640 kWH 0.015$ 185,800$ M. Lopez Caterpillar Electric Power Presentation January 2012. Boiler O&M 0 LS 7,300$ ‐$ Estimator Judgement Compressor O&M 1 LS 7,200$ 7,200$ MII Transformer Inspection & Maintenance 52 EA 550$ 28,600$ MII, Assumes weekly inspections Pipeline inspection, 4"‐12" diameter 6,960 LF 15$ 104,400$ MII, Assumes annual inspection Blower O&M 2 LS 2,730$ 5,460$ MII PRESENT VALUE ANALYSIS 5.0% Discount Rate Year Cost Type Cost Rate (5%) Present Value 2019 0 Capital Cost $4,724,551 1.00 $4,724,551 2020 1 O&M Year $440,960 0.95 $419,962 2021 2 O&M Year $440,960 0.91 $399,963 2022 3 O&M Year $440,960 0.86 $380,917 2023 4 O&M Year $440,960 0.82 $362,779 2024 5 O&M Year $440,960 0.78 $345,503 2025 6 O&M Year $440,960 0.75 $329,051 2026 7 O&M Year $440,960 0.71 $313,382 2027 8 O&M Year $440,960 0.68 $298,459 2028 9 O&M Year $440,960 0.64 $284,246 2029 10 O&M Year $440,960 0.61 $270,711 2030 11 O&M Year $440,960 0.58 $257,820 2031 12 O&M Year $440,960 0.56 $245,543 2032 13 O&M Year $440,960 0.53 $233,850 2033 14 O&M Year $440,960 0.51 $222,715 2034 15 O&M Year $440,960 0.48 $212,109 2035 16 O&M Year $440,960 0.46 $202,009 2036 17 O&M Year $440,960 0.44 $192,389 2037 18 O&M Year $440,960 0.42 $183,228 2038 19 O&M Year $440,960 0.40 $174,503 2039 20 O&M Year $440,960 0.38 $166,193 TOTAL PRESENT VALUE ANALYSIS $10,220,000 Notes: As the design is at conceptual stage, the tie‐ins to existing equipment and facilities have not being identified. Escalation is not included Exclusions: Only limited equipment specifications have been identified. Municipal fees & Licenses have been estimated as a percentage of the total direct costs The budget is based on 2nd quarter 2016 rates for Soldotna, Alaska. These AACE Classification Class 5 cost estimates are assumed to represent the actual total installed cost within the range of ‐50 percent to +100 percent (% based on AACE) of the cost indicated. It would appear prudent that internal budget allowances account for the highest cost indicated by this range as well as other site specific allowances. The cost estimate has been prepared for guidance in project evaluation and implementation from the information available at the time of the estimate. The final costs of the project will depend on actual labor and material costs, competitive market conditions, implementation schedule, and other variable factors. As a result, the final project costs will vary from the estimates presented herein. Because of this, project feasibility and funding needs must be carefully reviewed prior to making specific financial decisions to help ensure proper project evaluation and adequate funding. KPB (3%) and Soldotna (3%) sales tax included in unit rates. AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment I: HDR CPL Landfill Gas Management Plan Landfill Gas Management Plan Central Peninsula Landfill Soldotna, Alaska November 2010 Prepared for: Kenai Peninsula Borough Solid Waste Department 47140 East Poppy Lane Soldotna, Alaska 99669 Prepared by: HDR Alaska, Inc. 2525 C Street, Suite 305 Anchorage, Alaska 99503‐2632 (907) 644‐2000 HDR Project Number: 138724 Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan i HDR Alaska, Inc. TABLE OF CONTENTS 1. Introduction ........................................................................................................................................................... 1 2. Site Background and Operations ........................................................................................................................... 1 2.1 Closed Unlined Landfill ................................................................................................................................. 2 2.2 Lined Landfill ................................................................................................................................................ 2 3. Air Regulatory Status ............................................................................................................................................. 3 3.1 Greenhouse Gas Management Rule (40 CFR 98 Subpart HHH) ................................................................... 4 3.1.1 CPL Status – GHG Rule ............................................................................................................................. 4 3.2 New Source Performance Standards (NSPS, 40 CFR 60 Subpart WWW) ..................................................... 4 3.2.1 CPL Status ‐ NSPS ..................................................................................................................................... 5 3.3 Title V Permit ................................................................................................................................................ 6 3.3.1 CPL Status – Title V Applicability .............................................................................................................. 6 3.4 National Emission Standards for Hazardous Air Pollutants (NESHAP, 40 CFR 63 Subpart AAAA) ................ 6 3.5 Asbestos Disturbance Notification ............................................................................................................... 6 3.6 SSM Plan ....................................................................................................................................................... 7 3.7 Air Quality Construction Permit ................................................................................................................... 7 3.8 Flare Station Performance Test .................................................................................................................... 7 3.9 ADEC Meeting .............................................................................................................................................. 7 4. Landfill Gas Collection and Control System Plan ................................................................................................... 7 4.1 Design Variables ........................................................................................................................................... 7 4.1.1 Depth of Refuse – Lined Landfill .............................................................................................................. 8 4.1.2 Final Cover System ‐ Lined Landfill .......................................................................................................... 8 4.1.3 Waste Density ‐ Lined Landfill .................................................................................................................. 8 4.2 Landfill Gas Collection and Control System Calculations and Design Methodology .................................... 8 4.2.1 Site‐Specific Design Considerations ......................................................................................................... 9 4.2.2 Landfill Gas Generation Calculations ....................................................................................................... 9 4.2.3 Landfill Gas Collection Techniques ........................................................................................................ 11 4.2.4 Well Placement and Radius of Influence Calculations ........................................................................... 12 4.2.5 Landfill Gas Collection System Layout ................................................................................................... 13 4.2.6 Collection Pipe Sizing ............................................................................................................................. 14 4.2.7 Condensate Management ..................................................................................................................... 15 5. Gas Mover and Control Devices .......................................................................................................................... 16 5.1 Gas Mover Equipment ............................................................................................................................... 16 5.2 Control Devices – Flares ............................................................................................................................. 16 Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan ii HDR Alaska, Inc. 5.2.1 Enclosed Flares ...................................................................................................................................... 17 5.2.2 Candlestick Flares .................................................................................................................................. 17 5.2.3 Flare Recommendation .......................................................................................................................... 18 6. Landfill Gas End‐Use Opportunities ..................................................................................................................... 18 6.1 Landfill Gas to Energy ................................................................................................................................. 19 6.1.1 LFGTE Feasibility Study .......................................................................................................................... 20 6.2 Direct Use Options ..................................................................................................................................... 21 6.2.1 Potential Direct Use Recipients ............................................................................................................. 23 7. Landfill Gas Credits, Incentives and Bonds .......................................................................................................... 23 7.1 Renewable Energy Credits ......................................................................................................................... 23 7.2 Carbon Credits ............................................................................................................................................ 24 7.3 Clean Renewable Energy Bonds ................................................................................................................. 26 7.4 Federal Production Tax Credits .................................................................................................................. 27 7.5 Alaska Renewable Energy Grants ............................................................................................................... 27 8. Conclusions and Recommendations .................................................................................................................... 28 8.1 Site Background and Operations ................................................................................................................ 28 8.2 Air Regulatory Status .................................................................................................................................. 28 8.3 Conceptual Landfill Gas Collection and Control Plan ................................................................................. 29 8.4 Landfill Gas End‐Use Opportunities ........................................................................................................... 30 8.5 Landfill Gas Credits, Incentives and Bonds ................................................................................................. 30 8.6 Proposed Timeline for Schedule of Activities ............................................................................................. 31 TABLES Table 1 Design Capacity Estimate for the Central Peninsula Landfill Table 2 Vertical Gas Extraction Well Schedule for the Lined Landfill ATTACHMENTS Attachment A Conceptual Design Drawings Attachment B LandGEM Modeling Results for the Unlined Landfill Attachment C LandGEM Modeling Results for the Lined Landfill Attachment D Radius of Influence Calculations Attachment E Pipe2010 Modeling Results for the Gas Collection System Attachment F Condensate Generation Calculations Attachment G LANDTEC’s Landfill Automated Pump Station Attachment H Fen-Tech Environmental, Inc.’s 150 GPH Evap-O-Dry Evaporation System Attachment I Technical Specification Outline Attachment J Engineer’s Estimate of Probable Cost Attachment K Proposed Timeline for Schedule of Activities Kenai Peninsula Borough - CPL 1 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. 1. INTRODUCTION This Landfill Gas Management Plan (LFGMP) was prepared by HDR Alaska, Inc. (HDR) for the Kenai Peninsula Borough (Borough) Central Peninsula Landfill (CPL), and was tasked under the Design Development Phase of the contract resulting from Borough RFP 10-007. The purpose of this LFGMP is to provide the Borough with a plan for landfill gas management at the CPL that complies with, or will lead to compliance with, applicable State and Federal regulations. The LFGMP is organized into the following sections: 1. Introduction 2. Site Background and Operations 3. Air Regulatory Status 4. Landfill Gas Collection and Control System Plan 5. Gas Mover and Control Devices 6. Landfill Gas End Use Opportunities 7. Landfill Gas Credits, Incentives and Bonds 8. Conclusions and Recommendations 2. SITE BACKGROUND AND OPERATIONS The CPL is a Class I landfill under Alaska Department of Environmental Conservation (ADEC) Solid Waste Regulations (18 AAC 60), owned and operated by the Kenai Peninsula Borough. Sheet LFG-01 in Attachment A shows the layout of the CPL, which consists of four solid waste disposal units: (1) the closed unlined landfill; (2) the active lined landfill; (3) the C&D disposal area; and (4) the asbestos disposal area. The C&D disposal area is east of and abuts the closed unlined landfill. The asbestos disposal area is located north of the lined landfill. The CPL also serves as a center for recycling operations and special waste collection for the Borough. The CPL is located approximately 2.5 miles south of Soldotna, Alaska, at milepost 98.5 of the Sterling Highway, within Section 12 and 13 of Township 4 North, Range 11 West of the Seward Meridian. The CPL accepts waste from public and commercial entities, and hauls waste from four manned transfer stations in Kenai, Nikiski, Sterling and Seward. Additionally, waste is collected from eight unmanned transfer sites. When the Homer Landfill ceases to accept municipal solid waste (MSW), a transfer facility will be constructed and approximately 5,000 tons per year of Homer area MSW will be hauled to the CPL. Borough employees noted that construction and demolition (C&D) debris waste originating from transfer sites is recorded as MSW and disposed in the active Class I disposal site and accounts for approximately less than 25% of the total MSW accepted at the CPL. In the future, the Borough plans to investigate treating leachate using constructed wetlands in addition to the current leachate recirculation and off-site disposal operations. The CPL conducts leachate recirculation in accordance with their Research, Development and Demonstration (RD&D) project under ADEC Permit No. SWRDD002. The RD&D permit is approved for a period up to three years and may be renewed, with a maximum of three renewals allowed, for a total potential duration of 12 years. The current permit was issued on March 6, 2008 and expires on March 6, 2011. Kenai Peninsula Borough - CPL 2 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. 2.1 Closed Unlined Landfill The closed unlined landfill began operation in 1969 and continued accepting waste until final closure in 2007. The closed unlined landfill contains a mixture of MSW and other assorted wastes including C&D debris. Historical records indicating areas of separation between MSW and non MSW are not available, including areas that may have received asbestos. The unlined landfill received non-baled waste and daily cover from 1969 to June 1992. The CPL began baling operations in July 1992 and disposed of baled waste in the unlined landfill until its closure. C&D waste entering the unlined landfill was tracked separately from MSW beginning in 2001. Final closure of the unlined landfill was completed in September 2007. The closed unlined landfill is not planned for future disposal or other uses beyond using the top of the landfill as a recycling material processing area and possibly temporary emergency debris storage. Twelve passive LFG vents were installed during closure of the unlined landfill in 2007. These twelve vents are the surface outlets for an extensive piping network constructed of perforated pipe within the sub-grade layer in the final cover system. Four of the passive vents were sampled using a LandTec GEM- 2000 at the closed unlined landfill on April 12, 2010 by HDR as part of the Baseline Assessment site investigation. The Baseline Assessment sampling results indicate high quality landfill gas. These results may indicate that the cover system is providing adequate gas containment with low atmospheric intrusion. Borough employees noted that the unlined landfill area has settled since the final cover was installed (which may indicate active biodegradation of the waste mass), and there have been no instances of odor or distressed vegetation. Although sample results indicate high methane concentrations, the passive gas system was not designed or intended to become part of an active landfill gas system. 2.2 Lined Landfill The original lined landfill master plan included four landfill cells; however, the design was modified to expand the number of cells to five within the same overall footprint. Closure plans for the lined landfill consist of interim closure of cells until they reach final grade. When a cell reaches final grade, the Borough plans to cap the cell with a final cover system. Therefore, final closure of the lined landfill will proceed in phases with the partial final closure of each cell. Construction of Cell 1 was completed in October 2005. The 9.3-acre cell includes a composite liner system, leachate collection system, a leachate recirculation system, a leachate storage lagoon and tank, a stormwater collection and sedimentation basin, and a mechanical/pump building. Cell 1 began accepting MSW on a limited basis in 2006, and continued until the unlined landfill was closed in September 2007 when all MSW was directed to Cell 1 for disposal. At the same time, the CPL baler operation was shut down except for recyclables. Cell 1 currently accepts waste from approximately 75% of the Borough’s population. The Borough completed design of Cell 2 in June 2010. Construction is scheduled for 2011 and disposal operations are scheduled to begin in 2012. It is anticipated that ADEC will issue a permit modification to authorize Cell 2 construction following their review of the design. Borough facility operators are currently placing MSW in Lift 3 of 6 in Cell 1, approximately 30 feet above the base of Cell 1. Waste is compacted in place, using a landfill compactor at the working face. The landfill typically uses silty sand, stockpiled during Cell 1 excavations, for daily cover; however, alternative daily cover including temporary tarps, blast sand and other soils are also used. Kenai Peninsula Borough - CPL 3 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Recirculation into the waste mass is currently the primary means of leachate treatment. Leachate is recirculated through both surface application on new and old waste and injection into the waste mass via a network of horizontal perforated pipes. Leachate recirculation pipes are currently installed in Lift 2 at 75- foot lateral spacing. Additional leachate recirculation lines are planned to be installed in Lifts 4 and 6. The Borough has installed three piezometers within Cell 1 to measure the head of liquid on the liner. Head on the liner has consistently been measured at zero feet. Borough employees have not noted operational issues with the leachate recirculation system except for the freezing of the injection piping during the winter months. The Borough occasionally transports leachate off-site to the City of Kenai wastewater treatment plant as an additional management option. A summary of the leachate recirculation activities can be found in the semiannual reports that are submitted to ADEC. Sheet LFG-02 illustrates the existing LFG collection system installed at the lined landfill. Four horizontal gas collection wells were installed by Borough employees in Lift 2 approximately 22 feet above the base of Cell 1. These wells consist of 40-foot lengths of alternating 8” diameter solid HDPE and 12” diameter solid HDPE, with a 4-foot overlap at each intersection of the alternating diameter piping. The LFG wells were installed in the same trench as the leachate recirculation piping, approximately 2 feet above the recirculation pipes. A perimeter gas header pipe was also installed during construction of Cell 1. This 6” diameter HDPE header pipe is co-located with a recirculation header line, outside the lined landfill area. The header contains fourteen landfill gas connection vaults. These vaults were designed to allow future connection of horizontal extraction wells and other proposed collection system components to the header line, without the need for excavation of the header line. At each vault, a 2 inch diameter tee was stubbed out to connect to LFG wells. At the request of HDR, CPL operators sealed the ends of the horizontal gas collection wells a day before the Baseline Assessment site visit on April 12, 2010 to allow landfill gas to potentially accumulate in the piping system. HDR measured gas quality in the Cell 1 wells utilizing a LandTec GEM-2000 to assess the wells’ future viability as active landfill gas collection system components. The integrity of the horizontal collection pipes was assessed by investigating the quality of the gas extracted from the wells at the time of the site investigation. The quality of landfill gas measured from the Cell 1 vents is poor as indicated by the low methane concentrations in five of the six horizontal collection well sampling points. HDR believes that this may be due in part to issues associated with design and construction of the extraction wells. Typical horizontal extraction wells use perforated piping as the primary collection system, which allows for equal distribution of a vacuum through the length of the extraction well. Other potential causes of the low methane readings may include: (1) none of the landfill area has been completed with a low permeability closure system, so LFG is likely being emitted freely through the surface; (2) the waste may be saturated with liquid from leachate recirculation; (3) the waste may still be degrading through aerobic conditions (and thus not into the methane production stage of degradation); or (4) the low temperatures in the waste mass may be slowing the methane production rate. 3. AIR REGULATORY STATUS The United States Environmental Protection Agency has developed several regulatory documents that affect municipal solid waste disposal facilities. In particular, LFG is currently regulated by three separate regulations that set limits of emissions, operational standards, and other regulatory requirements that landfills must meet. These regulations include the Greenhouse Gas Management Rule, the New Source Kenai Peninsula Borough - CPL 4 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Performance Standards, and the National Emissions Standards for Hazardous Air Pollutants. Descriptions of these regulations, and CPL’s current status under the regulations, follow. 3.1 Greenhouse Gas Management Rule (40 CFR 98 Subpart HHH) Under the Environmental Protection Agency’s Mandatory Greenhouse Gas Reporting Rule (GHG Rule) owners or operators of landfills that accepted MSW on or after January 1, 1980 and that generate methane in amounts equal to or greater than 25,000 metric tons of carbon dioxide equivalent (CO2e) must report GHG emissions. A copy of this plan and all revisions and addenda are required to be kept on file at the facility. 3.1.1 CPL Status – GHG Rule Based on a preliminary assessment of waste accepted at the CPL, the GHG Rule applies to the CPL. In May, 2010, HDR developed a site specific Greenhouse Gas Monitoring Plan for the CPL. Annual reporting of GHG emissions will commence with the 2010 calendar year, and the first report is due on March 31, 2011. If the Borough chooses to move forward with a LFGCCS at the CPL, annual GHG emission reporting will also include reporting of methane collected and destroyed by the system per 40 CFR 98.342(b). Likewise, if the Borough chooses to move forward with a landfill gas to electricity (LFGTE) project, annual GHG emission reporting will include reporting of GHG emissions from stationary fuel combustion sources (e.g., boilers, simple and combined-cycle combustion turbines, engines, process heaters, etc.) per 40 CFR 98.342(c). 3.2 New Source Performance Standards (NSPS, 40 CFR 60 Subpart WWW) On March 12, 1996, the EPA promulgated the New Source Performance Standards (NSPS) and Emissions Guidelines (EG) for new and existing landfills under Section III (b) of the Clean Air Act (CAA). The basis for this legislation was the EPA’s determination that MSW landfills generate a significant quantity of air pollution that is potentially detrimental to public health. The NSPS are intended to control non-methane organic compounds (NMOC) and methane emissions from MSW landfills. NMOC’s include VOC, hazardous air pollutants (HAPs), and odorous compounds. The rules include provisions for “existing” and “new” landfills. The EG applies to existing landfills that were permitted prior to May 30, 1991 and have not been modified or reconstructed since that date. The NSPS applies to new landfills that were permitted, modified, or reconstructed on or after May 30, 1991. The ADEC chose not to implement the NSPS rules for existing landfills, and so the requirements of that regulation are implemented under the Federal Implementation Plan at 40 CFR Part 62, Subpart GGG. The provisions for new landfills are implemented by the ADEC under 18 AAC 50.040(a)(2)(II). A design capacity report is required for landfills to determine if they surpass the thresholds of 2.5 million megagrams (Mg) and/or 2.5 million cubic meters of MSW. The CPL as it existed on March 12, 1996 was an “existing” landfill as defined by the rules. Based on the development of the rules in the State of Alaska, submittal of the initial design capacity report for the CPL would have been due by April 5, 2000 if the landfill had still been classified as an “existing” landfill on that date. Construction of Cell 1 of the lined landfill was completed in 2005 and the cell began accepting MSW in 2006. The CPL had 90 days from the start of Cell 1 construction on May 14, 2004 to submit an updated design capacity report to be in compliance with air regulations for “new” landfills. Based on HDR’s review of historical CPL documents and interviews with facility operators, initial and updated design capacity reports have not been submitted to the ADEC. Based on these findings, HDR recommended that the CPL complete a Kenai Peninsula Borough - CPL 5 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. design capacity report to determine if the landfill has a design capacity equal to or greater than 2.5 million Mg and 2.5 million cubic meters. 3.2.1 CPL Status - NSPS At the request of the Borough, HDR prepared a draft Design Capacity Report for the CPL in July 2010 to determine if the landfill has exceeded the design capacity regulatory thresholds. This report includes calculation of the design capacity of the closed unlined landfill, and Cells 1 and 2 of the lined landfill. The design capacity calculations demonstrate that the CPL has not exceeded the 2.5 million cubic meter and 2.5 million Mg regulatory thresholds. The Borough plans to submit this finalized report to the ADEC within 90 days following issuance of the Cell 2 Construction permit. Based on the results of the draft Design Capacity Report, the CPL is not in violation of NSPS regulations other than not meeting the submittal deadlines for the initial and Cell 1 updated design capacity reports. Per 40 CFR 60.757(a)(3), an amended design capacity report is to be submitted to the ADEC providing notification of an increase in design capacity of the CPL, within 90 days of an increase in the maximum design capacity of the landfill to or above 2.5 million Mg and 2.5 million cubic meters. This design capacity increase could be attributed to an increase in the permitted volume of the landfill (e.g., Cells 3-5 of the lined landfill) and/or an increase in density as documented in the annual recalculation required by 40 CFR 60.758(f). The annual recalculation requires the Borough keep readily accessible, on-site records of the annual recalculation of site-specific density, design capacity, and the supporting documentation used to convert design capacity from volume to mass or mass to volume to demonstrate that the landfill’s design capacity is less than the regulatory thresholds. Off-site records may be maintained in lieu of on- site records if they are retrievable within 4 hours, and can be in either paper copy or electronic format. As shown in Table 1, the CPL’s design capacity is not forecasted to exceed regulatory thresholds until the Cell 5 expansion is permitted. The Borough should use the annual recalculation required by 40 CFR 60.758(f) to monitor the CPL’s design capacity status. HDR chose a conservative site-specific waste density of 1,200 pounds of waste per cubic yards of total volume for design capacity estimates. This value is based on Table 1 of the CPL’s RD&D Project 2009 Semi-Annual Report (July 1, 2009 – December 31, 2009) for years with leachate recirculation in Cell 1. HDR assumed leachate recirculation will also occur in Cells 2 through 5. Therefore, the average waste density used for Cells 2 through 5 is higher than CH2M-Hill’s Schematic-Design Basis Report average waste density estimate of 1,100. If the design capacity of the CPL surpasses the regulatory thresholds, the Borough is required to apply for a Title V permit within 12 months after becoming subject to the requirement to obtain such a permit [per 18 AAC 50.326(c)]. This deadline, according to 40 CFR 60.752(c)(2), applies regardless of when the design capacity report is submitted. In addition, the Borough is required to complete a Tier 1 NMOC report [40 CFR 60.754] within 90 days to estimate NMOC emissions at the CPL. The Tier 1 NMOC emission rate report is to contain an annual or 5-year estimate of NMOC emissions, and is to be submitted to the ADEC initially and annually thereafter if the estimated NMOC emission rate is less than 50 Mg per year. If the initial estimate of NMOC emissions is less than 50 Mg per year for the next 5 consecutive years, the Borough may elect to submit an estimate of the NMOC emission rate for the next 5-year period in lieu of annual reporting. The estimate is to include the actual amount of solid waste in-place and an estimated waste projection for the next 5 years, from which NMOC emission rate is estimated. If at any time during the 5-year period actual waste acceptance rate exceed the estimate waste projections contained in the 5-year estimate, the Borough is to submit a revised 5-year estimate to the Kenai Peninsula Borough - CPL 6 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. ADEC. This revised estimate will start on the year that the actual waste acceptance rate exceeded the estimated waste acceptance rate. If Tier 1 testing indicates a NMOC emission rate equal to or greater than 50 Mg per year, the Borough can elect to either: (1) submit a design plan for a LFGCCS, prepared by a professional engineer, to the ADEC within one-year [40 CFR 60.752(b)(2)(i)] and install the system within 30-months [40 CFR 60.752(b)(2)(ii)]; or (2) recalculate the NMOC emission rate using Tier 2 testing [40 CFR 60.754(a)(3)] within 180 days, or using Tier 3 testing [40 CFR 60.754(a)(4)] within one year. The LFGCCS plan documents how a specific facility (NSPS site) will comply with NSPS regulations. A LFGCCS plan outlines the methodology that will be employed to design a LFG management system that will collect, transport and dispose of LFG generated in the entire permitted landfill at final grades. Tier 2 testing consists of extracting landfill gas samples from various locations on the landfill (two samples per hectare from waste older than two years, the maximum number of samples needed is 50). The samples are sent to a laboratory for analysis to determine a site-specific NMOC concentration for use in calculating the NMOC emission rate. If the resulting NMOC emission rate is less than 50 Mg per year, annual reporting should resume until such time that the NMOC emission rate is equal to or greater than 50 Mg per year or the landfill is closed. If Tier 2 NMOC emission rate is equal to or greater than 50 Mg per year, the Borough can determine a site-specific methane generation rate constant (k) using Tier 3 testing to recalculate the NMOC emission rate, or proceed forward with the design and installation of a LFGCCS. Tier 3 testing is typically not performed due to the excessive cost of the testing. 3.3 Title V Permit Air regulations require that any landfill with a design capacity equal to or greater than 2.5 million Mg and 2.5 million cubic meters of MSW must apply for a Part 70 (also known as Title V) air quality operating permit. These landfills are deemed NSPS sites. In Alaska, Title V permitting is implemented under 18 AAC 50.326 and permits are issued by the ADEC Division of Air Quality. The emissions from all pollutant emitting sources (excluding the engines of mobile sources) within the facility are covered by the Title V permit. 3.3.1 CPL Status – Title V Applicability The CPL’s design capacity is not forecasted to exceed regulatory thresholds until the Cell 5 expansion is permitted. When design capacity exceeds regulatory thresholds and the CPL becomes a NSPS site, the Borough will be required to apply for a Title V permit with the ADEC Division of Air Quality in compliance with 18 AAC 50.326. 3.4 National Emission Standards for Hazardous Air Pollutants (NESHAP, 40 CFR 63 Subpart AAAA) NSPS sites are subject to the monitoring, recordkeeping and reporting requirements for MSW landfills contained in 40 CFR 63 Subpart AAAA. These requirements include the submittal of a compliance report every six months, beginning 180 days after startup of the LFGCCS. 3.5 Asbestos Disturbance Notification Before construction of a LFGCCS, the CPL will need to provide notification of any waste disturbance activities which may encounter asbestos (40 CFR 61.154(j)). Notification to the Air Quality Division of ADEC is to be made at least 45 days prior to the disturbance event. Kenai Peninsula Borough - CPL 7 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. 3.6 SSM Plan NESHAP regulations mandate that landfill owners develop a written Startup, Shutdown and Malfunction Plan (SSM Plan) to minimize the release of HAPs when air control devices (the LFGCCS) are not operating. SSM Plans include procedures for starting up and shutting down the control device, for documenting and keeping records of qualifying SSM events, and reporting deviations from the SSM Plan. NESHAP also requires submittal of semiannual reports to ADEC documenting SSM events, the corrective actions taken and any changes to the SSM Plan. The SSM Plan should be developed prior to the gas collection and control system start-up, and undergo revision when the conditions at the landfill change and/or are inadequately covered in the SSM Plan. 3.7 Air Quality Construction Permit The Borough will be required to apply for an air quality construction permit per 18 AAC 50.346 prior to constructing a LFGCCS since the system will include a combustion device that emits regulated air pollutants. HDR recommends that the permit application be submitted to the ADEC as soon as the Borough decides which control device(s) will be installed to avoid a delay in construction. 3.8 Flare Station Performance Test Within 180 days after initial startup of the LFGCCS, a flare performance test is required to be performed on the control device following the requirements of 40 CFR 60.757(g) and 40 CFR 60.8. A performance test report includes a diagram of the collection system, data for the LFGCCS design, documentation of the presence of asbestos or non-degradable material for each area from which collection wells have been excluded, calculations of LFG generation rates for each excluded area and the total sum for all excluded areas, provisions for upgrading the gas mover equipment to accommodate the maximum expected LFG generation rate, and provisions for the control of off-site migration of LFG. The initial test report will also include a brief summary of the performance test, its sampling and analysis procedures as well as any modifications, and test results. 3.9 ADEC Meeting HDR recommends that the Borough meet with the ADEC Division of Air Quality to discuss the facility, the Design Capacity Report, and the current regulatory status of the landfill. If any violations other than not meeting the submittal deadlines for the design capacity reports are realized during this meeting, an action plan for addressing and resolving these issues should be developed and implemented. Although not critical, HDR recommends inviting the appropriate ADEC Solid Waste personnel to this meeting to keep them informed of landfill operations and planning. 4. LANDFILL GAS COLLECTION AND CONTROL SYSTEM PLAN While not a regulatory requirement at the current time, the Borough chose to proceed with preparation of a conceptual LFGCCS Plan. This section of the LFGMP presents the conceptual LFGCCS Plan - it provides the schematic design of a LFG management system that will collect, transmit and dispose of LFG generated in the entire lined landfill at final grades. 4.1 Design Variables The conceptual design of a LFGCCS for the CPL was limited to the lined landfill at final build-out (i.e., Cells 1-5). The decision not to include the unlined landfill in a LFGCCS was based on declining LFG generation estimates, the NSPS regulatory status of the CPL, and the financial commitment necessary to collect LFG from the unlined landfill. Landfill gas generation rate estimates for both the unlined and Kenai Peninsula Borough - CPL 8 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. lined landfills are discussed in more detail later in this LFGMP. Listed below are the design variables that were used to develop the LFGCCS for the lined landfill at the CPL. 4.1.1 Depth of Refuse – Lined Landfill The original lined landfill master plan included four landfill cells; however, the design was modified to expand the number of cells to five with the same overall footprint. Cell 1 is currently the only constructed and active cell in the lined landfill. The as-built base elevation of Cell 1 is approximately 240’ above mean sea level (AMSL). The conceptual base grading plan for Cells 2 through 5 prepared by CH2M-Hill as part of the Cell 2 design shows base elevations ranging from approximately 250’ AMSL for Cell 2 to 275’ AMSL by the end of Cell 5. The conceptual closure plan for the lined landfill is currently permitted to a final elevation of 340’ AMSL. For the purposes of estimating LFG extraction well depths, HDR assumed these conceptual base and final grade plans will be followed. 4.1.2 Final Cover System - Lined Landfill Closure plans for the lined landfill are based on interim closure of cells until they reach final grade. When a cell reaches final grade, the CPL plans to cap the cell with a final cover system meeting the requirements of 18 AAC 60.395. The CPL’s conceptual closure plan, developed by URS in 2003, prescribes an alternative cover system for the lined landfill in compliance with 18 AAC 60.395(b). The final cover cross section from waste to surface is: 6-inch interim gravel cover layer 12-ounce nonwoven geotextile 40-mil linear low density polyethylene (LLDPE) geomembrane liner 12-ounce nonwoven geotextile 12-inch drainage layer 6-inch topsoil/erosion protection layer This alternative final cover system is currently permitted under Solid Waste Permit No. SW1A006-11; however, the Borough plans to reevaluate this closure system as Cell 2 is constructed and developed, and a new alternative final cover system may be proposed. 4.1.3 Waste Density - Lined Landfill Waste density is a function of the types of waste received, amount of cover soil placed and the degree of compaction applied at a landfill. Waste density has an inverse affect on a LFG extraction well’s radius of influence (ROI). As waste density increases, the migration pathways for gas become inhibited, resulting in a lower ROI for a well. The overall waste density for the lined landfill is estimated at 1,150 pounds of waste per cubic yard of total volume of waste material (MSW plus cover soil) placed. This estimate is an average of the historical waste density for Cell 1 and CH2M-Hill’s projected waste density for Cells 2 through 5. This waste density will be used for conceptual design of the LFGCCS. 4.2 Landfill Gas Collection and Control System Calculations and Design Methodology Control of landfill gas emissions requires effective collection of the generated LFG, and effective control strategies for its end-use (e.g., flaring, LFGTE, etc.). This section describes the design methodology and calculations used to size and lay out the conceptual LFG Collection and Control System (LFGCCS) for the lined landfill at full build-out. Site-specific design considerations are discussed, LFG generation rates are estimated, and the type of collection network is selected, sized and located on site drawings. Kenai Peninsula Borough - CPL 9 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. 4.2.1 Site-Specific Design Considerations The subarctic climate of Soldotna, Alaska requires a number of revisions to an industry-standard LFGCCS design. In milder climates, a standard LFGCCS typically includes polyvinyl chloride (PVC) components. In cold climates, system designs use alternatives to PVC such as high density polyethylene (HDPE), stainless steel and brass. HDPE can better withstand severe cold conditions, applied stresses and strains from differential settlement, and the large temperature fluctuations associated with LFG generation. PVC has a potential to become brittle and crack in cold weather conditions, and cannot withstand differential settlement as well as HDPE. The underground installation depth of LFG collection piping (laterals and headers) is another consideration for colder climates. In milder climates, the primary concerns of pipe trench design are to provide pipe support and to deter pipe deflection from applied forces. In colder climates, LFG collection pipe trench design also needs to consider cold temperature protection of underground systems. Although LFG temperatures normally range from 90 to 120 degrees Fahrenheit (°F), power failure or equipment breakdown can result in system shutdown and create static flow conditions in the LFG collection piping. If LFG collection piping is too shallow and/or not insulated, condensation of the super-saturated LFG may occur, and the condensate has the potential to freeze within the pipes. To combat cold temperatures, piping should be buried below the frost line or heat-traced and insulated. Some other site-specific cold climate design considerations for the CPL’s LFGCCS are as follows: Wellhead enclosures should be insulated Collection piping installed above ground should be insulated and possibly heat traced Leachate condensate piping should be heat traced and insulated The blower and control panel will need to be installed in a heated enclosure 4.2.2 Landfill Gas Generation Calculations An active LFG collection system must be designed to handle the maximum expected gas generation flow rate from the entire area of the landfill that warrants control per 40 CFR 60.752(b)(2)(ii)(A)(1) for the active life of the landfill. Sites with known year-to-year waste acceptance rates, such as the CPL, use the following first-order kinetic equation to calculate the maximum expected gas generation flow rate [40 CFR 60.755(a)(1)(ii)]: ikt iO n i lfg eMkLQ 1 2 where, Qlfg = maximum expected gas generation flow rate [m3/yr] k = methane generation rate constant [year-1] Lo = methane generation potential [m3/ Mg of solid waste] Mi = mass of solid waste in the ith section [Mg] ti = age of waste in the ith section [years] During the winter, waste is placed in the landfill at cold temperatures, and the ambient temperatures are generally cold. Cold temperatures will inhibit biological decomposition. However, once decomposition Kenai Peninsula Borough - CPL 10 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. begins to occur, heat will be generated and is expected to warm the surrounding waste mass. Optimum temperature ranges for anaerobic bacterial decomposition (which produces methane and carbon dioxide in oxygen-deprived environments) are 85 to 100 °F for mesophilic bacteria, and 131 to 140 °F for thermophilic bacteria. HDR calculated the maximum expected gas generation flow rates for CPL’s unlined and lined landfills using EPA’s updated Landfill Gas Emission Model [LandGEM]. LandGEM modeling, incorporating site-specific waste acceptance rates and the required variable input values base on 40 CFR 60.755(a)(1), predicts LFG generation volumes and its main components: carbon dioxide and methane. Inputs into LandGEM included historical and future waste tonnages at the CPL, and the recommended k and Lo kinetic factors published in the most recent Compilation of Air Pollutant Emission Factors (AP–42). The LandGEM modeling results for the unlined and lined landfills are included in Attachments B and C. Note that the graphs in Attachments B and C show different emissions for CH4, CO2 and NMOC expressed as mg/year. The emissions rate in m3/year or ft3/year for methane and carbon dioxide are equal; as a result, the methane line does not show on the plot because the carbon dioxide line overlies it. The values predicted by LandGEM modeling should be considered estimates of gas production, and by no means guarantee gas production at the CPL. Many variables that affect LFG production cannot be incorporated into the modeling with certain accuracy such as waste composition, moisture content, temperature and climatic conditions, landfill operations, etc. A breakdown of the inputs and outputs of the LandGEM modeling for the CPL is as follows: Unlined Landfill o Inputs Waste tonnages are from the historical records at the CPL and coincide with the values presented in HDR’s GHG Monitoring Plan and draft Design Capacity Report. Methane generation rate constant (k) is 0.02/year for drier areas such as Soldotna that receive less than 25 inches of rain annually per AP-42. Methane generation potential (Lo) is 100 m3/Mg of refuse per AP-42. o Output Maximum expected LFG generation flow rate is 3,110,000 m3/year (209 cfm) in the year 2008. Lined Landfill o Inputs Waste tonnages for years 2005 through 2009 are from the historical records at the CPL presented in the RD&D report. Waste tonnages for years 2010 through 2034 are based on the waste forecasts presented in Table 2 of CH2M-Hill’s Schematic-Design Basis Report, and take into account the total design capacity of the lined landfill (2,601,000 cubic yards). Methane generation rate constant (k) is 0.04/year due to leachate recirculation in the lined landfill. This is the default value AP-42 recommends for wet areas receiving greater than 25 inches of rain annually. Although Soldotna does not fall within this “wet” range, leachate recirculation has a similar affect on the biodegradation rate of waste as rain. Methane generation potential (Lo) is 100 m3/Mg of refuse per AP-42. Kenai Peninsula Borough - CPL 11 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. o Output Maximum expected LFG generation flow rate is 7,200,000 m3/year (484 cfm) in the year 2035. The LandGEM results for the unlined landfill show that LFG generation peaked in 2008 and is now on the decline. Considering the large investment in terms of planning, design and construction needed to collect gas from the unlined landfill, its gas generation estimate, and the NSPS regulatory status of the CPL, HDR considered it to be impractical to include the unlined landfill in a LFGCCS. This should be reevaluated in the future when feasibility studies for potential LFG end-use opportunities are conducted, if those studies show a financial benefit to including the unlined landfill in an end-use program. Therefore, the conceptual design of a LFGCCS for the CPL is limited to the lined landfill. The conceptual design of the LFGCCS for the lined landfill is based on a conservative estimate of the maximum LFG generation flow rate expected in the year 2035. In an effort to not undersize the collection system, a safety factor of 1.2 is applied to the LandGEM output. Thus, the lined landfill’s LFGCCS is sized to accommodate a maximum expected LFG generation flow rate of 581 cfm. It is important to note that the predicted maximum lined landfill gas flow rate will not be realized until 2035, the year after Cell 5 is projected to close. The gas flow rate increases over time. When evaluating or negotiating potential end-use options, the Borough should take gas flow rate trends and the overall collection efficiency at the site into account. A typical gas flow capture estimate and LFG collection system efficiency is roughly 75 percent until the landfill is finally closed and capped with a final closure system. The collection efficiency prior to closure is limited by a lower vacuum placed on the wells to prevent air infiltration and the potential release of emissions through the interim cover. Unlike the LFG collection system, the gas mover and control equipment (e.g., fan, blower, compressor, flare) are sized to handle the maximum expected gas flow rate over the intended use period of the equipment [40 CFR 60.752(b)(2)(ii)(A)(1)]. This intended use period should not exceed more than 15 years [40 CFR 60.755(a)(1)]. For conceptual design purposes (and to serve as an example), HDR selected the years 2012 through 2026 as the intended use period for the gas mover and control equipment at the CPL. The maximum expected gas flow rate for this period is 368 cfm. 4.2.3 Landfill Gas Collection Techniques Landfill gas collection systems can be categorized into two basic types: (1) active collection systems; and (2) passive collection systems. Active collection systems employ gas movers (blowers or compressors) to provide a pressure gradient to extract landfill gas. Active gas collection systems typically use vertical gas extraction wells or horizontal trench systems. Passive collection systems rely on the naturally occurring pressure gradients stemming from LFG generation within the landfill to convey gases to the atmosphere, or to a control system. Typically, well-designed active collection systems are considered a more efficient means of LFG collection. Passive collection systems usually operate as venting systems. They are typically installed at final closure to provide enhanced pathways for LFG to escape to the atmosphere. These systems are intended to reduce the potential for offsite subsurface LFG migration and to allow gas pressure dissipation under the final closure system. Passive venting costs less than active collection. Due to variability in pressure inside and outside of a landfill, passive venting may actually lead to more favorable conditions for offsite LFG migration compared to active collection. Additionally, the use of emission control devices (flares) with a passive venting system is uncontrolled and therefore does not allow an opportunity for a LFG to energy project or for carbon offset credits. Kenai Peninsula Borough - CPL 12 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. A passive collection system can be used at the lined landfill if NMOC emissions are equal to or greater than 50 Mg only if it meets the criteria listed under 40 CFR 60.752(b)(2)(ii)(B), which states that the passive collection system must be designed to: (1) handle the maximum expected gas flow rate over the expected lifespan of the collection equipment; (2) collect gas from each area of the landfill that warrants control; (3) minimize offsite migration of subsurface gas; and (4) be installed with liners on the bottom and all sides of the areas in which gas is collected (e.g., final closure for the entire lined landfill). The passive collection system must also route all gas collected to a control device that is in compliance NSPS regulations [40 CR 60.752(b)(2)(iii)]. The disadvantage of this approach for a LFGCCS is costs are generally higher than active systems when designed for the same collection efficiency due to uncontrolled and fluctuating gas flows, and the need for an encapsulating closure system. Active collection systems must be designed to the same criteria as passive collection systems except that they do not require an encapsulating closure system, and must collect gas at a sufficient extraction rate to maintain a negative pressure at all wellheads without causing air infiltration [40 CFR 60.752(b)(2)(ii)(A)]. An active horizontal trench collection system is typically applied at landfills employing layer-by-layer filling methods. These collection systems consist of horizontal wells installed in trenches. Horizontal collection systems are easy to install since drilling is not required, and convenient to operate in an active landfill. Horizontal wells should be designed with sufficient slope to allow for adequate drainage of condensate and/or leachate, and should be designed to allow for differential settlement. The ends of horizontal wells should include sections of solid pipe to discourage air infiltration through the side slopes of the landfill. Landfill gas can typically be extracted once 25 feet of waste is placed over the horizontal trench. However, the gas collected is usually of lower quality (i.e., methane) and quantity than vertical wells due to the potential for atmospheric intrusion and the difficulty of maintaining uniform vacuum along the length (or width) of the landfill. Horizontal wells are also more susceptible to blockage due to unplanned low points in the system due to differential settlement, and have a higher tendency for pipe collapse from overburden loads. Leachate recirculation can also flood the collection system. The disadvantages of a horizontal collection system make it more ideal for short-term, sacrificial use. For long term use, vertical gas extraction wells are typically used. In lined landfills, the wells are typically drilled to 75 percent of the landfill depth to avoid damaging the liner system. The spacing between vertical gas extraction wells depends on the landfill characteristics (e.g., waste density, LFG generation rate, etc.) and the amount of applied vacuum generated by the gas mover. These systems are typically applied at landfills employing cell-by-cell filling operations such as the CPL. When compared to horizontal collection systems, vertical collection systems are generally less expensive or equivalent in costs. The disadvantages of a vertical gas collection system are that wells are susceptible to damage by heavy equipment, and may impede filling operations. Therefore, vertical wells are commonly installed only on areas of the landfill that have reached final grade. 4.2.4 Well Placement and Radius of Influence Calculations The placement of gas extraction wells is a critical component of LFG control system design. The NSPS specifications for active collection systems emphasizes positioning wells at a sufficient density throughout all gas producing areas that warrant control [40 CFR 60.759(a)]. If wells are spaced too far apart (i.e., low density), the zone of influence of the well field might not cover the entire landfill resulting in potential surface emissions of LFG. The system operator may then be inclined to increase the vacuum on the well field in order to combat the situation. If the vacuum placed Kenai Peninsula Borough - CPL 13 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. on the wells is too high, air infiltration becomes an operational concern. Air infiltration can lead to subsurface combustion and/or inhibit methanogenic bacteria growth. When a well is placed under a vacuum, the recoverable LFG in the immediate vicinity will begin to move towards the well. This area of gas movement is referred to as the well’s radius of influence (ROI). The basic approach for designing both vertical and horizontal gas collection systems is to use the ROI calculated for vertical wells. For ease of calculation, the ROI is assumed to be the radial distance from an extraction well that has adequate air flow for the removal of LFG when a vacuum is applied to the well. The edge of the ROI is reached when the vacuum exerted by the well is zero (i.e., no pressure gradient) and LFG beyond this point does not flow towards the collection well. The actual extent of influence will vary from well to well based on site conditions and cannot be measured until the well is installed. Some factors that influence a well’s ROI include the depth of the well, the length of perforated pipe for gas collection, the refuse temperature, the in-situ LFG generation rate, the amount of vacuum applied to the well, and waste density. For conceptual design purposes, HDR calculated a theoretical ROI for a vertical gas extraction well. Assumptions were made concerning the well such as its collection efficiency (75%) and site-specific information for the CPL (e.g., design capacity, refuse density, maximum expected LFG generation rate, landfill age, landfill depth, etc.). The estimated ROI for a vertical well at the CPL was determined to be 150 feet. The ROI calculations are included in Attachment D. HDR used the calculated ROI to develop a conceptual design of a vertical gas collection system for the lined landfill at final build-out (i.e., Cells 1-5). The conceptual layout of this collection system is shown on Sheet LFG-03. Thirty-one wells are positioned throughout the lined landfill based on the estimated ROI of 150 feet. Vertical gas extraction wells are based on 6-inch SDR 11 HDPE pipe with a single perforated interval. The vertical gas extraction well schedule for the lined landfill is shown in Table 2. It is important to note that the placement of these wells is conceptual. The location of the wells may change due to waste fill plans, and the location of access roads, stormwater collection features and other active areas. Additionally, wells should not be placed in areas of the landfill with waste depths less than 45 feet. The ROI for each installed well will depend heavily on its applied vacuum. Wells placed near the perimeter of the landfill will typically operate with lower vacuums to avoid the potential for air intrusion through the side slopes. Consideration should be given to place these perimeter wells at a closer spacing. Another option for gas collection is to install wellheads on existing leachate cleanouts and draw gas from those connections into the header system. These connections will operate under low vacuum to avoid pulling leachate/condensate through the wellheads and into the collection network. 4.2.5 Landfill Gas Collection System Layout The purpose of LFG collection piping is to get vacuum to the wells and convey the gas collected to a central location for its end-use application (e.g., flare station, LFGTE, etc.). The collection piping for the lined landfill consists of lateral piping that connects the vertical gas extraction wells to a header pipe that circumnavigates the entire lined landfill. This collection system layout is illustrated in Sheet LFG-03. The layout of the collection system is based on compatibility with filling operations; ease of installation, operation and maintenance; condensate management; fill settlement; integration with end-use applications; system efficacy and durability; regulatory compliance; and cost. Kenai Peninsula Borough - CPL 14 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. The header system is designed to be a loop system around the entire lined landfill that connects to the existing header pipe installed around Cell 1. The header loop is designed with high points that slope to low points in the system to aid condensate management. Condensate sumps are located at the low points in the system so condensate can be pumped into the lined landfill’s leachate collection system. The header system is located outside of the perimeter of the lined landfill to avoid problems associated with installing pipe in the waste mass such as differential settlement, steeper pipe slopes (approximately 5 percent in waste), and potential for condensate buildup. The system is designed so that it can be expanded in phases as the lined landfill is developed. As cells are developed, interim headers can be installed between the cells to create individual loops. This design approach makes the system redundant at full build-out. This added safety measure provides flexibility in the system in case the main header loop becomes compromised or impeded. Some additional features of the header system are isolation valve boxes and access points. The header isolation valve boxes, located throughout the system, can be used to isolate a particular section of header pipe for maintenance purposes. Header line access points, consisting of a blind flanged assembly that vertically tees into the header pipe, provides spare connection points for lateral tie-ins in case existing laterals become compromised and/or additional wells are installed. Vertical gas extraction wells are to be connected to the lateral collection piping by wellheads. Wellheads will be located at each well and be protected in insulated enclosures. The gas flow rate (vacuum) at each wellhead can be adjusted for system efficiency and to help prevent air intrusion. Lateral collection piping will connect each wellhead to the header system. Depending on location, wells will be connected to the header in series or individually. Lateral piping will tee into the header loop, and be sloped a minimum 5 percent to limit effects of differential settlement on condensate flow. The lateral collection piping, like interim headers, can be installed prior to closure and in phases to coincide with landfill closure plans. 4.2.6 Collection Pipe Sizing HDR used Pipe2010, a computer modeling program developed by KY Pipe, Inc., to size the collection piping network to accommodate the maximum expected gas flow rates in the lined landfill. Pipe 2010 uses the Darcy-Weisbach equation to relate pressure head loss (due to friction along a given length of pipe) to fluid (gas) flow. The design standards used for modeling are as follows: (1) the pressure head loss from the blower (gas mover) to the furthest collection point in the system will be less than 10 percent of the applied vacuum; (2) gas flow velocity travelling in the same direction as condensate flow will not exceed 45 feet per second (fps); and (3) gas flow velocity travelling against condensate flow direction will not exceed 35 fps. HDR sized the collection piping with a design vacuum of 60” of water column. This design vacuum is a conservative estimate and allows the system to meet the design standards if a smaller vacuum (blower) is selected by the Borough. The header loop sizing around the lined landfill is 12” diameter SDR 17 HDPE pipe. The lateral collection piping sizing is either 4” or 6” diameter SDR 17 HDPE pipe depending upon whether one or two wells are served. The maximum calculated head loss for this system is 2” of water column; thus, a vacuum of approximately 58” of water column should be available for all gas extraction wells. The collection system may incur some additional pressure losses due to bends in the piping, fittings, wellhead Kenai Peninsula Borough - CPL 15 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. connections, condensate sumps and the lateral connection to wells, but these losses should be relatively minor. The results from HDR’s modeling are included in Attachment E. The existing 2” diameter lateral connections and ball valves in the vaults surrounding Cell 1 do not have sufficient diameter to accept the predicted gas flow rates without causing significant head loss. By HDR’s design methodology, the existing 6” diameter header pipe installed around Cell 1 is undersized for final build-out of the lined landfill. Likewise, the existing 6” diameter pipe for future connection to a flare station should be either bypassed or replaced with 12” diameter pipe. HDR recommends installing an additional header pipe between Cells 1 and 2 to form an additional loop for improved system performance. The header pipe should be installed similar to that of the lateral collection piping and should be 6” diameter SDR 11 HDPE pipe. The header should be installed when Cells 1 and 2 reach grade, as shown in Figure LFG-03. If this header is installed, lateral collection piping for vertical extraction wells EW-10, EW-11 and EW-12 should be re-routed to connect to this header pipe as opposed to the perimeter header loop. HDR developed the conceptual design of the LFG collection system based on NSPS requirements for the final build-out of the lined landfill. To that end, if future design capacity and NMOC emission estimates do not require the installation of a LFGCCS, a reduced system can be developed and installed to meet the Borough’s needs. If future design capacity and NMOC emission estimates require the installation of a LFGCCS, the Borough may be obligated to construct the LFGCCS in phases to meet 2-year and 5-year NSPS compliance measures. Per 40 CFR 60.753(a), the Borough would be required to operate a collection system in areas of the landfill in which solid waste has been in place for 5 years or more if active, or 2 years or more if closed or at final grade. The conceptual LFGCCS will also need to meet the requirements listed under 40 CFR 60.759 regarding gas system expandability, accessibility, fill settlement, and be built with corrosion resistant material of suitable dimensions to withstand installation, static and settlement forces and planned overburden or traffic loads. 4.2.7 Condensate Management Condensate management is a requirement for active LFG collection systems per 40 CFR 60.759(a)(1). Landfill gas condensate is the liquid (mostly water) from moisture within the LFG being recovered. As LFG is extracted from the waste mass, it cools and condenses in the collection network and forms into gas condensate. If the gas condensate is not removed from the collection system, liquid buildup will occur and adversely affect gas flow rates. HDR estimates that the maximum expected gas condensate generation rate for the lined landfill is 299 gallons per day. This approximation is based on the maximum expected LFG generation flow rate of 581 cfm in the year 2035. The condensate generation calculations are included in Attachment F. The LFG collection system is designed to drain gas condensate by gravity to collection sumps located at low points throughout the header system. Condensate collected at the sumps is pumped to the leachate collection system through leachate cleanout connections. This allows gas condensate to be combined with leachate, and the CPL can employ the same management techniques established for leachate to address gas condensate. An example of a typical condensate sump station is LANDTEC’s Landfill Automated Pump Station (LAPS). Based on the lined landfill’s estimated gas condensate generation rate, HDR recommends Kenai Peninsula Borough - CPL 16 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. LANDTEC’s LAPS-301 unit. Condensate from collection points in the LFG collection system (low points in header system) is gravity-fed to the LAPS reservoir for intermediate storage. Condensate collected in the reservoir is automatically discharged by an electric submersible pump to the appropriate disposal point (leachate cleanout connections). The LAPS-301 unit is capable of discharging liquid condensate at flow rates between 2 to 6 gpm. LANDTEC’s specification for this unit and a sample detail is included in Attachment G. Note that this detail will need to be modified for cold weather application at the CPL. HDR recommends that the Borough update their RD&D permit for leachate recirculation at the lined landfill during the next renewal period (March 6, 2011) to include the addition of gas condensate. This update will allow the CPL to operate under a liquids restriction variance for the placement of gas condensate (and leachate) in the lined landfill. Per 18 AAC 60.260(a)(1)(B), the RD&D permit could be revoked if gas condensate is disposed of at the lined landfill without an appropriate modification to the permit. To avoid expiration of the current RD&D permit, HDR suggests the Borough submit their renewal application to the ADEC at least thirty days prior to the expiration date. 5. GAS MOVER AND CONTROL DEVICES An active collection system utilizes a gas mover to transport LFG through the collection system to an emission control device. The gas mover and control equipment is sized to handle the maximum expected gas flow rate over the area of the landfill that warrants control for the intended use period of the equipment. This intended use period should not exceed 15 years. For conceptual design, HDR selected the years 2012 through 2026 as the intended use period for the CPL. The maximum expected gas flow rate for this period is 368 cfm. Listed below are brief discussions surrounding the gas mover and flare equipment recommended for the lined landfill. 5.1 Gas Mover Equipment NSPS regulations require gas to be collected at an extraction rate sufficient to maintain negative pressure at all wellheads in the collection system without causing air infiltration, including any wellheads connected to the system as a result of landfill expansion (cell development) or excess surface emissions (≥ 50 Mg of NMOC). Therefore, blower sizing is a crucial element of LFGCCS design. The typical lifetime of a blower is 15 years. HDR’s calculations indicate that the blower should be capable of applying 60 inches of water column vacuum that can operate between flow rates of 0 to 375 cfm. This blower selection meets the design standards used for sizing the collection network, and is adaptable for the expected gas flow rates at the lined landfill through the year 2026. In the event the collection or control system becomes inoperable, the blower should be shut down and all valves in the collection and control system that may contribute to venting to the atmosphere should be closed within one hour [40 CFR 60.753(e)]. 5.2 Control Devices – Flares A flare station is a basic type of emission control device that destroys LFG with no energy recovery. Flaring is an open combustion process in which oxygen used for combustion is either provided by ambient air or forced air. Flare efficiency is governed by flame temperature, residence time of gas constituents in the combustion zone, turbulent mixing of the combustion zone, and the amount of oxygen available for combustion. Kenai Peninsula Borough - CPL 17 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. The two main types of flares used at landfills are open (candlestick) and enclosed flares. Flare selection is usually based on applicable regulatory requirements and end-use goals for LFG collection at the landfill. Under NSPS regulations, flare stations must be capable of combusting LFG at a wide range of flow rates and be designed to meet the requirements listed under 40 CFR 60.752(b)(2)(iii). For example, flares must be able to operate with a NMOC destruction efficiency of at least 98 percent by weight (i.e., reduce NMOC emissions by 98%). Typically, both candlestick and enclosed flares meet this requirement. The selection of either flare device may qualify the CPL for carbon credits if the LFGCCS is installed voluntarily. Carbon credit potential for the CPL will be discussed later in this LFGMP. The environmental impacts of a control device also need to be considered. Testing and compliance monitoring will be required once a flare station is installed at the CPL to verify that the combustion emissions are within regulatory limits. Typical emission byproducts of LFG combustion include carbon monoxide (CO), nitrogen oxides (NOx), sulfur dioxide (SO2), hydrogen chloride (HCl), hydrogen sulfide (H2S) and particulate matter. Air regulations restrict LFG emissions of H2S to less than 500 parts per million, volumetric dry (ppmvd). The ADEC has a rule [18 AAC 50.055(c)] that limits SO2 emissions from fuel-burning equipment (e.g., flares) to a 500 ppm average over a period of three hours. Elevated SO2 emissions are generally associated with the combustion of hydrogen sulfide (H2S) gas generated from C&D debris. Sulfur dioxide emissions from flaring LFG produced by MSW landfills usually do not exceed 500 ppm. The lined landfill at the CPL is composed mostly of MSW, and receives only a small amount of C&D debris waste the Borough’s transfer sites. 5.2.1 Enclosed Flares Enclosed flares, sometimes referred to as ground flares, are control devices whose combustion is fully contained in a heat-retardant and insulating chamber (shell) that extends beyond the flame. The flame is usually not visible outside of the enclosure. The height of the flare station must be adequate to supply a draft of a sufficient air for combustion and be designed for thermal dispersion. Ground flare enclosures range in height from 20 to 60 feet with diameters between 4 and 13 feet. Enclosed flares can handle flow rates between 30 and 6,100 cfm depending upon sizing. Enclosed flares have consistently been shown to achieve combustion efficiencies greater than 98 percent for the NMOC contained in LFG, and potentially produce less unwanted emission byproducts such as CO and NOx than candlestick flares. Unlike open flares, enclosed flares can be measured for emissions to obtain reliable test data. The high destruction efficiency is a result of combustion taking place in a controlled environment that is less susceptible to weather conditions. Enclosed flares are able to reach and maintain higher combustion temperatures, and the intake of air can be adjusted depending upon flare temperature. These parameters can be monitored and controlled manually or electronically to produce a stable and efficient environment for combustion. Depending upon the sulfur content of the LFG being burned, condensation forming around the top of the stack may require corrective action to combat corrosion. The assembly of an enclosed flare and its long-term maintenance costs are usually higher than candlestick flares. 5.2.2 Candlestick Flares Candlestick flares, also called open or utility flares, combust LFG outside the flare stack. These flares can be located at ground level or can be elevated. The candlestick flame is visible and not enclosed. Flares located at ground level can be shielded with a fence. A small burner, typically fueled by a propane pilot, ignites the incoming LFG as it mixes with ambient air. These flares operate without the assistance of forced air, and rely on ambient air conditions and/or the velocity of incoming gas to mix gas and air for combustion. The flare stack ranges in height from 15 to 20 feet with diameters between 3 and 16 inches. Kenai Peninsula Borough - CPL 18 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Candlestick flares can handle flow rates between 35 and 6,000 cfm depending upon sizing. Candlestick flare assemblies are sometimes found mounted on skids along with other control components such as blower(s), condensate knockout drums, control panels and other equipment. Skid-mounted units are more mobile than permanent fixtures and can potentially reduce installation costs. Candlestick flares generally cost less than enclosed flares and require less maintenance. Skid-mounted flares offer simple design and relatively inexpensive installation. However, these flares may produce higher emissions than enclosed flares because of the variability of the combustion environment due to radiant heat loss. The incoming flow rate to the flare station must be carefully controlled to prevent low flow flashback problems and to avoid flame instability. Low flow flashback is caused when the gas flow rate to the flare is too low and the flame is pulled back into the stack. These flares cannot be easily sampled for emissions and conditions necessary to achieve 98 percent reduction in NMOC are described in 40 CFR 60.18. Candlestick flares, if designed and operated correctly, can meet the destruction efficiency for NMOC required by the NSPS regulations. 5.2.3 Flare Recommendation Flares are used at landfills primarily for air emission control or as a backup to an energy recovery system. HDR recommends using a candlestick flare for the conceptual design of LFGCCS for the CPL with an assumed lifetime of 15 years. Although an enclosed flare offers a more controlled combustion environment, a candlestick flare is easier to operate and less expensive. Open flares can still meet the 98 percent destruction efficiency required by NSPS regulations. Periodic sampling and/or modeling of the flare is recommended to show that an emission reduction of 98 percent NMOC content is achieved. The candlestick flare will also offer the Borough a backup control device in the event that an end-use system (e.g., LFGTE) is offline. The conceptual layout of a candlestick flare station is shown in Sheet LFG-07. Landfill gas is conveyed to the flare through the header system and transfer lines by a blower. Gas condensate is removed by a knockout drum. The flare station is located on the south side of the lined landfill where originally planned during Cell 1 construction. This location can easily be modified in the future if the Borough would like a different location due to landfill operations and/or power supply issues. 6. LANDFILL GAS END-USE OPPORTUNITIES LFG is typically an underutilized byproduct of the anaerobic decomposition of waste. During the past 30 years, significant advancements have been made in landfill gas conversion technologies to turn LFG into profitable and environmentally friendly beneficial end-uses. The selection of a recovery technique versus a control technique is highly dependent on such factors such as the LFG generation rate, the market availability for recovered energy, and environmental impacts. If landfill characteristics are such that the landfill does not produce enough LFG to make gas recovery economically feasible, control through flaring may be the best suited option for the landfill. Likewise, if there are no customers for the generated electricity or LFG supply, energy recovery systems are not feasible. Landfill gas is comprised mainly of methane (CH4), carbon dioxide (CO2), and several other constituents lumped together as balanced gas. Methane is typically the primary constituent accounting for an average percentage by volume of roughly 50 percent. Landfill gas with a methane concentration of 50 percent has a heating value of approximately 500 British thermal units (BTU) per cubic foot (ft3), which is about half that of natural gas. This energy content potential allows LFG to be used in a variety of ways, other than flaring, to not only destroy harmful gas constituents but also provide an economic benefit to the landfill owner and energy to the end users. Kenai Peninsula Borough - CPL 19 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. In general, there are three primary end-use options: (1) landfill gas to electricity (LFGTE); (2) direct use; and (3) gas stream modifications. These three end-use options all have individual benefits and drawbacks as well as different application techniques. Due to economies of scale associated with gas stream modifications, the small size of the CPL, and availability of low cost natural gas, HDR determined it is not a viable pursuit for the Borough, so this option was not addressed in this LFGMP. Below is a discussion of the most common (and proven) LFG end use options. 6.1 Landfill Gas to Energy A reciprocating internal combustion (IC) engine is the most prevalent technology currently used for the generation of electricity from landfill gas. According to EPA’s Landfill Methane Outreach Program (LMOP), approximately 58 percent of the estimated 518 LFGTE projects in operation as of July 6, 2010 use IC engines to generate electricity. In the early 1980’s, Caterpillar developed the first IC generator (model 3516) specifically designed to be fueled by landfill gas. Since then, Caterpillar, Jenbacher, and other manufacturers have advanced and refined the technologies to meet the needs of landfill gas to electricity projects. IC engines are modular and can be properly sized to optimize the collection and utilization of landfill gas. Most models can operate with methane levels as low as 40 percent. These engine-generator sets can be containerized, or placed inside a building. Containerization of the IC units allows the landfill operator to match generator capacity to the available LFG as it evolves over the life of the project; otherwise, a building would need to be sized to accommodate the maximum expected LFG generation rate. IC engines have relatively low capital costs, high thermal efficiency, low emissions, and require minimal pre-treatment of the fuel gas. LFG pre-treatment for an IC engine typically consists of a coalescent filter that removes entrained moisture and particulates from the landfill gas along with a blower to compress the landfill gas to the proper fuel injection pressure (roughly 5 psig). IC engines are susceptible to damage from elevated hydrogen sulfide and siloxane concentrations, which are typical contaminants of LFG when landfills contain wastes other than MSW. There are commercially available processes that can reduce these contaminants to allowable levels if higher concentrations are encountered; however, most currently operating LFGTE projects do not require pretreatment. The allowable level for H2S in most IC models is roughly 200 ppmvd. An iron sponge can be used for concentrations up to 2500 ppmvd. Over this concentration, a scrubber is likely required. To mitigate this potential risk, a gas composition analysis should be performed on the gas stream as part of the Borough’s consideration of end-uses. Typical staffing for LFGTE projects of similar size to the CPL include one part-time to full-time employee who can provide routine operations and maintenance (O&M) services. A call center comprised of experienced operators should also be established to provide 24 hours a day, 7 days a week (24/7) on call services. IC engines can be operated remotely. The systems are typically controlled using process-integral- derivative controllers that will automatically adjust the operation of the system based on the inlet concentrations of gas or the flow rate. Oil changes are the predominate maintenance needed for IC engines. These oil changes can be performed by Borough mechanics on a regular basis. Engine overhauls should be performed by an experienced maintenance technician. These minor and major overhauls can either be conducted onsite or in a repair shop. Minor and major overhauls are typically performed once a year and every four years, respectively. Kenai Peninsula Borough - CPL 20 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. An EPA survey of IC engines burning LFG concluded that IC engines can and do reach 98 percent NMOC emission reduction when operating at full load. The combustion efficiency for an IC engine operating at full load is primarily a function of the air-to-fuel ratio. When fuel efficiency decreases (i.e., fuel-to-air ratio below stoichiometric levels), or the IC engine is operating below full capacity, the destruction efficiency of NMOC can drop to about 95 percent. Since LFG is produced 24/7, the generated electricity from IC engines should go to end-users with a 24/7 electrical load requirement such as an electric utility company. The generated electricity can also be used onsite at the landfill to offset some electric costs. IC engines that are fueled by LFG are available in a wide range of speeds and loads. IC engines are available in capacities ranging from approximately 250 kilowatts (kW) up to well over 3 megawatts (MW). A preliminary analysis of the LandGEM results for the lined landfill for the years 2012 through 2026 with an IC engine with a 350 kW power range was conducted by HDR to determine electrical generation potential at the CPL. This analysis is based on the following assumptions: LandGEM results are accurate predictions; Landfill gas heating value is 500 BTU/ft3; Landfill gas collection efficiency is 75 percent; IC engine has a power range of 350 kW; Engine efficiency is 95 percent; Engine downtime is 15 percent for O&M activities; Parasitic loading (energy loss) is 7 percent; and Excess LFG is flared. The preliminary results from this analysis show that the CPL will be able to operate a 350 kW IC unit at full capacity beginning in the year 2014 and generate approximately 193,000 kW-hours of electricity per month. Beyond 2014, the load capacity of a single IC unit will be exceeded and excess LFG should be flared. However, additional IC engines could be added to the system and operate at reduced loads to minimize the amount of LFG being flared. A second IC engine could probably operate at full capacity in the year 2021. Based on the CPL’s Homer Electric Association (HEA) energy bill for 6/15/09 to 7/17/09, the landfill uses approximately 14,300 kW-hours per month. HDR recommends that a feasibility study and economic analysis be conducted before pursuing a LFGTE project to ensure its viability. 6.1.1 LFGTE Feasibility Study HDR recommends the Borough conduct a LFGTE feasibility study before pursuing such a project. The beneficiaries of LFGTE projects can either be the landfill itself or other end-user candidates. The feasibility study should address the following at a minimum: Identify any potential private developers/parties for financing, ownership, and/or routine O&M activities. Legal agreements between the Borough and private party will need to be drafted to divvy up responsibilities related to regulatory compliance, equipment ownership and operation control. Determine if there are any regulatory issues that could impact the LFGTE project. Develop a financial plan for the LFGTE project. Define the quality and quantity of gas being generated at the lined landfill. Select LFGTE equipment appropriately sized for the expected flow rates at the lined landfill. Determine the costs associated with purchase, shipping and handling, installation, and O&M Kenai Peninsula Borough - CPL 21 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. activities. Also determine the potential energy production and the gas management regime (e.g., number of IC units vs. flaring gas, etc.). Determine the end-user’s power demand and energy usage, and if they require backup power if the LFGTE system is offline. Evaluate the terms and conditions of the existing energy agreement between the end-user and HEA. Evaluate the option of selling excess electricity to HEA, and the terms and conditions of such an agreement (e.g., buy-back rate, variable supply). Evaluate any potential end-uses for the waste heat generated from production of electricity from LFG. Compare feasibility results to the option of selling all generated electricity directly to HEA. 6.2 Direct Use Options The primary conversion process typically associated with the direct use option includes boiler and dryer fuel. Since landfill gas is produced at all times, any direct use option should be continuous. Local industries or facilities can benefit from the use of LFG to help offset some of their existing fuel costs. Unused fuel, as a result of load swings or batch operations, is typically combusted through a flare station. In addition to using LFG for a fuel offset, some facilities have the ability to use the gas in a cogeneration process. In a cogeneration process, the waste heat resulting from the combustion of the landfill gas for power generation provides the host site with a thermal load for heating processes (e.g., buildings, water, biosolids). These systems are referred to as combined heat and power (CHP) projects. Landfill gas may be routed to an onsite boiler, or piped and sold to an offsite boiler to supply heat. The majority of LFG-fired boilers are utilized as a heat source for buildings and/or water. In some arrangements, LFG is routed to boilers to generate steam which in turn is fed to steam powered turbines to create electricity. However, these LFG boiler/steam turbine systems require high capital investment, and LFG flow rates that exceed the CPL’s potential. Another typical end-user of LFG is a municipal wastewater treatment plant (WWTP). A WWTP is typically a good candidate due to their 24/7 operations that require both electricity and heat. As energy prices continue to rise, WWTPs are turning to other sources of alternative energy and thermal inputs for their operations. Drying biosolids is also becoming more prevalent in WWTPs due to excessive dewatering costs and governing regulations. Depending on the configuration of a WWTP, landfill gas can be utilized to dry the sludge (boisolids) before final disposal such as land application. In addition to offsite direct use projects, LFG can be utilized onsite for leachate evaporation. Leachate evaporation systems are available to meet the capacity of the lined landfill’s leachate production. One common application is the destruction of leachate within an enclosed gas flare. Leachate is vaporized, either by air or mechanical atomization, and sprayed into an enclosed flare. Mechanical atomization is more simplistic in design and operation than air atomization; however, air atomization is more effective at diffusing the leachate and prolonging the useable life span of the injection tips. Increased O&M services are required to operate the leachate evaporation system effectively for long periods of time. The operator needs to closely monitor the equipment for signs of potential failure, perform routine maintenance on filters and spray nozzles, and monitor the amount of leachate (and/or air) injected into the flare. The flare combustion temperature must be closely monitored to ensure proper operating conditions for leachate injection and evaporation. If this intensive oversight is not performed, refractory material installed within Kenai Peninsula Borough - CPL 22 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. the enclosed flare may be damaged, and negatively impact the destruction efficiencies of LFG and leachate. Another possibility is to use the heat generated from LFG combustion to evaporate leachate. In this system, leachate is evaporated by using a burner that is submerged in a leachate tank, and uses LFG as the fuel source. Leachate is vaporized through contact with the enclosed, submerged burner. The combustion byproducts exit through an exhaust vent. A demister unit removes vapor from the exhaust gas, which is directed back into a leachate evaporator tank. Exhaust gas exiting the demister unit is emitted to the atmosphere. The leachate which has been evaporated and thickened by evaporation is termed “residual”. The residual leachate is composed of approximately 20% solids. The turbulence in the evaporator tank prevents simultaneous vaporization and removal of these residual solids. The evaporator must be turned off to allow for settlement prior to removal and disposal of the residual solids. Excess LFG not utilized for leachate evaporation and/or during downtimes is flared. Of the two options presented above, the immersion burner/evaporation method is generally preferable. The destruction of leachate in a gas flare carries greater O&M services and is more prone to system failure/downtime than an evaporation unit. Leachate evaporation systems are generally only feasible at landfills that have an adequate supply of LFG to evaporate the volume of leachate generated. It is also important to note that a reduction in leachate recirculation below the required optimum conditions will directly affect LFG production rates, and must be incorporated in the control system design if the Borough chooses to move forward with a leachate evaporation system. A preliminary analysis of Fen-Tech Environmental, Inc.’s (FTE’s) 150 GPH Evap-O-Dry Evaporation System (EOD) was modeled as a representative leachate evaporation unit. Typical landfill leachate takes approximately 10,100 BTUs to evaporate one gallon of leachate. Using a LFG heating value of 500 BTU/ft3 with 75% collection efficiency, the CPL could potentially evaporate approximately 120 gallons of leachate per hour based on the LandGEM results for the lined landfill for year 2012 with a 50% reduction in LFG to account for the loss value of leachate recirculation. Based on the same assumptions, the CPL could operate the EOD at full capacity (i.e., 150 gallons of leachate per hour) in the year 2014 when LFG flow rates reach 55 cfm. FTE’s quote for the 150 GPH EOD is included in Attachment H. Final closure of the lined landfill will proceed in phases with the partial final closure of each cell. Therefore, the maximum expected leachate generation flow rate will occur when Cell 1 is in operation because this cell has the largest planned footprint (approximately 9.3 acres). Leachate generation for Cell 1 of the lined landfill is estimated at 144 gallons per hour based on the leachate generation records for years 2007 through 2009 listed in Table 2 of the CPL’s RD&D Project 2009 Semi-Annual Report (July 1, 2009 – December 31, 2009) for years with leachate recirculation in Cell 1. This estimate calculates the average annual leachate generation increase for Cell 1 and incorporates a safety factor of 1.25. Leachate generation for Cell 1 of the lined landfill is estimated at 140 gallons per hour based on the rational method: (1) an annual average precipitation of 19 inches per year; (2) the current lined area is 9.3 acres; (3) no new areas are opened and/or closed; and (4) approximately 25% of precipitation becomes leachate. Kenai Peninsula Borough - CPL 23 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Given these assumptions, leachate evaporation may be a possible leachate management technique at the CPL. Based on FTE’s quote for the 150 GPH EOD, the estimated equipment cost for a leachate evaporation unit is roughly $161,000. This estimate includes shipping, and four days of system start-up and training provided by the manufacturer. This estimate does not include costs associated with engineering design, system installation, and/or the flare station if required to burn excess LFG. However, HDR does not recommend the use of leachate evaporation in lieu of leachate recirculation. Leachate recirculation provides many benefits to the CPL. Leachate recirculation increases waste disposal capacity due to more rapid decomposition and settlement of disposed waste. It also enhances LFG production rates that may lead to more gas recovery up front for energy use, as illustrated in the LandGEM model for the lined landfill. 6.2.1 Potential Direct Use Recipients The limiting factor for direct use projects is locating potential end-use recipients within a reasonable distance from the landfill. As the distance between the source and the end-user increases, so does the cost. To minimize this cost, industries or facilities located near the source are often the best candidates for these types of projects. While economics vary with project size and application, LFG pipelines as long as 20 miles are in commercial operation today. Some potential direct users of the lined landfill’s LFG (or a CHP project) are Skyview High School and the local ADOT&PF highway maintenance facility. These facilities are both located less than a mile away from the CPL. However, these pursuits may not be economically feasible because their energy demand (load) is not constant. The potential economic and social benefits from these projects should be investigated in further detail before the Borough selects these facilities as end-use recipients of LFG. Another option is the City of Soldotna’s WWTP located roughly 2.7 miles away from the landfill. The WWTP’s operations meets the criteria for 24/7 energy needs and could potentially benefit from the use of LFG in terms of electricity, fuel and/or heat. To further evaluate this option, the electrical and thermal load requirements at the WWTP would be required, along with their current rates for electricity and natural gas. HDR recommends conducting a feasibility study (similar to that of LFGTE projects) before pursuing any direct use project. 7. LANDFILL GAS CREDITS, INCENTIVES AND BONDS Landfill gas collection and control has the ability to provide owners the potential for generating revenue from credits and end-use projects such as gas-to-energy and direct use options. These renewable energy projects may be able to be financed through bonds, tax credits and/or grants. 7.1 Renewable Energy Credits As a result of higher fossil fuel prices, energy security interests, and increasing concern with global climate change, the federal government and some states have added and strengthened renewable energy programs. Since renewable energy projects are typically more costly than conventional power, government policy has, over the recent years, increased awareness and provided incentives for renewable energy projects. According to the EPA, as of March 2009 33 states plus the District of Columbia have adopted Renewable Portfolio Standards (RPS) to encourage or mandate renewable energy development. An RPS provides Kenai Peninsula Borough - CPL 24 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. states with a mechanism to increases renewable energy generation using a cost-effective, market-based approach. An RPS may require electric providers to supply their customers with a minimum load of electricity generated from eligible renewable energy sources. Landfill gas is considered an eligible technology under most state RPS requirements if the renewable energy project complies with the specified in-place service date (e.g., built after 1997 to encourage new and innovative renewable energy development). Renewable energy projects produce two distinct products: (1) electricity; and (2) Renewable Energy Credits (RECs). These products can be sold separately or bundled together. A REC represents the property rights to the environmental, social and other nonpower related qualities, termed attributes. These attributes are usually defined by policy under an RPS and are separate from the electric commodity. Typically, one REC corresponds to 1 MW-hour of electricity. RECs provide buyers with flexibility to support renewable energy development when that electricity is not available locally. RECs can be traded in a mandatory market established by a state RPS, or in a voluntary market if the REC meets the required specifications. Generally, there are three ways in which an electric supplier can comply with an RPS: (1) owning a renewable energy facility and its energy output; (2) purchasing unbundled RECs or electricity; or (3) purchasing bundled renewable electricity. Unfortunately, the CPL currently does not have the ability to collect RECs because Alaska has not adopted a state RPS. However, HEA has adopted a net metering standard designed to encourage the development of member-owned renewable energy systems. HEA will only bill participating members for their net energy consumption used (e.g., net energy consumption = HEA energy consumed - renewable energy supplied to HEA). If a member supplies more energy to HEA than they used in a billing cycle, then HEA will credit the member’s account. Regrettably, HEA has limited the qualifying renewable energy projects to just 25 kW of power generation. A LFGTE project at the CPL would exceed this power generation limit, and the landfill is most likely to produce more energy than it can consume for the duration of the project. HDR recommends talking to HEA and its community members because one of the seven cooperative principals it adheres to is concern for the community. This principle states that HEA will work for sustainable development of their community through policies accepted by their members. A LFGTE project at the CPL may qualify for such a policy vote. 7.2 Carbon Credits Landfill owners in the U.S. are realizing that their projects may meet the criteria to generate carbon credits through voluntary methane capture or abatement. Methane, one of the six primary greenhouse gases (GHGs), typically comprises approximately 50% by volume of LFG. The global warming potential of methane has been determined to be roughly 21-23 times that of carbon dioxide (i.e., CH4 entraps heat at a rate 21 times greater than the heat entrapment rate of CO2). In the United States, MSW landfills are the second largest source of anthropogenic methane emissions behind ruminant digestion. Landfills accounted for about 22% of these emissions in 2008, according to the EPA’s Landfill Methane Outreach Program (LMOP). Because of this fact, landfills have a significant opportunity to reduce GHG emissions. With growing concern over global climate change, international and domestic entities have established target goals for GHG reductions. In 1997, 161 countries completed negotiations for the Kyoto Protocol under United Nations oversight. This protocol includes target emission reductions with timetables for six Kenai Peninsula Borough - CPL 25 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. GHGs. For example, Canada agreed to set a target for 6 percent reduction of GHGs below their 1990 levels for the years 2008 through 2012. The Regional Greenhouse Gas Initiative (RGGI) is a market-based effort in the United States to cap and reduce GHG emissions. Ten participating Northeastern and Mid-Atlantic states agreed to cap and reduce their CO2 emissions from the power sector by 10 percent by 2018. The timing of the CO2 reductions correspond to capping emissions in 2009 through 2014, and reducing emissions by 2.5 percent annually from 2015 to 2018 for a total reduction of 10 percent. In 2006, California signed into law Assembly Bill 32 (AB 32): the Global Warming Solutions Act of 2006, which established a target goal of 25 percent GHG emission reductions by 2020. The GHG rules and market-based mechanisms for achieving this goal are being developed by the California Air Resources Board (ARB) and become effective in 2012. These international and domestic initiatives will most likely be based on a market-based compliance mechanism such as a credit trading program. Emission reduction trading (carbon credits) is an economic tool which allows a large number of parties to meet total emission reduction requirements at a lower cost by working together. Emission trading allows qualified surplus emission credits by a party to be traded to other parties needing to meet emission limits. The aim is to improve the overall flexibility and economic efficiency of obtaining emission reductions. Anyone can create an emission reduction and sell or trade this emission reduction in an open market trading system. To qualify for GHG emission reduction credits, a project has to demonstrate that the objective of the project is to mitigate climate change and be completed on a voluntary basis instead of because of regulatory compliance. Certain criteria have been developed to determine the validity and quality of a carbon credit (and therefore the price). The Voluntary Carbon Standards (VCS) Program and the Climate Action Reserve (CAR) are two programs that have developed regulatory-quality standards for the development, quantification and verification of voluntary emission offset projects. For instance, the CAR has published a Landfill Project Protocol for quantifying GHG emission credits. The Clean Development Mechanism (CDM), which operates under the Kyoto Protocol, allows developing countries with emission reduction projects to earn certified emission reduction (CER) credits if approved by the Designated National Authority. These CER credits can be traded or sold, and used by industrialized countries to meet some of their emission reduction targets under the Kyoto Protocol. This mechanism promotes sustainable development and emission reductions, while giving countries flexibility in how they meet their emission reduction targets. The VCS and CAR both operate registries for tracking emission reduction credits, from issuance to retirement, and are key operators in ensuring the credits are validated, verified and not double counted in open market trading systems. The price of GHG emission reduction credits varies depending on the project, its source of credit (e.g., VCS, CAR, CER), and the trading market. Prices are usually higher in Europe because of their more stringent carbon emission regulations. There are many open market emission trading groups established. Examples of North American groups are the CAR, the Chicago Climate Exchange (CCX), and the GHG Emission Reduction Trading (GERT) Pilot. Kenai Peninsula Borough - CPL 26 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. To reduce costs incurred by participating in an exchange market, some landfill owners choose to contract with an emission offset aggregator to represent the landfill on its behalf. Aggregators verify and trade GHG emission reduction credits associated with the destruction of methane in LFG. HDR’s experience working aggregators show credit values ranging from $2.00 to $4.50 per metric ton of carbon dioxide equivalent (tCO2e). The Green Exchange, a U.S. Commodity Future Trading Commission (CFTC) approved designated contract market for emission credit and allowance trading, shows 2010 future vintage credits in the CAR market trading between $2.00 to $4.00 per tCO2e. There is anticipation that the cost (and value) of carbon credits in the U.S. market will increase if a regulated cap and trade program goes into effect. HDR conducted a preliminary analysis of the LandGEM results for the lined landfill using the Landfill Project Protocol developed by the CAR. Assuming a LFG collection system efficiency of 75 percent and a net credit value of $4.00 per tCO2e, the Borough could realize potential revenue of approximately $28,000 in the year 2012. The duration of such a monetization depends upon the aggregator selected for the CPL’s project. HDR’s experience has shown some aggregators will offer a 5-year term for a project contract and assume all regulatory risks that may impact the value of the emission reduction credit. The Borough may benefit from such an arrangement with an emission reduction aggregator. The CPL may qualify for carbon credits if a LFGCCS is voluntarily installed rather than to fulfill a regulatory obligation. The carbon credits generated could become a source of revenue for the Borough. HDR recommends performing a carbon credit economic assessment to assist the Borough’s evaluation of this potential market. For the CPL to participate in a carbon credit market, they would need to install a LFGCCS and implement a quality monitoring program for the data collection needs of the market. This may include gas quality and quantity measuring and verification, and a third party review of the LFGCCS operation records, its destruction efficiency, and the facility’s regulatory status. This third party review will validate and verify the program’s compliance with a particular exchange market’s guidelines. HDR can assist the Borough with the design, installation, operation and monitoring of a LFGCCS, and help prepare the Borough for a third party review by an aggregator. 7.3 Clean Renewable Energy Bonds The federal Energy Tax Incentives Act of 2005 established clean renewable energy bonds (CREBs) as a financing mechanism for public sector renewable energy projects. CREBs may be issued by electric cooperatives, government entities (states, local governments, Indian tribal governments, or any other political subdivision thereof such as public universities), and by certain clean renewable energy bond lenders. Theoretically, CREBS are issued with a 0% interest rate. The borrower only pays back the principal on the bond, and the bondholder receives federal tax credits in lieu of traditional interest paid by the issuer. The 2005 Energy Act authorized the U.S. Treasury to allocate $800 million in tax credit bonds to be issued between January 1, 2006, and December 31, 2007. Through the Tax Relief and Health Care Act of 2006, an additional $400 million in CREB financing was made available for 2008. The Energy Improvement and Extension Act of 2008 and the American Recovery and Reinvestment Act of 2009 allocated a total of $2.2 billion for new CREB allocation. The expiration date for new CREB applications was August 4, 2009. A modification was incorporated into the CREB program as part of the Hiring Incentives to Restore Employment Act in June 2010. This modification allows cooperatives that issue CREBs to receive federal direct payments of allowances of federal tax credits to subsidize a prescribed portion of their Kenai Peninsula Borough - CPL 27 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. borrowing costs instead of federal tax credits that would otherwise be directed to the bondholder. The goal of this modification is to enhance the likelihood of issuing bonds at a reduced interest rate. In September 2010, a new solicitation (IRS Announcement 2010-54) was issued for approximately $900 million in unallocated new CREBs for qualified projects to be issued by electrical cooperatives. The deadline for electrical cooperatives to submit an application is November 1, 2010. The old CREBs and new CREBS under the acts of 2008 and 2009 are either no longer available or have been issued already. The only CREBs available to the Borough are those that fall under the IRS Announcement 2010-54. Therefore, if the Borough is interested in purchasing these new CREBs, they need to encourage HEA to apply to become an authorized issuer, or find another qualifying electrical cooperative that can issue these new CREBs. 7.4 Federal Production Tax Credits Section 45 tax credits are a corporate tax measure that allows renewable energy projects to qualify for federal production tax credits. In recent years, these federal production tax credits have been one of the single largest drivers for LFGTE projects. The American Jobs Creation Act of 2004 expanded the Section 45 tax credits to include LFGTE projects. The Energy Policy Act of 2005 expanded the credit term for these federal production tax credits from 5 to 10 years. The American Recovery and Reinvestment Act of 2009 (ARRA) provides additional tax incentives for LFGTE projects. The new law extends the eligibility dates of a federal production tax credit for facilities producing electricity from renewable energy sources. The place-in-service date for LFGTE projects was extended to December 31, 2013 (ARRA, Section 1101). Section 1102 of the ARRA gave businesses who place in service facilities that generate electricity from renewable energy sources after December 31, 2008 a choice between either an energy investment tax credit, which normally provides a 30 percent tax credit for the investment in an energy project or the federal production tax credit that can provide a credit of up to 2.1 cents per kW-hour. Naturally, a business cannot claim both of these tax credits. The Borough may qualify for Section 45 tax credits for a ten year period if the place-in-service date for a LFGTE project at the CPL is before December 31, 2013 deadline. Based on the preliminary LFGTE analysis for IC engines, the Borough may qualify for federal production tax credits in the range of $44,000 to $97,000 per year depending upon whether one or two 350 kW IC units are in operation and are operating at full load capacity. 7.5 Alaska Renewable Energy Grants In 2008, the State of Alaska established a renewable energy grant fund and authorized the Alaska Energy Authority (AEA) to distribute renewable energy grants based on qualifying criteria and procedures. The AEA has already completed three funding cycles (2008 through 2010) and accepted applications for the fourth round of funding for the 2011 funding cycle. The application deadline for the fourth round was September 15, 2010. Funding for projects is limited by the phase of the project, and is limited to $2 million or $4 million depending upon the location of the project during one Renewable Energy Fund round. A January 1, 2010, status report by AEA states that over three rounds funding applications, 353 applications requesting $970.9 million were reviewed. So far, roughly 103 projects have been appropriated grant funds during rounds 1 and 2 totaling approximately $125 million. In February 2010, Kenai Peninsula Borough - CPL 28 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. the AEA made amended recommendations for the Renewable Energy Fund Round III to the state legislative body. The AEA recommended funding for up to 90 projects totaling $65.8 million. The Alaska Renewable Energy Grants may be another option for funding for the Borough if they pursue a LFGTE project. It is expected that additional rounds of funding will become available in the future if the renewable energy portfolio of the AEA is expanded. However, the Borough should be aware that any funding received through grants may potentially impact the ability to collect Section 45 tax credits for a LFGTE project. The Alaska Legislature has also established a new grant program to be administered by the AEA, the Emerging Energy Technology Fund Grant Program. The AEA is currently working on regulations, an application, and associated documents to implement this program. Under this program, the AEA may make grants available to eligible applicants for demonstration projects of technologies that could become commercially viable within five years. These demonstration projects are designed to: (1) test emerging technologies/methods for energy conservation; (2) improve existing energy technology; or (3) deploy an energy technology (new or existing) that has not previously been tested in Alaska. 8. CONCLUSIONS AND RECOMMENDATIONS HDR was tasked by the Kenai Peninsula Borough (Borough) to develop a Landfill Gas Management Plan (LFGMP) for the Central Peninsula Landfill (CPL). The purpose of this LFGMP is to provide the Borough with a plan for landfill gas management at the CPL that complies with, or will lead to compliance with, applicable State and Federal regulations. The following is a summary of our conclusions and recommendations as discussed in this LFGMP: 8.1 Site Background and Operations The Baseline Assessment sampling results for the unlined landfill indicate high quality LFG being emitted from the passive venting system. Although sample results indicate good methane concentrations, the passive venting system was not designed or intended to be retrofitted for use in an active collection system. Based on the Baseline Assessment of the lined landfill, the existing horizontal LFG collection wells in the lined landfill do not appear to be functional for use in an active gas collection system. The 6-inch LFG header pipe installed around Cell 1’s perimeter may be undersized to accommodate potential LFG flow rates. Furthermore, the 2-inch lateral lines in the junction boxes may be insufficient for connection to extraction devices (gas movers). 8.2 Air Regulatory Status Based on a preliminary estimate of greenhouse gas (GHG) emissions, the Mandatory GHG Reporting Rule applies to the CPL. Annual reporting of GHG emissions will commence with the 2010 calendar year, and the first report is due on March 31, 2010. Based on the results of the draft Design Capacity Report, the CPL is not in violation of NSPS regulations other than not meeting the submittal deadlines for the initial and Cell 1 updated design capacity reports. The Borough should finalize and submit the Design Capacity Report to the ADEC within 90 days following issuance of the Cell 2 Construction permit. The CPL’s design capacity is not forecasted to exceed regulatory thresholds until the Cell 5 expansion is permitted. The Borough should track the design capacity of the CPL by performing the annual Kenai Peninsula Borough - CPL 29 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. recalculations required by 40 CFR 60.758(f). When the design capacity of the CPL exceeds regulatory thresholds and the CPL becomes a NSPS site, the Borough will be required to apply for a Title V permit with the ADEC Division of Air Quality in compliance with 18 AAC 50.326. The Borough should meet with the ADEC Division of Air Quality to discuss the facility, the Design Capacity Report, and the current regulatory status of the landfill. Although not critical, the Borough should invite the appropriate ADEC Solid Waste personnel to this meeting to keep them informed of landfill operations and planning. 8.3 Conceptual Landfill Gas Collection and Control Plan While not a regulatory requirement at this time, the Borough chose to move forward with the preparation of a conceptual LFGCCS Plan. HDR developed the conceptual design of a LFGCCS based on NSPS requirements for the final build-out of the lined landfill (i.e., Cells 1-5). The LFGCCS Plan provides the conceptual design of a LFG management system that will collect, transmit and dispose of LFG generated at the lined landfill. HDR determined it was impractical to include the unlined landfill in a LFGCCS based on declining LFG generation estimates, the NSPS regulatory status of the CPL, and the financial commitment necessary to collect LFG from the unlined landfill. This assessment should be reevaluated in the future when feasibility studies for potential LFG end-use opportunities are conducted, if those studies show a financial benefit to including the unlined landfill in an end-use program The active collection system for the lined landfill has been sized to handle a conservative estimate of the maximum LFG generation flow rate expected in the year 2035 of 581 cfm. HDR recommends installing an additional header pipe within the waste between Cells 1 and 2 as a loop for improved system performance. Additionally, the Borough is recommended to update their RD&D permit for leachate recirculation at the lined landfill to include gas condensate. The system is designed so that it can be expanded in phases as the lined landfill is developed. As cells are developed, interim headers can be installed between the cells to create individual loops. This design approach makes the system redundant at full build-out. This added safety measure provides flexibility in the system in case the main header loops become compromised or impeded. The gas mover (blower) and control device (candlestick flare) has been sized to handle the maximum gas flow rate of 368 cfm expected between years 2012 through 2026. The flare station is to be located on the south side of the lined landfill where originally planned during Cell 1 construction. This location can easily be modified in the future if the Borough would like a different location due to landfill operations and/or power supply issues. The LFGMP also includes an outline of the technical specifications required for the LFGCCS, and a preliminary engineer’s probable cost estimate. The technical specification outline is included under Attachment I. The preliminary cost estimate for the design and construction of a LFGCCS at the lined landfill is included in Attachment J. The total estimated construction cost is approximately $4,910,00. This estimate includes design and construction management assistance, startup and testing services, and project contingency. Kenai Peninsula Borough - CPL 30 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. 8.4 Landfill Gas End-Use Opportunities During the past 30 years, significant advancements have been made in landfill gas conversion technologies to turn LFG into profitable and environmentally friendly beneficial end-uses. The selection of a recovery technique versus a control technique is highly dependent on such factors such as the LFG generation rate, the market availability for recovered energy, and environmental impacts. If landfill characteristics are such that the landfill does not produce enough LFG to make gas recovery economically feasible, control through flaring may be the best suited option for the landfill. Likewise, if there are no customers for the generated electricity or LFG supply, energy recovery systems are not feasible.HDR recommends that a feasibility study and economic analysis be conducted before pursuing a LFGTE or direct use project to ensure its viability. The beneficiaries of these projects can either be the landfill itself or other end-user candidates. Some potential direct users of the CPL’s LFG (or a CHP project) are Skyview High School, the local ADOT&PF highway maintenance facility, and the City of Soldotna’s WWTP. Another potential end-use opportunity is to use the generated LFG onsite for leachate evaporation as an additive leachate management technique at the CPL. Leachate evaporation systems are generally only feasible at landfills that have an adequate supply of LFG to evaporate the volume of leachate generated. However, HDR does not recommend the use of leachate evaporation in lieu of leachate recirculation. Leachate recirculation provides many benefits to the CPL such as increased waste disposal capacity and enhanced LFG production rates. HDR recommends that a feasibility study and economic analysis be conducted before pursuing a leachate evaporation system to ensure its viability. 8.5 Landfill Gas Credits, Incentives and Bonds Landfill gas collection and control has the ability to provide the potential for generating revenue from credits and end-use projects such as gas-to-energy and direct use options. These renewable energy projects may be able to be financed through bonds, tax credits and/or grants. The CPL currently does not have the ability to collect Renewable Energy Credits (RECs) because Alaska has not adopted a state Renewable Portfolio Standard (RPS). However, Homer Electric Association (HEA) has adopted a net metering standard designed to encourage the development of member-owned renewable energy systems. Regrettably, HEA has limited the qualifying renewable energy projects to just 25 kW of power generation. The Borough is recommended to talk to HEA and its community members about the potential for a LFGTE project at the CPL. The CPL may qualify for carbon credits if a LFGCCS is voluntarily installed rather than to fulfill a regulatory obligation. The carbon credits generated could become a source of revenue for the Borough. HDR recommends performing a carbon credit economic assessment to assist the Borough’s evaluation of this potential market. The only clean renewable energy bonds (CREBs) available to the Borough are those that fall under the IRS Announcement 2010-54. Therefore, if the Borough is interested in purchasing these new CREBs, they need to encourage HEA to apply to become an authorized issuer, or find another qualifying electrical cooperative that can issue these new CREBs. Section 45 tax credits are a corporate tax measure that allows renewable energy projects to qualify for federal production tax credits. The Borough may qualify for Section 45 tax credits for a ten year period if the place-in-service date for a LFGTE project at the CPL is before December 31, 2013 deadline. Kenai Peninsula Borough - CPL 31 November 2010 Landfill Gas Management Plan HDR Alaska, Inc. The Alaska Renewable Energy Grants may be another option for funding for the Borough if they pursue a LFGTE project. It is expected that additional rounds of funding will become available in the future if the renewable energy portfolio of the Alaska Energy Authority (AEA) is expanded. However, the Borough should be aware that any funding received through grants may potential impact the ability to collect Section 45 tax credits for a LFGTE project. 8.6 Proposed Timeline for Schedule of Activities To assist the Borough with evaluation of the LFGMP, HDR prepared a preliminary schedule for addressing air regulatory compliance issues, carbon credit and grant funding, and the design, construction and startup of a LFGCCS. This proposed timeline is included in Attachment K. The timeline shows regulatory compliance activities the Borough must perform in 2010 and 2011, and provides generic sequencing of events for the implementation of a LFGCCS. Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Tables TABLE 1DESIGN CAPACITY ESTIMATE FOR THE CENTRAL PENINSULA LANDFILLDisposal Area Approx. Years of OperationTotal Volume (yd3) Volume of Daily Cover (yd3) Waste Volume (ft3)Weight of Waste (tons)Total Design Capacity (m3)Total Design Capacity (Mg)Unlined Landfill1,2Non-Baled Waste1969 - 1992 848,496 169,699 678,797 448,854 519,076 407,111 Baled Waste1992 - 2007 773,504 77,350 696,154 649,744 1,051,425 996,429 Lined Landfill3,4,5Cell 12005 - 2013 653,000 130,600 522,400 391,800 1,450,904 1,351,791 Cell 22012 - 2018 535,000 107,000 428,000 321,000 1,778,195 1,642,938 Cell 32017 - 2023 532,000 106,400 425,600 319,200 2,103,652 1,932,453 Cell 42022 - 2028 527,000 105,400 421,600 316,200 2,426,049 2,219,246 Cell 52027 - 2034 654,000 130,800 523,200 392,400 2,826,140 2,575,153 Conversion Factors0.907 megagrams/tons conversion factor0.7647 cubic meters/cubic yards conversion factorNotes1. For non-baled waste in the unlined landfill:a. Total Volume reported is from the GHG Monitoring Plan (Ref. 4), which correlates to the total volume capacity from Ref. 1b. The cover soil to waste volume ratio is estimated at 1:4 (20% of Total Volume) from Table 1 of CPL's RD&D Report (Ref. 3)c. The waste density is estimated at at 1,058 lbs of waste / cy of total volume from Table 1 of CPL's RD&D Report (Ref. 3)2. For baled waste in the unlined landfill:a. Total Volume reported is from the GHG Monitoring Plan (Ref. 4), which correlates to the total volume capacity from Ref. 1b. Volume of Cover Soil is estimated at 10 percent of Total Volumec. Weight of Waste is from scale records reported in the GHG Monitoring Plan (Ref. 4)3. For Cell 1 of the lined landfill:a. Total Volume reported is from CH2M-Hill's Schematic-Phase Design Basis Report (Ref. 2)c. The waste density is estimated at at 1,200 lbs of waste / cy of total volume from Table 1 of CPL's RD&D Report for years with leachate recirculation (Ref. 3)4. For Cell 2 of the lined landfill:a. Total Volume reported is from CH2M-Hill's Schematic-Phase Design Basis Report (Ref. 2)b. The cover soil to waste volume ratio is estimated at 1:4 from Table 1 of CPL's RD&D Report (Ref. 3)c. The waste density is estimated at at 1,200 lbs of waste / cy of total volume from Table 1 of CPL's RD&D Report for years with leachate recirculation (Ref. 3)5. For Cells 3 through 5 of the lined landfill:a. Total Volume reported is from CH2M-Hill's Schematic-Phase Design Basis Report (Ref. 2)b. The cover soil to waste volume ratio is estimated at 1:4 from Table 1 of CPL's RD&D Report (Ref. 3)c. The waste density is estimated at at 1,200 lbs of waste / cy of total volume from Table 1 of CPL's RD&D Report for years with leachate recirculation (Ref. 3)ReferencesReference 1: MACTEC. (2005, January 14). Technical Memorandum CPLC-8. Anchorage, Alaska.Reference 2: CH2M Hill. (2009, December 22). Schematic-Phase Design Basis Report Draft.Reference 3: Kenai Peninsula Borough, Solid Waste Department. (2010, February 1). Research, Development and Demonstration Project Report. Soldotna, Alaska. Reference 4: HDR Alaska, Inc. (2010, April). Greenhouse Gas Monitoring Plan. Anchorage , Alaska.b. The cover soil to waste volume ratio is estimated at 1:4 (20% of Total Volume) from Table 1 of CPL's RD&D Report (Ref. 3), which correlates to the GHG Monitoring Plan's assumption Kenai Peninsula Borough - CPLLandfill Gas Management PlanPage 1 of 1November 2010HDR Alaska, Inc. TABLE 2VERTICAL GAS EXTRACTION WELL SCHEDULE FOR THE LINED LANDFILL(SEE ATTACHMENT A)Well ID Northing EastingFinal Grade(ft AMSL)Base Grade (ft AMSL)Waste Depth (ft)Drill Depth (ft)Total HDPE Pipe (ft)Solid Pipe (ft)Perforated Pipe (ft)Stick Up (ft)EW-1 8908 10196 32025268 5356 1042 4EW-2 9110 10163 31825167 5255 1041 4EW-3 9281 10170 32024971 5659 1045 4EW-4 9393 10305 31124467 5255 1041 4EW-5 9537 10401 31124071 5659 1045 4EW-6 9463 10566 31824276 6164 1050 4EW-7 9285 10409 33624393 7881 1067 4EW-8 9092 10321 33524788 7376 1062 4EW-9 8836 10370 32525768 5356 1042 4EW-10 9015 10521 33625580 6568 1054 4EW-11 9213 10638 33525284 6972 1058 4EW-12 9385 10748 32024872 5760 1046 4EW-13 9306 10931 32325270 5558 1044 4EW-14 9137 10841 33525679 6467 1053 4EW-15 8936 10721 33626076 6164 1050 4EW-16 8763 10544 32326260 4548 1034 4EW-17 8690 10717 31926652 3740 1026 4EW-18 8860 10900 33626472 5760 1046 4EW-19 9071 11044 33426075 6063 1049 4EW-20 9228 11114 32525669 5457 1043 4EW-21 9150 11296 32726067 5255 1041 4EW-22 8984 11233 33426470 5558 1044 4EW-23 8792 11075 33626769 5457 1043 4EW-24 8617 10891 31527045 3033 1019 4EW-25 8560 11037 31927346 3134 1020 4EW-26 8604 11207 31827445 3033 1019 4EW-27 8819 11300 33926970 5558 1044 4EW-28 9075 11473 32726462 4750 1036 4EW-29 8939 11485 32426856 4144 1030 4EW-30 8765 11481 32127249 3437 1023 4EW-31 8663 11387 32027446 3134 1020 4TOTALS 16181711 3101277 124NOTES:1. Northing and Easting coordinates based on 2009 aerial topography provided by Kenai Peninsula Borough.2. Base grades are based on Cell 1 as-builts and CH2M-Hill's conceptual base grading plans for Cells 2 through 5.3. Final grades are based on URS's conceptual closure plan for the lined landfill.4. Location of wells may vary based on field conditions.5. All vertical wells are 6" diameter HDPE SDR 11 and shall have 10 feet of solid piping to mimize air intrusion. Solid pipe totals do not include stick up.6. Actual perforations and solid pipe length may vary based on field conditions.Kenai Peninsula Borough - CPLLandfill Gas Management PlanPage 1 of 1November 2010HDR Alaska, Inc. Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment A Conceptual Design Drawings Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment B LandGEM Modeling Results for the Unlined Landfill Attachment B - LandGEM - Unlined LF 11/17/2010 Summary Report Landfill Name or Identifier: KPB Unlined Landfill Date: Wednesday, November 17, 2010 Description/Comments: Waste tonnages are from the historical records at the CPL and coincide with the values presented in HDR’s GHG Monitoring Plan and draft Design Capacity Report. Methane generation rate constant (k) is 0.02/year for drier areas such as Soldotna that receive less than 25 inches of rain annually per AP-42. Methane generation potential (Lo) is 100 m3/Mg REPORT - 1 First-Order Decomposition Rate Equation: Where, QCH4 = annual methane generation in the year of the calculation (m 3 /year )i = 1-year time increment Mi = mass of waste accepted in the ith year (Mg ) n = (year of the calculation) - (initial year of waste acceptance) j = 0.1-year time increment k = methane generation rate (year -1 ) Lo = potential methane generation capacity (m 3 /Mg ) tij = age of the jth section of waste mass Mi accepted in the ith year (decimal years , e.g., 3.2 years) LandGEM is considered a screening tool — the better the input data, the better the estimates. Often, there are limitations with the available data regarding waste quantity and composition, variation in design and operating practices over time, and changes occurring over time that impact the emissions potential. Changes to landfill operation, such as operating under wet conditions through leachate recirculation or other liquid additions, will result in generating more gas at a faster rate. Defaults for estimating emissions for this type of operation are being developed to include in LandGEM along with defaults for convential landfills (no leachate or liquid additions) for developing emission inventories and determining CAA applicability. Refer to the Web site identified above for future updates. LandGEM is based on a first-order decomposition rate equation for quantifying emissions from the decomposition of landfilled waste in municipal solid waste (MSW) landfills. The software provides a relatively simple approach to estimating landfill gas emissions. Model defaults are based on empirical data from U.S. landfills. Field test data can also be used in place of model defaults when available. Further guidance on EPA test methods, Clean Air Act (CAA) regulations, and other guidance regarding landfill gas emissions and control technology requirements can be found at http://www.epa.gov/ttnatw01/landfill/landflpg.html. as So dot a t at ece e ess t a 5 c es o a a ua y pe et a e ge e at o pote t a ( o) s 00 3/ g of refuse per AP-42. About LandGEM: REPORT - 1 Attachment B - LandGEM - Unlined LF 11/17/2010 Input Review LANDFILL CHARACTERISTICS Landfill Open Year 1969 Landfill Closure Year (with 80-year limit)2007 Actual Closure Year (without limit)2007 Have Model Calculate Closure Year?No Waste Design Capacity 1,098,598 short tons MODEL PARAMETERS Methane Generation Rate, k 0.020 year -1 Potential Methane Generation Capacity, Lo 100 m 3 /Mg NMOC Concentration 4,000 ppmv as hexane Methane Content 50 % by volume GASES / POLLUTANTS SELECTED Gas / Pollutant #1:Total landfill gas Gas / Pollutant #2:Methane Gas / Pollutant #3:Carbon dioxide Gas / Pollutant #4:NMOC WASTE ACCEPTANCE RATES (Mg/year) (short tons/year) (Mg) (short tons) 1969 16,945 18,639 0 0 1970 16,945 18,639 16,945 18,639 1971 16,945 18,639 33,889 37,278 1972 16,945 18,639 50,834 55,917 1973 16,945 18,639 67,778 74,556 1974 16,945 18,639 84,723 93,195 1975 16,945 18,639 101,667 111,834 1976 16,945 18,639 118,612 130,473 1977 16,945 18,639 135,556 149,112 1978 16,945 18,639 152,501 167,751 1979 16,945 18,639 169,445 186,390 1980 16 945 18 639 186 390 205 029 Year Waste Accepted Waste-In-Place REPORT - 2 1980 16,945 18,639 186,390 205,029 1981 16,945 18,639 203,335 223,668 1982 16,945 18,639 220,279 242,307 1983 16,945 18,639 237,224 260,946 1984 16,945 18,639 254,168 279,585 1985 16,945 18,639 271,113 298,224 1986 16,945 18,639 288,057 316,863 1987 16,945 18,639 305,002 335,502 1988 16,945 18,639 321,946 354,141 1989 16,945 18,639 338,891 372,780 1990 16,945 18,639 355,835 391,419 1991 16,945 18,639 372,780 410,058 1992 30,275 33,302 389,725 428,697 1993 36,592 40,251 419,999 461,999 1994 35,163 38,679 456,591 502,250 1995 40,188 44,207 491,754 540,929 1996 38,348 42,183 531,942 585,136 1997 49,493 54,442 570,290 627,319 1998 38,265 42,092 619,783 681,761 1999 40,439 44,483 658,048 723,853 2000 45,343 49,877 698,487 768,336 2001 40,952 45,047 743,830 818,213 2002 41,817 45,999 784,782 863,260 2003 41,110 45,221 826,599 909,259 2004 39,745 43,719 867,709 954,480 2005 39,345 43,279 907,454 998,199 2006 41,893 46,082 946,798 1,041,478 2007 41,389 45,528 988,691 1,087,560 2008 0 0 1,030,080 1,133,088 REPORT - 2 Attachment B - LandGEM - Unlined LF 11/17/2010 WASTE ACCEPTANCE RATES (Continued) (Mg/year) (short tons/year) (Mg) (short tons) 2009 0 0 1,030,080 1,133,088 2010 0 0 1,030,080 1,133,088 2011 0 0 1,030,080 1,133,088 2012 0 0 1,030,080 1,133,088 2013 0 0 1,030,080 1,133,088 2014 0 0 1,030,080 1,133,088 2015 0 0 1,030,080 1,133,088 2016 0 0 1,030,080 1,133,088 2017 0 0 1,030,080 1,133,088 2018 0 0 1,030,080 1,133,088 2019 0 0 1,030,080 1,133,088 2020 0 0 1,030,080 1,133,088 2021 0 0 1,030,080 1,133,088 2022 0 0 1,030,080 1,133,088 2023 0 0 1,030,080 1,133,088 2024 0 0 1,030,080 1,133,088 2025 0 0 1,030,080 1,133,088 2026 0 0 1,030,080 1,133,088 2027 0 0 1,030,080 1,133,088 2028 0 0 1,030,080 1,133,088 2029 0 0 1,030,080 1,133,088 2030 0 0 1,030,080 1,133,088 2031 0 0 1,030,080 1,133,088 2032 0 0 1,030,080 1,133,088 2033 0 0 1,030,080 1,133,088 2034 0 0 1,030,080 1,133,088 2035 0 0 1,030,080 1,133,088 2036 0 0 1,030,080 1,133,088 2037 0 0 1,030,080 1,133,088 2038 0 0 1,030,080 1,133,088 2039 0 0 1,030,080 1,133,088 2040 0 0 1,030,080 1,133,088 2041 0 0 1,030,080 1,133,088 Year Waste Accepted Waste-In-Place REPORT - 3 2042 0 0 1,030,080 1,133,088 2043 0 0 1,030,080 1,133,088 2044 0 0 1,030,080 1,133,088 2045 0 0 1,030,080 1,133,088 2046 0 0 1,030,080 1,133,088 2047 0 0 1,030,080 1,133,088 2048 0 0 1,030,080 1,133,088 REPORT - 3 Attachment B - LandGEM - Unlined LF 11/17/2010 Pollutant Parameters Concentration Concentration Compound (ppmv )Molecular Weight (ppmv )Molecular Weight Total landfill gas 0.00 Methane 16.04 Carbon dioxide 44.01 NMOC 4,000 86.18 1,1,1-Trichloroethane (methyl chloroform) - HAP 0.48 133.41 1,1,2,2- Tetrachloroethane - HAP/VOC 1.1 167.85 1,1-Dichloroethane (ethylidene dichloride) - HAP/VOC 2.4 98.97 1,1-Dichloroethene (vinylidene chloride) - HAP/VOC 0.20 96.94 1,2-Dichloroethane (ethylene dichloride) - HAP/VOC 0.41 98.96 1,2-Dichloropropane (propylene dichloride) - HAP/VOC 0.18 112.99 2-Propanol (isopropyl alcohol) - VOC 50 60.11 Acetone 7.0 58.08 Acrylonitrile - HAP/VOC 6.3 53.06 Benzene - No or Unknown Co-disposal - HAP/VOC 1.9 78.11 Benzene Co disposal Gas / Pollutant Default Parameters:User-specified Pollutant Parameters:GasesREPORT - 4 Benzene - Co-disposal - HAP/VOC 11 78.11 Bromodichloromethane - VOC 3.1 163.83 Butane - VOC 5.0 58.12 Carbon disulfide - HAP/VOC 0.58 76.13 Carbon monoxide 140 28.01 Carbon tetrachloride - HAP/VOC 4.0E-03 153.84 Carbonyl sulfide - HAP/VOC 0.49 60.07 Chlorobenzene - HAP/VOC 0.25 112.56 Chlorodifluoromethane 1.3 86.47 Chloroethane (ethyl chloride) - HAP/VOC 1.3 64.52 Chloroform - HAP/VOC 0.03 119.39 Chloromethane - VOC 1.2 50.49 Dichlorobenzene - (HAP for para isomer/VOC)0.21 147 Dichlorodifluoromethane 16 120.91 Dichlorofluoromethane - VOC 2.6 102.92 Dichloromethane (methylene chloride) - HAP 14 84.94 Dimethyl sulfide (methyl sulfide) - VOC 7.8 62.13 Ethane 890 30.07 Ethanol - VOC 27 46.08Pollutants REPORT - 4 Attachment B - LandGEM - Unlined LF 11/17/2010 Pollutant Parameters (Continued) Concentration Concentration Compound (ppmv )Molecular Weight (ppmv )Molecular Weight Ethyl mercaptan (ethanethiol) - VOC 2.3 62.13 Ethylbenzene - HAP/VOC 4.6 106.16 Ethylene dibromide - HAP/VOC 1.0E-03 187.88 Fluorotrichloromethane - VOC 0.76 137.38 Hexane - HAP/VOC 6.6 86.18 Hydrogen sulfide 36 34.08 Mercury (total) - HAP 2.9E-04 200.61 Methyl ethyl ketone - HAP/VOC 7.1 72.11 Methyl isobutyl ketone - HAP/VOC 1.9 100.16 Methyl mercaptan - VOC 2.5 48.11 Pentane - VOC 3.3 72.15 Perchloroethylene (tetrachloroethylene) - HAP 3.7 165.83 Propane - VOC 11 44.09 t-1,2-Dichloroethene - VOC 2.8 96.94 Toluene - No or Unknown Co-disposal - HAP/VOC 39 92.13 Toluene - Co-disposal - HAP/VOC 170 92.13 Trichloroethylene (trichloroethene)- User-specified Pollutant Parameters:Gas / Pollutant Default Parameters:sREPORT - 5 (trichloroethene) - HAP/VOC 2.8 131.40 Vinyl chloride - HAP/VOC 7.3 62.50 Xylenes - HAP/VOC 12 106.16Pollutants REPORT - 5 Attachment B - LandGEM - Unlined LF 11/17/2010 REPORT - 6REPORT - 6 Attachment B - LandGEM - Unlined LF 11/17/2010 Graphs 0.000E+00 5.000E+02 1.000E+03 1.500E+03 2.000E+03 2.500E+03 3.000E+03 3.500E+03 4.000E+03 4.500E+03 EmissionsYear Megagrams Per Year Total landfill gas Methane Carbon dioxide NMOC 0.000E+00 5.000E+05 1.000E+06 1.500E+06 2.000E+06 2.500E+06 3.000E+06 3.500E+06 EmissionsCubic Meters Per Year REPORT - 7 0.000E+00 5.000E+02 1.000E+03 1.500E+03 2.000E+03 2.500E+03 3.000E+03 3.500E+03 4.000E+03 4.500E+03 EmissionsYear Megagrams Per Year Total landfill gas Methane Carbon dioxide NMOC 0.000E+00 5.000E+05 1.000E+06 1.500E+06 2.000E+06 2.500E+06 3.000E+06 3.500E+06 EmissionsYear Cubic Meters Per Year Total landfill gas Methane Carbon dioxide NMOC 0.000E+00 5.000E+01 1.000E+02 1.500E+02 2.000E+02 2.500E+02 EmissionsYear User-specified Unit (units shown in legend below) Total landfill gas (av ft^3/min)Methane (av ft^3/min)Carbon dioxide (av ft^3/min)NMOC (av ft^3/min) REPORT - 7 Attachment B - LandGEM - Unlined LF 11/17/2010 Results (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 1969 0 00000 1970 8.389E+01 6.717E+04 4.513E+00 2.241E+01 3.359E+04 2.257E+00 1971 1.661E+02 1.330E+05 8.937E+00 4.437E+01 6.651E+04 4.469E+00 1972 2.467E+02 1.976E+05 1.327E+01 6.590E+01 9.878E+04 6.637E+00 1973 3.257E+02 2.608E+05 1.752E+01 8.700E+01 1.304E+05 8.762E+00 1974 4.031E+02 3.228E+05 2.169E+01 1.077E+02 1.614E+05 1.085E+01 1975 4.790E+02 3.836E+05 2.577E+01 1.280E+02 1.918E+05 1.289E+01 1976 5.534E+02 4.432E+05 2.978E+01 1.478E+02 2.216E+05 1.489E+01 1977 6.264E+02 5.016E+05 3.370E+01 1.673E+02 2.508E+05 1.685E+01 1978 6.979E+02 5.588E+05 3.755E+01 1.864E+02 2.794E+05 1.877E+01 1979 7.679E+02 6.149E+05 4.132E+01 2.051E+02 3.075E+05 2.066E+01 1980 8.366E+02 6.699E+05 4.501E+01 2.235E+02 3.350E+05 2.251E+01 1981 9.039E+02 7.238E+05 4.863E+01 2.414E+02 3.619E+05 2.432E+01 1982 9.699E+02 7.767E+05 5.218E+01 2.591E+02 3.883E+05 2.609E+01 1983 1.035E+03 8.285E+05 5.566E+01 2.764E+02 4.142E+05 2.783E+01 1984 1.098E+03 8.792E+05 5.907E+01 2.933E+02 4.396E+05 2.954E+01 1985 1.160E+03 9.290E+05 6.242E+01 3.099E+02 4.645E+05 3.121E+01 1986 1.221E+03 9.778E+05 6.570E+01 3.262E+02 4.889E+05 3.285E+01 1987 1.281E+03 1.026E+06 6.891E+01 3.421E+02 5.128E+05 3.445E+01 1988 1.339E+03 1.072E+06 7.206E+01 3.577E+02 5.362E+05 3.603E+01 1989 1.397E+03 1.118E+06 7.514E+01 3.731E+02 5.592E+05 3.757E+01 1990 1.453E+03 1.163E+06 7.817E+01 3.881E+02 5.817E+05 3.908E+01 1991 1.508E+03 1.208E+06 8.113E+01 4.028E+02 6.038E+05 4.057E+01 1992 1.562E+03 1.251E+06 8.404E+01 4.172E+02 6.254E+05 4.202E+01 1993 1.681E+03 1.346E+06 9.044E+01 4.490E+02 6.730E+05 4.522E+01 1994 1.829E+03 1.464E+06 9.840E+01 4.885E+02 7.322E+05 4.920E+01 1995 1.967E+03 1.575E+06 1.058E+02 5.253E+02 7.874E+05 5.291E+01 1996 2.127E+03 1.703E+06 1.144E+02 5.681E+02 8.515E+05 5.721E+01 1997 2.274E+03 1.821E+06 1.224E+02 6.075E+02 9.106E+05 6.119E+01 1998 2.474E+03 1.981E+06 1.331E+02 6.609E+02 9.907E+05 6.657E+01 1999 2.615E+03 2.094E+06 1.407E+02 6.985E+02 1.047E+06 7.034E+01 2000 2 763E+03 2 213E+06 1 487E+02 7 381E+02 1 106E+06 7 434E+01 Year Total landfill gas Methane REPORT - 8 2000 2.763E+03 2.213E+06 1.487E+02 7.381E+02 1.106E+06 7.434E+01 2001 2.933E+03 2.349E+06 1.578E+02 7.834E+02 1.174E+06 7.890E+01 2002 3.078E+03 2.464E+06 1.656E+02 8.221E+02 1.232E+06 8.279E+01 2003 3.224E+03 2.581E+06 1.734E+02 8.611E+02 1.291E+06 8.672E+01 2004 3.363E+03 2.693E+06 1.810E+02 8.984E+02 1.347E+06 9.048E+01 2005 3.494E+03 2.798E+06 1.880E+02 9.332E+02 1.399E+06 9.398E+01 2006 3.619E+03 2.898E+06 1.947E+02 9.667E+02 1.449E+06 9.736E+01 2007 3.755E+03 3.007E+06 2.020E+02 1.003E+03 1.503E+06 1.010E+02 2008 3.886E+03 3.111E+06 2.091E+02 1.038E+03 1.556E+06 1.045E+02 2009 3.809E+03 3.050E+06 2.049E+02 1.017E+03 1.525E+06 1.025E+02 2010 3.733E+03 2.989E+06 2.009E+02 9.972E+02 1.495E+06 1.004E+02 2011 3.659E+03 2.930E+06 1.969E+02 9.774E+02 1.465E+06 9.844E+01 2012 3.587E+03 2.872E+06 1.930E+02 9.581E+02 1.436E+06 9.649E+01 2013 3.516E+03 2.815E+06 1.892E+02 9.391E+02 1.408E+06 9.458E+01 2014 3.446E+03 2.760E+06 1.854E+02 9.205E+02 1.380E+06 9.271E+01 2015 3.378E+03 2.705E+06 1.817E+02 9.023E+02 1.352E+06 9.087E+01 2016 3.311E+03 2.651E+06 1.781E+02 8.844E+02 1.326E+06 8.907E+01 2017 3.245E+03 2.599E+06 1.746E+02 8.669E+02 1.299E+06 8.731E+01 2018 3.181E+03 2.547E+06 1.712E+02 8.497E+02 1.274E+06 8.558E+01 REPORT - 8 Attachment B - LandGEM - Unlined LF 11/17/2010 Results (Continued) (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2019 3.118E+03 2.497E+06 1.678E+02 8.329E+02 1.248E+06 8.388E+01 2020 3.056E+03 2.447E+06 1.644E+02 8.164E+02 1.224E+06 8.222E+01 2021 2.996E+03 2.399E+06 1.612E+02 8.002E+02 1.200E+06 8.059E+01 2022 2.937E+03 2.351E+06 1.580E+02 7.844E+02 1.176E+06 7.900E+01 2023 2.878E+03 2.305E+06 1.549E+02 7.689E+02 1.152E+06 7.743E+01 2024 2.821E+03 2.259E+06 1.518E+02 7.536E+02 1.130E+06 7.590E+01 2025 2.766E+03 2.215E+06 1.488E+02 7.387E+02 1.107E+06 7.440E+01 2026 2.711E+03 2.171E+06 1.458E+02 7.241E+02 1.085E+06 7.292E+01 2027 2.657E+03 2.128E+06 1.430E+02 7.098E+02 1.064E+06 7.148E+01 2028 2.605E+03 2.086E+06 1.401E+02 6.957E+02 1.043E+06 7.007E+01 2029 2.553E+03 2.044E+06 1.374E+02 6.819E+02 1.022E+06 6.868E+01 2030 2.502E+03 2.004E+06 1.346E+02 6.684E+02 1.002E+06 6.732E+01 2031 2.453E+03 1.964E+06 1.320E+02 6.552E+02 9.821E+05 6.599E+01 2032 2.404E+03 1.925E+06 1.294E+02 6.422E+02 9.626E+05 6.468E+01 2033 2.357E+03 1.887E+06 1.268E+02 6.295E+02 9.436E+05 6.340E+01 2034 2.310E+03 1.850E+06 1.243E+02 6.170E+02 9.249E+05 6.214E+01 2035 2.264E+03 1.813E+06 1.218E+02 6.048E+02 9.066E+05 6.091E+01 2036 2.219E+03 1.777E+06 1.194E+02 5.928E+02 8.886E+05 5.971E+01 2037 2.175E+03 1.742E+06 1.170E+02 5.811E+02 8.710E+05 5.852E+01 2038 2.132E+03 1.708E+06 1.147E+02 5.696E+02 8.538E+05 5.736E+01 2039 2.090E+03 1.674E+06 1.125E+02 5.583E+02 8.369E+05 5.623E+01 2040 2.049E+03 1.641E+06 1.102E+02 5.473E+02 8.203E+05 5.512E+01 2041 2.008E+03 1.608E+06 1.080E+02 5.364E+02 8.040E+05 5.402E+01 2042 1.968E+03 1.576E+06 1.059E+02 5.258E+02 7.881E+05 5.295E+01 2043 1.929E+03 1.545E+06 1.038E+02 5.154E+02 7.725E+05 5.191E+01 2044 1.891E+03 1.514E+06 1.018E+02 5.052E+02 7.572E+05 5.088E+01 2045 1.854E+03 1.484E+06 9.974E+01 4.952E+02 7.422E+05 4.987E+01 2046 1.817E+03 1.455E+06 9.777E+01 4.854E+02 7.275E+05 4.888E+01 2047 1.781E+03 1.426E+06 9.583E+01 4.758E+02 7.131E+05 4.791E+01 2048 1.746E+03 1.398E+06 9.393E+01 4.663E+02 6.990E+05 4.697E+01 2049 1.711E+03 1.370E+06 9.207E+01 4.571E+02 6.852E+05 4.604E+01 2050 1 677E+03 1 343E+06 9 025E+01 4 481E+02 6 716E+05 4 512E+01 Total landfill gas MethaneYear REPORT - 9 2050 1.677E+03 1.343E+06 9.025E+01 4.481E+02 6.716E+05 4.512E+01 2051 1.644E+03 1.317E+06 8.846E+01 4.392E+02 6.583E+05 4.423E+01 2052 1.612E+03 1.291E+06 8.671E+01 4.305E+02 6.453E+05 4.336E+01 2053 1.580E+03 1.265E+06 8.499E+01 4.220E+02 6.325E+05 4.250E+01 2054 1.548E+03 1.240E+06 8.331E+01 4.136E+02 6.200E+05 4.166E+01 2055 1.518E+03 1.215E+06 8.166E+01 4.054E+02 6.077E+05 4.083E+01 2056 1.488E+03 1.191E+06 8.004E+01 3.974E+02 5.957E+05 4.002E+01 2057 1.458E+03 1.168E+06 7.846E+01 3.895E+02 5.839E+05 3.923E+01 2058 1.429E+03 1.145E+06 7.691E+01 3.818E+02 5.723E+05 3.845E+01 2059 1.401E+03 1.122E+06 7.538E+01 3.742E+02 5.610E+05 3.769E+01 2060 1.373E+03 1.100E+06 7.389E+01 3.668E+02 5.499E+05 3.694E+01 2061 1.346E+03 1.078E+06 7.243E+01 3.596E+02 5.390E+05 3.621E+01 2062 1.320E+03 1.057E+06 7.099E+01 3.525E+02 5.283E+05 3.550E+01 2063 1.293E+03 1.036E+06 6.959E+01 3.455E+02 5.178E+05 3.479E+01 2064 1.268E+03 1.015E+06 6.821E+01 3.386E+02 5.076E+05 3.410E+01 2065 1.243E+03 9.951E+05 6.686E+01 3.319E+02 4.975E+05 3.343E+01 2066 1.218E+03 9.754E+05 6.553E+01 3.254E+02 4.877E+05 3.277E+01 2067 1.194E+03 9.560E+05 6.424E+01 3.189E+02 4.780E+05 3.212E+01 2068 1.170E+03 9.371E+05 6.296E+01 3.126E+02 4.686E+05 3.148E+01 2069 1.147E+03 9.186E+05 6.172E+01 3.064E+02 4.593E+05 3.086E+01 REPORT - 9 Attachment B - LandGEM - Unlined LF 11/17/2010 Results (Continued) (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2070 1.124E+03 9.004E+05 6.050E+01 3.003E+02 4.502E+05 3.025E+01 2071 1.102E+03 8.825E+05 5.930E+01 2.944E+02 4.413E+05 2.965E+01 2072 1.080E+03 8.651E+05 5.812E+01 2.886E+02 4.325E+05 2.906E+01 2073 1.059E+03 8.479E+05 5.697E+01 2.829E+02 4.240E+05 2.849E+01 2074 1.038E+03 8.311E+05 5.584E+01 2.772E+02 4.156E+05 2.792E+01 2075 1.017E+03 8.147E+05 5.474E+01 2.718E+02 4.073E+05 2.737E+01 2076 9.973E+02 7.986E+05 5.366E+01 2.664E+02 3.993E+05 2.683E+01 2077 9.775E+02 7.827E+05 5.259E+01 2.611E+02 3.914E+05 2.630E+01 2078 9.582E+02 7.672E+05 5.155E+01 2.559E+02 3.836E+05 2.578E+01 2079 9.392E+02 7.521E+05 5.053E+01 2.509E+02 3.760E+05 2.527E+01 2080 9.206E+02 7.372E+05 4.953E+01 2.459E+02 3.686E+05 2.476E+01 2081 9.024E+02 7.226E+05 4.855E+01 2.410E+02 3.613E+05 2.427E+01 2082 8.845E+02 7.083E+05 4.759E+01 2.363E+02 3.541E+05 2.379E+01 2083 8.670E+02 6.942E+05 4.665E+01 2.316E+02 3.471E+05 2.332E+01 2084 8.498E+02 6.805E+05 4.572E+01 2.270E+02 3.402E+05 2.286E+01 2085 8.330E+02 6.670E+05 4.482E+01 2.225E+02 3.335E+05 2.241E+01 2086 8.165E+02 6.538E+05 4.393E+01 2.181E+02 3.269E+05 2.196E+01 2087 8.003E+02 6.409E+05 4.306E+01 2.138E+02 3.204E+05 2.153E+01 2088 7.845E+02 6.282E+05 4.221E+01 2.095E+02 3.141E+05 2.110E+01 2089 7.689E+02 6.157E+05 4.137E+01 2.054E+02 3.079E+05 2.069E+01 2090 7.537E+02 6.035E+05 4.055E+01 2.013E+02 3.018E+05 2.028E+01 2091 7.388E+02 5.916E+05 3.975E+01 1.973E+02 2.958E+05 1.987E+01 2092 7.242E+02 5.799E+05 3.896E+01 1.934E+02 2.899E+05 1.948E+01 2093 7.098E+02 5.684E+05 3.819E+01 1.896E+02 2.842E+05 1.910E+01 2094 6.958E+02 5.571E+05 3.743E+01 1.858E+02 2.786E+05 1.872E+01 2095 6.820E+02 5.461E+05 3.669E+01 1.822E+02 2.731E+05 1.835E+01 2096 6.685E+02 5.353E+05 3.597E+01 1.786E+02 2.676E+05 1.798E+01 2097 6.552E+02 5.247E+05 3.525E+01 1.750E+02 2.623E+05 1.763E+01 2098 6.423E+02 5.143E+05 3.456E+01 1.716E+02 2.572E+05 1.728E+01 2099 6.296E+02 5.041E+05 3.387E+01 1.682E+02 2.521E+05 1.694E+01 2100 6.171E+02 4.941E+05 3.320E+01 1.648E+02 2.471E+05 1.660E+01 2101 6 049E+02 4 844E+05 3 254E+01 1 616E+02 2 422E+05 1 627E+01 Year Total landfill gas Methane REPORT - 10 2101 6.049E+02 4.844E+05 3.254E+01 1.616E+02 2.422E+05 1.627E+01 2102 5.929E+02 4.748E+05 3.190E+01 1.584E+02 2.374E+05 1.595E+01 2103 5.812E+02 4.654E+05 3.127E+01 1.552E+02 2.327E+05 1.563E+01 2104 5.696E+02 4.561E+05 3.065E+01 1.522E+02 2.281E+05 1.532E+01 2105 5.584E+02 4.471E+05 3.004E+01 1.491E+02 2.236E+05 1.502E+01 2106 5.473E+02 4.383E+05 2.945E+01 1.462E+02 2.191E+05 1.472E+01 2107 5.365E+02 4.296E+05 2.886E+01 1.433E+02 2.148E+05 1.443E+01 2108 5.258E+02 4.211E+05 2.829E+01 1.405E+02 2.105E+05 1.415E+01 2109 5.154E+02 4.127E+05 2.773E+01 1.377E+02 2.064E+05 1.387E+01 REPORT - 10 Attachment B - LandGEM - Unlined LF 11/17/2010 Results (Continued) Year (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 1969 0 00000 1970 6.148E+01 3.359E+04 2.257E+00 9.631E-01 2.687E+02 1.805E-02 1971 1.217E+02 6.651E+04 4.469E+00 1.907E+00 5.321E+02 3.575E-02 1972 1.808E+02 9.878E+04 6.637E+00 2.832E+00 7.902E+02 5.309E-02 1973 2.387E+02 1.304E+05 8.762E+00 3.739E+00 1.043E+03 7.010E-02 1974 2.955E+02 1.614E+05 1.085E+01 4.629E+00 1.291E+03 8.676E-02 1975 3.511E+02 1.918E+05 1.289E+01 5.500E+00 1.534E+03 1.031E-01 1976 4.056E+02 2.216E+05 1.489E+01 6.354E+00 1.773E+03 1.191E-01 1977 4.591E+02 2.508E+05 1.685E+01 7.191E+00 2.006E+03 1.348E-01 1978 5.115E+02 2.794E+05 1.877E+01 8.012E+00 2.235E+03 1.502E-01 1979 5.628E+02 3.075E+05 2.066E+01 8.817E+00 2.460E+03 1.653E-01 1980 6.131E+02 3.350E+05 2.251E+01 9.605E+00 2.680E+03 1.800E-01 1981 6.625E+02 3.619E+05 2.432E+01 1.038E+01 2.895E+03 1.945E-01 1982 7.108E+02 3.883E+05 2.609E+01 1.114E+01 3.107E+03 2.087E-01 1983 7.582E+02 4.142E+05 2.783E+01 1.188E+01 3.314E+03 2.227E-01 1984 8.047E+02 4.396E+05 2.954E+01 1.261E+01 3.517E+03 2.363E-01 1985 8.503E+02 4.645E+05 3.121E+01 1.332E+01 3.716E+03 2.497E-01 1986 8.949E+02 4.889E+05 3.285E+01 1.402E+01 3.911E+03 2.628E-01 1987 9.387E+02 5.128E+05 3.445E+01 1.470E+01 4.102E+03 2.756E-01 1988 9.815E+02 5.362E+05 3.603E+01 1.538E+01 4.290E+03 2.882E-01 1989 1.024E+03 5.592E+05 3.757E+01 1.604E+01 4.473E+03 3.006E-01 1990 1.065E+03 5.817E+05 3.908E+01 1.668E+01 4.654E+03 3.127E-01 1991 1.105E+03 6.038E+05 4.057E+01 1.731E+01 4.830E+03 3.245E-01 1992 1.145E+03 6.254E+05 4.202E+01 1.793E+01 5.003E+03 3.362E-01 1993 1.232E+03 6.730E+05 4.522E+01 1.930E+01 5.384E+03 3.618E-01 1994 1.340E+03 7.322E+05 4.920E+01 2.100E+01 5.858E+03 3.936E-01 1995 1.441E+03 7.874E+05 5.291E+01 2.258E+01 6.299E+03 4.233E-01 1996 1.559E+03 8.515E+05 5.721E+01 2.442E+01 6.812E+03 4.577E-01 1997 1.667E+03 9.106E+05 6.119E+01 2.611E+01 7.285E+03 4.895E-01 1998 1.813E+03 9.907E+05 6.657E+01 2.841E+01 7.926E+03 5.325E-01 1999 1.916E+03 1.047E+06 7.034E+01 3.002E+01 8.375E+03 5.627E-01 2000 2 025E+03 1 106E+06 7 434E+01 3 173E+01 8 851E+03 5 947E-01 Carbon dioxide NMOC REPORT - 11 2000 2.025E+03 1.106E+06 7.434E+01 3.173E+01 8.851E+03 5.947E-01 2001 2.150E+03 1.174E+06 7.890E+01 3.367E+01 9.395E+03 6.312E-01 2002 2.256E+03 1.232E+06 8.279E+01 3.534E+01 9.858E+03 6.624E-01 2003 2.363E+03 1.291E+06 8.672E+01 3.701E+01 1.033E+04 6.938E-01 2004 2.465E+03 1.347E+06 9.048E+01 3.862E+01 1.077E+04 7.239E-01 2005 2.560E+03 1.399E+06 9.398E+01 4.011E+01 1.119E+04 7.519E-01 2006 2.652E+03 1.449E+06 9.736E+01 4.155E+01 1.159E+04 7.789E-01 2007 2.752E+03 1.503E+06 1.010E+02 4.311E+01 1.203E+04 8.081E-01 2008 2.848E+03 1.556E+06 1.045E+02 4.461E+01 1.245E+04 8.362E-01 2009 2.791E+03 1.525E+06 1.025E+02 4.373E+01 1.220E+04 8.196E-01 2010 2.736E+03 1.495E+06 1.004E+02 4.286E+01 1.196E+04 8.034E-01 2011 2.682E+03 1.465E+06 9.844E+01 4.201E+01 1.172E+04 7.875E-01 2012 2.629E+03 1.436E+06 9.649E+01 4.118E+01 1.149E+04 7.719E-01 2013 2.577E+03 1.408E+06 9.458E+01 4.036E+01 1.126E+04 7.566E-01 2014 2.526E+03 1.380E+06 9.271E+01 3.957E+01 1.104E+04 7.416E-01 2015 2.476E+03 1.352E+06 9.087E+01 3.878E+01 1.082E+04 7.270E-01 2016 2.427E+03 1.326E+06 8.907E+01 3.801E+01 1.061E+04 7.126E-01 2017 2.379E+03 1.299E+06 8.731E+01 3.726E+01 1.040E+04 6.985E-01 2018 2.331E+03 1.274E+06 8.558E+01 3.652E+01 1.019E+04 6.846E-01 REPORT - 11 Attachment B - LandGEM - Unlined LF 11/17/2010 Results (Continued) (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2019 2.285E+03 1.248E+06 8.388E+01 3.580E+01 9.988E+03 6.711E-01 2020 2.240E+03 1.224E+06 8.222E+01 3.509E+01 9.790E+03 6.578E-01 2021 2.196E+03 1.200E+06 8.059E+01 3.440E+01 9.596E+03 6.448E-01 2022 2.152E+03 1.176E+06 7.900E+01 3.372E+01 9.406E+03 6.320E-01 2023 2.110E+03 1.152E+06 7.743E+01 3.305E+01 9.220E+03 6.195E-01 2024 2.068E+03 1.130E+06 7.590E+01 3.239E+01 9.037E+03 6.072E-01 2025 2.027E+03 1.107E+06 7.440E+01 3.175E+01 8.858E+03 5.952E-01 2026 1.987E+03 1.085E+06 7.292E+01 3.112E+01 8.683E+03 5.834E-01 2027 1.947E+03 1.064E+06 7.148E+01 3.051E+01 8.511E+03 5.718E-01 2028 1.909E+03 1.043E+06 7.007E+01 2.990E+01 8.342E+03 5.605E-01 2029 1.871E+03 1.022E+06 6.868E+01 2.931E+01 8.177E+03 5.494E-01 2030 1.834E+03 1.002E+06 6.732E+01 2.873E+01 8.015E+03 5.385E-01 2031 1.798E+03 9.821E+05 6.599E+01 2.816E+01 7.857E+03 5.279E-01 2032 1.762E+03 9.626E+05 6.468E+01 2.760E+01 7.701E+03 5.174E-01 2033 1.727E+03 9.436E+05 6.340E+01 2.706E+01 7.548E+03 5.072E-01 2034 1.693E+03 9.249E+05 6.214E+01 2.652E+01 7.399E+03 4.971E-01 2035 1.659E+03 9.066E+05 6.091E+01 2.600E+01 7.253E+03 4.873E-01 2036 1.627E+03 8.886E+05 5.971E+01 2.548E+01 7.109E+03 4.776E-01 2037 1.594E+03 8.710E+05 5.852E+01 2.498E+01 6.968E+03 4.682E-01 2038 1.563E+03 8.538E+05 5.736E+01 2.448E+01 6.830E+03 4.589E-01 2039 1.532E+03 8.369E+05 5.623E+01 2.400E+01 6.695E+03 4.498E-01 2040 1.502E+03 8.203E+05 5.512E+01 2.352E+01 6.562E+03 4.409E-01 2041 1.472E+03 8.040E+05 5.402E+01 2.306E+01 6.432E+03 4.322E-01 2042 1.443E+03 7.881E+05 5.295E+01 2.260E+01 6.305E+03 4.236E-01 2043 1.414E+03 7.725E+05 5.191E+01 2.215E+01 6.180E+03 4.152E-01 2044 1.386E+03 7.572E+05 5.088E+01 2.171E+01 6.058E+03 4.070E-01 2045 1.359E+03 7.422E+05 4.987E+01 2.128E+01 5.938E+03 3.990E-01 2046 1.332E+03 7.275E+05 4.888E+01 2.086E+01 5.820E+03 3.911E-01 2047 1.305E+03 7.131E+05 4.791E+01 2.045E+01 5.705E+03 3.833E-01 2048 1.280E+03 6.990E+05 4.697E+01 2.004E+01 5.592E+03 3.757E-01 2049 1.254E+03 6.852E+05 4.604E+01 1.965E+01 5.481E+03 3.683E-01 2050 1 229E+03 6 716E+05 4 512E+01 1 926E+01 5 373E+03 3 610E-01 NMOCCarbon dioxideYear REPORT - 12 2050 1.229E+03 6.716E+05 4.512E+01 1.926E+01 5.373E+03 3.610E-01 2051 1.205E+03 6.583E+05 4.423E+01 1.888E+01 5.266E+03 3.538E-01 2052 1.181E+03 6.453E+05 4.336E+01 1.850E+01 5.162E+03 3.468E-01 2053 1.158E+03 6.325E+05 4.250E+01 1.814E+01 5.060E+03 3.400E-01 2054 1.135E+03 6.200E+05 4.166E+01 1.778E+01 4.960E+03 3.332E-01 2055 1.112E+03 6.077E+05 4.083E+01 1.743E+01 4.862E+03 3.266E-01 2056 1.090E+03 5.957E+05 4.002E+01 1.708E+01 4.765E+03 3.202E-01 2057 1.069E+03 5.839E+05 3.923E+01 1.674E+01 4.671E+03 3.138E-01 2058 1.048E+03 5.723E+05 3.845E+01 1.641E+01 4.578E+03 3.076E-01 2059 1.027E+03 5.610E+05 3.769E+01 1.609E+01 4.488E+03 3.015E-01 2060 1.007E+03 5.499E+05 3.694E+01 1.577E+01 4.399E+03 2.956E-01 2061 9.866E+02 5.390E+05 3.621E+01 1.546E+01 4.312E+03 2.897E-01 2062 9.670E+02 5.283E+05 3.550E+01 1.515E+01 4.226E+03 2.840E-01 2063 9.479E+02 5.178E+05 3.479E+01 1.485E+01 4.143E+03 2.783E-01 2064 9.291E+02 5.076E+05 3.410E+01 1.456E+01 4.061E+03 2.728E-01 2065 9.107E+02 4.975E+05 3.343E+01 1.427E+01 3.980E+03 2.674E-01 2066 8.927E+02 4.877E+05 3.277E+01 1.398E+01 3.901E+03 2.621E-01 2067 8.750E+02 4.780E+05 3.212E+01 1.371E+01 3.824E+03 2.569E-01 2068 8.577E+02 4.686E+05 3.148E+01 1.344E+01 3.748E+03 2.519E-01 2069 8.407E+02 4.593E+05 3.086E+01 1.317E+01 3.674E+03 2.469E-01 REPORT - 12 Attachment B - LandGEM - Unlined LF 11/17/2010 Results (Continued) (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2070 8.241E+02 4.502E+05 3.025E+01 1.291E+01 3.601E+03 2.420E-01 2071 8.077E+02 4.413E+05 2.965E+01 1.265E+01 3.530E+03 2.372E-01 2072 7.918E+02 4.325E+05 2.906E+01 1.240E+01 3.460E+03 2.325E-01 2073 7.761E+02 4.240E+05 2.849E+01 1.216E+01 3.392E+03 2.279E-01 2074 7.607E+02 4.156E+05 2.792E+01 1.192E+01 3.325E+03 2.234E-01 2075 7.456E+02 4.073E+05 2.737E+01 1.168E+01 3.259E+03 2.190E-01 2076 7.309E+02 3.993E+05 2.683E+01 1.145E+01 3.194E+03 2.146E-01 2077 7.164E+02 3.914E+05 2.630E+01 1.122E+01 3.131E+03 2.104E-01 2078 7.022E+02 3.836E+05 2.578E+01 1.100E+01 3.069E+03 2.062E-01 2079 6.883E+02 3.760E+05 2.527E+01 1.078E+01 3.008E+03 2.021E-01 2080 6.747E+02 3.686E+05 2.476E+01 1.057E+01 2.949E+03 1.981E-01 2081 6.613E+02 3.613E+05 2.427E+01 1.036E+01 2.890E+03 1.942E-01 2082 6.482E+02 3.541E+05 2.379E+01 1.015E+01 2.833E+03 1.904E-01 2083 6.354E+02 3.471E+05 2.332E+01 9.954E+00 2.777E+03 1.866E-01 2084 6.228E+02 3.402E+05 2.286E+01 9.757E+00 2.722E+03 1.829E-01 2085 6.105E+02 3.335E+05 2.241E+01 9.564E+00 2.668E+03 1.793E-01 2086 5.984E+02 3.269E+05 2.196E+01 9.374E+00 2.615E+03 1.757E-01 2087 5.865E+02 3.204E+05 2.153E+01 9.189E+00 2.563E+03 1.722E-01 2088 5.749E+02 3.141E+05 2.110E+01 9.007E+00 2.513E+03 1.688E-01 2089 5.635E+02 3.079E+05 2.069E+01 8.828E+00 2.463E+03 1.655E-01 2090 5.524E+02 3.018E+05 2.028E+01 8.653E+00 2.414E+03 1.622E-01 2091 5.414E+02 2.958E+05 1.987E+01 8.482E+00 2.366E+03 1.590E-01 2092 5.307E+02 2.899E+05 1.948E+01 8.314E+00 2.319E+03 1.558E-01 2093 5.202E+02 2.842E+05 1.910E+01 8.150E+00 2.274E+03 1.528E-01 2094 5.099E+02 2.786E+05 1.872E+01 7.988E+00 2.229E+03 1.497E-01 2095 4.998E+02 2.731E+05 1.835E+01 7.830E+00 2.184E+03 1.468E-01 2096 4.899E+02 2.676E+05 1.798E+01 7.675E+00 2.141E+03 1.439E-01 2097 4.802E+02 2.623E+05 1.763E+01 7.523E+00 2.099E+03 1.410E-01 2098 4.707E+02 2.572E+05 1.728E+01 7.374E+00 2.057E+03 1.382E-01 2099 4.614E+02 2.521E+05 1.694E+01 7.228E+00 2.016E+03 1.355E-01 2100 4.523E+02 2.471E+05 1.660E+01 7.085E+00 1.977E+03 1.328E-01 2101 4 433E+02 2 422E+05 1 627E+01 6 945E+00 1 937E+03 1 302E-01 Carbon dioxide NMOCYear REPORT - 13 2101 4.433E+02 2.422E+05 1.627E+01 6.945E+00 1.937E+03 1.302E-01 2102 4.345E+02 2.374E+05 1.595E+01 6.807E+00 1.899E+03 1.276E-01 2103 4.259E+02 2.327E+05 1.563E+01 6.672E+00 1.861E+03 1.251E-01 2104 4.175E+02 2.281E+05 1.532E+01 6.540E+00 1.825E+03 1.226E-01 2105 4.092E+02 2.236E+05 1.502E+01 6.411E+00 1.788E+03 1.202E-01 2106 4.011E+02 2.191E+05 1.472E+01 6.284E+00 1.753E+03 1.178E-01 2107 3.932E+02 2.148E+05 1.443E+01 6.159E+00 1.718E+03 1.155E-01 2108 3.854E+02 2.105E+05 1.415E+01 6.037E+00 1.684E+03 1.132E-01 2109 3.778E+02 2.064E+05 1.387E+01 5.918E+00 1.651E+03 1.109E-01 REPORT - 13 Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment C LandGEM Modeling Results for the Lined Landfill Attachment C - LandGEM - Lined LF 11/17/2010 Summary Report Landfill Name or Identifier: Kenai CPL Cells 1-5 Date: Wednesday, November 17, 2010 Description/Comments: Waste tonnages for 2005-2009 are from the historical records at the CPL presented in the RD&D report. Waste tonnages for 2010-2034 are based on the waste forecasts presented in Table 2 of CH2M-Hill’s Schematic-Design Basis Report. Methane generation rate constant (k) is 0.04/year due to leachate recirculation in the lined landfill (default wet REPORT - 1 First-Order Decomposition Rate Equation: Where, QCH4 = annual methane generation in the year of the calculation (m 3 /year )i = 1-year time increment Mi = mass of waste accepted in the ith year (Mg ) n = (year of the calculation) - (initial year of waste acceptance) j = 0.1-year time increment k = methane generation rate (year -1 ) Lo = potential methane generation capacity (m 3 /Mg ) tij = age of the jth section of waste mass Mi accepted in the ith year (decimal years , e.g., 3.2 years) LandGEM is considered a screening tool — the better the input data, the better the estimates. Often, there are limitations with the available data regarding waste quantity and composition, variation in design and operating practices over time, and changes occurring over time that impact the emissions potential. Changes to landfill operation, such as operating under wet conditions through leachate recirculation or other liquid additions, will result in generating more gas at a faster rate. Defaults for estimating emissions for this type of operation are being developed to include in LandGEM along with defaults for convential landfills (no leachate or liquid additions) for developing emission inventories and determining CAA applicability. Refer to the Web site identified above for future updates. LandGEM is based on a first-order decomposition rate equation for quantifying emissions from the decomposition of landfilled waste in municipal solid waste (MSW) landfills. The software provides a relatively simple approach to estimating landfill gas emissions. Model defaults are based on empirical data from U.S. landfills. Field test data can also be used in place of model defaults when available. Further guidance on EPA test methods, Clean Air Act (CAA) regulations, and other guidance regarding landfill gas emissions and control technology requirements can be found at http://www.epa.gov/ttnatw01/landfill/landflpg.html. epo t et a e ge e at o ate co sta t ( ) s 0 0 /yea due to eac ate ec cu at o t e ed a d (de au t et value per AP-42). Methane generation potential (Lo) is 100 m3/Mg of refuse per AP-42. About LandGEM: REPORT - 1 Attachment C - LandGEM - Lined LF 11/17/2010 Input Review LANDFILL CHARACTERISTICS Landfill Open Year 2005 Landfill Closure Year (with 80-year limit)2035 Actual Closure Year (without limit)2035 Have Model Calculate Closure Year?No Waste Design Capacity 1,608,461 short tons MODEL PARAMETERS Methane Generation Rate, k 0.040 year -1 Potential Methane Generation Capacity, Lo 100 m 3 /Mg NMOC Concentration 4,000 ppmv as hexane Methane Content 50 % by volume GASES / POLLUTANTS SELECTED Gas / Pollutant #1:Total landfill gas Gas / Pollutant #2:Methane Gas / Pollutant #3:Carbon dioxide Gas / Pollutant #4:NMOC WASTE ACCEPTANCE RATES (Mg/year) (short tons/year) (Mg) (short tons) 2005 686 755 0 0 2006 26,182 28,800 686 755 2007 39,414 43,355 26,868 29,555 2008 36,359 39,995 66,282 72,910 2009 39,268 43,195 102,641 112,905 2010 39,790 43,769 141,909 156,100 2011 40,132 44,145 181,699 199,869 2012 40,477 44,525 221,831 244,014 2013 51,447 56,592 262,308 288,539 2014 51,890 57,079 313,755 345,131 2015 52,336 57,570 365,645 402,210 2016 52 693 57 962 417 982 459 780 Year Waste Accepted Waste-In-Place REPORT - 2 2016 52,693 57,962 417,982 459,780 2017 53,052 58,357 470,675 517,742 2018 53,413 58,754 523,726 576,099 2019 53,776 59,154 577,139 634,853 2020 54,143 59,557 630,915 694,007 2021 54,413 59,854 685,058 753,564 2022 54,684 60,152 739,471 813,418 2023 54,956 60,452 794,155 873,570 2024 55,230 60,753 849,111 934,022 2025 55,505 61,056 904,341 994,775 2026 55,678 61,246 959,846 1,055,831 2027 55,851 61,436 1,015,525 1,117,077 2028 56,025 61,627 1,071,375 1,178,513 2029 56,199 61,819 1,127,400 1,240,140 2030 56,374 62,011 1,183,599 1,301,959 2031 56,549 62,204 1,239,973 1,363,970 2032 56,725 62,398 1,296,522 1,426,174 2033 56,902 62,592 1,353,247 1,488,572 2034 52,088 57,297 1,410,149 1,551,164 2035 0 0 1,462,237 1,608,461 2036 0 0 1,462,237 1,608,461 2037 0 0 1,462,237 1,608,461 2038 0 0 1,462,237 1,608,461 2039 0 0 1,462,237 1,608,461 2040 0 0 1,462,237 1,608,461 2041 0 0 1,462,237 1,608,461 2042 0 0 1,462,237 1,608,461 2043 0 0 1,462,237 1,608,461 2044 0 0 1,462,237 1,608,461 REPORT - 2 Attachment C - LandGEM - Lined LF 11/17/2010 WASTE ACCEPTANCE RATES (Continued) (Mg/year) (short tons/year) (Mg) (short tons) 2045 0 0 1,462,237 1,608,461 2046 0 0 1,462,237 1,608,461 2047 0 0 1,462,237 1,608,461 2048 0 0 1,462,237 1,608,461 2049 0 0 1,462,237 1,608,461 2050 0 0 1,462,237 1,608,461 2051 0 0 1,462,237 1,608,461 2052 0 0 1,462,237 1,608,461 2053 0 0 1,462,237 1,608,461 2054 0 0 1,462,237 1,608,461 2055 0 0 1,462,237 1,608,461 2056 0 0 1,462,237 1,608,461 2057 0 0 1,462,237 1,608,461 2058 0 0 1,462,237 1,608,461 2059 0 0 1,462,237 1,608,461 2060 0 0 1,462,237 1,608,461 2061 0 0 1,462,237 1,608,461 2062 0 0 1,462,237 1,608,461 2063 0 0 1,462,237 1,608,461 2064 0 0 1,462,237 1,608,461 2065 0 0 1,462,237 1,608,461 2066 0 0 1,462,237 1,608,461 2067 0 0 1,462,237 1,608,461 2068 0 0 1,462,237 1,608,461 2069 0 0 1,462,237 1,608,461 2070 0 0 1,462,237 1,608,461 2071 0 0 1,462,237 1,608,461 2072 0 0 1,462,237 1,608,461 2073 0 0 1,462,237 1,608,461 2074 0 0 1,462,237 1,608,461 2075 0 0 1,462,237 1,608,461 2076 0 0 1,462,237 1,608,461 2077 0 0 1,462,237 1,608,461 Year Waste Accepted Waste-In-Place REPORT - 3 2078 0 0 1,462,237 1,608,461 2079 0 0 1,462,237 1,608,461 2080 0 0 1,462,237 1,608,461 2081 0 0 1,462,237 1,608,461 2082 0 0 1,462,237 1,608,461 2083 0 0 1,462,237 1,608,461 2084 0 0 1,462,237 1,608,461 REPORT - 3 Attachment C - LandGEM - Lined LF 11/17/2010 Pollutant Parameters Concentration Concentration Compound (ppmv )Molecular Weight (ppmv )Molecular Weight Total landfill gas 0.00 Methane 16.04 Carbon dioxide 44.01 NMOC 4,000 86.18 1,1,1-Trichloroethane (methyl chloroform) - HAP 0.48 133.41 1,1,2,2- Tetrachloroethane - HAP/VOC 1.1 167.85 1,1-Dichloroethane (ethylidene dichloride) - HAP/VOC 2.4 98.97 1,1-Dichloroethene (vinylidene chloride) - HAP/VOC 0.20 96.94 1,2-Dichloroethane (ethylene dichloride) - HAP/VOC 0.41 98.96 1,2-Dichloropropane (propylene dichloride) - HAP/VOC 0.18 112.99 2-Propanol (isopropyl alcohol) - VOC 50 60.11 Acetone 7.0 58.08 Acrylonitrile - HAP/VOC 6.3 53.06 Benzene - No or Unknown Co-disposal - HAP/VOC 1.9 78.11 Benzene Co disposal Gas / Pollutant Default Parameters:User-specified Pollutant Parameters:GasesREPORT - 4 Benzene - Co-disposal - HAP/VOC 11 78.11 Bromodichloromethane - VOC 3.1 163.83 Butane - VOC 5.0 58.12 Carbon disulfide - HAP/VOC 0.58 76.13 Carbon monoxide 140 28.01 Carbon tetrachloride - HAP/VOC 4.0E-03 153.84 Carbonyl sulfide - HAP/VOC 0.49 60.07 Chlorobenzene - HAP/VOC 0.25 112.56 Chlorodifluoromethane 1.3 86.47 Chloroethane (ethyl chloride) - HAP/VOC 1.3 64.52 Chloroform - HAP/VOC 0.03 119.39 Chloromethane - VOC 1.2 50.49 Dichlorobenzene - (HAP for para isomer/VOC)0.21 147 Dichlorodifluoromethane 16 120.91 Dichlorofluoromethane - VOC 2.6 102.92 Dichloromethane (methylene chloride) - HAP 14 84.94 Dimethyl sulfide (methyl sulfide) - VOC 7.8 62.13 Ethane 890 30.07 Ethanol - VOC 27 46.08Pollutants REPORT - 4 Attachment C - LandGEM - Lined LF 11/17/2010 Pollutant Parameters (Continued) Concentration Concentration Compound (ppmv )Molecular Weight (ppmv )Molecular Weight Ethyl mercaptan (ethanethiol) - VOC 2.3 62.13 Ethylbenzene - HAP/VOC 4.6 106.16 Ethylene dibromide - HAP/VOC 1.0E-03 187.88 Fluorotrichloromethane - VOC 0.76 137.38 Hexane - HAP/VOC 6.6 86.18 Hydrogen sulfide 36 34.08 Mercury (total) - HAP 2.9E-04 200.61 Methyl ethyl ketone - HAP/VOC 7.1 72.11 Methyl isobutyl ketone - HAP/VOC 1.9 100.16 Methyl mercaptan - VOC 2.5 48.11 Pentane - VOC 3.3 72.15 Perchloroethylene (tetrachloroethylene) - HAP 3.7 165.83 Propane - VOC 11 44.09 t-1,2-Dichloroethene - VOC 2.8 96.94 Toluene - No or Unknown Co-disposal - HAP/VOC 39 92.13 Toluene - Co-disposal - HAP/VOC 170 92.13 Trichloroethylene (trichloroethene)- User-specified Pollutant Parameters:Gas / Pollutant Default Parameters:sREPORT - 5 (trichloroethene) - HAP/VOC 2.8 131.40 Vinyl chloride - HAP/VOC 7.3 62.50 Xylenes - HAP/VOC 12 106.16Pollutants REPORT - 5 Attachment C - LandGEM - Lined LF 11/17/2010 REPORT - 6REPORT - 6 Attachment C - LandGEM - Lined LF 11/17/2010 Graphs 0.000E+00 1.000E+03 2.000E+03 3.000E+03 4.000E+03 5.000E+03 6.000E+03 7.000E+03 8.000E+03 9.000E+03 1.000E+04 EmissionsYear Megagrams Per Year Total landfill gas Methane Carbon dioxide NMOC 0.000E+00 1.000E+06 2.000E+06 3.000E+06 4.000E+06 5.000E+06 6.000E+06 7.000E+06 8.000E+06 EmissionsCubic Meters Per Year REPORT - 7 0.000E+00 1.000E+03 2.000E+03 3.000E+03 4.000E+03 5.000E+03 6.000E+03 7.000E+03 8.000E+03 9.000E+03 1.000E+04 EmissionsYear Megagrams Per Year Total landfill gas Methane Carbon dioxide NMOC 0.000E+00 1.000E+06 2.000E+06 3.000E+06 4.000E+06 5.000E+06 6.000E+06 7.000E+06 8.000E+06 EmissionsYear Cubic Meters Per Year Total landfill gas Methane Carbon dioxide NMOC 0.000E+00 1.000E+02 2.000E+02 3.000E+02 4.000E+02 5.000E+02 6.000E+02 EmissionsYear User-specified Unit (units shown in legend below) Total landfill gas (av ft^3/min)Methane (av ft^3/min)Carbon dioxide (av ft^3/min)NMOC (av ft^3/min) REPORT - 7 Attachment C - LandGEM - Lined LF 11/17/2010 Results (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2005 0 00000 2006 6.735E+00 5.393E+03 3.624E-01 1.799E+00 2.697E+03 1.812E-01 2007 2.634E+02 2.109E+05 1.417E+01 7.036E+01 1.055E+05 7.086E+00 2008 6.398E+02 5.123E+05 3.442E+01 1.709E+02 2.562E+05 1.721E+01 2009 9.715E+02 7.780E+05 5.227E+01 2.595E+02 3.890E+05 2.614E+01 2010 1.319E+03 1.056E+06 7.095E+01 3.523E+02 5.280E+05 3.548E+01 2011 1.658E+03 1.327E+06 8.918E+01 4.427E+02 6.636E+05 4.459E+01 2012 1.986E+03 1.591E+06 1.069E+02 5.306E+02 7.953E+05 5.344E+01 2013 2.306E+03 1.846E+06 1.241E+02 6.159E+02 9.231E+05 6.203E+01 2014 2.720E+03 2.178E+06 1.463E+02 7.266E+02 1.089E+06 7.317E+01 2015 3.123E+03 2.500E+06 1.680E+02 8.341E+02 1.250E+06 8.400E+01 2016 3.514E+03 2.814E+06 1.891E+02 9.386E+02 1.407E+06 9.453E+01 2017 3.893E+03 3.117E+06 2.095E+02 1.040E+03 1.559E+06 1.047E+02 2018 4.261E+03 3.412E+06 2.293E+02 1.138E+03 1.706E+06 1.146E+02 2019 4.618E+03 3.698E+06 2.485E+02 1.234E+03 1.849E+06 1.242E+02 2020 4.965E+03 3.976E+06 2.671E+02 1.326E+03 1.988E+06 1.336E+02 2021 5.301E+03 4.245E+06 2.852E+02 1.416E+03 2.123E+06 1.426E+02 2022 5.627E+03 4.506E+06 3.028E+02 1.503E+03 2.253E+06 1.514E+02 2023 5.943E+03 4.759E+06 3.198E+02 1.588E+03 2.380E+06 1.599E+02 2024 6.250E+03 5.004E+06 3.362E+02 1.669E+03 2.502E+06 1.681E+02 2025 6.547E+03 5.242E+06 3.522E+02 1.749E+03 2.621E+06 1.761E+02 2026 6.835E+03 5.473E+06 3.677E+02 1.826E+03 2.736E+06 1.839E+02 2027 7.113E+03 5.696E+06 3.827E+02 1.900E+03 2.848E+06 1.913E+02 2028 7.382E+03 5.911E+06 3.972E+02 1.972E+03 2.956E+06 1.986E+02 2029 7.642E+03 6.120E+06 4.112E+02 2.041E+03 3.060E+06 2.056E+02 2030 7.894E+03 6.321E+06 4.247E+02 2.109E+03 3.161E+06 2.124E+02 2031 8.138E+03 6.516E+06 4.378E+02 2.174E+03 3.258E+06 2.189E+02 2032 8.374E+03 6.705E+06 4.505E+02 2.237E+03 3.353E+06 2.253E+02 2033 8.602E+03 6.888E+06 4.628E+02 2.298E+03 3.444E+06 2.314E+02 2034 8.823E+03 7.065E+06 4.747E+02 2.357E+03 3.533E+06 2.374E+02 2035 8.988E+03 7.197E+06 4.836E+02 2.401E+03 3.599E+06 2.418E+02 2036 8 636E+03 6 915E+06 4 646E+02 2 307E+03 3 458E+06 2 323E+02 Year Total landfill gas Methane REPORT - 8 2036 8.636E+03 6.915E+06 4.646E+02 2.307E+03 3.458E+06 2.323E+02 2037 8.297E+03 6.644E+06 4.464E+02 2.216E+03 3.322E+06 2.232E+02 2038 7.972E+03 6.384E+06 4.289E+02 2.129E+03 3.192E+06 2.145E+02 2039 7.659E+03 6.133E+06 4.121E+02 2.046E+03 3.067E+06 2.060E+02 2040 7.359E+03 5.893E+06 3.959E+02 1.966E+03 2.946E+06 1.980E+02 2041 7.070E+03 5.662E+06 3.804E+02 1.889E+03 2.831E+06 1.902E+02 2042 6.793E+03 5.440E+06 3.655E+02 1.815E+03 2.720E+06 1.827E+02 2043 6.527E+03 5.226E+06 3.512E+02 1.743E+03 2.613E+06 1.756E+02 2044 6.271E+03 5.021E+06 3.374E+02 1.675E+03 2.511E+06 1.687E+02 2045 6.025E+03 4.825E+06 3.242E+02 1.609E+03 2.412E+06 1.621E+02 2046 5.789E+03 4.635E+06 3.115E+02 1.546E+03 2.318E+06 1.557E+02 2047 5.562E+03 4.454E+06 2.992E+02 1.486E+03 2.227E+06 1.496E+02 2048 5.344E+03 4.279E+06 2.875E+02 1.427E+03 2.140E+06 1.438E+02 2049 5.134E+03 4.111E+06 2.762E+02 1.371E+03 2.056E+06 1.381E+02 2050 4.933E+03 3.950E+06 2.654E+02 1.318E+03 1.975E+06 1.327E+02 2051 4.739E+03 3.795E+06 2.550E+02 1.266E+03 1.898E+06 1.275E+02 2052 4.554E+03 3.646E+06 2.450E+02 1.216E+03 1.823E+06 1.225E+02 2053 4.375E+03 3.503E+06 2.354E+02 1.169E+03 1.752E+06 1.177E+02 2054 4.204E+03 3.366E+06 2.262E+02 1.123E+03 1.683E+06 1.131E+02 REPORT - 8 Attachment C - LandGEM - Lined LF 11/17/2010 Results (Continued) (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2055 4.039E+03 3.234E+06 2.173E+02 1.079E+03 1.617E+06 1.086E+02 2056 3.880E+03 3.107E+06 2.088E+02 1.036E+03 1.554E+06 1.044E+02 2057 3.728E+03 2.985E+06 2.006E+02 9.958E+02 1.493E+06 1.003E+02 2058 3.582E+03 2.868E+06 1.927E+02 9.568E+02 1.434E+06 9.636E+01 2059 3.442E+03 2.756E+06 1.852E+02 9.193E+02 1.378E+06 9.258E+01 2060 3.307E+03 2.648E+06 1.779E+02 8.832E+02 1.324E+06 8.895E+01 2061 3.177E+03 2.544E+06 1.709E+02 8.486E+02 1.272E+06 8.546E+01 2062 3.052E+03 2.444E+06 1.642E+02 8.153E+02 1.222E+06 8.211E+01 2063 2.933E+03 2.348E+06 1.578E+02 7.834E+02 1.174E+06 7.889E+01 2064 2.818E+03 2.256E+06 1.516E+02 7.526E+02 1.128E+06 7.580E+01 2065 2.707E+03 2.168E+06 1.457E+02 7.231E+02 1.084E+06 7.283E+01 2066 2.601E+03 2.083E+06 1.399E+02 6.948E+02 1.041E+06 6.997E+01 2067 2.499E+03 2.001E+06 1.345E+02 6.675E+02 1.001E+06 6.723E+01 2068 2.401E+03 1.923E+06 1.292E+02 6.414E+02 9.613E+05 6.459E+01 2069 2.307E+03 1.847E+06 1.241E+02 6.162E+02 9.236E+05 6.206E+01 2070 2.216E+03 1.775E+06 1.193E+02 5.920E+02 8.874E+05 5.963E+01 2071 2.130E+03 1.705E+06 1.146E+02 5.688E+02 8.526E+05 5.729E+01 2072 2.046E+03 1.638E+06 1.101E+02 5.465E+02 8.192E+05 5.504E+01 2073 1.966E+03 1.574E+06 1.058E+02 5.251E+02 7.871E+05 5.288E+01 2074 1.889E+03 1.512E+06 1.016E+02 5.045E+02 7.562E+05 5.081E+01 2075 1.815E+03 1.453E+06 9.764E+01 4.847E+02 7.266E+05 4.882E+01 2076 1.744E+03 1.396E+06 9.381E+01 4.657E+02 6.981E+05 4.690E+01 2077 1.675E+03 1.341E+06 9.013E+01 4.475E+02 6.707E+05 4.506E+01 2078 1.609E+03 1.289E+06 8.660E+01 4.299E+02 6.444E+05 4.330E+01 2079 1.546E+03 1.238E+06 8.320E+01 4.131E+02 6.191E+05 4.160E+01 2080 1.486E+03 1.190E+06 7.994E+01 3.969E+02 5.949E+05 3.997E+01 2081 1.427E+03 1.143E+06 7.680E+01 3.813E+02 5.715E+05 3.840E+01 2082 1.372E+03 1.098E+06 7.379E+01 3.663E+02 5.491E+05 3.690E+01 2083 1.318E+03 1.055E+06 7.090E+01 3.520E+02 5.276E+05 3.545E+01 2084 1.266E+03 1.014E+06 6.812E+01 3.382E+02 5.069E+05 3.406E+01 2085 1.216E+03 9.741E+05 6.545E+01 3.249E+02 4.870E+05 3.272E+01 2086 1 169E+03 9 359E+05 6 288E+01 3 122E+02 4 679E+05 3 144E+01 Total landfill gas MethaneYear REPORT - 9 2086 1.169E+03 9.359E+05 6.288E+01 3.122E+02 4.679E+05 3.144E+01 2087 1.123E+03 8.992E+05 6.042E+01 2.999E+02 4.496E+05 3.021E+01 2088 1.079E+03 8.639E+05 5.805E+01 2.882E+02 4.320E+05 2.902E+01 2089 1.037E+03 8.300E+05 5.577E+01 2.769E+02 4.150E+05 2.789E+01 2090 9.959E+02 7.975E+05 5.358E+01 2.660E+02 3.987E+05 2.679E+01 2091 9.569E+02 7.662E+05 5.148E+01 2.556E+02 3.831E+05 2.574E+01 2092 9.194E+02 7.362E+05 4.946E+01 2.456E+02 3.681E+05 2.473E+01 2093 8.833E+02 7.073E+05 4.752E+01 2.359E+02 3.537E+05 2.376E+01 2094 8.487E+02 6.796E+05 4.566E+01 2.267E+02 3.398E+05 2.283E+01 2095 8.154E+02 6.529E+05 4.387E+01 2.178E+02 3.265E+05 2.194E+01 2096 7.834E+02 6.273E+05 4.215E+01 2.093E+02 3.137E+05 2.108E+01 2097 7.527E+02 6.027E+05 4.050E+01 2.011E+02 3.014E+05 2.025E+01 2098 7.232E+02 5.791E+05 3.891E+01 1.932E+02 2.896E+05 1.945E+01 2099 6.948E+02 5.564E+05 3.738E+01 1.856E+02 2.782E+05 1.869E+01 2100 6.676E+02 5.346E+05 3.592E+01 1.783E+02 2.673E+05 1.796E+01 2101 6.414E+02 5.136E+05 3.451E+01 1.713E+02 2.568E+05 1.725E+01 2102 6.163E+02 4.935E+05 3.316E+01 1.646E+02 2.467E+05 1.658E+01 2103 5.921E+02 4.741E+05 3.186E+01 1.582E+02 2.371E+05 1.593E+01 2104 5.689E+02 4.555E+05 3.061E+01 1.520E+02 2.278E+05 1.530E+01 2105 5.466E+02 4.377E+05 2.941E+01 1.460E+02 2.188E+05 1.470E+01 REPORT - 9 Attachment C - LandGEM - Lined LF 11/17/2010 Results (Continued) (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2106 5.251E+02 4.205E+05 2.825E+01 1.403E+02 2.103E+05 1.413E+01 2107 5.046E+02 4.040E+05 2.715E+01 1.348E+02 2.020E+05 1.357E+01 2108 4.848E+02 3.882E+05 2.608E+01 1.295E+02 1.941E+05 1.304E+01 2109 4.658E+02 3.730E+05 2.506E+01 1.244E+02 1.865E+05 1.253E+01 2110 4.475E+02 3.583E+05 2.408E+01 1.195E+02 1.792E+05 1.204E+01 2111 4.300E+02 3.443E+05 2.313E+01 1.148E+02 1.721E+05 1.157E+01 2112 4.131E+02 3.308E+05 2.223E+01 1.103E+02 1.654E+05 1.111E+01 2113 3.969E+02 3.178E+05 2.135E+01 1.060E+02 1.589E+05 1.068E+01 2114 3.813E+02 3.054E+05 2.052E+01 1.019E+02 1.527E+05 1.026E+01 2115 3.664E+02 2.934E+05 1.971E+01 9.786E+01 1.467E+05 9.856E+00 2116 3.520E+02 2.819E+05 1.894E+01 9.403E+01 1.409E+05 9.470E+00 2117 3.382E+02 2.708E+05 1.820E+01 9.034E+01 1.354E+05 9.098E+00 2118 3.250E+02 2.602E+05 1.748E+01 8.680E+01 1.301E+05 8.742E+00 2119 3.122E+02 2.500E+05 1.680E+01 8.339E+01 1.250E+05 8.399E+00 2120 3.000E+02 2.402E+05 1.614E+01 8.012E+01 1.201E+05 8.070E+00 2121 2.882E+02 2.308E+05 1.551E+01 7.698E+01 1.154E+05 7.753E+00 2122 2.769E+02 2.217E+05 1.490E+01 7.396E+01 1.109E+05 7.449E+00 2123 2.660E+02 2.130E+05 1.431E+01 7.106E+01 1.065E+05 7.157E+00 2124 2.556E+02 2.047E+05 1.375E+01 6.828E+01 1.023E+05 6.876E+00 2125 2.456E+02 1.967E+05 1.321E+01 6.560E+01 9.833E+04 6.607E+00 2126 2.360E+02 1.889E+05 1.270E+01 6.303E+01 9.447E+04 6.348E+00 2127 2.267E+02 1.815E+05 1.220E+01 6.056E+01 9.077E+04 6.099E+00 2128 2.178E+02 1.744E+05 1.172E+01 5.818E+01 8.721E+04 5.860E+00 2129 2.093E+02 1.676E+05 1.126E+01 5.590E+01 8.379E+04 5.630E+00 2130 2.011E+02 1.610E+05 1.082E+01 5.371E+01 8.051E+04 5.409E+00 2131 1.932E+02 1.547E+05 1.039E+01 5.160E+01 7.735E+04 5.197E+00 2132 1.856E+02 1.486E+05 9.987E+00 4.958E+01 7.432E+04 4.993E+00 2133 1.783E+02 1.428E+05 9.595E+00 4.764E+01 7.140E+04 4.798E+00 2134 1.713E+02 1.372E+05 9.219E+00 4.577E+01 6.860E+04 4.609E+00 2135 1.646E+02 1.318E+05 8.857E+00 4.397E+01 6.591E+04 4.429E+00 2136 1.582E+02 1.267E+05 8.510E+00 4.225E+01 6.333E+04 4.255E+00 2137 1 520E+02 1 217E+05 8 176E+00 4 059E+01 6 084E+04 4 088E+00 Year Total landfill gas Methane REPORT - 10 2137 1.520E+02 1.217E+05 8.176E+00 4.059E+01 6.084E+04 4.088E+00 2138 1.460E+02 1.169E+05 7.856E+00 3.900E+01 5.846E+04 3.928E+00 2139 1.403E+02 1.123E+05 7.548E+00 3.747E+01 5.617E+04 3.774E+00 2140 1.348E+02 1.079E+05 7.252E+00 3.600E+01 5.396E+04 3.626E+00 2141 1.295E+02 1.037E+05 6.967E+00 3.459E+01 5.185E+04 3.484E+00 2142 1.244E+02 9.963E+04 6.694E+00 3.323E+01 4.982E+04 3.347E+00 2143 1.195E+02 9.572E+04 6.432E+00 3.193E+01 4.786E+04 3.216E+00 2144 1.149E+02 9.197E+04 6.180E+00 3.068E+01 4.599E+04 3.090E+00 2145 1.104E+02 8.837E+04 5.937E+00 2.948E+01 4.418E+04 2.969E+00 REPORT - 10 Attachment C - LandGEM - Lined LF 11/17/2010 Results (Continued) Year (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2005 0 00000 2006 4.936E+00 2.697E+03 1.812E-01 7.733E-02 2.157E+01 1.450E-03 2007 1.930E+02 1.055E+05 7.086E+00 3.024E+00 8.437E+02 5.669E-02 2008 4.689E+02 2.562E+05 1.721E+01 7.346E+00 2.049E+03 1.377E-01 2009 7.120E+02 3.890E+05 2.614E+01 1.115E+01 3.112E+03 2.091E-01 2010 9.665E+02 5.280E+05 3.548E+01 1.514E+01 4.224E+03 2.838E-01 2011 1.215E+03 6.636E+05 4.459E+01 1.903E+01 5.309E+03 3.567E-01 2012 1.456E+03 7.953E+05 5.344E+01 2.281E+01 6.362E+03 4.275E-01 2013 1.690E+03 9.231E+05 6.203E+01 2.647E+01 7.385E+03 4.962E-01 2014 1.994E+03 1.089E+06 7.317E+01 3.123E+01 8.713E+03 5.854E-01 2015 2.289E+03 1.250E+06 8.400E+01 3.585E+01 1.000E+04 6.720E-01 2016 2.575E+03 1.407E+06 9.453E+01 4.034E+01 1.125E+04 7.562E-01 2017 2.853E+03 1.559E+06 1.047E+02 4.470E+01 1.247E+04 8.378E-01 2018 3.123E+03 1.706E+06 1.146E+02 4.892E+01 1.365E+04 9.170E-01 2019 3.385E+03 1.849E+06 1.242E+02 5.302E+01 1.479E+04 9.939E-01 2020 3.639E+03 1.988E+06 1.336E+02 5.700E+01 1.590E+04 1.068E+00 2021 3.885E+03 2.123E+06 1.426E+02 6.087E+01 1.698E+04 1.141E+00 2022 4.124E+03 2.253E+06 1.514E+02 6.461E+01 1.802E+04 1.211E+00 2023 4.356E+03 2.380E+06 1.599E+02 6.824E+01 1.904E+04 1.279E+00 2024 4.580E+03 2.502E+06 1.681E+02 7.175E+01 2.002E+04 1.345E+00 2025 4.798E+03 2.621E+06 1.761E+02 7.516E+01 2.097E+04 1.409E+00 2026 5.009E+03 2.736E+06 1.839E+02 7.847E+01 2.189E+04 1.471E+00 2027 5.213E+03 2.848E+06 1.913E+02 8.166E+01 2.278E+04 1.531E+00 2028 5.410E+03 2.956E+06 1.986E+02 8.475E+01 2.364E+04 1.589E+00 2029 5.601E+03 3.060E+06 2.056E+02 8.774E+01 2.448E+04 1.645E+00 2030 5.786E+03 3.161E+06 2.124E+02 9.063E+01 2.529E+04 1.699E+00 2031 5.964E+03 3.258E+06 2.189E+02 9.343E+01 2.607E+04 1.751E+00 2032 6.137E+03 3.353E+06 2.253E+02 9.614E+01 2.682E+04 1.802E+00 2033 6.304E+03 3.444E+06 2.314E+02 9.876E+01 2.755E+04 1.851E+00 2034 6.466E+03 3.533E+06 2.374E+02 1.013E+02 2.826E+04 1.899E+00 2035 6.587E+03 3.599E+06 2.418E+02 1.032E+02 2.879E+04 1.934E+00 2036 6 329E+03 3 458E+06 2 323E+02 9 915E+01 2 766E+04 1 859E+00 Carbon dioxide NMOC REPORT - 11 2036 6.329E+03 3.458E+06 2.323E+02 9.915E+01 2.766E+04 1.859E+00 2037 6.081E+03 3.322E+06 2.232E+02 9.526E+01 2.658E+04 1.786E+00 2038 5.843E+03 3.192E+06 2.145E+02 9.153E+01 2.553E+04 1.716E+00 2039 5.613E+03 3.067E+06 2.060E+02 8.794E+01 2.453E+04 1.648E+00 2040 5.393E+03 2.946E+06 1.980E+02 8.449E+01 2.357E+04 1.584E+00 2041 5.182E+03 2.831E+06 1.902E+02 8.118E+01 2.265E+04 1.522E+00 2042 4.979E+03 2.720E+06 1.827E+02 7.799E+01 2.176E+04 1.462E+00 2043 4.783E+03 2.613E+06 1.756E+02 7.494E+01 2.091E+04 1.405E+00 2044 4.596E+03 2.511E+06 1.687E+02 7.200E+01 2.009E+04 1.350E+00 2045 4.416E+03 2.412E+06 1.621E+02 6.917E+01 1.930E+04 1.297E+00 2046 4.243E+03 2.318E+06 1.557E+02 6.646E+01 1.854E+04 1.246E+00 2047 4.076E+03 2.227E+06 1.496E+02 6.386E+01 1.781E+04 1.197E+00 2048 3.916E+03 2.140E+06 1.438E+02 6.135E+01 1.712E+04 1.150E+00 2049 3.763E+03 2.056E+06 1.381E+02 5.895E+01 1.644E+04 1.105E+00 2050 3.615E+03 1.975E+06 1.327E+02 5.663E+01 1.580E+04 1.062E+00 2051 3.473E+03 1.898E+06 1.275E+02 5.441E+01 1.518E+04 1.020E+00 2052 3.337E+03 1.823E+06 1.225E+02 5.228E+01 1.459E+04 9.800E-01 2053 3.206E+03 1.752E+06 1.177E+02 5.023E+01 1.401E+04 9.416E-01 2054 3.081E+03 1.683E+06 1.131E+02 4.826E+01 1.346E+04 9.046E-01 REPORT - 11 Attachment C - LandGEM - Lined LF 11/17/2010 Results (Continued) (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2055 2.960E+03 1.617E+06 1.086E+02 4.637E+01 1.294E+04 8.692E-01 2056 2.844E+03 1.554E+06 1.044E+02 4.455E+01 1.243E+04 8.351E-01 2057 2.732E+03 1.493E+06 1.003E+02 4.280E+01 1.194E+04 8.023E-01 2058 2.625E+03 1.434E+06 9.636E+01 4.113E+01 1.147E+04 7.709E-01 2059 2.522E+03 1.378E+06 9.258E+01 3.951E+01 1.102E+04 7.407E-01 2060 2.423E+03 1.324E+06 8.895E+01 3.796E+01 1.059E+04 7.116E-01 2061 2.328E+03 1.272E+06 8.546E+01 3.647E+01 1.018E+04 6.837E-01 2062 2.237E+03 1.222E+06 8.211E+01 3.504E+01 9.777E+03 6.569E-01 2063 2.149E+03 1.174E+06 7.889E+01 3.367E+01 9.393E+03 6.311E-01 2064 2.065E+03 1.128E+06 7.580E+01 3.235E+01 9.025E+03 6.064E-01 2065 1.984E+03 1.084E+06 7.283E+01 3.108E+01 8.671E+03 5.826E-01 2066 1.906E+03 1.041E+06 6.997E+01 2.986E+01 8.331E+03 5.598E-01 2067 1.832E+03 1.001E+06 6.723E+01 2.869E+01 8.005E+03 5.378E-01 2068 1.760E+03 9.613E+05 6.459E+01 2.757E+01 7.691E+03 5.167E-01 2069 1.691E+03 9.236E+05 6.206E+01 2.649E+01 7.389E+03 4.965E-01 2070 1.624E+03 8.874E+05 5.963E+01 2.545E+01 7.099E+03 4.770E-01 2071 1.561E+03 8.526E+05 5.729E+01 2.445E+01 6.821E+03 4.583E-01 2072 1.500E+03 8.192E+05 5.504E+01 2.349E+01 6.554E+03 4.403E-01 2073 1.441E+03 7.871E+05 5.288E+01 2.257E+01 6.297E+03 4.231E-01 2074 1.384E+03 7.562E+05 5.081E+01 2.169E+01 6.050E+03 4.065E-01 2075 1.330E+03 7.266E+05 4.882E+01 2.083E+01 5.813E+03 3.905E-01 2076 1.278E+03 6.981E+05 4.690E+01 2.002E+01 5.585E+03 3.752E-01 2077 1.228E+03 6.707E+05 4.506E+01 1.923E+01 5.366E+03 3.605E-01 2078 1.180E+03 6.444E+05 4.330E+01 1.848E+01 5.155E+03 3.464E-01 2079 1.133E+03 6.191E+05 4.160E+01 1.775E+01 4.953E+03 3.328E-01 2080 1.089E+03 5.949E+05 3.997E+01 1.706E+01 4.759E+03 3.197E-01 2081 1.046E+03 5.715E+05 3.840E+01 1.639E+01 4.572E+03 3.072E-01 2082 1.005E+03 5.491E+05 3.690E+01 1.575E+01 4.393E+03 2.952E-01 2083 9.658E+02 5.276E+05 3.545E+01 1.513E+01 4.221E+03 2.836E-01 2084 9.279E+02 5.069E+05 3.406E+01 1.454E+01 4.055E+03 2.725E-01 2085 8.915E+02 4.870E+05 3.272E+01 1.397E+01 3.896E+03 2.618E-01 2086 8 566E+02 4 679E+05 3 144E+01 1 342E+01 3 743E+03 2 515E-01 NMOCCarbon dioxideYear REPORT - 12 2086 8.566E+02 4.679E+05 3.144E+01 1.342E+01 3.743E+03 2.515E-01 2087 8.230E+02 4.496E+05 3.021E+01 1.289E+01 3.597E+03 2.417E-01 2088 7.907E+02 4.320E+05 2.902E+01 1.239E+01 3.456E+03 2.322E-01 2089 7.597E+02 4.150E+05 2.789E+01 1.190E+01 3.320E+03 2.231E-01 2090 7.299E+02 3.987E+05 2.679E+01 1.143E+01 3.190E+03 2.143E-01 2091 7.013E+02 3.831E+05 2.574E+01 1.099E+01 3.065E+03 2.059E-01 2092 6.738E+02 3.681E+05 2.473E+01 1.056E+01 2.945E+03 1.979E-01 2093 6.474E+02 3.537E+05 2.376E+01 1.014E+01 2.829E+03 1.901E-01 2094 6.220E+02 3.398E+05 2.283E+01 9.744E+00 2.718E+03 1.826E-01 2095 5.976E+02 3.265E+05 2.194E+01 9.362E+00 2.612E+03 1.755E-01 2096 5.742E+02 3.137E+05 2.108E+01 8.995E+00 2.509E+03 1.686E-01 2097 5.517E+02 3.014E+05 2.025E+01 8.642E+00 2.411E+03 1.620E-01 2098 5.300E+02 2.896E+05 1.945E+01 8.303E+00 2.316E+03 1.556E-01 2099 5.092E+02 2.782E+05 1.869E+01 7.978E+00 2.226E+03 1.495E-01 2100 4.893E+02 2.673E+05 1.796E+01 7.665E+00 2.138E+03 1.437E-01 2101 4.701E+02 2.568E+05 1.725E+01 7.364E+00 2.054E+03 1.380E-01 2102 4.517E+02 2.467E+05 1.658E+01 7.075E+00 1.974E+03 1.326E-01 2103 4.339E+02 2.371E+05 1.593E+01 6.798E+00 1.897E+03 1.274E-01 2104 4.169E+02 2.278E+05 1.530E+01 6.531E+00 1.822E+03 1.224E-01 2105 4.006E+02 2.188E+05 1.470E+01 6.275E+00 1.751E+03 1.176E-01 REPORT - 12 Attachment C - LandGEM - Lined LF 11/17/2010 Results (Continued) (Mg/year)(m 3 /year)(av ft^3/min) (Mg/year)(m 3 /year)(av ft^3/min) 2106 3.849E+02 2.103E+05 1.413E+01 6.029E+00 1.682E+03 1.130E-01 2107 3.698E+02 2.020E+05 1.357E+01 5.793E+00 1.616E+03 1.086E-01 2108 3.553E+02 1.941E+05 1.304E+01 5.566E+00 1.553E+03 1.043E-01 2109 3.414E+02 1.865E+05 1.253E+01 5.347E+00 1.492E+03 1.002E-01 2110 3.280E+02 1.792E+05 1.204E+01 5.138E+00 1.433E+03 9.631E-02 2111 3.151E+02 1.721E+05 1.157E+01 4.936E+00 1.377E+03 9.253E-02 2112 3.028E+02 1.654E+05 1.111E+01 4.743E+00 1.323E+03 8.890E-02 2113 2.909E+02 1.589E+05 1.068E+01 4.557E+00 1.271E+03 8.542E-02 2114 2.795E+02 1.527E+05 1.026E+01 4.378E+00 1.221E+03 8.207E-02 2115 2.685E+02 1.467E+05 9.856E+00 4.206E+00 1.174E+03 7.885E-02 2116 2.580E+02 1.409E+05 9.470E+00 4.042E+00 1.128E+03 7.576E-02 2117 2.479E+02 1.354E+05 9.098E+00 3.883E+00 1.083E+03 7.279E-02 2118 2.382E+02 1.301E+05 8.742E+00 3.731E+00 1.041E+03 6.993E-02 2119 2.288E+02 1.250E+05 8.399E+00 3.585E+00 1.000E+03 6.719E-02 2120 2.198E+02 1.201E+05 8.070E+00 3.444E+00 9.608E+02 6.456E-02 2121 2.112E+02 1.154E+05 7.753E+00 3.309E+00 9.231E+02 6.203E-02 2122 2.029E+02 1.109E+05 7.449E+00 3.179E+00 8.869E+02 5.959E-02 2123 1.950E+02 1.065E+05 7.157E+00 3.055E+00 8.522E+02 5.726E-02 2124 1.873E+02 1.023E+05 6.876E+00 2.935E+00 8.187E+02 5.501E-02 2125 1.800E+02 9.833E+04 6.607E+00 2.820E+00 7.866E+02 5.285E-02 2126 1.729E+02 9.447E+04 6.348E+00 2.709E+00 7.558E+02 5.078E-02 2127 1.662E+02 9.077E+04 6.099E+00 2.603E+00 7.262E+02 4.879E-02 2128 1.596E+02 8.721E+04 5.860E+00 2.501E+00 6.977E+02 4.688E-02 2129 1.534E+02 8.379E+04 5.630E+00 2.403E+00 6.703E+02 4.504E-02 2130 1.474E+02 8.051E+04 5.409E+00 2.309E+00 6.440E+02 4.327E-02 2131 1.416E+02 7.735E+04 5.197E+00 2.218E+00 6.188E+02 4.158E-02 2132 1.360E+02 7.432E+04 4.993E+00 2.131E+00 5.945E+02 3.995E-02 2133 1.307E+02 7.140E+04 4.798E+00 2.048E+00 5.712E+02 3.838E-02 2134 1.256E+02 6.860E+04 4.609E+00 1.967E+00 5.488E+02 3.688E-02 2135 1.207E+02 6.591E+04 4.429E+00 1.890E+00 5.273E+02 3.543E-02 2136 1.159E+02 6.333E+04 4.255E+00 1.816E+00 5.066E+02 3.404E-02 2137 1 114E+02 6 084E+04 4 088E+00 1 745E+00 4 868E+02 3 271E-02 Carbon dioxide NMOCYear REPORT - 13 2137 1.114E+02 6.084E+04 4.088E+00 1.745E+00 4.868E+02 3.271E-02 2138 1.070E+02 5.846E+04 3.928E+00 1.676E+00 4.677E+02 3.142E-02 2139 1.028E+02 5.617E+04 3.774E+00 1.611E+00 4.493E+02 3.019E-02 2140 9.878E+01 5.396E+04 3.626E+00 1.547E+00 4.317E+02 2.901E-02 2141 9.491E+01 5.185E+04 3.484E+00 1.487E+00 4.148E+02 2.787E-02 2142 9.119E+01 4.982E+04 3.347E+00 1.429E+00 3.985E+02 2.678E-02 2143 8.761E+01 4.786E+04 3.216E+00 1.372E+00 3.829E+02 2.573E-02 2144 8.418E+01 4.599E+04 3.090E+00 1.319E+00 3.679E+02 2.472E-02 2145 8.088E+01 4.418E+04 2.969E+00 1.267E+00 3.535E+02 2.375E-02 REPORT - 13 Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment D Radius of Influence Calculations Radius of Influence Calculations Attachment D Computation Project Kenai CPL - Cells 1-5 of the Lined Landfill Computed JLS System Landfill Gas Collection System Date 7/15/2010 Component Vertical Well Spacing Reviewed RCR Task Radius of Influence Calculation Date 9/20/2010 Purpose Find Description Variable Units Radius of Influence Ra feet Given Description Value Source Design Capacity 1,608,461 [tons], Calculated in KPB Assumptions Convert to tons/yr 51,886 [tons/yr] Avg. Annual Acceptance, R 47,070 [Mg/yr], calculated from below (if not provided) Methane Gen. Potential, Lo 100 [m3/Mg], landGEM model, inventory value Density of Waste 1,150 [lbs/cy], From KPB Assumptions,default to 1,200 if not supplied Landfill age at closure 31 [years], From 2005 - end of 2035 Gas Generation Constant, k 0.04 [1/yr], landGEM model, inventory value Solution Description Value Comment Radius of Influence 154 feet Solve for the gas well radius of influence using equations provided in EPA's document, Air Emissions from Municipal Solid Waste Landfills - Background Information for Proposed Standards and Guidelines. Solve for the gas well radius of influence using equations provided in EPA's document, Air Emissions from Municipal Solid Waste Landfills - Background Information for Proposed Standards and Guidelines. Assumptions Waste in Place Density 1,150 lbs/cy, client supplied value, default to 1200 if no value given Well Flow Rate 0.04 m3/min/ m of landfill depth, EPA Gas Background Document page 7-3 Collection Efficiency 75% average collection effieiency Landfill Depth, L 1 [m], unit convention for flow/meter Equations Where:Ra = Radius of Influence, [m] Qw = Gas flow rate , [m3/yr] L = Landfill Depth, [m] Equation 1 ref = Refuse Density, [Mg/m3] Source: EPA Gas Background Doc.Qgen = Peak generation rate, [m3/yr] Ea = Fractional collection efficiency DesignCap = Design Capacity [Mg] Where:Qgen = Peak generation rate [m3/yr] Equation 2 Lo = Methane generation potential [m3/Mg refuse] Source: EPA Gas Background Doc.R = Average annual acceptance rate [Mg/yr] (Scholl Canyon Model)K = Gas generation rate constant [1/yr] t = landfill age at closure, [yr] Solve for the gas well radius of influence using equations provided in EPA's document, Air Emissions from Municipal Solid Waste Landfills - Background Information for Proposed Standards and Guidelines. Solve for the gas well radius of influence using equations provided in EPA's document, Air Emissions from Municipal Solid Waste Landfills - Background Information for Proposed Standards and Guidelines. 21 agenrefuse w a EQL DesignCapQR kt ogen eRLQ 12 21 agenrefuse w a EQL DesignCapQR Kenai Peninsula Landfill - CPL Landfill Gas Management Plan Page 1 of 2 November 2010 HDR Alaska, Inc. Radius of Influence Calculations Attachment D Computation Project Kenai CPL - Cells 1-5 of the Lined Landfill Computed JLS System Landfill Gas Collection System Date 7/15/2010 Component Vertical Well Spacing Reviewed RCR Task Radius of Influence Calculation Date 9/20/2010 Calculation Description Equation Comment Value Units Gas Flow Rate per meter depth of well Assume Value from 0.04 m3/min-m Convert to yearly 525,600 min/yr 21,024 m3/yr-m Design Capacity Given Value 1,608,461 tons Convert to Mg 1 ton = .9072 Mg 1,459,196 Mg Convert to Mg/yr 47,071 Mg/yr Refuse Density Given value 1,150 lbs/cy Convert to Mg/m3 1 lb/cy = .000593 Mg/m3 0.682 ug/m3 Determine peak rate Equation 2 above 6,689,743 m3/yr If peak rate is less than what is calculated from LandGEM output, default to rate calculated in LandGEM.8,640,000 m3/yr Peak Gas Generation Rate from Maximum Landfill Capacity default to rate calculated in LandGEM.8,640,000 m /yr Convert to cfm 1 ft3/min = 14,883.3 m3/yr 581 cfm Radius of Influence Solve for Ra Equation 1 above 47.0 m Convert to feet 1 m = 3.28 ft 154 ft *Provided by client Reference: Air Emissions from Municipal Solid Waste Landfills - Background Information for Proposed Standards and Guidelines (1991) EPA -450/3-90-011a, pages 7-3 and G-3 Kenai Peninsula Landfill - CPL Landfill Gas Management Plan Page 2 of 2 November 2010 HDR Alaska, Inc. Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 1 November 2010 HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 2 November 2010 HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 3 November 2010 HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 4 November 2010 HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 5 November 2010 HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 6 November 2010 HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 7 November 2010 HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 8 November 2010 HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 9 November 2010 HDR Alaska, Inc. Attachment E Pipe2010 Modeling Results for the Gas Collection System Kenai Peninsula Borough - CPL Landfill Gas Mangement Plan 10 November 2010 HDR Alaska, Inc. Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment F Condensate Generation Calculations Condensate Generation Calculations Attachment F Computation Project Kenai CPL - Cells 1-5 of the Lined Landfill Computed JLS System Landfill Gas Collection System Date 7/9/2010 Task Condensate Generation Calculation Reviewed KP/RCR Date 9/23/2010 Purpose Find Description Variable Units Condensate Generation C gen gal/day Given Description Value Source Total Gas flow (Qg )581 [cfm], KPB Design Assumptions, Total Gen. Temperature of LFG at Wellhead (T1)100 [oF], as a conservative assumption Temperature of LFG at the Blower (T2) 32 [oF]1 Vacuum at Blower 60 (in H2O) Solution Description Value Units comments Calculating the total possible water vapor extracted at the given flow rate and temperature of the Solve for the landfill gas condensate generation using vapor pressure and temperature equations. landfill and subtracting the water vapor that remains in the gas flow given the lower temperature of the piping system. A Psychrometric chart for high temperatures (developed by Carrier Corporation) was used. Psychrometric chart referenced from "Air Pollution Control: A Design Approach" by C. David Cooper and F.C. Alley, 2nd edition 1994, pages 666-669. Assumptions Relative Humidity of Landfill 100 % Relative Humidity of Gas in Piping 100 % Concentration of water vapor at 100 oF 0.043 lbs/lbs dry air and 100% rel. Humidity (C1) 0.043 kg/kg dry air Concentration of water vapor at 32 oF 0.0054 lbs/lbs dry air and 100% rel. Humidity (C2) 0.0054 kg/kg dry air Net water vapor (Cnet ) condensed in gas extraction piping (C1 - C2)0.038 kg/kg dry air Solve for the landfill gas condensate generation using vapor pressure and temperature equations. Kenai Peninsula Borough - CPL Landfill Gas Management Page 1 of 2 November 2010 HDR Alaska, Inc. Condensate Generation Calculations Attachment F Computation Project Kenai CPL - Cells 1-5 of the Lined Landfill Computed JLS System Landfill Gas Collection System Date 7/9/2010 Task Condensate Generation Calculation Reviewed KP/RCR Date 9/23/2010 Equations Density of landfill gas using Ideal Gas Law; the weight of landfill gas is typically close to the weight of air. PV = nRT or for this calculation P(MW) = RT MW = Molecular Weight of landfill gas = 30.00 g/mole MW of landfill gas equivalent to MW of air T = Temperature at the Blower (T2) 273 K R = Universal Gas Constant 0.0821 (L atm/mol K) P = absolute pressure in Gas Piping 0.85 atm (1.0 atm = approximately 34' water column at 40°F) Conversion factor 1000.0 g-mole/kg-mole Calculation = air density in gas piping 0.0011410 kg/L Equations Qg Cnet = C gen =0.0011410 kg/L Q =581 cfm (From LandGEM at 60 0F and 1 atm) Qg =646 cfm (at 32 0F and 0.85 atm) Cnet =0.038 kg/kg dry air Conversions: 1440 min/day 28.32 L / Cubic foot Calculation C gen = 1,131 Kg per day (1 Kg ≈ 1 L) Cgen = 299 Gal / day Note 1 : The temperature at the blower is conservatively assumed as the minimum temperature to prevent freezing conditions within the pipe network. Kenai Peninsula Borough - CPL Landfill Gas Management Page 2 of 2 November 2010 HDR Alaska, Inc. Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment G LANDTEC’s Landfill Automated Pump Station © 1992/1993 LANDTEC 850 South Via Lata, Suite 650, Colton, CA 92324. www.LANDTECNA.com. Phone: (800) 821-0496 (909) 783-3636. WBS is a product trademark. LANDTEC and LAPS are registered with the U.S. Patent and Trademark Office. All rights reserved. Rev 3 17-Feb-2010 0109 LAPS301ElectSub Specs (2). LANDTEC reserves the right to change these specifications without notice. Use of these specifications shall constitute an Agreement to accept the terms of LANDTEC's License Agreement. 15484 - 1 LFG Condensate Pump System SPECIFICATION SECTION 15484 ELECTRICALLY-OPERATED LANDFILL GAS CONDENSATE LIQUID PUMP SYSTEM (SUBMERSIBLE PUMP OPTION) PART 1 - GENERAL 1.1 SCOPE A. This Section covers the minimum requirements for the supply, installation and start-up of condensate liquid sump and an electrically operated automatic pump system. B. It is the intent of this Specification that the condensate liquid sump and automatic pump system shall be supplied as a prefabricated and shop tested assembly by an ISO 9000:2008 certified manufacturer. 1.2 APPLICATION A. Condensate liquid in the landfill gas collection pipe will flow to engineered low points within the gas piping system. B. All low points in the gas pipe and other locations indicated on the project Plans shall freely drain condensate liquid to sealed condensate sumps. C. Liquids collected in the sumps shall be automatically pumped from the sumps to designated locations at the landfill as shown on the project Plans. 1.3 SUBMITTALS A. The condensate sump Manufacturer's Start Up Procedure. B. Product Drawing showing the depth of the proposed landfill condensate liquid collection sump inlet below the gas pipe invert. (Note: This should be at least 3 feet to allow usable reservoir volume in the sump.) C. A Piping and Instrumentation Diagram showing the workings of the automatic pump system. D. Product Drawing showing the equipment layout and details. E. Manufacturer's Installation Instructions. 1.4 RELATED SPECIFICATIONS A. The Contractor is advised that other specifications may relate to this Work. 1.5 PRECEDENCE A. The Specifications included in this Section are specific to this Section only. Unless called out otherwise, the Specifications shall have precedence over the Drawings. Additionally, if other specification sections are more stringent than those included in this Section, the most stringent shall apply. Should any conflicts between the Specifications arise, the Contractor shall immediately bring them to the attention of the Engineer. 1.6 EXCAVATIONS AND BACKFILL A. Excavation included in this section addresses the excavation of the pit for the installation of the condensate collection sump and automatic pump system. © 1992/1993 LANDTEC 850 South Via Lata, Suite 650, Colton, CA 92324. www.LANDTECNA.com. Phone: (800) 821-0496 (909) 783-3636. WBS is a product trademark. LANDTEC and LAPS are registered with the U.S. Patent and Trademark Office. All rights reserved. Rev 3 17-Feb-2010 0109 LAPS301ElectSub Specs (2). LANDTEC reserves the right to change these specifications without notice. Use of these specifications shall constitute an Agreement to accept the terms of LANDTEC's License Agreement. 15484 - 2 LFG Condensate Pump System B. Excavations shall be done in a manner that complies with local, state, and federal law. 1.7 SAFETY A. The Contractor shall provide a Health and Safety Plan appropriate for the Work that will be performed. In addition to general construction health and safety issues, the Health and Safety Plan shall address protecting workers from exposure to landfill gas or refuse during the execution of the Work. 1.8 DISPOSAL OF EXCAVATED REFUSE A. Refuse excavated during the course of this Work shall not be used as backfill material. Refuse or contaminated soil shall be disposed of in a legal manner at an approved refuse disposal site. 1.9 REPAIRING THE CLAY COVER A. For sites that are covered with a clay cap, following installation of the condensate sump, the cap shall be repaired according to the maintenance and repair procedures for the cap or as directed by the Engineer. PART 2 - PRODUCTS 2.1 PRODUCT DESCRIPTION A. The condensate liquid sump shall be a stand-alone device with a minimum condensate liquid capacity of 5 gallons. B. Integral to the condensate sump shall be an electrically operated submersible pump with an automatic liquid level controller. C. The equipment shall be rated for service in harsh explosive environments and be able to pump landfill liquids including both leachate and condensate. D. Approved Manufacturer and equipment for the landfill condensate liquid collection sump and pump is LANDTEC LAPS-301, Landfill Automatic Pump Station. E. Equipment manufacturer shall be ISO 9001:2008 certified and have a proven performance of not less than six (6) years in actual landfill condensate liquid collection and pump service. F. It is the intent of these Specifications that the landfill gas condensate liquid sump and automatic pump system be supplied as a complete manufactured unit. 2.2 APPLICABLE CODES AND STANDARDS A. Pipe Material 1. The sump used as part of the condensate liquid sump and automatic pump system shall meet the following ASTM Specifications: a. HDPE Pipe D-3350 Standard Specifications for Polyethylene Plastics Pipe and Fittings Materials. 2. The plastic pipe for the automated pump system used as part of the condensate liquid sump and automated pump system shall meet the following ASTM specifications: a. PVC Pipe D-1785 Standard Specification for Polyvinyl Chloride (PVC) Plastic Pipe, Schedules 40, 80, and 120 B. Backfill Material © 1992/1993 LANDTEC 850 South Via Lata, Suite 650, Colton, CA 92324. www.LANDTECNA.com. Phone: (800) 821-0496 (909) 783-3636. WBS is a product trademark. LANDTEC and LAPS are registered with the U.S. Patent and Trademark Office. All rights reserved. Rev 3 17-Feb-2010 0109 LAPS301ElectSub Specs (2). LANDTEC reserves the right to change these specifications without notice. Use of these specifications shall constitute an Agreement to accept the terms of LANDTEC's License Agreement. 15484 - 3 LFG Condensate Pump System 1. Washed 3/8 inch pea gravel free of organic materials shall be used for backfill around the condensate liquid sump where indicated on the Plans and in these Specifications. Gravel shall meet the requirements of ASTM D-2487 well-sorted, poorly graded gravel with less than 15 percent sand group GW material. 2. Clay shall meet the requirements of ASTM D-2487 group CH material. Clay shall have a permeability of less than 1x10-6 cm/sec. 3. At a minimum, soil backfill and cover shall meet the engineering requirements for the site and shall be approved by the Engineer. In addition soil backfill shall not have any large stones or other foreign materials present. Care shall be taken that the material adjacent to the condensate sump is fine graded and that no objects are present that could cause damage to the sump. C. Compaction 1. Compaction tests, if required by the Specifications, shall be performed in accordance with ASTM D- 1557 Method C or Method D, whichever is most appropriate. 2.3 MATERIALS A. This Article describes the acceptable materials that shall be used for the construction of the electrically operated landfill gas condensate liquid pump system. B. Condensate Liquid Sump 1. The condensate liquid sump shall be an all welded, single walled HDPE assembly. A 2-inch HDPE branch connection shall be used to drain liquid into the sump. The sump shall be liquid and gas tight and shall be designed to withstand vacuum of 100 in. W.C. and pressure of 1 PSIG. 2. The sump shall be designed to have a 3-inch deep solids settling area. Further the design shall be such that solids within the settling area will not effect the pump or control system operation. C. Equipment Enclosure 1. The liquid pump and motor shall be located internal to the liquid sump assembly. The level control assembly, well cap and isolation valves shall be located in the vault section located above the liquid reservoir. A PVC partition plate shall be installed to isolate the reservoir section from the level control section. 2. Equipment shall be arranged to be easily accessible for operation and maintenance. 3. The liquid discharge, equalization and the electrical conduit shall be bulkhead mounted on the wall of the equipment enclosure of the LAPS-300TM. 4. The motor controller, electrical disconnect and level control shall be housed in an external NEMA 4 stainless steel control panel. D. Flexible Hoses 1. This Section covers flexible hoses that are supplied with the condensate liquid pump station and are outside the liquid sump. a. The 2-inch liquid inlet shall be connected using a 2-inch PVC reinforced flexible hose. Hose shall be rated for a vacuum of at least 100 inches of w.c. at the appropriate buried depth. b. The high-pressure liquid discharge and pressure equalization lines shall be constructed of PVC pipe and reinforced PVC hose. The hose shall be rated for a pressure of 100 PSIG at 72 deg F. with a minimum safety factor of 3. © 1992/1993 LANDTEC 850 South Via Lata, Suite 650, Colton, CA 92324. www.LANDTECNA.com. Phone: (800) 821-0496 (909) 783-3636. WBS is a product trademark. LANDTEC and LAPS are registered with the U.S. Patent and Trademark Office. All rights reserved. Rev 3 17-Feb-2010 0109 LAPS301ElectSub Specs (2). LANDTEC reserves the right to change these specifications without notice. Use of these specifications shall constitute an Agreement to accept the terms of LANDTEC's License Agreement. 15484 - 4 LFG Condensate Pump System 2. This Section covers hoses that are internal to the condensate liquid sump supplied by the landfill gas condensate liquid pump system supplier. a. Discharge hose between the pump and well cap shall be Nitrile, PVC with a working pressure of 300 psi and a bursting pressure of 1000 psi. E. Piping 1. Piping included in this section is for materials internal to the condensate liquid pump system only. a. Liquid discharge and pressure equalization piping shall be PVC Schedule 80. F. Liquid Pump 1. A Grundfos type 5E8 submersible liquid pump shall be used to transfer liquids from the reservoir. 2. The pump body shall be manufactured from 304 Stainless Steel. 3. Pump seals and diaphragms, which contact liquid, shall be Viton and Teflon. 4. Pump shall have 1 inch NPT discharge connection. G. Level Control 1. The level controller shall utilize four stainless steel conductance probes connected to UL rated intrinsically safe control modules. The output shall be used to control liquid level and indicate a high level in the sump. 2. Except for the threaded level sensor connection all wetted components shall be stainless steel the threaded connection shall be brass. 3. The actuation levels for pump operation and high level shall be factory set. H. Electrical Controls: 1. Electrical controls, level controls, motor starter and circuit braker disconnect shall be mounted in a single NEMA 4 stainless steel electrical enclosure. The control panel shall be a Square D style 8539 or approved equal. 2. The control panel shall be fitted with an externally mounted oil tight, “hand-off-auto” switch. Switch shall be a Square D Class 9001 or approved equal. 3. A green “Power On” pilot light, a red “Run” pilot light and an amber “High” pilot light shall be mounted on the front exterior of the control panel. Legend plates shall be provided for each pilot light. The pilot status lights for this section shall be push to test Square D Class 9001 or approved equal. I. Valves 1. Hand valves and check valves used in liquid service shall have PVC bodies with Teflon seats and socket weld ends. Valves shall be removable for servicing. J. Connections 1. Materials used in the high-pressure liquid discharge line shall be rated for 100 PSIG pressure with a safety factor of 2. 2. The pressure equalizing line which runs between the landfill condensate liquid pump system and the top of the LFG header shall be PVC hose, PVC or PE pipe, or other non-corrosive material ½ inch diameter or larger and shall be free draining. © 1992/1993 LANDTEC 850 South Via Lata, Suite 650, Colton, CA 92324. www.LANDTECNA.com. Phone: (800) 821-0496 (909) 783-3636. WBS is a product trademark. LANDTEC and LAPS are registered with the U.S. Patent and Trademark Office. All rights reserved. Rev 3 17-Feb-2010 0109 LAPS301ElectSub Specs (2). LANDTEC reserves the right to change these specifications without notice. Use of these specifications shall constitute an Agreement to accept the terms of LANDTEC's License Agreement. 15484 - 5 LFG Condensate Pump System K. Hardware 1. Flange bolts and nuts are to be stainless steel. L. O-Rings 1. O-Ring material shall be Viton, Teflon, or an equivalent and non-reactive material. 2.4 PROCESS PERFORMANCE SPECIFICATIONS A. Liquid Pump Rate 1. The liquid pump shall be capable of the following performance Specifications: Water Flow Rate (GPM) Discharge Head (feet) 2 200 4 160 6 100 2. The pump shall be capable of a maximum discharge head of 210 feet (at S.G. 1.0). B. Process Connection Fittings Type and Size 1. Process connections described in this section are those that are made by the installation Contractor. 2. The following condensate liquid pump system fittings shall be connected to the landfill gas collection system: Connection Item Size Furnished Connection Contractor Supplied Connection a. Electric (control panel to Motor) b. Electrical (control panel to level control) 3/4 inch 1/2 inch 3/4 in MNPT 1/2 inch MNPT Conduit: 3 #14 THHN Conduit 4 #12 THHN b. Liquid discharge 1 inch PVC Plain End PVC SOC c. Pressure equalization line 1/2 inch PVC Plain End PVC SOC d. Liquid inlet line 2 inch PVC Plain End PVC SOC 2.5 EXPERIENCE A. The equipment manufacture shall be ISO 9001:2008 certified and must have at least six (6) years of proven landfill gas performance or alternatively have at least 150 units in landfill service. PART 3 - EXECUTION 3.1 INSTALLATION INSTRUCTIONS A. Work shall be performed in accordance with the Manufacturer's Written Instructions and installation drawings. 3.2 EXCAVATION AND PREPARATION A. The excavation for the sump shall provide clearance of twelve (12) inches to refuse in all directions. © 1992/1993 LANDTEC 850 South Via Lata, Suite 650, Colton, CA 92324. www.LANDTECNA.com. Phone: (800) 821-0496 (909) 783-3636. WBS is a product trademark. LANDTEC and LAPS are registered with the U.S. Patent and Trademark Office. All rights reserved. Rev 3 17-Feb-2010 0109 LAPS301ElectSub Specs (2). LANDTEC reserves the right to change these specifications without notice. Use of these specifications shall constitute an Agreement to accept the terms of LANDTEC's License Agreement. 15484 - 6 LFG Condensate Pump System B. Loose refuse shall be removed from the bottom of the excavation so that a firm base exists for the sump to rest on. C. Twelve (12) inches of 3/8-inch gravel shall be installed in the excavation to serve as a base for the sump. 3.3 DISPOSAL OF REFUSE A. Refuse excavated during the course of this Work shall not be used as backfill material. Refuse or contaminated soil shall be disposed of in a legal manner at an approved refuse disposal site. B. Refuse and spoils shall be disposed of on a daily basis. No exposed refuse shall be allowed overnight. C. Disposal operations shall not create unsightly or unsanitary nuisances. 3.4 HANDLING AND SETTING THE UNIT A. The unit shall be lifted and handled according to Written Instructions supplied by the Manufacturer. B. The unit is to be set within one (1) degree of vertical. C. The unit shall be set so that it is concentrically located in the prepared excavation. D. The condensate collection sump shall be at least 12 inches from any landfill refuse. E. The condensate liquid sump shall be installed in an area that does not allow accumulation or ponding of water. The top of the vault assembly shall be at least 6 inches higher than surrounding grade unless installed in a watertight vault. F. The bottom of the condensate liquid sump shall extend a minimum of 3 feet below the invert of the LFG pipe from which condensate liquid drains. 3.5 CONNECTIONS A. Prior to making connections, lines shall be purged of debris and thoroughly cleaned. B. Condensate liquid discharge: The condensate liquid discharge line shall be connected to the condensate sump using good engineering practices. Materials and installation shall be as indicated on the piping plans. C. Equalizing Line: A pressure equalizing line shall be connected between the condensate sump and the top of the LFG header. The equalizing line shall be free draining to either the landfill gas collection pipe or the sump and shall be free of kinks or other obstructions to liquid or airflow. D. The condensate liquid inlet line shall be connected to the condensate sump using a 2-inch PVC SCH 80 male adapter fitting. The fitting shall be wrapped by the Contractor with two layers of 20-mil PVC pipe wrap tape. 3.6 BACKFILL A. The excavation shall be backfilled with pea gravel to a level 12 inches above the 2-inch condensate inlet. B. The excavation shall be backfilled with compacted soil or clay as approved by the Engineer to a level 24 inches below grade. C. Compacted soil or clay as specified and approved by the Engineer shall be used for the final backfill. D. The condensate liquid discharge and pressure equalizing pipes shall be protected by sleeves. Protective sleeves shall be paced over the lines adjacent to the vault to avoid shearing their connection during compaction. E. Soil or clay shall be installed in 6-inch maximum lifts. F. A soil berm shall be placed around the sump and shall extend 6” above grade or above the highest anticipated water level, which ever is higher, and blended with surrounding grade at a 4:1 slope. G. Excessive water infiltration into the pit shall be prevented during backfill and compaction operations. 3.7 COMPACTION © 1992/1993 LANDTEC 850 South Via Lata, Suite 650, Colton, CA 92324. www.LANDTECNA.com. Phone: (800) 821-0496 (909) 783-3636. WBS is a product trademark. LANDTEC and LAPS are registered with the U.S. Patent and Trademark Office. All rights reserved. Rev 3 17-Feb-2010 0109 LAPS301ElectSub Specs (2). LANDTEC reserves the right to change these specifications without notice. Use of these specifications shall constitute an Agreement to accept the terms of LANDTEC's License Agreement. 15484 - 7 LFG Condensate Pump System A. Minimum compaction around the condensate sump and shall be 85 percent relative compaction at 0 percent to 3 percent above optimum moisture. B. Compaction testing may be performed by the Owner at the Owner's expense. C. A permanently installed PVC sleeve at least 2 inches in diameter larger than the field connections shall be installed around external connections to protect them during compaction. D. Use extreme caution when compacting the soil above or adjacent to pipe connections. 3.8 REPAIRING CLAY AND GEOMEMBRANE A. Where the condensate liquid pump system penetrates a clay cap or Geomembrane cover on the landfill surface, the cap shall be repaired per the procedures provided by the Engineer to a level at least equal to the original cap. 3.9 TESTING A. Check sump storage tank, lines and block valve positions prior to operation. B. Testing shall include the minimum operations: 1. Pressure test to verify that connections are sealed (maximum test pressure of 1 PSIG). 2. Leak test the buried 2-inch sump connection prior to setting backfill. 3. Conduct test run per operating manual. 3.10 ACCEPTANCE A. Prior to acceptance the following verifications shall be made: 1. Verify unit is installed vertically. 2. Verify unit has been installed per the Manufacturer's Written Instructions. 3. Verify connections have been pressure tested per the Manufacturer's recommendations. 4. Verify the pipes and connections are clean and free of debris. 5. Verify the level sensing rods are wired to correct treminals in control panel. 6. Verify required functional testing has been completed. 7. Verify that Submittal requirements have been met. END OF SECTION Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment H Fen-Tech Environmental, Inc.’s 150 GPH Evap-O-Dry Evaporation Unit 4601 S. Hwy 377 Brownwood, TX 76801 (888)-777-4512 Fax (830)-393-4092 e-mail (doug@fen-tech.com) Waste Water Evaporation Systems Quote# HDR072810-150 Date 07/28/10 Budgetary Proposal For Leachate Model EC 150 150 GPH Evap-O-Dry Evaporation System Tank Vessel, Lid, Exhaust Chamber and Tube Constructed with 316L S/S Utilizing LFG Gas HDR Destination Alaska CONTENTS Specifications 3 Components 4 Equipment Cost 5 Payment Schedule 5 Warranty 6 Process Drawing 7 Proposed Model Drawing 8 Quote Prepared by Fen-Tech Environmental, Inc. Doug Beauchamp National Sales Manager 888-777-4512 Introduction Fen-Tech Environmental Inc.(longtime front-runner in the manufacturing of sludge dehydration equipment) sees much promise on the horizon for its wastewater evaporation systems. Fen-Tech’s innovative approach, and long successful history producing some of the most cost efficient and user friendly equipment for the processing of industrial sludge waste, has now been incorporated in the wastewater evaporators it produces. Fen-Tech’s products have been put to the test in over one thousand industrial locations under the harshest environmental conditions since 1985. The Evap-O-Dry (patent pending) evaporators incorporate numerous features, which far outpace what the traditional equipment has to offer. The professionals at Fen-Tech have researched the market, listened to their customers, and talked to owners/operators of other equipment. The communications, observation and research convinced the Fen-Tech staff that others had only partially addressed the problems associated with wastewater vaporization. Addressing the fallacies of other systems, while incorporating their own stringent quality and design criteria, the Evap-O-Dry was developed. Numerous problems exist with evaporation systems in place today, ranging from precipitated solids handling, corrosion, limited fuel source capabilities, high energy consumption, limited g.p.h. capabilities, operator attention, cookie cut design restrictions, inadequate customer services to air emissions compliance/assistance and guidance. Seeking viable solutions for industrial and municipal wastes has been Fen-Techs agenda of the day since 1985, with hundreds of custom designed systems in place today. 1 Description Evap-O-Dry Wastewater Evaporation System The Fen-Tech Environmental EVAP-O-DRY Wastewater Evaporation System is designed to efficiently evaporate wastewaters. A submerged burner tube fires below the solution level, which achieves 95% + energy efficiency. The hot gas contact with the liquid creates almost instantaneous vapor while the combustion gasses rapidly mix the liquid for even heat distribution and allowing the tube to be continuously self-purging. Thru extensive testing by Fen-Tech, we have proven sub-merged combustion can save as much as 25% in energy cost over serpentine tubes and hot plates. The uniqueness of the Evap-O-Dry lies in the cylindrical design of the solution tank, with a cone bottom. A drain port affixed to the cone allows for easy removal of any solids build up which will settle in the cone. All models are pre-piped, wired and tested before shipment. All models have a 10 micron pad mist eliminator to ensure only vapor is released to the atmosphere. Multiple devices are furnished to ensure a safe efficient continuous operation. EVAP-O-DRY Evaporators require a minimum of 4 PSI and a maximum of 10 PSI gas pressure. See specifications for gas pipe size. 2 Quote # HDR072810-150 HDR Date 7/28/2010 Budgetary Proposal Specifications Type of Effluent Reported: Leachate Shop Air Available Yes Reported Effluent gallons/hr Produced:144 gals. 0.55 cu/meters 545.04 liters 3.43 barrels/hour Reported Plant Operation hr's/per/day: 24 Unit Will be Located Inside Altitude Above Sea Level - Reported Plant Days per/week:7 Reported PH:7-8 Reported Disposal Cost per/gal: -$ Reported Electrical Service: Hz 60 Effluent Makeup:N/A Phase: 3 - Voltage: 460 Reported Electricity Cost per/kw: 0.10$ Type of Fuel Requested: LFG Gas @ 4 - 10 psi - Evaporation Model Suggested For Project ( calculations below or for budgetary purposes only) 4 Model EC 150 Model Capacity @24/hrs/day: Cu/meter Gallons Liters Barrels Hour 0.57 150 568 4 Day 13.63 3,600 13,626 86 Year 4,974 1,314,000 31,286 Actual Operating Time on Waste Water Reported: Cu/meter Gallons Barrels Year (evaporated)4,762 1,257,984 29,952 Total Hours (year)8,387 BTU's / Hr.:1,500,000 Estimated LFG Gas Consumption: SCFM Needed 55 Cu.Ft. / hr Needed 3,297 Gas Pipe Size 4" Excess SCFM 245 Reported LFG SCFM 300 BTU Value of LFG Reported 455 Electricity: KW's Needed per/hr 14.82 Cost per/Kw 0.10$ Cost per/hr 1.48$ Cost per/gal 0.010$ Dimensions: Model EC 150 4 Diameter 60" Height 128" Length Including Containment Exhaust Stack Size:24" rd Drain Pipe Size:4" Effluent Feed Pump Required: Pump Size GPM 5.00 @ 10 psi Inlet Feed Pipe Size 1" Estimated Solids Removal: Reported Solids 3,500 mg/l Every 343.57 Hours Remove Estimated 8.92 Cu.Ft. Solids 3 Quote # HDR072810-150Budgetary Proposal HDR Date 7/28/2010 Components Model EC 150 Standard With Each Model: Mist Pad 10 Micron High Gas Pressure Safty Shutdown Drawings & Manuals: Burner Low Liquid Level Safety Shutdown Electrical Schematics CombustionBlower High Temperature Safety Shutdown Component Cut Sheets Burner UV Sensor Pre-wired and Pre-piped NEC Electrical Code Operation & Service Manuals Insulation as Required Low Gas Pressure Safety Shut Down Tank Vessel, Lid, Exhaust Chamber and Tube Constructed with 316L S/S Options Requested: PLC Controls: (Panel View Touch Screen) The MicroLogix 1200 is filled with features and options designed to handle extensive range of applications Available in 24 and 40-point versions, the I/O count can be expanded using rackless I/O modules. This results in larger control systems, greater application flexibility and expandability at a lower cost and reduced parts inventory. A field-upgradeable flash operating system ensures you will always be up-to-date with the latest features, without having to replace hardware. The controller can be easily updated with the latest firmware via a web site download. LFG Gas Train A LFG gas train will be required when utilizing LFG as fuel source. Flame Arrester: An option added to LFG gas train. LFG Booster Blower Pkg. A LFG booster will be necessary to achieve the gas pressure required (4psi). The system wil be pre-piped and pre-wired. Includes LFG Booster Blower, LFG Cooler and Moiture Seperator. 4 Quote # HDR072810-150 HDR Date 7/28/2010 Equipment Cost Model EC 150 79,072.00 Chemical Feed System Not Applicable Phase Converter Not Applicable Corrosion Pkg.Not Applicable - PLC Controls 15,435.00 - Auger Drag-out System Not Applicable LFG Gas Train 4,455.00 LFG Booster Blower Pkg.48,400.00 Auto-dialer Not Applicable - Flame Arrester 1,580.00 Solids Dewatering System Not Applicable Oil Skimmer Not Applicable - - - Sub Total 148,942.00 Sales Tax - 2 n *Start-Up / Training Four (4) days allowed for start-up & training 5,200.00 4 Shipping (Alaska 99 7,000.00 3500 Sub Total 161,142.00 - Total 161,142.00$ *Fen-Tech has charged for four (4) days start-up and training, If final connections have not been made and it takes more than four(4) days, due to the fact that customer fails to have the site, utilities, piping and etc. ready upon arrival of equipment. There will be a $ 1000.00 per day charge per man for each day in excess of stated four (4) day. Payment Schedule 45% Down with purchase order 72,513.90$ 45% Down when ready to ship 72,513.90$ Balance due 30 days after receipt of equipment 16,114.20$ - - - 161,142.00$ Allow fourteen (14) to sixteen (16) weeks delivery / depending on availability of S/S upon order Rigging, site placement and final hook ups of all utilities are the responsibility of client. EVAP-O-DRY Evaporators require a minimum of 4 PSI and a maximum of 10 PSI gas pressure. Budgetary Proposal Prices firm thirty (30) days from proposal date End user responsible for all state and local taxes 5 Quote # HDR072810-150 HDR Date 7/28/2010 150 GPH Evap-O-Dry Evaporation System Limited Warranty The Evap-O-Dry equipment manufactured by Fen-Tech Environmental Inc., hereafter known as Fen-Tech, is guaranteed to be free from defects in workmanship and materials for a period of one year from date of delivery. Fen-Tech's obligation under this warranty shall be limited to the repair or replacement, at our option, of any part which we deem defective under this warranty. Conditions of warranty: 1) The equipment shall be used only by persons who are considered knowledgeable and properly trained by Fen-Tech; 2) All chemicals used during evaporation of waste water shall be properly neutralized and rendered harmless; 3) No combustible substances shall be placed in the equipment; 4) The equipment shall be used in accordance with Local, State and Federal rules, regulations, laws, ordinances and guidelines. Fen-Tech makes no other warranties by course of dealing, usage of trade, or otherwise, expressed or implied, which extend beyond the description and warranties herein. It is agreed that said warranties are in lieu of, and purchaser hereby waives, all other warranties, guarantees, conditions or liabilities, expressed or implied, arising by law or otherwise, including, but not limited to, any warranty, merchantability or fitness for a particular purpose under the uniform commercial code, any obligation of the Fen-Tech with respect of consequential damages, and shall not be extended, altered or varied. All repairs and replacement parts furnished under this warranty shall be F.O.B. point of distribution (the purchaser shall pay all necessary freight and delivery charges involved). Applicable Federal, State, or Local taxes will be added as required. This warranty is effective for a period of one (1) year from delivery date. This warranty does not cover damages resulting from accident, misuse, abuse, neglect or alteration. Normal wear on bearings, sprockets, drive chains, and other moving parts is not covered under warranty. Fen-Tech reserves the right to prorate the warranty adjustment when the reason for failure is questionable. Defective parts shall be received by Fen-Tech before any applicable credit is granted. Warranty Disclaimer: Due to the many factors that affect the corrosion of the evaporator material. Fen-Tech Environmental, Inc offers only options on material selection and assumes no responsibility for any failure that can be attributed to corrosion. This is in lieu of any warranties written, implied or verbal related to the evaporator life or performance in a corrosive environment. Fen-Tech Environmental, Inc. reserves the right to prorate the warranty adjustment, within reason, when failure is questionable. Defective parts shall be received by Fen-Tech before any applicable credit is granted. Evaporation rates based on water only, rates may vary on wastewater streams and atmospheric conditions. 6 7 Mist Pad Exhaust Vapor Level Control Combustion Blower TJ Burner Combustion Tube Skid (option) 1800 F + Hot Gases Water Temp 180 - 200 F Fen-Tech Environmental, Inc. Typical Process Evap-O-Dry Evaporation Systems 8 76" 48"26" 64" 103" * Dimensions & Specifications are Subject to Change Without Notice Model ECD 150 Fen-Tech Environmental, Inc. Mist Pad Exhaust Vapor stack Burner Skid Combustion Tube Level Control Combustion Blower Tank Drain Gas Train Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment I Technical Specifications Outline Kenai Peninsula Borough Central Peninsula Landfill Landfill Gas Collection and Control System Specification Outline TECHNICAL SPECIFICATIONS SECTION CONTENTS HDR Alaska, Inc. November 2010 Attachment I Division 1 – General Requirements 01005 Administrative Procedures 01010 Summary of Work 01015 Project Schedule 01025 Measurement and Payment 01027 Application for Payment 01035 Modification Procedures 01040 Coordination 01090 Reference Standards 01200 Project Meetings 01300 Submittals 01310 Progress Schedules 01330 Construction Surveys 01340 Shop Drawings 01400 Quality Control 01450 Source Quality Control 01500 Construction Facilities and Temporary Controls 01600 Material and Equipment 01700 Contract Close-out Division 2 – Site Work 02072 Demolition and Removal 02110 Site Clearing 02300 Earthwork 02316 Trench Excavation and Backfill 02610 Utility Systems 02620 Corrugated Metal Pipe 02800 Landfill Gas Piping 02810 Landfill Gas Extraction Wells 02830 Fence 02936 Seeding and Mulching Kenai Peninsula Borough Central Peninsula Landfill Landfill Gas Collection and Control System Specification Outline TECHNICAL SPECIFICATIONS SECTION CONTENTS HDR Alaska, Inc. November 2010 Attachment I Division 3 – Concrete 03300 Cast in Place Concrete 03600 Grouting-Equipment Supports and Installation Division 5 – Metals 05500 Metal Fabrication Division 11 – Special Construction 11010 Pre-Engineered Metal Building Division 15 – Mechanical 15010 General Provisions 15110 Landfill Gas Valves and Appurtenances 15300 Landfill Gas Control System 15500 Heating and Ventilation 15900 Mechanical Controls Division 16 – Electrical 16010 Basic Electrical Requirements 16050 Basic Materials and Methods Division 17 – Process Control 17100 Process Control and Instrumentation Systems Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment J Engineer’s Estimate of Probable Cost ATTACHMENT JENGINEER'S ESTIMATE OF PROBABLE COSTLFGCCS - DESIGN DEVELOPMENT PHASEItem NumberDescriptionQuantity Unit Unit PricePrice1 Drilling and Completion of 36" Diameter Bore Vertical Wel1,618 LF750.00$ 1,213,500$ 2 Vertical Wellhead Assembly and Enclosure31 EA3,500.00$ 108,500$ 3 Benching20 EA3,000.00$ 60,000$ 4 Abandonment (10% of Total Drilling)162 LF220.00$ 35,640$ 5 Supply and Install 12" Diameter SDR 17 HDPE Header Pipe in 5' Deep Trench2,950 LF125.00$ 368,750$ 6 Supply and Install 6" Diameter SDR 11 HDPE Header Pipe in 5' Deep Trench1,000 LF65.00$ 65,000$ 7 Supply and Install 6" Diameter SDR 11 HDPE Lateral Pipe in 5' Deep Trench1,540 LF65.00$ 100,100$ 8 Supply and Install 4" Diameter SDR 11 HDPE Lateral Pipe in 5' Deep Trench3,530 LF44.00$ 155,320$ 9 12" Diameter Header Isolation Valve and Enclosure4 EA24,000.00$ 96,000$ 10 12" Diameter Header Access Point and Enclosure4 EA4,800.00$ 19,200$ 11 Existing 6" Diameter Header Connections2 EA4,500.00$ 9,000$ 12 Trench 4-8 feet deep9,020 LF62.50$ 563,750$ 13 Service Road Crossing (CMP, deep trenching and markers)40 LF250.00$ 10,000$ 14 Condensate Sump including Leachate Cleanout Connection and Enclosure3 EA32,000.00$ 96,000$ 15 Electric Pump for Condensate Sumps3 EA5,500.00$ 16,500$ 16 Leachate Cleanout Connection (not including lateral piping)2 EA5,000.00$ 10,000$ 17 Leachate Cleanout Wellhead Assembly and Enclosure2 EA3,500.00$ 7,000$ 18 Control Building1 LS200,000.00$ 200,000$ 19 Flare Station and Blower1 LS180,000.00$ 180,000$ 20 Additional System Components1 LS20,000.00$ 20,000$ 21 Shipping & Handling1 LS25,000.00$ 25,000$ 22 Additional Miscellaneous Fittings and Components1 LS75,000.00$ 75,000$ 23 Construction Surveys1 LS35,000.00$ 35,000$ 24 Construction Erosion and Sedimentation Control1 LS75,000.00$ 75,000$ 25 Mobilization and Demobilization1 LS150,000.00$ 150,000$ ESTIMATED CONSTRUCTION COST SUBTOTAL3,694,260$ DESIGN AND CONSTRUCTION MANAGEMENT ASSISTANCE 12.00%443,311$ STARTUP AND TESTING SERVICES 1.00%36,943$ CONTINGENCY 20.00%738,852$ TOTAL ESTIMATED CONSTRUCTION COST 4,913,366$ Notes:1)2)3)4)5) Benching was assumed to occur on all vertical wells installed on the side slopes of the landfil6) Landfill gas collection system is for lined landfill onlyThe cost associated with testing services and project startup was assumed to be 1% of the construction subtotaA design and construction management assistance fee of 12% was used based on HDR experience with similar projects and the assumption that KPB will provideadministration, document control, and full-time supervision during constructionConstruction contingency was assumed to be 20% of the construction subtotal cosUnit price estimates are based on recent landfill gas projects in AlaskaMiscellaneousGas Collection System PipingVertical Well ConstructionCondensate SumpsLeachate Cleanout ConnectionsLFG Control Blower and Flare StationKenai Peninsula Borough - CPLLandfill Gas Management PlanPage 1 of 1November 2010HDR Alaska, Inc. Kenai Peninsula Borough - CPL November 2010 Landfill Gas Management Plan HDR Alaska, Inc. Attachment K Proposed Timeline for Schedule of Activities ATTACHMENT KPROPOSED TIMELINE FOR SCHEDULE OF ACTIVITIESOctoberNovemberDecemberJanuaryFebruaryMarchJanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecemberJanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecemberJanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecemberFinalize and Submit Design Capacity ReportMeet with ADECGHG Reporting for 2010Carbon Credit Feasibility StudyGrant Application Submission and AwardNotification to ADEC/EPARegister with Carbon Credit MarketPrepare GCCS Construction DocumentsAir Quality Permit ApplicationBidding ProcessPotential for Asbestos Disturbance NotificationInstallation of GCCSFlare Station Performance TestSSM Plan DevelopmentGCCS StartupNotes:Year 31) The carbon credit feasibility study will investigate the potential for complete funding of the gas collection and control system. Assuming that the carbon credit projectindicates that the project may be financially viable the project will proceed forward.2) Assuming that the grant application development, submission and award requires a 6 month period the design of the GCCS will not commence until the following year.If a grant can not be obtained for the site the feasibility of installing a collection and control system may not be sufficient with the capital required for the initialinstallation.3) Construction is assumed to take place on the collection and control system during the Summer of Year 3 to allow sufficient time for the budgeting for the installationand design of the collection and control system.Year 22010 2011 Year 1Kenai Peninsula Borough ‐ CPLLandfill Gas Mangement PlanPage 1 of 1November 2010HDR Alaska, Inc. AEEC – CPL Landfill Gas CHP Project REF Round 14 Application Attachment J: Project Financial Feasibility Model Runs AEEC Central Peninsula Landfill Gas to Energy Project Feasibility Analysis Project Start Cell Names Present Value 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 Discount Rate (approximate real rate, excludes inflation)2.0% Inflation Rate 2.0%Inf_Rate Discount Rate (nominal, includes inflation)2.0%Disc_Rate Project Capital Cost $12,534,000 CAPEX Gas System Installation Costs $2,283,500 GasSystem_CAPEX Natural gas Btu (Btu/gal)12,000 Gas_Btu Natural Gas Heating Value (Btu per Ccf)98,500 Btu_Ccf Percent Methane 50%pct_CH4 AEEC Small Facility Power Purchase Rate ($/MWh)$91.50 Current_Gen_Cost Interconnect Cost (2019$)$150,000 Interconnect Enstar G4 Rates Customer Charge ($/month)$530 C_Charge Service Charge (Base, $/Ccf)$0.06483 S_Charge Supplier Gas Cost Charge (GCA, $/Ccf)$0.79196 GCA Regulatory Cost Charge (RCC, % of total bill)0.4%RCC Scenario Base Case Engine rated capacity (MW)1.6 MW AEEC Net savings $4,755,000 Availablity 95.0%Availability KPB Savings $10,755,000 Line losses 2.0%Line_Losses Total Project Savings $15,510,000 Parasitic losses 5.0%Par_Losses CHP natural gas fuel requirement (scf/min)270.0 NG_fuel Non-Fuel CHP Operating Cost $0.045 CHP routine maintenance, labor and consumables ($/kWh)$0.025 CHP_labor CHP major maintenance and non-routine reserve ($/kWh)$0.020 CHP_reserve Operating cost reduction if NG only 20.0%NG_reduce Grant Funding for CHP engine purchase $0 CHP_Grant 2019 Payment by KPB for CHP O&M costs $0 KPB_O&M_2019 Property Taxes $0 Year LFG is blended with NG as fuel for CHP 2022 Year_LFG Revenues to AEEC Electricity Revenues (after costs of transmission and distribution) Use full 1.6MW output (Yes) or use only LFG when not evaporating (No)Yes % of potential output CHP engine runs during the year pct_output 0 0 0 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100% Electricity sales (MWh with availability and losses)MWh 0 0 0 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 Cost of Competing Generation ($/MWh)Gen_Cost $91.50 $93.33 $95.20 $97.10 $99.04 $101.02 $103.04 $105.10 $107.21 $109.35 $111.54 $113.77 $116.04 $118.37 $120.73 $123.15 $125.61 $128.12 $130.68 $133.30 $135.96 $138.68 $141.46 $144.29 $147.17 $150.12 $153.12 $156.18 $159.30 $162.49 $165.74 $169.05 $172.44 Renewable energy incentives (RE certificates, tax credits, GHG credits)Ren_Credits $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Electricity Revenues $33,857,000 $0 $0 $0 $1,197,646 $1,221,599 $1,246,031 $1,270,951 $1,296,370 $1,322,298 $1,348,744 $1,375,718 $1,403,233 $1,431,298 $1,459,923 $1,489,122 $1,518,904 $1,549,282 $1,580,268 $1,611,873 $1,644,111 $1,676,993 $1,710,533 $1,744,744 $1,779,639 $1,815,231 $1,851,536 $1,888,567 $1,926,338 $1,964,865 $2,004,162 $2,044,245 $2,085,130 $2,126,833 KPB Payment to AEEC for Exhaust Heat Leachate requiring evaporation (gal/year)Leachate_Yr 1,633,612 1,666,284 1,699,610 1,733,602 1,768,274 1,803,639 1,839,712 1,876,506 1,914,037 1,952,317 1,991,364 2,031,191 2,071,815 2,113,251 2,155,516 2,198,626 2,242,599 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 Leachate evaporation rate from CAT engine (gal/day)Evap_Rate 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 Natural gas equivalents/yr to operate CHP engine at 1.6MW (Ccf/year)CHP_NG_yr 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 Days required to evaporate leachate at 1.6MW Evap_Days 194 198 202 206 211 215 219 223 228 232 237 242 247 252 257 262 267 272 272 272 272 272 272 272 272 272 272 272 272 272 272 272 272 Days when evaporator is not running Nonevap_Days 171 167 163 159 154 150 146 142 137 133 128 123 118 113 108 103 98 93 93 93 93 93 93 93 93 93 93 93 93 93 93 93 93 Natural gas equivalents/day to operate CHP engine at 1.6MW (Ccf/day)NGe_day 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 Landfill gas generation (cf/min)LFG_per_min 248.5 267.1 285.2 302.8 319.8 336.2 352.2 367.7 382.7 397.2 411.2 424.7 437.8 450.5 462.8 474.7 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 Landfill gas generation (Ccf/yr)LFG_gen 1,306,116 1,403,878 1,499,011 1,591,517 1,680,869 1,767,067 1,851,163 1,932,631 2,011,471 2,087,683 2,161,267 2,232,223 2,301,077 2,367,828 2,432,477 2,495,023 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 Landfill methane available per year (Ccf/year)CH4_gen 653,058 701,939 749,506 795,758 840,434 883,534 925,582 966,316 1,005,736 1,043,842 1,080,634 1,116,112 1,150,538 1,183,914 1,216,238 1,247,512 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 Landfill methane available per day (Ccf/day)CH4_day 1,789 1,923 2,053 2,180 2,303 2,421 2,536 2,647 2,755 2,860 2,961 3,058 3,152 3,244 3,332 3,418 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 Pipeline gas used to evaporate leachate per day (Ccf/day)NG_day 2,099 1,965 1,835 1,708 1,585 1,467 1,352 1,241 1,133 1,028 927 830 736 644 556 470 406 406 406 406 406 406 406 406 406 406 406 406 406 406 406 406 406 Natural gas equivalents to evaporate leachate (Ccf/year)KPB_NG_usage 756,129 771,251 786,677 802,410 818,458 834,827 851,524 868,554 885,926 903,644 921,717 940,151 958,954 978,133 997,696 1,017,650 1,038,003 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 KPB natural gas price, ENSTAR ($/Ccf)KPB_NG_Price $0.8687 $0.8860 $0.9038 $0.9218 $0.9403 $0.9591 $0.9783 $0.9978 $1.0178 $1.0381 $1.0589 $1.0801 $1.1017 $1.1237 $1.1462 $1.1691 $1.1925 $1.2163 $1.2407 $1.2655 $1.2908 $1.3166 $1.3429 $1.3698 $1.3972 $1.4251 $1.4536 $1.4827 $1.5124 $1.5426 $1.5735 $1.6049 $1.6370 KPB Payment to AEEC for Exhaust Heat KPB_Heat_Pmt $25,850,000 $0 $0 $0 $739,687 $769,570 $800,661 $833,007 $866,661 $901,674 $938,101 $976,001 $1,015,431 $1,056,455 $1,099,135 $1,143,540 $1,189,739 $1,237,805 $1,287,812 $1,313,568 $1,339,840 $1,366,637 $1,393,969 $1,421,849 $1,450,286 $1,479,291 $1,508,877 $1,539,055 $1,569,836 $1,601,233 $1,633,257 $1,665,922 $1,699,241 $1,733,226 KPB Payment for CHP O&M costs KPB_CHPOM_Pmt $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Revenues $59,707,000 $0 $0 $0 $1,937,332 $1,991,169 $2,046,691 $2,103,958 $2,163,031 $2,223,971 $2,286,845 $2,351,719 $2,418,664 $2,487,752 $2,559,059 $2,632,662 $2,708,644 $2,787,087 $2,868,080 $2,925,442 $2,983,951 $3,043,630 $3,104,502 $3,166,592 $3,229,924 $3,294,523 $3,360,413 $3,427,621 $3,496,174 $3,566,097 $3,637,419 $3,710,168 $3,784,371 $3,860,058 Costs to AEEC Capital Cost of Improvements $10,251,000 $0 $0 $10,664,620 less grant funding $0 $0 $0 $0 plus Interconnect costs $150,000 $0 $0 $156,060 Total Capital Cost of Improvements $10,401,000 Fuel Cost Fuel Type by year Natural gas purchased (Ccf)NG_purchase 0.0 0.0 0.0 623,362 578,686 535,586 493,538 452,804 413,384 375,278 338,486 303,008 268,582 235,206 202,882 171,608 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 Landfill methane (Ccf)LFM_purchase 0.0 0.0 0.0 795,758 840,434 883,534 925,582 966,316 1,005,736 1,043,842 1,080,634 1,116,112 1,150,538 1,183,914 1,216,238 1,247,512 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 AEEC natural gas price ($/Mcf)AEEC_NG_Price $7.62 $8.09 $8.14 $8.20 $8.27 $8.43 $8.60 $8.78 $8.95 $9.13 $9.31 $9.50 $9.69 $9.88 $10.08 $10.28 $10.49 $10.70 $10.91 $11.13 $11.35 $11.58 $11.81 $12.05 $12.29 $12.53 $12.78 $13.04 $13.30 $13.57 $13.84 $14.12 $14.40 AEEC natural gas purchases NG_pmt $0 $0 $0 $511,097 $478,542 $451,759 $424,618 $397,364 $370,026 $342,635 $315,224 $287,828 $260,229 $232,449 $204,513 $176,448 $155,448 $158,556 $161,728 $164,962 $168,261 $171,627 $175,059 $178,560 $182,132 $185,774 $189,490 $193,279 $197,145 $201,088 $205,110 $209,212 $213,396 AEEC Payment to KPB for LFG Usage AEEC_LFG_Pmt $0 $0 $0 $733,555 $790,233 $847,373 $905,454 $964,209 $1,023,614 $1,083,645 $1,144,277 $1,205,481 $1,267,518 $1,330,372 $1,394,030 $1,458,472 $1,515,533 $1,545,843 $1,576,760 $1,608,295 $1,640,461 $1,673,270 $1,706,736 $1,740,870 $1,775,688 $1,811,202 $1,847,426 $1,884,374 $1,922,062 $1,960,503 $1,999,713 $2,039,707 $2,080,501 Total Fuel Cost $36,201,000 $0 $0 $0 $1,244,652 $1,268,775 $1,299,133 $1,330,073 $1,361,573 $1,393,640 $1,426,280 $1,459,501 $1,493,309 $1,527,746 $1,562,821 $1,598,543 $1,634,920 $1,670,980 $1,704,400 $1,738,488 $1,773,257 $1,808,723 $1,844,897 $1,881,795 $1,919,431 $1,957,819 $1,996,976 $2,036,915 $2,077,654 $2,119,207 $2,161,591 $2,204,823 $2,248,919 $2,293,898 Non-Fuel Operating Costs CHP routine maintenance, labor and consumables ($/kWh)CHP_Labor_Trend $0.025 $0.026 $0.026 $0.027 $0.027 $0.028 $0.028 $0.029 $0.029 $0.030 $0.030 $0.031 $0.032 $0.032 $0.033 $0.034 $0.034 $0.035 $0.036 $0.036 $0.037 $0.038 $0.039 $0.039 $0.040 $0.041 $0.042 $0.043 $0.044 $0.044 $0.045 $0.046 $0.047 CHP major maintenance and non-routine reserve ($/kWh)CHP_Reserve_Trend $0.020 $0.020 $0.021 $0.021 $0.022 $0.022 $0.023 $0.023 $0.023 $0.024 $0.024 $0.025 $0.025 $0.026 $0.026 $0.027 $0.027 $0.028 $0.029 $0.029 $0.030 $0.030 $0.031 $0.032 $0.032 $0.033 $0.033 $0.034 $0.035 $0.036 $0.036 $0.037 $0.038 Reduction if natural gas fuel only 20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0% Percent Pipeline gas Pct_Pipegas 0.0%0.0%0.0%43.9%40.8%37.7%34.8%31.9%29.1%26.4%23.9%21.4%18.9%16.6%14.3%12.1%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4% Cost per kWh - NG only NG_O&M_Trend $0.036 $0.037 $0.037 $0.038 $0.039 $0.040 $0.041 $0.041 $0.042 $0.043 $0.044 $0.045 $0.046 $0.047 $0.048 $0.048 $0.049 $0.050 $0.051 $0.052 $0.053 $0.055 $0.056 $0.057 $0.058 $0.059 $0.060 $0.061 $0.063 $0.064 $0.065 $0.067 $0.068 Cost per kWh - NG with LFG NG&LFG_O&M_Trend $0.045 $0.046 $0.047 $0.048 $0.049 $0.050 $0.051 $0.052 $0.053 $0.054 $0.055 $0.056 $0.057 $0.058 $0.059 $0.061 $0.062 $0.063 $0.064 $0.066 $0.067 $0.068 $0.070 $0.071 $0.072 $0.074 $0.075 $0.077 $0.078 $0.080 $0.082 $0.083 $0.085 Total non-fuel operating costs $8,350,000 $0 $0 $0 $537,261 $326,631 $330,022 $333,354 $336,621 $339,815 $342,931 $345,960 $348,895 $351,727 $354,449 $357,051 $359,524 $361,858 $364,042 $371,323 $378,749 $386,324 $394,051 $401,932 $409,970 $418,170 $426,533 $435,064 $443,765 $452,640 $461,693 $470,927 $480,346 $489,953 Total costs to AEEC $54,952,000 $1,781,913 $1,595,406 $1,629,155 $1,663,427 $1,698,193 $1,733,455 $1,769,211 $1,805,461 $1,842,204 $1,879,474 $1,917,270 $1,955,594 $1,994,444 $2,032,838 $2,068,442 $2,109,810 $2,152,007 $2,195,047 $2,238,948 $2,283,727 $2,329,401 $2,375,989 $2,423,509 $2,471,979 $2,521,419 $2,571,847 $2,623,284 $2,675,750 $2,729,265 $2,783,850 AEEC Comparison Costs per MWh Project annualized capital cost ($/MWh)$39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 $39 Project cost to AEEC (per MWh)$0 $0 $0 $144 $129 $132 $135 $138 $141 $143 $146 $149 $152 $155 $159 $162 $165 $168 $171 $174 $178 $182 $185 $189 $193 $196 $200 $204 $209 $213 $217 $221 $226 Total Project Cost ($/Mwh)$0 $0 $0 $184 $169 $171 $174 $177 $180 $183 $186 $189 $192 $195 $198 $201 $204 $207 $210 $214 $217 $221 $224 $228 $232 $236 $240 $244 $248 $252 $256 $260 $265 Cost of Competing Generation ($/MWh)$92 $93 $95 $97 $99 $101 $103 $105 $107 $109 $112 $114 $116 $118 $121 $123 $126 $128 $131 $133 $136 $139 $141 $144 $147 $150 $153 $156 $159 $162 $166 $169 $172 Net Revenues to AEEC $4,755,000 KPB Feasibility Revenue and Cost of New System Revenue and Savings Revenue from gas sale to AEEC $30,457,000 $0 $0 $0 $733,555 $790,233 $847,373 $905,454 $964,209 $1,023,614 $1,083,645 $1,144,277 $1,205,481 $1,267,518 $1,330,372 $1,394,030 $1,458,472 $1,515,533 $1,545,843 $1,576,760 $1,608,295 $1,640,461 $1,673,270 $1,706,736 $1,740,870 $1,775,688 $1,811,202 $1,847,426 $1,884,374 $1,922,062 $1,960,503 $1,999,713 $2,039,707 $2,080,501 Foregone Cost of Natural Gas Spent on Current Evaporator System 2017-18 Cost per gallon, inflated $0.105 $0.107 $0.110 $0.112 $0.114 $0.116 $0.119 $0.121 $0.123 $0.126 $0.128 $0.131 $0.134 $0.136 $0.139 $0.142 $0.145 $0.148 $0.151 $0.154 $0.157 $0.160 $0.163 $0.166 $0.170 $0.173 $0.176 $0.180 $0.183 $0.187 $0.191 $0.195 $0.199 Foregone Cost $6,775,000 $0 $0 $0 $193,879 $201,712 $209,861 $218,340 $227,161 $236,338 $245,886 $255,820 $266,155 $276,908 $288,095 $299,734 $311,843 $324,441 $337,549 $344,300 $351,186 $358,209 $365,374 $372,681 $380,135 $387,737 $395,492 $403,402 $411,470 $419,699 $428,093 $436,655 $445,388 $454,296 Total Savings (Cost) of New System $37,232,000 Costs Gas System Capital Costs Capital Cost without project (end of cell 5)$2,890,500 Capital Cost if spent for this project $3,233,500 Net Present Value of Capital Cost for this project $343,000 Payment to AEEC for waste heat $25,850,000 $0 $0 $0 $739,687 $769,570 $800,661 $833,007 $866,661 $901,674 $938,101 $976,001 $1,015,431 $1,056,455 $1,099,135 $1,143,540 $1,189,739 $1,237,805 $1,287,812 $1,313,568 $1,339,840 $1,366,637 $1,393,969 $1,421,849 $1,450,286 $1,479,291 $1,508,877 $1,539,055 $1,569,836 $1,601,233 $1,633,257 $1,665,922 $1,699,241 $1,733,226 Labor Cost to Operate Evaporation System Current Evaporator $23,410 $24,355 $25,339 $26,363 $27,428 $28,536 $29,689 $30,888 $32,136 $33,435 $34,785 $36,191 $37,653 $39,174 $40,757 $41,572 $42,403 $43,251 $44,116 $44,999 $45,899 $46,817 $47,753 $48,708 $49,682 $50,676 $51,689 $52,723 $53,778 $54,853 CHP Evaporator $31,538 $32,812 $34,138 $35,517 $36,952 $38,445 $39,998 $41,614 $43,295 $45,044 $46,864 $48,757 $50,727 $52,776 $54,908 $56,006 $57,127 $58,269 $59,434 $60,623 $61,836 $63,072 $64,334 $65,620 $66,933 $68,272 $69,637 $71,030 $72,450 $73,899 Added Labor Cost of New System $284,000 $0 $0 $0 $8,128 $8,457 $8,798 $9,154 $9,524 $9,908 $10,309 $10,725 $11,158 $11,609 $12,078 $12,566 $13,074 $13,602 $14,152 $14,435 $14,723 $15,018 $15,318 $15,625 $15,937 $16,256 $16,581 $16,912 $17,251 $17,596 $17,948 $18,307 $18,673 $19,046 Payment to AEC for CHP O&M costs $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Cost of New System $26,477,000 Net savings (cost) of new system $10,755,000 Results AEEC Central Peninsula Landfill Gas to Energy Project Feasibility Analysis Project Start Cell Names Present Value 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 Discount Rate (approximate real rate, excludes inflation)2.0% Inflation Rate 2.0%Inf_Rate Discount Rate (nominal, includes inflation)2.0%Disc_Rate Project Capital Cost $11,649,014 CAPEX 10764028 Gas System Installation Costs $2,283,500 GasSystem_CAPEX Natural gas Btu (Btu/gal)12,000 Gas_Btu Natural Gas Heating Value (Btu per Ccf)98,500 Btu_Ccf Percent Methane 50%pct_CH4 AEEC Small Facility Power Purchase Rate ($/MWh)$91.50 Current_Gen_Cost Interconnect Cost (2019$)$150,000 Interconnect Enstar G4 Rates Customer Charge ($/month)$530 C_Charge Service Charge (Base, $/Ccf)$0.06483 S_Charge Supplier Gas Cost Charge (GCA, $/Ccf)$0.79196 GCA Regulatory Cost Charge (RCC, % of total bill)0.4%RCC Scenario Base Case Engine rated capacity (MW)1.6 MW AEEC Net savings $5,640,000 Availablity 95.0%Availability KPB Savings $10,755,000 Line losses 2.0%Line_Losses Total Project Savings $16,395,000 Parasitic losses 5.0%Par_Losses CHP natural gas fuel requirement (scf/min)270.0 NG_fuel Non-Fuel CHP Operating Cost $0.045 CHP routine maintenance, labor and consumables ($/kWh)$0.025 CHP_labor CHP major maintenance and non-routine reserve ($/kWh)$0.020 CHP_reserve Operating cost reduction if NG only 20.0%NG_reduce Grant Funding for CHP engine purchase $0 CHP_Grant 2019 Payment by KPB for CHP O&M costs $0 KPB_O&M_2019 Property Taxes $0 Year LFG is blended with NG as fuel for CHP 2022 Year_LFG Revenues to AEEC Electricity Revenues (after costs of transmission and distribution) Use full 1.6MW output (Yes) or use only LFG when not evaporating (No)Yes % of potential output CHP engine runs during the year pct_output 0 0 0 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100% Electricity sales (MWh with availability and losses)MWh 0 0 0 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 Cost of Competing Generation ($/MWh)Gen_Cost $91.50 $93.33 $95.20 $97.10 $99.04 $101.02 $103.04 $105.10 $107.21 $109.35 $111.54 $113.77 $116.04 $118.37 $120.73 $123.15 $125.61 $128.12 $130.68 $133.30 $135.96 $138.68 $141.46 $144.29 $147.17 $150.12 $153.12 $156.18 $159.30 $162.49 $165.74 $169.05 $172.44 Renewable energy incentives (RE certificates, tax credits, GHG credits)Ren_Credits $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Electricity Revenues $33,857,000 $0 $0 $0 $1,197,646 $1,221,599 $1,246,031 $1,270,951 $1,296,370 $1,322,298 $1,348,744 $1,375,718 $1,403,233 $1,431,298 $1,459,923 $1,489,122 $1,518,904 $1,549,282 $1,580,268 $1,611,873 $1,644,111 $1,676,993 $1,710,533 $1,744,744 $1,779,639 $1,815,231 $1,851,536 $1,888,567 $1,926,338 $1,964,865 $2,004,162 $2,044,245 $2,085,130 $2,126,833 KPB Payment to AEEC for Exhaust Heat Leachate requiring evaporation (gal/year)Leachate_Yr 1,633,612 1,666,284 1,699,610 1,733,602 1,768,274 1,803,639 1,839,712 1,876,506 1,914,037 1,952,317 1,991,364 2,031,191 2,071,815 2,113,251 2,155,516 2,198,626 2,242,599 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 Leachate evaporation rate from CAT engine (gal/day)Evap_Rate 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 Natural gas equivalents/yr to operate CHP engine at 1.6MW (Ccf/year)CHP_NG_yr 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 Days required to evaporate leachate at 1.6MW Evap_Days 194 198 202 206 211 215 219 223 228 232 237 242 247 252 257 262 267 272 272 272 272 272 272 272 272 272 272 272 272 272 272 272 272 Days when evaporator is not running Nonevap_Days 171 167 163 159 154 150 146 142 137 133 128 123 118 113 108 103 98 93 93 93 93 93 93 93 93 93 93 93 93 93 93 93 93 Natural gas equivalents/day to operate CHP engine at 1.6MW (Ccf/day)NGe_day 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 Landfill gas generation (cf/min)LFG_per_min 248.5 267.1 285.2 302.8 319.8 336.2 352.2 367.7 382.7 397.2 411.2 424.7 437.8 450.5 462.8 474.7 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 Landfill gas generation (Ccf/yr)LFG_gen 1,306,116 1,403,878 1,499,011 1,591,517 1,680,869 1,767,067 1,851,163 1,932,631 2,011,471 2,087,683 2,161,267 2,232,223 2,301,077 2,367,828 2,432,477 2,495,023 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 Landfill methane available per year (Ccf/year)CH4_gen 653,058 701,939 749,506 795,758 840,434 883,534 925,582 966,316 1,005,736 1,043,842 1,080,634 1,116,112 1,150,538 1,183,914 1,216,238 1,247,512 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 Landfill methane available per day (Ccf/day)CH4_day 1,789 1,923 2,053 2,180 2,303 2,421 2,536 2,647 2,755 2,860 2,961 3,058 3,152 3,244 3,332 3,418 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 Pipeline gas used to evaporate leachate per day (Ccf/day)NG_day 2,099 1,965 1,835 1,708 1,585 1,467 1,352 1,241 1,133 1,028 927 830 736 644 556 470 406 406 406 406 406 406 406 406 406 406 406 406 406 406 406 406 406 Natural gas equivalents to evaporate leachate (Ccf/year)KPB_NG_usage 756,129 771,251 786,677 802,410 818,458 834,827 851,524 868,554 885,926 903,644 921,717 940,151 958,954 978,133 997,696 1,017,650 1,038,003 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 KPB natural gas price, ENSTAR ($/Ccf)KPB_NG_Price $0.8687 $0.8860 $0.9038 $0.9218 $0.9403 $0.9591 $0.9783 $0.9978 $1.0178 $1.0381 $1.0589 $1.0801 $1.1017 $1.1237 $1.1462 $1.1691 $1.1925 $1.2163 $1.2407 $1.2655 $1.2908 $1.3166 $1.3429 $1.3698 $1.3972 $1.4251 $1.4536 $1.4827 $1.5124 $1.5426 $1.5735 $1.6049 $1.6370 KPB Payment to AEEC for Exhaust Heat KPB_Heat_Pmt $25,850,000 $0 $0 $0 $739,687 $769,570 $800,661 $833,007 $866,661 $901,674 $938,101 $976,001 $1,015,431 $1,056,455 $1,099,135 $1,143,540 $1,189,739 $1,237,805 $1,287,812 $1,313,568 $1,339,840 $1,366,637 $1,393,969 $1,421,849 $1,450,286 $1,479,291 $1,508,877 $1,539,055 $1,569,836 $1,601,233 $1,633,257 $1,665,922 $1,699,241 $1,733,226 KPB Payment for CHP O&M costs KPB_CHPOM_Pmt $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Revenues $59,707,000 $0 $0 $0 $1,937,332 $1,991,169 $2,046,691 $2,103,958 $2,163,031 $2,223,971 $2,286,845 $2,351,719 $2,418,664 $2,487,752 $2,559,059 $2,632,662 $2,708,644 $2,787,087 $2,868,080 $2,925,442 $2,983,951 $3,043,630 $3,104,502 $3,166,592 $3,229,924 $3,294,523 $3,360,413 $3,427,621 $3,496,174 $3,566,097 $3,637,419 $3,710,168 $3,784,371 $3,860,058 Costs to AEEC Capital Cost of Improvements $9,366,000 $0 $0 $9,743,881 less grant funding $0 $0 $0 $0 plus Interconnect costs $150,000 $0 $0 $156,060 Total Capital Cost of Improvements $9,516,000 Fuel Cost Fuel Type by year Natural gas purchased (Ccf)NG_purchase 0.0 0.0 0.0 623,362 578,686 535,586 493,538 452,804 413,384 375,278 338,486 303,008 268,582 235,206 202,882 171,608 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 Landfill methane (Ccf)LFM_purchase 0.0 0.0 0.0 795,758 840,434 883,534 925,582 966,316 1,005,736 1,043,842 1,080,634 1,116,112 1,150,538 1,183,914 1,216,238 1,247,512 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 AEEC natural gas price ($/Mcf)AEEC_NG_Price $7.62 $8.09 $8.14 $8.20 $8.27 $8.43 $8.60 $8.78 $8.95 $9.13 $9.31 $9.50 $9.69 $9.88 $10.08 $10.28 $10.49 $10.70 $10.91 $11.13 $11.35 $11.58 $11.81 $12.05 $12.29 $12.53 $12.78 $13.04 $13.30 $13.57 $13.84 $14.12 $14.40 AEEC natural gas purchases NG_pmt $0 $0 $0 $511,097 $478,542 $451,759 $424,618 $397,364 $370,026 $342,635 $315,224 $287,828 $260,229 $232,449 $204,513 $176,448 $155,448 $158,556 $161,728 $164,962 $168,261 $171,627 $175,059 $178,560 $182,132 $185,774 $189,490 $193,279 $197,145 $201,088 $205,110 $209,212 $213,396 AEEC Payment to KPB for LFG Usage AEEC_LFG_Pmt $0 $0 $0 $733,555 $790,233 $847,373 $905,454 $964,209 $1,023,614 $1,083,645 $1,144,277 $1,205,481 $1,267,518 $1,330,372 $1,394,030 $1,458,472 $1,515,533 $1,545,843 $1,576,760 $1,608,295 $1,640,461 $1,673,270 $1,706,736 $1,740,870 $1,775,688 $1,811,202 $1,847,426 $1,884,374 $1,922,062 $1,960,503 $1,999,713 $2,039,707 $2,080,501 Total Fuel Cost $36,201,000 $0 $0 $0 $1,244,652 $1,268,775 $1,299,133 $1,330,073 $1,361,573 $1,393,640 $1,426,280 $1,459,501 $1,493,309 $1,527,746 $1,562,821 $1,598,543 $1,634,920 $1,670,980 $1,704,400 $1,738,488 $1,773,257 $1,808,723 $1,844,897 $1,881,795 $1,919,431 $1,957,819 $1,996,976 $2,036,915 $2,077,654 $2,119,207 $2,161,591 $2,204,823 $2,248,919 $2,293,898 Non-Fuel Operating Costs CHP routine maintenance, labor and consumables ($/kWh)CHP_Labor_Trend $0.025 $0.026 $0.026 $0.027 $0.027 $0.028 $0.028 $0.029 $0.029 $0.030 $0.030 $0.031 $0.032 $0.032 $0.033 $0.034 $0.034 $0.035 $0.036 $0.036 $0.037 $0.038 $0.039 $0.039 $0.040 $0.041 $0.042 $0.043 $0.044 $0.044 $0.045 $0.046 $0.047 CHP major maintenance and non-routine reserve ($/kWh)CHP_Reserve_Trend $0.020 $0.020 $0.021 $0.021 $0.022 $0.022 $0.023 $0.023 $0.023 $0.024 $0.024 $0.025 $0.025 $0.026 $0.026 $0.027 $0.027 $0.028 $0.029 $0.029 $0.030 $0.030 $0.031 $0.032 $0.032 $0.033 $0.033 $0.034 $0.035 $0.036 $0.036 $0.037 $0.038 Reduction if natural gas fuel only 20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0% Percent Pipeline gas Pct_Pipegas 0.0%0.0%0.0%43.9%40.8%37.7%34.8%31.9%29.1%26.4%23.9%21.4%18.9%16.6%14.3%12.1%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4% Cost per kWh - NG only NG_O&M_Trend $0.036 $0.037 $0.037 $0.038 $0.039 $0.040 $0.041 $0.041 $0.042 $0.043 $0.044 $0.045 $0.046 $0.047 $0.048 $0.048 $0.049 $0.050 $0.051 $0.052 $0.053 $0.055 $0.056 $0.057 $0.058 $0.059 $0.060 $0.061 $0.063 $0.064 $0.065 $0.067 $0.068 Cost per kWh - NG with LFG NG&LFG_O&M_Trend $0.045 $0.046 $0.047 $0.048 $0.049 $0.050 $0.051 $0.052 $0.053 $0.054 $0.055 $0.056 $0.057 $0.058 $0.059 $0.061 $0.062 $0.063 $0.064 $0.066 $0.067 $0.068 $0.070 $0.071 $0.072 $0.074 $0.075 $0.077 $0.078 $0.080 $0.082 $0.083 $0.085 Total non-fuel operating costs $8,350,000 $0 $0 $0 $537,261 $326,631 $330,022 $333,354 $336,621 $339,815 $342,931 $345,960 $348,895 $351,727 $354,449 $357,051 $359,524 $361,858 $364,042 $371,323 $378,749 $386,324 $394,051 $401,932 $409,970 $418,170 $426,533 $435,064 $443,765 $452,640 $461,693 $470,927 $480,346 $489,953 Total costs to AEEC $54,067,000 $1,781,913 $1,595,406 $1,629,155 $1,663,427 $1,698,193 $1,733,455 $1,769,211 $1,805,461 $1,842,204 $1,879,474 $1,917,270 $1,955,594 $1,994,444 $2,032,838 $2,068,442 $2,109,810 $2,152,007 $2,195,047 $2,238,948 $2,283,727 $2,329,401 $2,375,989 $2,423,509 $2,471,979 $2,521,419 $2,571,847 $2,623,284 $2,675,750 $2,729,265 $2,783,850 AEEC Comparison Costs per MWh Project annualized capital cost ($/MWh)$36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 $36 Project cost to AEEC (per MWh)$0 $0 $0 $144 $129 $132 $135 $138 $141 $143 $146 $149 $152 $155 $159 $162 $165 $168 $171 $174 $178 $182 $185 $189 $193 $196 $200 $204 $209 $213 $217 $221 $226 Total Project Cost ($/Mwh)$0 $0 $0 $180 $165 $168 $171 $174 $176 $179 $182 $185 $188 $191 $194 $198 $201 $204 $207 $210 $214 $217 $221 $225 $228 $232 $236 $240 $244 $249 $253 $257 $262 Cost of Competing Generation ($/MWh)$92 $93 $95 $97 $99 $101 $103 $105 $107 $109 $112 $114 $116 $118 $121 $123 $126 $128 $131 $133 $136 $139 $141 $144 $147 $150 $153 $156 $159 $162 $166 $169 $172 Net Revenues to AEEC $5,640,000 KPB Feasibility Revenue and Cost of New System Revenue and Savings Revenue from gas sale to AEEC $30,457,000 $0 $0 $0 $733,555 $790,233 $847,373 $905,454 $964,209 $1,023,614 $1,083,645 $1,144,277 $1,205,481 $1,267,518 $1,330,372 $1,394,030 $1,458,472 $1,515,533 $1,545,843 $1,576,760 $1,608,295 $1,640,461 $1,673,270 $1,706,736 $1,740,870 $1,775,688 $1,811,202 $1,847,426 $1,884,374 $1,922,062 $1,960,503 $1,999,713 $2,039,707 $2,080,501 Foregone Cost of Natural Gas Spent on Current Evaporator System 2017-18 Cost per gallon, inflated $0.105 $0.107 $0.110 $0.112 $0.114 $0.116 $0.119 $0.121 $0.123 $0.126 $0.128 $0.131 $0.134 $0.136 $0.139 $0.142 $0.145 $0.148 $0.151 $0.154 $0.157 $0.160 $0.163 $0.166 $0.170 $0.173 $0.176 $0.180 $0.183 $0.187 $0.191 $0.195 $0.199 Foregone Cost $6,775,000 $0 $0 $0 $193,879 $201,712 $209,861 $218,340 $227,161 $236,338 $245,886 $255,820 $266,155 $276,908 $288,095 $299,734 $311,843 $324,441 $337,549 $344,300 $351,186 $358,209 $365,374 $372,681 $380,135 $387,737 $395,492 $403,402 $411,470 $419,699 $428,093 $436,655 $445,388 $454,296 Total Savings (Cost) of New System $37,232,000 Costs Gas System Capital Costs Capital Cost without project (end of cell 5)$2,890,500 Capital Cost if spent for this project $3,233,500 Net Present Value of Capital Cost for this project $343,000 Payment to AEEC for waste heat $25,850,000 $0 $0 $0 $739,687 $769,570 $800,661 $833,007 $866,661 $901,674 $938,101 $976,001 $1,015,431 $1,056,455 $1,099,135 $1,143,540 $1,189,739 $1,237,805 $1,287,812 $1,313,568 $1,339,840 $1,366,637 $1,393,969 $1,421,849 $1,450,286 $1,479,291 $1,508,877 $1,539,055 $1,569,836 $1,601,233 $1,633,257 $1,665,922 $1,699,241 $1,733,226 Labor Cost to Operate Evaporation System Current Evaporator $23,410 $24,355 $25,339 $26,363 $27,428 $28,536 $29,689 $30,888 $32,136 $33,435 $34,785 $36,191 $37,653 $39,174 $40,757 $41,572 $42,403 $43,251 $44,116 $44,999 $45,899 $46,817 $47,753 $48,708 $49,682 $50,676 $51,689 $52,723 $53,778 $54,853 CHP Evaporator $31,538 $32,812 $34,138 $35,517 $36,952 $38,445 $39,998 $41,614 $43,295 $45,044 $46,864 $48,757 $50,727 $52,776 $54,908 $56,006 $57,127 $58,269 $59,434 $60,623 $61,836 $63,072 $64,334 $65,620 $66,933 $68,272 $69,637 $71,030 $72,450 $73,899 Added Labor Cost of New System $284,000 $0 $0 $0 $8,128 $8,457 $8,798 $9,154 $9,524 $9,908 $10,309 $10,725 $11,158 $11,609 $12,078 $12,566 $13,074 $13,602 $14,152 $14,435 $14,723 $15,018 $15,318 $15,625 $15,937 $16,256 $16,581 $16,912 $17,251 $17,596 $17,948 $18,307 $18,673 $19,046 Payment to AEC for CHP O&M costs $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Cost of New System $26,477,000 Net savings (cost) of new system $10,755,000 Results AEEC Central Peninsula Landfill Gas to Energy Project Feasibility Analysis Project Start Cell Names Present Value 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 Discount Rate (approximate real rate, excludes inflation)2.0% Inflation Rate 2.0%Inf_Rate Discount Rate (nominal, includes inflation)2.0%Disc_Rate Project Capital Cost $7,888,814 CAPEX 5522169.8 7003828 Gas System Installation Costs $2,283,500 GasSystem_CAPEX Natural gas Btu (Btu/gal)12,000 Gas_Btu Natural Gas Heating Value (Btu per Ccf)98,500 Btu_Ccf Percent Methane 50%pct_CH4 AEEC Small Facility Power Purchase Rate ($/MWh)$91.50 Current_Gen_Cost Interconnect Cost (2019$)$150,000 Interconnect Enstar G4 Rates Customer Charge ($/month)$530 C_Charge Service Charge (Base, $/Ccf)$0.06483 S_Charge Supplier Gas Cost Charge (GCA, $/Ccf)$0.79196 GCA Regulatory Cost Charge (RCC, % of total bill)0.4%RCC Scenario Base Case Engine rated capacity (MW)1.6 MW AEEC Net savings $9,401,000 Availablity 95.0%Availability KPB Savings $10,755,000 Line losses 2.0%Line_Losses Total Project Savings $20,156,000 Parasitic losses 5.0%Par_Losses CHP natural gas fuel requirement (scf/min)270.0 NG_fuel Non-Fuel CHP Operating Cost $0.045 CHP routine maintenance, labor and consumables ($/kWh)$0.025 CHP_labor CHP major maintenance and non-routine reserve ($/kWh)$0.020 CHP_reserve Operating cost reduction if NG only 20.0%NG_reduce Grant Funding for CHP engine purchase $0 CHP_Grant 2019 Payment by KPB for CHP O&M costs $0 KPB_O&M_2019 Property Taxes $0 Year LFG is blended with NG as fuel for CHP 2022 Year_LFG Revenues to AEEC Electricity Revenues (after costs of transmission and distribution) Use full 1.6MW output (Yes) or use only LFG when not evaporating (No)Yes % of potential output CHP engine runs during the year pct_output 0 0 0 100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100%100% Electricity sales (MWh with availability and losses)MWh 0 0 0 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 12,334 Cost of Competing Generation ($/MWh)Gen_Cost $91.50 $93.33 $95.20 $97.10 $99.04 $101.02 $103.04 $105.10 $107.21 $109.35 $111.54 $113.77 $116.04 $118.37 $120.73 $123.15 $125.61 $128.12 $130.68 $133.30 $135.96 $138.68 $141.46 $144.29 $147.17 $150.12 $153.12 $156.18 $159.30 $162.49 $165.74 $169.05 $172.44 Renewable energy incentives (RE certificates, tax credits, GHG credits)Ren_Credits $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Electricity Revenues $33,857,000 $0 $0 $0 $1,197,646 $1,221,599 $1,246,031 $1,270,951 $1,296,370 $1,322,298 $1,348,744 $1,375,718 $1,403,233 $1,431,298 $1,459,923 $1,489,122 $1,518,904 $1,549,282 $1,580,268 $1,611,873 $1,644,111 $1,676,993 $1,710,533 $1,744,744 $1,779,639 $1,815,231 $1,851,536 $1,888,567 $1,926,338 $1,964,865 $2,004,162 $2,044,245 $2,085,130 $2,126,833 KPB Payment to AEEC for Exhaust Heat Leachate requiring evaporation (gal/year)Leachate_Yr 1,633,612 1,666,284 1,699,610 1,733,602 1,768,274 1,803,639 1,839,712 1,876,506 1,914,037 1,952,317 1,991,364 2,031,191 2,071,815 2,113,251 2,155,516 2,198,626 2,242,599 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 2,287,451 Leachate evaporation rate from CAT engine (gal/day)Evap_Rate 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 Natural gas equivalents/yr to operate CHP engine at 1.6MW (Ccf/year)CHP_NG_yr 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 1,419,120 Days required to evaporate leachate at 1.6MW Evap_Days 194 198 202 206 211 215 219 223 228 232 237 242 247 252 257 262 267 272 272 272 272 272 272 272 272 272 272 272 272 272 272 272 272 Days when evaporator is not running Nonevap_Days 171 167 163 159 154 150 146 142 137 133 128 123 118 113 108 103 98 93 93 93 93 93 93 93 93 93 93 93 93 93 93 93 93 Natural gas equivalents/day to operate CHP engine at 1.6MW (Ccf/day)NGe_day 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 3,888 Landfill gas generation (cf/min)LFG_per_min 248.5 267.1 285.2 302.8 319.8 336.2 352.2 367.7 382.7 397.2 411.2 424.7 437.8 450.5 462.8 474.7 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 483.6 Landfill gas generation (Ccf/yr)LFG_gen 1,306,116 1,403,878 1,499,011 1,591,517 1,680,869 1,767,067 1,851,163 1,932,631 2,011,471 2,087,683 2,161,267 2,232,223 2,301,077 2,367,828 2,432,477 2,495,023 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 2,541,802 Landfill methane available per year (Ccf/year)CH4_gen 653,058 701,939 749,506 795,758 840,434 883,534 925,582 966,316 1,005,736 1,043,842 1,080,634 1,116,112 1,150,538 1,183,914 1,216,238 1,247,512 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 Landfill methane available per day (Ccf/day)CH4_day 1,789 1,923 2,053 2,180 2,303 2,421 2,536 2,647 2,755 2,860 2,961 3,058 3,152 3,244 3,332 3,418 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 3,482 Pipeline gas used to evaporate leachate per day (Ccf/day)NG_day 2,099 1,965 1,835 1,708 1,585 1,467 1,352 1,241 1,133 1,028 927 830 736 644 556 470 406 406 406 406 406 406 406 406 406 406 406 406 406 406 406 406 406 Natural gas equivalents to evaporate leachate (Ccf/year)KPB_NG_usage 756,129 771,251 786,677 802,410 818,458 834,827 851,524 868,554 885,926 903,644 921,717 940,151 958,954 978,133 997,696 1,017,650 1,038,003 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 1,058,763 KPB natural gas price, ENSTAR ($/Ccf)KPB_NG_Price $0.8687 $0.8860 $0.9038 $0.9218 $0.9403 $0.9591 $0.9783 $0.9978 $1.0178 $1.0381 $1.0589 $1.0801 $1.1017 $1.1237 $1.1462 $1.1691 $1.1925 $1.2163 $1.2407 $1.2655 $1.2908 $1.3166 $1.3429 $1.3698 $1.3972 $1.4251 $1.4536 $1.4827 $1.5124 $1.5426 $1.5735 $1.6049 $1.6370 KPB Payment to AEEC for Exhaust Heat KPB_Heat_Pmt $25,850,000 $0 $0 $0 $739,687 $769,570 $800,661 $833,007 $866,661 $901,674 $938,101 $976,001 $1,015,431 $1,056,455 $1,099,135 $1,143,540 $1,189,739 $1,237,805 $1,287,812 $1,313,568 $1,339,840 $1,366,637 $1,393,969 $1,421,849 $1,450,286 $1,479,291 $1,508,877 $1,539,055 $1,569,836 $1,601,233 $1,633,257 $1,665,922 $1,699,241 $1,733,226 KPB Payment for CHP O&M costs KPB_CHPOM_Pmt $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Revenues $59,707,000 $0 $0 $0 $1,937,332 $1,991,169 $2,046,691 $2,103,958 $2,163,031 $2,223,971 $2,286,845 $2,351,719 $2,418,664 $2,487,752 $2,559,059 $2,632,662 $2,708,644 $2,787,087 $2,868,080 $2,925,442 $2,983,951 $3,043,630 $3,104,502 $3,166,592 $3,229,924 $3,294,523 $3,360,413 $3,427,621 $3,496,174 $3,566,097 $3,637,419 $3,710,168 $3,784,371 $3,860,058 Costs to AEEC Capital Cost of Improvements $5,605,000 $0 $0 $5,831,769 less grant funding $0 $0 $0 $0 plus Interconnect costs $150,000 $0 $0 $156,060 Total Capital Cost of Improvements $5,755,000 Fuel Cost Fuel Type by year Natural gas purchased (Ccf)NG_purchase 0.0 0.0 0.0 623,362 578,686 535,586 493,538 452,804 413,384 375,278 338,486 303,008 268,582 235,206 202,882 171,608 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 148,219 Landfill methane (Ccf)LFM_purchase 0.0 0.0 0.0 795,758 840,434 883,534 925,582 966,316 1,005,736 1,043,842 1,080,634 1,116,112 1,150,538 1,183,914 1,216,238 1,247,512 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 1,270,901 AEEC natural gas price ($/Mcf)AEEC_NG_Price $7.62 $8.09 $8.14 $8.20 $8.27 $8.43 $8.60 $8.78 $8.95 $9.13 $9.31 $9.50 $9.69 $9.88 $10.08 $10.28 $10.49 $10.70 $10.91 $11.13 $11.35 $11.58 $11.81 $12.05 $12.29 $12.53 $12.78 $13.04 $13.30 $13.57 $13.84 $14.12 $14.40 AEEC natural gas purchases NG_pmt $0 $0 $0 $511,097 $478,542 $451,759 $424,618 $397,364 $370,026 $342,635 $315,224 $287,828 $260,229 $232,449 $204,513 $176,448 $155,448 $158,556 $161,728 $164,962 $168,261 $171,627 $175,059 $178,560 $182,132 $185,774 $189,490 $193,279 $197,145 $201,088 $205,110 $209,212 $213,396 AEEC Payment to KPB for LFG Usage AEEC_LFG_Pmt $0 $0 $0 $733,555 $790,233 $847,373 $905,454 $964,209 $1,023,614 $1,083,645 $1,144,277 $1,205,481 $1,267,518 $1,330,372 $1,394,030 $1,458,472 $1,515,533 $1,545,843 $1,576,760 $1,608,295 $1,640,461 $1,673,270 $1,706,736 $1,740,870 $1,775,688 $1,811,202 $1,847,426 $1,884,374 $1,922,062 $1,960,503 $1,999,713 $2,039,707 $2,080,501 Total Fuel Cost $36,201,000 $0 $0 $0 $1,244,652 $1,268,775 $1,299,133 $1,330,073 $1,361,573 $1,393,640 $1,426,280 $1,459,501 $1,493,309 $1,527,746 $1,562,821 $1,598,543 $1,634,920 $1,670,980 $1,704,400 $1,738,488 $1,773,257 $1,808,723 $1,844,897 $1,881,795 $1,919,431 $1,957,819 $1,996,976 $2,036,915 $2,077,654 $2,119,207 $2,161,591 $2,204,823 $2,248,919 $2,293,898 Non-Fuel Operating Costs CHP routine maintenance, labor and consumables ($/kWh)CHP_Labor_Trend $0.025 $0.026 $0.026 $0.027 $0.027 $0.028 $0.028 $0.029 $0.029 $0.030 $0.030 $0.031 $0.032 $0.032 $0.033 $0.034 $0.034 $0.035 $0.036 $0.036 $0.037 $0.038 $0.039 $0.039 $0.040 $0.041 $0.042 $0.043 $0.044 $0.044 $0.045 $0.046 $0.047 CHP major maintenance and non-routine reserve ($/kWh)CHP_Reserve_Trend $0.020 $0.020 $0.021 $0.021 $0.022 $0.022 $0.023 $0.023 $0.023 $0.024 $0.024 $0.025 $0.025 $0.026 $0.026 $0.027 $0.027 $0.028 $0.029 $0.029 $0.030 $0.030 $0.031 $0.032 $0.032 $0.033 $0.033 $0.034 $0.035 $0.036 $0.036 $0.037 $0.038 Reduction if natural gas fuel only 20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0%20.0% Percent Pipeline gas Pct_Pipegas 0.0%0.0%0.0%43.9%40.8%37.7%34.8%31.9%29.1%26.4%23.9%21.4%18.9%16.6%14.3%12.1%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4%10.4% Cost per kWh - NG only NG_O&M_Trend $0.036 $0.037 $0.037 $0.038 $0.039 $0.040 $0.041 $0.041 $0.042 $0.043 $0.044 $0.045 $0.046 $0.047 $0.048 $0.048 $0.049 $0.050 $0.051 $0.052 $0.053 $0.055 $0.056 $0.057 $0.058 $0.059 $0.060 $0.061 $0.063 $0.064 $0.065 $0.067 $0.068 Cost per kWh - NG with LFG NG&LFG_O&M_Trend $0.045 $0.046 $0.047 $0.048 $0.049 $0.050 $0.051 $0.052 $0.053 $0.054 $0.055 $0.056 $0.057 $0.058 $0.059 $0.061 $0.062 $0.063 $0.064 $0.066 $0.067 $0.068 $0.070 $0.071 $0.072 $0.074 $0.075 $0.077 $0.078 $0.080 $0.082 $0.083 $0.085 Total non-fuel operating costs $8,350,000 $0 $0 $0 $537,261 $326,631 $330,022 $333,354 $336,621 $339,815 $342,931 $345,960 $348,895 $351,727 $354,449 $357,051 $359,524 $361,858 $364,042 $371,323 $378,749 $386,324 $394,051 $401,932 $409,970 $418,170 $426,533 $435,064 $443,765 $452,640 $461,693 $470,927 $480,346 $489,953 Total costs to AEEC $50,306,000 $1,781,913 $1,595,406 $1,629,155 $1,663,427 $1,698,193 $1,733,455 $1,769,211 $1,805,461 $1,842,204 $1,879,474 $1,917,270 $1,955,594 $1,994,444 $2,032,838 $2,068,442 $2,109,810 $2,152,007 $2,195,047 $2,238,948 $2,283,727 $2,329,401 $2,375,989 $2,423,509 $2,471,979 $2,521,419 $2,571,847 $2,623,284 $2,675,750 $2,729,265 $2,783,850 AEEC Comparison Costs per MWh Project annualized capital cost ($/MWh)$22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 $22 Project cost to AEEC (per MWh)$0 $0 $0 $144 $129 $132 $135 $138 $141 $143 $146 $149 $152 $155 $159 $162 $165 $168 $171 $174 $178 $182 $185 $189 $193 $196 $200 $204 $209 $213 $217 $221 $226 Total Project Cost ($/Mwh)$0 $0 $0 $166 $151 $154 $157 $159 $162 $165 $168 $171 $174 $177 $180 $183 $186 $189 $193 $196 $200 $203 $207 $211 $214 $218 $222 $226 $230 $234 $239 $243 $247 Cost of Competing Generation ($/MWh)$92 $93 $95 $97 $99 $101 $103 $105 $107 $109 $112 $114 $116 $118 $121 $123 $126 $128 $131 $133 $136 $139 $141 $144 $147 $150 $153 $156 $159 $162 $166 $169 $172 Net Revenues to AEEC $9,401,000 KPB Feasibility Revenue and Cost of New System Revenue and Savings Revenue from gas sale to AEEC $30,457,000 $0 $0 $0 $733,555 $790,233 $847,373 $905,454 $964,209 $1,023,614 $1,083,645 $1,144,277 $1,205,481 $1,267,518 $1,330,372 $1,394,030 $1,458,472 $1,515,533 $1,545,843 $1,576,760 $1,608,295 $1,640,461 $1,673,270 $1,706,736 $1,740,870 $1,775,688 $1,811,202 $1,847,426 $1,884,374 $1,922,062 $1,960,503 $1,999,713 $2,039,707 $2,080,501 Foregone Cost of Natural Gas Spent on Current Evaporator System 2017-18 Cost per gallon, inflated $0.105 $0.107 $0.110 $0.112 $0.114 $0.116 $0.119 $0.121 $0.123 $0.126 $0.128 $0.131 $0.134 $0.136 $0.139 $0.142 $0.145 $0.148 $0.151 $0.154 $0.157 $0.160 $0.163 $0.166 $0.170 $0.173 $0.176 $0.180 $0.183 $0.187 $0.191 $0.195 $0.199 Foregone Cost $6,775,000 $0 $0 $0 $193,879 $201,712 $209,861 $218,340 $227,161 $236,338 $245,886 $255,820 $266,155 $276,908 $288,095 $299,734 $311,843 $324,441 $337,549 $344,300 $351,186 $358,209 $365,374 $372,681 $380,135 $387,737 $395,492 $403,402 $411,470 $419,699 $428,093 $436,655 $445,388 $454,296 Total Savings (Cost) of New System $37,232,000 Costs Gas System Capital Costs Capital Cost without project (end of cell 5)$2,890,500 Capital Cost if spent for this project $3,233,500 Net Present Value of Capital Cost for this project $343,000 Payment to AEEC for waste heat $25,850,000 $0 $0 $0 $739,687 $769,570 $800,661 $833,007 $866,661 $901,674 $938,101 $976,001 $1,015,431 $1,056,455 $1,099,135 $1,143,540 $1,189,739 $1,237,805 $1,287,812 $1,313,568 $1,339,840 $1,366,637 $1,393,969 $1,421,849 $1,450,286 $1,479,291 $1,508,877 $1,539,055 $1,569,836 $1,601,233 $1,633,257 $1,665,922 $1,699,241 $1,733,226 Labor Cost to Operate Evaporation System Current Evaporator $23,410 $24,355 $25,339 $26,363 $27,428 $28,536 $29,689 $30,888 $32,136 $33,435 $34,785 $36,191 $37,653 $39,174 $40,757 $41,572 $42,403 $43,251 $44,116 $44,999 $45,899 $46,817 $47,753 $48,708 $49,682 $50,676 $51,689 $52,723 $53,778 $54,853 CHP Evaporator $31,538 $32,812 $34,138 $35,517 $36,952 $38,445 $39,998 $41,614 $43,295 $45,044 $46,864 $48,757 $50,727 $52,776 $54,908 $56,006 $57,127 $58,269 $59,434 $60,623 $61,836 $63,072 $64,334 $65,620 $66,933 $68,272 $69,637 $71,030 $72,450 $73,899 Added Labor Cost of New System $284,000 $0 $0 $0 $8,128 $8,457 $8,798 $9,154 $9,524 $9,908 $10,309 $10,725 $11,158 $11,609 $12,078 $12,566 $13,074 $13,602 $14,152 $14,435 $14,723 $15,018 $15,318 $15,625 $15,937 $16,256 $16,581 $16,912 $17,251 $17,596 $17,948 $18,307 $18,673 $19,046 Payment to AEC for CHP O&M costs $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Cost of New System $26,477,000 Net savings (cost) of new system $10,755,000 Results