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HomeMy WebLinkAboutMine Power Study, Arctic Project-Ambler Mining District Alaska, February 17, 2006 _ Mine Power Study Arctic Project - Ambler Mining District Alaska Prepared for: February 17, 2006 pf Ambier Mining District -Mine Power Study “LEGAL NOTICE” This document was prepared by Stone & Webster Management Consultants, Inc. (“Stone & Webster”) solely for the benefit of Alaska Gold Company and its affiliates. Neither Stone & Webster, nor its parent company or affiliates, nor Alaska Gold Company, nor any person acting in their behalf (a) makes any warranty, expressed or implied, with respect to the use of any information or methods disclosed in this document; or (b) assumes any liability with respect to the use of any information or methods disclosed in this document. Any recipient of this document, by their acceptance or use of this document, releases Stone & Webster, its parent company or affiliates, and Alaska Gold Company from any liability for direct, indirect, consequential or special loss or damage whether arising in contract, warranty, express or implied, tort or otherwise, and irrespective of fault, negligence, and strict liability.” Shaw store & Webster Management Consuttants, inc. Sedat: Ambler Mining District -Mine Power Study Executive Summary 1.0 Site Conditions and Generation Facility Locations... 1.1 General Site Conditions... 1.2 Diesel Module Locations.. 1.3. Windfarm Module Locations . 1.4 Hydro Power Module Locations 1.5 Transportation Access . 1.6 Waste Disposal............ 2.0 Screening of Power Delivery Alternatives 2.1 Onsite Power Options... a 2.2 Access to Fuel and cn ‘Seisiian: 2.3 New Regional Power Generation Projects.......... 24 Candidate Fuel Sources and Delivery Options .2-4 25 Generator Options .. 3.0 Diese! Power Generation 3.1 Equipment Suppliers. 3.2. Fuel Requirements ... 3.3 Plant Capacity and Sait Utilization . 3.4 35 MW Diesel Plant Design... 3.5 Site and Fuel Storage Requirements. 3.6 Performance CalculationS.............0000 37 Environmental Considerations... 3.8 Capital Cost Estimate ............... 3.9 Operations and Maintenance Costs 3.10 Schedule....... 3.11 References ... 4.0 Windfarm Power Generation Module 41 Wind Resource Definition ...... 4.2 Candidate Wind Technologies... 4.3. Wind Power Module Capital Cost... 4.4 Wind Power Module Operating Costs. 4.5 Wind Power Module Estimated Power Production .. 5.0 Hydroelectric Power Generation Options ..........s.essee 5.1 Considerations For Hydroelectric Development .. 5.2 Shungnak River Hydro Full Development........ 5.3 Shungnak Hydro Limited Development at El. 490 5.4 Kogoluktuk River Full Hydro Developmert........... Shaw stone & Webster Management Consultants, inc. 2/20/2006 ; ee Ambler Mining District -Mine Power Study 4 “5.5 Kogoluktuk- Limited development at El. 315 5.6 Run of River Hydro Sites .... 5.7 Summary Of Hydro Opportunities 6.0 Reliability and Dispatch Considerations 6.1 Flexibility and Potential for Future Growth 6.2 Expected System Dispatch.................0 7.0 Overview of Environmental and Permitting Requirements 7.1 Permit Acquisition Process .. 7.2 NEPA Compliance 7.3. Communication with Key Stakeholders .... 7.4. Landowner Coordination............ 7.5 Key Agencies...... aes 7.6 Potential Permit Requiremen' 7.7 Permitting Schedule and Costs....... 8.0 Economic Comparison of Candidate Power Supply Alternatives .. 8.1 Economic Evaluation Assumptions and Methodology 82 Economic Comparison of Onsite Power Options... 83. Economic Comparison of Speculative Power Options Conclusions and Recommendations 9.0 Appendices .... List of References il Shaw Stone & Webster Management Consultants, Inc. ; 2/20/2006 Ambier Mining District -Mine Power Study Executive Summary Stone & Webster Management Consultants (Stone & Webster) has prepared this mine power study for the Arctic Project, located in the Ambler Mineral District, approximately 170 miles east of Kotzebue, Alaska, in the Brooks Range near Shungnak and Kobuk, Alaska. Stone & Webster has investigated and characterized a list of potential sources of reliable power and supplemental electric energy for a potential future hard rock mining and milling operation. Alaska Gold will review available power supply options in considering the feasibility of mine development and how to assemble a power supply configuration to support a 24-hour per day, seven days per week mining operation with the flexibility to adapt to future growth and changing power needs. The objectives of this mine power study are to: Cover a full range of feasible power generation and delivery options ¢ Describe candidate concepts, establish implementation requirements and costs « Compare economics and risks of various options available to support a range of loads The information for this study is based on experience with other mining power supply arrangements, Stone & Webster’s in-house database on power generation projects, and information collected during the study. Inputs to the study were obtained by attending the Alaska Rural Energy Conference in Valdez in September, 2005. Various meetings and telephone interviews were conducted with Alaska Gold, Alaska Village Electric Cooperative (AVEC), Alaska Industrial Development and Export Authority (AIDEA), Alaska Energy Authority (AEA), Alaska Natural Gas Development Authority, National Renewable Energy Laboratory, Northwest Arctic Borough, Denali Commission, Alaska state government officials, representatives of various villages in Alaska, and numerous equipment and technology suppliers. The size and type of generating options studied address the range of loads that can be expected when the mining complex is developed. Information was collected to characterize opportunities to tie into existing and planned transmission networks, and to evaluate the potential for coordination with other larger power supply projects in the region. All conceivable generation options were reviewed to determine feasible options. The following table summarizes the options selected as viable candidates for onsite power and more speculative candidates for regional power supply with transmission interconnection to the Ambler Mine. ShaW store 8 Webster Management Consuttants, inc. 1 Feoruary 17, 2006 . per Ambier Mining District -Mine Power Study 9 ~ Table 1 — Potential Power Supply Options Onsite Power Option Regional Power Option ¢ 35 MW base load diesel module 150 MW Coal-fired Circulating Fluid © 40 MW backup diesel module Bed Power Plant ¢ 15 MW wind power system near the site ¢ 121 MW Oil-fired Combined Cycle ¢ 13 MW Shungnak hydro project ¢ 122 MW Gas-fired Combined Cycle © 10.6 MW limited Shungnak hydro project e 170 MW Advanced Nuclear Pebble ¢ 11.7 MW Kogoluktuk hydro project Bed Reactor ¢ 7MwW limited Kogoluktuk hydro project ¢ Various run-of-river hydro projects Available Fuels and Energy Sources 1. Unless a connecting road is constructed to the coast, or if regional gas exploration is successfully pursued, the only feasible fossil fuels for the mining complex are diesel oil and jet fuel delivered by air transport or by seasonal barge/cat-train expeditions. This conclusion should be compared to the results of the transportation study undertaken separately by others. 2. It appears that significant wind resources occur near the site that may support the development of one or more windfarms which may provide the lowest cost energy for the mine. 3. Several candidate sites exist nearby that can be developed to provide hydroelectric generation which are expected to be competitive with diesel plant operation. 4. Coal or fuel oil delivery to a regional generating station tied by new transmission to several load centers could provide the most economical source of energy to the mine, but would still require the installation of diesels to provide reliability. Candidate Generation Options Diesel engines can be provided in clusters of about 35 MW for reliable base load power, including spares for maintenance and reliability, designed to provide cogeneration capability to also support thermal loads in the mining complex. The diesels would be enclosed in cold weather design structures. Diesel fuel would be flown in or delivered seasonally by barge and cat-trains, and stored onsite. Windfarm development in areas confirmed through wind data collection as having good wind resources will require construction in difficult terrain with interconnecting transmission facilities. For planning purposes, we have characterized a 15 MW windfarm module to support a preliminary economic evaluation with average and high wind resources. Hydro power options were developed for the Shungyak and Kogoluktuk Rivers for full and partial dam development which could provide over 25 MW of capacity about half of the time to the mine. A preliminary review of run-of-river hydro options was also completed which concluded such installations would be less attractive than the larger hydro projects. Shaw ‘Stone & Webster Managemen: Consultants, inc. 2) ‘ February 17, 2008 Ambler Mining District -Mine Power Study wo + Tf may be possible to develop a regional gas, oil or coal fueled central power station to the west of the mining site that serves the Red Dog Mine and various villages along with the Ambler Mine. Such a Project would require coordinated development and confirmation of the feasibility and cost of a transmission line connecting to the Ambler Mine. The South African Pebble Bed Reactor (PBMR) is the only small scalé nuclear power option that is expected to be commercially available for operation in the US in the 2016+ time frame. At 170 MW, it may provide a feasible option for a regional power generation project, especially if the Ambler Mine undertakes onsite ore refining. Economic Evaluation Results Figure 1 compares the levelized power costs for each of the onsite power options. Figure 1 Levelized Cost of Onsite Power Options Levelized Cost Comparison 0 0&M @ Fuel Cost @ Capital Cost Recovery| $/MWh 11.7MW 7™™wW SSMW Base 40MWBackup 15MWWind 15 MW Wind 13 MW 10.6 Mw Load Diese! Diese: (Avg wind) (High wind) —Shungnak Hydro Shungnak Hydro Kogoluktuk Hydro Kogoluktuk Hydro Based on the assumptions used for this analysis, onsite wind generation potentially offers the lowest cost energy, followed by development of either of the Shungnak hydro options, and possibly one of the Kogoluktuk hydro options. Figure 2 summarizes the estimated levelized power costs from several regional power plant options. SShaW- stone & Webster Management Consultants, inc. 3 February 17, 2006 $/MWh Ambier Mining District -Mine Power Study Figure 2 Levelized Power Cost of Regional Power Options Levelized Cost Comparison 200.0 + as 180.0 + ea 160.0 + 140.0 - 120.0 + a { @ Fuel Cost re ® Capital Cost Recovery | 60.0 5 40.0 + 20.0 0.0 7 + : Regional 150 MW 121 MW Regional 122 MW Regional 168 MW Nuclear CFB Oil Combined Gas Combined PBMR Cycle Cycle These results indicate that the economies of scale associated with larger (100 MW-200 MW) power plant configurations may provide energy supply options that compete with the development of onsite wind power systems. However, the complexity and additional risk of developing and permitting such projects, and high development cost, may make these options less attractive than the identification of good wind siting areas and the coordination of wind and hydro resources at the site. A large remote power station does have the advantage of all but eliminating seasonal (winter) dependence on diesel fuel for energy when hydro and wind resource availability is interrupted. Recommendations Based on the assumptions and findings presented above, the following recommendations should be considered: 1. Further evaluation of the wind resource near the site is justified and should be undertaken early to determine whether excellent wind resources exist near the Ambler Mine site. Wind power, even without any subsidies, appears to be the most cost effective onsite power production option to displace the use of diesel fuel. Further evaluation of the hydro power options should be considered to verify major assumptions regarding the available hydrological resource, evaluate additional sites and power options, and resolve key questions regarding the permitting and construction issues likely to be confronted in project implementation. Development of a regional power plant should be considered through further discussion with the Northwest Arctic Borough, the Red Dog Mine, the AEA, AIDEA, AVEC, the Denali Commission and others that represent potential stakeholders. Investment in a central power facility and major transmission project will likely compete directly with investment in wind and Shaw stone & Webster Management Consutants, Inc. 4 Februy 17, 2008 Ambler Mining District -Mine Power Study hydro power options in displacing the use of diesel fuel, so decisions may be required to support commercial commitments needed for a reasonable implementation timeline. 4. The implementation of a major, well-coordinated dieseV/hydro/wind power system represents an important accomplishment in establishing reliance on renewable technologies as part of a reliable power mini-grid. This is an area of technology development that is of interest to the NREL, AEA, DOE and the international energy community. As a result, we may be able to approach these organizations for grants or cost-shared funding to assist in data collection, implementation planning, optimization and engineering of the proposed power system. 5. The adjacent villages of Kobuk and Shungyak may play an important role in acceptance of the Ambler Mine project as the public hearing process proceeds to support environmental permitting. It will likely be critical to offer those villages interconnections to provide lower cost and more reliable power, jobs, and other benefits. It may be appropriate to submit grant applications in cooperation with these villages to fund some studies to evaluate interconnection options that will make lower cost renewable electric power available. AEA just released such a grant application (#AEA-06-018) dated February 13, 2006, for which responses are due March 13, 2006. It may be appropriate to approach both villages and ask if they would like support to prepare and submit grant applications to support a study of interconnections and also local monitoring of wind resources. Shaw Stone & Webster Management Consultants, Inc 5 Februay 17, 2008 i ee Ambler Mining District -Mine Power Study "y 1.0 Site Conditions and Generation Facility Locations The exact site of the mining complex has not yet been identified. Therefore the following site conditions and facility locations are assumed to support a conceptual design basis for the implementation of each generating option. 1.1. General Site Conditions Figure 1-1 below shows the areas intended for development. The following site characteristics are assumed: Foundation Conditions The surface conditions vary seasonally with underlying permafrost. Flooding Potential Sites for all facilities except the hydroelectric generation modules are assumed to be located in areas not subject to flooding. SHAW: store & Weoster Management Cons.itants, ne. 1-1 Febromy 17,2008 of 2 Ambler Mining District -Mine Power Study Climatology/Meteorology The Kobuk, Shungnak and Ambler region is located in Alaska’s transitional climate zone. Temperatures average -10 to 15 degrees Fahrenheit during winter and 40 to 65 degrees Fahrenheit during summer. Temperature extremes have been recorded from -68 to 90 degrees Fahrenheit. Snowfall averages 56 inches, with 17 inches of total precipitation per year. Typically, the Kobuk River is navigable from the end of May through October. The following table summarizes average temperatures at the site by month (DCCED, 2005). Table 1-1 2004 Temperature Data for Ambler, Alaska Recorded Temperature (°F) Data | Jan | Feb | ‘Mar Apr | May | Jun Jul Aug | ‘Sep | ‘Oct “Nov | Dec Monthly 37.6 | 26.3 Mean 3.1 11.1 | 12.8 | 31.7 | 49.1 | 57.0 | 606 | 588 | 41.8 2.1) | (4.1) 10.0 + Extreme 55 41 21 43 9 ; Daily High 43 37 72 86 I 8 86 | 70 (46) | (9) 36 Extreme 18 -13 Daily Low -33 -40 -35 -24 27 EP} 36 28 | 16 (-16) | (49) -39 Data Source: University of Alaska-Fairbanks, Center for Global Change & Arctic System Research ? Missing 20 > Missing 2004 data July 5. * Missing 2004 data Sep. 2 * Missing 2004 data Oct 23-31. Next most recent data available from October 1995 provided in parentheses. * Missing 2004 data Nov 1-9 and Nov 11. Next most recent data available from 1981-1987 (Source: Alaska State Climate Center) provided in parentheses. No specific wind data exists for the potential areas of wind power generation. Table 1-2 shows the wind power class ratings at average wind speeds and typical wind turbine tower heights. However, at least Class 3 or higher wind power is estimated for mountain summits and ridge crests in the Alaska Range and portions of the Brooks Range. In general, map analyses Suggest that eastern facing portions of hills immediately around the site above about 1000 ft elevation are likely to offer an excellent wind resource (Class 5 and above). Wind speeds can vary significantly from one ridge crest to another as a result of the orientation to the prevailing slope of the ridge and its closeness to other ridgelines. Winter is the season for highest wind speed and power at mountain summits and ridge crests. In general, many of the higher exposed ridge crests and mountain summits in the area are estimated to experience as much as Class 7 wind resource for a winter average. However, extreme winds, icing, and inaccessibility caused by poor weather and snow depths during winter may severely restrict the suitability of many of these areas for wind energy development (USDOE, 1986). Shaw ‘Stone & Webster Management Consuttamts, Inc. 1-2 February 17, 2006 P 4 Ambler Mining District -Mine Power Study a similar projects. If a road were to be developed first, the cost of installing the pipeline would be reduced substantially. The magnitude of these costs generally put these options out of reach for the mine project unless such facilities were implemented with major government support as part of a regional development program and/or shared with other fuel oil users such as additional mining facility developments. Since no such plans have yet been established, fuel oil delivery by pipeline is not considered feasible. Pipeline Delivery of Natural Gas Pipeline delivery would require development of a new pipeline to connect to a new natural gas production facility or major gas pipeline. Although gas exploration near the coast to the west of the site has been proposed, there are no concrete plans to do so. Connecting to the proposed Alaska natural gas pipeline would require an extended and difficult route to the east. In the absence of an access road along a pipeline route, construction of this pipeline could cost up to several million $ per mile. If a road were to be developed, the cost of installing the pipeline would be significantly reduced. As is the case for a fuel oil pipeline, the magnitude of these costs put these options out of reach for the mine project unless such facilities were implemented with major government support as part of a regional development program. The Northwest Arctic Borough has proposed exploration of natural gas production northwest of Noorvik. However, there does not appear to be a large enough market in the region to support the interest of gas producers in pursuing the exploration and development of gas production facilities in that region. Pipeline Delivery of Coal Coal could be delivered to the mine as a slurry by pipeline from a remote coal receiving/transshipping facility at a port on the west coast of Alaska. This facility could receive coal shipments during summer months when barge deliveries are possible and stockpile sufficient coal to support year round shipment to the mine. This would require a large storage facility to supply 12 months worth of coal based on 2-3 delivery months. The installation of a dedicated pipeline to the Ambler Mine is difficult to estimate, but could cost $300-400M, plus the installation of a receiving facility to dewater the coal slurry and treat and utilize or release the water. The cost of such an unloading/storage terminal and coal water slurry delivery pipeline system could vary considerably based on the amount of coal needed to support mining power requirements, Also, such a coal receiving/storage/transfer terminal may have complementary functionality with an ore delivery system. Coal could be increasingly stockpiled based on deliveries during summer months while ore, stockpiled during winter months, is transferred to the barges for ship delivery near the coast. Road Delivery of Fuel Oil or Coal Delivery by road of fuel oil or coal from a coastal receiving terminal west of the site may be possible if road access were developed. The conclusion of the transportation study for the project is that such a Project is not economical and no plans have been announced to support such development with government funds. aks ‘Stone & Webster Management Consultants, Inc. 2:9 February 17, 2008 . E Ambier Mining District -Mine Power Study 4 ~ Potential high wind class areas may exist in the surrounding mountains at Class 6 to 7 ratings on nearby summits (AEA, 2005). At this time, certainty ratings of this data are conservative primarily because of the complexity of the terrain over most of the area and areas absence of wind data. Water Supply Water supply for consumptive uses is assumed to be available both from groundwater and surface water.. Water quality is assumed to be excellent. Makeup water will be treated by filtration and chlorination when used for potable and service water applications. Some water may be consumed for evaporative cooling depending on the power generation configuration selected. A raw water treatment and storage facility for the entire mining complex will be provided and is not included in the scope of each onsite generating option. Support Logistics All material and equipment will be delivered to the site either by air transport to a dedicated airstrip near the mining complex, and transported by truck to each facility site from a central warehousing facility. Alternatively, barge delivery to the end of the navigable portion of the Kobuk River will be scheduled during summer months, with storage near the unloading point and subsequent delivery by cat train to the site during winter months. Labor for Construction and Operation All labor required for installation of the generation facilities will be provided by off-site contractors. A camp will be developed to support seasonal, and some year round, accommodations for workers. A permanent camp facility will remain after construction, integrated with the housing and living requirements of the mining complex workforce. 1.2 Diesel Module Locations Diesel power modules will be located near the mining complex to allow cogeneration (hot water) in support of local camp facilities. The sites are assumed to be flat with permafrost foundation conditions. Each site will have access by road to a dedicated airstrip for transport of materials and equipment. Makeup water for consumptive uses will be provided from a water supply pumping station located at a nearby river or groundwater well. Diesel fuel will be pumped to each diesel generation module from a central diesel fuel storage facility. 1.3. Windfarm Module Locations The windfarm modules will tentatively be located at ridgelines along the hilss adjacent to the mining complex at an elevation of about 1000 feet as shown conceptually in Figure __. An access road will be provided between the mining complex and windfarm modules to support construction using large cranes and to facilitate maintenance of interconnecting transmission. Shaw ‘Stone & Webster Managernem Consuttants, Inc. 1-3 | February 17, 2006 p- Ambier Mining District -Mine Power Study 4 14 — Hydro Power Module Locations Several hydroelectric projects are considered at various opportune locations near the proposed mining facility. Generators will be located at various power house locations integrated with each project design. 1.5. Transportation Access Air freight deliveries will provide year-round access to supplies and equipment up to maximum payload size and weight restrictions with periodic limitations due to extreme weather conditions. Barge delivery up the Ambler River and winter cat train transport to the site may also be used for some equipment and material deliveries. Alaska Gold has completed a transportation study independent of this power study. We understand that the conclusions of this study are that no road or railroad access to the site will be considered to support mining operations. 1.6 Waste Disposal All wastewater will be treated to a suitable quality for discharge into a nearby river. Solid waste will be stored onsite and disposed of properly onsite or removed from the site by air transport or through a barge access point if local disposal is not permitted. Shaw Stone & Webster Manageme: Consultants, inc, 1-4 February 17, 2008 Ambler Mining District -Mine Power Study a 2.0 Screening of Power Delivery Alternatives Power supply alternatives include the installation of power generation facilities on or near the site, and installation of transmission lines to connect with new or existing generation located remote from the site. This entails several technology and fuel options that can be considered. 21 Onsite Power Options Table 2-1 below summarizes onsite power generation options that were reviewed for possible application to the proposed mine: Table 2-1 Summary of Power Generation Technologies and Fuel/Energy Sources Plant (Technology) Fuel (Energy Source) Reciprocating engines Natural gas; distillate; crude oil Combustion turbines Natural gas; distillate; crude oil Combined cycle Natural gas; distillate; crude oil Pulverized coal Coal Fluidized bed combustion Coal Coal gasification combined cycle Coal Fuel cells Natural gas; hydrogen Wind power generation Wind Hydroelectric power generation Water head and flow (river or impoundment) Cogeneration (combined with onsite power Natural gas; distillate; crude oil generation and thermal loads) , Solar thermal electric Direct sunlight Photovoltaics Total sunlight Small nuclear reactors Advanced nuclear fuels 2.2 Access to Fuel and Energy Sources Selection of feasible alternatives is driven first by the accessibility to the fuel or energy source. Most fuel delivery options require bulk transport by some combination of barge and cat train, pipeline, truck or air freight. Power delivery by transmission from remote generating facilities is also addressed. Pipeline Delivery of Fuel Oil Fuel oil pipeline delivery would require development of approximately 150-200 miles of new pipeline to connect to a coastal tanker unloading facility. In the absence of an access road along a pipeline route, construction of this pipeline is difficult to estimate but could cost on the order of $200-400M based on SShAW stone & Weoster Management Consutants, nc. 2-1 February 17, 2008 , pe Ambler Mining District -Mine Power Study * Rail Delivery of Coal Based on the transportation study conducted for Alaska Gold, the cost of constructing a rail link to the site from a port on the west coast of Alaska would be prohibitive, and is outside the feasible range of investment for this mine development project unless such work was heavily subsidized as part of regional development program. Currently, there is no indication that the State of Alaska intends to proceed with such support within the time frame of the mine development project. Air Transport of Fue! Oil Fuel oil is currently transported by air to various locations in Alaska that are otherwise inaccessible. This is considered the baseline fuel delivery scenario for the study and forms the basis for comparison with other options. Additionally, the mining complex may have an air transport terminal to support frequent air freight deliveries to the site. A jet fuel depot could be established to receive and store jet fuel near this facility for aircraft refueling. Some of this jet fuel can be utilized in aeroderivative combustion turbines for power generation. Deliveries of jet fuel could be arranged by special tanker aircraft to reduce delivery costs. 2.3. New Regional Power Generation Projects Implementation of large power projects located at sites that can be tied in by transmission lines to both the proposed mining complex and other large loads may be possible. A study was completed by the Northwest Arctic Borough entitled “Centralized Power Generation/Interconnection Study” dated August 2005, that described a proposed combined cycle power plant located near a possible new gas production area northwest of Noorvik. Six 10 MW combined cycle units were considered to provide redundancy and Teliability to serve loads of about 27MW at Red Dog Mine, 4MW at Kotzebue, and about 2MW at five other villages (Kiana, Kivalina, Noatak, Noorvik and Selawik). Figure 2-1 below shows the proposed 138kV transmission line connecting these loads to the proposed plant site. Discussions with individuals involved with this study indicate that they also considered providing additional capacity at this site with a transmission link to the Amber Mine site. The cost of building the 132 miles of transmission lines shown in Figure 2-1 are estimated to be about $130M. The cost of extending this line to the Ambler mine is difficult to estimate, but could be in the range of $200-300M given the difficult terrain, access and construction logistics. Based on reviewing this report and discussing the potential for gas exploration with gas industry representatives, it appears that even with expansion of the power project to serve the Ambler mine the projected revenue from a gas production operation would be insufficient to promote exploration by gas producers. Shaw stone & Webster Management Consuttants, inc. 2-3 February 17, 2008 Ambler Mining District -Mine Power Study Figure 2-1 Proposed Regional Gas Fired Power Plant and Transmission System Other power plant and fuel configurations could be considered to serve this small grid. Due to the long transmission line runs, each power delivery destination would probably have to maintain backup capacity for transmission outages, and operate some generators to maintain load flow and frequency stability. Such options are included in the economic comparison of off site power generation options as discussed in Section 8.3. Windfarms could be developed but would, by themselves, not provide long term reliable power and would encounter grid stability problems on a small extended transmission system. The operational limitations of windfarms could be overcome by using backup combustion turbines or diesels near the loads, but that would result in only part-time utilization of an expensive transmission system which makes the net cost per kWh that much higher to recover its investment. No other large regional power generating projects have been proposed within a reasonable transmission distance to the Ambler Mine. 24 Candidate Fuel Sources and Delivery Options Fuel delivery options considered for this study include diesel fuel, jet fuel, natural gas and coal. ShaW stone & Webster Management Consultants, Inc. 2-4 y February 17, 2008 Y ee Ambler Mining District -Mine Power Study ’ - Fuel Oil Diesel fuel prices have been rising sharply in Alaska and other parts of the US during the last year. The State of Alaska Department of Commerce, Community and Economic Development issued a report “Current Community Conditions, Fuel Prices Across Alaska” dated December 2005 which documents the recent history of fuel oi] and gasoline prices to various locations and for various delivery methods. Diesel fuel currently is delivered by air freight to remote inland customers at prices near $5/gallon. Assuming 140,000 Btu/gallon, that is about $35.70/MMBtu. Since the Ambler Mine would be receiving large and frequent shipments a lower equivalent price would be expected. A nominal price of $35/MMButu is used as a representative cost of delivered diesel oil for purposes of the economic analysis. It may be more economical to deliver diese] fuel by barge to a storage terminal near the Kobuk River with subsequent pipeline delivery to the site. Barging costs., construction costs for a receiving terminal, and the cost of a pipeline forwarding system were not evaluated in detail for this study, but should be investigated further. Natural Gas There are currently no plans to develop new gas production facilities anywhere near the Ambler Mine to support pipeline delivery. If the Alaska gas pipeline is installed, it may be possible to install a delivery pipeline that connects to the Ambler Mine. However, this pipeline would have to traverse over 200 miles over difficult terrain that currently does not have road access to support construction. It is not possible to estimate the cost of this project, but a comparison with other pipeline projects in remote areas indicates that the cost of such a system would have to include the development of a construction access road, with a total cost possibly exceeding $500M. This is not considered a feasible option at this time. Coal Coal can be delivered to the near the site by seasonal barge transport up the Kobuk River to an unloading terminal, from which it could be forwarded to the Ambler Mine by a 50-60 mile pipeline as a coal/water slurry or dry by conveyor. The costs of this delivery route are difficult to estimate given the need to evaluate barge delivery schedules and the transshipping facilities that would be required. Such a delivery arrangement would be undertaken in combination with the transport of raw or processed ore, fuel oil and other materials. This option has not been recommended by the transportation study prepared for the Ambler Mine. A nominal delivered cost of coal of $4/MMBtu is assumed to support the economic analysis for this study. An estimate for air freight delivery of coal was not available, but may be derived from the transportation study results by evaluating the cost of shipping ore by air. 2.5 Generator Options Several onsite power generation options are identified as follows. Shaw Stone & Webster Management Consultants, Inc. 2-5 February 17, 2006 Ambier Mining District -Mine Power Study «por Diesels Diesel engines are commonly used in remote mining applications to provide reliable power. Two diesel plant configurations are used to evaluate the relative economics. A 45 MW plant consisting of nine 5 MW heavy duty low speed engines adapted for cold weather service is considered to provide 35 MW of continuous reliable power. A second configuration of 21 SMW units is evaluated, which has a rated output of 109MW but should produce a reliable continuous net output of 89MW. These designs and the basis for their economic evaluation are described in Section 3. Combustion Turbines Combustion turbines can be operated using distillate or jet fuel delivered to the site by air transport or barge/pipeline. A combined cycle configuration can be used to recover waste heat for cogeneration as well as to maximize power generation efficiency to minimize fuel delivery requirements and costs. Combustion turbines operating on liquid fuels require more frequent and extensive maintenance, and would rely on larger unit sizes making redundancy for reliability more expensive. Since overall generating costs would be close to that for diesels, no specific designs and economics were developed for a simple cycle or combined cycle application at the site. Hydroelectric Power Potential hydro power sites were evaluated on the Shungnak and Kogoluktuk Rivers. In addition to full development for maximum economic capacity and energy production, reduced development options were reviewed to avoid impounding water in the Ambler Lowland at each site. These options are described in detail in Section 6 of this report. Coal Fired Boiler Steam Electric Plants Pulverized coal boilers and circulating fluid bed (CFB) boilers would require large quantities of coal and limestone deliveries to the site, along with disposal of large amounts of ash and byproducts from sulfur removal systems. The economics of a 100 MW CFB plant are included in the economic evaluation using representative cost and performance information from other projects. For purposes of this analysis, coal would be barged up the Kobuk River during summer months to an offloading/truck transfer system. The coal would then be trucked to the site where it stockpiled for year-round use. This would require construction of a haul road, assumed to be 60 miles long. An allowance of $100M is included for the construction of this road, which would be available for other barge deliveries to/from the site. If ore were shipped from the site using this route, then the cost of the road and trucks would not all be allocated toward this power generation option. Shaw stone 8 Webster Management Consutants, Inc. 2-6 February 17, 2008 . ps a Ambler Mining District -Mine Power Study wh Photovoltaic Energy Conversion Several large scale photovoltaic power generation systems have been installed at costs as low as $6000/kW. However, the high latitude of the site results in low sun angles which result in loss of direct sunlight due to diffusion and dispersion, making focusing collectors impractical. Also, heavy snow occurs much of the year that would further constrain the availability of such a plant. Such a facility would operate at only 10-15% of rated capacity on an annual average basis with most of the output during summer months. Figure 2-2 below shows that northern Alaska generally receives only about 1100 kWh/kW rated capacity for photovoltaic systems. We did not attempt to model this system economically due to the low annual output and further losses due to seasonal snow cover. Figure 2-2 Solar Radiation Available in Alaska TY 1 1800 Pier Source SEIA Solar Thermal Energy Conversion Due to the low amount of annual direct solar radiation and heavy snowfall, linear concentrating solar thermal systems would have a very low capacity factor on the order of 10-15% making them impractical. Biomass The climate near the site does not support the production and harvesting of biomass at a scale needed for power generation. Shipping biomass to the site by air or barge is less attractive than shipping other fuels that provide higher energy densities. Obtaining biodiesel, derived from vegetable oils, can be considered as fuel for diesel engines if available and economical. Shaw ‘Stone & Webster Management Consultants, Inc. 2-7 February 17, 2008 . f- Ambler Mining District -Mine Power Study 4 Discussions with the Alaska Energy Authority and a review of available maps indicate that there are no known geothermal resources near the site. Also, exploration for geothermal resources is expensive and not likely to be pursued in the region in the near future. Shaw ‘Stone & Webster Management Consuttants, inc. 2-8 February 17, 2008 Ambler Mining District -Mine Power Study aw % 3.0 Diesel Power Generation Electrical generators driven by reciprocating diese] engines are widely-used in the mining industry and provide a reliable power source. Current applications in remote Alaska locations include remote military facilities, petrochemical facilities and remote mining operations. Such units are readily available from numerous vendors in a variety of output sizes and can be modularized and coupled to match facility needs. Individual units are transportable and replacement parts are readily available. Diesel fuel is distributed throughout Alaska from in-state refining facilities. This section presents a description of a 35MW diesel power generating plant concept along with estimates of capital cost, O&M cost, performance, and environmental impacts. 3.1 Equipment Suppliers Package diesel power generation units are readily available in a wide variety of capacities from manufacturers that include Wartsila and Caterpillar. Units are manufactured upon ordering; there is generally a 24 month lead time required between the time the units are ordered and shipped. Wartsila technology is selected as a representative candidate for this application. Wartsila currently has several units operating in remote Alaska locations, many of which use the same engine package identified below. Wartsila offers service, parts and technical support. Units are shipped FOB by the vendor to a specified site or major port city in the contiguous United States. Figure 3-1 Wartsila W32 Diesel Engine Shaw’ store & Webster Management Consuitants, inc.” 34 February 17, 2008 Ambler Mining District -Mine Power Study eo : equirements The diesel generators will be designed to operate using light fuel oil since this product is widely available throughout Alaska. This Wartsila 12V32 engine product can operate with a heavier grade (#2 diesel) which is generally used in the summer months and a lighter winter grade (#1 diesel) which is less prone to gelling in cold temperatures. Preliminary performance calculations and net plant output are based on the use of #1 diesel. 3.3 Plant Capacity and Expected Utilization This plant is configured to provide a reliable year-round capacity of 35 MWnet. This plant configuration allows for two redundant engines to allow maintenance of one engine and failure of one engine, with seven engines operating at all times. Each engine is overhauled about every 40,000 hours of operation (shorter intervals if operated at part load or with frequent starts). This plant is assumed to operate reliably (no forced losses in output) year round. In the event that this plant is utilized in combination with other energy sources like wind and hydro power, then its utilization would decrease accordingly. More frequent overhaul cycles will be required if they are operated intermittently. For peaking duty and to provide better system load response, the substitution of less efficient, higher speed engines may be considered to provide better dynamic capabilities. If some of the machines are required only seasonally (ie winter months when hydro power is not available), then maintenance could be scheduled accordingly and the reliable rating would be based on eight engines operating with one on standby, increasing the rated capacity to 40 MW net output. 34 35 MW Diesel Plant Design The plant design includes nine engines each with 5.0 MW gross output. The gross maximum output of all nine units combined is 45 MW, which is reduced to about 40 MW when one unit is out of service for maintenance. Allowing for the possible failure of one operating unit, this leaves a reliable capacity of about 35 MW based on 7 engines operating. Wartsila provided the following weight and dimensions for the 12V32C unit, which is representative of units in this size range: Weight — 100 tons e Dimensions — 31.3 ft L x 9.6 ft Wx 15.1 ftH This unit is transportable by road and barge. It can also be transported by a Boeing 747 airframe. The plant would be housed in an insulated building of approximately 30,000 square feet, equipped with shop space, an overhead crane to support maintenance, and supporting mechanical systems such as fire suppression and heating/ventilation. The plant could be arranged to allow lateral expansion to Shaw ‘Stone & Webster Management Consuttarts, Inc. 32 February 17, 2006 Ambier Mining District -Mine Power Study accommodate additional generators. Appendix 1- Ambler 35 MW Diesel Generator Conceptual Arrangement shows a conceptual plant layout for the 35 MW plant. Appendix 2 - Ambler 35 MW Diesel Generator Building Section. shows a typical building cross section for this arrangement. 3.5 Site and Fuel Storage Requirements Construction of a diesel power system requires a relatively flat area with good structural soil. Fuel storage facilities will be provided nearby to provide a reliable fuel supply. Assuming that three months of storage will be sufficient to overcome the longest interruption in fuel delivery, about 4 million gallons of fuel oil storage should be provided. About 400,000 sq ft of land is required for the diese] area and fuel storage and unloading facility for the 35 MW diesel plant. 3.6 Performance Calculations Performance estimates were obtained as fuel rates in gallons per kWh from the equipment supplier for full- and partial-load conditions. Gross power output was set based on manufacturer's recommended continuous rating. Frequent partial-load operation will result in the formation of deposits in the exhaust system and shortens scheduled maintenance intervals. Engine performance is affected by fuel quality and environmental factors.. #1 diesel fuel typically has 1.4 to 3.5% less heat content than # 2 diesel fuel. While it may be feasible to scavenge waste heat to allow on site storage of #2 diesel without fuel gelling, power output during winter months is conservatively based on the use of #1 diesel. As a result, the gross output of each engine is de- rated by 3.5% to account for the smaller heating value of #1 diesel fuel. Wartsila provided a heat balance calculation for their 12V32 engine. The heat balance uses the following assumptions: ¢ LHYV of #2 diesel of 18,300 Btu/Ibm ¢ Worst-case ambient temperature of 92 deg F e Altitude of 500 feet msi Based on the Wartzila data, the specific fuel consumption for the 12V32C unit is 0.049 gallons of diesel per kilowatt hour gross output (Wartsila, 2005). When operating near full load in winter conditions using #1 diesel fuel, each engine produces about 18.9 net kWh/gal fuel oil (7250 Btw/kWh for 137,000 Btwgal). When operating on #2 fuel oil with 21 deg C cooling water, each engine produces about 19.6 net kWh/gal fuel oil (7194 Btu/kWh). An average annual efficiency of 19.3 kWh/gal (7200 Btu/kWh) is assumed for Shaw swne & Weoster Management Consutants, inc. 33 February 17,2008 Ambler Mining District -Mine Power Study purposes of estimating annual fuel costs. Btu values are LHV (lower heating value) which are about 5% lower than HHV (higher heating value). Net plant output to the mining operations with 7 engines operating is 33.4MW, after deducting auxiliary power loads and transformer losses. 3.7. Environmental Considerations Internal combustion engines require an optimum air-fuel ratio in order to maintain satisfactory performance and low emissions. Units operating at high elevation and high ambient temperatures experience lower output due to decreased air density. The Ambler area is located in the Northwest Arctic Borough and experiences extreme annual temperature variations. Temperatures average -10 to 15 during winter; 40 to 65 during summer. Temperature extremes have been recorded from -65 to 92. Snowfall averages 80 inches and precipitation is 16 inches total per year. High temperatures are experienced two months out of the year (NW Arbor, 2005). Diesel engines will be located indoors to protect them from extreme weather conditions. Waste heat from engine cooling systems will be used for space heating. The diesel power plant can be constructed at an elevation of less than 1,500 feet mean sea level (msl) at one or more locations that will serve nearby loads at the mining and processing operations. Existing airports near the mine site have elevations less than 500 feet ms] (FAA, 2005). Air emissions and noise are normally the key environmental issues that are addressed in permitting diesel power generation facilities. An air quality control construction permit will be required. Air quality permits are issued by the State of Alaska Department of Environmental Conservation. Based on recent cases of diesel power generation permitting actions, emissions control for nitrous oxides will likely be required. Noise control can be achieved by purchasing a combination of vendor-provided muffler equipment plus the use of an acoustically insulated building. Detailed emissions rates by pollutant are available from the manufacturer based on specific engine configurations and fuel characteristics. Air quality permits should be achievable based on the use of state of the art emission control technology available from the manufacturer. About 500,000 sq ft of land is required for the diesel area and fuel storage and unloading facility for the 35 MW diesel plant. Fuel storage areas will require spill prevention systems, as well as electrical or steam heat tracing to control viscosity during cold weather. No significant water consumption is required except for consumptive uses for residential, commercial or industrial hot water co-produced by the engines. Radiators, designed and properly situated for cold weather conditions, will provide heat rejection when there is not an opportunity to utilize waste heat. Shaw stone & Webster Management Consuitants, Inc 3-4 abruary 17, 2008 , & Ambler Mining District -Mine Power Study 4 ‘Wastewater from stormwater runoff and maintenance activities would be collected, filtered, and conveyed to other site facilities integrated for total site waste treatment. 3.8 Capital Cost Estimate Table 3-1 presents an order-of-magnitude capital cost estimate for each configuration Table 3-1 Diesel Plant Capital Requirements $k US January, 2006 Diesel engines 23,650 Building 6,630 Fuel storage and handling 1,6230 Transformers, substation 3,380 Balance-of-plant 700 Other EPC costs 6,350 Initial fuel inventory (3 mos) 19,500 Owner’s Costs 5,900 Contingency 4,300 Construction interest 4,600 Total 77,290 Wartsila provided budget pricing and performance estimates for the 12V32C diesel engine package consistent with features expected for this application. The rest of the estimate was derived from Stone & Webster’s experience with other projects. Other EPC costs include engineering, site office, site delivery and logistics, and contingency/profit. Owner’s costs include water supply, overall procurement and management, permitting and licenses, initial fuel inventory, startup costs and spare parts. Fuel inventory cost is based on 3 days or 72 hours of storage for a full load fuel consumption rate of 2,270 gal/hr for the 35 MW plant, and 5,300 gal/hr for the 90 MW plant. Spare parts are estimated at 0.5 percent of the direct cost. Construction interest is estimated at 8% based on assumed midpoint of construction to commercial operation. This can vary considerably with the scheduling of payments for the initial fuel inventory, which could alternatively be considered working capital. 3.9 Operations and Maintenance Costs The O&M cost calculation is divided into fixed and variable components. Fixed O&M Fixed O&M costs represent expenditures that are not related to how much the diesel engines are operated, such as salaries for full time staff and maintenance and repair of structures and equipment other than the Shhaw ‘stone & Webster Management Consultants, Inc. 35 Februay 17, 2008 i fe Ambler Mining District -Mine Power Study 4 diesel engines. This includes the cost of full time plant staff, supervision and overhead and an allowance for maintenance materials. Table 3-2 Summary of Fixed O&M Costs $k/yr S/AW-yr Operating labor 1,318 39.52 Maintenance labor 527 15.81 Maintenance material 100 3.00 Total 1,945 58.33 Variable O&M Variable O&M accounts for costs that are incurred in proportion to the operation of the diesel engines. This includes allowances for consumables and incremental maintenance of the diesel engines. Oil is changed when contamination is identified during periodic inspections. An on site waste oil burner is assumed to be on site to process spent motor oil; therefore, no disposal costs are included. The SCR emissions control unit uses ammonia as a catalyst and is included as a consumable in the cost estimate. Contract labor will be used to visit the site regularly to conduct annual inspections and major overhauls. Wartsila recommends an interval of 40,000 operation hours for major overhaul of each engine. Overhauls include replacement of all moving and worn contact parts of the cylinder assembly, cleaning the interior of the crankcase, and test-running the engine. Wartsila provided a cost estimate on an engine operating hour basis for these items based on a ten year operation period. This works out to be about $20 per engine-hour. For 35 MWnet operating continuously, this represents the equivalent of 7 diesels x 8760 hr per year, or about Table 3-3 Variable O&M Summary $/hr $k/yr $/kWh Consumables 6 33. 0.00018 Overhauls 140 1,226 0.00420 Other variable O&M 1 li 0.00004 147 1,290 0.00442 3.10 Schedule A representative barchart schedule is shown as Figure 3-2. The 35 MW diesel power plant schedule is based on an overall duration of 60 months. Its critical path is through environmental permitting, fabrication and delivery of the diesel generator unit, installation and start-up and test of the diesel generator unit. The following assumptions apply. Many of the time durations are extended to address the seasonal limitations affecting shipping and construction activities. ¢18-month licensing (environmental permitting) period starting before with conceptual engineering. Release to fabricate (e.g., diesel generator unit, tanks, pumps and miscellaneous equipment) not rendered until the permitting process is complete (permits received). ¢24-month diesel generator unit fabrication and delivery period. ¢18-month actual delivery and construction period (includes start-up and test). Shaw stone & Webster Management Constants, no 3-6 * February 17,2008 a a Figure 3-2 Diesel Plant Project Summary Schedule Milestone Schedule 0 12 24 36 Ambler Mining District -Mine Power Study Months from Start of Permitting 48 72 | Permitting ae Design & Procurement + —= Fabrication Ship to Site i | j Construction | | | | Commission/startup | | 3.11 References Lindeburg, Michael. 2001. Mechanical Engineering Handbook, Eleventh Edition. Publications, Inc., California. Professional Wartsila, 2005. Parametric cost figures and heat balance, Personal and e-mail communication in October 2005. FAA, 2005. http://www.lat-long.com/Alaska/Ambler-Airport_1417544.html NW Arbor, 2005. http://www.nwabor.org/profiles/Default.htm Shaw stove 8 Weoster Management Consultants, inc, 37 Feorvary 17, 2008 Ambler Mining District -Mine Power Study 4.0 Windfarm Power Generation Module A nominal 15 MW windpower module is described in this section. The feasibility of this option is subject to (a) the verification of the wind resource near the mining area, (b) a preliminary evaluation of the logistics of transporting and erecting a state-of-the-art wind turbine generators (WTGs) at proposed sites, and (c) the economics of the wind power modules. 4.1. Wind Resource Definition A preliminary wind resource mapping effort has been completed by the Alaska Energy Authority and is being reviewed at the time of this study by the National Renewable Energy Laboratory (NREL) in Golden, CO. Figure 4-1 below shows the mapping of the. wind resource in the area near the proposed mining site. Several category 5, 6 and 7 areas (i.e., superior wind resource) are in the region and appear to be suitable for windfarm applications. Figure 4-1 AEA Wind Resource Map Ehergy Resources laska Wind map ‘2005 jf Shaw stone & Webster Management Consuitarts, nc. 4-4 February 17,2008 Ambler Mining District -Mine Power Study = fer Table 4-1 Classes of Wind Power Density at 10 m and 50 m(a) 10 m (33 ft) Wind Speed”? = mis (mph) (Wim?) 5.1 (11.5)/5.6 (12.5) 6.4 (14.3)/7.0 (15.7) 5.6 (12.5)/6.0 (13.4) 7.0 (15.7)/7.5 (16.8) 400 - 500 6.0 (13.4)/6.4 (14.3) 7.5 (16.8)/8.0 (17.9) 6.4 (14.3)/7.0 (15.7) 8.0 (17.9/8.8 (19.7) >7.0 (15.7) >8.8 (19.7) (a) Vertical extrapolation of wind speed based on the 1/7 power law (b) Mean wind speed is based on the Rayleigh speed distribution of equivalent wind power density. Wind speed is for standard sea-level conditions. To maintain the same power density, speed increases 3%/1000 m (5%/5000 ft) of elevation. Source: Battelle Wind Energy Resource Atlas Maps of the proposed Ambler Mine area were reviewed with wind resource experts at the National Renewable Energy Laboratory (NREL) in Colorado. NREL is reviewing the Alaska Energy Authority’s statewide wind mapping work by overlaying various models and available data to independently establish promising resource areas. Based on the topography around the mining area, the NREL wind specialists expect that excellent siting areas may exist on the hills adjacent to the proposed mine, as shown in Figure 4-2 below. Regional wind characteristics indicate a predominant easterly wind, with inversions that may interfere with laminar wind flow below 1000 ft elevations. The areas highlighted in Figure 4-2 may be considered for wind data collection. Their location may minimize the cost of transmission to the loads at the mining operation, and the cost of developing access roads to support construction and maintenance. One of the objectives of wind monitoring will be to establish the minimum elevations at which consistent winds can be accessed. Wind towers will be at least 60m high, or as limited by shipping and construction logistics. Therefore wind resource measurements should be taken as high as practical or adjusted for height using calculation techniques (which are limited in accuracy). SHAW stone & Webster Management Consuttants, inc. 4-2 Fetrony 17,2008 Ambier Mining District -Mine Power Study Figure 4-2 Initial Indications of Wind Resources j PROMISING SITES AT 1000’+ EAST FACING 4 ELEVATIONS 4.2 Candidate Wind Technologies A wide range of suitable WTGs exists that have considerable commercial experience. Because we neither know where the WTGs will be sited nor the magnitude of the wind resource, we currently project that the combination of reasonably strong winds during various periods, cold temperatures, and periodic icing conditions will require that WTGs be employed that are designed for a rugged Class 1A wind regime. Certain WTGs are designed for lower wind-speed sites that are less demanding because the sites have lower peak winds and less turbulence (eg., Class 2 or 3 winds). Therefore, our selection of candidate WTGs is limited to those designed for Class 1A sites. 1.5-MW wind generators were selected to provide a planning module for this study. A typical WTG that is roughly in this range is the GE Wind Model 1.5 or a Vestas Model V80. These machines represent the smallest machines that these vendors currently manufacture for sales in North America. These models represent a balance between economies of scale and size to allow for transportation to the site. GE Wind and Vestas are both reputable, proven vendors with the largest fleets of installed capacity at this size. Shaw ‘Stone & Webster Management Consutants, Inc 4-3 ; February 17, 2006 . fe Ambier Mining District -Mine Power Study ¥ WTGs of similar size are available from approximately three other, foreign vendors, but we will restrict our analysis to WTGs from GE and Vestas. A summary of the relevant WTG power ratings, sizes and weights are given in Table 5-1. Two versions of the GE Wind WTG are listed because the WTGs are available in two different rotor diameters, where the smaller diameter WTG is tailored for more energetic wind sites (i.e., Class 1 winds) and the larger diameter for sites with lower wind speeds and lower turbulence. It is believed that the combination of wind and potential ice loading may cause the overall loading on the WTG to be that of a Class 1A wind site. The weights of the nacelle and gearbox are listed in Table 4-2 because they will affect the crane needs during assembly at the site and during operation and maintenance activities — should a gearbox have to be removed and replaced. The Vestas Model V80 WTG is tailored for more energetic wind sites. Table 4-2. Major Characteristics of Typical Candidate WTGs WTG Model Rated Rotor Approximate Approximate Supplier Number Power Diameter Nacelle Weight Gearbox Weight MW m tons tons GE Wind 15s 1.5 70.5 50 18 GE Wind 1.5 sle 1.5 77 50 18 Vestas A/S V80 18 80 63 25 If the site is confirmed to be a Class 2 wind site, then the use of a Vestas Model V82 (rated at 1.65 MW, nameplate) might also be considered because it is generally a simpler and more cost-effective WTG. Wind Power Module Design The windpower module configuration includes 10 approximately 1.5 MW wind turbines. The output from these 10 WTGs will feed through the power collection system, which in turn sends power along the (assumed 5 mile) transmission line to the mine loads. Service and general access to the WTGs will be via gravel interconnecting roads which provide limited seasonal access. WTG design limits operating at cold temperatures due to the behavior of materials used in blade construction. Both GE and Vestas provide WTGs that can operate down to approximately -20 °C. Normally, wind speeds at extremely low temperatures are low given the atmospheric conditions during such periods. A correlation of wind speed to ambient temperature will need to be conducted to estimate the amount of energy lost during such periods, although such losses are expected to be small. Shaw stone & Webster Management Constants, ine, 4-4 Fetruay 17, 2006 ‘pO Ambler Mining District -Mine Power Study — The GE 1.5 line of wind machines listed in Table 5-1 has rotor diameters of 70.5 to 77 meters with a hub height of 52.5 to 85 meters, while the Vestas V80, has only the 80-m diameter rotor and is generally available with hub heights of between 60 and 80 meters. Figure 4-3 GE Model 1.5 Wind Generators Either of these wind turbine models will include the following components: Nacelle — The drivetrain, bedplate, hydraulic system and a portion of the controller are enclosed within the fiberglass nacelle structure that is secured to the bedplate. The nacelle provides shelter for the equipment and working personnel. The nacelle interior is well ventilated by louvers to help to cool the gearbox, generator and hydraulic system — all of which can become very warm during prolonged periods of high energy production. Drivetrain - The rotor speed in each WTG is increased through a multistage gearbox that transmits the associated torque to a single generator. The loads that are imparted to the rotor are carried by the low-speed drive shaft which consists of a large, hollow, steel cylinder that is supported by two main bearings. The hollow center of the shaft provides space for the hydraulic lines for the pitch actuation system on some of the WTGs or for the passage of electric power for electric pitch actuators mounted within the hub (eg., GE WTGs have electric actuators). A generator is attached to the high-speed output shaft of the gearbox. Various rpm sensors are strategically placed on the drivetrain to provide important signals to the turbine control and safety systems. Almost all WTGs considered for use in this project operate in a variable speed fashion in which the rotor speed can vary from approximately 10 to 19 rpm. This approach helps to gain more energy and relieve mechanical loads on the WTG. A SWhaW stone & Weoster Management Consultants, Inc. 4-5 February 17, 2008 Ambier Mining District -Mine Power Study iM , Tower - The wind turbines sit atop enclosed, cylindrical, welded steel towers that provide a hub height of up to 85 m (or higher for special cases). The enclosed towers provide for better aesthetics than a trussed tower and a degree of shelter for maintenance personnel. The enclosed towers also provide fewer perching areas for birds and therefore, can lead to a lower level of concern for avian mortality. A substantial portion of the WTG computer controller and all of the network interface system are housed in the base of the tower. WTGs of this size could include a man-lift or elevator. Most WTGs have a small lifting device within the nacelle to assist in lifting loads up to approximately one ton. The towers are shipped in sections and erected by a crane. Control System - A critical element of the turbine is the control system. The control system performs the following functions: (i) supervises turbine starts and stops under normal operation, (ii) protects the turbine under extreme and emergency conditions such as faults caused by a component problem or a loss of utility load while under power, and (iii) controls the output power of the turbine by (a) pitching the blades and (b) changing the generator slip, to maximize energy production while minimizing loads for high wind speeds greater than approximately 55 mph. The controller is a digital computer that, for the most part, employs programs that have been proven for several years. Portions of the controller are found both in the base of the tower and in the nacelle. These are linked by fiber optic lines to minimize interference and damage from lightning. Current WTG controllers and associated power electronics meet stringent guidelines recently defined by the Federal Energy Regulatory Commission (FERC) regarding (a) power factor control, (b) low-voltage ride-through features, and (c) SCADA system access by an Independent System Operator (ISO). Generators - Some WTGs are supplied with an asynchronous (induction) generator that is bolted to the turbine frame or bedplate. The WTGs listed in Table 5-1 are supplied with specially modified or design generators to allow them to operate in a variable-speed manner. For example, the GE WTGs use wound-rotor, doubly-fed generators and the Vestas WTGs use induction generators in which they vary the resistance of the rotor circuit to achieve variable speed operation. Each such WTG has a set of slip rings to achieve rotor current control. Typical generators provide power at approximately 600 to 690 VAC, at 60 hertz. WTG synchronization to the utility network is automatically controlled to occur when the speed of the generator field is similar to that of the network frequency. Shaw: stone & Weoste: Management Consultants, Inc. 4-6 Fetruay 17,2008 Ambier Mining District -Mine Power Study Figure 4-4 — GE Wind Turbine Components 1 Nacele 2 eat Excnanger 3 Genera Ne 7. Kydraune Parking Brake Gearbox impact Noise insutaton 0 Yaw Drive 11. Yaw Drive Rotor Shatt Oil Cooler Pitch Onve Rotor Hub 18 Nose Cone Power Collection System and Substation In multi-unit windfarms, WTGs are typically sited in rows with spacing that are no closer than approximately 8 to 10 rotor diameters (RDs) downwind and 2 RDs crosswind. The output of each WTG is wired through a circuit breaker located at the WIG. The 600- to 690-volt output from the WTG generator is usually increased at the WTG before being sent to a switchyard or substation. The secondary voltage of the transformers is typically in the range of 12.6 to 34.5 kV. The transformer is either found on the ground (a pad-mount unit for GE WTGs) or within the aft end of the nacelle (Vestas V80 units). The power collection lines from the WTGs will enter an enclosed substation or switchyard. At the substation/switchyard, there is typically a large disconnect switch to allow the windfarm (or sections of the windfarm) to be readily taken off line should the need arise. The voltage range of many of the substations encountered in the US wind business is typically between69 and 230 kV. WTG Arrangement The final layout and spacing of the WTGS will be determined based on a detailed wind resource and micrositing analyses. The spacing and locations are determined to minimize downstream interference based on dynamic loads and long-term wind speed and direction data. , Site Conditions The potential site is located near the Kobuk River, approximately 5 miles from the mine site. Transportation of equipment to the site may be by air cargo (if weights are not too great), or by summer barge delivery up the Kobuk River and winter delivery to the site using cat transports. Small airports are near by and a small road exists for personnel access. Site meteorology and other conditions are summarized in Section 1.1. Shaw ‘Stone & Webster Manageme Consultants, inc. 4-7 , February 17, 2008 Ambler Mining District -Mine Power Study PC y The topography of the specific sites for the wind farm can vary from high ridges to plateaus and valleys. Sites will be selected based on information yet to be developed regarding a detailed wind resource assessment and road design constraints. Tower erection will require the use of cranes which need road access during construction.. Geotechnical Investigations & Foundation Design A geotechnical field and laboratory investigation will be required to establish foundation design requirements. Some locations may need to address the effects of transitional permafrost which may impose seasonal limits on foundation effectiveness. Also, the presence of asbestos in the local soils may require special handling of excavated materials. Structural Tower Design An engineering design study may be required to determine whether commercially available turbine towers possess the structural properties to operate in the potential extreme low temperatures of the region. 4.3 Wind Power Module Capital Cost Table 4-3 presents a summary of the windfarm capital requirements. Table 4-3 15 MW Wind Power Capital Requirements Wind turbine generators 13,000 Foundations 3,750 ; Towers 3,450 Transformers, transmission 2,450 Balance-of-plant 1,700 Extended 5-yr WTG warrantee = 2,500 Other EPC costs 4,190 Owner’s Costs 2,850 Contingency 4,650 Construction interest 2.060 Total 40,590 An EPC contract is assumed which provides all items not covered by the Owner’s Costs category. Other EPC costs include engineering, site office and logistics, equipment delivery to the site, special tools and equipment, startup and testing, insurance and bonds, and contingency/profit. Shaw: stone & Webster Management Consultants, Inc. 4-8 February 17,208 . ge Ambler Mining District -Mine Power Study % Owners costs include site geotechnical investigations, project planning and procurement, permitting and licenses, project management and oversight, an indoor substation to distribute power to load centers, and spare parts. Delivery of components to the site is assumed to be a summer barge delivery to the end of the navigable portion of the Kobuk River, with subsequent winter transport to the construction site by a cat expedition. A project implementation schedule is provided below. Figure 4-5 Estimated Implementation Schedule Milestone Schedule Months from Start of Permitting 0 12 24 36 48 | Permiting fs | | Design & Procurement - _ | | Sal | | | Fabrication 5 | | Ship to Site + — | | Construction 4 | EE | Commissiorstartup + | od . | | | | i 4.4 Wind Power Module Operating Costs A central power generating control room will be used to supervise the operations of all onsite and nearby power generation and to manage the grid for the mining complex. Therefore no dedicated operating staff unique to the wind modules which are designed for unattended operation. However, for safety, a maintenance staff of one technician, one shift per day, is assumed for each 15 MW wind power module to perform inspections and maintenance work. Also, periodic maintenance, including inspections and lubricant changes are addressed, as well as major overhauls of the wind generators which are recommended after approximately 10 years of operation. . Therefore, the average annual operating cost for each 15 MW wind module is summarized in the following table: Shaw ‘Stone & Webster Management Consultants, inc, 4.9 , February 17, 2008 Ambler Mining District -Mine Power Study ummary of Wind Power Module Operating Costs Sk/yr = $/kW-yr Maintenance labor 211 14.17 Contract labor 32 2.15 Maintenance materials ro} 5.04 Total fixed O&M 318 2137 Operating costs are greater than what would generally be expected for other large wind projects due to the remote and harsh location, and relatively small size. Unscheduled maintenance is based on rebuilds and replacements of components as they wear out where (a) the rate of replacements is governed by a Weibull failure-rate model, (b) replacement/rebuild costs are based on past experience in the wind business, and (c) crane and other vehicle costs are included for use with heavy components. These operating expenses can be expected to increase by nearly 100% after 10 years to include the levelized costs associated with major overhauls of the machines at that time. Periodic (scheduled) maintenance of each wind turbine, if done regularly and properly, is expected to have only a minor impact on the availability of the wind power module. 4.5 Wind Power Module Estimated Power Production Output from each 15 MW wind power module will depend on the exact siting and wind characteristics of the installation. The wind resource map prepared by AEA indicate the potential for excellent wind characteristics. NREL has reviewed available data in the region against the topography of the site and expects excellent siting areas are possible at elevations above 1000 ft adjacent to the mining area. Pending a more detailed review of available wind data and the implementation of a wind monitoring program at the site, we conservatively assume that each wind power module will experience winds with an annual average speed of approximately 14.5 mph (6.5 m/s). In Table 4-5, we have computed an estimated annual energy production. For the analysis we have assumed that the hub-height wind speeds are distributed in accordance with an accepted annual statistical distribution, called a Rayleigh distribution. We then used a published sea-level power curve for the GE Wind Model 1.5s, 1.5-MW WTG that has a diameter of 70.5 m. We chose the smaller WTG diameter (where a 77-m diameter is also available) because we expect that the wind and ice loading at the site would require the smaller diameter. We also assumed that the annual average air density would be slightly greater than that found at sea level for standard conditions at 25 deg. C. Based on the Rayleigh distribution and power curve, we computed an annual gross energy production of 3,596 MWh per year. Then, based on past experience, we made estimates of various loss and efficiency factors that might apply for the proposed region and weather — leading to a gross-to-net energy efficiency ShhaW: stone & Webster Management. Consuttants, Inc. 4-10 February 17,2006 fr Ambler Mining District -Mine Power Study 4 » factor of 0.782. We multiplied the gross energy by this efficiency factor and calculated an annual net energy production from the WTG of 2,813 MWh. This is equivalent to a capacity factor of 0.214. It should be recognized that we have made several conservative assumptions in this analysis. When more study is complete, we may find that the annual energy production may be substantially greater for the following reasons: 1) The hub-height winds in the region may be far greater than we assumed. 2) It may be possible to use a WTG with a larger rotor diameter that does not compromise the life and reliability of the WTG. 3) The estimated efficiency factors may be higher than those indicated in Table 4-5. Production losses from scheduled maintenance and forced outages are expected to be minor. However, one key uncertainty is the manufacturers’ temperature constraint on operations. GE identifies a minimum ambient operating temperature of - 20deg C. Similarly, Vestas identifies a minimum operating temperature of -20 deg C. When on-site, or nearby wind and ambient temperature data are available, we will review the joint probability of the wind availability and temperature to estimate how much energy may be lost from lack of operation in extremely cold conditions (i.e., at less than 20 deg. C). From our past experience, we have found that many cold-weather sites experience relatively low wind speeds during periods of extreme cold temperatures. We are reviewing the basis for this operating constraints with the equipment suppliers as well as options to reduce or eliminate these constraints. Shaw Stone & Webster Management Consultants, Inc. 4-11 February 17, 2008 Ambier Mining District -Mine Power Study a Table 4-5 Preliminary Wind Farm Output Estimate for GE Wind 1.5 MW Wind Turbine ASSUMPTIONS Note: Sasa is Haat Rayie’ = eee] Rated Power/m* (kWim’): [i038 —— wri oq] 7.14% 625.1 || Ce. | a __—_4_____ tial et || a ce PS 1.90%] 1,042.7] 102.6f 103.9f 108,287 | [7 "tras fT a] ——— rast — sr 7 346.6 318,583, pf 8.98%] 786.9 525.6, 532.0] 418,842 | Pf 7.28%] 638.0 T7716 781.1] 498,304 | } tof __ssiv]_ ois ff __joagaf_soaz7] 822.340 [ral set se [| 15060 ——— 108 — a7 252.8 1465.0] 370,126 | pf 1.93%] 169.1 fT 1800.0f"1500.0f 253,602 | .0 [za sre a7 ff 1500 ——— 1500 —— "| 22 0.01% 0.7 1] 1500.0) 1500.0) 992 28 0.00% OST 1600.07 1500.0] 436 | sill ainsi cons nce ce nc nna We ee 0.00% 0, 2 + — he a | ———__ + I DO aS oad pe Typical Site Efficiency Factors (for rough evaluation purpos Note: (1) For air densities other than 1.225 kg/m*3, power curves of variable-pitch machines must be faired in near rated power such that rated power is achieved for wind >= rated wind speed. (2) Weibull Scale Factor, C = VBAR/[Gamma(1+(1/k))] = (approx) 1.11°VBAR, VBAR = Annual avg wind spd ...where Gamma is the Gamma function (see CRC Tables, Burringtons, etc.) Shaw’ Sone & Weoster Management Consuitants, Inc. 4-12 February 17, 208 Ambler Mining District -Mine Power Study at ve 5.0 Hydroelectric Power Generation Options Shaw Stone & Webster conducted an initial evaluation of hydro power potential to support facilities infrastructure and mining operations at the proposed Alaska Gold mine east of Ambler, Alaska. Our initial review focused on the area of the proposed camp and mine area and included rivers and streams in the sector generally bounded by N67°00 to N67°15 and W156°00 to W157°30.. Hydro power potential of important capacity is limited in the area due to wide, flat valley drainage topography which results in large, long dam structures to form potential reservoirs. Stream drainage areas are limited in size and, correspondingly, river flows are not substantial. Two rivers have some hydro power potential: Shungnak River and Kogoluktuk River. These two potential hydro power developments are discussed below. Also, run of river installations at these sites as well as on smaller side drainages in the area are addressed. First, various considerations for identifying and defining hydro power development features and costs are addressed as follows. 5.1 Considerations For Hydroelectric Development Hydrology Average monthly flow data to characterize the area runoff is available from the USGS stream gage No. 15744000, Kobuk River at Ambler, for a period of 13 years (1966-1978). This gage measures flow from a drainage area of 6,570 square miles. Average monthly flows at the Shungnak and Kogoluktuk sites were estimated from prorating Kobuk River flows on the basis of drainage area. Drainage areas for the Shungnak and Kogoluktuk sites are only 200 and 290 square miles, respectively. The limited extent of side drainages in the area is only about 10 square miles each. Reservoir The height of dam and the resulting extent and volume of a potential reservoir is a limiting factor. Because of the wide, flat valley terrain, as dam height increases, reservoir volume increases substantially. If the reservoir is very large, it could take several years to fill the reservoir. Therefore, height of dam and resulting volume of reservoir has been limited to a reservoir that can be filled in 2 to 4 years. Even this time frame is somewhat long, depending on the timing and scheme of the mine development. Full development at the Shungnak and Kogoluktuk sites creates reservoirs that extend upstream into the Ambler Lowland. This may result in significant environmental and wildlife impacts. Therefore, hydro projects of reduced size with reduced height of dam were also considered at each site to avoid having the respective reservoirs extend into the lowland. ShaW store & Webster Management Consuttants, Inc. 5-4 Februay 17,2008 , pr Ambler Mining District -Mine Power Study ® “Dam A concrete-faced rockfill dam is considered for the potential impounding structure. This is consistent with construction methods and material in remote north country. Also, a rockfill structure is appropriate and durable for the significant seismic conditions of this region. The slopes of the dam are 1.7H:1V on the upstream and 1.5H:1V downstream. Power Tunnel A power tunnel is considered in the potential hydro power schemes, extending from an intake at the dam downstream to the powerhouse. This provides full development of potential head and derives a reasonable maximum power output. The cost of a tunnel adds to the capital cost of the project, but a cursory look at relative cost and power derived indicates that the power tunnels have merit. For the purposes of this evaluation, the power tunnels are sized based on flow velocity of 7 feet per second (ft/sec) and assumed to be concrete-lined through their entire length. Tunnels could be buried pipe, which would be the case for smaller conveyance for smaller run of river options. Estimated Annual Energy Our cursory evaluation of annual energy output is based on 1) maintaining the reservoir at or near full level to maximize power output and 2) operating the reservoir through the year to capture all available inflow and avoid spilling water. Generally, this means significant generation through the high flow season and maintaining a full reservoir (June through October), reduced generation and some drawdown of the reservoir in November and December, shutdown of the plant during low inflow into the reservoir (January through April) and full generation in May to drawdown the reservoir sufficiently to capture the large inflow volume in June and have the reservoir refilled. This is just one option of how the reservoir and the project might be operated. Other variations are possible depending on mine needs and seasonal integration of hydro power with other power generation options such as wind or diesel. 5.2. Shungnak River Hydro Full Development The Shungnak dam is located northwest of Shungnak Mountain. The dam location and extent of the full reservoir is shown on Figure 5-1. The normal maximum reservoir level is limited to Elevation 550 (EL 550) for two reasons: At E] 550, it is estimated that filling of the reservoir will take over two years and filling a larger reservoir would take an undesirably longer time. Also, there is a topographic saddle (ridge) at about El] 600 over which higher reservoir levels would pass into the Ambler River drainage unless a saddle dike or dam is built. Such an auxiliary structure is to be avoided for cost considerations. Shaw stone & Webster Management Consultants, Inc. 5-2 Fetruary 17, 2008 Ambler Mining District -Mine Power Study At El 550, the reservoir covers about 13 square miles (8,300 acres) and full reservoir volume is about 428,000 acre-feet (AF). The average annual inflow volume is 100,754 cubic feet per second — days (cfs-days) (about 200,000 AF). This equates to an average flow of 276 cfs. This is a comparative statistic, since inflow is high during summer runoff and quite low during the winter. The concrete faced rockfill dam is 195 feet high and the crest length is estimated to be 800 feet. The dam is at an attractive location of steep, narrow valley topography. The estimated volume of the dam is 1.2 million cubic yards. The power tunnel is 10.5 feet in diameter and extends 11,700 feet downstream from the dam to the powerhouse. Estimated static head gained by transmitting the flow to the downstream powerhouse location is 160 feet. The total estimated net head available for generation is 310 feet. Based on inspection of the monthly average flow data, the assumed hydraulic capacity of the power tunnel and powerhouse is 600 cfs. Based on these values of estimated head and flow, the installed capacity of the Shungnak scheme is 13 MW. The powerhouse arrangement has two units for reliability. During low flow season, one unit can operate while maintenance is performed on the other unit. At high flow periods, both units can operate for maximum project output. Our cursory estimate of average annual energy output is based on 1) maintaining the reservoir at or near full level to maximize power output, 2) operating the reservoir through the year to capture all available inflow and avoid spilling water, as discussed above and 3) an availability of 98 percent. Based on these SAW: stone & Weoste Managernent Consuitants, Inc. 5-3 February 17, 2008 Ambler Mining District -Mine Power Study " i a Considerations, a preliminary estimate of average annual energy from the proposed Shungnak hydro power facility is approximately 51,500 MWH, as presented in Table 5-1. Table 5-1 Performance Estimate for Shungnak Hydro Plant (Full development @ El. 550) Days per Inflow GenQ, Gen vol cfs-days MW MWH month volume cfs out, cfs- cfs-days days Jan 31 1,366 - - 210,492 - - Feb 28 1,054 : : 211,546 = i Mar 31 1,048 - - 212,594 - - Apr 30 1,056 - - 213,650 - - May 31 14,183 660 20,460 207,373 14 10,636 Jun 30 28,219 660 19,800 215,792 14 10,293 Jul 31 14,099 455 14,099 215,800 10 7,329 Aug 31 14,457 466 14,457 215,800 10 7,516 Sep 30 12,411 414 12,411 215,800 9 6,452 Oct 31 8,101 261 8,101 215,800 6 4,211 Nov 30 2,963 190 5,700 213,063 4 2,963 Dec 31 1,797 185 5,735 209,125 4 2,981 Total MWH 52,382 The preliminary order-of-magnitude cost estimate for the Shungnak hydro power development is based on our recent hydro power experience and construction in remote Alaska. The estimated overnight cost is $83.7 million as summarized in Table 5-2 below. Table 5-2 Shungnak Project (Full Development) Capital Cost Dam 12,000 Concrete facing 800 Diversion tunnel 2,600 Cofferdanms 500 Spillway 2,200 Intake 300 Power tunnel 11,700 Hydraulic equipment 3,700 Power house 2,000 Maintenance & electrical equipment 7,700 Access roads, misc. 2,500 Other EPC 24,150 Contingencies 10,523 Owners Costs 2,981 Construction Interest 6.023 Total 89,676 The estimate includes engineering and design, a 1,200-foot long bridge across the reservoir for access from the airstrip to the area of the camp and facilities and owners costs such as permitting, startup and project management. At this early stage, the estimate also includes extensive contingencies to address Shaw store & Wedster Management Constants, Inc. 5-4 February 17, 2008 Ambler Mining District -Mine Power Study cold climate issues, as well as Owner’s costs and construction interest. Representative quantities for construction were assumed based on experience with similar projects. Geology and geotechnical conditions are unknown at this time and are assumed adequate for project development. Adverse geological conditions could negatively impact the cost of project implementation Based on an installed capacity of 13 MW and the project capital requirements defined above, the cost of the Shungnak scheme is about $6,900 per installed kilowatt. A representative implementation schedule for all of the hydro projects is provided as Figure 5-2 below. Figure 5-2 Implementation Schedule | Milestone Schedule Months from Start of Permitting 0 12 24 6 48 60 | Permitting Design & Procurement Fabrication | | | | | | | | | | | | Ship to Site Commission/startup | | Construction | | | Operating and maintenance costs for these facilities is limited to annual inspection and maintenance with occasional repairs. Icing and other factors may require periodic component repair and replacement. No full time operating staff is required as these facilities run unattended, monitored from a remote control room that will be integrated with other mining facility power generation facilities. An annual allowance of $500k is included as fixed O&M. The same allowance is used for the other hydro units described below. 5.3. Shungnak Hydro Limited Development at El. 490 Development of the Shungnak site at E] 490 provides a smaller reservoir that does not extend into the Ambler Lowland. Full reservoir volume is about 99,000 AF. The concrete faced rockfill dam is 135 feet high and the crest length is estimated to be 750 feet. The estimated volume of the dam is 550,000 cubic yards. Shaw stone & Webster Management Consuitants, nc. 55 Februar 17, 2006 Ambler Mining District -Mine Power Study sg 4 The power tunnel remains the same as the larger scheme (10.5 feet diameter, extending 11,700 feet downstream, and design flow of 600 cfs). The total estimated net head available for generation is 253 feet. Based on these values of estimated head and flow, the installed capacity of the Shungnak scheme at El. 490 is 10.6 MW. Our cursory estimate of average annual energy output is based on 1) maintaining the reservoir at or near full level to maximize power output, 2) operating the reservoir through the year to capture all available inflow and avoid spilling water, as discussed above and 3) an availability of 98 percent. Based on these considerations, a preliminary estimate of average annual energy from the proposed Shungnak hydro power facility is approximately 42,000 MWH, as presented in Table 5-3. Table 5-3 Performance Estimate for Shungnak Hydro Plant (Limited development @ El. 490) Days Inflow GenQ, Gen vol cfs-days MW MWH per volume cfs out cfs- month cfs-days days Jan 31 1,366 - - 44652 - - Feb 28 1,054 - - 45706 - - Mar 31 1,048 - - 46754 - - Apr 30 1,056 - - 47810 - - May 31 14,183 660 20,460 41533 tha 8,681 Jun 30 28,219 660 19,800 49952 11.7 8,401 Jul 31 14,099 455 14,099 49900 8 5,982 Aug 31 14,457 466 14,457 49900 8.2 6,134 Sep 30 12,411 414 12,411 49900 7.3 5,266 Oct 31 8,101 261 8,101 49900 46 3,437 Nov 30 2,963 188 5640 47223 3.3 2,393 Dec 31 1,797 185 §,735 43285 3.3 2,433 Total MWH 42,725 The preliminary order-of-magnitude capital requirements for the Shungnak limited hydro development at E]. 490 is about $62 million, based on adjusting the costs shown in Table 5-2 with the same assumptions. Based on an installed capacity of 10.6 MW, the cost of this Shungnak scheme is $5,850 per installed kilowatt. 5.4 Kogoluktuk River Full Hydro Development The Kogoluktuk dam is located southeast of Asbestos Mountain. The dam location and extent of the full teservoir is shown on Figure 5-1. The normal maximum reservoir level is limited to El 400 for two reasons: 1) at El 400, it is estimated that filling of the reservoir will take over four years and filling a larger reservoir would take an undesirably longer time; and 2) there is a topographic saddle (ridge) at about El 495 south of Kollioksak Lake over which higher reservoir levels would pass into the Kollioksak River drainage unless a saddle dike or dam of a mile or more in length is built. Such an auxiliary structure is to be avoided for cost considerations. Shaw: store 8 Webster Management Consultants, nc. 5-6 February 17, 2008 . per Ambier Mining District -Mine Power Study 4 At El 400, the reservoir covers about 32 square miles (20,500 acres) and full reservoir volume is about 1,228,000 acre-feet (AF). The average annual inflow volume is 146,094 cfs-days (about 290,000 AF). This equates to an average flow of 400 cfs. This is a comparative statistic, since inflow is high during summer runoff and quite low during the winter. The concrete faced rockfill dam is 175 feet high and the crest length is estimated to be 3,200 feet. The dam is at a wider valley location than for the Shungnak site. Accordingly, the estimated volume of the dam is significantly larger at about 3.5 million cubic yards. The power tunnel is 12 feet in diameter and extends 12,600 feet downstream from the dam to the powerhouse. Estimated static head gained by transmitting the flow to the downstream powerhouse location is 65 feet. The total estimated net head available for generation is 210 feet. Based on inspection of the monthly average flow data, the assumed hydraulic capacity of the power tunnel and powerhouse is 800 cfs. Based on these values of estimated head and flow, the installed capacity of the Kogoluktuk scheme is 11.7 MW. The powerhouse arrangement has two units for reliability. During low flow season, one unit can operate while maintenance is performed on the other unit. At high flow periods, both units can operate for maximum project output. Our cursory estimate of average annual energy output is based on 1) maintaining the reservoir at or near full level to maximize power output, 2) operating the reservoir through the year to capture all available inflow and avoid spilling water, as discussed above and 3) an availability of 98 percent. Based on these considerations, a preliminary estimate of average annual energy from the proposed Kogoluktuk hydro power facility is approximately 50,500 MWH, as presented in Table 5-4. Shaw’ stone & Weoster Managernen: Consutants, inc. 5-7 February 17,2008 Ambler Mining District -Mine Power Study Table 5-4 Performance Estimate for Kogoluktuk Hydro Plant (Full development @ E! 400) Days Inflow Gen Q, Gen vol cfs-days MW MWH per volume cfs out, cfs- month cfs-days days Jan 31 1,981 - - 606,596 - - Feb 28 1,529 - - 608,125 - - Mar 31 1,520 - - 609,645 - : Apr 30 1,531 - - 611,176 - - May 31 20,565 880 27,280 604,460 13 9,607 Jun 30 40,918 880 26,400 618,978 13 9,297 Jul 31 20,443 659 20,443 619,000 10 7,199 Aug 31 20,963 676 20,963 619,000 10 7,382 Sep 30 17,996 600 17,996 619,000 9 6,337 Oct 31 11,746 379 11,746 619,000 6 4,136 Nov 30 4,297 350 10,500 612,797 5 3,698 Dec 31 2,605 348 10,788 604,614 5 3.799 Total MWH 51,456 The preliminary order-of-magnitude cost estimate for the Kogoluktuk hydro power development is based on our recent hydro power experience and construction in remote Alaska. The estimated overnight cost is $148 million as summarized in Table 5-5. The estimate includes engineering and design and owners costs such as permitting, startup and project management. At this early stage, the estimate also includes 15 percent for indeterminates, a 5 percent process contingency (to address cold climate issues) and a 10 percent project contingency. Geology and geotechnical conditions are unknown at this time and are assumed adequate for project development. We understand that naturally occurring asbestos is found in the area of Asbestos Mountain. The impact of asbestos on project development and project costs is not known at this time and not included in the cost estimate. In general, adverse geological conditions could negatively impact the cost of project development. Shaw’ stone & Webster Management Consuttants, Inc. 5-8 February 17, 2008 Ambier Mining District -Mine Power Study po Table 5-5 Kogoluktuk Project (Full Development) Capital Cost Dam 35,000 Concrete facing 2,560 Diversion tunnel 3,700 Cofferdanms 600 Spillway 2,800 Intake 300 Power tunnel 16,400 Hydraulic equipment 5,000 Power house 3,200 Maintenance & electrical equipment 11,600 Access roads, misc. 1,200 Other EPC 43,200 Contingencies 18,900 Owners Costs 3,200 Construction Interest 10.600 Total 158,200 Based on an installed capacity of 11.7 MW and the project cost defined above, the capital requirements for the full scale Kogoluktuk scheme are about $13,500 per installed kilowatt. An allowance of $500k/year for fixed O&M would add about $42.7/kW-yr. 5.5 Kogoluktuk- Limited development at El. 315 Limited development of the Kogoluktuk site at El 315 provides a smaller reservoir that does not extend into the Amber Lowland. Full reservoir volume is about 40,000 acre-feet (AF). The concrete faced rockfill dam is 90 feet high and the crest length is estimated to be 1,800 feet. The estimated volume of the dam is 610,000 cubic yards. The power tunnel remains the same as the larger scheme (12 feet diameter, extending 12,600 feet downstream, and design flow of 800 cfs). The total estimated net head available for generation is 125 feet. Based on these values of estimated head and flow, the installed capacity of the Kogoluktuk scheme at El. 315 is 7 MW. Our cursory estimate of average annual energy output is based on 1) maintaining the reservoir at or near full level to maximize power output, 2) operating the reservoir through the year to capture all available inflow and avoid spilling water, as discussed above and 3) an availability of 98 percent. Based on these A Shaw Stone & Weoster Managemem: Consuttarts, inc. 5-9 February 17, 2006 , le Ambler Mining District -Mine Power Study 4 considerations, a preliminary estimate of average annual energy from the proposed Kogoluktuk hydro power facility is approximately 30,000 MWH, as presented in Table 5-6. Table 5-6 Performance Estimate for Kogoluktuk Hydro Plant (Limited development @ El 315) Days Inflow Gen Q, Gen vol cfs-days MW MWH per volume cfs out, cfs- month cfs-days days Jan 31 1,981 - - 7,796 - - Feb 28 1,529 - : 9,325 - : Mar 31 1,520 - - 10,845 - - Apr 30 1,531 - - 12,376 - - May 31 20,565 880 27,280 5,660 7.7 5,718 Jun 30 40,918 880 26,400 20,178 7.7 5,534 Jul 34 20,443 659 20,443 20,200 5.8 4,285 Aug 31 20,963 676 20,963 20,200 5.9 4,394 Sep 30 17,996 600 17,996 20,200 §.2 3,772 Oct 31 11,746 379 11,746 20,200 3.3 2,462 Nov 30 4,297 350 10,500 13,997 3.1 2,201 Dec 31 2,605 348 10,788 5,814 3.0 2,261 Total MWH 30,629 The preliminary order-of-magnitude capital requirements for the limited Kogoluktuk hydro development at El. 315 is $80 million using the same assumptions as for the full development case. Based on an installed capacity of 7 MW, the cost of this limited Kogoluktuk scheme is about $11,400 per installed kilowatt. Using an allowance of $500k/year for fixed O&M, this would add $71.4/kW-yr. 5.6 Run of River Hydro Sites Run of river hydro sites develop hydro power via diversion / intake schemes without constructing a dam of significant size. There is no reservoir with useful volume to regulate varying streamflow conditions through the changing seasons of the year. Water is available for generation as it flows in the stream and arrives at the intake, thus power generation is limited to “run of river” operation. At any given time, water not diverted into the intake is spilled or otherwise lost for generation. Furthermore, without a dam and the resulting higher headwater levels, available head for generation is limited and resulting power output is reduced for a run of river scheme. SHAW stone & Weoster Management Consutants, Inc. 5-10 February 17, 2008 pe Ambler Mining District -Mine Power Study i Po? GAs, a : ) 3 " of - River Hydro Sites |, Wy | Run of river developments are possible at both the Shungnak and Kogoluktuk sites. These schemes include the same power tunnel and powerhouse location as for other larger schemes discussed above. Shungnak run of river scheme has available head of 138 feet and an installed capacity of 5,800 kW. Kogoluktuk run of river scheme has available head of 57 feet and an installed capacity of 3,200 kW. Run of river installations on smaller side drainages in the area were also evaluated. These schemes include an intake and pressure pipe delivering water to a downstream powerhouse to develop available head. Sites on Cosmos Creek, Ryan Creek, Dahl Creek, Kollioksak Lake, and Ruby Creek were considered. The available output from each of these schemes is very limited (1 MW or less) because each of these drainage areas is small (about 10 to 12 square miles) and correspondingly available streamflow is very limited. Initial parameters of potential run of river schemes are comparatively summarized below in Table 5-7. Shaw’ siore & Webster Management Consuitants, ne 5-11 February 17, 2008 Ambler Mining District -Mine Power Study \feO Table 5-7 Comparative Summary of Run of River Hydro Sites Site Drainage Installed Hydraulic Estimated net Est annual area,sqmi capacity, kW _ capacity, cfs head, ft energy, MWH Shungnak River 200 5,800 600 138 19,900 Kogoluktuk River (1) 290 3,200 800 57 12,000 Comos Creek 13 1,000 50 293 2,900 Ryan Creek (1) 17 600 45 200 1,800 Dahl Creek (1) 9 500 35 222 1,500 Kollioksak Lake (2) 10 400 40 145 1,300 Ruby Creek 5 200 20 133 500 (1) Located at Asbestos Mountain area. (2) Powerhouse is about 15 miles from camp area. Capital and operating costs for these installations will be much higher on a $/kW basis than for the larger hydro power applications at Shungnak and Kogoluktuk, and the costs become much more sensitive to project development and permitting costs and the risks of completion. These projects could be evaluated further if higher cost options become appropriate. 5.7. Summary Of Hydro Opportunities In the area of the proposed mine, there are two potential hydro power sites, one each on the Shungnak and Kogoluktuk Rivers. Full development and reduced development to avoid impounding water in the Ambler Lowland are considered at each site. Initial parameters for the schemes are summarized in Table 5.8. Because of the relatively small drainage areas of these sites, estimated river flows are limited and corresponding potential hydro power capacity is also limited. SAW store & Weoster Management Consultants, nc. 5-12 February 17, 2006 _ Ambler Mining District -Mine Power Study oe Table 5-8 Comparative Summary of Kogoluktuk and Shungnak Sites FULL DEVELOPMENT REDUCED DEVELOPMENT Kogoluktuk Shungnak Kogoluktuk Shungnak Reservoir full WL, ft 400 550 a5) 490 Installed capacity, MW 11.7 13 7 10.6 PH tailwater level, ft 165 200 165 200 Assumed head loss, ft 25 40 25 37 Assumed net head, ft 210 310 125 253 Drainage area, sq mi 290 200 290 200 Avg annual inflow volume, cfs-days 146,094 100,754 146,094 100,754 Avg annual flow, cfs 400 276 400 276 PH hydraulic capacity, cfs 800 600 800 600 Dam type Concrete faced Concrete Concrete faced Concrete faced faced rockfill rockfill rockfill rockfill Dam height at max section, ft 175 195 90 135 Dam crest length, ft 3200 800 1800 750 Dam volume, cy 3,500,000 1,200,000 610,000 550,000 Power tunnel length, ft 12,600 11,700 12,600 11,700 Power tunnel diameter, ft 12 10.5 12 10.5 Bridge across reservoir, L, ft wa 1200 na wa Reservoir full surface area, sq mi 32 13 Reservoir full volume, AF 1,228,000 428,000 40,000 99,000 Time for filling of reservoir, yrs 4.2 21 0.1 0.5 Avg annual energy, MWH 51,500 52,400 30,600 42,700 Cost per installed kW, $/kW 13,500 6,900 11,400 5,850 Of the two sites, the Shungnak scheme appears more attractive and potentially at a cost level that might be more viable for remote Alaska. Mainly because of the larger dam structure, the Kogoluktuk scheme appears more costly. Also, higher costs are included for the longer power tunnel as well as turbine and hydraulic equipment passing larger flow at a lower head. Shaw: store & Weoste- Management Consuttants, inc. 5-13 February 17,2008 ; Ambler Mining District -Mine Power Study 6.0 Reliability and Dispatch Considerations Based on our experience with the design and operation of power supply systems for other remote mining operations, it is clear that power supply and delivery requirements must satisfy not only projected energy and capacity requirements, but also rigorous reliability requirements. Reliability and security of power supply are important given the potential for loss of revenue and damage to major equipment that could result from supply interruptions and system instability and blackouts. The dynamics of coordinating mining loads with onsite and remote generation form a significant challenge that can threaten the security and reliability of power supply. Major mining loads are likely to include electric shovels, conveyor systems, grinding mills and residential/commercial loads supporting the personnel near the mine. A distribution system and control center will be provided to coordinate the operation of a number of generating units with a variety of loads, most likely dominated by several large electric motors some of which are operated intermittently. Special consideration must be given to the operation of several generators in way that maintains the stability and security of the distribution grid as major loads come on and off line. Instabilities resulting from sudden loss or increase of load could result in blackouts resulting in costly lost mine production. The dynamic requirements of the system must therefore be considered alongside the capacity and energy requirements in evaluating generation and transmission options. 6.1 Flexibility and Potential for Future Growth The options identified will provide Nova Gold with the flexibility to consider groupings of generating options and transmission options, which in combination will serve a range of loads to serve various levels of development of mining and support facilities. The potential need for staged development and future addition of generating capacity to support expansion of mining operations should also be considered in sizing initial capability of any initial capital intensive investments. 6.2 Expected System Dispatch Based on the operation of other mining facilities, the proposed mining facility will require a mix of peaking, intermediate and base load generation. If long transmission lines to remote generation plants, or resource limited wind and hydro generation are installed, then standby capacity will be needed to provide full system capacity when renewable resources are not available or transmission lines are damaged from storms or other causes. One alternative is to consider load shedding or selective dispatch of loads to match the availability of renewable resources. It may be possible to oversize the capacity of certain mining equipment and stockpile material to reduce reliance on oil-based diesel generation. Shaw Stone & Webster Management Consultants, inc. 6-1 : February 17, 2008 Ambler Mining District -Mine Power Study ~~ ————— 7.6 Overview of Environmental and Permitting Requirements This section provides an overview of the environmental and permitting requirements likely to be encountered based on the proposed power generation options. Common pre-construction, construction and operational requirements for the proposed power sources are addressed. Since the development of the power sources is integral to the overall project, any environmental review must consider all proposed mining operations as well as any proposed fuel-powered generator plant, hydroelectric, and wind power facilities, including associated access routes or power transmission lines. Should secondary power distribution occur to nearby communities, this is likely subject to inclusion in environmental reviews and/or permitting. The information included is based on examples of similar development projects in Alaska. 7.1 Permit Acquisition Process The project permitting process should generally include the following documentation. © formal permit applications ¢ written approvals or agreements © — letters of non objection © permissions * consistency reviews e materials sales contracts © property or right-of-way acquisitions All project permits and authorizations are subject to the project’s proposed engineering design details and work schedules. In turn, final project planning will be subject to permit criteria. Permit development will be integral throughout the project’s development of comprehensive environmental compliance documentation. 7.2 NEPA Compliance Since the project is likely to require area development of public lands and pose the potential for environmental impacts, compliance with the National Environmental Policy Act (NEPA) [42 U.S.C. 4321 et seq.] will be necessary. This federal mandate applies when a federal permit must be issued that authorizes activities with the potential for environmental impactslikely . Another potential criteria for NEPA action would be any potential partial federal funding for any part of the mine development, including power sources. For example, NEPA applies if funding is provided by the U.S. Department of Agriculture, Division of Rural Utilities. SHAW stone & Webster Management Consuitants, Inc 7-2 February 17, 2008 Ambier Mining District -Mine Power Study ; ion with Key Stakeholders The extent of the documentation required under NEPA must be determined by soliciting any and all interested parties potentially affected by the project. These could include: ¢ Legally-mandated federal and state regulatory and natural resource agencies with project area jurisdiction ¢ Local community governments, such as the city offices of Ambler, Shungnak, Kobuk, etc. ¢ Regional borough government - departments of the Northwest Arctic Borough ¢ Non-governmental organizations (NGOs): © Native Village Councils or Traditional Councils © Regional Native Corporation - Northwest Arctic Native Association (NANA) Corporation o Regional development groups - Northwest Arctic Economic Development Commission co Regional native housing authority - Northwest Inupiat Housing Authority co Electric utilities - Alaska Village Electric Cooperative (AVEC), Kobuk Valley Electric Cooperative © Private landowners © Individual citizens Considering the project components described in this report, the potential impacts would likely require an Environmental Impact Statement (EIS) to address the potential environmental effects. The basic EIS process includes, in order: ¢ Identify lead federal agency responsible to prepare EIS (EPA, BLM, etc.). e Lead federal agency publishes in the Federal Register the Notice of Intent (NOI) to prepare an EIS. ¢ Scoping Process: Agency, stakeholder meetings, identify significant issues, define EIS Purpose and Need, identify alternatives and impacts with agencies and public. e Analysis: Draft EIS, develop alternatives, define impacts. e Issue the Notice of Availability and publish the Draft EIS (45-day review period). ¢ Comment Period: Public hearing(s). ¢ Issue the Notice of Availability and publish the Final EIS (30-day review period). e Incorporate comments. e Lead agency issues the ROD (Record of Decision). ¢ Implementation of project with possible appeal period. ShaW store & Webster Management Consuitarts, Inc. 7-3 February 17, 2008 , &- Ambler Mining District -Mine Power Study ¥ 74 Landowner Coordination A key to permitting will be identifying potentially affected property owners. Land ownership in the proposed operations, power generation and mining areas involves numerous parties. The principle landowners include the Bureau of Land Management (BLM), State of Alaska, Alaska Native Claims Settlement Act- (ANCSA-) patented, or interim conveyed property owners (SOA, 2005). Additional minority owners or lease holders must be identified. With the high probability that barging of fuel for operations is required along the Kobuk River, additional coordination may be required as transport will be conducted through federal parkland (Kobuk Valley National Park, Selawik National Wildlife Refuge). Separate access agreements or applications may be required in the case of native corporations or tribal property. 7.5 Key Agencies Under NEPA, a designated lead federal agency will manage the open public scoping process and preparation of the EIS. This is designed to insure that all significant issues and reasonable alternatives are addressed in the EIS. The lead agency must identify any other agency that may ultimately be involved in the project’s proposed action, including any subsequent permitting [48 FR 34264] actions. The lead agency is typically the primary agency with jurisdiction over general land uses in the project area. The Federal Energy Regulatory Commission (FERC) will be involved regarding the significant hydroelectric facilities proposed (greater than 5 MW). FERC has exclusive authority to license most nonfederal hydropower projects located on navigable waterways or federal lands. FERC’s integrated licensing process may be implemented to streamline the project’s permitting schedule. It has yet to be determined the extent to which the Regulatory Commission of Alaska would be involved. As recent mining development projects indicate, close coordination is likely between the lead federal agency and the State of Alaska Department of Natural Resources, Large Mine Permitting Group. This collaboration has expedited communications between the various agencies and streamlined permitting timelines. 7.6 Potential Permit Requirements Table 7-1 below includes a summary of the currently common major permits that may be applicable for pre-construction, construction and operations for mining development projects. Without further design detail, this list is not inclusive of any number of additional major, minor or general permits, agreements, notifications, or licenses that may be required. In addition, it is premature to anticipate which federal agency may be the lead in any permitting effort. However, the list reflects the substantial nature of the permitting effort that would need funding and resources. It is typical for the developer to use a consultant as an agent to assist in coordination of applications and develop any support documentation. As project planning and design develops, it is recommended that a SAW’ stone & Webster Management Consultants, inc. 7-4 February 17, 2008 rus 1 Ambler Mining District -Mine Power Study ermitting Plan be formulated. Due to the complexity of the project, a large number of authorizations are anticipated. The plan should form a clear, concise approach for initiating, tracking, and completing the permit applications and any associated support documents. The plan should reflect up-to-date discussions with involved agency staff and be organized to include the following: ¢ identification of critical stakeholders and authorities © — specific permit requirements and agency acquisition steps * necessary environmental studies and plans anticipated to support permits * permitting schedule (including support studies and plans) e Application tracking system ¢ Cost estimate (including agency filing fees, science or engineering support for applications, agency staff assistance, etc.) Table 7-1 List of Major Permits Authority Agency Document Requirement Federal Clean Water Act EPA National Pollutant Discharge Completed when discharge of wastewater or fill (CWA), 33 USC 1342, Elimination System (NPDES) Water materials into designated waters of the U.S., Section 402 Discharge Permit coordinated with ADEC CWA 33 USC 1344, Discharge of Dredge or Fill Materials Coordinated with USACE and ADEC Section 404 into Waters of the U.S. (including wetlands) CWA and Stormwater Discharge Permits Coordinated with ADEC, includes construction 40 CFR 122 and operation activities, Stormwater Pollution Prevention Plan (SWPPP) required 40 CFR 112 Spill Prevention, Control, and T Applies to below and above ground oil storage Countermeasure (SPCC) Plan facilities, coordinated with ADEC 18 AAC 78 Resource Conservation Hazardous Waste Facility Permit | Coordinated with ADEC (18 AAC 63) and Recovery Act (RCRA) 40 CFR 270 Federal Power Act Federal Energy Hydropower Project License ‘New project license, integrated with NEPA, (FPA) Regulatory Application includes USFWS consultation L Commission (FERC) Federal Aviation Act Federal Aviation Notice of Landing Area Proposal Construct or activate an airport (takeoff or FAR Part 157 Agency (FAA) landing areas), fixed wing or helicopter operations CWA Section 404 U.S. Army Corps of | Discharge of Dredge or Fill Materials Nationwide and/or Individual Permits 404 33 CFR 323 Engineers (USACE) into Waters of the U.S. (including project application triggers ADEC water quality wetlands) Teview Rivers and Harbors impoundment (Dam or Dike) Permit Any impoundment spanning a navigable water Act, 33 USC 403, Section 10 and 33 CFR 321 33 CFR 322 Permits for Structures or Work in or Any work or structure placed in a navigable Affecting Navigable Waters of the water of the U.S. below ordinary high water United States {| mark Rivers and Harbors U.S. Coast Guard Construction Permit for a Bridge Temporary or permanent structure Act (Section 9), (USCG) Across Navigable Waters, General Bridge Act impoundment Permit Threatened and U.S. National Consultation/Correspondence i Support information required for Shaw stone & Webster Managernent Consutants, Inc. 75 February 17, 2008 A i> Ambier Mining District -Mine Power Study Authority Agency Document Requirement Endangered Species Oceanic and correspondence Act, Section 7 Atmospheric Magnuson-Stevens Administration, Essential Fish Habitat (EHF) Potential EFH Assessment Fishery Conservation National Marine Consultation/Correspondence | and Protection Act, 50 | Fisheries Service CFR 600 (NMFS) 49 CFR 100-150 US. Department of | Hazardous Materials Registration iT Applies to any hazardous construction or Transportation Number operations related materials (USDOT) Fish and Wildlife U.S. Fish and Consultation/Correspondence: 7 Support information required for Coordination Act Wildlife Service Threatened and Endangered Species correspondence (USFWS) Act, Section 7 | nal Consultation/Correspondence: Bald Support information required for Eagle Protection Act correspondence r Consultation/Correspondence: Particularly applies to wind meteorological data Migratory Bird Protection Act tower or turbine siting State of Alaska | L Alaska Department of Environmental Conservation (ADEC) CWA Section 401 Division of Water Certificate of Reasonable Assurance Coordinated by USACE with ADEC, review ACMP AS 46.40 Quality “401 Certificate” begins with Sections 402 and 404 applications, 18 AAC 401 review concurrent with ACMP review Stormwater Discharge Permit "| Coordinated with EPA, ADEC reviews the Storm Water Discharge Pollution Prevention Plans required by EPA | Wastewater Disposal Permit (also Coordinated with 401 Certificate process, called General Non-Domestic includes discharge of wastewater into or upon ‘Wastewater Disposal Permit) all state waters and land surface, if injection wells are part of the Wastewater Disposal Plan, then the requirements of EPA’s Underground Injection Control Class V Wells must be met for this permit Construction Dewatering Permit Coordinated with 401 Certificate process, plan Teview required ‘Approval to Construct and Operate a ‘Coordinated with 401 Certificate process, plan Public Water Supply System review required Construction Approval Non-Domestic Part of an application for a state Wastewater Wastewater Treatment System Disposal Permit and an NPDES Permit. ADEC would review an NPDES application for adequacy under its Section 401 Certificate of Reasonable Assurance authority. ADEC must Teview and approve treatment facility plans 18 AAC 50 Division of Air Air Quality Control Permit to Construct | Title V air quality review for power plant | Quality Air Quality Control Permit to Operate permit is based on the source location, total | emissions, and changes in emissions for sources specified in 18 AAC 50.300 and Ambient Air Quality Standards of 18 AAC 50.020(a) Air Quality Permit to Open Bum Applies to open burning of cleared vegetation or L non-commercial timber 18 AAC 75 Division of Spill Oil Discharge Prevention and Tequired prior to commencement of operation of Prevention and Contingency Plan (C-Plan) Approval vessels and oil barges on state waters, or for oil Response terminal facilities capable of storing 10,000 barrels or more, coordinated with EPA Spill Prevention countermeasures and Contingency (SPCC) Plan Review Approval r 7-6 February 17, 2008 Ambler Mining District -Mine Power Study é Agency | Document Requirement 18 AAC 31 Division of Food Sanitation Permit Includes construction camps 18 AAC 60 Environmental Health | Solid Waste Disposal Permits | General or site specific permit options Alaska Department of Natural Resources (ADNR) Division of Mining, ] Mining Plan of Operations "| Includes project description, including utilities Land, and Water and transportation plan and access to power (DMLW) | system site(s) or distribution features Millsite Lease Includes use of lands for millsites or other mining support purposes Land Use Permits - Miscellaneous | Includes construction of winter roads during project development Grant of Right-of-Way Applies to state land crossings by project access Toads, power lines, or pipelines, could include road maintenance agreement with state | TIAAC 93 Certificate or Approval to Construct a Applies to construction, enlargement, alteration, Dam repair (other than routine maintenance), or * abandonment of a dam a | Certificate or Approval to Operate a | Post construction, following completion repart, Dam engineering as-builts, O&M manual Temporary Water Use Permit Temporary use of a “significant” volume of | water for up to 5 years Water Rights Permit - Certificate of Property right for use of public surface and Appropriation _| subsurface waters AS 38.05.020 Material Sale Gravel borrow materials not located within the boundary of the mill site lease or a road ROW; Development Plan, bonding, Reclamation Plan Tequired AS 41.15.050, 060 Bum Permit | Fire control measure for burns outside | incinerator AS 46.40 Alaska Office of Habitat Consistency Review: Northwest Arctic | Includes Coastal Project Questionnaire a | Coastal Management Management and Borough Coastal Management Plan Program Permitting (OHMP) AS 41.14.870 OHMP with Alaska Anadromous Fish Passage Permit ~] Applies to any project activity that may disturb Anadromous Fish Act | Department of Fish anadromous fish habitat, including water and Game (ADF&G) withdrawals 4 AS 41.14.840 Fishway Non-anadromous Fish Passage Permit See above, but specific to relevant non- Act anadromous species ‘National Historic Office of History and | Section 106 Consultation, Cultural Historical and cultural resources protection Preservation Act, Archaeology ~ State Resources Authorizations: Concurrence | consultation, Field Archaeology Permit included Section 106 Historic Preservation Letter (“No Historic Properties if survey work necessary to minimize or Officer (SHPO) Affected”) mitigate impacts, could include mitigation plan(s) | Alaska Department of | Utility Permit on State Right-of-Way | Applies to construction on ADOT managed Transportation & lands or power lines crossing ADOT property | Public Facilities Road Construction Plan Approval Requires engineering design plans and (ADOT&PF) specifications Approval to Transport Hazardous —— or operations related materials Materials | | Life and Fire Safety Plan Check Construction or operations activities Plan Review Certificate of Approval for each Building Including facility support structures ShaW stone & Webster Management Consuttants, Inc. 7-7 February 17, 2008 Ambier Mining District -Mine Power Study 7.7 Permitting Schedule and Costs An 18-month permitting schedule is assumed in evaluating power project implementation timelines. However, this period can be extended to 2-3 years or even longer if there are major objections or challenges to the project. Permitting use of national park lands has resulted in considerable delay and extra effort related to recent hydro projects in Alaska. Allowances are included in the Owner’s costs for each project to cover the expected permitting effort. Actual costs for permitting can vary substantially when permitting efforts for the mining complex and several power generation options are combined into a single permitting plan. Costs can be minimized by coordinating the permitting process, but the range of environmental impacts associated with various power generation options (ie flooding areas for hydro power, location of windfarms, location of transmission facilities, arrangements for transporting heavy equipment to the site by barge and cat trains) could introduce additional permitting risk to the project as a whole and should be considered in evaluating power generation options. Shaw store & Webster Management Consutants, inc. 7-8 Fesruay 17, 2008 Ambler Mining District -Mine Power Study pr 8.0 Economic Comparison of Candidate Power Supply Alternatives Candidate diesel, wind and hydro onsite power generation options have been conceptualized in Sections 3-5. Several more speculative options for power generation are described in Section 2, including the construction of regional generating stations with high voltage transmission to the site. : 81 Economic Evaluation Assumptions and Methodology A levelized cost calculation spreadsheet model was adapted from similar comparisons done for other projects. Key assumptions utilized in this analysis are: e All capital and operating costs are in January, 2006, dollars. ¢ Construction interest at 8% is calculated from the midpoint of construction to the commercial operation date. Capital cost escalation from January, 2006, to the midpoint of construction is not included since commercial operation dates have not been set. ¢ A capital recovery factor of 15% is applied to the total capital requirement to calculate the annual repayment of equity, principal and interest and related charges. e Fuel and O&M cost streams are levelized by escalating them over the economic life (2.5%/yr for O&M; 3%/yr for fuel), determining their present value to January, 2006, and calculating an equivalent level payment using a discount rate of 10%. e Annual output from each plant is considered as an average constant, even though planned maintenance outages may reduce output in some years with higher output in non-outage years. This should not impact the diesel plant since operational spares are included to allow maintenance without affecting output, although operation of spare engines on an opportunity basis could allow additional energy production if required. © No federal tax credits or other incentives are included which, if in effect during implementation of these projects, could reduce the net production costs for some of the designs. 8.2 Economic Comparison of Onsite Power Options Economic analysis of the candidate onsite power options indicate that the hydro and wind options look very promising compared to the baseline diesel plant design. Figure 8-1 shows a comparison of the levelized power generation costs along with supporting assumptions. SShaW store & Webster Management Consutants, inc. 8-1 Fetrumy 17, 2008 Ambler Mining District -Mine Power Study Figure 8-1 Comparison of Levelized Power Generation Costs for Onsite Power Options Levelized Cost C rison 500.0 + ma e ‘e st Comparis: 450.0 400.0 + 10 O&M @ Fuel Cost 350.0 + $/IMWh N a 3S ° 35MW Base 40MWBackup 15 MW Wind 15 MW Wing 13MwW 10.6 MW 11.7MW 7MW Load Diese! Diesel (Arg wind) (High wine) Shungnak Hydro Shungnak Hydro Kogoluktuk Hydro Kogoluktuk Hydro This chart indicates clearly that fuel costs dominate the cost of power from the baseline 35MW diesel option, and an adaptation of that case assuming the diesels run on average at half of their energy output as a backup to other non-reliable (wind and hydro) power generators. The mining facility will have to rely on diesels for partial or complete backup to provide close to 100% reliability in support of continuous mining operations. This may still be true even for a regional power facility with transmission to the plant site, given the vulnerability of extended transmission over rough, remote terrain to extended outages. The capital cost portion of the diesel plant goes up inversely with its utilization. The reliable capacity of the backup diesel plant increases to 40 MW based on the assumption that 8 engines are available when needed with one on standby, with planned outages for maintenance scheduled during periods when hydro power is available. Diesel plant generating costs are highly sensitive to the initial cost of fuel ($5/gal) assumed, as well as the escalation rate (3%/yr) assumed. The wind and hydro options are capital intensive and their cost of power production is more sensitive to the basis for capital cost estimates and the cost of capital (assumed to be 15%/yr). Therefore, Alaska Gold should review their cost of capital carefully in interpreting these results. Additional charts below summarize the relative annual energy production, capital costs, and first year production costs, respectively. Shaw store & Webster Management Consuitants, inc. 82 February 17, 2008 P pS vA Ambler Mining District -Mine Power Study 4 Figure 8-2 Annual Energy Production from Onsite Power Options Annual Energy Production 0.350 0.300 + 0.250 4 0.200 < = = — 0.150 2 & -2. 5 8 0.100 £ & s s 2 as 0.050 0.000 ‘ Ea ; EA _ Ea —_A It is important to note that the windfarm power production is highly sensitive to the siting of the wind turbines and their access to strong, steady winds as illustrated by the average and high wind cases. The limited hydro development designs have lower outputs but lower capital costs. GWhlyr 13 MW Shungnak Hydro 10.6 MW Shungnak Hydro 11.7 MW Kogoluktuk Hydro 7MW Kogoluktuk Hydro SAW store & Weoster Management Consutants, Inc 8-3 February 17, 2008 Ambler Mining District -Mine Power Study Figure 8-3 Capital Cost of Onsite Power Options 160 ;—— a ————— 1) os | Total Capital Cost O Construction Interest, $M | /— 5 | eee aera asta LJ | O Project Contingency $M! @ Owners Cost $M | _| BEPC Cost $M 120 8 PS reer Cee $M (2006) Q Oo 40 : | eA 20 | ¥ fe 35 MW Base 40 MW 15MWWind 15 MWWind 13 MW 10.6 MW 11.7 MW 7MW Load Diese! Backup (Avg wind) = (High wind) Shungnak ‘Shungnak Kogoluktuk Kogoluktuk Diesel Hydro Hydro Hydro Hydro Figure 8-4 First Year Operating Costs of Viable Options 100.0 - 90.0 -+ i ian ed 80.0 0O0&M | a | m Fuel Cost | iH E Capital Charges, 40.0 30.0 i 20.0 10.0 5 - EZ SS MWBase 40 MW Backup 15 MW Wind 15 MW Wind 13 MW 10.6 MW 11.7 MW TMwW Load Diese! Diese! (Aig wing) (High wind) Shungnak Hyoro Shungnak Hyco — Kogoluktuk = Kogoluktuk Hydro yao As shown in this chart, annual cash flows are relatively small for the wind and hydro cases which, in turn produce lower amounts of energy. Shaw Stone & Webster Management Consultants, inc. 8-4 February 17, 2006 , g- Ambler Mining District -Mine Power Study “ Table 7-1 Summary of Onsite Power Generation Options Economic Analysis i] a] GH OE 3 ac a 2 Performance: Net Capacity, MW 35.0 40.0 15.0 15.0 13.0 10.6 11.7 7.0 Net Heat Rate, Btu/kWh 7,200 8,000 Fuel Diese! Diesel Wind Wind Hydro Hydro Hydro Hydro Capacity Factor, % 100% 50% 21% 35% 46% 37% 50% 50% Capital Requi EPC Cost ($k) 42,950 42,950 31,026 31,026 70,150 48,326 125,569 63,579 OWNER'S COST ($k) [1] 25,400 25,400 2,850 2,850 2,981 2,054 3,200 1,620 PROJECT CONTINGENCY 4,300 4,300 4,650 4,650 10,523 7,249 18,900 9,570 ($k) [2] Caan INTEREST 4,600 4,600 2,060 2,060 6,023 4,149 10,600 5,367 (Sk) [4] TOTAL CAPITAL COST (k) 77,250 77,250 40,586 40,586 89,677 61,777 158,269 80,136 EPC Cost ($/kW) 1,227 1,074 2,068 2,068 5,396 4,559 10,732 9,083 Owners Cost (/kW) 726 635 190 190 229 194 274 231 Project Contingency ($/kW) 123 108 310 310 809 684 1,615 1,367 Construction Interest, S/W 131 115 137 137 463 —391 -906 Z67 Total Capital Cost, $/kW 2,207 1,931 2,706 2,706 6,898 5,828 13,527 11,448 Fixed O&M, $/kW-yr (1st yr) 58.3 58.3 214 21.4 38.5 472 42.7 71.4 Variable O&M, $/MWh (1st yr) 0.0044 0.0088 : : - - - Fuel price, S/MMBtu (HHV) (1st 35.70 35.70 - - - - - - yt) Annual Production (GWH) 0.307 0.175 0.028 0.046 0.052 0.035 0.051 0.031 Pi Capital Charges 11.6 11.6 6.1 6.1 13.5 9.3 23.7 12.0 Fuel Cost 78.8 50.0 0.0 0.0 0.0 0.0 0.0 0.0 O&M 2.0 23 o3 o3 Os os O.5 os Total 92.4 64.0 64 6.4 14.0 9.8 24.2 12.5 Levelized Annual Cost, $M Capital Charges 11.6 11.6 6.1 6.1 13.5 9.3 23.7 12.0 Fuel Cost 105.9 67.2 : - - - - : O&M 2.4 2.7 04 04 0.6 0.6 0.6 06 Total Levelized COP 119.8 81.5 6.5 6.5 14.0 9.8 24.3 12.6 li of Production. Capital Cost Recovery 37.8 66.1 216.5 132.4 256.8 266.2 461.3 392.5 Fuel Cost 345.4 383.8 0.0 0.0 0.0 0.0 0.0 0.0 Total Levelized Cost ($/MWh) 390.9 465.3 229.6 140.4 267.8 282.8 472. 411.3 E icA ; Initial Fuel Price ($/MMBtu) 35.70 35.70 Fuel Escalation Rate (%/yr) 3.00% 3.00% 3.00% 3.00% 3.00% 3.00% 3.00% 3.00% O&M Escalation Rate (%/yr) 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% Levelizing Factors: Fuel 1.34 1.34 O&M 1.15 1.16 1.15 1.15 1.15 1.15 1.15 1.15 Economic Life (years) 30 30 30 30 30 30 30 30 Discount Rate 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% 10.00% Levelized Capital Recovery 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% 15.00% Rate 8.3. Economic Comparison of Speculative Power Options Several regional energy projects were compared using the same methodology to determine if the order of magnitude production costs justify further consideration of their more complex implementation requirements. Shaw stone & Webster Management Consutants, Inc. 8-5 » February 17, 2006 , fr- Ambler Mining District -Mine Power Study > Figure 8-5 below summarizes the result of comparing the potential economics of a regional power generation project that would sell power to the Ambler Mine in addition to other loads on the west coast of Alaska. Figure 8-5 Levelized Production Costs for Potential Regional Power Projects 200.0 -— Levelized Cost Comparison - 180.0 } 160.0 140.0 120.0 + 100.0 = 80.0 + 60.0 40.0 - 20.0 0.0 $/MWh Regional 150 MW 121 MW Regional 122 MW Regional 168 MW Nuclear CFB Oil Combined Gas Combined PBMR Cycle Cycle The basis for these calcuilations is presented in Table 8-2. Key assumptions include: Coal, oil or gas can be delivered reliably to a site along the proposed transmission system described in Figure 2-1 in Section 2.3. Plant sizes were selected to obtain economies of scale not available from smaller projects. Give high assumed transmission cost to the site ($250M), these options may be more attractive for expanded development of the Ambler Mine (with onsite ore refining). The coal, oil and gas options could be scaled down to the 100MW level with an increase of 10-20% in the levelized cost of power. The PBMR nuclear unit represents the only size available, which is the smallest commercial nuclear reactor expected to licensable in the US in the time frame associated with development of Amber mine. Unless other PBMR applications are licensed in the US in advance, substantial additional first of a kind engineering and nuclear technology certification costs would need to be addressed in addition to the Owner’s Costs assumed for this study. The coal and nuclear options entail substantially higher permitting risk than gas and oil plant options due to more complex air emission and potential nuclear related issues. The extended transmission line that would be required to connect a regional plant to the Ambler Mine introduces significant availability risk that would likely justify installation of backup diesels for most of the normal plant operating loads. In this event, the diesels would operate on a much more limited (<10%) capacity factor, and it may be cost effective to select lower cost, lower efficiency high speed diesels more suited to backup power applications. For purposes of this study, it is assumed that the capital cost savings of purchasing lower cost high speed diesels will be partially offset by their lower operating efficiency and therefore we have not proceeded with development of different designs and costs. SShaW' stone & Webster Management Consuttants, nc. 8-6 February 17, 2008 Ambler Mining District -Mine Power Study Table 8-2 Economic Evaluation of Speculative Power Options Regional Regional! Regional Nuclear CFB Combined Combined PBMR Cycle (Oil) Cycle (Gas) Performance: Net Capacity, MW 150 121 122 170 Net Heat Rate, Btu/kWh (HHV, ISO) 10,000 7,800 8,000 Fuel coal oil gas 9.6% enr U Capacity Factor, % 86% 93% 93% 94% Capital t Construction Period (months) 38 26 26 36 EPC Cost ($k) 427,024 160,000 150,000 450,000 OWNER'S COST ($k) [1] 40,351 21,000 20,500 58,500 PROJECT CONTINGENCY (Sk) [2] 42,702 16,000 15,000 45,000 TRANSMISSION [S$] [3] 250,000 250,000 250,000 250,000 CONSTRUCTION INTEREST ($k) [4] 77,021 31,000 30,195 77,136 TOTAL CAPITAL COST (k) 837,099 478,000 465,695 880,636 EPC Cost ($/kW) 2,847 1,322 1,230 2,647 Owners Cost ($/kW) 269 174 168 344 Project Contingency ($/kW) 285 132 123 265 Transmission Impact ($/kW) 1,667 2,066 2,049 1,471 Construction Interest, $/kW 513 256 247 454 Total Capital Cost, S/W 5,581 3,950 3,817 5,180 Fixed O&M, $/kKW-yr (1st yr) 60.0 46.0 44.0 120.0 Variable O&M, $/MWh (1st yr) 7.0 45 43 3.0 Fuel price, $/MMBtu (HHV) (1st yr) 3.00 9.00 10.00 Annual Production (GWH) 1.13 0.99 0.99 1.40 irst Year if ion, Capital Charges 125.6 TAT. 69.9 132.1 Fue! Cost 33.9 69.2 79.5 8.0 O&M 16.9 10.0 96 246 Total 176.4 150.9 159.0 164, iz l Mi Capital Charges 125.6 CUE 69.9 132.1 Fuel Cost 45.6 93.0 106.8 10.8 O&M 195 115 441 28.4 Total Levelized COP 190. 176. 187.8 171. i of ion. Capital Cost Recovery 111.1 72.7 70.3 94.4 Fuel Cost 40.3 94.3 107.5 en O&M 17.3 i117 112 20.3 Total Levelized COP 168. 178.8 189.0 122. Economic Assumptions Initial Fuel Price ($/MMBtu) 3.00 9.00 10.00 Fuel Escalation Rate (%/yr) 3.00% 3.00% 3.00% 3.00% O&M Escalation Rate (%/yr) 1.50% 1.50% 1.50% 1.50% Levelizing Factors: Fuel 1.34 1.34 1.34 1.34 O&M 1.15 1.15 1.15 1.16 Construction Cash Flow Midpoint 0.60 0.60 0.60 0.60 Economic Life (years) 30 30 30 30 Discount Rate 10.00% 10.00% 10.00% 10.00% Levelized Capital Recovery Rate 15.00% 15.00% 15.00% 15.00% ShaW stone & Webster Management Consuttants, inc. 8-7 February 17, 2006 wf 4 Ambler Mining District -Mine Power Study Conclusions and Recommendations The findings of this power study are as follows: re Most or all of the power generation capacity for the Ambler Mine project will be served by diesels, at least in the form of backup capacity, to provide near 100% reliability of service to mining loads. This is based on the expectation that production losses due to the unavailability of the power supply system will be much greater than the investment required to provide full reliability. Diesel generation will provide reliable capacity at levelized energy costs (in 2006$) ranging from about $390-470/MWh, depending on their level of utilization. Fuel accounts for $350-380/MWh of this amount and can be cost-effectively be displaced by other power options. Development of one or more 15MW increments of wind power should provide electrical energy to displace diesel fuel at a levelized energy cost of about $150-225/MWh, depending on the magnitude of wind resources that can be utilized at the site. Development of hydro power options can provide seasonal power at $270-411/MWh, depending on the specific opportunities. Additional run-of-river capacity can be developed at higher costs that have not yet been determined. : Development of region power generation projects using coal, oil, gas or nuclear fuels may offer attractive delivered levelized energy cost on the order of $120-190/MWh, or higher if they are scaled down to smaller sizes. Such projects would rely on a transmission line to connect the plant to other loads and to the Ambler mine. The implementation of a central power and major transmission project would be more complex than the development of onsite power, resulting in longer, more expensive and riskier project development effort. Permitting risks would also be higher, potentially leading to delays in completion and heavy fuel penalties if it results in extensive diesel fuel consumption. Based on the assumptions and findings presented above, the following recommendations should be considered: 1. Further evaluation of the wind resource near the site is justified and should be undertaken early to determine whether excellent wind resources exist near the Ambler Mine site. Wind power, even without any subsidies, appears to be the most cost effective onsite power production option to displace the use of diesel fuel. Further evaluation of the hydro power options should be considered to verify major assumptions regarding the available hydrological resource, evaluate additional sites and power options, and resolve key questions regarding the permitting and construction issues likely to be confronted in project implementation. Development of a regional power plant should be considered through further discussion with the Northwest Arctic Borough, the Red Dog Mine, the AEA, AIDEA, AVEC, the Denali Shhaw - stone & Webster Management Consultants, In. 8-8 Februmry 17, 2008 Ambler Mining District -Mine Power Study Commission and others that represent potential stakeholders. Investment in a central power facility and major transmission project will likely compete directly with investment in wind and hydro power options in displacing the use of diesel fuel, so decisions may be required to support commercial commitments needed for a reasonable implementation timeline. 4. The implementation of a major, well-coordinated diesel/hydro/wind power system represents an important accomplishment in establishing reliance on renewable technologies as part of a reliable power minigrid. This is an area of technology development that is of interest to the NREL, AEA, DOE and the international energy community. As a result, we may be able to approach these organizations for grants or cost-shared funding to assist in data collection, implementation planning, optimization and engineering of the proposed power system. 5. The adjacent villages of Kobuk and Shungyak may play an important role in acceptance of the Ambler Mine project as the public hearing process proceeds to support environmental permitting. It will likely be critical to offer those villages interconnections to provide lower cost and more reliable power, jobs, and other benefits. It may be appropriate to submit grant applications in cooperation with these villages to fund some studies to evaluate interconnection options that will make lower cost renewable electric power available. AEA just released such a grant application (#AEA-06-018) dated February 13, 2005, for which responses are due March 13. It may be appropriate to approach both villages and ask if they would like support to prepare and submit grant applications to support a study of interconnections and also local monitoring of wind resources, SAW store & Weoster Management Consuitants, nc. 8-9 Fetruay 17,2006 o Ambler Mining District -Mine Power Study Appendices A dix 1 ~ Diesel generator layout(later dix 2 — Diesel buildi ‘Oss-section (lat SAW" stone 8 Weoster Management Consuttants, inc. 8-1 February 17, 2008 yg Ambler Mining District -Mine Power Study List of References State of Alaska, Alaska Energy Authority (AEA), 2005. Map: Draft Wind Resources — Kobuk (Alaska) Area. May. State of Alaska, Department of Commerce, Community, and Economic Development (DCCED), 2005. Alaska Community Database - Community Information Summaries. Website Data: http:/www.commerce.state.ak.us/dca/commdb/CF_CIS.htm. December. State of Alaska, 2005. Map: General Land Status, Northern Alaska. March. U.S. Department of Commerce, National Climatic Data Center (NCDC), 2005. Table Data: YEAR Average Annual Temperature for Ambler, Alaska. January. U.S. Department of Energy (USDOE), 1986. Wind Energy Resource Atlas of the United States. Prepared by Pacific Northwest Laboratory for the USDOE. October. Staw Stone & Webster Management Consiitants, nc. 8-2 February 17, 2008