HomeMy WebLinkAboutVol5 Appendix F-IDonlin Creek Mine Power
Supply Feasibility Study
Nuvista Light & Power, Co.
301 Calista Ct.
Anchorage, AK 99518-2038
Volume 5
Appendix F-I
Final Report
June 11, 2004
Bettine, LLC 1120 E. Huffman Rd. Pmb 343
Anchorage, AK 99501
907-336-2335
TABLE OF CONTENTS
VOLUME I
SECTION I - EXECUTIVE SUMMARY
SECTION II - INTRODUCTION
SECTION III - POWER SUPPLY ALTERNATIVES
SECTION IV - 138-kV TRANSMISSION LINE & SUBSTATIONS
SECTION V - PRELIMINARY ENVIRONMENTAL PLANNING
SECTION VI- PROJECT COST ESTIMATES
SECTION VII - PROJECT MANAGMENT & SCHEDULING
SECTION VIII - PROJECT FINANCING
SECTION IX - ECONOMIC ANALYSIS OF POWER SUPPLY ALTERNATIVES
GLOSSARY OF TERMS
VOLUME 2
Appendix A - Coal Plant Feasibility Design and Report Prepared by PES
VOLUME 3
Appendix B - Modular Plant Feasibility Design and Report Prepared by PES
VOLUME 4
Appendix C - 138 kV Transmission Line Feasibility Design Information
Appendix D - Electric System Studies Prepared by EPS
Appendix E - Foundation and Fuel Storage Feasibility Design Reports Prepared by
LCMF
VOLUME 5
Appendix F - Preliminary Environmental Assessment Review
Appendix G - Economic Analysis
Appendix H - Miscellaneous Information
Appendix I - Agency and Public Comments
APPENDIX F-I
Appendix F – Preliminary Environmental Assessment Review
1. Transmission Line Review and Report by Travis-Peterson, Inc.
2. Power Plant Review and Report by Steigers Corporation
Appendix G – Economic Analysis
1. Coal-Fired Plants
2. Combustion Turbine Plants – Bethel
3. Combustion Turbine Plant – Crooked Creek
4. Transmission Lines from Rail-belt
Appendix H – Misc.
1. Loss of Load Expectation Calculations
2. Coal Cost Projections
3. Coal Plant Efficiencies and Reliability Information
4. EMF Information
5. Permafrost Information
6. Bethel River Bank Erosion Sketch
Appendix I – Public Comments
APPENDIX F
Appendix F – Preliminary Environmental Assessment Review
1. Transmission Line Review and Report by Travis-Peterson, Inc.
Environmental Planning for the
138 kV Donlin Creek Transmission Line
Prepared for
NUVISTA LIGHT & POWER CO.
301 Calista Court, Suite A
Anchorage, AK 99518
Prepared by
TRAVIS/PETERSON ENVIRONMENTAL CONSULTING, INC.
3305 Arctic Blvd. Suite 102
Anchorage, Alaska 99503
329 2nd Street
Fairbanks, Alaska 99701
Project Number
1117-01
July 2003
Frank J. Bettine, P.E., 1117-01 10/13/2003
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TABLE OF CONTENTS
Page
1.0 INTRODUCTION...................................................................................................1
2.0 AFFECTED ENVIRONMENT...............................................................................1
3.0 ENVIRONMENTAL CONCERNS.........................................................................4
3.1 Land Use Impacts ........................................................................................4
3.2 Wetlands ......................................................................................................7
3.3 Navigable Rivers..........................................................................................8
3.4 Floodplain Management..............................................................................8
3.5 Threatened and Endangered Species ...........................................................8
3.6 Essential Fish Habitat ..................................................................................8
3.7 Anadromous Fish Streams...........................................................................9
3.8 State Lands/State Parks................................................................................9
3.9 Coastal Zone Management ........................................................................10
3.10 Cumulative and Secondary Impacts...........................................................10
3.11 Historic, Architectural, Archaeological, and Cultural Resources..............10
3.12 Construction Impacts.................................................................................11
4.0 FEDERAL PROCESS...........................................................................................11
5.0 COMMENTS FROM AGENCIES, BUSINESSES AND THE PUBLIC.............14
5.1 Federal Agencies........................................................................................14
5.2 State Agencies............................................................................................14
5.3 City and Village.........................................................................................15
5.4 Private Organizations.................................................................................15
6.0 ANTICIPATED PERMITS...................................................................................16
7.0 CONCLUSIONS....................................................................................................18
7.1 Preliminary Research.................................................................................18
7.2 Responses to Letter....................................................................................18
8.0 REFERENCES ......................................................................................................19
LIST OF FIGURES
Figure 1 Region/Vicinity and Proposed Alternative..................................................2
Figure 2 Proposed Power Plant Location...................................................................3
Figure 3 Segment Breakdown of Transmission Line.................................................6
Figure 4 NEPA Decision Making Flowchart...........................................................13
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LIST OF TABLES
Table 1 Breakdown in Segments of the Proposed Route..........................................5
Table 2 Landownership Rights.................................................................................7
Table 3 Potential Permits and Approvals................................................................16
LIST OF APPENDICES
Appendix A Mailing List and Sample Letter
Appendix B Phone Log, Comments from Agencies, Businesses, and the Public
Appendix C Landownership Maps
Appendix D USDA RUS NEPA Policies and Regulations
Appendix E ADNR Application for Easement Right-of-way Permit
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TABLE OF ACRONYMS
ACMP Alaska Coastal Zone Management Program
ADF&G Alaska Department of Fish and Game
ADNR State of Alaska Department of Natural Resources
AVEC Alaska Village Electric Cooperative, Inc
BMPs Best Management Practices
BNC Bethel Native Corporation
BLM United States Bureau of Land Management
CRSA Coastal Regional Service Area
DMLW Division of Mining, Land and Water
EFH Essential Fish Habitat
EIS Environmental Impact Statement
ESCP Erosion Control Plan
FAA Federal Aviation Administration
NEPA National Environmental Policy Act
NMFS National Marine Fisheries Service
NOI Notice of Intent
NPDES National Pollution Discharge Elimination System
NWR National Wildlife Refuge
OHMP Office of Habitat Management and Permitting
OHW Ordinary High Water
OPMP Office of Project Management and Permitting
ROD Record of Decision
ROW Right-of-way
RUS Division of Rural Utilities Service
SHPO State Historic and Preservation Office
SUP Special use permits
SWPPP Storm Water Pollution Prevention Plan
TKC The Kuskokwim Corporation
TPECI Travis/Peterson Environmental Consulting, Inc.
USACE United States Army Corps of Engineers
USDA United States Department of Agriculture
USFWS United States Fish and Wildlife Service
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1.0 INTRODUCTION
Nuvista Light & Power, Co. (Nuvista) initiated a feasibility study to construct a power
plant in Bethel, Alaska and a 138 kV transmission line from Bethel to eight rural
communities along the Kuskokwim River and the proposed Donlin Creek gold mine
project (Figure 1). Nuvista is a non-profit corporation created to serve as a regional
generation and transmission utility for the Calista region. The transmission line will be
located along the northern bank of the Kuskokwim River. The power line will serve
Bethel, Akiachak, Akiak, Tulusak, Lower/Upper Kalskag, Aniak, Chuathbaluk Crooked
Creek and the proposed Donlin Creek gold mine (Figure 1). The proposed power plant
will be located south of the Bethel Airport at approximately 60˚ 46.225 minutes north
latitude and 161˚ 47.320 west longitude (Figure 2).
The goal of this project is to develop an economical source of electrical power for the
Calista region with less environmental impacts. Currently, each village has its own
diesel-powered electric generators and tank farms. Constructing a centralized power
plant located at Bethel and a power grid along the Kuskokwim River would reduce
energy cost in the region and minimize fuel storage at each village.
Nuvista retained the services of Frank J. Bettine, P.E., Esq. as the project consultant. Mr.
Bettine subcontracted with Travis/Peterson Environmental Consulting, Inc. (TPECI) to
develop an environmental overview for the transmission line portion of the feasibility
study.
A letter was sent to environmental agencies, the affected communities, landowners, and
other interest groups to introduce the proposed transmission line and power plant project
and request comments. A copy of the letter and the responses are located in Appendices
A and B. This report summarizes the environmental issues identified by the
environmental agencies and the other interested parties. The report outlines the National
Environmental Policy Act (NEPA) process and time requirements for the proposed
project. Lastly, the report lists the necessary permits required to proceed with the project.
2.0 AFFECTED ENVIRONMENT
Bethel is located along the Kuskokwim River, 40 miles inland from the Bering Sea. It lies
in the Yukon Delta National Wildlife Refuge, 400 air miles west of Anchorage. Bethel
is located in the Bethel Recording District Sec. 09, T08N, R71W, Seward Meridian.
Precipitation averages 16 inches a year in this area with snowfall of 50 inches. Summer
temperatures range from lows of 42˚ to highs of 62˚ F. Winter low and high temperatures
average -2˚ to 19˚ F (ADCED, 2003)
The area varies from a coastal climate near Bethel to a prevailing continental climate at
Crooked Creek the easternmost town. Snowfall averages from about 50 inches at Bethel
to upwards of 85 inches per year at Crooked Creek. Rainfall in the Kuskokwim River
area averages approximately 15 to 20 inches. Temperature variances are greatest in the
areas experiencing continental climate, where they may vary from -59˚ F in the winter up
Frank J. Bettine, P.E., 1117-01 10/13/2003
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to 94˚ F in the summer. High winds are common along the Kuskokwim River in the fall
and winter. The Kuskokwim River is ice-free typically from late-May through October
(ADCED, 2003).
The proposed transmission line would run along the north bank of the Kuskokwim River.
It would provide power to Bethel and eight other communities en route to the Donlin
Creek mine. These communities are Bethel, Akiachak, Akiak, Tulusak, Lower/Upper
Kalskag, Aniak, Chuathbaluk, and Crooked Creek.
Bethel is the largest city along the 191 mile route. The population in Bethel is 5,736, and
the population in the other communities range from slightly under 100 residents to over
600 (ADCED, 2003). Crooked Creek is the last community along the route before the
transmission line diverts north approximately 12 miles to the proposed Donlin Creek
mine.
3.0 ENVIRONMENTAL CONCERNS
Office research and agency comments revealed the following environmental concerns.
3.1 LAND USE IMPACTS
The feasibility study has identified an alternative that is approximately 190.5 miles in
length. Except for a one mile section of the United States Bureau of Land Management
(BLM) land and 6.4 miles of State lands, the route traverses private lands that have either
been conveyed to the various native corporations or have been selected for conveyance.
The design team intentionally routed the transmission line through private lands to avoid
crossing Yukon Delta National Wildlife Refuge (NWR) lands and, to the maximum
extent possible, state and other federal lands.
The proposed project may affect five groups of land owners. These are regional
corporations, village corporations, state, federal, and native allotments (Appendix C).
The majority of the lands over which the transmission line will be built are owned by
private landowners and village corporations. The Kuskokwim Corporation (TKC) owns
the majority of the land along the proposed route. The proposed transmission route will
also cross native allotments. Two federal groups own land along the proposed route.
The BLM manages federal lands and the United States Fish and Wildlife Service
(USFWS) manages the Yukon Delta NWR. Michael B. Reardon, Refuge Manager,
should be contacted with questions regarding land status and ROW permitting in the
refuge (USFWS, 2003a) Secondary transmission lines feeding power to the
communities would cross native village corporation and the city lands.
No permanent roads will be maintained on the transmission line right-of-way (ROW).
The transmission line will require a ROW width of 40 to 50 feet within the Bethel City
limits and a 125-foot width for the remainder of the line. Once the transmission line is in
operation, the power line will be maintained using a combination of helicopters, boats
and tracked vehicles.
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Landownership consists of surface rights and subsurface rights. This project will affect
mainly the surface estate, but some subsurface lands will be affected due to required
material sources. Table 1 displays a breakdown of the transmission line and the
ownership rights within each segment of the affected lands. Figure 3 displays a map of
the individual segments of the proposed transmission line.
TABLE 1
BREAKDOWN IN SEGMENTS OF THE PROPOSED ROUTE
Segment
Length
(miles)
Accumulated
Length (miles)
Minimum
Elevation (ft)
Maximum
Elevation (ft)
Land Ownership
Comments
A-B 6 6 24 66 City of Bethel;
BNC; Private
Parcels; Native
Allotments
Power Plant 138 kV Step-
up Substation at Mile 0.0
B-C 15.9 21.9 13 61 BNC; Akiachak Akiachak Substation at
Mile 19.7
C-D 16.0 37.9 19 48 Akiachak;
Kokarmiut;
Tuluksarmute
Akiak Substation at Mile
26.2
D-E 16.6 56.5 39 61 Tuluksarmute Tuluksak Substation
Mile 43.4
E-F 15.6 70.1 39 59 Tuluksarmute;
TKC & 4.2 mi.
TKC Selected
F-G 15.5 85.6 36 73 TKC & 2.8 mi.
TKC Selected
Kalskag Substation at
Mile 85.6
G-H 15.3 100.1 59 415 TKC; 11 Native
Allotments
H-I 16.1 117 83 477 TKC; 10 Native
Allotments
Aniak Substation at Mile
110.6
I-J 15.8 132.8 87 497 TKC & 1 mi.
TKC Selected; 6
Native
Allotments
Chuathbaluk Substation at
Mile 123.4
J-K 13.3 146.1 103 700 TKC & 3.4 mi
TKC Selected; 5
Native
Allotments
K-L 14.4 160.5 124 717 1 mile BLM;
4.2 miles State;
TKC
L-M 17.0 177.5 161 556 2.1 miles State;
TKC; 2 Native
Allotments
M-N 13.7 191.2 140 947 TKC; 1 Native
Allotment
Crooked Creek Substation
at Mile 177.8; Donlin
Creek Mine Substation at
Mile 191.2
The following are responses from landowners located within the proposed transmission
route. The USFWS indicated that any lands in a NWR that have been selected but not
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conveyed to a native corporation are managed as any other refuge lands under their
jurisdiction. The development on those lands will require a ROW permit. The USFWS
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stated that a review of the alternatives along with their impacts is necessary to assure that
the use of the refuge land is compatible with the mandated purposes of the Yukon Delta
NWR. Only the alternative that meets the mandated purposes of the NWR system and
would not adversely impact the refuge values would be permitted (USFWS, 2003a). The
State of Alaska Department of Natural Resources (ADNR) Division of Mining, Land and
Water (DMLW) indicated that an ROW permit would be required to cross state owned
lands and any RS 2477 trails (ADNR DMLW, 2003a). The Bethel Native Corporation
(BNC) explains that landownership is complicated around the City of Bethel. They
explain that there are many private allotments, city owned land, BNC owned land, and
Calista owns the subsurface rights (BNC, 2003). Table 2 breaks down the surface and
subsurface landownership rights.
TABLE 2
LANDOWNERSHIP RIGHTS
Owner
Surface Rights Subsurface Rights Explanation
Calista Regional Corporation Yes Yes Own Both Rights
Village Corporations Yes No Calista Owns Subsurface
Rights
City Lands Yes No Calista Owns Subsurface
Rights
Native Allotments Yes No Calista Owns Subsurface
Rights
USFWS Yes Yes Owns Both Rights
State Lands Yes Yes Owns Both Rights
BLM Yes Yes Owns Both Rights
3.2 WETLANDS
The proposed transmission line will parallel the north bank of the Kuskokwim River
between Bethel and Crooked Creek. There are many small streams entering the
Kuskokwim River from the north. There are swamps, bogs, sloughs and other wetlands
in the area.
Wetland mapping has not been completed along the project corridor. Therefore, wetland
areas will need to be delineated and mapped. All fill material placed on wetlands will
require a permit from the United States Army Corps of Engineers (USACE) (USACE,
2003). This includes temporary fills for access roads, boat ramps, and temporary bridges.
Most of the impacted wetlands should have negligible or minimal impacts to their overall
functions because the overhead lines and support structures will require minimal fill.
Mitigation and minimization measures need to be discussed in the permit application.
Comments from the USACE are documented in their correspondence located in
Appendix B.
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3.3 NAVIGABLE RIVERS
The Kuskokwim River is considered a navigable river. Two other major navigable
rivers, the Gweek and Owhat Rivers, will be crossed by the transmission line. Many
other small creeks will be crossed that may be classified as navigable. Section 10 of the
Rivers and Harbors Act requires a permit for any structures placed within or work
performed below the high water mark of a navigable river (USACE, 2003). It is
anticipated that all rivers and creeks will be spanned.
3.4 FLOODPLAIN MANAGEMENT
The power plant and transmission lines will be located within the Kuskokwim River’s
floodplain. Neither the transmission line nor its support towers will restrict flow. Ice
flows are common within the Kuskokwim River floodplain. Support towers vulnerable
to ice flows and flood events will be engineered to withstand these events.
3.5 THREATENED AND ENDANGERED SPECIES
According to the USFWS, there are no threatened or endangered species of plants or
animals found to occur within the project area. Three different sources were consulted to
make the determination. TPECI consulted Mr. Greg Balogh and Mr. Michael Jimmy of
the Yukon Delta NWR (USFWS, 2003b) and (USFWS, 2003c). The USFWS (USFWS,
2003d) and National Marine Fisheries Service (NMFS) (NMFS, 2003a) internet website
was used to confirm that there are no threatened or endangered species within the project
area. Jeanne Hanson (NMFS) indicated that NMFS did not expect any threatened or
endangered species under their jurisdiction (NMFS, 2003a).
3.6 ESSENTIAL FISH HABITAT
NMFS considers the Kuskokwim River as Essential Fish Habitat (EFH) under the
Magnuson-Stevens Act. Many creeks and rivers located draining into the Kuskokwim
River also appear to have EFH. According to the NMFS web pages, the following
essential fish species may inhabit these streams: chinook salmon, coho salmon, sockeye
salmon, chum salmon, and pink salmon. Over-water work will be necessary to complete
the free-span transmission line. Over-water work does not require a permit from NMFS
or the Alaska Department of Fish and Game (ADF&G).
An EFH assessment will need to be performed to determine what EFH will be impacted
and what minimization and mitigation measures will be performed to offset the impacts.
The construction of temporary ramps, river access points, small bridges, and river
crossings will need EFH assessments to be performed. Once the EFH assessment is
complete, the Lead Agency for the NEPA document will send it to NMFS for review.
The review process can take up to 60 days to complete. If NMFS agrees with the results
and the mitigation they will concur with the assessment enabling the construction effort
to proceed. Mitigation may be necessary (NMFS, 2003a).
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3.7 ANADROMOUS FISH STREAMS
A search of the ADF&G “An Atlas to the Catalog of Waters Important to the Spawning,
Rearing or Migration of Anadromous Fishes (AWC)” (ADF&G, 2003a) found that the
Kuskokwim River is a cataloged anadromous fish stream (335-10-16600). The
Kuskokwim River supports sheefish, whitefish and spawning whitefish, chinook salmon,
sockeye salmon, coho salmon, chum salmon, and pink salmon. There are other
anadromous fish streams in the area but the ADF&G has not catalogued the streams
located to the north side of the Kuskokwim River. This does not mean that there are no
anadromous fish streams to the north. Mr. Wayne Dolezal (ADF&G) informed us that
ADF&G is in the process of cataloguing the streams to the north (ADF&G, 2002b). The
work will not be completed by ADF&G because this responsibility has been taken over
by the ADNR Office of Habitat Management and Permitting (OHMP). There are no set
dates for completion of this task.
Any anadromous fish streams that may be impacted within the project area will be
reported to ADNR OHMP for approval. ADNR OHMP indicated that they need to know
the following information for any work conducted below the Ordinary High Water
(OHW) mark.
• Location of the stream;
• Stream crossing methods;
• Type of work occurring in the stream;
• Type of transmission lines and supports structures;
• Fish species present or utilizing each stream;
• Geomorphic characteristics at each site;
• Habitat characteristics at each site; and
• Methods, locations, and permanency of access to the transmission line during and
after construction.
If ADNR concurs with the results then the project may proceed (ADNR OHMP, 2003b).
3.8 STATE LANDS/STATE PARKS
The ADNR Division of Parks and Outdoor Recreation website and the ADF&G State of
Alaska Refuges, Critical Habitat Areas, and Sanctuaries Database (ADF&G, 2003c) were
consulted to determine that there are no state parks, refuges, sanctuaries, or critical
habitat areas in the area. Mr. John Zimmerly, Park Ranger, with the Alaska State Parks
Service confirmed via phone that there are no Alaska State Parks in the subject area
(ADNR, 2003d). The response from ADNR DMLW indicated that some of the work will
be performed on state lands (ADNR DMLW, 2003e). Appendix C shows the state-
owned lands along the project area.
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3.9 COASTAL ZONE MANAGEMENT
A review of the “Coastal Zone Boundaries” atlas found that the proposed project area is
within the Coastal Zone Management Area (ADNR ACMP, 2003f). The project affects
two Coastal Zone Management Areas; the City of Bethel Coastal Management District,
and the Cenaliulriit Coastal Regional Service Area (CRSA).
A Coastal Project Questionnaire (CPQ) will need to be completed and sent to the ADNR,
Office of Project Management and Permitting (OPMP) for review. The OPMP helps
determine the federal permitting requirements for the project. The OPMP will make the
determination that the project design is consistent or not consistent with the Alaska
Coastal Zone Management Program (ACMP).
3.10 CUMULATIVE AND SECONDARY IMPACTS
The USACE and the USFWS stated that they are very concerned about cumulative and
secondary impacts (USACE, 2003 & USFWS, 2003a). These agencies have suggested
that any environmental analysis and permitting may need to consider the transmission
line, the power plant, Crooked Creek airport expansion, mine access road, and Donlin
Creek gold mine as the complete project.
The proposed power plant and transmission line would supply the power necessary to
operate the Donlin Creek Mine. Donlin Creek Mine will consume over 70 percent of the
electrical power transmitted along the new power grid. Donlin Creek Mine would utilize
Crooked Creek’s airport to supply fuel, cargo, and passengers. The airport will need to
be expanded to accommodate large cargo aircraft. A new road would be built to link
Donlin Creek Mine with the airport. The close proximity of the mine to the village
would generate business within Crooked Creek. Operation of the mine will increase
supplies and the number of travelers through Crooked Creek.
In the future, the power plant may supply energy for communities away from the primary
corridor. It is possible transmission lines would be built to feed communities to the west
or north of Bethel to provide a cheaper and cleaner source of power for those
communities. The opportunity for cheaper power in some of these other towns could
lead to an increase in population in these areas.
3.11 HISTORIC, ARCHITECTURAL, ARCHAEOLOGICAL, AND
CULTURAL RESOURCES
The State Historic and Preservation Office (SHPO) anticipates that there will be many
areas of cultural significance. Once the final transmission line route is chosen cultural
surveys may be necessary to determine areas of cultural significance (SHPO, 2003).
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3.12 CONSTRUCTION IMPACTS
The section of the power line between Bethel and Upper Kalskag traverses marshy
lowlands composed of fine grain sands and silts that are dotted with numerous small
lakes, small streams and sloughs. It is anticipated that this section of the line will be built
during the winter months when the ground is frozen and there is sufficient snow cover to
protect the vegetation. Terrain along the remainder of the proposed route appears
suitable for year-round construction.
Construction of the transmission line will require temporary access points from the
Kuskokwim River. Special use permits (SUPs) and ROW permits will need to be
obtained from the land owners to access and perform construction within the transmission
line ROW. Temporary ramps, roads, supply and housing structures will be needed for
staging the construction effort for this project. Temporary fill may be placed in wetlands
to build ramps and roads for construction of the transmission lines. The fill will be
removed after the construction is complete. No permanent roads will be built for
maintaining the transmission line. The transmission lines will be maintained via off-road
vehicles, boats and helicopters.
Trees and undergrowth will be removed from access points and during construction of
the transmission lines. Temporary impacts to wildlife are expected during the
construction phase of the project. Construction may temporarily disrupt normal wildlife
activities. The impacts could temporarily affect subsistence hunting at communities
where construction occurs. These impacts are not expected to be long term and should
dissipate after the construction phase. Some construction could occur during the winter
months utilizing frozen ground or ice-roads. Winter construction efforts would have
fewer adverse effects on tundra, birds, fish, wetlands, EFH, and erosion.
Water quality impacts may result from the build alternative due to erosion and runoff
from construction areas. The contractor will minimize these impacts by implementing
Best Management Practices (BMPs) for erosion and pollution control in accordance with
the Environmental Protection Agency under the National Pollution Discharge
Elimination System (NPDES) General Permit program for Alaska. A Storm water
Pollution Prevention Plan (SWPPP) and an Erosion Control Plan (ESCP) will be
implemented to minimize water quality impacts during the construction phase.
Construction will generate some solid waste. The waste will be disposed of in nearby
community landfills or removed off-site to Bethel. Construction methods, locations, and
timing concerns are expressed in the agency letters located in Appendix B.
4.0 FEDERAL PROCESS
Since it is anticipated that federal money will be used to finance the electrical system, the
project must comply with the NEPA. It is anticipated that the proposed power plant and
transmission line will be classified as a major federal action that will significantly affect
the human environment. 7 CFR 1794.25 states in relevant part, “An EIS will normally
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be required in connection with proposed actions involving the following types of
facilities: (1) New electric generating facilities of more than 50 MW (nameplate rating)
other than diesel generators or combustion turbines. All new associated facilities and
related electric power lines shall be covered in the EIS …” Therefore, an Environmental
Impact Statement (EIS) must be prepared for the transmission line. Agencies responding
to the feasibility letter agreed that the proposed project will require an EIS. These
agencies also suggested that the Cumulative Impact Section must address the
transmission line, power plant, Donlin Creek Mine, the expansion of Crooked Creek
Airport, and the construction of the new road between the airport and the mine (USFWS,
2003a & USACE, 2003).
A simplified version of the EIS process is as follows:
• Determine the Lead agency for the transmission line and Bethel power plant
project. The RUS would be the lead agency of choice for this project but it has
not agreed to serve as the lead agency ;
• The lead agency submits a Notice of Intent (NOI) to the Federal Register;
• Complete the Scoping Process (Identify significant issues, translate the issues into
the purpose and need for the action, introduce alternatives and non-alternatives,
and introduce the impacts);
• Develop alternatives;
• Prepare a draft EIS;
• Notice of Availability 45 day review period;
• Hold a public hearing;
• Incorporate comments;
• Finalize EIS and circulate the final document for 30 days; and
• RUS issues a Record of Decision (ROD).
A copy of the USDA RUS NEPA policies and regulations are attached in Appendix D.
TPECI estimates the entire environmental process to take approximately 2.5 years to
complete assuming there are no significant obstacles encountered during the EIS process.
Figure 4 displays a simplified version of the NEPA process that federally funded projects
must follow.
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FIGURE 4
NEPA DECISION MAKING FLOWCHART
Determine
Lead Agency
Lead Agency
Concurs that an
EIS is Required
Scoping
Final
EIS
ROD
Implement Decision
Draft
EIS
Public and
Agency Review
NOI in
Federal
Register
Develop
Alternatives
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5.0 COMMENTS FROM AGENCIES, BUSINESSES, AND THE PUBLIC
TPECI and Frank J. Bettine, P.E., developed a letter and graphics describing the project
and mailed the letter to federal, state, local government agencies, cities, and native
corporations. The interested groups were allowed to comment on the project. These
comments are summarized below. The letters containing the comments, questions, and
concerns are located in Appendix B.
5.1 FEDERAL AGENCIES
Three federal agencies replied to the letter. They were the NMFS, the USACE, and the
USFWS (Appendix B).
Ms. Jeanne L. Hanson, NMFS Field Office Supervisor for Habitat Conservation Division,
pointed out that she did not expect the project to affect any Threatened or Endangered
Species under their jurisdiction but the project could lead to adverse affects of EFH. An
EFH assessment is required (NMFS, 2003a).
Two of the agencies, the USACE and the USFWS stated that the project needs to
evaluate alternate transmission routes and their impacts. The EIS must include the
proposed power plant, Donlin Creek Mine, and infrastructure associated with the Donlin
Creek mine project (USACE, 2003 & USFWS, 2003a). The USACE specified if the
power plant and transmission line were economically feasible without the mine then they
might consider the project separate from the mine project (USACE, 2003). The two
agencies also stated that they needed to evaluate the alternate routes and their
environmental impacts to determine which alternative has the least adverse
environmental impacts. Both agencies also listed permits required under their
jurisdiction. The USACE permits are the Section 404 Wetland Fill Permit and the
Section 10 Navigable Rivers Permit. These two permits can be combined and applied for
as a Section 404/10 Permit. Assuming the power line is routed across lands that have
been selected by a village corporation for conveyance, but have not yet been conveyed, a
USFWS National Wildlife Refuge ROW permit will also be needed.
5.2 STATE AGENCIES
Three divisions of the ADNR replied to the letter describing the proposed project. The
SHPO believes an archaeological survey will be necessary for this project. The DMLW
acknowledged that the project will require ROW permitting to conduct work on or access
state lands for the proposed project. They also mailed a permit application describing the
specific information required for their permit review process (ADNR DMLW, 2003e). A
copy of the permit application is included in Appendix E. The OHMP’s concerns involve
work that will be conducted in and around streams. The OHMP indicated that Fish
Habitat Permits will most likely be required depending on line and equipment crossings
methods and locations. They indicated that any work below the OHW mark will require
these permits. The specific information required for a fish habitat permit is outlined in
Frank J. Bettine, P.E., 1117-01 10/13/2003
Bethel Transmission Line Page 16
the letter from the OHMP (ADNR OHMP, 2003b). The letters from the agencies are
located in Appendix B.
The Alaska Department of Environmental Conservation (ADEC) did not have any
comments pertaining to the letter. However, ADEC permitting will be necessary for
completion of the project. Permitting will be required during construction of the project
and for operating the power plant. The necessary ADEC permits can be found in Table 3.
5.3 CITY AND VILLAGE
A wide array of comments and questions were in the responses from the village
corporations and the City of Kwethluk. The mayor of the City of Kwethluk expressed his
gratitude for the information (Kwethluk, 2003). The mayor desires to comment on the
project after the details are outlined in the EIS. Three village corporations and one city
responded to the letter. The corporations were the BNC, Kwethluk Incorporated, and
Akiachak Limited. The City of Kwethluk was the only city to respond to the letter.
The village corporations expressed their acceptance for an environmentally friendly and
economic source of electricity for their region. Their main environmental concerns
pertained to land use restrictions, subsistence hunting, and wildlife. The village
corporations also expressed a desire to review alternate routes and the possibility of an
underground transmission line (Kwethluk Incorporated, 2003, Akiachak, 2003 & BNC,
2003). The City of Kwethluk and most of the village corporations also expressed their
gratitude for being considered in the early development of the project.
BNC’s main concern involved land status impacts. BNC explained that landownership
around Bethel is complicated due to the number of landowners (city-owned, corporation,
and private). BNC was also concerned about the future location of the power plant
because they heard second-hand that one proposed location was on their lands (BNC,
2003).
BNC has several environmental concerns pertaining to the proposed project. Their main
concern involves health issues associated with a coal-fueled power plant. They also
specified their preference for an alternate location of the power plant and transmission
line farther away from the city of Bethel and away from the Kuskokwim River (BNC,
2003). The letters are located in Appendix B.
5.4 PRIVATE ORGANIZATIONS
The Alaska Village Electric Cooperative, Inc (AVEC) is the current electricity provider
for the area. AVEC had very specific questions relating to power line and power plant
specifications, tower configuration, conductor size, transformers (AVEC, 2003).
AVEC’s response is located in Appendix B.
Frank J. Bettine, P.E., 1117-01 10/13/2003
Bethel Transmission Line Page 17
6.0 ANTICIPATED PERMITS
Project permits will require detailed design information. Project specifics, alternatives,
and work time frames will need to be completed according to permit specifications. It
will be helpful to prepare a Coastal Project Questionnaire first to coordinate permit
submittals.
The project is currently undergoing a feasibility study. Nuvista anticipates the feasibility
study will be completed by January 2004. The EIS and location engineering for the 138
kV transmission line are scheduled to begin during the onset of 2004 and would not be
completed until the middle of 2006. Detailed engineering will begin in mid-to-late 2004
and would continue into 2006. The project team anticipates completing the
environmental work and engineering by the end of 2006. The project team anticipates
acquiring all permits by the end of 2007. Construction of the selected power supply
alternative and the Bethel to Donlin Creek mine 138 kV transmission line is currently
scheduled for 2008-2010. The system is scheduled for full operation by late spring 2010.
Table 3 summarizes the potential permits required for this project and the regulatory
agencies that approve them.
TABLE 3
POTENTIAL PERMITS AND APPROVALS
Agency Name Type of
Permit/Approval
Reason for Permit/Approval
Federal Agencies
Dept. of Agriculture, RUS Location Approval. Lead Agency approves the NEPA document.
Section 404 A Section 404 permit is required for authorization of
wetland fills.
U.S. Army Corps of
Engineers
Section 10 A section 10 Permit is required for any work
performed in a navigable river below the OHW mark
or for any structures placed within a navigable river
Endangered Species Protection of endangered and threatened species U. S. Fish and Wildlife
Service Refuge Crossing Permit Any transmission lines across wildlife refuges require
approval.
U. S. National Marine and
Fisheries Service
Essential Fish Habitat
Assessment
Minimize impacts to fish habitats.
State Agencies
ADEC Wastewater
General
A general permit is for similar situations with standard
conditions, such as excavation dewatering, floating
and non-permanent shore-based camps. The permit
tells what limits must be met, what measures must be
taken, which types of discharges are covered by it
Alaska Department of
Environmental
Conservation
Food Service A permit must be obtained for permanent, temporary,
limited or mobile food service operations serving 11
or more persons per day must. (May apply to
construction camp)
Frank J. Bettine, P.E., 1117-01 10/13/2003
Bethel Transmission Line Page 18
CONTINUED
Certificate of
Reasonable Assurance
(401 Certificate)
ADEC must issue a 401 Certificate to accompany any
federal permit issued under the Federal Clean Water
Act. For example, a COE Section 404 permit would
trigger the need for a state certificate.
Title V Air Quality for
power plant
ADEC must issue an air quality control permit to
construct and operate a power plant.
Alaska Department of
Natural Resources,
OHMP.
In Cooperation with
Alaska Department of
Fish & Game
(Title AS 41.14.870)
“Anadromous Fish
Passage”
Or
(Title AS 41.14.840)
“Fish Passage”
A General Waterway/Water body Application must be
submitted if heavy equipment usage or construction
activities disturb fish habitat and anadromous fish
habitats. These permits also stipulate how stream
water withdrawals may be conducted.
Or
The above information dealing with only non-
anadromous fish passage.
Alaska Department of
Natural Resources,
OPMP
Coastal Project
Questionnaire
A project application that is filled out to help
determine what state and federal permitting is
necessary to proceed with a project located within the
Coastal Zone Management Area.
Temporary Water Use This permit is required if water withdrawals will occur
during construction. The permit lasts for the length of
a temporary project.
Alaska Department of
Natural Resources,
DMLW
Materials Sale &
Mining Plan
Purchase of required materials from state lands.
Land Use A land use permit is required for use of state lands
along the proposed ROW.
Alaska Department of
Natural Resources,
DMLW ROW A ROW is required for construction of transmission
lines or other improvements that cross state lands.
Alaska Department of
Natural Resources, SHPO
Cultural Resource
Concurrence Section
106 Review
For any federally permitted, licensed, or funded
project, the SHPO must concur that cultural resources
would not be adversely impacted, or that proper
methods would be used to minimize or mitigate
impacts that would take place.
Alaska Department of
Transportation and Public
Facilities
Utility Permit on State
ROW
Required before construction on DOT&PF managed
state lands or for structures crossing DOT&PF ROWs.
City of Bethel
Planning Department Building Permission is required to build transmission lines
across City land.
Calista Corporation
Land Department ROW Administrative approval for crossing Calista Lands.
Village Approvals
Akiachak, Akiak, Tulusak,
Lower/Upper Kalskag,
Aniak, Chuathbaluk, and
Crooked Creek
ROW and Easements Village corporations and councils issue permission for
utility crossings of village lands.
Private Individuals ROW and Easements Permission is required to build transmission lines
across private lands unless ROW is secured eminent
domain process.
Frank J. Bettine, P.E., 1117-01 10/13/2003
Bethel Transmission Line Page 19
7.0 CONCLUSIONS
Preliminary research was performed by contacting agencies, researching publications and
internet web sites, and reviewing comments. The following summarizes information
collected for the project.
7.1 PRELIMINARY RESEARCH
Preliminary research concluded the following environmental consequences pertaining to
the proposed power plant and transmission lines:
• Review of the ADF&G publication “State of Alaska Refuges, Critical Habitat Areas,
and Sanctuaries” found that there are no State Refuges, Critical Habitat Areas, or
Sanctuaries in the project vicinity;
• The ADNR Division of Parks and Outdoor Recreation “Individual State Park Units in
Alaska” was reviewed and it was found that there are no State Parks in the proposed
project vicinity. There are state appropriated lands along the proposed alignment;
• Review of the “Coastal Zone Boundaries” atlas found that the proposed project area
is within the Coastal Management Area. The project affects two Coastal Zones; the
City of Bethel Coastal Management District, and the Cenaliulriit CRSA. A CPQ will
need to be filled out and submitted to the OPMP;
• Research through NMFS and USF&WS revealed that there are no threatened or
endangered species existing in the vicinity of the proposed project area. TPECI also
contacted two USF&WS representatives to confirm;
• The Kuskokwim River is considered EFH. Several creeks and rivers draining into the
Kuskokwim River also appear to have EFH. According to the NMFS & the
USF&WS web pages, the following essential fish species may inhabit these streams:
chinook salmon, coho salmon, sockeye salmon, chum salmon, and pink salmon. At
this stage of design, it has been determined that over-water work will be necessary to
complete the transmission line. The construction of temporary ramps, river access
points, small bridges, and river crossings will need EFH assessments to be performed;
• A search of the ADF&G “An Atlas to the Catalog of Waters Important to the
Spawning, Rearing or Migration of Anadromous Fishes (AWC)” found that the
Kuskokwim River is a cataloged anadromous fish stream (335-10-16600). There are
other anadromous fish streams in the area but the ADF&G have not catalogued the
streams located to the north side of the Kuskokwim River. The Kuskokwim River
supports sheefish, whitefish and spawning whitefish, chinook salmon, sockeye
salmon, coho salmon, chum salmon, and pink salmon; and
• Research of the USF&WS web site indicates that approximately 7 miles of the
preliminary power line routing would cross lands, within the Yukon Delta NWR, that
have been selected by TKC but have yet to be conveyed.
7.2 RESPONSES TO LETTER
Letters received from agencies, cities, villages and from AVEC raised several general
issues. General comments regarding these issues are as follows:
Frank J. Bettine, P.E., 1117-01 10/13/2003
Bethel Transmission Line Page 20
• Construction of the transmission line may require an EIS that evaluates the proposed
transmission line, power plant, Donlin Creek Mine and access road, and the Crooked
Creek runway extension project;
• The EIS will also require a discussion of alternate routes and associated impacts;
• Construction of the proposed power plant may require purchasing or leasing lands
owned by the BNC and private individuals;
• Construction of the proposed transmission lines will require ROWs across native
lands, private lands, state and federal lands; and
• The transmission line will require many different permits for its completion (Table 3).
The project alternatives and their specifics need to be determined after the feasibility
report is completed. Each specific alternative will need to be outlined explaining a
detailed route, landownership, environmental impacts, mitigation and minimization
techniques, time schedules, and reasoning behind the Proposed Action.
8.0 REFERENCES
ADCED, 2003. Alaska Department of Community and Economic Development,
Community Database, Database available at http://www.dced.state.ak.us May 2003.
ADF&G, 2003a. Alaska Department of Fish and Game, Publications Database,
Anadromous Waters Catalog and Atlas, Database available at
http://www.habitat.adfg.state.ak.us/geninfo/anadcat/anadcat.shtml May 2003.
ADF&G, 2003b. Alaska Department of Fish and Game, Mr. Wayne Dolezal, personal
communication, February 12, 2003.
ADF&G, 2003c. Alaska Department of Fish and Game, State of Alaska Refuges, Critical
Habitat Areas, and Sanctuaries Database, Database available at
http://www.state.ak.us/adfg/adfghome.htm May 2003.
ADNR DMLW, 2003a. State of Alaska Department of Natural Resources, Division of
Mining, Land and Water, Ms. Mary Jane Sutliff, letter, April 15, 2003.
ADNR OHMP, 2003b. State of Alaska Department of Natural Resources, Office of
Habitat Management and Permitting, Mr. Edward Weiss and Ms. Robin Willis, letter,
May 21, 2003.
ADNR State Parks, 2003c. State of Alaska Department of Natural Resources, State Parks
Database, Database available at http://www.dnr.state.ak.us/parks/units/index.htm May,
2003.
ADNR, 2003d. State of Alaska Department of Natural Resources, Division of Parks and
Outdoor Recreation, Mr. John Zimmerly, phone conversation, March 11, 2003.
Frank J. Bettine, P.E., 1117-01 10/13/2003
Bethel Transmission Line Page 21
ADNR DMLW, 2003e. State of Alaska Department of Natural Resources, Division of
Mining, Land and Water, Ms. Mary Jane Sutliff, letter, May 8, 2003.
ADNR ACMP, 2003f. State of Alaska Department of Natural Resources, Alaska Coastal
Management Program Database, Database available at
http://www.gov.state.ak.us/dgc/Explore/Tournw.htm May 2003.
Akiachak Limited, Mr. Willie Kasayulie, letter, April 25, 2003.
AVEC, 2003. Alaska Village Electric Cooperative, Inc., Ms. Meera Kohler, letter, April
21, 2003.
BNC, 2003. The Bethel Native Corporation, Mr. Marc D. Stemp, letter, April 21, 2003.
Kwethluk, 2003. City of Kwethluk, Mr. Boris L. Epchook, letter, April 8, 2003.
Kwethluk Incorporated, 2003. Mr. George Guy, letter, April 30, 2003.
NMFS, 2003a. National Marine Fisheries Service, Ms. Jeanne Hanson, e-mail, April 15,
2003.
NMFS, 2003b. National Marine Fisheries Service, Endangered and Threatened Species
Database, Database available at http://www.fakr.noaa.gov/protectedresources/default.htm
May, 2003.
SHPO, 2003. State of Alaska Department of Natural Resources, State Historical
Preservation Office, Ms. Julie Raymond-Yakoubian, e-mail, April 10, 2003.
USACE, 2003. Department of Army, United States Army Corps of Engineers, Ms. Mary
Leykom, letter, April 28, 2003.
USFWS, 2003a. United States Fish and Wildlife Service, Ms. Ann G. Rappoport, letter,
May 7, 2003.
USFWS, 2003b. United States Fish and Wildlife Service, Yukon Delta National Wildlife
Refuge, Mr. Greg Balogh, phone conversation, June 17, 2003.
USFWS, 2003c. United States Fish and Wildlife Service, Yukon Delta National Wildlife
Refuge, Mr. Michael Jimmy, phone conversation, March 17, 2003.
USFWS, 2003d. United States Fish and Wildlife Service, Endangered Species Database,
Database available at http://www.r7.fws.gov/es/te.cfm May 2003.
APPENDIX A
MAaING LIST AND SAMPLE LETTER
712/2003
Pagel
Frank J. Bettine, P.E., 1117-01
Bethel Power Plant & Tranani~aOD Line
April 3, 2003
Re: Bethel Transmission Line
Project Number: 1117-01
Subject: Bethel Power Plant &
Transmission Line
<Title> <First Name> <Last Name>
<lob Title>
<Company>
<Address>
<City> <State> <Zip Code>
Dear <Title> <Last Name>
Nuvista Light & Power, Co., (Nuvista) initiated a feasibility study to construct a 138 kV
transmission line from Bethel, Alaska to the proposed Donlin Creek gold mine project,
located north of Crooked Creek. Nuvista is a non-profit corporation recently formed by
Calista Corporation to serve as a regional generation and transmission utility. The
transmission line would be located along the northern bank of the Kuskokwim River. The
power line would provide electricity to the proposed Donlin Creek mine project and the
community of Bethel, and in due course the villages of Akiachak, Akiak, Tulusak,
Lower/Upper Kalskag, Aniak, Chuathbaluk, and Crooked Creek. The goal of this project
is to develop a more economical and environmentally friendly long-term source of
electrical power for the Calista region as well as to provide power to the Donlin Creek
mine project. Nuvista retained the services of Frank J. Bettine, P.E., Esq. as the project
consultant. Mr. Bettine subcontracted with Travis/Peterson Environmental Consulting,
Inc. (TPECI) to develop an environmental overview and determine the land ownership
status.
Early identification of environmental concerns associated with 138 kV transmission line
will facilitate efficient project development. To ensure that all possible factors are
considered in the design of the proposed project, Nuvista is requesting agency and public
comments and recommendations. Your agency's input at this time is important to this
project.
Location and Description
Bethel is located at the mouth of the Kuskokwim River, 40 miles inland from the Bering
Sea, and 400 air miles west of Anchorage. It lies at approximately 60.792220 North
Latitude and 161.755830 West Longitude (Sec. 09, T008N, R071W, Seward Meridian.)
(DCED, 2002) (Figure 1).
Donlin Creek Mine, the final destination of the 138 kV transmission line, is located
approximately 12 miles north of Crooked Creek. Neither Bethel nor the other
communities along the transmission route are connected via a road system. Crooked
7M311:l9AM
7/2/2003
Page2
Frank J. Bettine, P.E., 1117-01
Bethel Power Plant &; Transmission Line
Creek lies on the north bank of the Kuskokwim River within the Kilbuk-Kuskokwim
Mountains, 141 miles northeast of Bethel and 275 miles west of Anchorage. It lies at
approximately 62.012050° North Latitude and 158.197033° West Longitude. (Sec. 32,
T021N, R048W, Seward Meridian) (Figure 1).
Calista Corporation and its associated village corporations own the majority of the lands
along the proposed 138 kV transmission line corridor. A number of private native
allotments would be affected by the transmission line.
Proposed Project
The length of the 138 kV transmission line between Bethel and the Donlin Creek mine
will be approximately 191 miles. (Figurel). The transmission line will require a right-of-
way width of 40-50 feet within the Bethel City limits and a 125-foot width for the
remainder of the line. Construction of the transmission line between Bethel and Donlin
Creek will require temporary points of access from the Kuskokwim River. Power to
supply the community of Bethel, the villages along the power line route and the 70
megawatts of power required by the Donlin Creek gold mine project will come from a
large power plant built in Bethel. The proposed site of the power plant and the beginning
point of the 138 kV transmission line is located south of Bethel, at the approximate
coordinates N60. 770417°, WI61.788667°.
ProjKt Schedule
The project is currently undergoing a feasibility study. Nuvista anticipates the feasibility
study will be completed in November, 2003. The Environmental Impact Statement (EIS)
and location engineering are scheduled to begin during the onset of 2004 and would not
be completed until March, 2006. Detailed engineering will begin in mid-to-late 2004 and
would continue into 2006. The project team anticipates completing the environmental
work and engineering by the end of 2006. Construction of the selected power supply
alternative and the Bethel to Donlin Creek mine 138 kV transmission line is currently
scheduled for 2008-2010. The system is scheduled for full operation by late spring 2010.
What We Want from You
Over the next 30 days. we would like to get your comments and concerns involving only
the 138 kV transmission line. Comments and concerns regarding the proposed power
plant at Bethel will be solicited at a later date. Your concerns will be reviewed to help
identify new possibilities. issues, and permit requirements. All questions and comments
are important.
For More Information
If you have any questions regarding the project, please contact Michael Travis at (907)
522-4337 or Frank J. Bettine, P.E., Esq, at (907) 336-2335.
"'JO'\ 11:19AM
7fl/2OO3
Page 3
Frank J. Bettine. P.E., 1117-01
Bethel Power Plant &; Trnnsmission Line
Sincerely,
Michael Travis. P .E.
President
3305 Arctic Boulevard, Suite #102
Anchorage, Alaska 99503
Enclosed Figure 1 - Location and Vicinity Map, Transmission Route
7M31l:JtAM
APPENDIX B
PHONE LOG, COMMENTS FROM AGENCIES, BUSINESSES,
AND THE PUBLIC
n
MEETING LOG
DATE: February 12,2003
TIME: Afternoon
IN A'n'ENDENCE: Mr. Bill Anklewich (TPECI) and Mr. Wayne Dolezal (ADF&G)
SUBJECT: Anadromous Fish Stream Catalog
Mr. Bill Anklewich of Travis/Peterson Environmental Consulting (TPECI )went to the
Alaska Department of Fish and Game (ADF&G) Habitat Division to view the
anadromous fish stream catalogs. TPECI spoke briefly with Mr. Wayne Dolezal about
catalogued fish streams. Mr. Dolezal stated that none of the streams of the northern bank
on the Kuskowim River have been catalogued yet. He informed Mr. Anklewich that this
did not mean that they are not anadromous fish streams, only that they haven't had the
time to catalog them yet. He told me that they would not be finished with cataloguing
them until 2007 or later. He informed Mr. Anklewich that for now they all go by the
Kuskokwim River catalog number.
TELEPHONE LOG
DATE: March 11, 2003
TIME: Unknown
FROM: John Zimmerly; ADNR, State Parks and Recreation
TO: Michael Travis in place of Bill AnkIewich; Travis/Peterson Environmental
Consulting, Inc.
SUBJECT: State parks in the Proposed Bethel Kuskokwim Transmission Line Area
Ranger John Zimmerly (sp.) left a message with Mr. Travis that there are no state parks
in the subject area. The ADNR web site was also consulted and it confirmed this.
TELEPHONE LOG
DATE: March 12, 2003
TIME: Unknown
FROM: Mike Coleman of Federal Energy Regulatory Commission (FERC) (202) 502-
8236 He returned my phone Call
TO: Bill Anklewich ofTravis/Peterson Environmental Consulting. Inc (TPECI)
SUBJECT: Looking for Lead Agency for Bethel Transmission Line Project
Mr. Coleman phoned me in response to a message I left on his phone pertaining to being
the lead agency for the project. He informed me that they were not going to be the lead
agency because it was not in their jurisdiction. The reasoning behind his FERC siting
answer was as follows:
.
.
They do not have authority over electric transmission lines;
They do not have authority over intrastate work, only authority involves interstate
work; and
Only have authority over gas pipeline and hydroelectric interstate power and are
the rate authority.
.
He did infonn me to check with the Alaska power commission. I thanked him for his
time and infonnation.
TELEPHONE LOG
DATE: March 17,2003
TIME: 9:20 am
FROM: Bill AnkIewich
TO: Nurul Islam
SUBJECT: Lookjng for Lead Agency for Bethel Transmission Line Project
I phoned Mr. Islam looking for answers pertaining to the lead agency of the proposed
project. He asked me questions pertaining to project specifics (kind of power plant,
length of transmission lines, and main user of the electricity). I informed him of what we
knew at this point, and that TPECI was performing this initial non-specific environmental
study and that the rest of the environmental would be bid on in the future. I informed
him TPECI was looking at finding out who the Lead Agency would be pertaining to this
project, what kind of permitting would be required, and the environmental impacts of the
project.
He informed me that he didn't know anything about the project and he could not answer
if they would be the lead agency. He informed me to determine that he would need to
know more about the project. He also informed me of the following:
. They may be the main funding agency but may not be the Lead Agency;. They may just be a Cooperating Agency or one of many Cooperating agencies;
. He informed me that if the transmission lines are going through federal lands that
BLM may want to be the Lead Agency; and
. He informed me that other factors may be involved to determine who the Lead
Agency would be.
I asked him for his address and told him I would send him some information for his
review. I thanked him for his time and information.
TELEPHONE LOG
DATE: March 17, 2003
TIME: 2:05 pm
FROM: Bill AnkIewich
TO: Michael Jimmy; USF&WS Refuge Info Technician II
SUBJECT: Threatened and Endangered Species in the Yukon Delta National Wildlife
Refuge
I spoke to Mr. TimmY to find out the species of animals and plants that are listed as
threatened or endangered in the Yukon Delta National Wildlife Refuge. He informed me
the only species listed in the park are the Spectacled Eider, Steller's Eider, and the
Emperor Goose. He informed me that these birds only occur near the coastal areas. He
told me he did not know of any animals or plants that are threatened or endangered near
the Kuskokwim River. I thanked him for the information and double checked it with
information found on the internet and Mr. Greg Balogh ofUSF&WS.
TELEPHONE LOG
DATE: June 17, 2003
TIME: Unknown
FROM: Bill Anklewich, Travis/Peterson Environmental Consulting, Inc.
TO: Greg Balogh, United States Fish and Wildlife Service
SUBJECT: Proposed Kuskokwim Bethel Transmission Line Subject Area Threatened
and Endangered Species
Mr. Greg Balogh was contacted to reassure that there are no threatened or endangered
species of plants or animals in the subject area. He informed me that there are not any
threatened or endangered species in the area. I thanked him for his time and information.
Mike Travis
From:
Sent:
To:
Cc:
Subject:
Jeanne Hanson [Jeanne.Hanson@noaa.gov]
Friday, April 18, 200310:45 AM
Mike Travis
Lawrence R. Peltz
Re: Bethel Power Plant and Transmission Line
Then it will be USDA that will make the call whether or not there would be an adverse affect to EFH, and if so
do an assessment and consultation.
Jeanne
Mike Travis wrote:
> Good point. So far, it appears that the US Department of Agriculture
> will be the lead agency.
>
>
>
>
>
>-
>
>
>
Original Message From: Jeanne Hanson [mailto:Jeanne.Hanson@noaa.gov]
Sent: Wed 4/16/2003 10:56 AM
To: Mike Travis
Cc: Lawrence R. Peltz
Subject: Re: Bethel Power Plant and Transmission Line
The question will be who is the Federal Action Agency for
:>
>
> this?
>
>
>
> > Thank you, Jeanne, for your timely response. We will be coordinating closely with NMFS as-the
project progresses.
> >
> > Sincerely,
> >
> > Michael Travis
> >
> >.
> >
> '-
Mike Travis wrote:
,
>
>
>
>
>
>
>
~---Original Message---
From: Jeanne Hanson [mailto:Jeanne.Hanson@noaa.gov]
Sent: Tue 4/15/20033:48 PM
To: Mike Travis
Cc: Lawrence R. Peltz
Subjec~: Bethel Power Plant and Transmission Line
>
>
Dear Michael,
>
>
>
;>
>
>
NOAA Fisheries (National Marine Fisheries Service) received your inquiry
1
>
>
>
>
>
>
>
>
>
>
>
>
>
>
>
requesting agency comments and recommendations on a proposed
transmission line from Bethel to the Donlin Creek gold mine project.
NOAA Fisheries is charged with protection of living marine resources
including Essential Fish Habitat (EFH), marine m8n1mals and the
administration of the Endangered Species Act as it applies to certain
cetaceans and pinnipeds in Alaska. From the information you provided,
we do not expect these marine mammals to be affected by your proposed
activity. NOAA Fisheries' primary concern for this project will be the
possibility of adverse impacts to EFH for salmon in the Yukon River and
all tributaries within the project boundaries.
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The trigger for EFH consultation is a Federal action agency's
detemrination that an action may adversely affect EFH. If a Federal
action agency detennines that an action will not adversely affect EFH~
no consultation is required, and the Federal action agency is not
required to contact NMFS.
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Should there be an adverse affect detennination consultation will be
necessary, and the Federal action agency will be required to submit an
EFH assessment. Once an assessment is received by NOAA Fisheries, the
Habitat Conservation Division will then review and offer conservation
recommendations, if any, to the action agency to protect EFH.;>
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We have established an EFH area on our Internet site
http:/www.fakr@noaa.gov, Habitat Conservation. This site includes the
EFH Environmental Assessment, EFH Habitat Assessment Reports, EFH data
sets, EFH maps and an EFH search for species by latitude/longitude
tool. We continue to expand this site and hope the EFH information will
assist your review.
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Any action that may adversely affect EFH should include an EFH
assessment in either a separate document or clearly referenced in a
support documentt such as an environmental assessment for the project.
An EFH assessment is outlined in 50 CFR Part 600.920 (g) and includes
the mandatory contents: (i) a description of the proposed actiont (ii)
an analysis of the effects on EFHt (iii) the agencies views regarding
the effects of the action on EFHt and (iv) proposed mitigation. These
contents will be included in some form of your assessmentt presumably
the EIS mentioned in your letter. However t a clearly referenced EFH
assessment will satisfy the requirements of the provisions regarding EFH
within the administration of the Magnuson Stevens Act (16 U.S.C. 1801
et seq.).
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Please contact Larry Peltz, 271-1332, the NMFS biologist for your area,
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Jeanne L. Hanson
Field Office Supervisor for
Habitat Conservation Division
2
United States Department of the Interior
FISH AND WILDUFE SERVICE
Anchorage Fish &; Wildlife Field Office
60S West 4* Avenue, Room 0-61
Anchorage, Alaska 99S01-2249
MAY - 7 3m
IN REPLY REFER 1'0:
AFWFO
Mr. Michael Travis
Travis/Peterson Environmental Consulting
3305 Arctic Boulevard, Suite 102
Anchorage, Alaska 99503
Re: Bethel Power Plant and
Transmission Line
Dear Mr. Travis,
The U.S. Fish and Wildlife Service (Service) has reviewed your April 3, 2003, letter requesting
identification of concerns related to a potential 13 8 k V transmission line from Bethel to the
proposed Donlin Creek gold mine project. The project is currently undergoing a feasibility study
scheduled for completion in November 2003. The Environmenta\lmpsct,Statement and location
engineering are scheduled to begin in 2004 and to be completed in 2006. Construction is
currently scheduled for 2008 to 2010. The transmission line would be approximately 191 miles
long, and outside the Bethel city limits would require a 125-foot wide right-of-way.
Construction of the transmission line would require temporary points of access from the
Kuskokwim River. The project would require construction of a power plant in Bethel.
The Service provided comments on an earlier study (letter dated July 9,2002 from Michael B.
Rearden to Frank J. Bettine), and those comments are still valid. In that letter, the Service made
several points, several of which are reiterated here. First, lands within a National Wildlife
Refuge which have been selected but not conveyed to a Native corporation are managed as any
other refuge land, and any development on such lands would require a right-of.way permit. The
Service also commented that in making a decision on a right-of-way permit, we would look at
the existence of feasible and prudent alternatives which would not impact refuge values. These
may encompass alternative power line routes as well as alternative modes of meeting regional
power needs. Finally, no refuge use may be allowed unless it is compatible with the purposes for
which the refuge was established and with the purposes of the refuge system as a whole. Thus,
the compatibility standard is not only a decision factor under Title XI of ANll.,CA, it is a specific
requirement of ANll.,CA.
The Service believ~ that the entire scope of the project should be comprehensively evaluated as
is required under NEP A, including direst, indirect, and cumulative project impacts. This
includes not only ~ aspects of the transmission line including alternative routes, but also the
Mr. Michael Travis Page 2
power plant and other power generation alternatives, the Donlin Creek mine, the road to the
mine, and secondary power distribution to Yukon Delta and Kuskokwim River villages.
Specific issues which should be addressed in the feasibility study include:
1 An assessment of the costs and schedule necessary for preparation of an environmental
impact statement to obtain a right-of-way permit for construction of the transmission line
within the Yukon Delta National Wildlife Refuge.
2.Potential impacts of all project features, including the transmission line and towers, on
migratory birds.
3.Potential impacts of all project features, including the trangmission line and towers on
fish and wildlife populations and habitat, and subsistence activities.
4.Construction timing and methods to minimize impacts to fish, wildlife, habitat, and
subsistence activities.
5 Construction access points along the Kuskokwim River and the need for and location of
construction camps.
6.Stream crossing methods and buffer strip retention.
7.Fuel transportation, storage and spill prevention plans.
8 Raptor nest surveys along the Kuskokwim River.
9.Presence of endangered species and the potential for adverse impacts on those species.
10,Requirements for development (wetland fills) to support transmission line construction
and an assessment of potential development in the villages should power be made
available.
11 Methods to mitigate all adverse impacts on the environment.
Page 3Mr. Michael Travis
If you have any qt;}estions concerning these comments please contact Phil Brna of our project
planning staffat (907) 271-2440 or by email at phil bma@fws.gov. Questions regarding land
status and right-of-way pem1itting within the Yukon Delta National Wildlife Refuge should be
addressed to Michael B. Rearden, Refuge Manager at (907) 543-3151or by emai1 at
michael_rearden@fws.gov.
Sincerely,
0--1~~.J--
Ann G. Rappoport
Field Supervisor
cc:M. Rearden, Yukon Delta NWR, USFWS
S. Shuck, Realty, USFWS
K. Laing, Migratory Bird Management, USFWS
E. Weiss, ADF&G
M. Leykom, COE
T:\Phil_Bma\Miao Projedl\Betbbl1o DonlinN2.doo
DEPARTMENT OF THE ARMY
U.S. ARMY ENGINEER DISTRICT, ALASKA
P.O. BOX 6898
ELMENDORF AFB, ALASKA 99506-6898
-'Y'YO~..-a.T- OP:
Regulatory Branch
North Section
.9-2003-0375
APRIl! 2 8 2003
Mr. Michael Travis, P.E.
Travis/Peterson Consulting, Inc
3305 Arctic Blvd., Suite 102
Anchorage, AK 99503
Travi8:Dear Mr
This is in regard to your April 3, 2003, request for comments and concerns
relating to a proposed 138 kV transmission line to be constructed from Bethel,
Alaska to the Donlin Creek Mine north of the village of Crooked Creek.
Complex issues surround the scope of this project and will need to be
clarified prior to beginning work on the environmental document and Department
of the Army (DA) permitting. The scope of analysis for this project will
necessarily include the construction of the proposed power plant or
alternative power generation source. It appears that the Donlin Creek Mine
may be an integral part of the project as well. If so, the transmission line
and power generating facility would need to be evaluated in NEPA documents
supporting the mine project. If the transmission line/Bethel power generation
facility is an independent project, i.e. it is an economically viable project
obviate of the mine, then we may consider the project separately from the mine
project.
Required DA permits would include a Section 404 permit for the disposal of
dredged or fill material in waters of the u.s. including wetlands. The
Kuskokwim River is navigable and consequently any structures placed in, or
work conducted below the ordinary high water mark of the Kuskokwim River,
would require a Section 10 permit.
Additional issues which would concern us include: the applicant's
evaluation of alternative transmission line routes in an effort to avoid
adverse impacts; potential impacts of-the power lines and towers to bird
migration routes and air traffic routes; infrastructure requirements in the
individual villages connected to the transmission line; proximity of the
overhead lines and support tower. to village airports; access to the project
facilities in areas not on existing roads; and construction methods and
timing.
Thank you for the opportunity to become involved early in the project
genesis. If copies of the preliminary feasibility study for this project are
still available, please send me one with your next correspondence. If you
have questiQns concerning this letter, please contact me at 753-2716.
/'Vt
~
Mary
Regulatory Specialist
FRANK 1(; MURKOWSKf
GOVERNOR
DEPARTMENT OF NATURAL RESOURCES
DIVISION OF MINING, LAND AND WATER
SOUTHCENTRAL REGION LAND OFFICE
550 W. 7TH AVE., SUtTE ~
NoK:;OORA.GE, ALASKA. 99501-3577
April 15, 2003
Michael D. Travis P.E.
President
Travis! Peterson Environmental Consulting, Inc.
3305 Arctic Boulevard
Anchorage, Alaska 99503
Re: Bethel Power Plant & Transmission Line
Dear Mr. Travis,
Thank you for the notification of your proposed transmission line in the Bethel to Donlin
Creek Mine area. Because of the scale of the map we are unable to determine, with
accuracy, which state lands are involved.
We have reviewed an overview of the area covered by the project and it appears that the
route traverses several RS 2477 trails, some airports and the Kuskokwim River. This
information may not be accurate.
Could you please submit a map of the project that accurately and specifically describes its
location. We would appreciate a legal description of the lands involved by providing an
accurate map and list the land descriptions according to Township, Range, Meridian and
Section. This infonnation is available at State Department of Natural Resources Public
Room. Once we receive the infonnation we will be in a better position to detennine if an
application for a right of way on state lands is appropriate.
If you have any questions regarding this request please contact me at 269-8564. We look
forward to working with you to secure the appropriate state authorization for your
project.
Sincerely,
ldt/& L)£- /1R \d:l~1
Ma:vi~e Sutl~- lIT
Natural Resource Specialist
"Develop, Conserve and Enhance Natural Resources for Present and Future Alaskans"
FRANK 17': MURKOWSKI
GOVERNOR
DEPARTMENT OF NATURAL RESOURCES
DIVISION OF MINING, LAND AND WA TER
SOUTHCENTRAL REGION LAND OFFICE
550 W. 7TH AVE., SUfTE 9OOC
ANCt-K>RAGE. ALASKA 9950 1.3577
William Anklewich
Staff Scientist
Travis/Peterson
Environmental Consulting, Inc.
3305 Arctic Boulevard
Anchorage, Alaska 99503
May 8, 2003
Re: Bethel Power Plant and Transmission Line
Dear Mr. Anklewich,
Thank you for providing the status maps for the Bethel Power Plant and Transmission
Line Project. When State lands are involved, as in this case, there needs to be an
application for a right of way. I have enclosed an application form that can be submitted
to the following address along with the application fee:
Public Infonnation Center
Department of Natural Resources
550 West 7th Avenue
Suite 1260
Anchorage, Alaska 99501-3557
(907) 269-8400
Thank you for your prompt response to my request for information. If you have any
questions please call me at 269-8564.
Sincerely " ~
'A/U 1._J P~"
Mary /a;l Sutliff
Natural Resource Specialist
"Develop, Conserve and Enhance Natural Resources for Present and Future Alaskans"
IK\~
May 21, 2003
Michael Travis, P .E.
Travis/Peterson Environmental Consulting, Inc.
3305 Arctic Boulevard, Suite 102
Anchorage, AK 99503
Dear Mr. Travis:
The Alaska Department ofFish and Game (ADF&G) and the Alaska Department of Natural
Resources, Office of Habitat Management and Permitting (DNR/OHMP) has received your request
to provide scoping comments on the proposed electrical tran~ssion line between Bethel, Alaska
and the Donlin Creek Mine. The information provided was rather general, however, some concerns
are evident from what was provided. Once full plans are developed, the ADF&G and OHMP would
also like to review those for potential concerns. Based on a review of the information provided, we
have the following comments.
O~ Fish Habitat Permits will most likely be required for the project, dependent on transmission
line crossing methods and equipment crossing methods and locations. In order to fully evaluate the
permitting needs and provide meaningful input, the OHMP and ADF&G will need more
information on the project. Initially, the location and methods for equipment and ~~qgion line
crossing for each stream crossed by the 11'an--qrnission line will be needed. If the crossings or
construction methods involve any work below the Ordinary High Water (OHW) mark of the stream
or water body, then these additional data are needed.
Type of work occurring in the stream
Fish species present or utilizing each stream
Geomorphologic characteristics at each site
Habitat characteristics at each site
.
.
.
.
Another issue will be access to the line both during and after construction. Your letter mentions use
of access pointS from the Kuskokwim River. Information on ~ese sites, and on any access road
along the length of the line, will be needed. The projected use and permanency of these roads and
access sites will be needed in -addition to the information requested above. The type of transmission
line (aerial, underground, etc.) and the methods for construction will also affect other fish and
wildlife concerns such as interference with migrations, bird strikes, etc.
"Develop, Conserve, and Enhance Natural Resourcesfo1' Present and Future Alaskans. "
2Michael Travis, P .E.May 21,2003
We appreciate the opportunity to comment. Once plans start to solidify more, we would be
available for a meeting to discuss concerns and options. For your information, projects of this
nature in Western Alaska formerly reviewed by the ADF&G, Habitat & Restoration Division, will
now be reviewed by the ADF&G in Anchorage and the new OHMP in Fairbanks. In the future, you
can contact Robin Willis at ADF&G (907)-267-2329 for comments related to the ADF&G fish and
wildlife concerns. You can contact Mac McLean (907)-459-7281 with the /OHMP regarding
comments related to fish habitat and permitting at stream crossings along the route.
SincerelYt
Dick Lefebvre, Deputy Commissioner
t~..Qj vJ. tJ(,...: -
Edward W. Weiss
Habitat Biologist
Anchorage Area Office
ed- weiss@adnr.state.ak.us
r~ tA)~Q.L.~ ~
Robin Willis
Habitat Biologist
ADF&G
TObin - willis@:fishgame.state.ak. us
cc:A. Rappoport, USFWS
J. Hanso~ NMFS
T. Ward, ADF&G/CF/Betbel
C. Whitmore, ADF&G/SF/Bethel
J. Oscar, Cefialiulriit CRSA
J. Hooper, AVCP
M. Mc~ ADNR
R. Willis, ADF&G/WC/Anchorage
R. Seavoy, ADF&G/WC/Bethel
Bill Anklewich
Mike Travis
Thursday, April 10, 200311:23AM
Bill Anklewich
FW: Bethel Transmission Line
From:
Sent:
To:
Subject
~
cw for ~Ie
Raymond- Y akoii .
Oriqinal Messaqe From: Julie Raymond-Yakoublan [mailto:jullery@dnr.state.ak.us]
Sent: Thursday, April 10, 2003 10:52 AM
To: Mike Travis
Subject: Bethel Transmission Line
Michael,
~ I mentioned in our telephone conversation earlier today, with a project the size of the
proposed transmission line, it is likely that large areas will require archaeological
survey. Therefore, it would be wise, as you noted, to include the likelihood of
archaeological survey work in the budget planning process. At this time our office is ..
unable to give any more specific details regarding the scope or nature of such a survey.
Thanks!
Julie Raymond-Yakoubian
1
April 21, 2003
Travis/Peterson Environmental Consulting, Inc.
3305 Arctic Boulevard, Suite 102
Anchorage, Alaska 99503
Re: Bethel Power Plant & Transmission Une
Dear Mr. Travis,
Bethel Native Corporation (BNC) is in receipt of your letter of April 2, 2003, requesting
our comments and concerns on the proposed project to install a 138kV electric
transmission line from Bethel to the proposed Donlin Creek mine project. BNC's land
Committee met on April 12, 2003 and had an opportunity to review your letter. We
understand that the transmission line will run for 191 miles from Bethel to Donlin Creek,
and will require a right-of-way width of 40-50 feet within Bethel City limits and a 125-foot
wide width for the remainder of the line. This project is currently undergoing a feasibility
study, which is expected to be completed in November 2003.
The land status around Bethel is complicated the existence of numerous land holders,
induding BNC (surface), Calista (subsurface) Native Allottees, the City of Bethel, and
other private land owners. The map provided did not include detailed land status
information and it was difficult for the land Committee members to comment on the
transmission line route or determine what impad the line would have on BNC lands. It is
evident, due to the land status around Bethel, that site control to acquire the right-of-
way for the transmission line will be complicated by having to obtain permits from
private land holders who own land under ANCSA, and those who own land in a
restrided status. We did note that the transmission line followed sedion lines. Is there
a reason for this? Will this power line be construded above ground? We would also like
to obtain a more detailed map to assist the land Committee in understanding what
impacts the transmission line will have on BNC lands. Additionally, we would like to
inform you that permission would be needed from BNC to perform any studies or
environmental work on our land. Your request must be made in writing to BNC and be
accompanied by a filing fee of $50.00.
The Land Committee understands that there will be a power plant, but that the location
and other SpedflCS are not known, other than the plant wjll be located somewhere south
of Bethel. One of our Land Committee members was present at a recent Bethel
Chamber of Commerce meeting in which it was reported that the power plant would be
located somewhere on BNC's lands. BNC was never contaded nor informed that their
land would be used prior to it becoming public knowledge. We reproadl the lad< of
courtesy given to BNC, .and request that we are kept in the loop on any and all issues
that involve BNC land.
BNC has environmental concerns and because we lack adequate information regarding
this project, it is impossible for us to support the project. Other questions raised by our
Land Committee include: What kind of power plant will be established and how much
land will be required for its development? We have heard rumors that it will be fueled
by coal. We have concerns that burning coal is not healthy for the people, animals, and
the tundra. Who will monitor its operation? Our rough estimates of the location places it
near traditional subsistence and established fish camps. What other options have
Nuvista considered for the location of the transmission line? Have they considered
placing it on the other side of the mountain?
In closing, BNC needs more information up front and would like to be informed about
the process and plans about the project as it progresses. We are unable to comment
on the location of the line given the lack of detailed information on the map. We thank
you for this opportunity to comment.
Sincerely,
-~.~~=- ~ ./~-
Marc D. Ster1l"p
President/CEO
AKIA CHAK LIMITED
Post Office Box 51010
Akiachak, Alaska 99551
(907) 825-4328
Fax # (907) 825-4115
2S April 2003
Mr. Michael Travis, P .E.
President
3305 Arctic Boulevard, Suite #102
Anchorage, Alaska 99503
Bethel Transmission Line
Project Number: 111701
Re:
Dear Mr. Travis,
Per Board of Director directive I am responding to your request for
comments regarding the Bethel Power Plant and Transmission Line, letter dated
April 3, 2003.
The Akiachak Limited Board of Directors met on April 11th, 2003, and
reviewed and discussed your letter. Generally, we are supportive of the efforts of
the Nuvista Light & Power Company (Nuvista) to provide low cost electricity to
the villages along the Kuskokwim River in light of the high cost of generating our
community with fossil fuel system.
The Board realizes that Nuvista will go on the corporate lands during the
course of the construction of a 138 kV transmission line from Bethel to the Donlin
Mine site, basically on the north side of the Kuskokwim River. The Board does
not object to this endeavor.
There are several questions the Board would like some answers to
regarding the proposed route and the possible impacts to our shareholder activities
on corporate lands. They are:
1.
2.
3,
Is the project intent to construct a road on the length of the right-
of-way to maintain the power line?
Are there going to be any restrictions for shareholders to conduct
subsistence activities along the right-of-way?
\Yhat type of restrictions and/or protections are there for Akiachak
Limited when the transmission line crosses the Oweek River?
What type of restrictions and/or protections are there for Akiachak
Limited when the transmission line crosses corporate lands?
.4.
There may be other comments and questions in the future. but these are
the primary issues of concern to the Board of Directors. We would like to be kept
infonned and be involved during the course of the project.
I thank you for allowing us to make our comments regarding the project.
Sincerely,
AKlACHAK LIMITED
~~~~f
Wiliie~KasaYu1te
President & CEO
P. O. Box 110 Kwethluk, Alaska 99621 Phone: (907) 757-6613,' Fax: (907) 757-6212
Apri130.2003
Michael Travis, P .E. President
Travis/PeteI'sm1 Environmmtal
Consulting, Inc.
3305 Arctic Boulevard, Suite 102
Anchorage, AK 99503
Re: Transmission Line
from Bethel to D<X1lin Creek
Dear Mr. Travis, P .E.
The r~ipt and invitation of YOm'S for comments and/or recommendations dated April 3. 2003 is acknowledged.
thank you.
The developmmt of an "ecoo<Xnical and mvironmmtally frimdly" electric p<JWel' soun:e in the Calista! Association
of Village COWlcil President region will be most welcome if: (1) Ecmlomically, electricity use costs will definitely
be lowered to acceptable leveVs for all commercial, educational, and private customers. (2) Environmentally
friendly goal and objectives should apply in all of the development phases of the electric transmission line project.
There is no doubt that various subsistence hunting, fishing, and b'apping areas could be disturbed rendering th~
less/non-productive places. To minimiwmitigate such ~ible mvironmmtal impacts to the Kuskokwim River
watershed and including all its north side triOOtaries watersheds should undergo individual careful review in their
respective "crossing areas" (of the transmission line) for preventioo of m- mitigation of riverbank m- stream bank
U"~ioos. It must be clearly understood that all these watershed areas are important parts of the entire breadbasket of
the Kuskokwim RivU" area villages which and whose respective residents are highly dependent on renewable natural
resources. (3) Perhaps, as a thought, the transmission lines rights of way could be designed to run on the southcr-n
edges, as appropriate, of the tundra north of the Kuskokwim River. In the hill or mountain areas, the transmission
lines design shoold provide for maximum pr~OD, including ~ible a1hancemmts, of fish and game habitat. (4)
To keep reduced high wires aa-ial cluttering particularly in the vicinities of the villages referred to East ofBethei,
the possible applicability of single wire ground return and electric line such as exists between Bethel and Napakiak
should be given some review or study. The affected village residents should be consulted fm- their view points and
thoughts for the most acceptable rights of way design to their village. This conception, development, and
implementation of the transmission line will change the landscape to pe!'petuity that makes it of utmost importance
for extra diligent selection of rights of way routes. In additioo, diligmt selectioos may lead to "ownership"
relevancy, pride and acceptability of the proposed project. I thank you for the opportunity to present.
Sincerely,
Kwethluk, Inc0rp<M'8ted
..,.:q.~7 I?-~_-
G~ge Guy,
Business Manager
GO/amo
cc: file
PAGE 81CITY CF K\I£TH..lI<751&49114:2904/08/2003
City of KwClhluk
11. K W8thluk Street
P.O. Box'O
K w.cIIIuk, AI8Sk8 99621
Telephone (9(T1) ",.6022 PAX (907) 751.6497
April 8. 2003
Mr. Michael D. Travis. P. E.
Travis/Peterson Environmental Consulting. Inc.
330S Arctic BouJevard
Anchorage. Alaska 99503
Subject: Letter'dated April 3. 2003
Bethel Transmission Line. Project' 1117-01
BetheJ Power Plant & Transmission Une
De8r Mr. Travis:
Thank you for the conespondence refcm)Ced above and your quest for ~ts and
concerns we may have in the development of this project.
As of today, I ~ave no comments and or concerns but wi" bring to the attention of the
City Council the corresponcknce yoo lent to seek their comments and or concerns of the
proposed Transmission Line from Bethel Alaska to the Donlin Creek Mine.
I would rather co~nt as soon as lleceive a copy of me Environmental Impact
Statement and the proposed cOlt of die JXOject ftUD p1anning. .ve)c,~iit. aDd to
implemenwion.
Thank you for considering our CiJuw.ent$ and CVI~--WS as. imporunt to the deveJop~t
of this project while in the planning phase.
If you have any questions or commonta please feel fRe to contKt me at the above listed
~lephcne number durina Ronna) business hours.
~
Cordially.
Cjty of Kwethluk
(::1 .:Ei'"'~ ~ ...L
Boris ~ P,iJChook. May«
Cc: Kwethluk City Counci1
File
ALASKA vnLAGE ELEcrRIC COOPERA'l1VE, INC.
April 21, 2003 O~50E
Mr. Michael Travis, P.E.
President
Travis/Peterson Environmental Consulting, Inc.
Suite, 102
3305 Arctic Boulevard
Anchorage, Alaska 99503
RE: Comments on Bethel Transmission Line
Dear Mr. Travis:
A review of the three page letter dated April 3, 2003, and attached Figure 1, Bethel
Transmission Une Proposed Route dated February 14, 2003, resulted in the following
comments:
1. How does the capadty of the proposed 138 KV line CQf1'1>are with current and
projected loads? Would a lower ~rating voltage line be adequate, or is a higher
operating vohage line necessary?
2. Was a DC transmission line considered, and if so, why is it not being given additional
consideration?
3. How many individual stepdown transformation sites are proposed between Bethel
and the Donlin Creek mine site?
4. How will the reliability of the line be affeded by the number of individual stepdown
transformation sites?
5. Will a communications conductor such as a fiber optic cable be carried on the
transmission line?
6. Is a paralleling road being proposed for construdion and Mure maintenance of the
line?
7. Will there be any 138 KV crossings of the Kuskokwim River, for example at Aniak?
8. Has a recommended conductor size been identified?
9. Has a recommended tower configuration been developed at this time?
10. Has an average span length been recomrrended at this tilTe?
4831 Eag-le Street. Anchoraue. Alaska 99503-7497 . Phnnf'; (007) ~1-1R1R . Tn ~t~tp (ROO) t7$l.1.Q1.Q . F~v (Q()7) ,,~?AnS!h
11. It does not appear that the proposed route is in any avalanche areas. However, it
could be located in areas of severe icing and flooding and ice flows from flooding.
What steps are being taken to prevent power interruptions associated with these
natural events?
12. Vandalism in the form of rifle shots at the insulators and conductors may occur. What
steps are being taken to alleviate this potential hazard?
13. Is automated load shedding of individual stepdONn transformer loads being proposed
in order to restore service after an interruption?
Sincerely yours,
~ { ~ '1\ L(;{{lQ 1\1
Meera Kohler
President and CEO
MK: ejp
Mark Teitzel, Vice President and Manager, EngineeringCc:
APPENDIX C
LANDOWNERSHIP MAPS
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APPENDIX D
USDA RUS NEP A POLICIES AND REGULA nONS
Friday
December 11, 1998
Part VI
Rural Utilities Service
7 CFR Part 1780 and 1794
Environmental Policies and Procedures;
Final Rule
DEPARTMENT OF AGRICULTURE
Rural Utilities Service
7 CFR Parts 1780 and 1794
RJN 0572-AB33
Environmental Policies and
Procedures
AGENCY: Rural Utilities Service. USDA.
ACTION: Final rule.
!I_~: The Rural Utilities Service
(RUS) hereby revises its existing
environmental regulations,
Environmental Policies and Procedures,
which have served as RUS
implementation of the National
Environmental Policy Act (NEPA) (42
U.S.C. 4321 et seq.) in compliance with
the Council on Environmental Quality
(CEQ) Regulations for Implementing the
Procedural Provisions of the NEP A.
Based on new Congressional mandates.
changes in the electric industry. and
RUS experience and review of its
existing procedures. RUS has
determined that several changes are
necessary for its environmental review
process to operate in a smooth, efficient,
and effective manner.
The implementation of this rule has
required that certain changes be made to
7 CFR part 1780 regarding
environmental compliance. The
amendments published in this
document consist of those necessary to
make the provisions of Part 1780 subject
to the environmental requirements of
this rule.
&FECI1VE DAtE: December II, 1998.
R)R ~ER ~~ COtTACT: Gary
j. Morgan, Director, or Lawrence R.
Wolfe. Senior Environmental Protection
Specialist. Engineering and
Environmental Staff; Rural Utilities
Service, Stop 1571. 1400 Independence
Ave., SW., Washington. DC 20250-1571.
Telephone (202) 720-1784. E-mail
address gmorgan@>ms.usda.gov or
lwolfe@)rus.usda.gov.
This rule and the guidance bulletins
described in this rule will be available
on the Internet via the RUS home page
at www.usda.gov/rus/.
SU~ARY ~FOMA~:
Classification
This rule has been determined to be
significant and was reviewed by the
Office of Management and Budget
(OMB) under Executive Order 12866.
Civil justiu Refonn
This rule has been reviewed under
Executive Order 12988, Civil justice
Reforrp. RUS has determined that this
propqiSed rule meets the applicable
standards provided In sec. 3 of the
Executive Order.
In accordance with tlM! Executive
Order and the rule; (1) all state and local
laws and regulations that are In conflict
with this rule will be preempted; (2) no
retro-active effect will be given to the
rule; and (3) administrative proceedings
are required to be exhausted prior to
initial litigation against the Department
(7 U.S.C. 6912).
Regulatory Flexibility Act Certification
Pursuant to section 605(b) of the
Regulatory Fle.x1bility Act. 5 U.S.C.
6O5(b). RUS certifies that this rule will
not have a significant economic impact
on a su~tantial number of small
entities. If a rule has a significant
economic impact on a su~tantial
number of small entities. the Regulatory
Flexibility Act requires agencies to
analyze regulatory options that would
minimize any significant impact of a
rule on small entities. The application
for financial assistance under the RUS
Electric and Telecommunications
programs and the application for loans
and grants under the RUS Water and
Waste program are discretionary;
regulatory requirements will. therefore.
apply only to those entities which
choose to apply for fmancial assistance
or funding.
Information Collection and
Recordkeepins Requirements
The recordkeeping and reporting
burdens contained in this rule were
approved by the Office of Management
and Budget (OMB) pursuant to the
Paperwork Reduction Act of 1995 (44
U.S.C. chapter 35,) under control
number 0572-0117.
National Performance Review
This regulatory action is being taken
as part of the National Performance
Review to eliminate unnecessary
regulations and imJX"OVe those that
remain in force.
Envil'onmental justice
This rule is subject to the
requirements of Executive Order 12898.
Federal Actions to Address
Environmental Justice in Minority
Populations and Low-Income
Populations. Implementation of these
requirements will occur at the time of
actions performed hereunder.
National Envil'onmental Policy Act
Certification
The Administrator of RUS has
determined that this rule will not
significantly affect the quality of the
human environment as defined by the
National Environmental Policy Act of
1969 (42 U.S.C. 4321 et seq.) Therefore,
this action does not require an
environmental impact statement or
assessment.
CataloR of Federal Domestic Assistance
The programs described by this
proposed rule are listed in the Catalog
of Federal Domestic Assistance
programs under numbers 10.850, Rural
Electrification Loans and Loan
Guarantees, 10.851, Rural Telephone
Loans and Loan Guarantees, 10.760,
Water and Waste Disposal System for
Rural Communities, 10.764, Resource
Conservation Development Loans, and
10.765, Watershed Protection and Flood
Prevention Loans. This catalog is
available on a subscription basis from
the Superintendent of Documents, the
U.S. Government Printing Office,
Washington, DC 20402.
Intergovernmental Review
This rule excludes the Electric and
Telecommunications Programs from the
scope of Executive Order 12372,
Intergovernmental Consultation, which
may require consultation with State and
local officials. A final rule related notice
entitled, "Department Program and
Activities Excluded from Executive
Order 12372," (50 FR 47034)
determined that RUS loans and loan
guarantees, and RTB bank loans, were
not covered by Executive Order 12372.
The Water and Waste Program is subject
to the provisions of Executive Order
12372. Consultation will be completed
at the time of actions performed
hereunder.
Unfunded Mandates
This rule contains no Federal
mandates (under the regulatory
provision of Title n of the Unfunded
Mandates Reform Act) for State, local,
and tribal governments or the private
sector. Thus this rule is not subject to
the requirements of section 202 and 205
of the Unfunded Mandates Reform Act.
BackRrGund
On March 13,1984, the Rural
Electrification Administration
(predecessor of RUS) published 7 CFR
Part 1794, Environmental Policies and
Procedures, as a final rule in the Federal
Register (49 FR 9544) covering the
actions of the Electric and
Telecommunications programs. Based
on new congressional mandates,
changes in the electric industry, and
RUS experience and review of its
existing procedures, RUS has
determined that several changes are
necessary for its environmental review
process to openJte in a smooth, efficient,
and effective manner.
The existing 7 CFR part 1794 was
designed to implement the requirements
of NEP A and the CEQ regulations for
RUS Electric arxI Telecommunicatiom
programs. As a result of the Federal
Crop Insurance Reform and Department
of Agriculture Reagantzatton Act of
1994 (Pub. L 103-354. 108 Stat. 3178),
the programs of the Rural Electrification
Administration. were combined with
the Water and Waste program from the
former Fanners Home Administration
(FmHA) Into RUS. Most changes
proposed to 7 CFR pM1l794 result from
the addition of the Water and Waste
program to RUS.
For further guidance In the
preparation of public notices and
environmental documents. RUS has
prepared a series of guidance ~letins.
Three program specific bulletins are
available which provide guidance In
preparing the Environmental Report
(ER) f(X' pro~ actions classified as
categorical exclusions and proposed
actions which require an EnvIronmental
Assessment (EA). Further information
on these bulletins Is provided In
§ 1794.7.
This final rule contains a variety of
su~tantlve and procedural changes
from the provisions of the current rule.
Some of these revisions are minor
(§ 1794.4, Trivial Violations was
deleted) or are merely Intended to
clarify extsttng RUS policies and
procedures (§ 1794.6. Definitions, was
added). Other revisions reflect changes
In RUS implementation of the CEQ
regulations as (Xlt1tned below.
The relationship between RUS and its
Electric and Telecommunications
applicants has c})an8ed substantially
since RUS i~ued the final rule In March
of 1984. Changes that have occurred In
the last 4 years have been particularly
dramatic. Historically. RUS provided
su~tta1ly all of its applicants' capital
needs and established a lending
relationship reflecting that dominant
lending role. However. because of
limited annual loan authorization
levels, RUS no longer ~ such a role.
Moreover, In a 1993 amendment to
section 3O6E of the Rural Electrification
Act of 1936 (RE Act). as amended (7
U.S.C. 936e). Congress required RUS to
abandon its close hands-on control of its
applicants and Instead follow the
practices of private market lenders. RUS
has done so through the development of
~ f(X'ffiS of loan agreements and
security Instruments and the
publication of 7 CFR Part 1717. subpart
M. Operational Cmtrols. which reduce
or eliminate much of the oversight and
control historically exercised by RUS
over its Electric applicants.
experience aOO a survey of the
thresholds established by the
Environmental Protection AgeOCY
which administft'S similar programs.
RUS has eliminated the two tiered
classification for EAs that Is contained
in 7 CFR Part 1940, Subpart G, the
environmental regulation of the fonner
FmHA. and adopted the more
traditional claslflcation scheme as
outlined in 40 CFR 1508.9. Because RUS
co-funds a sJgniftcant portion of its
projects with other Federal and state
agencies, a more traditional
classification and documentation
scheme is thought to be more corouclve
to minimizing duplicative
environmental review efforts.
RUS has modified Its procedures in
subparts D through G of this part. The
EA will be the subject document of the
notice of availability requirements in
§ 1794.42, where previously, the
applicant's ER was the subject
document. By this change, the notice
requirements for all three ~ will
be consistent for both EA proposals and
EA with scoping pro~. This change
will erK:DUrage more public involvement
by allowing public review of EA
proposals prior to the issuance of a
FirKting of No Significant Impact
(FONSI).
RUS has also changed Its notice
requirements for Electric program
projects requiring scoplng. The timing
of RUS FedeI'a1 Relister notice for
public scoping meetings in § 1794.52(b)
has been reduced from 30 days to 14
days prior to the meeting. No
appreciable benefit resulted from an
earlier I}(X.ice requirement. The exJsting
regulation allows RUS to adopt the
applicant's ER as its EA but requires
RUS to prepare Its own EA from the
applicant's Enviromnental Analysis
(EV AL) where a proposed action
requires scoping. RUS has changed this
requirement by allowing the EV AL to
Sft"Ve as Its EA (see § 1794.53) consistent
with 40 CFR § 1506.5(b).
RUS has modifIed its policy regarding
the use of contractor prepared ElSs.
Under the existing regulation, RUS was
required to useageocy funds when an
lrKIependent contractor was ch~n by
RUS to prepare the ElS. In accordance
with the provisl(X1S of 7 CFR Part 1789.
"Use of ~ltants Funded by
Applicants" and Section 759A of the
Federal Agriculture Improvement and
Refonn Act of 1996, the draft aOO final
ElS may be prepared by a consultant
selected by RUS and funded by the
applicant. A JEW requirement.
publication of a notice of availability by
RUS and the applicant for a Record of
Decision Is esoollshed in § 1794.63.
Refl~ttng these changes and reforms,
RUS has revised § 1794.3 of the rule.
Environmental reviews will continue to
be required in connection with the
approval of financial assistance for
applicants and the issuance of rules,
regulations. and bulletins by RUS.
However, no reviews will be required in
co~ction with approvals provided by
RUS pursuant to its loan conttacts and
security insttument5 with applicants
such as approvals of lien
accommodations or the use of general
funds by applicants. These approvals
are not major Federal actions
significantly affecting the quality of the
human env~.
Within subpart C of this rule, a
classification system defines the level of
environmental review required for RUS
and applicant ~ actiom. In
Section 1794.20 RUS has clarified its
position for detemlining drcumstances
under which an applicant's
participation in a proj~t results in a
Federal action. Sectiom 1794.21
through 1794.25 of this subpart are
further subdivided when appropriate to
differentiate between actions being
proposed by RUS and actions proposed
by El~tric, Telecommunications, and
Water and WMte JX'ograID applicants.
A number of cl~tncation changes
have been made within subpart C of this
rule. These reclassifications involve
minor actions JX"Oposed by applicants
which rarely, if ever. result in
significant environmental impact or
public interest. RUS believes this rule
includes adequate safeguards to identify
any unusual dn:umstances that may
require additional agency scrutiny.
RUS has modified the thresholds for
acreage (facility sites). and capacity
(generation facilities) within
§ 1794.22(a). In additi(X1 to modifying
the thresholds for acreage and capacity,
RUS ~ imposed different thresholds
for construction of electric generating
caJ:NtCity at new sites versus existing
sites within § 1794.23(c). Acreage and
capacity threshold changes within
§ 1794.24. and a capacity dreshold
change within § 1794.25 reflect changes
that have been made in §§ 1794.22(a).
and 1794.23(c). No changes were made
to the existing thresholds for
transmission line length. CapM:ity
thresholds have been eliminated fcx
hydroelectric proposals in §§ 1794.22
and 1794.23. RUS will normally adopt
the NEP A document prepared by the
Federal licensing agency of
hydroelectric projects in which RUS
applicants partidpate.The thresholds for proposed actiom
in dle Water and WMte program are
classified in §§ 1794.21 (c) and
1794.22(b). ~ on historical
Preparation of the Rulemaking
The proposed rule (7 CFR part 1794)
was published in the Federal Register
on November 24, 1997 (62 FR 62527).
Public comment was invited for a 60-
day period, ending on january 23,1998.
Eighty-nine written comments were
received representing 32 specific
organizations and individuals. These
included two Federal agencies, eight
Federal agency state offices, one
regional commission, two electric
cooperative associations, and seventeen
rural electric cooperatives. All
comments were fully considered when
revising the proposed rule for
publication as a final rulemaking.
Every effort has been made to respond
in detail in the preamble to every
question raised or suggestion offered.
Where commenters pointed out errors in
spelling. syntax, and minor technical
errors these errors were con"ected and
not mentioned fUrther in the preamble.
In addition, many commenters made
similar suggestions or raised similar
issues. In the interest of clarity,
comments that were similar in nature
were grouped and discussed in the most
relevant section in the preamble. Some
comments pointed out vague and
unclear language. Clarifying and
explanatory language was added to the
rule and preamble as appropriate. The
discussion under General Comments
responds to general comments and
clarification of misunderstandings as to
RUS's intent. The statements under
Comments on Specific Sections address
the more significant comments received
on particular provisions and how RUS
responded to them.
General Comments
Several comments focused on the
background discussion of the preamble
to the proposed rule regarding the
proposed renumbered § 1794.3, entitled" Actions requiring environmental
review." The background discussion
explained that, because of changes in
law and reforms in the Electric and
Telecommunications industry, RUS
proposed to revise that section to reflect
that RUS would no longer treat as
Federal actions subject to environmental
reviews, approvals provided by RUS
pursuant to its loan contracts and
security instruments. The preamble
explained that these approvals are
"ministerial" and not major Federal
actions for the purposes of NEP A. The
commenters, who uniformly supported
the proposed revision, asked that RUS
identify all approvals that would no
longer be subject to environmental
review or clarify that only the approval~
of loans and loan guarantees will
require an environmental review.
Agency Respome: The proposed
revision to § 1794.3 deletes reference to
"lien accommodations, and approvals
provided pursuant to loan contracts and
security instruments (e.g., approvals of
the use of general funds)." In pertinent
part, the revised section identifies as
actions requiring environmental review,
"the approval of financial assistance
pursuant to the Electric,
Telecommunications, and Water and
Waste Programs." In response to the
comments, RUS has added a clarifying
sentence to § 1794.3 stating that,
" Approvals provided by RUS pursuant
to loan contracts and security
instruments, including approvals of lien
accommodations, are not actions for the
purpose of this part and the provisions
of this part shall not apply to the
exercise of such approvals:' RUS
believes that. while it is principally the
approvals of loans and loan guarantees
to which environmental reviews attach,
it is p~ible that other types of
discretionary financial assistance could
be available under the RUS program,
which would trigger environmental
reviews. Examples include lien
subordinations under § 306 of the RE
Act (7 U.S.C. 936). The regulatory text
should not limit those actions requiring
environmental review to the approval of
loans and loan guarantees.
Consequently, no other change has been
made in response to the comments.
Ten commenters expressed concern
about the two-tier classification that was
created for "categorically excluded"
proposals in §§ 1794.21 and 1794.22,
which they believe is overly
burdensome arxi confusing. They
further believe that many of the size,
voltage, distance, and acreage
thresholds have been arbitrarily
determined and need to be reevaluated.
Agency Respome: RUS established
the two-tier classification system for
categorically excluded proposals
specifically to reduce the burden on
applicants without compromising the
requirements of NEP A and the CEQ
regulations. Categorically excluded
proposals listed in § 1794.21 normally
do not significantly impact the quality
of the human environment. Therefore
the submittal of an ER is not required.
An ER is required for categorically
excluded proposals listed in § 1794.22
to provide for circumstances in which a
normally excluded action may have a
significant impact (see 40 CFR 1508.4).
Prior to issuing the proposed rule, RUS
reevaluated the thresholds established
in the existing regulation and
determined that the revised thresholds
included in the proposed rule represent
a reasonable delineation consistent with
40 CPR 1508.4.
The commenters also questioned why
an environmental report should be
required for a prop~l that is normally
categorically excluded and recommend
that where appropriate. proposals listed
in § 1794.22 be incorporated into
§ 1794.21.
Agency Response: The changes
proposed by these comments are not
consistent with the definition of
categorical exclusion in 40 CFR 1508.4.
In order to ensure that a proposed action
does not significantly affect the quality
of the human environment. RUS must
conduct an environmental review. The
two-tlered classification system for
Categorical Exclusions establishes the
level of information that must be
provided by the applicant for proposals
lIsted in each tier. This information is
necessary so RUS can identify
extraordinary drcumstances in which a
normally excluded action may have
significant environmental effects.
One commenter recommended
incorporating language into § 1794.21 by
which RUS could in~ the level of
environmental review for any
categorically excluded project. which
had a significant environmental effect.
Other commenters point out that
proposals in these two categories
already must meet the requirements of
§ 1794.31. Therefore a safeguard already
exists whereby RUS can evaluate each
project and determine if further
environmental review is appropriate.
Agency Response: This rule includes
a requirement in § 1794.22(a) by which
RUS reserves the right to request
environmental documentation for
proposals listed in § 1794.21 (b) and (c)
if significant environmental effects
result from the implementation of the
proposal. RUS believes that determining
whether an ER should be prepared for
all categorically excluded proposals on
a case-by-case basis would be
inconsistent with the CEQ regulations
(40 CPR 1508.4) and would extend the
RUS environmental review process.
Three commenters assert that the
thresholds established to differentiate
between projects that require an
environmental assessment (EA) with
and without scoping (§§ 1794.23 and
1794.24) were also arbitrarily
determined and point out that a 1 MW
increase in capacity can increase the
level of review. The commenters
recommend that all § 1794.24 proposals
which normally require scoping be
incorporated into § 1794.23 and that
RUS adopt language allowing the
agency to require scoping for projects
which are expected to have significant
impacts.
Federal Register/Vol. 63. No. 238/Friday. December II. 1998/Rules and Regulations 68651
Agency Response: RUS has
reevaluated the thresholds that were
established in the existing regulation for
proposed actions listed in §§ 1794.23
and 1794.24. The thresholds accurately
delineate the difference between
proposed actions which can be
adequately reviewed with an EA and
those actions which have a higher
potential for needing an EIS. The latter
required the preparation of an EV AL by
the applicant. The EV AL will serve $
the RUS EA, (40 CFR 1506.5(b». Instead
of establishing a single classification
system for actions normally requiring an
EA and determining the need for
scoping on an individual basis, RUS
agrees some flexibility is needed and
has included a provision to modify or
waive scoping requirements in
§ 1794.52 for actions that normally
require an EA with scoping.
Two commenters expressed concern
with the provisions of the proposed rule
that aliow the applicant or its consultant
to prepare the environmental report (ER)
which normally serves $ RUS" EA for
Water and W$te proposals. These
commenters $5ert that there may be an
appearance of a conflict of interest.
Agency Response: Agency
responsibIlity is addressed in 40 CFR
1506.5. The CEQ regulations allow an
agency to require an applicant to submit
environmental information for possible
use by that agency (40 CFR 1506.5(a».
The agency should assist the applicant
by outlining the types of information
required. The agency shall
independently evaluate the information
provided by the applicant and accept
responsible for its accuracy. RUS b$
developed guidance Bulletin 1794A-
602 for that purpose. An agency can
pennit an applicant to prepare an EA
provided the agency makes its own
evaluation of the environmental issues
and takes responsibility for the scope
and content of the EA (40 CFR
1506.5(b».
One commenter recommends that the
procedures defined in 7 CFR 194O-G
under which RUS reviews information
submitted by the applicant and
completes the assessment should be
used for Water and Waste proposals.
Agency Response: This rule provides
for an agency-prepared EA. Section
1794.41 states that the ER will normally
serve as the RUS EA. The decision of
whether RUS uses the applicant's ER as
Its EA or prepares the EA from
infonnation provided in the ER will be
made by the State Environmental
Coordinator (SEC).
Another commenter noted that by not
allowing RUS employees to complete
EAs, the agency is limiting the ability of~
Emergency Situation to account for
threats to the environment and
including a definition of "multiplexing
sites."
Agency Response: The words "or to
the human environment" have been
added to the end of the definition of
Emergency Situation and a definition
has been included in this section for
multiplexing sites.
Anothercommentersuggested
deleting the words "document and"
from the definition of ER.
Agency Response: RUS recognizes
that the amount of documentation that
can be included in an ER can vary for
the types of proposals listed in
§§ 1794.22 and 1794.23 from a few
pages to 100 pages or more. Since the
word "document" does not add any
significance to the definition of ER' the
word has been deleted.
A third commenter thought that the
terms ER, EA and Environmentallmpact
Assessment were confusing and needed
further explanation.
Agency Response: RUS agrees and ~
reverted to the tenninology used in the
existing rule. RUS has in the past and
proposes to continue to differentiate
between the documentation submitted
by the applicant for pro~ that
nonnally require an EA (§ 1794.23) and
proposals that normally require an EA
with scoping (§ 1794. 24) by titling the
fonner an ER and the later an EV AL.
The agency prepared document for
proposals listed in §§ 1794.23 and
1794.24 is still titled an EA (40 CFR
1508.9).
One commenter requested that this
section be modified so the ER and EA
can be stand-alone documents and not
a mandatOry part of the Preliminary
Engineering Report (PER) for Water and
Waste proposals. This commenter
asserts that such a restriction precludes
the use of other resources to complete
the preparation of the environmental
documentation.
Agency Response: Although RUS
intends for the ER to be submitted with
the PER for Water and Waste pro~,
there is no requirement that the ER be
prepared exclusively by the engineering
consultant that prepares the PER. The
key issue is that environmental
concerns be considered at the earliest
planning stage of a proposal to ensure
that environmental values are given
appropriate consideration. The earliest
p~ stage of a proposal is the PER.
Section 1794.8 (now § 1794. 7): Two
commenters noted that RUS Bulletin
1780-26 already has been designated for
guidance for another purpose.
Agency Response: The designations
for the guidance documents referenced
in this section have been corrected.
its employees to provide technical
assistance to rural areas.
Agency Response: RUS does not agree
with this statement. By improving the
efficiency of document preparation,
Rural Development staff will have more
time to provide meaningful guidance
and technical assistance to applicants.
Comments on Spedftc Sections
Background: One commenter
requested clarification of paragraph 9 of
the proposed rules Background section
that discusses exempting from review
approvals provided by RUS pursuant to
its loan contracts and security
instruments.
Agency Response: This comment is
addressed in the response to the first
general comment.
Section 1794.2: One commenter
questioned whether the item (d) in this
section correctly characterized the roles
RUS and the applicant play under
NEP A and the CEQ regulations. He
asserts that the applicant should be
responsible for the accuracy of the
information contained in environmental
documents and the agency should be
responsible for compliance with
appropriate regulations.
Agency Response: RUS agrees. The
text of item (d) has been changed to
clarify the role of the applicant. RUS is
responsible for compliance with NEPA,
including verifying the accuracy of the
information it uses in its environmental
review (40 CFR 1506.5). The applicant
is responsible for compliance with all
applicable RUS requirements.
Section 1794.3: Six commenters
recommended that this section clearly
state that the rule applies only to direct
loans and loan guarantee approvals.
Agency Response: This comment is
addressed in the response to the first
general comment.
Section 1794.5 (now § 1794.4): Two
commenters support the proposed
format of placing metric units in
parentheses following the non-metric
equivalents which is the reverse of the
current format. An(X:ber commenter
questioned whether the change in
metric system format w<X1ld be contrary
to the national effort to convert to the
metric system and not in compliance
with Executive Order 12770.
Agency Response: It has been RUS
experience that the current format in
which metric units are followed by the
non-metric equivalents in parentheses
has been impractical and has confused
readers. This rule's provisions for the
use of metric units comply with
Executive Order 12770.
Section 1794.7 (now § 1794.6): One
commenter suggested adding "the
environment" to the definition of
Federal Resister/Vol. 63. No. 238/Friday. December 11. 1998/Rul~ and ReguJations68652
One commenter recommended that a
standard format be developed for
applicants to follow In the preparation
of an ER or EA.
Agency Response: The appropriate
bulletins referenced In this section wll1
contain a standard format for pr'eparing
an ER: the applicant does not ~ an
EA.
The same commenter further
recommended that State DIrectors be
able to Issue supplements with less than
approval by the Administrator.
Agency Response: State Directors
have the abll1ty to Issue supplements.
However, to emure compliance with
environmental laws and regulations and
maintain uniformity with neighboring
states and within a region. requires
AdmlnJstrator review and approval of
supplements.Six commenters urged RUS to consult
with Interested parties regarding the
referenced electric arx1
telecommunications guidance
documents prior to taking 8naI action
on this rule.
Agency Response: RUS has
comidered all comments received on
the current versions of Bulletim 1794A-
600 arx11794A-601 In poeparing the
revisions to these two Bulletins. B<X.h
Bulletins wll1 be made available to
applicants via the Internet prior to ~
effective date of this final rule.
Two commenters believe that the
referenced Water arx1 Waste bulletin
(RUS Bulletin 1794A-602) should be
published fm' comment arx1 one
commenter requested a 6O-day
extension to the comment period on the
proposed rule following the rel~ of
d1at draft bulletin.
Agency Response: RUS Bulletin
1794A-602 was reviewed by Rural
Development staff prim' to the effective
date of this 8naI rule. RUS does not
agree d1at the comment period (X1 the
proposed rule should be extended
subject to the releMe of the draft
bulletin.
Section 1794.10: One commenter
recommended repladng "wx1er RUS
direct guidance and supervision" with
"wlth advise from RUS" Instead.
Agency Response: The referenced
language has bren revised. RUS will
assist applicants by outlining the types
of Information required and provide
guidance and oversight In the
development of the documentation (40
CFR 1506.5).
This commenter also recommended
d1at the language In §§ 1794.10 and
1794.31 (b) be consistent and refer to the
SEC or neither.
Agency Response: The language In
§ 1794.10 applies to all three RUS
programs. Theref~. a specific agency
official is only identified in
§ 1794.31 (b). which is speclflc to the
W8:er" and WEte ..-~.
SectIon 1794.13: 0I1e cornmenter
recommended that In (a)(3) all
comments on Water and Waste
p~ be ~t directly to the RUS
State Office imtead of through the
applicant.Agency Response: Applicant notices
must state tmt comments should be sem
to the RUS appI'OPIiate office for Water
and Waste proposals and to the
W~h1ngton. DC. office for Electric and
Telecommunications ~ls.
However. RUS reaJgntzes that both
verbal and written comments on a
proposal are sometimes directed to the
applicant. This su~ion accounts for
this ~ibllity by requlrlng the
applicant to submit comments to RUS.
Seven commenters were concerned
that the requirement In § 1794. 13(a)(4)
making all environmental documents
and documentaJon related to the
proposed action available In specific
locations w~ too broad and created an
overly burdensome and onerous
responsibility for the applicant. They
~ended that RUS narrow the
scope of Information that the applicant
is required to make available in a public
setting and require the applicant to
designate a cont-=t person to respond to
requests for additional and supJ)(X'ting
Information.
Agency Response: RUS agrees that the
requirement making all environmental
documens and documentation available
In speclflc locations creates an overly
burdensome and onerous responsibility
for the applicant and does not enhance
public JB"tictpation In the
envinxtmental process. The language in
§ 1794. 13(a) (4) has been revised. RUS
wili determine which project related
enviroomental documents will be made
available for review .. locations
convenient for the IXIblic. To ensure full
public disclosure. a list of all documents
not JX'OYided fcx- public review will be
included. Documents not provided will
be available for Inspection through a
designated RUS or applicant contact
person.Two commentelS requested that
§ 1794. 13(a) (5) be expanded to note that
public hearings are to be confined to the
environmental aspects of a proposed
action.
Agency Response: RUS believes that
the purpose of the public hearings or
mee~ has been adequately identified
Inthissectlon.
One conunenter requested that RUS
CO(XOdlnate its meetings with meetings.
hearings. and environmental reviews.
which may be held and/or required by
others.
Agency Response: RUS agrees with
this comment and has revised
§ 1794. 13(a) (5) to include coordination
of its meetings with the requirements of
other interested agencies and groups.
Six commenters questioned why RUS
has established differing threshol~ fcr
publication of notices in the Feder'a)
Register with respect to the Electric and
Telecommunications programs in
§ 1794. I 3 (b) and the Water and Waste
program in § 1794.13(c). They
recommended that the language in
§ 1794.13(c) be consistent for all three
programs.
Agency RespoI1ge: RUS agrees and hM
decided to revise the language in
§§ 1794. I 3 (b) and 1794.42(b) thereby
making the threshol~ for publication of
notices c~nt for all three programs.
RUS will provide interested agencies
with notification of Its FaNSI
determinations through direct mailings
or, at its option, the Feder'a) ReIIster,
when appropriate.
Section 1794.14: One commenter
endcrsed the flexibility provided in this
section and recommended that this
flexibility be more clearly ~. The
commenter also suggested that the
duties of a cooperating agency are
unclear and a brief list sh~d be
included.
Agency Response: The duti~ of a
cooperating agency are described in 40
CPR 1501.6 and are incorporated by
reference.
Section 1794.17: One commenter
questioned whether the mitigative
measures would be discussed In the
FONSI memo to the rue in addition to
the FONSI public notice. Two
commenters noted that the provisions of
(b) (3) appear to expand the
responsibilities of field staff beyond that
of development specialists. One
commenter suggested that a better role
for the agency would be to n~tfy the
appropriate regulatory agency to enforce
the mItigative measures.
Agency RespoI1ge: M1 tigation
measures sha1I be d~ in both the
FaNSI memo and public notice. The
responsibilities of field staff have not
been expanded. In the ~ttne process of
checking on-sIte conditions for
compliaoce with relevant loan or grant
provisIons. it is appropriate for staff to
docwnent the applicant's compliance
stabJS with regard to mitigation
measures that were agreed upon as part
of the conditions for the loan/grant. If
discrepandes are noted, the agency may
need to notify the appropriate regulaory
agency fcr action.
Section 1794.21 (a): Six commenters
recommended that in addition to
defining "emergency situation" this
68653Federal Register/Vol. 63. No. 238/Friday. I)eceIJi>er 11. 1998/Rules and Regulations
section be expanded to account for such
situations.
Agency Response: RUS has added
action (4) to account for emergency
situations.
Section 1794.21 (b): One commenter
questioned why a "detailed
description" was required for 12 actions
in this category when all actions in this
category had to be sufficiently
described. That C(Xnmenter
recommended this requirement be
deleted.
Agency Response: RUS has
determined through experience that the
types of JX"Oposals contained in this
section normally do not significantly
affect the quality of ~ human
environment. llXJS the submission of an
ER is not normally required. However,
in order to waive the ER requirement for
the 12 actions in this cMegory so
designated. ~ RUS reviewer must have
a complete description of what is being
proposed, how it will be constructed.
and the settjng in which the ~
project wiD be located. Evaluating these
12 actions on a case-by-c8se ~is is
more effective than uniformly requiring
the mandatcxy submittal of an ER.
Another commenter was concerned
that the submittal of an environmental
document was not required for
proposed actions described in
§ 1794.2 I (b) (4), (8). (14), (15) and (16).
which could under certain
circumstances provide a hazard to birds.
Agency Response: RUS agrees that
under certain circumstances actions
described in § 1794.21 (b) (4), (8), (14),
(15), and (16) could result in sIgnIficant
effects to the human environment, such
as presenting a haZM"d to birds. The
description of the facilities to be
constructed that must be provided for
these actions and others so noted in
§ 1794.21 (b) is used by RUS to
detennine whether the current level of
review is adequate or a higher level of
review is wm-ranted.
One commenter expressed concern
over the provision in action
§ 1794.21 (b) (18) which require ~
applicant oIxain certJftcation from the
utility owner that the facilities to be
purchased are in compliance with
applicable environmental laws and
regulations. This commenter believes
that the normal environmental review
process should be sufficient to identify
and resolve issues that may be
encountered.
Agency Response: RUS agrees that
obtaining a certification of compliance
for the purc~ of existing facilities is
not the app-opriate form of
documentation. Upon further review.
RUS has determined that establishing
two separate levels of review for the
purchase of existing facilities.
specifically action (18) In § 1794.21 (b)
and action (7) In § 1794.23(b), is not
warranted. Both references to these
actions have been deleted from the final
rule and replaced by new actioo (11) In
§ 1794.22(a). Under the new
requirement applicants will have the
option of submitting an ER or the results
of a facility enviromnental audit. A
higher level of review may be required
before RUS approves an applicant's
p~ of facilities that are
detelmlned to be In violation of Federal.
state. or local envirorunentallaws or
regulations.One commenter recommended that
the threshold for action described In
§ 1794.21(b)(21). standby diesel
generators, be Increased from 1
megawatt (MW) to 2 MW and also be
utilized for load management purposes
In addition to emergency power.
Agency Respor5e: RUS does not
agree. The ~ of this category Is to
exclude stardby diesel generat(X'S that
would be subject to limited use (I.e.
emergency outages). Utilizing such
facilities fCK load management purposes
Increases the hours of usage and thus
Increase potential effects to the quality
of the human envirorunent.
A commenter asserts that the action
described In § 1794.21 (b) (24) could
create a major change in local air
quality .
Agency Response: RUS agrees that
wording describing action (24) could be
misinterpreted and has added the
following statement: "Repowering or
uprating that results In an Increased fuel
consumption or tM substitution of one
fuel combustion technology with
another Is excluded from this
c~cation:' Because this actioo d~
not Include an Increase In fuel
consumption, no change In local air
quality Is anticipated.
ThIs commenter further
recommended that the type of customer
facilities covered In § 1794.21 (b) (24)
Include commercial and agricultural.
Agency Response: RUS agrees to add
commercial and agriculture facUlties to
Item (24).
Section 1794.22: Three commenters
noted th-. ~ls identified In
§ 1794.22(a)(II) and § 1794.21 (b) (20)
which discuss facilities that will reduce
the amount of pollutants rel~ Into
the environment Me redundant and tM
reference In § 1794.22 should be
deleted.
Agency Respor5e: RUS agrees that tM
requirements of § 1794.22(a)(11) and
§ 1794.21 (b) (20) are redundant.
Accordingly. action 111 In § 1794.22(a)
of the p~ rule ~ been deleted.
One commenter asserted that
proposals listed In § 1794.22(b)(3) and
(4) have the potential to Impact
Important resources but will be
excluded from environmental review.
Agency Response: Applicants are
required to prepare and submit an ER
for all proposed actions listed in
§ 1794.22(b). RUS will review the ER to
detenn Ine whether a noImally
categorically excluded ~tlon may have
a significant environmental effect (40
CFR 1508.4).
One commenter suaested d\at
§ 1794.22(c) belongs in § 1794.23 which
describes EA proposals.
Agency Response: Proposals listed In
§ 1794.22(c) were so designated to
parallel the level of documentation
required by the EPA In 40 CFR 6.505(c)
for slmUar proposals. Agencies with
similar programs .-e el1COUraged by
CEQ to comult with each other to
coCX'dinate their procedures. especially
for programs requesting slmUar
lnf0rm8:.ion from applicants (40 CFR
1507.3(a». RUS believes that these
actions are correctly described in
§ 1794.22(c).
One commenter noted that
§ 1794.22(c)(1) and (2) only apply to
discharges and need to be expanded to
Include water withdrawals.
Agency Respol6e: RUS agrees and has
expanded the discussion In § 1794.22(c)
to clarify this issue.
Two comrnenters requested that
"substantial ~" In § 1794.22
(c)(2) be def"med and one commenter
also questioned how this term applied
to a new facility.
Agency Response: The term
"substantial increases" has not been
defined because Its interpretation
depends on local conditions and
regulatory requirements. RUS agrees
that this ~tion should not Include new
facUlties and has revised the language
accordIng1y.
One commenter noted that § 1794.22
(c) (3) stipulates no greater than a 30
percent growth factor whereas § 1794.22
(b)(3) stipulates a modest growth
potential and requests consistency
within the rule.
Agency Respo~e: The 30 percent
growth f~tor ts an established
threshold, whereas the term "modest
growth" applies to local conditions and
regulatory requirements.
Anod1er comment« ~ that the
thresholds in § 1794.22(c)(3) need to be
changed because It appears that a small
system (20-30 EDU's) could be
expanded up to 500 EDU's and still be
a categorically excluded proposal.
Agency Response: RUS believes the
capacity criteria as stated is sufficient
f(X" the ~ of cl~lfvtna an action
expanded to allow the adoption of
environmental documents prepared by
state or local agencies or other parties in
accordance with the provisions of
§ 1794.84 of the existing regulation.
Agency Response: The CEQ
regulations in 40 CFR 1506.3 only
pemtit a Federal agency to adopt
documents prepared by or for another
Federal Agency. In 40 CFR 1506.2,
Federal agencies are required to
cooperate with state and local agencies
to the fullest extent possible to reduce
duplication between NEP A and state
and local requirements by jointly
preparing EAs and EIs.~. RUS
acknowledges that its policy on the
incorporation of environmental
documents prepared by others was
omitted from the proposed rule. This
o~ion has been corrected with the
addition of § 1794.74.
One commenter suggested that RUS
be more flexible in its adoption
procedures and not duplicate another
agency's public notice and comment
period.
Agency Response: RUS believes that
its decisions must be subject to public
notification regardless of who prepares
the environmental documentation. The
preferred strategy to avoid duplication
of effort would be foc RUS to participate
with other agencies in the preparation of
the initial environmental documents as
stated in § 1794.14.
This commenter also recommended
that RUS accept environmental
documents prepared by states under the
State Revolving Fund (SRF) programs as
its own documents or at a minimum
adopt the subject documents.
Agency Response: RUS may adopt
environmental documents prepared by
state agencies administering SRF
programs under the Clean Water Act (32
U.S.C. 1251) arKi the Safe Drinking
Water Act (42 U.S.C. 300). Where
appropriate, the State Director will enter
into an agreement with appropriate state
agencies to establish the necessary
procedures.
Any environmental document
accepted or prepared by RUS prior to
the effective date of these regulations
may be developed in accordance with
RUS environmental requirements in
effect at the time the document was
accepted or prepared by RUS.
Us! of Subjects in 7 CFR Part 1780
Business and industry. Community
development. Community facilities,
Grant programs-housing and
community development. Reporting and
recordkeeping requirements. Rural
areas, Waste treatment and disposal,
Water supply, Watersheds.
as a categorical exclusion. Two other
provisions may be applicable to the
commenter's point. First, the ER would
provide sufficient information to
detemtine if there are any extraordinary
circumstances in which a normally
categorically excluded action may have
a signIficant environmental effect (see
40 CFR 1508.4). Second, under
§ 1794.22(b)(2), RUS could determine
that the facility improvements are not
modest in use, size, capacity, purpose,
or location and would require an EA.
Section 1794.23: One commenter
recommended that for consistency, this
section be titled "Proposals normally
requiring an EA without scoping.' ,
Agency Response: RUS disagrees.
Early public involvement may be
appropriate for any level of
environmental review and should not be
explicitly dismissed by excluding
scoping for certain thresholds.
Section 1794.31: One commenter
stated that RUS should not be
supervising or giving direct guidance to
the applicant. He suggested modifying
the wording in (b) to "with advice from
RUS."
Agency Response: This issue is
addressed in the response to the
comment on § 1794.10.
Another commenter noted that ~
SEC would be unable to devote the time
necessary to supervise all applicants.
Agency Response: High volume states
have been provided additional
environmental specialist positions in
anticipation of the increased workload.
Section 1794.32: One commenter
wanted clarification in (b) on the criteria
used to determine when public notice
would be required if important land
resources are affected Ano~r
commenter suggested that in (b)
reference should be made to § 1794.7 or
the RUS Bulletin 1794A-602.
Agency Response: RUS agrees with
this suggestion and has referenced the
two bulletins that provide guidance in
preparing an ER.
Section 1794.33: One commenter
noted that this section allows RUS to act
on an application without any
environmental review.
Agency Response: The commenter's
interpretation of § 1794.33 is incon'ect.
RUS shall conduct an environmental
review for all proposed actions covered
by this section. Proposals listed in
§ 1794.21 (b) and (c) normally require
the submittal of a project description.
~reas, proposals listed in
§ 1794.22(a) and (b) normally require
the submittal of an ER. RUS reserves the
right to require additional
environmental information on any
proposal the agency believes may have
significant effects on the quality of the
human environment (§ 1794.30).
Section 1 794.41: One commenter
noted that the typical applicant would
need ~istance from their consulting
engineer in preparing the ER, resulting
in a fee increase to the applicant. If the
SEC retains approval authority for the
ER, another layer of review is added
before the ER is accepted.
Agency Response: RUS anticipates
that the applicant's engineer will
prepare the ER at the same time that
project planning is done. RUS further
antidpates that any increase in the
engineering fee should be modest since
the engineer in m~t projects has been
preparing the applicant's environmental
information for the agency. The SEC
should be the only agency approval
official fcr the ER.
Section 1794.44: Two commenters
noted that it appears RUS will take final
action on proposals covered by this
section without waiting for public
input.
Agency Response: Actions listed in
§ 1794.23 are subject to public input
when the EA is made available for
review through applicant notice.
Normally there is no provision for
additional public input when RUS
makes a FONSI determination for
actions listed in § 1794.23.
These commenters also noted that
draft RUS Bulletin 1794A-602 calls for
a IS-day review period if significant
comments are received on the draft EA.
Agency Response: The reference to
the IS-day review period was
inadvertently omitted from the
proposed rule. Section 1794.44 has been
modified to include an opportunity for
the public to review the RUS FONSI
determination if substantive comments
are received on the EA.
Section 1 794.51: One commenter
noted that no mention is made in (a)
where the applicant's notice will be
published.
Agency Response: The commenter is
colTect that § 1794.51 does not state
where the applicant's notice will be
published. That information is provided
in § 1794.13(a)(I) and (2).
Section 1794.61: Two commenters
asserted that the cost of an EIS would
be prohibitive for nearly all Water and
Waste applicants which could result in
even high priority projects being
canceled due to the inability of the
applicant to fund the EIS.
Agency Response: RUS agrees that an
EIS can be an expensive document to
prepare and has identified certain
methods of funding an EIS in
§1794.61(a).
Section 1794.70: One commenter
recommends that this section be
Federal Register/Vol. 63. No. 238/Friday. December II. 1998/Rules and Regulations 68655
List of Subjects in 7 CFR Part 1794
Environmental Impact statements,
Reporting and recordkeeping
requirements.
Therefore RUS amends chapter XVII
of title 7 of the Code of Federal
Regulations as follows:
PART 178O-WATER AND WASTE
LOANS AND GRANTS
Subpart B-Loan and Grant
Application Processing
1. Section 1780.31 Is amended by
revising paragraph (e) to read as follows:
11780.31 G81-.1.
* * * * *
(e) Starting with the earlIest
discussIon with prospective applicants,
the State Environmental Coordinator
shall discuss with prospective
applicants and be available for
consultation during the applIcation
process the environmental review
requIrements for evaluating the
potential environmental consequences
of the project. Pursuant to 7 CFR part
1794 and guidance in RUS Bulletin
1794A-602, the environmental review
requIrements shall be performed by the
applicant simultaneously and
concurrently with the project's
engineering planning and design. This
should provide flexibility to consider
reasonable alternatives to the project
and development methods to mitigate
IdentIfied adverse environmental
effects. Mitigation measures necessary
to avoid or minimize any adverse
environmental effects must be
integrated into project desIgn.
2. Section 1780.33 Is amended by
revising paragraphs (c)(3), and (0 to read
as follows:
11780.33 Applcatlon requ~nts.
* * * * *
(c) * * *
(3) The State staff engineer will
consult with the applicant's engineer as
appropriate to resolve any questions
concerning the PER. Written comments
will be provIded by the State staff
engineer to the processing office to meet
eligibility determination time lines.
* * * * *
(0 Environmental Report. For th~e
actions listed in §§ 1794.22(b) and
1794.23(b), the applIcant shall submit.
in accordance with RUS Bulletin
1794A-602. two copIes of the
completed Environmental Report.
(I) Upon receipt of the Environmental
Report. the processing office shall
forward o~ copy of the report with
comments and recornmeJx1ation to the
State Environmental Coordinator for
review.
(2) The State Environmental
Coordinator will consult with the
applicant as appropriate to resolve any
environmental concerns. Written
comments will be provided by the State
Environmental Coordinator to the
processing office to meet eligibillty
determination time lines.
* * * * *
3. Section 1780.39 is amended by
revising paragraph (b) introductory text
and removing and revising paragraph
(h).
t 1780.39 Application ~ng.
* * * * *
(b) Professional services and contracts
related to the facility. Fees provided for
in contracts or agreements shall be
reasonable. The Agency shall consider
fees to be ~nable if they are not in
excess of those ordinarily charged by
the profession as a whole for similar
work when RUS financing is not
involved. Applicants will be responsible
for providing the services necessary to
plan projects including design of
facilities. environmental review and
documentation requirements.
preparation of c~t and income
estimates. development of proposals for
organization and financing. and overall
operation and maintenance of the
facility. Applicants should negcx.iate for
procurement of professional services.
whereby competitors' qualifications are
evaluated and the most qualified
competitor is selected. subject to
negotiations of fair aJxi reasonable
compensation. Contracts or other forms
of agreement between the applicant and
its professional and technical
representatives are required and are
subject to RUS concurrence.
* * * * *
4. Section 1780.41 is amended by
revising paragraph (a) (8) to read as
follows:
t 1780.41 lo8I or gr8rt .IXOV8L
(a) * * *
(8) Completed environmental review
documents including copies of public
notices and appropriate proof of
publication. if applicable; and
* * * * *
SUBPART C-PLANNING, DESIGN,
BIDDING, CONTRACTING,
CONSTRUCTING AND INSPECTIONS
5. Section 1780.55 is revised to read
as follows:
§ 1780.55 Prelmlnary "gI~ reports.
Preliminary engineering reports and
Environmental Reports. Preliminary
engineering reports (PERs) must
conform to customary professional
standards. PER guidelines for water,
sanitary sewer, solid waste, and storm
sewer are available from the Agency.
Environmental Reports must meet the
policies and intent of the National
Environmental Policy Act and RUS
procedures. Guidelines foc preparing
Environmental Reports are available in
RUS Bulletin 1794A-602.
6. Section 1780.57 is amended by
revising paragraph (a) to read as follows:
11780.57 o.lgn~
* * * * *
(a) Environmental review. Facilities
financed by the Agency must undergo
an environmental impact analysis in
accordance with the National
Environmental Policy Act and RUS
procedures. Facility planning and
design must not only be responsive to
the owner's needs but must consider the
environmental consequences of the
proposed project. Facility desIgn shall
incorporate and integrate, where
practicable, mitigation measures that
avoid or minimize adverse
environmental impacts. Environmental
reviews serve as a means of assessing
environmental impacts of JX"Oject
proposals, rather than justifying
decisions already made. Applicants may
not take any action on a project proposal
that will have an adverse environmental
impact or limit the choice of reasonable
project alternatives being reviewed prior
to the completion of the Agency's
environmental review.
* * * * *
7. Part 1794 is revised to read as
follows:
PART 1794-ENVIRONMENTAL
POLICIES AND PROCEDURES
Subpart A-GeneraI
Sec.
1794.1 Purpose.
1794.2 Authority.
1794.3 Actions requiring environmental
review.
1794.4 Metric units.
1794.5 Responsible officials.
1794.6 Definitions.
1794.7 Guidance.
1794.8-1794.9 (Reserved)
Subpart &-Implementation of the National
Environmental Policy Act
1794.10 Applicant responsibilities.
1794.11 Apply NEP A early in ~ planning
process.
1794.12 Consideration of alternatives.
1794.13 Public involvement.
1794.14 Interagency involvement and
coordination.
1794.15 Umttations on actions during the
NEP A ~.
1794.16 Tiering.
1794.17 Mitigation. of NEP A (40 CFR parts 1500 through 11794.3 Aetion8 requhing environmental
1794.18-1794.19 [Reserved) 1508) and certBin related Federal review.
Subpart c-claslflcatlon of Propos8i8 environmental laws, statutes, The provisions of this part apply to
1794 20 Co 1 regulations, and Executive Orders (EO) actions by RUS including the approval
1794:21 Ca."etrorlcall excluded proposals that apply to RUS programs and of financial assistance pursuant to the
without ~ ER. Y administrative actions. Electric, Telecommunications, and
1794.22 Categorically excluded proposals (b) The policies and procedures Water and W~te Programs, the disposal
requiring an ER contained in this part are intended to of property held by RUS pursuant to
1794.23 Proposals normally requiring an help RUS officials make decisions that such programs, and the issuance of new
EA. are based on an understanding of or revised rules, regulations, and
1794.24 Proposals nonnally requiring an environmental consequences, and take bulletins. Approvals provided by RUS
EA with scoping. . actions that protect, restore, and pursuant to loan contracts and security
179~ Proposals nonnally requ1rms an enhance the environment. In MsesSing instruments, including approvals of lien
1794.2~ 1794.29 (Reserved] the potential environmental impacts of accommodations, are not actions for the
its actions, RUS will consult early with purposes of this part and the provisionsSubpart c-.-R;-~ure for Categ0ric8 appropriate FederaL State, and local of this part shall not apply to the
Exdll8lons agencies and other organizations to exercise of such approvals.
1794.30 Ge~ral. provide decision-makers with
1794.31 Classification. information on the issues that are truly 11794.4 Metric ~
1794.32 Environm~tal report. significant to the action in question. RUS normally will prepare
1794.33 Agency action. environmental documents using non-
1794.34-1794.39 [Reserved] 11794.2 Authortty. metric equivalents with one of the
Subpart E-Procedure for Environmental (a) This part derives its authority from following two options; metric units in
Assessments and is intended to be compliant with parentheses immediately following the
1794.40 Ge~ral. NEP A, CEQ Regulations for non-metric equivalents or a metric
1794.41 Document requirements. Implementing the Procedural Provisions conversion table as an appendix.
1794.42 Notice of a~ilability. of NEP A. and other RUS regulations. Environmental documents prepared by
1794.43 Agency fmdmg. (b) Where practicable, RUS will use or for a RUS applicant should follow the
1794.44 Timing of agency action. NEP A analysis and documents and same format.
1794.45-1794.49 (Reserved]i d t .
t te therev ew proce ures 0 m egra
Subpart F-Procedure for Environmental requirements of related environmental 11794.5 Responsible officials.
.cA~...sments WIth Scoping statutes, regulations, and orders. The Administrator of RUS has the
1794.50 NomJal sequence. (c) This part integrates the responsibility for Ageocy compliance
1794.51 Preparation for scoplng. requirements of NEP A with other with all environmental laws,
1794.52 Scoping meetings. planning and environmental review regulations, and EOs that apply to RUS
1794.53 Environmental analysis. procedures required by law or by RUS programs and administrative actions.
1794.54 Agency determination. practice including oot not limited to: Responsibility for ensuring
1794.55-1794.59 (Reserved] (1) Endangered Species Act of 1973 environmental compliance for actions
Subpart G-Procedure for Environmental (16 U.S.C. 1531 et seq.); taken by RUS has been delegated as
aped Stat8nent8 (2) The National Historic Preservation follows:
1794.60 Normal sequence. Act (16 U.S.C. 470 et seq.); (a) Electric and Telecommunications
1794.61 Environmental impact statement. (3) Farmland Protection Policy Act (7 Programs. The appropriate Assistant
1794.62 Supplemental EIS. U.S.C. 4201 et seq.); Administrator is responsible for
1794.63 Record of decision. (4) E.O. 11593, Protection and ensuring compliance with this part for
1794.64 Timing of agency action. Enhancement of the Cultural the respective programs.
1794.65-1794.69 [Reserved] Environment (3 CFR, 1971 Comp., p. (b) Water and Waste Program. The
SubpartH -AdoptIon of EnvWonmental 154); Assistant Administrator for this program
Docum8lts (5) E.O. 11514, Protection and is responsible for ensuring compliance
1794. 70 Ge~ral. Enhancement of Environmental Quality with this part at the national level. The
1794.71 Adoption of an EA. (3 CFR, 1970 Comp., p. 104); State Director is the responsible official
1794.72 Adoption of an ElS. (6) E.O. 11988, Floodplain for ensuring compliance with this part
1794.73 Timing of agency action. Management (3 CFR. 1977 Comp., p. for actions taken at the State Office
1794.74 ~ration of environnM!ntal 117); level.
materials. (7) E 0 11990 Protection of Wetlands
1794.75-1794.79 (Reserved] (3 CFR: 1977 Co~p., p. 121); and 11794.8 Definitions.
Authority: 7 V.S.C. 6941 et SftJ., 42 V.S.C. (8) E.O. 12898, Federal Actions to The following definitions, as well as
4321 et SftJ.; 40 CFR Parts 1500-15~. Address Environmental justice in the definitions contained in 40 CFR part
Subpart A-General Minority Populations and Low-Income 1508 of the CEQ regulations, apply to
Populations (3 CFR, 1994 Comp.. p. the implementation of this part:
11794.1 Pwpo". 859). Applicant. The organization applying
(a) This part contains the policies and (d) Applicants are responsible for for financial assistance or other
procedures of the Rural Utilities Service ensuring that proposed actions are in approval from either the Electric or
(RUS) for implementing the compliance with all appropriate RUS Telecommunications programs or the
requirements of the National requirements. Environmental organization applying for a loan or grant
Environmental Policy Act of 1969 documents submitted by the applicant from the Water and W~te program.
(NEPA), as amended (42 U.S.C. 4321- shall be prepared under the oversight Construction Work Plan (CWP). The
4346); the Council on Environmental and guidance of RUS. RUS wili evaluate document required by 7 CFR part 1710.
Quality (CEQ) Regulations for and be responsible for the accuracy of Emergency Situation. A natural
Implementing the Procedural Provisions all information contained therein. disaster or system failure that may
Federal Register/Vol. 63. No. 238/Friday. December 11. 1998/Rules and Regulations 68657
involve an immediate or imminent
threat to public health, safety, or the
human environment.
Environmental Analysis (EVAL). The
document submitted by the applicant
for proposed actions subject to
compliance with § 1794.24 and w)cfer
special circumstances § 1794.25.
Environmental Report (ER). The
environmental documentation nonnally
submitted by applicants for proposed
actions subject to compliance with
§§ 1794.22 and 1794.23. An ER for the
Water and W ~te Program refers to the
environmental review documentation
nonnally included as part of the
Preliminary Engineering Report.
Environmental review. Any one or all
of the levels of environmental analysis
described under subpart C of this part.
Equivalent Dwelling Unit (EDU). Level
of water or w~te service provided to a
typical rural residential dwelling.
hnportant Land Resources. Defined
pursuant to the U.S. Department of
Agriculture's Departmental Regulation
9500-3, Land Use Policy, as important
fannland, prime forestland, prime
rangeland, wetlands, and floodplains.
Copies of this Departmental Regulation
are available from USDA, Rural Utilities
Service, Washington, DC 20250.
Loan Design. Document required by 7
CFR part 1737.
Multiplexing Center. A field site
where a telecommunications provider
houses a device that combines
individual subscriber circuits onto a
single system for economical connection
with a switching center. The combiner,
or "multiplexer," may be m(X1nted on a
pole, on a concrete pad, or in a partial
or full enclosure such ~ a shelter, or
small building.
Natural Resource Management Guide.
Inventory of natural resources, land
uses, and environmental factors
specified by Federal, State, and local
authorities ~ deserving some degree of
protection or special consideration. The
guide describes the standards or types of
protection that apply.
PrelimlnaJy Engineering Report (PER).
Document required by 7 CFR part 1780
for Water and Waste Programs. A PER
is prepared by an applicant's
engineering consultant documenting a
proposed action's preliminary
engineering plan and design and the
applicable environmental review
activities as required in this part. Upon
approval by RUS, the PER, or a portion
thereof, shall serve as the RUS
environmental document.
Supervisory Control and Data
Acquisition System (SCADA). Electronic
monitoring and control equipment
installed at electric su~tations and
switching stations.
Third party Consultant. A party
selected by RUS to prepare the EIS for
proposed actions described in § 1794.25
where the applicant initiating the
p~l agrees to fund preparation of
the document in accordance with the
provisions of 7 CPR Part 1789. "Use of
Consultants Funded by Borrowers" and
Section 759A of the Federal Agriculture
Improvement and Refonn Act of 1996 (7
U.S.C. 2204b(b».
t 1714.7 Guidance.
(a) Electric and Telecommunications
Programs. For further guidance in the
preparation of public notices and
environmental documents, RUS has
prepared a series of program specific
guidance bulletins. RUS Bulletin
1 794A-600 provides guidance in
preparing the ER for proposed actions
classified as categorical exclusions (CEs)
(§ 1794.22(a» and RUS Bulletin l794A-
601 provides guidance in preparing the
ER for pro~ actions which require
EAs (§ 1 794.23(b) Telecommunications
only and (c»;. Copies of these bulletins
are available upon request by contacting
Rural Utilities Service, Publications
Office, PDRA. Stop 1522; 1400
Independence Avenue, SW;
Washington, DC 2025(}-1522.
(b) Water and Waste Program. RUS
Bulletin l794A-602 provides guidance
in preparing the ER for propmed actions
classified ~ CEs (§ 1 794.22 (b» and EAs
(§ l794.23(b». A copy of this bulletin is
available upon request by contacting the
appropriate State Director. State
DireCtors may provide supplemental
guidance to meet state and local laws
and regulations and to provide for
orderly application procedures and
efficient service to applicants. State
DireCtors shall obtain the
Administrator's approval for all
supplements to RUS Bulletin l794A-
602. Each State Office shall maintain an
updated Natural Resource Management
Guide and provide applicants with
pertinent sections or a copy of the
current edition thereof.
H 1794.8-1794.9 (Reserved)
Subpart B-Implementation of the
National Environmental Policy Act
t 1794. 1 0 Applicant F88ponstilties.
As described in subpart C of this part,
applicants shall prepare the applicable
environmental documentation
concurrent with a proposed action's
engineering. planning. and design
activities. RUS shall assist applicants by
outlining the types of information
required and shall provide guidance and
oversight in the development of the
documentation. Documentation shall
not be considered complete until all
public review periods, as applicable,
have expired and RUS concurrence, as
set forth in the appropriate decision
document and associated public notice,
has been issued.
, 1794.11 Apply NEPA 88rIy kI the
plannkig process.
The environmental review process
requires early coordination with and
involvement of RUS. Applicants should
consult with RUS at the earliest stages
of planning for any proposal that may
require RUS action. For proposed
actions that normally require an EIS,
applicants shall consult with RUS prior
to obtaining the services of an
environmental consultant.
, 1794. 12 ConaId.-a1Ion of alternatives.
In detennining what are re~onable
alternatives, RUS considers a number of
factors. These factors may include, but
are not limited to, the proposed action's
size and scope, state of the technology,
economic considerations. legal and
socioeconomic concerns, availability of
resources, and the timeframe in which
the identified need must be fulIllled.
§ 1794.13 ~IIC Invotveln8lt.
(a) In carrying out its responsibilities
under NEPA, RUS shall make diligent
efforts to involve the public in the
environmental review process through
public notices and public hearings and
meetings.
(I) All public notices required by this
part shall describe the nature, location.
and extent of the pro~d action and
indicate the availability and location of
additional information. They shall be
published in newspaper(s) of general
circulation within the proposed action's
area of environmental impact and the
county(s) in which the proposed action
will take place or such other places as
RUS determines.
(2) The number of editions in which
the notices should be published will be
specified in the Bulletins referenced in
§ 1794.7 or established on a project-by-
project basis. Alternative forms of notice
may also be necessary to ensure that
residents located in the area affected by
the proposed action are notified. The
applicant should not publish notices for
compliance with this part until so
notified by RUS.
(3) A copy of all comments received
by the applicant concerning
environmental aspects of the proposed
action shall be provided to RUS in a
timely manner. RUS and applicants
shall ~ and consider public
comments both individually and
collectively. Responses to public
comments will be appended to the
applicable environmental document.
68658 Federal Resister/Vol. 63. No. 238/Friday. December 11. 1998/Rules and Regulations
-- -
(4) RUS and applicants shall make
available to the public those project
related environmental documents that
RUS determines will enhance public
participation in the environmental
process. These materials shall be placed
in locations convenient for the public as
determined by RUS in consultation with
applicants. Included with the
documentation shall be a list of other
project-related information that shall be
available for inspection through a
designated RUS or applicant contact
person.
(5) Public hearings or meetings shall
be held at reasonable times and
locations concerning environmental
aspects of a proposed action in all cases
where. in the opInion of RUS. the need
for h~ or meetings is indicated in
order to develop adequate infonnation
on the environmental implications of
the proposed action. Public hearings or
meetings conducted by RUS will be
coordinated to the extent practicable
with other meetings. hearings. and
environmental reviews which may be
held or required by other Federal. state
and local agencies. Applicants shall. as
necessary. participate in all RUS
conducted public he~ or meeting.
(6) Scoping procedures. in accordance
with 40 CFR 1501.7. are required for
proposed actions normally requiring an
EA with scoping (§ 1794.24) or an EIS
(§ 1794.25). RUS may require scoping
procedures to be followed for other
proposed actions where appropriate to
achieve the purposes ofNEPA.
(b) The applicant shall have public
notices described in this section
published in a newspaper(s). Applicants
shall obtain proof of publication from
the newspaper(s) for inclusion into the
applicable environmental document.
Where the proposed action requires an
EIS RUS shall, in addition to applicant
published notices. publish notice in the
Federal Register. In all cases. RUS may
publish notices in the Federal Resister
as appropriate.
S 1794.14 ~ncy i~Iv8nMt 8Id
coordination.
In an attempt to reduce or eliminate
duplication of effort with state or local
procedures. RUS will, to the extent
possible and in accordance with 40 CFR
1506.2. actively participate with any
governmental agency to cooperatively or
jointly prepare environmental
documents so that one document will
comply with all applicable laws. wme
RUS has agreed to participate as a
cooperating agency. in accordance with
40 CFR 1501.6. RUS may rely upon the
lead agency's procedures for
implementing NEP A procedures. In
addition. RUS shall request that
(a) The lead agency indicates that
RUS is a cooperating agency in all
NEPA-related notices published for the
proposed action:
(b) The scope and content of the EA
or EIS satisfies the statutory and
regulatory requirements applicable to
RUS; and
(c) The applicant shall infonn RUS in
a timely manner of its involvement in a
proposed action where another Federal
agency is preparing an environmental
document so as to pennit RUS to
adequately fulfill its duties as a
cooperating agency.
f 1794.15 UInIt8IIGn8 ~ actions during
the NEPA pr1)C8SS.
(a) General. Until RUS concludes its
environmental review process. the
applicant shall take no action
concerning the proposed action which
would have an adverse environmental
impact or limit the choice of reasonable
alternatives being considered in the
environmental review process (40 CPR
1506.1).
(b) Electric Program. In detennining
which applicant activities related to a
proposed action can proceed prior to
completion of the environmental review
process. RUS must detennine. among
other matters that
(1) The activity shall not have an
adverse environmental impact and shall
not preclude the seM'ch for other
alternatives. For example. purchase of
water rights. optioning or transfer of
land title. or continued use of land as
historically employed will not have an
adverse environmental impact.
However. site preparation or
construction at or near the proposed site
(e.g. rail spur) or development of a
related facility (e.g. opening a captive
mine) normally will have an adverse
environmental impact.
(2) Expenditures are minimal. To be
minimal, the expenditure must not
exceed the amount of loss which the
applicant could a~rb without
jeopardizing the Government's security
interest in the event the proposed action
is not approved by the Administrator.
and must not compromise the
objectivity of RUS environmental
review. Not withstanding other
considerations. expenditures equivalent
to up to 10 percent of the proposed
action's cost mrmally will not
compromise RUS objectivity.
Expenditures for the purpose of
producing documentation required for
RUS environmental review are excluded
from this limitation.
11794.18 Tlertng.
It is the policy of RUS to prepare
programmatic level analysis in order to
tier an EIS and an EA where:
(a) It is practicable, and
(b) There will be a reduction of delay
and paperwork, or where better decision
making will be fostered (40 CFR
1502.20).
11794.17 Mitigation.
(a) General. In addition to complying
with the requirements of 40 CFR
1502.1400, it is RUS policy that a
discussion of mitigative measures
essential to render the impacts of the
proposed action not significant will be
included in or referenced in the Finding
of No Significant Impact (FONSI) and
the Record of Decision (ROD).
(b) Water and Waste Program. (1)
Mitigation measures which involve
protective measures for environmental
resources cited in this part or
restrictions or limitations on real
property located in the service areas of
the propOsed action shall be negotiated
with applicants and any relevant
regulatory agency so as to be
enforceable. All mitigation measures
incorporating land use issues shall
recognize the rights and responsibilities
of landholders in making private land
use decisions and recognize the
responsibility of governments in
influencing how land may be used to
meet public needs.
(2) Mitigation measures shall be
included in the letter of conditions.
(3) RUS has the responsibility for the
post approval construction or security
inspections or monitoring to ensure that
all mitigation measures included in the
environmental documents have been
implemented as specified in the letter of
conditions.
H 1794.18-1794.19 (R...ved)
Subpart C-Classlfication of Proposals
11794.20 Control.
Electric and Telecommunications
Programs. For environmental review
purposes, RUS has identified aJxi
established categories of proposed
actions (§§ 1794.21 through 1794.25).
An applicant may propose to participate
with other parties in the ownership of
a project where the applicant(s) does not
have sufficient control to alter the
development of the project. In such a
case, RUS shall determine whether the
applicant participants have sufficient
control and responsibility to alter the
development of the proposed project
prior to determining its classification.
Where the applicant proposes to
participate with other parties in the
Federal Register/Vol. 63, No. 238/Friday, December II, 1998/RuIes and Regulations 68659
ownership of a proposed project and all
applicants cumulatively own:
(a) Five percent or less of a project is
not considered a Federal action subject
to this part;
(b) Thirty-three and one-third percent
or more of a project shall be treated in
its usual category;
(c) More than five percent but less
than 331/3 percent of a project, RUS shall
determine whether the applicant
participants have sufficient control and
responsibility to alter the development
of the proposal such that RUS's action
will be considered a Federal action
subject to this part. Consideration shall
be given to such factors as:
(1) Whether construction would be
completed regardless of RUS financial
~istance or approval;
(2) The stage of planning and
construction;
(3) Total participation of the
applicant;
(4) Participation percentage of each
utility; and
(5) Managerial arrangements and
contractual provisions.
t 1794.21 Cat8goricanyexcluded
.-oPOS88- ~ an ER.
(a) General. Certain types of actions
taken by RUS do not normally require
an ER. Proposed actions within this
classification are:
(1) The issuance of bulletins and
information publications that do not
concern environmental matters or
substantial facility design, construction,
or maintenance practices;
(2) Procurement activities related to
the operation of RUS;
(3) Personnel and administrative
actions; and
(4) Repairs made because of an
emergency situation to return to service
damaged facilities of an applicant's
system.
(b) Electric and TelfN:Ommunlcations
Programs. Applications for financial
~istance for the types of proposed
actions listed in this paragraph (b)
normally do not require the submission
of an ER. These types of actions are
subject to the requirements of § 1794.31.
Applicants shall sufficiently identify all
proposed actions so their proper
classification can be determined.
Detailed descriptions shall be provided
for each proposal noted in this section.
RUS normally requires additional
information in addition to a description
of what is being proposed, to ensure that
proposals are properly classified. In
order to provide for extraordinary
circumstances, RUS may require
development of an ER for proposals
listed in this section. Proposed actions
within this classification are:
(1) Purchase of land where use shall
remain unchanged, or the purch$e of
existing water rights where no
associated construction is involved;
(2) Additional or substitute financial
assistance for pro~ actions which
have previously ~eived environmental
review and approval from RUS,
provided the scope of the proposal and
environmental considerations have not
changed;(3) Rehabilitation or reconstruction of
transportation facilities within existing
rights-of-way (ROW) or generating
facility sites. A desaiption of the
rehabilitation or reconstruction shall be
provided to RUS;
(4) Changes or additions to microwave
sites, substations. switching stations,
telecommunications switching or
multiplexing centers. bwldings. or small
structures requiring new physical
disturbance or fencing of less than one
acre (0.4 hectare). A description of the
additions or changes and the area to be
impacted by the expansion shall be
provided to RUS;
(5) Internal modifications or
equipment additions (e.g., computer
facUities. relocating interior walls) to
structures or buildings;
(6) Internal or minor external changes
to electric generating or fuel processing
facUities and related support structures
where there is negligible impact on the
outside environment. A description of
the changes shall be provided to RUS;
(7) Ordinary maintenance or
replacement of equipment or small
structures (e.g.. line support structures,
line transformers. microwave facilities,
telecommunications remote switching
and multiplexing sites);
(8) The construction of
telecommunications facilities within the
fenced area of an existing substation.
switching station. or within the
boundaries of an existing electric
generating facility site. A description of
the facilities to be constructed shall be
provided to RUS;
(9) SCADA and energy management
systems involving no ~w external
construction;
(10) Testing or monitoring work (e.g.,
soil or rock core sampling, monitoring
wells. air monitoring);
(11) Studies and engineering
undertaken to define propmed actions
or alternatives sufficiently so that
environmental effects can be assessed;
(12) Construction of electric power
lines within the fenced area of an
existing substation, switching station. or
within the boundaries of an electric
generating facility site;
(13) Contracts for certain items of
eqwpment which are part of a proposed
action for which RUS is preparing an
EA or EIS, and which meet the
limitations on actions during the NEP A
process as established in 40 CFR
1506.1 (d) and contained in
§ 1794. 15(b)(2);
(14) Rebuilding of power lines or
telecommunications cables where road
or highway reconstruction requires the
applicant to relocate the lines either
within or adjacent to the new road or
highway easement or right -of-way. A
description of the facilities to be
constructed shall be provided to RUS;
(15) Phase or voltage conversions,
reconductoring or upgrading of existing
electric distribution lines, or
telecommunication facilities. A
description of the facilities to be
constructed shall be provided to RUS;
(16) Construction of new power lines,
substations, or telecommunications
facilities on industrial or commercial
sites, where the applicant has no control
over the location of the new facilities.
Related off-site facilities would be
treated in their normal category. A
description of the facilities to be
constructed shall be provided to RUS;
(17) Participation by an applicant(s)
in any proposed action where total
applicant financial participation wilt be
five pa:cent or less;
(18) Construction of a battery energy
storage system at an existing generating
station or substation site. A description
of the facilities to be constructed shall
be ~ded to RUS.
(19) Additional bulk commodity
storage (e.g., coal, fuel oil, limestone)
within existing generating station
boundaries. A certification attesting to
the current state of compliance of the
existing facilities and a description of
the facilities to be added shali be
provided to RUS;
(20) Proposals designed to reduce the
amount of pollutants released into the
environment (e.g., precipitators,
baghOU5e or scrubber installations, and
coal washing equipment) which will
have no other environmental impact
outside the existing facility site. A
description of the facilities to be
constructed shall be provided to RUS;
(21) Construction of standby diesel
electric generators (one megawatt or less
total capacity) and associated facilities,
for the primary purpose of providing
emergency power, at an existing
applicant headquarters or district office,
telecommunications switching or
multiplexing site, or at an industrial,
commercial or agricultural facility
served by the applicant. A description
of the facilities to be constructed shall
be provided to RUS;
(22) Construction of onsite facilities
designed for the transfer of ash, scrubber
wastes, and other byproducts from coal-
68660 Federal Register/Vol. 63. No. 238/Friday. December 11. 1998/Rules and Regulations
fired electric generating stations for
recycling or storage at an existing coal
mine (surface or underground). A
description of the facilities to be
constructed shall be provided to RUS:
(23) Changes or additions to an
existing water well system, including
new water supply wells and associated
pipelines within the boundaries of an
existing well field or generating station
site. A description of the changes or
additions shall be provided: and
(24) Repowering or uprating of an
existing unit(s) at a fossil-fueled
generating station in order to improve
the efficiency or the energy output of
the facillty. Repowering or uprating that
results in increased fuel consumption or
the substitution of one fuel combustion
technology with another is excluded
from this classification.
(c) Water and Waste Program.
Appllcations for financial assistance for
certain proposed actions do not
normally require the submission of an
ER. Applicants shall sufficiently
identify all proposed actions so their
proper classification can be detennined.
These types of actions are subject to the
requirements of § 1794.31. In order to
provide for extraordinary
circumstances, RUS may require
development of an ER for proposals
listed in this section. Proposed actions
within this classification are:
(1) Management actions relating to
invitation for bids, award of contracts,
and the actual physical commencement
of construction activities:
(2) Proposed actions that primarily
involve the purchase and installation of
office equipment or motorized vehicles:
(3) The award of financial assistance
for technical assistance, planning
purposes, environmental analysis,
management studies, or feasibility
studies; and
(4) Loan closing and servicing
activities that do not alter the purpose,
operation, location, or design of the
proposal as originally approved, sum as
subordinations, amendments and
revisions to approved actions, and the
provision of additional financial
assistance for cost overruns.
t 1794.22 Categorically excluded
~. requiring an ER.
(a) Electric and Telecommunications
Programs. Applications for financial
assistance for the types of proposed
actions listed in this section normally
require the submission of an ER and are
subject to the requirements of § 1794.32.
Proposed actions within this
classification are:
(1) Construction of electric power
lines and associated facilities designed~
for or capable of operation at a nominal
vol~e of ei~:
(I) Less that 69 kilovolts (kV);
(il) Less than 230 kV if no more than
25 miles (40.2 kilometers) of line are
involved; or
(iii) 230 kV or greater involving no
more than three miles (4.8 kilometers) of
line;
(2) Construction of buried and aerial
telecommunications lines. cables. and
related facilities;
(3) Construction of microwave
facilities. SCADA. and energy
management systems involving no more
than five acres (2 hectares) of physical
disturbance at any single site;
(4) Construction of cooperative or
company headquarters. maintenance
facilities. or o~ buildings involving
no more than 10 acres (4 hectares) of
physical disturbance or fenced property;
(5) Changes to existing transmission
lines that involve less than 20 percent
pole replacement. or the complete
rebuilding of existing distribution lines
within the same ROW. Changes to
existing transmission lines that require
20 percent or greater pole replacement
wili be considered the same as new
construction;
(6) Changes or additions to existing
substations. switching stations.
telecommunications switching or
multiplexing centers. or external
changes to buildings or small structures
requiring one acre (0.4 hectare) or more
but no more than five acres (2 hectares)
of new physically disturbed land or
fenced property;
(7) Construction of substations.
switching stations. or
telecommunications switching or
multiplexing centers requiring no more
than five acres (2 hectares) of new
physically disturbed land or fenced
property;
(8) Construction of diesel electric
generating facilities of five megawatts
(MW) (nameplate rating) or less either at
an existing generation or substation
sites. This category also applies to a
diesel electric generating facility of five
MW or less that is located at or adjacent
to an existing landfill site and supplied
with refuse derived fuel. All new
associated facilities and related electric
power lines shall be covered in the ER;
(9) Additions to or the replacement of
existing generating units at a
hydroelectric facility or dam which
result in no change in the nonnal
maximum surface area or normal
maximum surface elevation of the
existing impoundment. All rew
associated facilities and related electric
power lines shall be covered in the ER;
(10) Construction of new water supply
wells and associated pipelines not
located within tOO boundaries of an
existing well field or generating station
site: and
(11) Purchase of existing facilities or
a portion thereof where use or operation
will remain unchanged. The results of a
facility environmental audit can be
sumtituted for tOO ER.
(b) Water and Waste Program. For
certain proposed actions, applications
for financial assistance normally require
the submittal of an ER as part of tOO
PER. These types of actions are subject
to the requirements of § 1794.32.
Proposed actions within this
classification are:
(1) Rehabilitation of existing fadlities,
functional replacement or rehabilitation
of equipment, or the construction of
new ancillary fadlities adjacent or
appurtenant to existing facilities,
including but not limited to,
replacement of utilities such as water or
sewer lines and appurtenances for
existing users with modest or moderate
growth potential, reconstruction of
curbs and sidewalks, street repaving,
and building modifications,
renovatiom, and improvements;
(2) Fadlity improvements to meet
current needs with a modest change in
use, size, capacity, purpose or location
from the original fadlity. The proposed
action must be designed for
predominantly residential use with
other new or expanded users being
small-scale, commercial enterprises
having limited secondary impacts;
(3) Construction of new facilities that
are designed to serve not more than 500
EDUs and with modest growth
potential. The proposed action must be
designed for predominantly residential
use with other users being small-scale,
comrnerdal enterprises having limited
secondary impacts;
(4) The extension, enlargement or
construction of interceptors, collection,
transmission or distribution lines within
a one-mile (1.6-kilometer) limit from
existing service areas estimated from
any boundary listed as follows:
(i) The corporate limits of the
community being served;
(ii) If there are developed areas
immediately contiguous to the corporate
limits of a community, the limits of
these developed areas; or
(iii) If an unincorporated area is to be
served, the limits of the developed
areas:
(5) Installation of new water supply
wells or water storage facilities that are
required by a regulatory authority or
standard engineering practice as a
backup to existing production well(s) or
as reserve for fire protection;
(6) Actions described in
§ 1794.21 (c) (4) which alter the purpose,
Federal Register/Vol. 63, No. 238/Friday, December II, 1998/Rules and Regulations 68661
operation, location, or design of the
proposed oction as originally approved,
and such alteration is equivalent in
magnitude or type as described in
paragraphs (b) (1) through (b)(5) of this
section; and
(7) The lease or disposal of real
property by RUS, which may result in
a change in use of the real property in
the reasonably fm-eseeable future and
such change, is equivalent in magnitude
or type as described in paragraphs (b) (1)
through (b)(5).
(c) Spedalized criteria for not
granting a CE for Water and Waste
Projects. An EA must be prepared if a
proposed action normally classified as a
CE meets any of the following:
(1) Will either create a new or relocate
an existing discharge to or a withdrawal
from surface or ground waters;
(2) Will result in substantial increases
in the volume or the loading of
pollutants from an existing discharge to
receiving waters;
(3) Will cause a substantial increase in
the volume of withdrawal from surfoce
or ground waters at an existing site; or
(4) Would provide capacity to serve
more than 500 EDUs or a 30 percent
increase in the existing population
whichever is larger.
t 1794.23 Proposals nonnally r8qUh1ng an
EA.
RUS will normally prepare an EA for
all proposed octions which are neither
categorical exclusions (§§ 1794.21 and
1794.22) nor normally requiring an EIS
(§ 1794.25). For certain actions within
this class, scoping and document
procedUl-es contained in §§ 1794.50
through 1794.54 sha1I be followed (see
§ 1794.24). The following are proposed
actions which normally require an EA
and shall be subject to the requirements
of §§ 1794.40 through 1794.44.
(a) General. Issuance or modification
of RUS regulations concerning
environmental matters.
(b) Telecommunications and Water
and Waste Programs. An EA sha1I be
prepared for applications for financial
assistance for all proposed actions not
specifically defmed as a CE or otherwise
specifically categorized by the
Administrator on a case-by-case basis.
(c) Electric Program. Applications for
finandal assistance for certain proposed
actions normally require the preparation
of an EA. Pro~ actions falling
within this classification are:
(1) Construction of combustion
turbine or diesel generating facilities of
SO MW (nameplate rating) or less at a
new site (no existing generating
capacity) except for items covered by
§ 1794.22(a)(8). All new associated
facilities and related electric power
lines shall be covered in the EA;
(2) Construction of combustion
turbine or diesel generating facilities of
100 MW (nameplate rating) or less at an
existing generating site, except for items
covered by § I 794.22(a) (8). All new
associated fadlities and related electric
power lires shall be covered in the EA;
(3) Construction of any other type of
new electric generating facilities of 10
MW (nameplate rating) or less. All new
associated facilities and related electric
power lines shall be covered in the EA;
(4) Repowering or uprating of an
existing unit(s) at a fossil-fueled
generating station where the existing
fuel combustion technology of the
affected unit(s) is substituted for another
(e.g. coal or oil-fired boiler is converted
to a fluidized bed boiler or replaced
with a combustion turbine unit);
(5) Installation of new generating
units at an existing hydroelectric facility
or dam, or the replacement of existing
generating units at a hydroelectric
facility or dam which will result in a
change in the normal maximum surface
area or normal maximum surface
elevation of the existing impoundment.
All new associated facilities and related
electric power lines shall be covered in
the EA ;
(6) A new drillb1g operation or the
expansion of a mining or drilling
operation;
(7) Construction of cooperative
headquarters, maintenance, and
equipment storage facilities involving
more than 10 acres (4 hectares) of
physical disturbance or fenced property;
(8) The construction of electric power
lines and related facilities designed for
and capable of operation at a nominal
voltage of 230 kV or more involvb1g
more than three miles (4.8 kilometers)
but not more than 25 miles (40
kilometers) of line;
(9) The construction of electric power
lines and related facilities designed for
or capable of operation at a nominal
voltage of 69 kV or more but less than
230 kV where more than 25 miles (40
kilometers) of power line are involved;
(10) The construction of substations
or switching stations requiring greater
than five acres (2 hectares) of new
physical disturbance at a sb1gle site; and
(11) Construction of facilities
designed for the transfer and storage of
ash, scrubber wastes, and other
byproducts from coal-fired electric
generating stations that will be located
beyond the existing fadlity site
boundaries.
t 1794.24 Proposals normaly requiring an
EA with scoping.
(a) General. Applications for f"mancial
assistance for certain prop~d actions
require the use of a scoping procedure
in the development of the EA. These
types of actions are subject to the
requirements of §§ 1794.50 through
1794.54. RUS has the discretion to
modify or waive the requirements listed
in § 1794.52 for a proposed action in
this category.
(b) Electric Program. Proposed actions
falling within this classification are:
(1) The construction of electric power
lines and related facilities designed for
and capable of operation at a nominal
voltage of 230 kV or more where more
than 25 miles (40 kilometers) of power
line are involved;
(2) Construction of combustion
turbines and diesel generators of more
than 50 MW at a new site or more than
100 MW at an existing site; and the
construction of any other type of electric
generating facility of more than 10 MW
but not more than 50 MW (nameplate
rating). All new associated facilities and
related electric power lines shail be
covered in any EA or EIS that is
prepared.
(c) Telecommunications and Water
and Waste Programs. There are no
actions normally falling within this
classification.
t 1794.25 Pn»posai8 normally requiring an
EIS.
Applications for f"mancial assistance
for certain proposed actions that may
significantly affect the quality of the
human environment shall require the
preparation of an EIS.
(a) Electric Program. An EIS will
normally be required in connection with
proposed actions involving the
following types of facilities:
(1) New electric generating facilities
of more than 50 MW (nameplate rating)
other than diesel generators or
combustion turbines. All new associated
facilities and related electric power
lines shall be covered in the EIS; and
(2) A new mining operation when the
applicants have effective control (e.g.,
dedicated mine or purchase of a
substantial portion of the mining
equipment) .
(b) Proposals listed above are subject
to the requirements of §§ 1794.60.
1794.61.1794.63, and 1794.64.
Preparation of a supplemental draft or
final EIS in accordance with 40 CFR
1502.9 shall be subject to the
requirements of §§ 1794.62 and 1794.64.
(c) Telecommunications and Water
and Waste Programs. No groups or sets
of proposed actions normally require
the preparation of an EIS. The
I. 1~/Ru1~ and Regulations68662Federal Register/Vol. 63. No. 238/Friday. December
environmental review process. as
described in this part. shall be used to
identify those proposed actlom for
which the preparation of an EIS is
necessary. If an EIS is required. RUS
shall proceed directly to its preparatim.
Prior completion of an EA is not
mandatory.
H 1794.2t-1794.29 (R..-vedJ
Subpart O-Procedur8 for Categorical
Exclusions
11794.30 General
The procedures of this subpa't which
apply to proposed actions classified as
CEs in §§ 1794.21 am 1794.22 provide
RUS with information necessary to
determine if the proposed action meets
the criteria for a CEo Where. beca~ of
eXtnK)rdinary circumstances. a normally
categorically excluded action may have
a significant effect on the quality of the
human environme", RUS may require
additional environmental
docwnentation.
11794.31 CI8uIftc8tIon.
(a) Electric and Telecommunications
Programs. RUS will normally detennine
the proper environmental classification
of projects based on its evaluation of the
project description set forth in the
constNctlon work plan or loan design
which the applicant is required to
submit with its applicaion for financial
assistance. Each project must be
sufficiently described to ensure its
proper c~iflcation. RUS may require
the applicant to provide additional
information on a project where
appropriate.
(b) Water and Waste Program. RUS
will normally determine the pI'oper
environmental cl~iflcation for projects
based on its evaluation of the
preliminary planning and design
information.
11~ E ~ r-.-t.
(a) For proposed actions listed in
§ 1794.21 (b) and (c). the applicant is
rxxma1ly not required to submit an ER.
(b) For proposed actions listed in
§ 1794.22(a) and (b). the applicant shall
nonnally submit an ER. Guidance in
preparing the ER for Electric and
Telecommunication proposals is
contained in RUS Bulletin 1794A-600.
Guidance in preparing the ER for Water
and Waste proposals is contained In
RUS Bulletin 1794A-602. The applicant
may be required to publish public
notices and provide evidence of such if
the proposed action is located in,
impacts, or converts important land
~.
11714.33 AQ8ncy 8ctIon.
RUS may -=t on an application for
ftnanctal asslstance upon determining.
based on the review of documents as set
forth in § 1794.32 and such additional
Information as RUS deems necessary.
that the project is categorically
excluded.
H 1794.34-17M.8 IR..v8d1
Subpart E-Procedure for
Environmental .cA~"8ments
117MAG o J.
This subpart applies to ~
actions described in § 1794.23. WheI'e
appropriate to caTy out the p1rposes of
NEP A. RUS may impose. on a case-by-
case basis. additional requirements
~iated with the prepanKion of an
EA. If at any polm in the preparation of
an EA. RUS determines that the
proposed action wlll have a significant
effect on the quality of the human
environment. the preparation of an ElS
shall be required and the procedures in
subpart G of this part shall be followed.
11~1 ~ ~r8m8ItL
Applicants will provide an ER in
accordance with the appropriate
guidance documents referenced in
§ 1794.7. After RUS has evaluated the
ERandhasdetermlnedtheER
adequately ~ all applicable
environmental issues. the ER will
normally serve as RUS' EA. However.
RUS reserves the right to prepare its
own EA from the Information provided
in the ER. RUS will take responsibility
for the scope and content of an EA.
117NA2 NotIce or 8V8i8b8ty.
Prior to RUS ma1dng a flnd1ng in
accordance with § 1794.43 and upon
RUS autlK>rlzation and guidance. the
applicant shall have a notice published
which announces the availability of the
EA and solicits public comments on ~
EA.
11794.43 Agencyftnd~.
(a) General.lfRUS fiOOs. ~ on an
EA that the proposed action will not
have a significant effect on the quality
of the human envlrorunent. RUS will
prepare a PONSI. Upon authorization of
RUS. the applicant shall have a notice
published which Informs ~ public of
the RUS finding and ~ availability of
the EA and FaNSI. The notice shall be
prepared and published in accordance
with RUS guidaoce.
(b) Electric and Telecommunications
Programs. RUS shall have a notice
published in the Federal Re&ister that
announces the availability of the EA and
FONSI.
11794.44 Tknmg of 8g8ncy 8ctIon.
RUS may take its final action on
proposed ~tions requiring an EA
(§ 1794.23) at any time after publication
of the RUS and applicant notices that a
FONSI has been made and any required
review period ~ expired. When
su~tantlve comments are received on
the EA, RUS may provide an additional
period (15 days) f(X' public review
following the publication of Its FONSI
detelmination. Final action shall not be
taken until this review period has
expired.
H 1794.45-1794.49 (Reserved)
Subpart F-Procedure for
Environmental Ass.ssments With
Scoping
11794..50 ~~.
For proposed actions covered by
§ 1794.24 and other actions determined
by the Administrator to require an EA
with $coping. RUS and the applicant
will follow the same procedures for
scoping and the requirements f(X'
notices and documents as for proposed
actions normally requiring an EIS
through the point at which ~
Environmental Analysis (EV AL) Is
submitted (see § 1794.54). After the
EV AL has been submitted. RUS will
make a judgment to utilize the EV AL ~
its EA and ~ue a FONSI or prepare an
EIS.
11794.51 Pr8.-r8t1on for scopmg.
(a) As soon as practicable after RUS
and the applicant have developed a
schedule for the environmental review
process. RUS shall have its notice of
intent to prepare an EA or EIS
(§ 1794.13) published in ~ Feder'aI
~ (see 40 CFR 1508.22). The
applicant shall have published. in a
timely manner, a notice similar to RUS.
notice.
(b) As part of the early planning. the
applicant should consult with
appropriate Federal. state. and local
agencies to Infonn them of the pro~
action, identify permits and approvals
which must. be obtained, and
administrative procedures which must
be followed.
(c) Before formal scoping is initiated.
RUS will require the applicant to submit
an Alternative Evaluation Study and
eitle- a Siting Study (generation) (X' a
Macro-Corrtdor Study (transmlMlon
lines).
(d) The applicant Is encouraged to
hold public infonnation meetings in the
~ location of the proposed action
and any reasonable alternatives when
such applicant meetings will make the
scoping process more meaningful. A
written summary of the comments mOM:1e
68663Federal Register/Vol. 63. No. 238/Friday. December 11. 1998/Rules and Regulations
at such meetings must be submitted to
RUS as soon as practicable after the
meetings.
11794.52 &coping meetings.
(a) Both RUS and the applicant shall
have a notice published which
announces a public scoping meeting is
to be conducted, either in conjunction
with the notice of intent or as a ~parate
notice.
(b) The RUS notice shall be published
in the Federal Register at leMt 14 days
prior to the meeting(s). The applicant's
notice shall be published in a
newspaper at least 10 days prior to the
meeting(s). Other fornJS of media may
also be used by the applicant to notice
the meetings.
(c) Where an environmental
document is the subject of the hearing
or meeting. that document will be made
available to the public at least 10 days
in advance of the meeting.
(d) The scoping meeting(s) will be
held in the area of the proposed action
at such place(s) as RUS determines will
best afford an opportunity for public
involvement. Any person or
repre~ntative of an organization, or
government body desiring to make a
statement at the meeting may make such
statement in writing or orally. The
format of the meeting may be one of two
styles. It can either be of the traditional
Style which features formal
presentations followed by a comment
period, or the open house style in which
attendees are able to individually obtain
information on topics or issues of
interest within an established time
period A transcript will be made of the
scoping meeting.
(e) As soon as practicable after the
scoping meeting(s), RUS, as lead agency,
shall determine the significant issues to
be analyzed in depth and identify and
eliminate from detailed study the issues
which are not significant or which have
been covered by prior environmental
review. RUS will develop a proposed
scope for further environmental study
and review. RUS shall send a copy of
this proposed scope to cooperating
agencies and the applicant. and allow
recipients 30 days to comment on the
scope's adequacy and emphasis. After
expiration of the 30-day period, RUS
shall provide written guidance to the
applicant concerning the scope of
environmental study to be perf<X"lned
and information to be gathered.
11794.53 Envt~ 8n8Iy8tL
(a) Mter scoping procedures have
been completed. RUS shall require the
applicant to develop and submit an
EV AL. The EV AL shall be prepared
under the supervision and guidance of
RUS staff and RUS shall evaluate and be
responsible for the accuracy of all
infonnation contained therein.
(b) The EV AL will normally serve as
the RUS EA. The EV AL can also serve
as the basis for an EIS. and under such
circumstances will be made an
appendix to the EIS. After RUS has
reviewed and found the EV AL to be
satisfactory. the applicant shall provide
RUS with a sufficient number of copies
of the EV AL to satisfy the RUS
distribution plan.
(c) The EV AL shall include a
summary of the construction and
operation monitoring and mitigation
measures for the prop~ action. These
measures may be revised as appropriate
in response to comments and other
information. and shall be incorporated
by summary or reference into the FONSI
or ROD.
t 1794.54 Agency d_rmln8tlon.
Following the scoping process and the
development of a satisfactory EA. RUS
shall determine whether the proposed
action is a major Federal action
significantly affecting the quality of the
human environment. If RUS determines
the action is significant. RUS will
continue with the procedures in subpart
G of this part. If RUS determines the
action is not significant, RUS will
proceed in accordance with §§ 1794.42
through 1794.44.
It 1794.55-1794.59 [Reserved]
Subpart G-Procedure for
Environmental Impact Statements
t 1794.60 Monnal Mquence.
For proposed actions requiring an EIS
(see § 1794.25). the NEPA process shall
proceed in the same manner as for
proposed actions requiring an EA with
scoping through the point at which the
scoping process is completed (see
§ 1794.52).
t 1794.61 EnvIroNneId8I npect
8tBt8nI8Id.
(a) General. An EIS shall be prepared
in accordance with 40 CFR part 1502.
Funding, in whole or in part. for an EIS
can be obtained from any lawful source
(e.g.. cooperative agreements developed
in accordance with Section 759A.
Federal Agricultural Improvement and
Reform Act of 1996. Pub. L. 104-127
and 31 U.S.C. 6301). A third-party
consultant selected by RUS and funded
by the applicant (7 CFR part 1789) may
prepare the EIS.
(1) After a draft or final EIS has been
prepared, RUS and the applicant shall
concurrently have a notice of
availability for the document published.
The time period allowed for review will
be a minimum of 45 days for a draft EIS
and 30 days for a final EIS. This period
is measured from the date that the U.S.
Environmental Protection Agency (EP A)
publishes a notice in the Federal
Register in accordance with 40 CFR
1506.10.
(2) In addition to circulation required
by 40 CFR 1502.19, the draft and final
EIS (or summaries thereof, at RUS
discretion) shall be circulated to the
appropriate state, regional, and
metropolitan clearinghouses.
(3) Where a final EIS does not require
su~tantial changes from the draft EIS,
RUS may document required changes
through errata sheets, insertion pages.
and revised sections to be incorporated
into the draft EIS. In such cases, RUS
shall circulate such changes together
with comments on the draft EIS,
responses to comments, and other
appropriate information as its final EIS.
RUS will not circulate the draft EIS
again, although RUS will provide the
draft EIS if requested within 30 days of
publication of notice of availability of
the final EIS.
(b) Electric Program. Where the
applicant or its consultant has prepared
an EV AL, RUS wili develop its draft and
final EIS from the EV AL. An EV AL will
not be required if a third-party
consultant prepares the draft and final
EIS.
11794.62 ~plem81d81 EIS.
(a) A supplement to a draft or final
EIS shall be prepared, circulated, and
given notice by RUS and the applicant
in the same manner (exclusive of
scoping) as a draft and final EIS (see
§ 1794.61).
(b) Normally RUS and the applicant
will have published notices of intent to
prepare a supplement to a final EIS in
those cases where a ROD has already
been issued.
(c) RUS, at its discretion, may issue an
information supplement to a final EIS
where RUS determines that the
purposes of NEP A are furthered by
doing so even though such supplement
is not required by 40 CFR l502.9(c)(1).
RUS and the applicant shall
concurrently have a notice of
availability published. The notice
requirements shall be the same as for a
final EIS and the information
supplement shall be circulated in the
same manner as a final EIS. RUS shall
take no final action on any proposed
modification discussed in the
information supplement until 30 days
after the RUS notice of availability or
the applicant's notice is published,
whichever occurs later.
68664 Federal Register/Vol. 63. No. 238/Friday. December II. 1998/Rules and Regulations
interested parties upon request. If the
adopted EIS is not generally available,
RUS shall have a public notice
published informing the public of its
action and will circulate copies of the
EIS in accordance with 40 CFR 1502.19
and 40 CFR 1506.3.
t 1794.73 TRine of agency action.
Where RUS has adopted ano~r
agency's enviromnental documents, the
timing of the action shall be subject to
the same requirements as if RUS had
prepared the required EA or EIS.
t 1794.74 InCOIpGration of enYk'onmental
mBtertaIs.
RUS may incorporate into its
enviromnental documents,
environmental documents or portions
thereof prepared by state, or local
agencies or other parties for purposes
other than compliance with the
requirements of NEP A. RUS will
circulate the incorporated documents as
a part of its EA or draft and final EIS in
the same manner as if prepared by RUS.
t 1794.75-1794.79 [Reserved)
Dated: December 7. 1998.
Jm Long Thompson.
Under Secretary, Rural Development.
IFR Doc. 98-32882 Filed 12-10-98; 8:45 am)
BI.l.MG CODE Mt"'~
t 1794.63 Record of dedsIon.
(a) Upon completion of the review
period for a final EIS. RUS will have its
ROD prepared in accordance with 40
CPR 1505.2.
(b) Separate RUS and applicant
notices of availability shall be published
concurrently. The notices shall
summarize the RUS decision and
announce the availability of the ROD.
Copies of the ROD will be made
available upon request from the point of
contact identified in the notice.
t 1794.84 Dnkig of agency action.
(a) RUS may take its final action or
execute commitments on proposed
actions requiring an EIS or
Supplemental EIS at any time after the
ROD has been published
(b) For budgetary purposes some
finandal assistance may be approved
conditionally with a stipulation that no
funds shall be advanced until a ROD has
been prepared.
It 1794.65-1794.69 [RMWYed)
Subpart H-Adoption of Environmental
Documents
t 1794.70 General.
This subpart COvers the adoption of
environmental documents prepared by
other Federal agencies. Where
applicants partidpate in proposed
actions for which an EA or EIS has been
prepared by or foc another Federal
agency. RUS may adopt the existing EA
or EIS in accordance with 40 CFR
1506.3.
t 1794.71 AdoptIon of an EA.
RUS may adopt a Federal EA or EIS
or a portion thereof as its EA. RUS shall
make the EA available and assure that
notice is provided in the same manner
as if RUS had prepared the EA.
t 1794.72 ~ of an as.
(a) Where RUS determines that an
existing Federal EIS requires additional
information to meet the standards for an
adequate statement for RUS proposed
action. RUS may adopt all or a portion
of the EIS as a part of its draft EIS. The
circulation and notice provisions for a
draft and {"mal EIS (see § 1794.61) apply.
(b) If RUS was not a cooperating
agency but determines that another
Federal agency's EIS is adequate. RUS
shall adopt that agency's EIS as its final
EIS. RUS and the applicant shall have
separate notices published advising of
RUS adoption of the EIS and
independent determination of its
adequacy.
(c) If the adopted EIS is generally
available and meets RUS standards.
RUS shall have a public notice
published informing the public of its
action and availability of the EIS to
APPENDIX E
ADNR APPLICAnON FOR EASEMENT RIGHT-OF-WAY PERMIT
STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES
DIVISION OF MINING, LAND AND WATER
0 0 0Northern Region
3700 Airport Way
Fairbanks. AK 99709
(907) 451-2740
Southeast Region
400 Willoughby, #400
Juneau, AK 99801
(907) 465-3400
Southcentral Region
550 W 7th Ave., Suite 90OC
Anchorage, AK 99501-3577
(907) 269-8552
APPLICATION FOR EASEMENT
AS 38.05.850
Non-refundable application fee: $100.
ACL.
(t) ~ j~ ., by 1t8t8)
Aoolicanfs Name Doina busirwss as:
.Mailina Address E-Mai: .
Citv/State/ZlD
Messaae Phone () Work Ptta. ( ) Sac. Sec. # and/or Tax ID ..
Is applicant a non~t OOOperative assoaa&n? ( ] ~ ( ] no. If yes, 818 ~u applying br 8n exemption under AS
38.05.850(b)? [ ] yes ( ] no. If yes. please submit proof of nonprofit status (e.g. b)'oI8wa. erUa. aflnQJfPOf8llan, lax statement).
Meridian
Section
Section
1/4,.1/4.
1/4,.1/4
locatOO of activity/Lega' Descriptk)n: Municipality
Township. - , Range
T own,hip . - . , Range
(- ... ~ - ".--
Speciftc purpose of easement (e.g. electric utIity, fiber-optic ooOOult or catM. teleoommunlcatbns tower, ~d. br'Kige,
ai~trlp/airport, driveway, trail. drainage), and type of anticipated tramc (e.g. plane, truck. heavy equipment): Explain
Are yoo ap~lng for the DMsk)n of MIning, land and Water k) ~ s Public E888ment? V. 0 No O. Are you applying
to be granted a Private Esl8ment? Ves 0 No O. (NoW: Annual r8nt8I fee rwqu~ fa' prtt'ate 888m8nt)
-See 11 AAC 05.010 r8g8nIrIg '- for f8d8r81 81d Ioc8I ~ ~..:-.
Date St8mp:
102.112 (Rn. 10101)1
STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES
. DIVISION OF MINING, LAND AND WATER
0 0Northern Region
3700 Airport Way
Fairbanks, AK 99709
(907) 451-2740
[X]Southeast Region
400 Willoughby, #400
Juneau, AK 99801
(907) 465-3400
SouthcentraJ Region
550 W 7th Ave., Suite 90OC
Anchorage, AK 99501-3577
(907) 269-8552
INSTRUCTIONS FOR COMPLETING A DEVELOPMENT PLAN
A development plan is a written statement (nanative) and a sketch or bluefine nwing desalbing the proposed use aJxj
development of state land. The infOm1ation contained In a devel~ment plan is needed to provide a complete review of the
application and the proposed use and development, and helps to determine the terms and conditions of the authorization and
the level of bonding and insurance that may be required.
Most appIk:ations submitted to the Division of Mining, Land and Water must have an attached development plan. The few
exceptions to this rule include applications for state land sales and some types of land use pennil The amount and type of
informatk>n included in the development plan will depend on the proposed use and level of development. Insuff"lCient
information in the development plan and'or appl~tion or failure to prome a development plan may result in a delay in
processing the appI~tion. If you are unsure whether your applk:atk>n Wll require a development plan, contact the regiooaJ
office responsible for managing the area you are planning to use (regional ~ addresses and phone numbers are shown at
the top of this sheet).
If the appIkation Is approved, the approved development plan becomes a part of the authorizatkx1 doo.ment Authorized
activities are limited to those described In the development plan and/or authorization document The development plan must
be updated If changes to an approved project are proposed before or during the projecfs siting, construction, or operation; If
any additional ~ures, buikfings, or Improvements are proposed; or If there Is a change In activity that was not addressed
during considerab1 of the appIk:ation. Please note that these deve~t plans or plan changes must be approved by the
DMsial of Mining, Land and Water .bi!Q[g any change ~rs i1 use, consmJctk)n, or actMty. Conducting activities that are
not authorized by the development plan and authorization document could result In revocation and termination of the
authorization and/or other appropriate legal action.
I. General Guidelines for Preoarfna a Develooment Plan For new authorlzatk)ns, the development plan must show the
proposed improvements and/or use areas, as well as preconstruction plans. For existing authorizations without a current
development plan or If the development plan Is being updated, the plan must show existing Improvements and/or use areas,
etc., and any known future changes. The development plan must Include: .
. Maps: a USGS map at a scale of at least 1 :63,360 showing the k)catIcx1 of U18 Prq)O8ed project; a blueline drawing or
sketch, drawn to scale (the attached d"lagram may be used); and -
. Written Project description: a detailed written descriptk>n (narrative) of the mended use and level of devetoprnent
planned under the authorization and an explanation of the sketch or blueline drawing.
II. land Use PI([DIts PenT1anent Improwments cannot be autt1orlzed by a land use permit. However, a development plan
accompanying.. a land use permit application must describe nonpermanent structures and actMtles. (Nonpermanent
structures are structures that can be easily and quickly taken down and removed from the site, without any signifICant
disturbance or damage to the area.) Several of the specific development plan items listed below will not apply to activities
authorized under a land use permit; those items that do apply shoukj be descrbed In as mlx:i1 detail as possible, to enable
prompt review of the apprlCation. If the proposed land use permit activity Is of a mobile nature, sld1 as a permit to move
heavy equipment across state land, a. development plan Is not required; but a map showing the proposed route-of travel is
required. If the Impact wouki not have a significant effect on the environment, sld1 as a permit to harvest wild produce. a
development plan is not required, but a map showing the location of the pr~ hSlVest area is required.
III. Narrative oortfon of the develooment alan Descri>e the type of ~ or development planned for the site; specify if
any facilities are intended for commercial use, or will be rented o~ and provtde a description and explanation of the items
shown on the sketch or bluellne. Following is a list of specific information to be included In the narrative, if aDDlicable tD the
proposed project:
1O2-DEVPL (Rev. ~)
VICINITY MAP
~Pr8P8I8d:~tWr.-.
STATE OF ALASKA
DEPARTMefr OF NA1URAL RESOuRCEs
aVISION OF MINNa. lAND AND WATER
DIAGRAM
~) - T ~ = ~ . MIi.~~'--
~1..
&EET-OF ~.
2. Power Plant Review and Report by Steigers Corporation
Bethel Power Plant
Environmental Permitting Requirements Assessment
Prepared for
NUVISTA LIGHT & POWER, CO.
Anchorage, Alaska
Prepared by
Steigers Corporation
Littleton, Colorado
November 2003
TABLE OF CONTENTS
1.0 INTRODUCTION 1
2.0 PROJECT DESCRIPTION 2
2.1 Alternative 1 – Land-Based Coal-Fired Power Plant 3
2.2 Alternative 2 – Barge-Mounted Coal-Fired Power Plant 4
2.3 Alternative 3 – Combustion Turbine Plant 4
3.0 CONSULTATION 8
4.0 COMMENTS ON THE PROPOSED PROJECT 9
4.1 State of Alaska 9
4.2 Federal Agencies 10
.3 Others 12
5.0 ENVIRONMENTAL ISSUES AND MAJOR PERMITTING REQUIREMENTS 13
5.1 Alaska Coastal Zone Management 13
5.2 Air Quality 14
5.3 Water Quality 17
5.4 Wetlands and Navigable Rivers 20
5.5 Fish Habitat 22
5.6 Floodplain Development 24
5.7 Air Traffic 25
5.8 NEPA Compliance 25
5.9 Field Data Collection 30
5.10 Potential Permits and Approvals for Bethel Power Plant 31
6.0 PLANNING-LEVEL COST ESTIMATE AND SCHEDULE 32
7.0 REFERENCES 33
LIST OF FIGURES
Figure 1 Aerial Photo of Bethel and Vicinity Showing Proposed Bethel Power Plant 6
Locations
Figure 2 Photo of an Existing Air-Supported Coal Storage Structure 7
ATTACHMENT
ATTACHMENT 1 Initial Consultation Letter, Bethel Power Plant Project Description, Parties
to Whom the Initial Consultation Letter Was Sent and Responses.
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Bethel Power Plant Environmental Permitting Requirements Assessment
1.0 INTRODUCTION
Nuvista Light & Power, Inc. (Nuvista) is evaluating the feasibility of constructing and operating
an energy generation facility near the community of Bethel, Alaska. Three alternatives for
power production are being considered:
• Alternative 1 – a land-based coal-fired power plant
• Alternative 2 – a barge-mounted coal-fired power plant
• Alternative 3 – diesel-fired combustion turbines.
Brief descriptions of the three power plant alternatives are provided in Section 2.
The proposed power plant would be developed for two purposes: 1) sell wholesale power to local
utilities for resale to their customers, an endeavor that would ultimately serve approximately 40
communities and villages in the region and distribute hot water to meet local district heating
needs in Bethel and 2) supply electrical power directly to the proposed Donlin Creek Gold Mine,
which is currently under exploration by Placer Dome, Inc. and NovaGold Resources, Inc.
Steigers Corporation was retained by Bettine, LLC on behalf of Nuvista Light & Power, Co. to
assess the environmental and permitting requirements for the Bethel Power Plant and
appurtenant structures. The conclusions of this assessment are included in this report. Issues
related to development of the transmission line system have been addressed in a separate report,
"Environmental Planning for the Proposed Bethel Power Plant and Transmission Line," prepared
by Travis/Peterson Environmental Consulting, Inc. (Travis/Peterson 2003). Development of the
Donlin Creek Gold Mine is not part of the Bethel Power Plant proposal, and specific
environmental issues and permitting requirements related to its construction and operation are
not addressed here.
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2.0 PROJECT DESCRIPTION
Nuvista proposes to construct the Bethel Power Plant near Bethel, Alaska. Bethel is located in
southwest Alaska about 400 air miles west of Anchorage. It is situated on the Kuskokwim River
about 60 miles upstream of the river’s mouth at Kuskokwim Bay on the Bering Sea. Bethel has
a population of about 5,500 and is the commercial and transportation hub of the Yukon Delta.
Access to Bethel is by air or the Kuskokwim River.
Bethel is located within the Yukon Delta National Wildlife Refuge, a large area of low-lying
tundra, wetlands, intertidal mud and sand flats, and small lakes. The preferred location for
Bethel Power Plant Alternative 1 or Alternative 3 is a site approximately 1 mile south of Bethel
in Section 20 of Township 8 North, Range 7 West of the Seward Meridian at an elevation of
approximately 50 feet mean sea level. A photograph showing the proposed location of the
facility and the associated facility dock, access roads, and cooling pond is provided as Figure 1.
Alternatives 1 and 2 would differ from one another primarily in the location and configuration of
their nearly identical facility components. Alternative 2 would have the coal-fired power plant
mounted on barges anchored at a nearby site (also in Section 20) in the Kuskokwim River. The
proposed location of the barge-mounted coal plant is shown in Figure 1. All proposed locations
for the Bethel Power Plant are situated on private property.
The power plant alternatives are described below. In addition to the facility site itself, each of
the alternatives involves developing a number of linear support features outside the facility
boundary, including a variety of pipelines and conveyor systems. While parts or all of the
facility sites per se may be expected to experience extensive disturbance during construction, the
proposed off-site pipeline and conveyor systems have been designed to minimize surface
disturbance and avoid the need to develop permanent rights-of-way for maintenance. Likewise,
while the selected plant site will experience continuous human activity throughout the operations
phase, the off-site facilities should be relatively free of project-related activity over the long
term.
All alternatives propose the use of a naturally occurring, approximately 78-acre pond for steam-
cycle cooling of the power generation facilities (see Figure 1). The pond is located generally
south of the proposed facility sites and would be connected to the power plant by heavily
insulated, 2- to 3-foot-diameter pipelines elevated 6 to 8 feet above the ground on driven piles or
small A-frame towers. Use of a cooling pond rather than forced-air cooling towers would reduce
construction costs and also substantially reduce annual operating costs. However, should further
investigation indicate overriding environmental constraints associated with using the existing
pond as a cooling pond, the cooling tower option would be revisited.
All alternatives also propose to capture waste heat from the power plant and distribute hot water
via a district heating system. The district heating system will include a central heat exchange
station located about midway between the power plant and Bethel and more than 6 miles of main
trunk lines leading from the power plant to the Bethel Municipal Airport and to the town of
Bethel and beyond. The main trunk lines will consist of 14- to 16-inch pipes hung from pilings
and elevated about 2 feet above the ground. As currently envisioned, the district heating system
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main trunk lines will follow existing roads and streets. It is estimated that the captured waste
heat would displace nearly all of the fuel oil currently used by Bethel Utilities to supply Bethel’s
power needs, approximately 3.5 million gallons annually. The existing Bethel Utilities power
plant houses about 10 MW of diesel generation, which would likely remain operational to
provide additional standby/backup power for the proposed Bethel Power Plant.
Other features common to all alternatives include a dock on the Kuskokwim River and new
access roads from the plant site(s) to an existing road to Bethel. These roads will likely be two
lanes and of dirt/gravel construction.
2.1 Alternative 1 – Land-Based Coal-Fired Power Plant
The proposed land-based coal-fired power plant would consist of two atmospheric pulverized
coal-fired boilers each powering a 48-MW steam turbine, plus one 46-MW diesel-fired simple-
cycle combustion turbine, for a total installed capacity of 142 MW. The power plant would
generate approximately 670,000 MWh annually. The two coal-fired steam turbines would
provide primary power, with the combustion turbine providing standby/backup generation. It is
estimated that the combustion turbine will generate approximately 3 percent of the annual
generation, or about 20,000 MWh per year.
The land-based coal-fired plant would burn about 300,000 short tons of coal annually. The
project proposes to use a high-BTU, very low-sulfur coal from the Black Bear Mine in Canada as
the coal supply for the power plant. The coal would be shipped from Canada in self-off-loading
freighters and transferred to barges in the area of Goodnews Bay for movement up the
Kuskokwim River to the Bethel Power Plant facility’s barge unloading station and dock. Coal
deliveries would occur during the open water season from the end of May through the end of
September each year.
From the unloading station, the coal will be transported approximately one-half mile to the coal
storage pile at the power plant by means of a covered conveyor belt. The conveyor belt system
will be elevated 12 to 20 feet above the ground by steel A-frame towers mounted on small
concrete surface pads over pilings. The conveyor belt will parallel a new road between the dock
and the plant. To minimize blowing coal dust, the coal would be stored in a large covered
building such as the air-supported structure shown in Figure 2.
A 3-million-gallon fuel tank would be built at the site to store the fuel oil for the combustion
turbine. Under this alternative, where the combustion turbine serves only as a backup unit, the
incrementally small amount of diesel fuel needed will likely be purchased from the existing tank
farm in Bethel and trucked to the power plant.
In addition to the coal-fired boilers and the combustion turbine and their associated pumps and
control room, other features of the land-based coal-fired alternative include additional coal
conveyors and various coal-handling equipment, an approximately 1-acre blowdown pond, an
electrical switchyard and associated 138-kV transmission lines to Bethel, and the initial section
of the district heating system. The proposed land-based coal-fired power plant facility would
occupy approximately 80 acres. Exhaust stack height is estimated at approximately 120 feet.
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The land-based coal-fired power plant would generate approximately 33,000 tons of ash
annually. The ash will be processed as it is produced by adding 6 percent Portland cement and
16 percent water to form approximately 40,000 tons of gravel-like aggregate. The aggregate can
be put to beneficial use locally and regionally for road construction or in concrete as a substitute
for gravel.
2.2 Alternative 2 – Barge-Mounted Coal-Fired Power Plant
The barge-mounted coal-fired power plant alternative would occupy two barges off the
Kuskokwim River plus adjacent land for coal and diesel fuel storage and other facility features.
Each barge would be 100 feet wide by 300 feet long and has a draft of about 8 feet; together the
barges would occupy less than 2 acres. The barges would be set in place by digging a channel
into the river bank of sufficient width, length, and depth to float the barges into position. Once
the barges are in place, an armored berm would be built between the barge channel and the river
to protect the barges from ice flows during spring breakup and to provide an earthen platform for
unloading supplies. The barges would be located in the floodplain of the river at a location
where there is little elevation difference in the bank and the river.
Each barge would accommodate a 48-MW atmospheric pulverized coal-fired power plant. One
of the two barges would also accommodate a 46-MW diesel-fired simple-cycle combustion
turbine as standby generation. The total installed capacity would be 142 MW. Under this
alternative, the power plant would generate approximately 670,000 MWh annually. As with the
land-based coal-fired power plant alternative, it is estimated that the combustion turbine would
generate approximately 3 percent of the annual generation, or about 20,000 MWh per year.
The barge-mounted coal-fired plant would burn about 300,000 short tons of coal annually.
Details of the coal supply, coal delivery, and coal storage systems for the barge-mounted coal-
fired power plant are expected to be similar to those described for the land-based coal-fired
power plant, including covered storage for the coal pile. Likewise, diesel fuel for the backup
combustion turbine will be obtained locally. Processing and disposition of ash wastes would be
the same as for the land-based coal-fired power plant alternative.
The 300,000 tons of coal storage and a single 3-million-gallon fuel storage tank would be located
on the adjacent river bank directly above the barges, and these would be connected to the
generating facilities by a short conveyor and pipeline, respectively. Other auxiliary features of
the barge-mounted coal-fired power plant alternative, including the blowdown pond and the
electrical switchyard, would also be located in this area, which would occupy approximately 80
acres. Exhaust stack height for the barge-mounted plant is estimated at approximately 120 feet,
which would place the top of the stack 60 to 70 feet above the top of the adjacent river bank.
There are significant cost savings to the project for the barge-mounted coal plant over the land-
based coal plant.
2.3 Alternative 3 – Combustion Turbine Plant
The combustion turbine alternative would consist of a 151-MW combined-cycle plant consisting
of three simple-cycle, 42-MW combustion turbines, plus one or two heat recovery steam turbine
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generators with a total capacity of 25 MW. Under this alternative, the power plant would
generate approximately 670,000 MWh annually.
The power plant would burn #2 diesel fuel, of which it would consume about 35 million gallons
annually. The diesel fuel needed to fire the combustion turbine plant would be delivered by
barge to the facility dock and pumped to the facility diesel fuel storage tanks via an aboveground
pipeline. The fuel pipeline will be 8 to 12 inches in diameter and will be elevated 2 feet above
the ground. The fuel pipeline would parallel the new road between the dock and the plant site
mentioned above. Fuel storage requirements would be 25 million gallons annually, and the fuel
would be stored in eight, 3.1 million gallon bermed tanks.
Auxiliary features of the combustion turbine alternative include an electrical switchyard, the
associated 138-kV transmission lines to Bethel, and the initial section of the district heating
system. The entire combustion turbine facility would occupy approximately 40 acres. Exhaust
stack height is estimated at approximately 75 feet.
No ash would be generated by the combustion turbine power plant alternative.
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3.0 CONSULTATION
Input from interested parties is important in determining the permitting requirements for a
project, defining the scope of the environmental analysis, and ensuring that concerns of these
parties are considered from the earliest stages of project planning and development. A letter was
developed and presented initiating consultation with potentially interested parties, including
State of Alaska and federal resource and regulatory agencies, municipalities in the vicinity of the
proposed project, potentially affected native communities, and other stakeholders. The initial
consultation letter included the project description provided in Sections 1 and 2, above, and
solicited input from recipients regarding:
• federal, state, or local permits that will or may be required for the construction and
operation of any of the three alternatives
• general or specific resource issues and concerns that should be addressed in the
environmental analysis of any of the three alternatives
• existing information that would help in conducting accurate and thorough analysis of the
effects of the project
• specific resource studies that will or may need to be conducted
• existing or reasonably foreseeable projects or activities that should be considered in the
assessment of cumulative impacts.
The initial consultation letter described why Nuvista is proposing that development of the Bethel
Power Plant, the Donlin Creek Gold Mine, and the transmission line from Bethel to the mine be
evaluated independently and requested cooperation of recipients with this approach.
A copy of the initial consultation letter, the project description, and the list of parties to whom
the initial consultation letter for the Bethel Power Plant was sent is provided in Attachment 1.
All but a few of these letters were transmitted on September 2, 2003, with a request for responses
by October 1, 2003. A few others were mailed later in response to referrals from the initial
recipients or requests from additional interested parties.
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4.0 COMMENTS ON THE PROPOSED PROJECT
Written responses were received from 11 entities contacted by means of the initial consultation
letter. These responses are summarized below, and copies of the letters are provided in
Attachment 1.
4.1 State of Alaska
Three responses to the initial consultation letter were received from the Alaska Department of
Natural Resources (ADNR).
• Ms. Kerry Howard, ADNR Office of Habitat Management and Permitting, referred future
consultation on the project to Mr. Robert F. McLean, ADNR Office of Habitat
Management and Permitting, Fairbanks Area Office, and to Ms. Sue Magee, ADNR
Office of Project Management and Permitting, for coordination of project review for
consistency with the Alaska Coastal Management Program (ACMP) (ADNR 2003a).
These individuals have been added to the project distribution list.
• Ms. Sue Magee and Ms. Cynthia Zuelow-Osborne, ADNR Office of Project Management
and Permitting, ACMP, each provided a copy of the Coastal Project Questionnaire and
Certification (CPQ) form that is used to determine whether the final proposal will require
a coordinated review for consistency with state and local standards of the ACMP (ADNR
2003b, ADNR 2003c).
Ms. Zuelow-Osborne also referred the project to sources of information on local
standards and requirements as Mr. John Malone, City of Bethel Planning Department,
and, outside the City of Bethel, Mr. John Oscar, Cenaliulritt Coastal Resource Service
Coordinator. These individuals have been added to the project distribution list.
One response to the initial consultation letter was received from the Alaska Department of
Environmental Conservation (ADEC).
• Tom Chapple, Director, ADEC Division of Air and Water Quality, indicated that ADEC
will require an air quality control construction permit and an air quality control operating
permit for the project (ADEC 2003). These may be subject to federal Clean Air Act New
Source Performance Standards (NSPS), in which case the project may be required to
collect ambient air quality data and meteorological data representative of the airshed in
the vicinity of the project and to conduct a case-by-case assessment of control
technologies for the project.
With regard to water quality permits, ADEC may, depending on the design flow and
cooling water discharge conditions, require a state non-domestic wastewater discharge
permit or (more likely) an Environmental Protection Agency (EPA) National Pollutant
Discharge Elimination System (NPDES) permit; water quality standards for temperature
and thermal discharge would apply. If a Clean Water Act Section 404 permit is required
by the U.S. Army Corps of Engineers (ACOE), ADEC water quality staff would need to
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evaluate and certify compliance with state water quality standards under Section 401 of
the Clean Water Act.
Mr. Chapple provided a number of ADEC contacts for specific permitting tasks. He also
directed the project to contact Stan Foo of the ADNR Office of Project Management and
Permitting regarding consistency review under the ACMP and indicated that the project
scope for National Environmental Policy Act (NEPA) review will be delineated by the
lead federal agency in charge of the review.
4.2 Federal Agencies
Six responses to the initial consultation letter were received from federal resource and regulatory
agencies.
• Mr. Bill Allen, State Director, U.S. Department of Agriculture, Rural Development,
stated that his office supports the state administration concerning resource development.
He had no specific recommendations (USDA 2003).
• Mr. William W. Wood, State Biologist, U.S. Department of Agriculture, Natural
Resources Conservation Service (NRCS), indicated that the agency has an established
field office in the town of Bethel and that a copy of the initial consultation letter would be
forwarded to the District Conservationist in charge of that service area (NRCS 2003).
NRCS's initial interest in the Bethel Power Plant Project would focus on: administration
and documentation of the public participation process; potential impacts to private
property natural resources; potential impacts to wetland, water, plant, soil erosion and
sedimentation; and wildlife and fisheries resources.
• Ms. Nora J. Braman, Contracting Officer, Acquisition and Real Estate, U.S. Department
of Transportation, Federal Aviation Administration (FAA) provided an FAA form that
must be completed for coordination and evaluation by the FAA Air Traffic and
Frequency Management Divisions and submitted with a topographic map marked with
the location of the plant site (FAA 2003).
The FAA expressed concerns over the potential for the power plant to generate ice fog
that could adversely affect the Bethel airport and the possible adverse affects on
instrument procedures at the Bethel airport.
• Mr. James W. Balsiger, Administrator, Alaska Region, National Marine Fisheries
Service (NMFS), identified NMFS's two areas of concern related to the project as the
potential impact on Essential Fish Habitat (EFH) for salmon in the Kuskokwim River and
all tributaries within the project boundaries and the potential impact on marine mammals.
Specific EFH concerns for the Bethel Power Plant Project are all potential impacts to five
species of Pacific salmon in the Kuskokwim River, e.g., cooling water source, fish
species present in the proposed cooling pond, and proposed access road stream crossings.
The federal action agency must prepare an EFH assessment for any action that may
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adversely affect EFH; requirements of the EFH assessment, as well as a reference to
NMFS's EFH website, are provided in the response letter. NMFS subsequently reviews
the EFS assessment and offers conservation recommendations to protect EFH.
Mr. Balsiger also offered guidance on compliance with the Endangered Species Act of
1973 (ESA), pointing out that, in addition to including threatened or endangered species
that may occur near Bethel, Section 7 consultation must address threatened or endangered
species that may occur along marine routes. NMFS's concerns are the potential for
petroleum fuel spills and the potential impact of marine traffic transiting the Beaufort Sea
on migration of the endangered bowhead whale.
• Mr. Gary Edwards, Acting Regional Director, U.S. Fish and Wildlife Service (USFWS),
stated that the USFWS believes that the entire scope of the project should be
comprehensively evaluated, including direct, indirect, and cumulative project impacts,
"as is required under [NEPA] . . . when project components are so interrelated as to be
inseparable." According to the USFWS, this would include the transmission line, power
plant and other power generation alternatives, the Donlin Creek mine, the road to the
mine, and secondary power distribution to Yukon Delta and Kuskokwim River villages.
The scope of the NEPA analysis would be determined by the lead federal agency.
Mr. Edwards reiterated comments on the project previously provided by Michael B.
Rearden, Yukon Delta National Wildlife Refuge Manager), i.e., lands within National
Wildlife Refuge selected by but not yet conveyed to Alaska Native corporation are
managed as any other refuge land and any development on such lands would require a
right-of-way (ROW) permit from USFWS; decision on a ROW permit would look at the
existence of feasible and prudent alternatives that would not impact refuge values; refuge
use must be compatible with the purposes for which the refuge was established and with
the mission of the refuge system as a whole.
If a ROW permit is required, feasibility study and environmental analysis of the project
will need to be prepared for the USFWS application, including: assessment of cost and
schedule for preparation of an EIS necessary to evaluate a ROW permit for construction
of the primary transmission line or secondary transmission lines within the Yukon Delta
National Wildlife Refuge and a complete description of all project features including the
power plant, hot water pipelines, central heat exchange, conveyor system, dock, coal and
fuel transfer and storage areas, the Goodnews Bay coal transfer site, cooling water
requirements, ash and cooling water disposal areas, dreded material disposal areas,
transmission lines, and electric power substations.
Project evaluation should also include assessment of factors that could impact USFWS
trust responsibilities, including: potential impacts of project features on migratory birds;
potential impacts of project features on fish and wildlife populations and habitat and on
subsistence activities; construction timing and other methods to minimize impacts to fish,
wildlife, habitat, and subsistence activities; stream crossing methods and buffer strip
retention along transmission lines; fuel transportation, storage, and spill prevention plans;
presence of endangered species and the potential for adverse impacts from direct or
indirect effects to listed species or designated critical habitat at locations of all project
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features; delineation of wetlands and assessment of wetland functional values to aid in
assessment of impacts to fish and wildlife and their habitats; assessment of potential
secondary development in the villages that could potentially impact fish and wildlife
populations and habitat and subsistence activities; methods to mitigate adverse impacts on
the environment, including methods to avoid and minimize impacts to fish and wildlife
populations and habitat and subsistence activities.
• Mr. Don R. Rice, Lead Project Manager, U.S. Army Corps of Engineers (ACOE, "the
Corps"), U.S. Army Engineer District, Alaska, outlined Corps jurisdiction pursuant to
Section 10 of the Rivers and Harbors Act of 1899 for permitting certain structures or
work in or affecting navigable waters of the U.S. The Kuskokwim River is a navigable
waterway as defined by ACOE, Alaska District.
Mr. Rice also outlined Corps jurisdiction pursuant to Section 404 of the Clean Water Act
for permitting placement or discharge of dredged and/or fill material into waters of the
U.S., including wetlands.
A number of criteria that would establish Corps jurisdiction over the federal (NEPA)
review of the project were discussed. With regard to the scope of the NEPA assessment,
the Corps is precluded from "piecemealing" projects for analysis and permitting. "If the
power plant and mine are in fact tied together in an economic analysis, we cannot
separate the power plant from the mine. The power plant must demonstrate an
independent utility to be permitted as a separate action . . . . To consider the Bethel
power generation facility a separate project the plant must be an economically viable
project independent of the mine."
Mr. Rice concluded that to date it appears that the Donlin Creek Mine is an integral part
of the Bethel Power Plant Project and that the Corps is not convinced that the power
generation facility and the mine are independent projects.
4.3 Others
One response to the initial consultation letter was received from parties other than State of
Alaska and federal resource and regulatory agencies..
• Ms. Meera Kohler, President and CEO, Alaska Village Electric Cooperative, Inc.
(AVEC) provided several suggestions for revising Figure 1 of the project description
included with the initial consultation letter (AVEC 2003).
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5.0 ENVIRONMENTAL ISSUES AND MAJOR PERMITTING REQUIREMENTS
Because the Bethel Power Plant is in the initial feasibility design phase and because a number of
alternatives are still being considered, final selection, design, location, and operation of project
facilities are not known. Consequently, it is not possible to precisely delineate all environmental
issues that may arise as a result of the project as it will ultimately be defined. Therefore, this
section will focus on major environmental issues likely to be associated with one or more of the
power plant alternatives and on the major permitting requirements associated with these issues.
Environmental issues and permitting requirements addressed in this section include:
• Alaska Coastal Zone Management
• Air Quality
• Water Quality
• Wetlands and Navigable Rivers
• Fish Habitat
• Floodplain Development
• Air Traffic
• NEPA Compliance
5.1 Alaska Coastal Zone Management
The sites proposed for development of the Bethel Power Plant fall within the State of Alaska’s
Coastal Zone (ADNR 2003c). The project would likely affect two coastal zone management
areas, the City of Bethel Coastal Management District and the Cenaliulriit Coastal Regional
Service Area.
Projects proposed within the Alaska Coastal Zone must conform to Alaska’s Coastal
Management Program (ACMP) and are subject to an ACMP Consistency Review. The ACMP
Consistency Review, administered by the ADNR Office of Project Management and Permitting
(OPMP) is a multiple-agency review process intended to determine the project’s consistency
with the standards of the ACMP and with enforceable policies of approved district coastal
management programs.
The Consistency Review will require the Bethel Power Plant Project to submit a Coastal Project
Questionnaire (CPQ), which OPMP and various state and federal agencies will then review for
program consistency. The CPQ requires completion of the detailed questionnaire and submittal
of information about the Bethel Power Plant, as well as a detailed project description and a
topographic map showing the project location. All information necessary to complete the CPQ
should be available from investigations and data collection for other permits.
OPMP’s permit coordination process includes an evaluation of all permit applications submitted
for the project. Copies of all permit applications must be submitted to the OPMP to complete the
project’s Coastal Project Questionnaire submittal. OPMP forwards copies of these permit
applications to all state and federal agencies that have permit requirements for the project. These
agencies have the opportunity to review all applications submitted for the project and to provide
comments to OPMP. Based on the information received from this review process, OPMP makes
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a determination as to the consistency of the project with ACMP and issues a finding for approval
or denial of the project. Before an agency can approve a permit application, a positive ACMP
finding from OPMP must be received.
While the ACMP Consistency Review is merely a review and approval process and not a permit
itself, it incorporates coordination of a review of the CPQ and all permit applications by all
interested state and federal agencies. Since the review period for the ACMP Consistency
Review does not start until a complete CPQ has been submitted, accurate preparation of the CPQ
is a very important part of the project permitting effort. Coordination with the affected agencies
will greatly facilitate successful completion of the CPQ and substantially reduce the potential for
delays in the review process.
Once the ACMP Consistency Review is complete, approval is valid indefinitely unless the
project is modified.
5.2 Air Quality
Any of the three generating alternatives proposed for the Bethel Power Plant will require an air
quality control construction permit and an operating permit from the Alaska Department of
Environmental Conservation (ADEC). The air quality construction permit is based on projecting
future air quality conditions by dispersion modeling of emissions specified for the proposed
equipment and site-specific pre-construction meteorological and air quality data. The air quality
construction permit will allow the construction and initial operation of the coal-fired boilers
and/or diesel-fired combustion turbines proposed under either Alternative 1, Alternative 2, or
Alternative 3 for the Bethel Power Plant. Once operation of the Bethel Power Plant commences,
the project would apply for an operating permit, which would be based on actual emissions
resulting from operation of the completed facility. Because it is a post-construction requirement,
the air quality operating permit will not be addressed further in this report.
As a new fossil-fuel-fired source of air pollutant emissions with a heat input rating of more than
250 MMBtu/hr and the potential to emit more than 100 tons per year of nitrogen oxides (NOx),
carbon monoxide (CO), sulfur dioxide (SO2), and particulate matter (PM10), the Bethel Power
Plant will require a Prevention of Significant Deterioration (PSD) air quality construction permit.
ADEC will grant air quality construction permit approval if the proposed facility:
• Demonstrates that the expected air quality impacts from the facility will not cause an
exceedance or contribute to an existing exceedance of the National/State Ambient Air
Quality Standards (NAAQS) or exceed PSD increments
• Meets the applicable emission standards or, depending on the vintage and history of the
emitting units, New Source Performance Standards (NSPS) for new air emission units.
Under Alternatives 1 and 2, the proposed facility would use two atmospheric pulverized
coal-fired boilers to supply high-pressure steam to 48-MW steam turbines, plus one 46-
MW diesel-fired simple-cycle combustion turbine, for a total installed capacity of 142
MW. The boilers will likely be subject to 40 CFR 60 Subpart Da (NSPS for electric
utility steam generating units). Under Alternative 3, the proposed facility would consist
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of a 151-MW combined-cycle plant including three simple-cycle, 42-MW combustion
turbines, plus one or two heat recovery steam turbine generators with a total capacity of
25 MW.
• Demonstrates that the air quality impacts will not adversely affect Air Quality-Related
Values (AQRVs), such as visibility, vegetation, soils, and related growth.
The construction permit application will request operating conditions, including those for the
emission control equipment, to ensure that the Bethel Power Plant will comply with Alaska’s air
quality control regulations.
5.2.1 Emission Limits
The boilers will be subject to federal NSPS, Subpart Da, which sets the upper limits for the
emission rates of NOx, PM10, and SO2. The NSPS limits that apply to the boilers are:
• NOx = 0.18 lb/MMBtu
• PM10 = 0.03 lb/MMBtu (99 percent control efficiency)
• SO2 = 0.60 lb/MMBtu (70 percent control efficiency).
PSD review for the Bethel Power Plant will likely require several types of analyses, including
assessment of the Best Available Control Technology (BACT) for of NOx, PM10, SO2, and
carbon monoxide (CO). Technologies that may need to be addressed in the BACT analysis
include:
• NOx -- selective non-catalytic reduction (SNCR)
• CO -- good combustion control
• PM10 -- baghouse
• SO2 -- limestone injection.
The Bethel Power Plant may also emit sufficient quantities of acid gases (hydrogen chloride,
hydrogen fluoride) and heavy metals (e.g., beryllium) and thus be classified as a major source of
hazardous air pollutants (HAPs). Major HAP sources may be subject to Maximum Achievable
Control Technology (MACT) requirements. It is expected that the emission controls that would
be installed as BACT to control criteria air pollutants would also constitute MACT for acid gases
and heavy metals under Section 112(g) of the Clean Air Act.
Though EPA is in the process of developing such regulations, it is not currently known to what
degree coal-fired power plants will need to control their mercury emissions. However, some
mercury control techniques for coal-fired utility boilers include:
• advance coal cleaning
• carbon filter beds (99 percent mercury control)
• wet scrubbing (90+ percent control for water soluble species, limited control for
elemental mercury)
• selenium filters (90 percent mercury control)
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• activated carbon injection (50 to 90 percent mercury control).
It will be important to determine the mercury content of the coal to be fired in the Bethel Power
Plant boilers and closely follow the development of EPA regulations. Possible mercury control
methods should be evaluated during engineering and design of the facility in case the need arises
to retrofit the exhaust stream to further control emissions.
The region in which the Bethel Power Plant is proposed to be located is classified as an
attainment area for all criteria pollutants. Therefore, installation of the Lowest Achievable
Emission Rate (LAER) controls and acquiring emission offsets will not be required.
5.2.2 Ambient Air Quality Analyses
The primary task in the construction permit application process involves dispersion modeling of
NOx, CO, PM10, and SO2 emissions to demonstrate that the proposed Bethel Power Plant will
comply with NAAQS and PSD increments. It is expected that EPA’s refined dispersion model
for industrial sources, AERMOD, will be adequate to demonstrate compliance. The surrounding
terrain is not hilly or mountainous, so use of a complex terrain model should not be required.
A key step in the NAAQS and PSD increment compliance demonstration for the facility will be
securing representative meteorological and ambient air quality data to conduct the dispersion
modeling analyses. In general, meteorological data must be collected on site for a 1-year period
before air quality permitting can begin, but this requirement may be waived if representative
meteorological data from a nearby location is available for use in the dispersion modeling. The
EPA's SCRAM website lists 6 years (1984 through 1989) of surface-level National Weather
Service (NWS) office meteorological data for Bethel. Typically, more recent data would be
necessary to support PSD modeling. It is likely that the National Climatic Data Center (NCDC)
will have more recent data and, therefore, that 5 years of representative NWS data could be
obtained for Bethel Power Plant emissions dispersion modeling. Obtaining suitable NWS data
would preclude the need for the project to collect 1 year of on-site meteorological data.
The air quality analysis would be initiated by contacting the National Climatic Data Center to
obtain the most recent 5 years of representative surface and mixing height meteorological data
for the NWS station in Bethel. The location of the NWS station would be compared to those of
the two proposed project sites to assess the representativeness of the meteorological data for
modeling. The meteorological data would be reviewed for completeness to determine if they
meet PSD data quality requirements, and the available data parameters would be assessed to
determine which EPA-approved dispersion models the data would support. The results of this
review would be presented to ADEC for its concurrence with the use of the existing Bethel NWS
meteorological data for conducting the ambient air quality modeling analysis in support of
construction permitting for the Bethel Power Plant.
Collection of ambient air quality data is another requirement for PSD permitting. However, this
requirement can be avoided if dispersion modeling predicts ambient air quality impacts from the
facility that are less than the de minimis monitoring concentrations. Therefore, if the NWS
meteorological data are deemed by ADEC to be suitable and representative for conducting the
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dispersion modeling, a dispersion modeling analysis can be conducted using stack parameters
and emissions as currently envisioned. If the results of the modeling analysis indicate that the
impacts are higher than de minimis monitoring concentrations, the project may seek ADEC’s
concurrence with the use of existing air quality data to represent the ambient air quality
background concentrations for the region and, if necessary, to fulfill the requirements for pre-
construction air quality monitoring.
5.2.3 Air Quality-Related Values
A PSD construction permit applicant must perform an AQRV analysis to ensure that
environmental values (i.e., visibility, flora, fauna, etc.) are not adversely affected by the total
pollutant concentration they will experience as a result of emissions from the proposed source,
any recently permitted (but not yet operating) sources in the area, and existing sources. The
AQRV analysis must include a cumulative air quality analysis in which the proposed source and
any recently permitted (but not operating) sources in the area are modeled. This total modeled
concentration is then added to measured ambient levels to assess the effect of all anticipated
ambient concentrations on AQRVs.
No Class I air quality areas (specified national parks, wilderness areas, national wildlife areas, or
native American lands) exist in close proximity to the proposed locations for the Bethel Power
Plant. Furthermore, no other large sources of pollutants that might potentially contribute to
cumulative air quality impacts occur in the area. Finally, because the project will utilize BACT,
impacts to soil and vegetation are not anticipated to be significant. Therefore, it is not likely that
an AQRV analysis would result in adverse impacts to AQRVs.
5.3 Water Quality
All three alternatives for the Bethel Power Plant would utilize an approximately 79-acre
naturally occurring freshwater pond for the recirculation of condenser cooling water from the
steam turbines. Because of the preliminary nature of this evaluation, the facility’s wastewater
discharge has not yet been thoroughly characterized. Plant process water would be treated to
meet State Water Quality Standards before being discharged into the cooling pond, and so the
most significant component of the facility’s wastewater discharge is likely to be elevated
temperatures. However, the volume of condenser cooling water required to be circulated under
each of the three alternatives is not known at this time and, therefore, the resulting temperature
regime of the cooling pond has not been modeled. Likewise, the biological characteristics of the
proposed cooling pond, including fisheries, other aquatic species, and wildlife, are not known, so
potential impacts to these systems from wastewater discharge to the pond cannot be predicted at
this time. Also, the proposed cooling pond may be hydrologically connected to local
groundwater aquifers and the nearby Kuskokwim River, and the potential for impacts to these
systems from changes in the cooling pond temperature would need to be investigated.
If disposal of the Bethel Power Plant’s thermal effluent and operational wastewater requires
discharge of wastewater or pollutants to waters of the U.S., it will be necessary to secure a
National Pollutant Discharge Elimination System (NPDES) Wastewater Discharge Permit as
mandated by the Clean Water Act. NPDES permitting for industrial wastewater discharges is
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regulated by U.S. Environmental Protection Agency (EPA) Region 10 in the State of Alaska.
Preparation of an NPDES permit requires the State to complete a Clean Water Act Section 401
Certification, which is the state’s certification that the proposed discharge meets all State-
mandated Water Quality Standards (18 AAC 70) and that the discharge will not result in
unacceptable environmental impacts. Therefore, NPDES permit preparation would be completed
by the EPA, and the Section 401 Certification would be completed by ADEC.
One alternative to use of the proposed cooling pond is the installation of forced-air cooling
towers to provide all of the necessary cooling for plant operations. Installation of forced-air
cooling towers would eliminate the need for the cooling pond and, likewise, the need for an
NPDES permit and Section 401 Certification for cooling water. Elimination of these permitting
requirements could significantly reduce the overall permitting effort and cost of the project.
Installation of forced-air cooling towers would also eliminate the need for NEPA compliance
triggered by the NPDES permitting process (but not necessarily NEPA compliance that might be
triggered by other federal actions).
5.3.1 NPDES Permit
If the 79-acre pond for the recirculation of condenser cooling water from the steam turbines is
selected as the preferred alternative, the Bethel Power Plant Project will be required to submit an
NPDES permit application to EPA prior to commencement of plant operations. It will be
necessary to collect on-site data and conduct thermal modeling, including information on the
quantity and quality of raw water to be withdrawn from the cooling pond, as well as the quantity
and quality of effluent and other related information, prior to developing the NPDES permit
application. Following receipt of the application, EPA will prepare the NPDES Wastewater
Discharge Permit.
It is likely that the only difficulty that would prevent issuance of the draft NPDES permit might
be meeting State standards for approval of the Section 401 Certification and identification of
unmitigable impacts from the thermal discharge. The State Section 401 Certification will be
prepared concurrently with the draft NPDES permit and, following completion of both, the draft
NPDES permit will be submitted for public comment. Public opinion of a project such as this is
very difficult to forecast and could affect the permit processing schedule. By addressing any
public concerns early in the permitting process, it is usually possible to limit or eliminate delays
resulting from public opposition.
Though securing an NPDES permit for the facility’s wastewater discharge will require a
significant level of effort, there are no indications that such an effort would be impossible unless
the project identified significant impacts or was unable to meet State Water Quality Standards.
The greatest impact to project development would likely be the uncertainty associated with the
schedule for securing the final permit. EPA’s backlog, field and technical studies needed to meet
the requirements for a State Section 401 Certification, or public opposition could all delay final
permit approval. If this option is to be considered, it is recommended that the project consult
with EPA and ADEC staff after the wastewater discharge requirements for operations are
established to identify and quantify any areas of concern. If the project has done a thorough job
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in addressing the concerns of EPA and ADEC during preparation of the draft permit, then it is
unlikely public opposition will result in significant project delays.
Because this action requires a federal approval for a new source of a wastewater discharge, it is
likely that EPA will require the project to undergo NEPA compliance. EPA will likely require
preparation of Environmental Assessment (EA), and if this assessment demonstrates that project
development will not result in a significant environmental impact, NEPA requirements will have
been met. If it is determined that project development may result in environmental impacts, EPA
will require preparation of an Environmental Impact Statement (EIS). EA and EIS requirements
are discussed in greater detail in the NEPA Compliance section of this document.
5.3.2 Section 401 Certification
ADEC will conduct an antidegradation review and a water quality review after receipt of an
NPDES permit application and a Section 401 Certification application from the project. The
Section 401 Certification will be completed concurrently with the draft NPDES Permit and will
identify any potential problems with the proposed discharge. It is assumed that, through
treatment, all constituents of the facility’s wastewater discharge other than temperature will meet
State Water Quality Standards. It will be up to OCMP to determine potential impacts and make
recommendations as to allowable thermal discharges to the cooling pond. Once allowable
discharge limits have been established, a variety of design alternatives will be evaluated to
maintain thermal discharges at or below these limits.
It will likely be necessary to study temperature impacts to the proposed cooling pond and any
other potentially connected waters before ADEC would approve the facility’s proposed
discharge. At a minimum, this will require thermal modeling to identify the extent of the thermal
impact to fisheries, other aquatic species, and wildlife associated with the cooling pond. State
Water Quality Standards also include a clause that allows a facility to petition for a variance
from the thermal standard if it is shown that the established temperature limit is more stringent
than what is necessary to protect the resource. Further evaluation will be necessary to determine
if this variance will be available to the Bethel Power Plant.
Issuance of the Section 401 Certification will depend on the nature of the impacts identified from
the facility’s discharge. Additional analysis may be required to quantify these impacts before
ADEC will issue the Section 401 Certification. ADEC may also request that the Alaska
Department of Fish and Game (ADF&G) provide its comments on the Section 401 Certification
prior to issuing its approval to ensure fisheries issues are adequately addressed.
The Section 401 Certification will be issued with the draft NPDES permit, assuming no
significant problems are identified. Processing time could depend on the number of Section 401
Certifications being prepared by ADEC at the time of application submittal.
5.3.3 NPDES Stormwater Discharge Permit for Operations
As an industrial facility, the Bethel Power Plant will need an NPDES Permit for stormwater
discharges associated with industrial operational activities. This permit is administered by EPA
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and would be authorized under a Multi-Sector General Permit that has been issued to the State of
Alaska. The major requirement for this permit will be a demonstration that stormwater
discharged from the facility and its associated property to waters of the State does not contain
pollutants. Testing for contaminants at the stormwater outfall and demonstrating that control
structures are in place to effectively contain all potential pollution will effectively meet this
requirement. A Stormwater Pollution and Prevention Plan (SWPPP) detailing the location and
effectiveness of control structures, sampling techniques and frequencies, pollutants stored on
site, and reporting requirements will be developed as a condition of the permit. An evaluation of
the facility for appropriate maintenance and installation of Best Management Practices to prevent
sediment and pollution from entering waters of the State through stormwater discharge will
provide the basis for developing the SWPPP. EPA will work with the permittee to ensure that an
agreement is reached that will allow coverage under an NPDES Stormwater Discharge Permit.
It is possible to include the analysis and application for the NPDES Stormwater Discharge
Permit with that for the NPDES Wastewater Discharge Permit.
5.4 Wetlands and Navigable Rivers
The site proposed for construction of Bethel Power Plant Alternative 1 or Alternative 3 occupies
low-lying tundra areas, wetlands, and ponds. Alternative 2 proposes construction and/or
dredging and filling within the floodplain of the Kuskokwim River to accommodate barge-
mounted power plant units. All three power plant alternatives propose the use of a naturally
occurring, approximately 79-acre pond for steam-cycle cooling of the power generation facilities
(see Figure 1). Any or all of these activities would likely trigger federal permitting under the
Clean Water Act and/or the Rivers and Harbors Act.
The Corps regulates impacts to wetlands and waters of the U.S. by enforcing the requirements of
Section 404 of the Clean Water Act. Section 404 requires that a Department of the Army permit
be obtained for the placement or discharge of dredged and/or fill materials into waters of the
U.S., including wetlands. For regulatory purposes, the Corps defines wetlands as those areas that
are inundated or saturated by surface water or groundwater at a frequency and duration sufficient
to support, and under normal circumstances do support, a prevalence of vegetation typically
adapted for life in saturated soil conditions. Land-clearing operations involving vegetation
removal with mechanized equipment, windrowing of vegetation, land leveling, or other soil
disturbances in wetlands are considered placement of fill material under Corps jurisdiction.
Given the proposed location of the Bethel Power Plant relative to the prevalence of wetlands, it
is likely that significant involvement will be required by the Corps in applying its regulatory
requirements for wetlands disturbance under Section 404. Consequently, it is necessary to
consider potential impacts to these resources as project development proceeds. Development of
the power plant and appurtenant conveyors and pipelines may require one or more wetlands
permits. A site investigation and wetland delineation/determination will be necessary to
determine the extent to which project development will impact regulated wetlands and waters of
the U.S.
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Likewise, the Corps regulates construction of certain structures or work in or affecting navigable
waters of the U.S. pursuant to Section 10 of the Rivers and Harbors Act of 1899.
5.4.1 Section 404 Nationwide Permit
The nature and extent of the wetlands to be developed have a significant influence over the
permitting requirements and degree of permitting difficulty. Under many circumstances,
temporary disturbance to wetlands resulting from certain construction and development activities
can be completed under a Corps Section 404 Nationwide permit (Nationwide permit) to meet
federal regulatory requirements. Securing a Nationwide permit generally is a straightforward
procedure requiring minimal time, effort, and expense to complete and, as a rule, does not
require wetlands mitigation.
Some aspects of project development may be covered under Nationwide permit(s), however the
bulk of most project development activities would require an Individual permit, the details of
which are discussed below. These issues will need to be discussed in consultation with the
Corps prior to project development.
5.4.2 Section 404 Individual Permit
Depending on the existing biological characteristics of the pond designated for development as
the project cooling pond, the design of proposed inlet and outlet structures, and the nature of
physical impacts resulting from its operation as a cooling pond (e.g., water temperature, water
surface elevation), use of this natural feature as a cooling pond could result in significant impacts
to wetlands and their functional values. Consequently, its development could require a more
involved and complicated wetlands permitting effort. Other wetland areas would also be
impacted by surface disturbance related to construction of the power plant and its appurtenant
structures.
Significant disturbance to wetlands typically requires a Section 404 Individual permit (Individual
permit), and the level of effort necessary to secure an Individual permit can vary greatly but
usually requires a fairly significant permitting effort. Assuming that an Individual permit is
required for development of the cooling pond, it is likely that the Corps would include all
wetland-related impacts from project development under the Individual permit in order to
evaluate all project-related impacts cumulatively. This would preclude the need for additional
Nationwide permits for other project development activities. Securing an Individual permit
would require field investigations, including wetland delineations, wetlands mitigation, and
possibly habitat assessments for federally listed threatened and endangered species. It will also
be necessary to evaluate the project area to determine that high value wetlands will not be
affected by project development. Preparation of an Individual permit would also require the
State of Alaska to complete a Clean Water Act Section 401 Certification
The greatest concerns for project development that could result from disturbance of wetlands
requiring an Individual permit would be a long processing time for approval of the permit and
the possibility of the Corps requiring significant mitigation for impacts to wetlands. It is not
possible to accurately determine the degree of permitting difficulty without a more thorough
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assessment of the project area and consultation with the Corps. In addition, if an Individual
permit were required for project development, then it is possible that issuance of this permit
would be considered a major federal action, which would result in the application of NEPA
requirements to the project.
If the project were to install forced-air cooling towers to provide plant cooling in place of the
cooling pond alternative, project development might be able to proceed with a lesser wetlands
permitting effort for plant construction and the installation of other appurtenances. As stated
previously, this level of wetlands disturbance might typically be permitted through one or more
Nationwide permits, and securing these permits usually requires a reasonable level of effort.
Thus, the need for an Individual permit and the associated 401 Certification for wetland
disturbances would possibly be reduced, though this is a Corps decision and cannot be
determined at this time. Elimination of Individual permit requirements through the Corps could
significantly reduce the overall permitting effort and cost of the project. Elimination of the
Individual 404 permit would also reduce the federal requirement for NEPA compliance for
Section 404 permitting (but not necessarily NEPA compliance that might be triggered by other
federal actions).
5.4.3 Section 401 Certification
Approval of an Individual permit from the Corps would also require securing a Section 401
Certification from ADEC as mandated by the Clean Water Act. Disturbances from development
in wetlands can result in impacts to water quality downstream from the area of disturbance.
ADEC will require the project to demonstrate that the appropriate controls will be used to
prevent impacts that degrade water quality beyond the State Water Quality Standards. It is
assumed that the project will be able to meet these requirements and that there will be no
complications in securing this certification.
5.4.4 Rivers and Harbors Act
Corps jurisdiction under the Rivers and Harbors Act is limited to "navigable water" or to waters
subject to the ebb and flow of the tide shoreward to the mean high water mark that may be used
to transport interstate or foreign commerce. The Kuskokwim River is a navigable waterway as
defined by the ACOE, Alaska District.
All alternatives propose the construction of at least dock and barge-unloading facilities adjacent
to the Kuskokwim River, and Alternative 2 proposes construction and/or dredging and filling
within the river floodplain. Tradeoffs between the Clean Water Act Section 404 and the Rivers
and Harbors Act Section 10 permitting requirements for the different alternatives could become a
significant factor in the final choice of Bethel Power Plant alternatives.
5.5 Fish Habitat
All three alternatives for the Bethel Power Plant involve aquatic habitats and, therefore
potentially, fish habitat. The Kuskokwim River, which will host at least dock and barge-
unloading facilities under all alternatives and also constructed mooring accommodations for the
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barge-mounted power plants under Alternative 2, is considered by NMFS to be Essential Fish
Habitat (EFH) for five species of salmon under the Magnuson Stevens Fishery Conservation and
Management Act. The Kuskokwim River is also catalogued as an anadromous fish stream by the
Alaska Department of Fish and Game (ADF&G) (ADF&G 2003).
The fisheries status of the naturally occurring pond that has been designated for development as
the project cooling pond for all three power plant alternatives is not known, nor is its hydrologic
relationship to the Kuskokwim River or to other potential fish habitats.
Both federal and State resource agencies have an interest in fish habitat in Alaska, including the
National Oceanic and Atmospheric Administration’s NMFS and the Alaska Department of
Natural Resources, Office of Habitat Management and Permitting.
5.5.1 Essential Fish Habitat Assessment
In its response to the initial consultation letter for the Bethel Power Plant Project, NMFS
identified its specific EFH concerns for the project as all potential impacts to the five species of
Pacific salmon in the Kuskokwim River. These species include chinook salmon, coho salmon,
sockeye salmon, chum salmon, and pink salmon. NMFS general concerns regarding the project
include the cooling water source, fish species present in the proposed cooling pond, and
proposed access road stream crossings.
NMFS requires the federal agency authorizing the project to prepare an EFH Assessment for any
action that may adversely affect EFH. The EFH Assessment may be a separate document or be
clearly referenced as a support document to an EA or an EIS for the project. The EFH
Assessment includes the following mandatory contents: (i) a description of the proposed action,
(ii) an analysis of the effects on EFH, (iii) the agency's views regarding the effects of the action
EFH, and (iv) proposed mitigation.
Once it has received the EFS Assessment, NMFS reviews it and offers conservation
recommendations to protect EFH, if any, to the federal action agency. These recommendations
would be considered in the NEPA assessment.
5.5.2 Fish Habitat Permit
The ADNR Office of Habitat Management and Permitting (OHMP) Fish Habitat Permit is
designed to guarantee efficient passage of fish and to protect and conserve fishery resources and
fish habitat in waters designated as important for the spawning, rearing, and migration of resident
and anadromous fish. Historically impacts to anadromous fish have been emphasized in the
application of this permitting requirement; however, the possibility exists that OHMP could
regulate impacts to resident fish. A Fish Habitat Permit could be required for any instream work
during both the construction and operations phases of the project and for wastewater discharges.
Because of its classification as an anadromous fish stream by ADF&G, construction activities in
the Kuskokwim River under any of the three alternatives would likely require application for a
Fish Habitat Permit, and, depending on the fisheries characteristics of the proposed cooling pond,
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location or construction of the cooling water discharge pipe and discharge of non-contact cooling
water to the cooling pond might also require this permit.
A letter of intent and complete copies of the plans and specifications for the proposed activity
normally satisfy permit application requirements. The application must include: 1) type of
project and its purpose, 2) legal description of the project site, 3) type and timing of the activity,
4) description of any dredge and fill activities, 5) characteristics of the waterbody, and 6)
engineering drawings or sketches of hydraulic structures to be placed below the ordinary high
water mark of the water body. Additional information relating to the quantity of intake water
and to the source, quantity, and quality of discharge water may also be required.
It is anticipated that the project will be required to evaluate the potential for impacts through
detailed analysis of fisheries. The requirements for these analyses would be met by the studies
required for preparation of an EIS, or, if an EIS is not required, these studies should be designed
to meet the requirements for the Fish Habitat Permit. Data collection and field surveys for Corps
permit applications will generally also meet the requirements of the Fish Habitat Permit
application. A possible exception could be the collection of additional flow data should existing
data prove to be incomplete. The application for this permit would be submitted at
approximately the same time as the application for the Corps permit because of the similarity of
their requirements. Based on previous experience with similar projects, there are no foreseeable
difficulties in obtaining a Fish Habitat Permit for the project unless important fisheries are found
to exist in the proposed cooling pond.
Construction of an air-cooled condenser would eliminate the need for the cooling pond as well as
for the discharge of cooling water. Under these circumstances, the need for a Fish Habitat
Permit for the project may be minimized, assuming that project development could proceed
without impacts to anadromous fish in the Kuskokwim River.
5.6 Floodplain Development
All alternatives for the Bethel Power Plant propose the construction of at least dock and barge-
unloading facilities along the Kuskokwim River, and Alternative 2 proposes construction and/or
dredging and filling within the Kuskokwim River floodplain to accommodate the barge-mounted
power plant. The approximate elevation of the designated mapped floodplain near Bethel is 17
feet mean sea level (HDR 2003), so, at approximately 50 feet mean sea level, most of the
construction for Alternative 1 or Alternative 3 would likely be outside the Kuskokwim River
floodplain.
Prior to issuing any building, grading, or development permits involving activities in a regulatory
floodway, the project must provide certification that the proposed development will not impact
the pre-project base flood elevations, floodway elevations, or floodway data widths. A “no-rise”
assessment would need to be conducted to meet this certification requirement. The engineering
or “no-rise” certification must be supported by technical data, which involves two separate
analyses: a step-backwater analysis and a conveyance analysis. Computer models are used to
determine the changes in floodplain elevations that would result from the proposed development.
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The certification is provided by the permittee and is signed and sealed by a registered
professional engineer.
In addition to the “no-rise” certification, an Application for Flood Hazard Permit must be
completed and submitted to the local municipality.
Applicability of these requirements to the project will depend on the nature of the dredging and
mitigation activities occurring in the Kuskokwim River floodplain. A determination as to the
necessity of a floodplain assessment will be made concurrently with development of the
permitting requirements for dredging activities in the Kuskokwim River. If it is deemed
necessary, a floodplain assessment will need to be conducted as required by the Federal
Emergency Management Agency (FEMA).
5.7 Air Traffic
Each of the three alternatives proposed for the Bethel Power Plant is located within
approximately 2 miles of the Bethel Airport. A notice must be provided to the Federal Aviation
Administration (FAA) if structures are constructed or installed that may interfere with aircraft
flight paths. In its response to the initial consultation letter for the Bethel Power Plant, the FAA
provided FAA Form 7460-1 (Notice of Proposed Construction or Alteration), which must be
completed for coordination and evaluation by the FAA Air Traffic and Frequency Management
Divisions. The FAA letter expressed concern over possible adverse effects on instrument
procedures to the airport and the potential for the power plant to generate ice fog that could
adversely affect the airport. Form 7460-1 will be provided to the FAA, along with a topographic
map with the plant site identified, for a determination of the aircraft safety considerations
associated with constructing the Bethel Power Plant stack(s). Based on the relatively short
stacks envisioned at the facility, it is not at this time anticipated that there will be difficulties in
receiving FAA approval.
Considering the proximity of the proposed facility to Bethel Airport, it is realistic to assume that
the Bethel Power Plant stacks will require some form of marking to meet FAA approval. The
FAA will place notification of impending construction of a new obstruction on Sectional
Aeronautical Charts, and pilots will be notified through Notice to Airman and other flight
information publications in accordance with FAA flight safety regulations.
The issue of potential ice fog formation from power plant operation would also be investigated
as part of the meteorological/air quality analysis in the NEPA assessment.
5.8 NEPA Compliance
5.8.1 Trigger for NEPA Compliance
Major federal actions require compliance with the National Environmental Policy Act (NEPA).
Major federal actions include authorizing development of public lands, federal funding of a
project, or issuance of a federal permit that authorizes activities with the potential for
environmental effects. As currently envisioned, partial funding of the Bethel Power Plant
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Project would be provided through the U.S. Department of Agriculture (USDA), Division of
Rural Utilities (RUS). Thus, federal funding would likely be the trigger for NEPA compliance,
and RUS would be the lead agency for the NEPA review. Other federal actions related to the
three proposed alternatives for the Bethel Power Plant that could result in a NEPA compliance
requirement are EPA NPDES permitting and Corps Section 404 permitting, primarily due to
development of the cooling pond. Federal regulations stipulate that issuance of an NPDES
permit to a new source by EPA may be a major federal action and, as such, could be subject to
the environmental review provisions of NEPA. NEPA compliance is not typically required for a
Corps Section 404 Nationwide permit but can apply to a project requiring a Section 404
Individual permit. In addition, it is possible that NEPA compliance could be required if work in
the Kuskokwim River, particularly the more significant earthmoving and construction work
described for Alternative 2, required Corps permitting under Section 10 of the Rivers and
Harbors Act. If these federal permits were required, the agencies administering them would
likely be cooperating agencies in the NEPA review process.
5.8.2 Scope of NEPA Consistency Review
An issue that has arisen in assessing the feasibility and permittability off the Bethel Power Plant
is whether development of the power plant and appurtenances and the associated transmission
line can be separated from development of the Donlin Creek Gold Mine, at least from a NEPA
compliance standpoint. The development of the Bethel Power Plant is seen by certain agencies
to be closely tied to development of the gold mine in that the mine would constitute the majority
consumer of the power produced under the current development scenario, and providing the
power to the mine is the predominant factor in transmission line routing.
In response to the initial consultation letter for the Bethel Power Plant, the USFWS commented
that it believes that the entire scope of the project should be comprehensively evaluated,
including direct, indirect, and cumulative project impacts, "as is required under [NEPA] . . .
when project components are so interrelated as to be inseparable" (USFWS 2003). According to
the USFWS, this would include the transmission line, power plant and other power generation
alternatives, the Donlin Creek mine, the road to the mine, and secondary power distribution to
Yukon Delta and Kuskokwim River villages.
With regard to the scope of the NEPA assessment, the Corps stated in its response to the initial
consultation letter that, when the Corps has jurisdiction over NEPA review, it is precluded from
"piecemealing" projects for analysis and permitting. "If the power plant and mine are in fact tied
together in an economic analysis, we cannot separate the power plant from the mine. The power
plant must demonstrate an independent utility to be permitted as a separate action . . . . To
consider the Bethel power generation facility a separate project the plant must be an
economically viable project independent of the mine." The response concluded that it appears
that the Donlin Creek Gold Mine is an integral part of the Bethel Power Plant Project and that the
Corps is not convinced that the power generation facility and the mine are independent projects.
Although some parties have suggested that the gold mine and power plant/transmission line
projects be evaluated together, there are a number of important reasons for treating them
independently.
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• First, scheduling constraints require that environmental review and permitting of the
power plant and transmission line must proceed ahead of those for the mine so that these
facilities can be constructed and operational by the time power is needed for mine
construction and operation. If not, the mine would need to permit and operate its own
power generating source until the Bethel Power Plant and transmission lines were
completed, which would preclude the need for an alternative power source and would
likely preempt development of the Bethel Power Plant as proposed.
• Second, development of the Bethel Power Plant, as proposed, represents only one of
several alternative sources of electrical power for the gold mine; therefore, analysis of the
power plant in the context of the environmental assessment for the mine is not likely to
be as thorough as would be possible under an independent review.
• Third, the entirely different functions of the facilities and the considerable distance
between the gold mine, the (majority of the) transmission line, and the proposed power
plant location suggest few synergies to be realized from coordinated review of these
facilities. Other than regarding socioeconomic considerations, few similar impacts are
expected from the three projects, and these could be evaluated under the cumulative
impacts assessment for each, as appropriate.
• Finally, the power plant could be developed independent of development of the gold
mine, and vice versa; e.g., a power plant could be constructed to serve just the local
community and other communities in the region along the transmission line route.
A number of reviewers have pointed out that the scope of the NEPA analysis will be delineated
by the lead federal agency in charge of the review. However, conversely, selection of the lead
federal agency will likely be determined by the scope of the NEPA review. Thus, as discussed
above, if the scope of the NEPA review is restricted to the Bethel Power Plant and the
transmission line, RUS would likely be the lead agency, whereas, if the scope of the NEPA
review is extended to include the gold mine, another federal agency, such as the U.S.
Departments of the Interior or Army could be the lead agency, depending on the nature of the
major federal action requiring NEPA compliance. The issue of how NEPA compliance for the
Bethel Power Plant Project can be structured to both accomplish a valid environmental analysis
of the project and preserve the necessary project schedule needs further investigation. It is
possible that providing an enhanced treatment of cumulative impacts, including those from the
proposed mine, in the NEPA analysis for the power plant/transmission line, along with tiering of
any subsequent NEPA analysis for the gold mine, would be a satisfactory approach. We
recommend that a meeting among the potentially affected parties and agencies to discuss and
define the fundamental issue of project scope at this early stage in project planning would be
useful in resolving this issue early in the permitting process for the Bethel Power Plant Project.
For the purpose of this review of NEPA Compliance requirements for the Bethel Power Plant
Project, we will continue to assume that the scope of the NEPA review will include only the
power plant and its appurtenances and the associated transmission line and that RUS will be the
lead federal agency.
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5.8.3 Environmental Assessment
NEPA compliance generally requires an analysis of the environmental effects of the action,
typically through preparation of an EA or an EIS. It is assumed that RUS would require
preparation of an EIS for the project.
The federal lead agency for the NEPA review would require the project to provide information
regarding the nature of project development and the potential for environmental impacts in an
Environmental Information Document (EID). The requirements for the information contained in
this document are not well defined and would be determined based on the project and the project
location. The information required for the EID would also depend on such things as the size of
the project and the availability of supporting information. The EID will be the basis for
preparation of the NEPA documents.
If a preliminary environmental review indicates that a significant environmental impact may
occur and this impact cannot be eliminated by modification of the proposed project, an EIS will
be required. While it is not possible to predict the ultimate outcome of the environmental
review, the possibility exists that an EIS will be necessary for development of the Bethel Power
Plant/transmission line.
The federal lead agency has the responsibility for preparing the EIS. The project proponent
usually has the option of retaining a third party contractor acceptable to the federal lead agency
to prepare the EIS in order to expedite preparation of the document.
An EIS is a thorough environmental review of the proposed project, including a detailed
evaluation of what is termed the “affected environment.” Several of the key components of the
evaluation of the affected environment will be discussed in greater detail below. These issues
have been selected and included in the NEPA Compliance section of this report because these
issues would be addressed in that document. However, even if an EIS is not required, these
issues would likely have to be addressed before securing approval for other project permits.
• Threatened and Endangered Species. The EIS will require an evaluation of project-
related impacts on endangered species as mandated by the Endangered Species Act of
1973 (ESA), and regulations under this Act are enforced by the USFWS and NMFS. An
evaluation of impacts to endangered species may also be required for approval of any
federal permits required for project development in the absence of an EIS. If it is
determine that project activities will not affect federally listed threatened or endangered
species or their habitat, then the project will have met its regulatory requirements under
the ESA.
Review of existing documentation for the area preliminarily indicates that federally listed
endangered species or endangered species habitat do not occur at the project site. A more
detailed analysis will be required to confirm these findings through ESA Section 7
Consultation with USFWS. This consultation may require a detailed habitat assessment
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for any listed species and their habitat that could occur in the project area. It is possible
that existing documentation may preclude the need for a detailed habitat assessment.
In its response to the initial consultation letter for the Bethel Power Plant, NMFS offered
guidance on compliance with the ESA, pointing out that, in addition to including
threatened or endangered species that may occur near Bethel, ESA Section 7 consultation
must address threatened or endangered species that may occur along marine routes
proposed for use in supplying coal to the project. NMFS's concerns are the potential for
petroleum fuel spills and the potential impact of marine traffic transiting the Beaufort Sea
on migration of the endangered bowhead whale.
• Wildlife and Habitat. The proposed location for the Bethel Power Plant lies adjacent to
the Yukon Delta National Wildlife Refuge, as does most of the landscape that would be
traversed by the transmission line. The Refuge is known to provide prime habitat for a
wide variety of wildlife species, including brown and black bears, caribou, moose and
wolves. In terms of both density and species diversity, the Yukon Delta is the most
important shorebird nesting area in the United States. Birds from six major flyways, from
the Atlantic Ocean to the east coast of Asia, nest on the refuge or stop to rest and feed
during migration. A detailed habitat assessment will likely be required to identify
potential impacts to these animals. Where significant impacts to wildlife are identified,
project development would need to be modified or mitigation would need to be provided.
The Kuskokwim River and its tributaries provide hundreds of miles of spawning and
rearing habitat for fish. A total of 44 species use the Yukon Delta National Wildlife
Refuge's waters, including all five North American Pacific salmon, Dolly Varden char,
northern pike, sheefish, arctic grayling, several species of whitefish, burbot and rainbow
trout. Although fisheries characteristics of the proposed cooling pond are not known, its
operation could result in impacts to any resident species, and these potential impacts
would need to be evaluated. Again, where impacts are identified, project development
would need to be modified or mitigation provided. An assessment of potential impacts to
fish species is provided in the development of the OHMP Fish Habitat Permit. Likewise,
assessment of potential impacts to salmon in the Kuskokwim River and its tributaries is
provided in the NMFS Essential Fish Habitat Assessment.
• Cultural and Archaeological Resources. Cultural resources are prehistoric, ethno-
historic, or historic properties, sites, objects, or districts that reflect past human use of the
land. NEPA requires consideration of cultural resources, as does the National Historic
Preservation Act (NHPA). The NHPA mandates that federally funded, licensed, or
permitted actions must afford the federal Advisory Council on Historic Preservation an
opportunity to comment on actions that may affect cultural resources. Other key laws
that pertain to assessment, mitigation, and preservation of cultural resources and graves
include the Archaeological and Historic Preservation Act, the Archaeological Resources
Protection Act, and the Native American Graves and Repatriation Act.
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The State Historic Preservation Officer (SHPO) will also issue a Cultural Resources
Concurrence under the NHPA and the Alaska Historic Preservation Act for developments
that may affect historic or archaeological sites. ADNR approval could be required under
circumstances where federal requirements do not apply, as would be the case when a
project required state permits but did not require major federal permits.
There are a number of sources of information on cultural resources in Alaska, the records
of which will need to be searched to identify any known archaeological sites prior to
project development. Following the records research, it is likely that field surveys to
identify cultural resource sites will also be required to satisfy NHPA Section 106
requirements. Depending on the significance of any survey finds, some items may
merely be catalogued and/or collected, while, in other situations, sites may be excluded
from development, which can have significant impacts on project schedule and cost. It is
likely that project development would be able to proceed without significant negative
effects from the presence of cultural or archaeological resources, assuming effort is
expended to identify these sites early in project development.
Also included in the evaluation of the affected environment are such subjects as climate and air
quality, geology and soils, vegetation, wetlands, water resources, socioeconomic resources,
visual resources, recreation and tourism, and health and human safety. Some of these subjects,
such as air quality, wetlands, and water resources, will require evaluation with or without the
requirement of an EIS. However, the level of project scrutiny and the additional requirements
for study and analysis of project impacts to numerous other potentially affected resources will
require a significant level of time, effort, and expense should an EIS be required for project
development.
An EIS will also include a comparison of several project alternatives that ultimately leads to a
preferred alternative that will address and mitigate environmental impacts while allowing project
development to move forward, although it is possible that findings in the EIS will indicate that
the environmental impacts resulting from the proposed project are unacceptable and an
approvable alternative is not available. It is not expected that the Bethel Power Plant Project, as
proposed, will result in unmitigable environmental impacts preventing project development. It is
likely, however, that preparation and approval of an EIS will be a significant burden to project
development resulting in high permitting costs and potential project delays.
5.9 Field Data Collection
Data collection requirements have been identified for a number of the permits described above.
Agencies typically establish study requirements in the course of consultation on specific
permitting issues, and required field studies must be designed and implemented in support of the
permits being developed. Field work can generally be accomplished during one summer field
season and is followed by data analysis and report preparation. Total time to complete field
studies may be expected to be on the order of 6 to 8 months.
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5.10 Potential Permits And Approvals For Bethel Power Plant
Agency Name Permit/Approval
Alaska Department of Natural
Resources, Office of Project
Management and Permitting
Alaska Coastal Management Program (ACMP)
Consistency Review
Alaska Department of Environmental
Conservation, Division of Air and Water
Quality
Air Quality Construction Permit, including
monitoring programs
U.S. Environmental Protection Agency National Pollutant Discharge Elimination System
(NPDES) Wastewater Discharge Permit
Alaska Department of Environmental
Conservation, Division of Air and Water
Quality
Clean Water Act Section 401 Certification(s)
Alaska Department of Environmental
Conservation, Division of Air and Water
Quality
National Pollutant Discharge Elimination System
Stormwater Discharge Permit for Operations
U.S. Department of the Army, Army
Corps of Engineers
Clean Water Act Section 404 Nationwide and/or
Individual Permits
U.S. Department of the Army, Army
Corps of Engineers
Rivers and Harbors Act Section 10 Permit
Alaska Department of Natural
Resources, Office of Habitat
Management and Permitting
Fish Habitat Permit
U.S. National Oceanic and Atmospheric
Administration, National Marine
Fisheries Service
Essential Fish Habitat Assessment
Federal Emergency Management Agency Flood Hazard Permit and "No-Rise" Certification
U.S. Department of Transportation,
Federal Aviation Administration
Notice of Proposed Construction or Alteration
U.S Department of Agriculture, Division
of Rural Utilities
National Environmental Policy Act (NEPA)
Compliance, including field data collection
U.S. Department of the Interior, U.S.
Fish and Wildlife Service
Endangered Species Act (ESA) Section 7
Consultation
U.S. National Oceanic and Atmospheric
Administration, National Marine
Fisheries Service
Endangered Species Act (ESA) Section 7
Consultation
Alaska Department of Natural
Resources, State Historic Preservation
Officer
National Historic Preservation Act (NHPA) Section
107 Consultation
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6.0 PLANNING-LEVEL COST ESTIMATE AND SCHEDULE
Permit/Approval Estimated Cost* Anticipated Schedule
Alaska Coastal Management Program
(ACMP) Consistency Review
$50,000 30 months
Air Quality Construction Permit,
including monitoring program
$650,000 32 months
National Pollutant Discharge Elimination
System (NPDES) Wastewater Discharge
Permit
$340,000 28 months
Clean Water Act Section 401
Certification(s)
$90,000 12 months
National Pollutant Discharge Elimination
System Stormwater Discharge Permit for
Operations
$25,000 6 months
Clean Water Act Section 404
Nationwide and/or Individual Permits
$450,000 16 months
Rivers and Harbors Act Section 10
Permit
$210,000 8 months
Fish Habitat Permit $200,000 6 months
Essential Fish Habitat Assessment $60,000 10 months
Endangered Species Act (ESA) Section 7
Consultation
$50,000 8 months
National Historic Preservation Act
(NHPA) Section 107 Consultation
$40,000 4 months
Flood Hazard Permit and "No-Rise"
Certification
$190,000 6 months
FAA Notice of Proposed Construction or
Alteration
$35,000 3 months
National Environmental Policy Act
(NEPA) Compliance, including field
data collection
$1,200,000 24 months
Total/Longest Duration $3,590,000 32 months
* Contractor Cost – Does not include project or engineering/design support costs.
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7.0 REFERENCES
ACOE 2003. U.S. Department of the Army, U.S. Army Corps of Engineers. Letter from Don R.
Rice, Lead Project Manager, received October 2, 2003.
ADEC 2003. Alaska Department of Environmental Conservation, Division of Air and Water
Quality. Letter from Tom Chapple, Director, dated October 10, 2003.
ADF&G 2003. An Atlas to the Catalog of Waters Important to the Spawning, Rearing or
Migration of Anadromous Fishes. Alaska Department of Fish and Game.
ADNR 2003a. Alaska Department of Natural Resources, Office of Habitat Management and
Permitting. E-mail from Ms. Kerry Howard dated September 11, 2003.
ADNR 2003b. Alaska Department of Natural Resources, Office of Project Management and
Permitting. E-mail from Ms. Sue Magee dated September 11, 2003.
ADNR 2003c. Alaska Department of Natural Resources, Office of Project Management and
Permitting. E-mail from Ms. Cynthia Zuelow-Osborne dated October 22, 2003.
AVEC 2003. Alaska Village Electric Cooperative, Inc. Letter from Ms. Meera Kohler,
President and CEO, dated September 30, 2003.
FAA 2003. U.S. Department of Transportation, Federal Aviation Administration. Letter from
Ms. Nora J. Braman, Contracting Officer, Acquisition and Real Estate, dated October 17,
2003.
HDR 2003. Bethel Airport Master Plan Environmental Assessment, Project No. 52659. HDR
Alaska, Inc. Prepared for State of Alaska Department of Transportation and Public
Facilities. February 2003.
NMFS 2003. U.S. Department of Commerce, National Oceanic and Atmospheric
Administration, National Marine Fisheries Service. Letter from Mr. James W. Balsiger,
Administrator, Alaska Region, dated September 26, 2003.
NRCS 2003. U.S. Department of Agriculture, Natural Resources Conservation Service. Letter
from Mr. William W. Wood, State Biologist, dated September 15, 2003.
Travis/Peterson 2003 Environmental Planning for the Proposed Bethel Power Plant and
Transmission Line. Travis/Peterson Environmental Consulting, Inc. Prepared for Frank
J. Bettine, P.E. July 2003.
USDA 2003. U.S. Department of Agriculture, Rural Development. E-mail from Mr. Bill Allen,
State Director, dated September 23, 2003.
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USFWS 2003. U.S. Department of Interior, U.S. Fish and Wildlife Service. Letter from Mr.
Gary Edwards, Acting Regional Director, received September 26, 2003.
ATTACHMENT 1
INITIAL CONSULTATION LETTER
BETHEL POWER PLANT PROJECT DESCRIPTION
PARTIES TO WHOM THE INITIAL CONSULTATION LETTER WAS SENT
Mr. Tom Chapple September 2, 2003
Director J.O.N. 185 WP 1, 2f
Alaska Department of Environmental Conservation Letter No. 185-003
Division of Air and Water Quality
555 Cordova Street
Anchorage, AK 99501
Subject: Bethel Power Plant
Dear Mr. Chapple,
Nuvista Light & Power, Inc. (Nuvista) is evaluating the feasibility of constructing and operating an
energy generation facility near Bethel, Alaska. Three alternatives for power production are being
considered: 1) a land-based coal-fired power plant; 2) a barge-mounted coal-fired power plant; and
3) diesel-fired combustion turbines. The facility would be developed for two purposes: 1) to supply
electrical power directly to the proposed Donlin Creek Gold Mine, which is currently under
exploration by Placer Dome, Inc. and NovaGold Resources, Inc. and 2) to sell wholesale power to
local utilities for resale to their customers, an endeavor that would ultimately serve approximately
40 communities and villages in the region and distribute hot water to meet local district heating
needs in Bethel. A brief description of the three power plant alternatives is attached.
We are aware that you may have already received information related to development of the Donlin
Creek Gold Mine and/or development of the transmission line from Bethel to the mine. Although
some parties have suggested that these three projects be evaluated together, there are a number of
important reasons for treating them independently. First, scheduling constraints require that
environmental review and permitting of the power plant and transmission line proceed ahead of
those for the mine so that these facilities can be constructed and operational by the time power is
needed for mine construction and operation. If not, the mine will be required to permit and operate
its own power generating station which would preclude the need for this alternative power sources.
Second, the power plant could be developed independent of development of the gold mine, and vice
versa; e.g., a power plant could be constructed to serve just the local community and other
communities in the region. Third, development of the Bethel Power Plant, as proposed, represents
only one alternative source of power for the gold mine; therefore, analysis of the power plant in the
context of the environmental assessment for the mine is not likely to be as thorough as would be
possible under an independent review. Finally, the entirely different functions of the facilities and
the considerable distance between the gold mine, the (majority of the) transmission line, and the
proposed power plant location suggest few synergies to be realized from coordinated review of
these facilities. Few similar impacts are expected from the three projects, and these would be
evaluated under the cumulative impacts assessment for each, as appropriate. For these reasons, we
are pursuing the proposal for the Bethel Power Plant independently from the proposals for the other
two projects. Your cooperation with this approach will be greatly appreciated
Bethel Power Plant Description
Nuvista Light & Power, Inc. (Nuvista) is evaluating the feasibility of constructing and operating
an energy generation facility near the community of Bethel, Alaska. Three alternatives for
power production are being considered: Alternative 1 – a land-based coal-fired power plant;
Alternative 2 – a barge-mounted, coal-fired power plant; and Alternative 3 – diesel-fired
turbines. Alternatives 1 and 2 would differ from one another primarily in the location and
configuration of their nearly identical facility components. The proposed power plant would be
developed for two purposes: 1) to supply electrical power directly to the proposed Donlin Creek
Gold Mine, which is currently under exploration by Placer Dome, Inc. and NovaGold Resources,
Inc., and 2) to sell wholesale power to local utilities for resale to their customers, an endeavor
that would ultimately serve approximately 40 communities and villages in the region, and
distribute hot water to meet local district heating needs in Bethel.
Bethel is located in southwest Alaska about 400 air miles west of Anchorage. It is situated on
the Kuskokwim River about 60 miles upstream of the river’s mouth at Kuskokwim Bay on the
Bering Sea. Bethel has a population of about 5,500 and is the commercial and transportation hub
of the Yukon Delta. Access to Bethel is by air or the Kuskokwim River.
Bethel lies within the Yukon Delta National Wildlife Refuge, a large area of low-lying tundra,
wetlands, intertidal mud and sand flats, and small lakes. The preferred location for Bethel
Power Plant Alternative 1 or Alternative 3 is a site approximately 1 mile south of Bethel in
Section 20 of Township 8 North, Range 7 West of the Seward Meridian at an elevation of
approximately 50 feet mean sea level. A photograph showing the proposed location of the
facility and the associated facility dock, access roads, and cooling pond is attached (Figure 1).
The alternative coal-fired configuration, Alternative 2, would have the coal plant mounted on
barges anchored at a nearby site (also in Section 20) in the Kuskokwim River. The proposed
location of the barge-mounted coal plant is shown in Figure 1. All proposed locations for the
Bethel Power Plant are situated on private property.
The power plant alternatives are described below. In addition to the facility site itself, each of
the alternatives involves developing a number of linear support features outside the facility
boundary, including a variety of pipelines and conveyor systems. While parts or all of the
facility sites per se may be expected to experience extensive disturbance during construction, the
proposed off-site pipeline and conveyor systems have been designed to minimize surface
disturbance and to avoid the need to develop permanent rights-of-way for maintenance.
Likewise, while the plant sites will experience continuous human activity throughout the
operations phase, the off-site facilities should be relatively free of project-related activity over
the long term.
All alternatives propose the use of a naturally occurring, approximately 78-acre pond for steam-
cycle cooling of the power generation facilities (see Figure 1). The pond is located generally
south of the proposed facility sites and would be connected to the power plant by heavily
insulated, 2- to 3-foot-diameter pipelines elevated 6 to 8 feet above the ground on driven piles or
small A-frame towers. Use of a cooling pond rather than forced-air cooling towers would reduce
construction costs and also substantially reduce annual operating costs. However, should further
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investigation indicate environmental constraints associated with using the existing pond as a
cooling pond, the cooling tower option would be revisited.
All alternatives also propose to capture waste heat from the power plant and distribute hot water
via a district heating system. The district heating system will include a central heat exchange
station located about midway between the power plant and Bethel and more than 6 miles of main
trunk lines leading from the power plant to the Bethel Municipal Airport and to the town of
Bethel and beyond. The main trunk lines will consist of 14- to 16-inch pipes hung from pilings
and elevated about 2 feet above the ground. As currently envisioned, the district heating system
main trunk lines will follow existing roads and streets. It is estimated that the captured waste
heat would displace nearly all of the fuel oil currently used by Bethel Utilities to supply Bethel’s
power needs, approximately 3.5 million gallons annually. The existing Bethel Utilities power
plant houses about 10 MW of diesel generation, which would likely remain operational to
provide additional standby/backup power for the proposed Bethel Power Plant.
Other features common to all alternatives include a dock on the Kuskokwim River and new
access roads from the plant site(s) to an existing road to Bethel. These roads will likely be two
lanes and of dirt/gravel construction.
Alternative 1 – Land-Based Coal-Fired Power Plant
The proposed land-based coal-fired power plant would consist of two atmospheric pulverized
coal-fired boilers each powering a 48-MW steam turbine, plus one 46-MW diesel-fired simple-
cycle combustion turbine, for a total installed capacity of 142 MW. The power plant would
generate approximately 670,000 MWh annually. The two coal-fired steam turbines would
provide primary power, with the combustion turbine providing standby/backup generation. It is
estimated that the combustion turbine will generate approximately 3 percent of the annual
generation, or about 20,000 MWh per year.
The land-based coal-fired plant would burn about 300,000 short tons of coal annually. The
project proposes to use a high-BTU, very low-sulfur coal from the Black Bear Mine in Canada as
the coal supply for the power plant. The coal would be shipped from Canada in self-off-loading
freighters and transferred to barges in the area of Goodnews Bay for movement up the
Kuskokwim River to the Bethel Power Plant facility’s barge unloading station and dock. Coal
deliveries would occur during the open water season from the end of May through the end of
September each year.
From the unloading station, the coal will be transported approximately one-half mile to the coal
storage pile at the power plant by means of a covered conveyor belt. The conveyor belt system
will be elevated 12 to 20 feet above the ground by steel A-frame towers mounted on small
concrete surface pads over pilings. The conveyor belt will parallel a new road between the dock
and the plant. To minimize blowing coal dust, the coal would be stored in a large covered
building such as the air-supported structure shown in Figure 2.
A 3-million-gallon fuel tank would be built at the site to store the fuel oil for the combustion
turbine. Under this alternative, where the combustion turbine serves only as a backup unit, the
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small amount of diesel fuel needed will likely be purchased from the existing tank farm in Bethel
and trucked to the power plant.
In addition to the coal-fired boilers and the combustion turbine and their associated pumps and
control room, other features of the land-based coal-fired alternative include additional coal
conveyors and various coal-handling equipment, an approximately 1-acre blowdown pond, an
electrical switchyard and associated 138-kV transmission lines to Bethel, and the initial section
of the district heating system. The proposed land-based coal-fired power plant facility would
occupy approximately 80 acres. Exhaust stack height is estimated at approximately 120 feet.
The land-based coal-fired power plant would generate approximately 33,000 tons of ash
annually. The ash will be processed as it is produced by adding 6 percent Portland cement and
16 percent water to form approximately 40,000 tons of gravel-like aggregate. The aggregate can
be put to beneficial use locally and regionally for road construction or in concrete as a substitute
for gravel.
Alternative 2 – Barge-Mounted Coal-Fired Power Plant
The barge-mounted coal-fired power plant alternative would occupy two barges off the
Kuskokwim River plus adjacent land for coal and diesel fuel storage and other facility features.
Each barge is 100 feet wide by 300 feet long and has a draft of about 8 feet; together the barges
would occupy less than 2 acres. The barges would be set in place by digging a channel into the
river bank of sufficient width, length, and depth to float the barges into position. Once the
barges are in place, an armored berm would be built between the barge channel and the river to
protect the barges from ice flows during spring breakup and to provide an earthen platform for
unloading supplies. The barges would be located in the floodplain of the river at a location
where there is little elevation difference in the bank and the river.
Each barge would accommodate a 48-MW atmospheric pulverized coal-fired power plant. One
of the two barges would also accommodate a 46-MW diesel-fired simple-cycle combustion
turbine as standby generation. The total installed capacity would be 142 MW. Under this
alternative, the power plant would generate approximately 670,000 MWh annually. As with the
land-based coal-fired power plant alternative, it is estimated that the combustion turbine will
generate approximately 3 percent of the annual generation, or about 20,000 MWh per year.
The barge-mounted coal-fired plant would burn about 300,000 short tons of coal annually.
Details of the coal supply, coal delivery, and coal storage systems for the barge-mounted coal-
fired power plant are expected to be similar to those described for the land-based coal-fired
power plant, including covered storage for the coal pile. Likewise, diesel fuel for the backup
combustion turbine will be obtained locally. Processing and disposition of ash wastes would be
the same as for the land-based coal-fired power plant alternative.
The 300,000 tons of coal storage and a single 3-million-gallon fuel storage tank would be located
on the adjacent river bank directly above the barges, and these would be connected to the
generating facilities by a short conveyor and pipeline, respectively. Other auxiliary features of
the barge-mounted coal-fired power plant alternative, including the blowdown pond and the
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electrical switchyard, would also be located in this area, which would occupy approximately 80
acres. Exhaust stack height for the barge-mounted plant is estimated at approximately 120 feet,
which will place the top of the stack 60 to 70 feet above the top of the adjacent river bank.
There are significant cost savings to the project for the barge-mounted coal plant over the land-
based coal plant.
Alternative 3 – Combustion Turbine Plant
The combustion turbine alternative would consist of a 151-MW combined-cycle plant consisting
of three simple-cycle, 42-MW combustion turbines, plus one or two heat recovery steam turbine
generators with a total capacity of 25 MW. Under this alternative, the power plant would
generate approximately 670,000 MWh annually.
The power plant would burn #2 diesel fuel, of which it would consume about 35 million gallons
annually. The large amount of diesel fuel needed to fire the combustion turbine plant would be
delivered by barge to the facility dock and pumped to the facility diesel fuel storage tanks via an
aboveground pipeline. The fuel pipeline will be 8 to 12 inches in diameter and will be elevated 2
feet above the ground. The fuel pipeline will parallel the new road between the dock and the
plant site mentioned above. Fuel storage requirements would be 25 million gallons annually, and
the fuel would be stored in eight, 3.1 million gallon tanks.
Auxiliary features of the combustion turbine alternative include an electrical switchyard, the
associated 138-kV transmission lines to Bethel, and the initial section of the district heating
system. The entire combustion turbine facility would occupy approximately 40 acres. Exhaust
stack height is estimated at approximately 75 feet.
No ash would be generated by the combustion turbine power plant alternative.
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Bethel Power Plant August 2003 Project Description Steigers Corporation 6Bethel Power Plant August 2003 Project Description Steigers Corporation 6
Bethel Power Plant Information Distribution List AGENCY/ENTITY DIRECTOR-LEVEL CONTACTTELEPHONE/FAXState of Alaska Alaska Department of Environmental Conservation Tom Chapple, Director Division of Air and Water Quality Alaska Department of Environmental Conservation 555 Cordova Street Anchorage, AK 99501 (907) 269-7686 (907) 269-3098 Alaska Department of Environmental Conservation Kristin Ryan, Director Division of Environmental Health Alaska Department of Environmental Conservation 555 Cordova Street Anchorage, AK 99501 (907) 269-7645 (907) 269-7654 Alaska Department of Environmental Conservation William Ashton Environmental Engineer Alaska Department of Environmental Conservation 555 Cordova Street Anchorage, AK 99501 (907) 269-6282 (907) 269-7508 Alaska Department of Natural Resources Kerry Howard, Executive Director Office of Habitat Management and Permitting 400 Willoughby Avenue, 4th Floor Juneau, AK 99801-1796 (907) 465-4105 (907) 465-4759 Alaska Department of Natural Resources Susan Magee, Project Review Coordinator Office of Project Management and Permitting 550 West Seventh Avenue, Suite 1660 Anchorage, AK 99501 (907) 269-7472 (907) 269-3981 Regulatory Commission of Alaska Mary Grace Salazar, Administrative Manager Regulatory Commission of Alaska 701 W. Eighth Avenue, Suite 300 Anchorage, AK 99501-1963 (907) 276-6222 (907) 276-0160 Bethel Power Plant August 2003 Distribution List Steigers Corporation 1
Bethel Power Plant August 2003 Distribution List Steigers Corporation 2AGENCY/ENTITY DIRECTOR-LEVEL CONTACT TELEPHONE/FAX Federal U.S. Army Corps of Engineers Don Rice, Team Leader North Section U.S. Army Corps of Engineers Regulatory Branch P. O. Box 6898 Elmendorf AFB, AK 99506-6898 (907) 753-2712 (907) 753-5567 U.S. Bureau of Indian Affairs Niles Cesar, Regional Director U.S. Bureau of Indian Affairs Alaska Regional Office P.O. Box 25520 709 West 9th Street Juneau, AK 99802 (800) 645-8397 (907) 856-7252 U.S. Fish & Wildlife Service Rowan W. Gould, Regional Director U.S. Fish & Wildlife Service 1011 East Tudor Road, Mail Stop 381 Anchorage, AK 99503-6199 (907) 786-3542 (907) 786-3306 U.S. Fish & Wildlife Service Michael B. Rearden, Refuge Manager Yukon Delta National Wildlife Refuge P.O. Box 346 Bethel, AK 99559-0346 (907) 543-3151 (907) 543-4413 National Marine Fisheries Service Ron Burke, Deputy Regional Administrator National Marine Fisheries Service, Alaska Region P.O. Box 21668 Juneau, AK 99802-1668 (907) 586-7221 (907) 586-7249 Rural Utilities Service Bill Allen, State Director Alaska Rural Development 800 W. Evergreen, Suite 201 Palmer, AK 99645 (907) 761-7705 (907)761-7784 National Resource Conservation Service Bill Wood, State Biologist National Resource Conservation Service 800 W. Evergreen, Suite 100 Palmer, AK 99645 (907) 761-7761
AGENCY/ENTITY DIRECTOR-LEVEL CONTACT TELEPHONE/FAX Federal Aviation Administration Jan Girard, Manager of Acquisitions and Real Estate Federal Aviation Administration 222 W. Seventh Avenue Anchorage, AK 99513 (907) 271-5427 Native Communities Association of Village Council Presidents Mr. Myrom Maneng, President Association of Village Council Presidents P.O. Box 219 Bethel, AK 99559 (907) 543-7301 (907) 543-3596 Akiachak Native Community Mr. George Peter, Tribal Administrator Akiachak Native Community P.O. Box 90 Akiachak, AK 99551 (907) 825-4626 (907) 825-4029 Akiak IRA Council Mr. Ivan M. Ivan, Executive Director Akiak IRA Council P.O. Box 52165 Aniak, AK 99552 (907) 765-7112 (907) 765-7512 Aniak Traditional Council Ms. Lovey Duffy, Village Administrator Aniak Traditional Council P.O. Box 349 Aniak, AK 99557 (907) 675-4349 (907) 675-4513 Bethel Native Corporation Mr. Marc Stemp, President Bethel Native Corporation P.O. Box 719 Bethel, AK 99559 (907) 543-2124 (907) 543-2897 Orutsararmuit Native Council Ms. Flora Olrun, Executive Director Orutsararmuit Native Council P.O. Box 927 Bethel, AK 99559 (907) 543-2608 (907) 543-2639 Chuathbaluk Village Council Ms. Helen Pitka, Village Administrator Chuathbaluk Village Council (907) 467-4313 (907) 467-4113 Bethel Power Plant August 2003 Distribution List Steigers Corporation 3
AGENCY/ENTITY DIRECTOR-LEVEL CONTACT TELEPHONE/FAX P.O. Box CHU Chuathbaluk, AK 99557 Crooked Creek Village Council Ms. Mini John, Village Adminiatrator Crooked Creek Village Council P.O. Box 69 Crooked Creek, AK 99575 (907) 432-2200 (907) 432-2201 Upper Kalshag Village Council Ms. Bernice Hetherington, Village Administrator Upper Kalshag Village Council P.O. Box 50 Kalshag, AK 99607 (907) 471-2207 (907) 471-2399 Kuskokwim Native Association Mr. Leo Morgan, Executive Director Kuskokwim Native Association P.O. Box 127 Aniak, AK 99557 (907) 675-4384 (907) 675-4387 Village of Lower Kalskag Ms. Rose Nook, Village Administrator Village of Lower Kalskag P.O. Box 27 Lower Kalskag, AK 99626 (907) 471-2379 (907) 471-2378 Kwethluk IRA Mr. Wassillie George, Deputy Director Kwethluk IRA P.O. Box 130 Kwethluk, AK 99621 (907) 757-6714 (907) 757-6328 Organized Village of Kwethluk Mr. Chariton Epchook, President Organized Village of Kwethluk P.O. Box 130 Kwethluk, AK 99621 (907) 757-6043 (907) 757-6321 Tuntutuliak Traditional Council EPA Mr. Noah Allexie Sr., Council Member Tuntutuliak Traditional Council EPA P.O. Box 95 Tuluksak, AK 99679-0095 (907) 695-6420 (907) 695-6932 Bethel Power Plant August 2003 Distribution List Steigers Corporation 4
AGENCY/ENTITY DIRECTOR-LEVEL CONTACT TELEPHONE/FAX Tuluksak Native Community Mr. Joseph Sallaffie, Tribal Administrator Tuluksak Native Community P.O. Box 97 Tuluksak, AK 99679-0095 (907) 695-6420 (907) 695-6932 Lower Kuskokwim Economic Development Council Mr. Carl Berger, Executive Director Lower Kuskokwim Economic Development Council P.O. Box 219 Bethel, AK 99559 (907) 543-5967 (907) 543-3130 Cities City of Akiak Mr. Peter Gillia, City Administrator City of Akiak P.O. Box 52167 Akaik, AK 99552 (907) 765-7412 (907) 765-7414 City of Bethel Mr. Robert E. Herron, City Manager City of Bethel P.O. Box 1388 Bethel, AK 99559 (907) 543-1372 (907) 543-4171 City of Bethel Mr. John Malone, Planning Department City of Bethel P.O. Box 1388 Bethel, AK 99559 (907) 543-1372 (907) 543-4171 City of Upper Kalskag Mr. Paul Kermeroff City of Upper Kalskag P.O. Box 80 Upper Kalskag, AK 99607 (907) 471-2220 (907) 471-2237 City of Aniak Mr. Travis Pate, City Manager City of Aniak P.O. Box 189 Aniak, AK 99557 (907) 675-4481 (907) 675-4486 Bethel Power Plant August 2003 Distribution List Steigers Corporation 5
AGENCY/ENTITY DIRECTOR-LEVEL CONTACT TELEPHONE/FAX City of Lower Kalskag Ms. Anastasia Levi, Mayor City of Lower Kalskag P.O. Box 69 Lower Kalskag, AK 99626 (907) 471-2440 (907) 471-2460 City of Kwethluk Mr. Boris Epchook, Mayor City of Kwethluk P.O. Box 50 Kwethluk, AK 99621 (907) 757-6022 (907) 757-6497 Corporations AVEC, Inc. Ms. Meera Kohler, CEO AVEC, Inc. 4831 Eagle Street Anchorage, AK 99503 (800) 478-1818 (800) 478-2389 Akiachak, Limited Mr. Willie Kasayulie, President Akiachak, Limited P.O. Box 51010 Akaichak, AK 99551 (907) 825-4328 (907) 825-4115 Aniak Light & Power Company Mr. Artie Demantle, Owner Aniak Light & Power Company P.O. Box 129 Aniak, AK 99557 (907) 675-4334 Bethel Utilities Mr. Hal Borrego Bethel Utilities 3380 C Street, Suite 210 Anchorage, AK 99503 (907) 562-2500 (907) 562-2502 Kokarmiut Corporation Mr. Sam Jackson, Chairman Kokarmiut Corporation P.O. Box 147 Akiak, AK 99552 (907) 765-7228 (907) 765-7619 Bethel Power Plant August 2003 Distribution List Steigers Corporation 6
Bethel Power Plant August 2003 Distribution List Steigers Corporation 7AGENCY/ENTITY DIRECTOR-LEVEL CONTACT TELEPHONE/FAX Kuskokwim Corporation Mr. Robert Ballow, President Kuskokwim Corporation 4300 B Street Anchorage, AK 99503 (907) 243-2944 Kwethluk Incorporated Mr. George Guy, Business Manager Kwethluk Incorporated P.O. Box 110 Kwethluk, AK 99621 (907) 757-6613 (907) 757-6212 Calista Corporation Mr. Jeff Foley, Senior Exploration Geologist Calista Corporation 301 Calista Court, Suite A Anchorage, AK 99518-3028 (907) 279-5516 (907) 272-5060
APPENDIX G
1. Coal-Fired Plant
2. Combine-Cycle Combustion Turbine Plant – Bethel
3. Combine-Cycle Combustion Turbine Plant – Crooked Creek
4. Transmission Lines from Railbelt
COAL PLANT
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeFording Coal97 MW Land-Based Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 00000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 00000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $210,975,000 $210,975,000 $210,975,000 $210,975,000 $210,975,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $227,995,000 $227,995,000 $227,995,000 $227,995,000 $227,995,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $392,282,800 $392,282,800 $392,282,800 $392,282,800 $392,282,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $19,614,140 $19,614,140 $19,614,140 $19,614,140 $19,614,140 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $14,614,140 $14,614,140 $14,614,140 $14,614,140 $14,614,140 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $12,114,140 $12,114,140 $12,114,140 $12,114,140 $12,114,140 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $9,614,140 $9,614,140 $9,614,140 $9,614,140 $9,614,140 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $7,114,140 $7,114,140 $7,114,140 $7,114,140 $7,114,140 $0 $0 $0 $0 $0 $0Total Capital Cost5% $411,896,940 $411,896,940 $411,896,940 $411,896,940 $411,896,940 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $306,896,940 $306,896,940 $306,896,940 $306,896,940 $306,896,940 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $254,396,940 $254,396,940 $254,396,940 $254,396,940 $254,396,940 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $201,896,940 $201,896,940 $201,896,940 $201,896,940 $201,896,940 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $149,396,940 $149,396,940 $149,396,940 $149,396,940 $149,396,940 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $33,051,676 $33,051,676 $33,051,676 $33,051,676 $33,051,676 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $24,626,204 $24,626,204 $24,626,204 $24,626,204 $24,626,204 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $20,413,469 $20,413,469 $20,413,469 $20,413,469 $20,413,469 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $16,200,733 $16,200,733 $16,200,733 $16,200,733 $16,200,733 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $11,987,997 $11,987,997 $11,987,997 $11,987,997 $11,987,997 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 305,157 309,320 313,482 316,554 319,627 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $16,783,661 $17,012,573 $17,241,484 $17,410,481 $17,579,478 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan$500,969$507,801 $514,634$519,678$524,723$136,099$136,099$136,099$136,099$136,099$136,099 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $20,425,345 $20,682,553 $20,939,761 $21,129,648 $21,319,535 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,866,985 $7,869,372 $7,871,759 $7,873,521 $7,875,283 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.056 $0.055 $0.054 $0.054 $0.053 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.042 $0.041 $0.040 $0.040 $0.039 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.035 $0.034 $0.033 $0.033 $0.033 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.027 $0.027 $0.027 $0.026 $0.026 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.020 $0.020 $0.020 $0.019 $0.019 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.035 $0.034 $0.034 $0.034 $0.034 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.013 $0.013 $0.013 $0.013 $0.013 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.048 $0.048 $0.047 $0.047 $0.047 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.104 $0.103 $0.101 $0.101 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.090 $0.089 $0.088 $0.087 $0.086 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.082 $0.082 $0.081 $0.080 $0.080 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.075 $0.075 $0.074 $0.073 $0.073 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.068 $0.068 $0.067 $0.066 $0.066 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.109 0.108 0.106 0.106 0.105 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.095 0.094 0.093 0.092 0.091 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.087 0.087 0.086 0.085 0.085 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.080 0.080 0.079 0.078 0.078 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.073 0.073 0.072 0.071 0.071 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $64,296,215 $64,603,542 $64,910,869 $65,137,757 $65,364,644 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $55,870,743 $56,178,070 $56,485,397 $56,712,285 $56,939,173 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $51,658,007 $51,965,334 $52,272,661 $52,499,549 $52,726,437 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $47,445,271 $47,752,598 $48,059,925 $48,286,813 $48,513,701 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $43,232,536 $43,539,863 $43,847,190 $44,074,077 $44,300,965 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 64,296,215 386,084,615 709,409,651 1,034,190,883 1,360,106,553 1,631,876,628 1,683,434,122 1,734,991,615 1,786,549,108 1,838,106,601 1,889,664,095$100 M Grants, Bal. 5% 55,870,743 335,531,785 616,729,463 899,383,336 1,183,171,648 1,421,239,837 1,472,797,330 1,524,354,824 1,575,912,317 1,627,469,810 1,679,027,303$150 M Grants, Bal. 5% 51,658,007 310,255,370 570,389,369 831,979,563 1,094,704,196 1,315,921,441 1,367,478,935 1,419,036,428 1,470,593,921 1,522,151,414 1,573,708,908$200 M Grants, Bal. 5% 47,445,271 284,978,955 524,049,274 764,575,790 1,006,236,743 1,210,603,046 1,262,160,539 1,313,718,032 1,365,275,525 1,416,833,019 1,468,390,512$250 M Grants, Bal. 5% 43,232,536 259,702,540 477,709,180 697,172,016 917,769,291 1,105,284,650 1,156,842,143 1,208,399,636 1,259,957,130 1,311,514,623 1,363,072,116Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,144,705,549$100 M Grants, Bal. 5% $994,701,631$150 M Grants, Bal. 5% $919,699,671$200 M Grants, Bal. 5% $844,697,712$250 M Grants, Bal. 5% $769,695,75343/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeFording Coal97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 00000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 00000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $369,487,800 $369,487,800 $369,487,800 $369,487,800 $369,487,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $18,474,390 $18,474,390 $18,474,390 $18,474,390 $18,474,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $13,474,390 $13,474,390 $13,474,390 $13,474,390 $13,474,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,974,390 $10,974,390 $10,974,390 $10,974,390 $10,974,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,474,390 $8,474,390 $8,474,390 $8,474,390 $8,474,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,974,390 $5,974,390 $5,974,390 $5,974,390 $5,974,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $387,962,190 $387,962,190 $387,962,190 $387,962,190 $387,962,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $282,962,190 $282,962,190 $282,962,190 $282,962,190 $282,962,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $230,462,190 $230,462,190 $230,462,190 $230,462,190 $230,462,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $177,962,190 $177,962,190 $177,962,190 $177,962,190 $177,962,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $125,462,190 $125,462,190 $125,462,190 $125,462,190 $125,462,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $31,131,090 $31,131,090 $31,131,090 $31,131,090 $31,131,090 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $22,705,618 $22,705,618 $22,705,618 $22,705,618 $22,705,618 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,492,882 $18,492,882 $18,492,882 $18,492,882 $18,492,882 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,280,147 $14,280,147 $14,280,147 $14,280,147 $14,280,147 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $10,067,411 $10,067,411 $10,067,411 $10,067,411 $10,067,411 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 305,157 309,320 313,482 316,554 319,627 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $16,783,661 $17,012,573 $17,241,484 $17,410,481 $17,579,478 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan$500,969$507,801 $514,634$519,678$524,723$136,099$136,099$136,099$136,099$136,099$136,099 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $20,425,345 $20,682,553 $20,939,761 $21,129,648 $21,319,535 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,866,985 $7,869,372 $7,871,759 $7,873,521 $7,875,283 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.053 $0.052 $0.051 $0.050 $0.050 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.038 $0.038 $0.037 $0.037 $0.036 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.031 $0.031 $0.030 $0.030 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.024 $0.024 $0.023 $0.023 $0.023 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.017 $0.017 $0.017 $0.016 $0.016 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.035 $0.034 $0.034 $0.034 $0.034 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.013 $0.013 $0.013 $0.013 $0.013 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.048 $0.048 $0.047 $0.047 $0.047 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.101 $0.099 $0.098 $0.098 $0.097 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.086 $0.085 $0.085 $0.084 $0.083 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.079 $0.078 $0.078 $0.077 $0.076 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.072 $0.071 $0.071 $0.070 $0.070 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.065 $0.064 $0.064 $0.063 $0.063 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.106 0.104 0.103 0.103 0.102 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.091 0.090 0.090 0.089 0.088 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.084 0.083 0.083 0.082 0.081 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.077 0.076 0.076 0.075 0.075 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.070 0.069 0.069 0.068 0.068 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $62,375,628 $62,682,955 $62,990,283 $63,217,170 $63,444,058 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $53,950,157 $54,257,484 $54,564,811 $54,791,699 $55,018,586 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $49,737,421 $50,044,748 $50,352,075 $50,578,963 $50,805,850 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $45,524,685 $45,832,012 $46,139,339 $46,366,227 $46,593,115 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $41,311,949 $41,619,276 $41,926,603 $42,153,491 $42,380,379 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 62,375,628 374,561,098 688,283,202 1,003,461,502 1,319,774,241 1,583,861,972 1,635,419,465 1,686,976,958 1,738,534,452 1,790,091,945 1,841,649,438$100 M Grants, Bal. 5% 53,950,157 324,008,268 595,603,014 868,653,956 1,142,839,337 1,373,225,180 1,424,782,674 1,476,340,167 1,527,897,660 1,579,455,153 1,631,012,647$150 M Grants, Bal. 5% 49,737,421 298,731,853 549,262,920 801,250,183 1,054,371,884 1,267,906,785 1,319,464,278 1,371,021,771 1,422,579,264 1,474,136,758 1,525,694,251$200 M Grants, Bal. 5% 45,524,685 273,455,438 502,922,826 733,846,409 965,904,432 1,162,588,389 1,214,145,882 1,265,703,376 1,317,260,869 1,368,818,362 1,420,375,855$250 M Grants, Bal. 5% 41,311,949 248,179,023 456,582,731 666,442,636 877,436,979 1,057,269,993 1,108,827,487 1,160,384,980 1,211,942,473 1,263,499,966 1,315,057,460Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,110,512,156$100 M Grants, Bal. 5% $960,508,237$150 M Grants, Bal. 5% $885,506,278$200 M Grants, Bal. 5% $810,504,319$250 M Grants, Bal. 5% $735,502,35943/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeFording Coal80 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000000000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000000000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000Combustion Turbine Bethel 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000CCK00000000000 Mine00000000000Bethel Utilities Plant 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000Total Capacity in KWs 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant $250 $250 $250 $250 $250 $250 $250 $250 $250 $250 $250138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $175,200,000 $175,200,000 $175,200,000 $175,200,000 $175,200,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $9,250,000 $9,250,000 $9,250,000 $9,250,000 $9,250,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities Plant $2,500,000 $2,500,000 $2,500,000 $2,500,000 $2,500,000Total $186,950,000 $186,950,000 $186,950,000 $186,950,000 $186,950,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $351,237,800 $351,237,800 $351,237,800 $351,237,800 $351,237,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $17,561,890 $17,561,890 $17,561,890 $17,561,890 $17,561,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $12,561,890 $12,561,890 $12,561,890 $12,561,890 $12,561,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,061,890 $10,061,890 $10,061,890 $10,061,890 $10,061,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $7,561,890 $7,561,890 $7,561,890 $7,561,890 $7,561,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,061,890 $5,061,890 $5,061,890 $5,061,890 $5,061,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $368,799,690 $368,799,690 $368,799,690 $368,799,690 $368,799,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $263,799,690 $263,799,690 $263,799,690 $263,799,690 $263,799,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $211,299,690 $211,299,690 $211,299,690 $211,299,690 $211,299,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $158,799,690 $158,799,690 $158,799,690 $158,799,690 $158,799,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $106,299,690 $106,299,690 $106,299,690 $106,299,690 $106,299,690 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $29,593,441 $29,593,441 $29,593,441 $29,593,441 $29,593,441 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $21,167,970 $21,167,970 $21,167,970 $21,167,970 $21,167,970 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $16,955,234 $16,955,234 $16,955,234 $16,955,234 $16,955,234 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $12,742,498 $12,742,498 $12,742,498 $12,742,498 $12,742,498 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $8,529,762 $8,529,762 $8,529,762 $8,529,762 $8,529,762 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 305,157 309,320 313,482 316,554 319,627 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $16,783,661 $17,012,573 $17,241,484 $17,410,481 $17,579,478 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan$500,969$507,801 $514,634$519,678$524,723$136,099$136,099$136,099$136,099$136,099$136,099 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $20,425,345 $20,682,553 $20,939,761 $21,129,648 $21,319,535 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,866,985 $7,869,372 $7,871,759 $7,873,521 $7,875,283 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.050 $0.049 $0.049 $0.048 $0.047 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.036 $0.035 $0.035 $0.034 $0.034 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.029 $0.028 $0.028 $0.027 $0.027 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.022 $0.021 $0.021 $0.021 $0.020 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.014 $0.014 $0.014 $0.014 $0.014 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.035 $0.034 $0.034 $0.034 $0.034 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.013 $0.013 $0.013 $0.013 $0.013 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.048 $0.048 $0.047 $0.047 $0.047 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.098 $0.097 $0.096 $0.095 $0.094 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.084 $0.083 $0.082 $0.081 $0.081 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.077 $0.076 $0.075 $0.075 $0.074 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.069 $0.069 $0.068 $0.068 $0.067 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.062 $0.062 $0.061 $0.061 $0.060 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.103 0.102 0.101 0.100 0.099 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.089 0.088 0.087 0.086 0.086 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.082 0.081 0.080 0.080 0.079 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.074 0.074 0.073 0.073 0.072 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.067 0.067 0.066 0.066 0.065 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $60,837,980 $61,145,307 $61,452,634 $61,679,522 $61,906,409 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $52,412,508 $52,719,835 $53,027,162 $53,254,050 $53,480,938 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $48,199,772 $48,507,099 $48,814,426 $49,041,314 $49,268,202 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $43,987,037 $44,294,364 $44,601,691 $44,828,578 $45,055,466 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $39,774,301 $40,081,628 $40,388,955 $40,615,843 $40,842,730 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 60,837,980 365,335,206 671,369,068 978,859,125 1,287,483,621 1,545,420,757 1,596,978,251 1,648,535,744 1,700,093,237 1,751,650,730 1,803,208,224$100 M Grants, Bal. 5% 52,412,508 314,782,376 578,688,879 844,051,579 1,110,548,717 1,334,783,966 1,386,341,459 1,437,898,953 1,489,456,446 1,541,013,939 1,592,571,432$150 M Grants, Bal. 5% 48,199,772 289,505,961 532,348,785 776,647,805 1,022,081,264 1,229,465,570 1,281,023,064 1,332,580,557 1,384,138,050 1,435,695,543 1,487,253,036$200 M Grants, Bal. 5% 43,987,037 264,229,546 486,008,691 709,244,032 933,613,812 1,124,147,175 1,175,704,668 1,227,262,161 1,278,819,654 1,330,377,148 1,381,934,641$250 M Grants, Bal. 5% 39,774,301 238,953,131 439,668,597 641,840,259 845,146,359 1,018,828,779 1,070,386,272 1,121,943,765 1,173,501,259 1,225,058,752 1,276,616,245Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,083,136,441$100 M Grants, Bal. 5% $933,132,522$150 M Grants, Bal. 5% $858,130,563$200 M Grants, Bal. 5% $783,128,603$250 M Grants, Bal. 5% $708,126,64443/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeFording Coal97 MW Land-Based Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 80,000 80,000 80,000 80,000 80,000 000000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 6,700 6,700 6,700 6,700 6,700 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 106,061 107,825 109,590 110,729 111,869 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 613,200,000 613,200,000 613,200,000 613,200,000 613,200,000 000000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 678,041,628 687,588,100 697,134,571 704,182,362 711,230,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 58,692,000 58,692,000 58,692,000 58,692,000 58,692,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 802,433,628 811,980,100 821,526,571 828,574,362 835,622,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine 0 0 0 0 0 000000Bethel Utilities Plant 0 0 0 0 0 000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 782,372,788 791,680,597 800,988,407 807,860,003 814,731,600 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 20,060,841 20,299,502 20,538,164 20,714,359 20,890,554 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 0 0 0 0 0 000000Purchased Power 0 0 0 0 0 0000002. Capital Cost(1)Plant CostsCoal Plant $/kW $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $210,975,000 $210,975,000 $210,975,000 $210,975,000 $210,975,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $227,995,000 $227,995,000 $227,995,000 $227,995,000 $227,995,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine 0 0 0 0 0 000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $392,282,800 $392,282,800 $392,282,800 $392,282,800 $392,282,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $19,614,140 $19,614,140 $19,614,140 $19,614,140 $19,614,140 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $14,614,140 $14,614,140 $14,614,140 $14,614,140 $14,614,140 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $12,114,140 $12,114,140 $12,114,140 $12,114,140 $12,114,140 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $9,614,140 $9,614,140 $9,614,140 $9,614,140 $9,614,140 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $7,114,140 $7,114,140 $7,114,140 $7,114,140 $7,114,140 $0 $0 $0 $0 $0 $0Total Capital Cost5% $411,896,940 $411,896,940 $411,896,940 $411,896,940 $411,896,940 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $306,896,940 $306,896,940 $306,896,940 $306,896,940 $306,896,940 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $254,396,940 $254,396,940 $254,396,940 $254,396,940 $254,396,940 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $201,896,940 $201,896,940 $201,896,940 $201,896,940 $201,896,940 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $149,396,940 $149,396,940 $149,396,940 $149,396,940 $149,396,940 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $33,051,676 $33,051,676 $33,051,676 $33,051,676 $33,051,676 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $24,626,204 $24,626,204 $24,626,204 $24,626,204 $24,626,204 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $20,413,469 $20,413,469 $20,413,469 $20,413,469 $20,413,469 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $16,200,733 $16,200,733 $16,200,733 $16,200,733 $16,200,733 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $11,987,997 $11,987,997 $11,987,997 $11,987,997 $11,987,997 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 349,841 354,004 358,166 361,238 364,311 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,503,461 1,521,347 1,539,234 1,552,439 1,565,644 232,911 232,911 232,911 232,911 232,911 232,911CCKMine 0 0 0 0 0 000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $19,241,282 $19,470,194 $19,699,105 $19,868,102 $20,037,098 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,804,153 $1,825,617 $1,847,081 $1,862,927 $1,878,772 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $574,325 $581,158 $587,991 $593,035 $598,079 $136,099 $136,099 $136,099 $136,099 $136,099 $136,099 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $23,186,760 $23,443,968 $23,701,176 $23,891,063 $24,080,950 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $200,608 $202,995 $205,382 $207,144 $208,906 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,892,608 $7,894,995 $7,897,382 $7,899,144 $7,900,906 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.049 $0.048 $0.047 $0.047 $0.046 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.036 $0.036 $0.035 $0.035 $0.035 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.030 $0.030 $0.029 $0.029 $0.029 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.024 $0.024 $0.023 $0.023 $0.023 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.018 $0.017 $0.017 $0.017 $0.017 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.034 $0.034 $0.034 $0.034 $0.034 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.012 $0.011 $0.011 $0.011 $0.011 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.046 $0.046 $0.045 $0.045 $0.045 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.095 $0.094 $0.093 $0.092 $0.091 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.082 $0.081 $0.081 $0.080 $0.080 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.076 $0.075 $0.075 $0.074 $0.074 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.070 $0.069 $0.069 $0.068 $0.068 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.064 $0.063 $0.063 $0.062 $0.062 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.100 0.099 0.098 0.097 0.096 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.087 0.086 0.086 0.085 0.085 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.081 0.080 0.080 0.079 0.079 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.075 0.074 0.074 0.073 0.073 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.069 0.068 0.068 0.067 0.067 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $67,521,253 $67,828,580 $68,135,907 $68,362,795 $68,589,682 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $59,095,781 $59,403,108 $59,710,435 $59,937,323 $60,164,211 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $54,883,045 $55,190,373 $55,497,700 $55,724,587 $55,951,475 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $50,670,310 $50,977,637 $51,284,964 $51,511,851 $51,738,739 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $46,457,574 $46,764,901 $47,072,228 $47,299,116 $47,526,003 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 67,521,253 405,434,845 744,885,072 1,085,791,495 1,427,832,356 1,712,502,585 1,764,060,078 1,815,617,571 1,867,175,065 1,918,732,558 1,970,290,051$100 M Grants, Bal. 5% 59,095,781 354,882,015 652,204,884 950,983,948 1,250,897,452 1,501,865,794 1,553,423,287 1,604,980,780 1,656,538,273 1,708,095,767 1,759,653,260$150 M Grants, Bal. 5% 54,883,045 329,605,600 605,864,789 883,580,175 1,162,429,999 1,396,547,398 1,448,104,891 1,499,662,384 1,551,219,878 1,602,777,371 1,654,334,864$200 M Grants, Bal. 5% 50,670,310 304,329,185 559,524,695 816,176,402 1,073,962,547 1,291,229,002 1,342,786,496 1,394,343,989 1,445,901,482 1,497,458,975 1,549,016,468$250 M Grants, Bal. 5% 46,457,574 279,052,770 513,184,601 748,772,629 985,495,095 1,185,910,607 1,237,468,100 1,289,025,593 1,340,583,086 1,392,140,579 1,443,698,073Annual Net Income 3,390,208 3,437,940 3,485,673 3,520,912 3,556,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 3,390,208 20,388,981 41,064,357 62,013,633 83,174,342 101,445,247 104,386,152 107,327,056 110,267,961 113,208,866 116,149,77043/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeFording Coal97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 80,000 80,000 80,000 80,000 80,000 000000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 6,700 6,700 6,700 6,700 6,700 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 106,061 107,825 109,590 110,729 111,869 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 613,200,000 613,200,000 613,200,000 613,200,000 613,200,000 000000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 678,041,628 687,588,100 697,134,571 704,182,362 711,230,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 58,692,000 58,692,000 58,692,000 58,692,000 58,692,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 802,433,628 811,980,100 821,526,571 828,574,362 835,622,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 782,372,788 791,680,597 800,988,407 807,860,003 814,731,600 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 20,060,841 20,299,502 20,538,164 20,714,359 20,890,554 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $369,487,800 $369,487,800 $369,487,800 $369,487,800 $369,487,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $18,474,390 $18,474,390 $18,474,390 $18,474,390 $18,474,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $13,474,390 $13,474,390 $13,474,390 $13,474,390 $13,474,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,974,390 $10,974,390 $10,974,390 $10,974,390 $10,974,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,474,390 $8,474,390 $8,474,390 $8,474,390 $8,474,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,974,390 $5,974,390 $5,974,390 $5,974,390 $5,974,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $387,962,190 $387,962,190 $387,962,190 $387,962,190 $387,962,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $282,962,190 $282,962,190 $282,962,190 $282,962,190 $282,962,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $230,462,190 $230,462,190 $230,462,190 $230,462,190 $230,462,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $177,962,190 $177,962,190 $177,962,190 $177,962,190 $177,962,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $125,462,190 $125,462,190 $125,462,190 $125,462,190 $125,462,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $31,131,090 $31,131,090 $31,131,090 $31,131,090 $31,131,090 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $22,705,618 $22,705,618 $22,705,618 $22,705,618 $22,705,618 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,492,882 $18,492,882 $18,492,882 $18,492,882 $18,492,882 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,280,147 $14,280,147 $14,280,147 $14,280,147 $14,280,147 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $10,067,411 $10,067,411 $10,067,411 $10,067,411 $10,067,411 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 349,841 354,004 358,166 361,238 364,311 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,503,461 1,521,347 1,539,234 1,552,439 1,565,644 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $19,241,282 $19,470,194 $19,699,105 $19,868,102 $20,037,098 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,804,153 $1,825,617 $1,847,081 $1,862,927 $1,878,772 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $574,325 $581,158 $587,991 $593,035 $598,079 $136,099 $136,099 $136,099 $136,099 $136,099 $136,099 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $23,186,760 $23,443,968 $23,701,176 $23,891,063 $24,080,950 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $200,608 $202,995 $205,382 $207,144 $208,906 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,892,608 $7,894,995 $7,897,382 $7,899,144 $7,900,906 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.046 $0.045 $0.045 $0.044 $0.044 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.033 $0.033 $0.033 $0.032 $0.032 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.027 $0.027 $0.027 $0.026 $0.026 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.021 $0.021 $0.020 $0.020 $0.020 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.015 $0.015 $0.014 $0.014 $0.014 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.034 $0.034 $0.034 $0.034 $0.034 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.012 $0.011 $0.011 $0.011 $0.011 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.046 $0.046 $0.045 $0.045 $0.045 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.092 $0.091 $0.090 $0.089 $0.089 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.079 $0.079 $0.078 $0.077 $0.077 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.073 $0.072 $0.072 $0.071 $0.071 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.067 $0.066 $0.066 $0.065 $0.065 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.061 $0.060 $0.060 $0.059 $0.059 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.097 0.096 0.095 0.094 0.094 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.084 0.084 0.083 0.082 0.082 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.078 0.077 0.077 0.076 0.076 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.072 0.071 0.071 0.070 0.070 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.066 0.065 0.065 0.064 0.064 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $65,600,667 $65,907,994 $66,215,321 $66,442,209 $66,669,096 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $57,175,195 $57,482,522 $57,789,849 $58,016,737 $58,243,625 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $52,962,459 $53,269,786 $53,577,113 $53,804,001 $54,030,889 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $48,749,723 $49,057,050 $49,364,377 $49,591,265 $49,818,153 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $44,536,988 $44,844,315 $45,151,642 $45,378,529 $45,605,417 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 65,600,667 393,911,327 723,758,623 1,055,062,115 1,387,500,045 1,664,487,928 1,716,045,422 1,767,602,915 1,819,160,408 1,870,717,901 1,922,275,395$100 M Grants, Bal. 5% 57,175,195 343,358,497 631,078,435 920,254,568 1,210,565,140 1,453,851,137 1,505,408,630 1,556,966,124 1,608,523,617 1,660,081,110 1,711,638,603$150 M Grants, Bal. 5% 52,962,459 318,082,082 584,738,341 852,850,795 1,122,097,688 1,348,532,741 1,400,090,235 1,451,647,728 1,503,205,221 1,554,762,714 1,606,320,208$200 M Grants, Bal. 5% 48,749,723 292,805,667 538,398,246 785,447,022 1,033,630,235 1,243,214,346 1,294,771,839 1,346,329,332 1,397,886,825 1,449,444,319 1,501,001,812$250 M Grants, Bal. 5% 44,536,988 267,529,252 492,058,152 718,043,248 945,162,783 1,137,895,950 1,189,453,443 1,241,010,936 1,292,568,430 1,344,125,923 1,395,683,416Annual Net Income 3,390,208 3,437,940 3,485,673 3,520,912 3,556,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 3,390,208 20,388,981 41,064,357 62,013,633 83,174,342 101,445,247 104,386,152 107,327,056 110,267,961 113,208,866 116,149,77043/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeFording Coal80 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 80,000 80,000 80,000 80,000 80,000 0 0 0 0 0 0Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 6,700 6,700 6,700 6,700 6,700 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 106,061 107,825 109,590 110,729 111,869 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 613,200,000 613,200,000 613,200,000 613,200,000 613,200,000 0 0 0 0 0 0Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 678,041,628 687,588,100 697,134,571 704,182,362 711,230,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 58,692,000 58,692,000 58,692,000 58,692,000 58,692,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 802,433,628 811,980,100 821,526,571 828,574,362 835,622,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000Combustion Turbine Bethel 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000CCK00000000000 Mine00000000000Bethel Utilities Plant 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000Total Capacity in KWs 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000Generation KWHsCoal Plant 782,372,788 791,680,597 800,988,407 807,860,003 814,731,600 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 20,060,841 20,299,502 20,538,164 20,714,359 20,890,554 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant $250 $250 $250 $250 $250 $250 $250 $250 $250 $250 $250138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $175,200,000 $175,200,000 $175,200,000 $175,200,000 $175,200,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $9,250,000 $9,250,000 $9,250,000 $9,250,000 $9,250,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities Plant $2,500,000 $2,500,000 $2,500,000 $2,500,000 $2,500,000Total $186,950,000 $186,950,000 $186,950,000 $186,950,000 $186,950,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $351,237,800 $351,237,800 $351,237,800 $351,237,800 $351,237,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $17,561,890 $17,561,890 $17,561,890 $17,561,890 $17,561,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $12,561,890 $12,561,890 $12,561,890 $12,561,890 $12,561,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,061,890 $10,061,890 $10,061,890 $10,061,890 $10,061,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $7,561,890 $7,561,890 $7,561,890 $7,561,890 $7,561,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,061,890 $5,061,890 $5,061,890 $5,061,890 $5,061,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $368,799,690 $368,799,690 $368,799,690 $368,799,690 $368,799,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $263,799,690 $263,799,690 $263,799,690 $263,799,690 $263,799,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $211,299,690 $211,299,690 $211,299,690 $211,299,690 $211,299,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $158,799,690 $158,799,690 $158,799,690 $158,799,690 $158,799,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $106,299,690 $106,299,690 $106,299,690 $106,299,690 $106,299,690 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $29,593,441 $29,593,441 $29,593,441 $29,593,441 $29,593,441 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $21,167,970 $21,167,970 $21,167,970 $21,167,970 $21,167,970 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $16,955,234 $16,955,234 $16,955,234 $16,955,234 $16,955,234 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $12,742,498 $12,742,498 $12,742,498 $12,742,498 $12,742,498 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $8,529,762 $8,529,762 $8,529,762 $8,529,762 $8,529,762 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 349,841 354,004 358,166 361,238 364,311 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,503,461 1,521,347 1,539,234 1,552,439 1,565,644 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $19,241,282 $19,470,194 $19,699,105 $19,868,102 $20,037,098 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,804,153 $1,825,617 $1,847,081 $1,862,927 $1,878,772 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $574,325 $581,158 $587,991 $593,035 $598,079 $136,099 $136,099 $136,099 $136,099 $136,099 $136,099 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $23,186,760 $23,443,968 $23,701,176 $23,891,063 $24,080,950 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $200,608 $202,995 $205,382 $207,144 $208,906 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,892,608 $7,894,995 $7,897,382 $7,899,144 $7,900,906 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek MIne -70 MW Aveage Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.044 $0.043 $0.042 $0.042 $0.042 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.031 $0.031 $0.030 $0.030 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.025 $0.025 $0.024 $0.024 $0.024 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.019 $0.019 $0.018 $0.018 $0.018 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.013 $0.012 $0.012 $0.012 $0.012 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.034 $0.034 $0.034 $0.034 $0.034 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.012 $0.011 $0.011 $0.011 $0.011 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.046 $0.046 $0.045 $0.045 $0.045 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.089 $0.089 $0.088 $0.087 $0.087 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.077 $0.076 $0.076 $0.075 $0.075 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.071 $0.070 $0.070 $0.069 $0.069 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.065 $0.064 $0.064 $0.063 $0.063 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.058 $0.058 $0.058 $0.057 $0.057 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.094 0.094 0.093 0.092 0.092 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.082 0.081 0.081 0.080 0.080 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.076 0.075 0.075 0.074 0.074 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.070 0.069 0.069 0.068 0.068 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.063 0.063 0.063 0.062 0.062 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $64,063,018 $64,370,345 $64,677,672 $64,904,560 $65,131,448 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $55,637,546 $55,944,874 $56,252,201 $56,479,088 $56,705,976 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $51,424,811 $51,732,138 $52,039,465 $52,266,352 $52,493,240 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $47,212,075 $47,519,402 $47,826,729 $48,053,617 $48,280,504 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $42,999,339 $43,306,666 $43,613,993 $43,840,881 $44,067,769 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 64,063,018 384,685,436 706,844,489 1,030,459,737 1,355,209,425 1,626,046,714 1,677,604,207 1,729,161,700 1,780,719,194 1,832,276,687 1,883,834,180$100 M Grants, Bal. 5% 55,637,546 334,132,606 614,164,300 895,652,191 1,178,274,520 1,415,409,923 1,466,967,416 1,518,524,909 1,570,082,402 1,621,639,896 1,673,197,389$150 M Grants, Bal. 5% 51,424,811 308,856,191 567,824,206 828,248,418 1,089,807,068 1,310,091,527 1,361,649,020 1,413,206,513 1,464,764,007 1,516,321,500 1,567,878,993$200 M Grants, Bal. 5% 47,212,075 283,579,776 521,484,112 760,844,644 1,001,339,615 1,204,773,131 1,256,330,624 1,307,888,118 1,359,445,611 1,411,003,104 1,462,560,597$250 M Grants, Bal. 5% 42,999,339 258,303,361 475,144,018 693,440,871 912,872,163 1,099,454,736 1,151,012,229 1,202,569,722 1,254,127,215 1,305,684,708 1,357,242,202Annual Net Income 3,390,208 3,437,940 3,485,673 3,520,912 3,556,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 3,390,208 20,388,981 41,064,357 62,013,633 83,174,342 101,445,247 104,386,152 107,327,056 110,267,961 113,208,866 116,149,77043/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeFording Coal97 MW Land-Based Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 60,000 60,000 60,000 60,000 60,000 0 0 0 0 0 0Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 3,500 3,500 3,500 3,500 3,500 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 82,861 84,625 86,390 87,529 88,669 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 438,000,000 438,000,000 438,000,000 438,000,000 438,000,000 0 0 0 0 0 0Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 502,841,628 512,388,100 521,934,571 528,982,362 536,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 30,660,000 30,660,000 30,660,000 30,660,000 30,660,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 599,201,628 608,748,100 618,294,571 625,342,362 632,390,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine 0 0 0 0 0 0 0 0 0 0 0Bethel Utilities Plant 0 0 0 0 0 0 0 0 0 0 0Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 584,221,588 593,529,397 602,837,207 609,708,803 616,580,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 14,980,041 15,218,702 15,457,364 15,633,559 15,809,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 0 0 0 0 0 0 0 0 0 0 0Purchased Power 0 0 0 0 0 0 0 0 0 0 02. Capital Cost(1)Plant CostsCoal Plant $/kW $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175 $2,175Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $210,975,000 $210,975,000 $210,975,000 $210,975,000 $210,975,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $227,995,000 $227,995,000 $227,995,000 $227,995,000 $227,995,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine 0 0 0 0 0 0 0 0 0 0 0Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $392,282,800 $392,282,800 $392,282,800 $392,282,800 $392,282,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $19,614,140 $19,614,140 $19,614,140 $19,614,140 $19,614,140 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $14,614,140 $14,614,140 $14,614,140 $14,614,140 $14,614,140 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $12,114,140 $12,114,140 $12,114,140 $12,114,140 $12,114,140 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $9,614,140 $9,614,140 $9,614,140 $9,614,140 $9,614,140 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $7,114,140 $7,114,140 $7,114,140 $7,114,140 $7,114,140 $0 $0 $0 $0 $0 $0Total Capital Cost5% $411,896,940 $411,896,940 $411,896,940 $411,896,940 $411,896,940 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $306,896,940 $306,896,940 $306,896,940 $306,896,940 $306,896,940 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $254,396,940 $254,396,940 $254,396,940 $254,396,940 $254,396,940 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $201,896,940 $201,896,940 $201,896,940 $201,896,940 $201,896,940 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $149,396,940 $149,396,940 $149,396,940 $149,396,940 $149,396,940 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $33,051,676 $33,051,676 $33,051,676 $33,051,676 $33,051,676 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $24,626,204 $24,626,204 $24,626,204 $24,626,204 $24,626,204 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $20,413,469 $20,413,469 $20,413,469 $20,413,469 $20,413,469 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $16,200,733 $16,200,733 $16,200,733 $16,200,733 $16,200,733 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $11,987,997 $11,987,997 $11,987,997 $11,987,997 $11,987,997 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 261,237 265,399 269,561 272,634 275,707 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,122,680 1,140,566 1,158,453 1,171,658 1,184,863 232,911 232,911 232,911 232,911 232,911 232,911CCKMine 0 0 0 0 0 0 0 0 0 0 0Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $14,368,051 $14,596,963 $14,825,874 $14,994,871 $15,163,868 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,347,216 $1,368,680 $1,390,144 $1,405,990 $1,421,835 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $428,866 $435,699 $442,532 $447,576 $452,620 $136,099 $136,099 $136,099 $136,099 $136,099 $136,099 O&M Tug + Barges $2,100,000 $2,100,000 $2,100,000 $2,100,000 $2,100,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $18,244,133 $18,501,342 $18,758,550 $18,948,436 $19,138,323 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $149,800 $152,187 $154,574 $156,336 $158,098 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,841,800 $7,844,187 $7,846,574 $7,848,336 $7,850,098 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.066 $0.065 $0.063 $0.062 $0.062 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.049 $0.048 $0.047 $0.047 $0.046 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.041 $0.040 $0.039 $0.039 $0.038 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.032 $0.032 $0.031 $0.031 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.024 $0.023 $0.023 $0.023 $0.022 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.036 $0.036 $0.036 $0.036 $0.036 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.016 $0.015 $0.015 $0.015 $0.015 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.052 $0.051 $0.051 $0.051 $0.050 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.118 $0.116 $0.114 $0.113 $0.112 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.101 $0.099 $0.098 $0.097 $0.096 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.092 $0.091 $0.090 $0.089 $0.088 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.084 $0.083 $0.082 $0.081 $0.081 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.076 $0.075 $0.074 $0.073 $0.073 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.123 0.121 0.119 0.118 0.117 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.106 0.104 0.103 0.102 0.101 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.097 0.096 0.095 0.094 0.093 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.089 0.088 0.087 0.086 0.086 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.081 0.080 0.079 0.078 0.078 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $61,651,818 $61,959,145 $62,266,472 $62,493,360 $62,720,248 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $53,226,346 $53,533,674 $53,841,001 $54,067,888 $54,294,776 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $49,013,611 $49,320,938 $49,628,265 $49,855,152 $50,082,040 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $44,800,875 $45,108,202 $45,415,529 $45,642,417 $45,869,304 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $40,588,139 $40,895,466 $41,202,793 $41,429,681 $41,656,569 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 61,651,818 370,218,236 680,321,288 991,880,537 1,304,574,225 1,565,766,714 1,617,324,207 1,668,881,700 1,720,439,194 1,771,996,687 1,823,554,180$100 M Grants, Bal. 5% 53,226,346 319,665,406 587,641,100 857,072,991 1,127,639,320 1,355,129,923 1,406,687,416 1,458,244,909 1,509,802,402 1,561,359,895 1,612,917,389$150 M Grants, Bal. 5% 49,013,611 294,388,991 541,301,006 789,669,218 1,039,171,868 1,249,811,527 1,301,369,020 1,352,926,513 1,404,484,006 1,456,041,500 1,507,598,993$200 M Grants, Bal. 5% 44,800,875 269,112,576 494,960,912 722,265,444 950,704,415 1,144,493,131 1,196,050,624 1,247,608,118 1,299,165,611 1,350,723,104 1,402,280,597$250 M Grants, Bal. 5% 40,588,139 243,836,161 448,620,818 654,861,671 862,236,963 1,039,174,735 1,090,732,229 1,142,289,722 1,193,847,215 1,245,404,708 1,296,962,202Annual Net Income 2,514,208 2,561,940 2,609,673 2,644,912 2,680,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,514,208 15,132,981 30,552,357 46,245,633 62,150,342 76,041,247 78,982,152 81,923,056 84,863,961 87,804,866 90,745,77043/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine Life97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 60,000 60,000 60,000 60,000 60,000 0 00000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 3,500 3,500 3,500 3,500 3,500 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 82,861 84,625 86,390 87,529 88,669 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 438,000,000 438,000,000 438,000,000 438,000,000 438,000,000 0 00000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 502,841,628 512,388,100 521,934,571 528,982,362 536,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 30,660,000 30,660,000 30,660,000 30,660,000 30,660,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 599,201,628 608,748,100 618,294,571 625,342,362 632,390,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 584,221,588 593,529,397 602,837,207 609,708,803 616,580,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 14,980,041 15,218,702 15,457,364 15,633,559 15,809,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $369,487,800 $369,487,800 $369,487,800 $369,487,800 $369,487,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $18,474,390 $18,474,390 $18,474,390 $18,474,390 $18,474,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $13,474,390 $13,474,390 $13,474,390 $13,474,390 $13,474,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,974,390 $10,974,390 $10,974,390 $10,974,390 $10,974,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,474,390 $8,474,390 $8,474,390 $8,474,390 $8,474,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,974,390 $5,974,390 $5,974,390 $5,974,390 $5,974,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $387,962,190 $387,962,190 $387,962,190 $387,962,190 $387,962,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $282,962,190 $282,962,190 $282,962,190 $282,962,190 $282,962,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $230,462,190 $230,462,190 $230,462,190 $230,462,190 $230,462,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $177,962,190 $177,962,190 $177,962,190 $177,962,190 $177,962,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $125,462,190 $125,462,190 $125,462,190 $125,462,190 $125,462,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $31,131,090 $31,131,090 $31,131,090 $31,131,090 $31,131,090 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $22,705,618 $22,705,618 $22,705,618 $22,705,618 $22,705,618 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,492,882 $18,492,882 $18,492,882 $18,492,882 $18,492,882 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,280,147 $14,280,147 $14,280,147 $14,280,147 $14,280,147 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $10,067,411 $10,067,411 $10,067,411 $10,067,411 $10,067,411 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 261,237 265,399 269,561 272,634 275,707 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,122,680 1,140,566 1,158,453 1,171,658 1,184,863 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $14,368,051 $14,596,963 $14,825,874 $14,994,871 $15,163,868 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,347,216 $1,368,680 $1,390,144 $1,405,990 $1,421,835 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $428,866 $435,699 $442,532 $447,576 $452,620 $136,099 $136,099 $136,099 $136,099 $136,099 $136,099 O&M Tug + Barges $2,100,000 $2,100,000 $2,100,000 $2,100,000 $2,100,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $18,244,133 $18,501,342 $18,758,550 $18,948,436 $19,138,323 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $149,800 $152,187 $154,574 $156,336 $158,098 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,841,800 $7,844,187 $7,846,574 $7,848,336 $7,850,098 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.062 $0.061 $0.060 $0.059 $0.058 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.045 $0.044 $0.044 $0.043 $0.042 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.037 $0.036 $0.035 $0.035 $0.034 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.028 $0.028 $0.027 $0.027 $0.027 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.020 $0.020 $0.019 $0.019 $0.019 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.036 $0.036 $0.036 $0.036 $0.036 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.016 $0.015 $0.015 $0.015 $0.015 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.052 $0.051 $0.051 $0.051 $0.050 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.114 $0.112 $0.111 $0.110 $0.108 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.097 $0.096 $0.094 $0.094 $0.093 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.089 $0.088 $0.086 $0.086 $0.085 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.080 $0.079 $0.078 $0.078 $0.077 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.072 $0.071 $0.070 $0.070 $0.069 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.119 0.117 0.116 0.115 0.113 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.102 0.101 0.099 0.099 0.098 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.094 0.093 0.091 0.091 0.090 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.085 0.084 0.083 0.083 0.082 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.077 0.076 0.075 0.075 0.074 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $59,731,232 $60,038,559 $60,345,886 $60,572,774 $60,799,661 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $51,305,760 $51,613,087 $51,920,414 $52,147,302 $52,374,190 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $47,093,024 $47,400,351 $47,707,678 $47,934,566 $48,161,454 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $42,880,289 $43,187,616 $43,494,943 $43,721,830 $43,948,718 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $38,667,553 $38,974,880 $39,282,207 $39,509,095 $39,735,982 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 59,731,232 358,694,718 659,194,840 961,151,157 1,264,241,913 1,517,752,057 1,569,309,551 1,620,867,044 1,672,424,537 1,723,982,030 1,775,539,523$100 M Grants, Bal. 5% 51,305,760 308,141,888 566,514,651 826,343,611 1,087,307,008 1,307,115,266 1,358,672,759 1,410,230,252 1,461,787,746 1,513,345,239 1,564,902,732$150 M Grants, Bal. 5% 47,093,024 282,865,473 520,174,557 758,939,837 998,839,556 1,201,796,870 1,253,354,363 1,304,911,857 1,356,469,350 1,408,026,843 1,459,584,336$200 M Grants, Bal. 5% 42,880,289 257,589,058 473,834,463 691,536,064 910,372,104 1,096,478,475 1,148,035,968 1,199,593,461 1,251,150,954 1,302,708,447 1,354,265,941$250 M Grants, Bal. 5% 38,667,553 232,312,643 427,494,369 624,132,291 821,904,651 991,160,079 1,042,717,572 1,094,275,065 1,145,832,559 1,197,390,052 1,248,947,545Annual Net Income 2,514,208 2,561,940 2,609,673 2,644,912 2,680,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,514,208 15,132,981 30,552,357 46,245,633 62,150,342 76,041,247 78,982,152 81,923,056 84,863,961 87,804,866 90,745,77043/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine Life80 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 60,000 60,000 60,000 60,000 60,000 0 0 0 0 0 0Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 3,500 3,500 3,500 3,500 3,500 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 82,861 84,625 86,390 87,529 88,669 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 438,000,000 438,000,000 438,000,000 438,000,000 438,000,000 0 0 0 0 0 0Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 502,841,628 512,388,100 521,934,571 528,982,362 536,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 30,660,000 30,660,000 30,660,000 30,660,000 30,660,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 599,201,628 608,748,100 618,294,571 625,342,362 632,390,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000Combustion Turbine Bethel 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000CCK00000000000 Mine00000000000Bethel Utilities Plant 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000Total Capacity in KWs 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000Generation KWHsCoal Plant 584,221,588 593,529,397 602,837,207 609,708,803 616,580,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 14,980,041 15,218,702 15,457,364 15,633,559 15,809,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190 $2,190Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant $250 $250 $250 $250 $250 $250 $250 $250 $250 $250 $250138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $175,200,000 $175,200,000 $175,200,000 $175,200,000 $175,200,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $9,250,000 $9,250,000 $9,250,000 $9,250,000 $9,250,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities Plant $2,500,000 $2,500,000 $2,500,000 $2,500,000 $2,500,000Total $186,950,000 $186,950,000 $186,950,000 $186,950,000 $186,950,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $351,237,800 $351,237,800 $351,237,800 $351,237,800 $351,237,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $17,561,890 $17,561,890 $17,561,890 $17,561,890 $17,561,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $12,561,890 $12,561,890 $12,561,890 $12,561,890 $12,561,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,061,890 $10,061,890 $10,061,890 $10,061,890 $10,061,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $7,561,890 $7,561,890 $7,561,890 $7,561,890 $7,561,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,061,890 $5,061,890 $5,061,890 $5,061,890 $5,061,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $368,799,690 $368,799,690 $368,799,690 $368,799,690 $368,799,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $263,799,690 $263,799,690 $263,799,690 $263,799,690 $263,799,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $211,299,690 $211,299,690 $211,299,690 $211,299,690 $211,299,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $158,799,690 $158,799,690 $158,799,690 $158,799,690 $158,799,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $106,299,690 $106,299,690 $106,299,690 $106,299,690 $106,299,690 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $29,593,441 $29,593,441 $29,593,441 $29,593,441 $29,593,441 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $21,167,970 $21,167,970 $21,167,970 $21,167,970 $21,167,970 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $16,955,234 $16,955,234 $16,955,234 $16,955,234 $16,955,234 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $12,742,498 $12,742,498 $12,742,498 $12,742,498 $12,742,498 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $8,529,762 $8,529,762 $8,529,762 $8,529,762 $8,529,762 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 261,237 265,399 269,561 272,634 275,707 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,122,680 1,140,566 1,158,453 1,171,658 1,184,863 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $14,368,051 $14,596,963 $14,825,874 $14,994,871 $15,163,868 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,347,216 $1,368,680 $1,390,144 $1,405,990 $1,421,835 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $428,866 $435,699 $442,532 $447,576 $452,620 $136,099 $136,099 $136,099 $136,099 $136,099 $136,099 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $17,711,133 $17,968,342 $18,225,550 $18,415,436 $18,605,323 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $149,800 $152,187 $154,574 $156,336 $158,098 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,841,800 $7,844,187 $7,846,574 $7,848,336 $7,850,098 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 50 MW Average Demand, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.059 $0.058 $0.057 $0.056 $0.055 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.042 $0.041 $0.041 $0.040 $0.039 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.034 $0.033 $0.032 $0.032 $0.032 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.025 $0.025 $0.024 $0.024 $0.024 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.017 $0.017 $0.016 $0.016 $0.016 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.035 $0.035 $0.035 $0.035 $0.035 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.016 $0.015 $0.015 $0.015 $0.015 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.051 $0.050 $0.050 $0.050 $0.049 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.110 $0.108 $0.107 $0.106 $0.105 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.093 $0.092 $0.091 $0.090 $0.089 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.085 $0.083 $0.082 $0.082 $0.081 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.076 $0.075 $0.074 $0.074 $0.073 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.068 $0.067 $0.066 $0.066 $0.065 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.115 0.113 0.112 0.111 0.110 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.098 0.097 0.096 0.095 0.094 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.090 0.088 0.087 0.087 0.086 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.081 0.080 0.079 0.079 0.078 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.073 0.072 0.071 0.071 0.070 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $57,660,583 $57,967,910 $58,275,237 $58,502,125 $58,729,013 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $49,235,112 $49,542,439 $49,849,766 $50,076,653 $50,303,541 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $45,022,376 $45,329,703 $45,637,030 $45,863,918 $46,090,805 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $40,809,640 $41,116,967 $41,424,294 $41,651,182 $41,878,069 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $36,596,904 $36,904,231 $37,211,558 $37,438,446 $37,665,334 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 57,660,583 346,270,827 636,417,705 928,020,780 1,220,758,293 1,465,985,843 1,517,543,336 1,569,100,829 1,620,658,323 1,672,215,816 1,723,773,309$100 M Grants, Bal. 5% 49,235,112 295,717,997 543,737,517 793,213,233 1,043,823,388 1,255,349,051 1,306,906,545 1,358,464,038 1,410,021,531 1,461,579,024 1,513,136,518$150 M Grants, Bal. 5% 45,022,376 270,441,582 497,397,423 725,809,460 955,355,936 1,150,030,656 1,201,588,149 1,253,145,642 1,304,703,135 1,356,260,629 1,407,818,122$200 M Grants, Bal. 5% 40,809,640 245,165,167 451,057,329 658,405,687 866,888,484 1,044,712,260 1,096,269,753 1,147,827,247 1,199,384,740 1,250,942,233 1,302,499,726$250 M Grants, Bal. 5% 36,596,904 219,888,752 404,717,235 591,001,914 778,421,031 939,393,864 990,951,358 1,042,508,851 1,094,066,344 1,145,623,837 1,197,181,331Annual Net Income 2,514,208 2,561,940 2,609,673 2,644,912 2,680,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,514,208 15,132,981 30,552,357 46,245,633 62,150,342 76,041,247 78,982,152 81,923,056 84,863,961 87,804,866 90,745,77043/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeLuscar Coal Valley Mine 97 MW Land-Based Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 00000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 00000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $2,225 $2,225 $2,225 $2,225 $2,225 $2,225 $2,225 $2,225 $2,225 $2,225 $2,225Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $215,825,000 $215,825,000 $215,825,000 $215,825,000 $215,825,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $232,845,000 $232,845,000 $232,845,000 $232,845,000 $232,845,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $397,132,800 $397,132,800 $397,132,800 $397,132,800 $397,132,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $19,856,640 $19,856,640 $19,856,640 $19,856,640 $19,856,640 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $14,856,640 $14,856,640 $14,856,640 $14,856,640 $14,856,640 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $12,356,640 $12,356,640 $12,356,640 $12,356,640 $12,356,640 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $9,856,640 $9,856,640 $9,856,640 $9,856,640 $9,856,640 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $7,356,640 $7,356,640 $7,356,640 $7,356,640 $7,356,640 $0 $0 $0 $0 $0 $0Total Capital Cost5% $416,989,440 $416,989,440 $416,989,440 $416,989,440 $416,989,440 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $311,989,440 $311,989,440 $311,989,440 $311,989,440 $311,989,440 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $259,489,440 $259,489,440 $259,489,440 $259,489,440 $259,489,440 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $206,989,440 $206,989,440 $206,989,440 $206,989,440 $206,989,440 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $154,489,440 $154,489,440 $154,489,440 $154,489,440 $154,489,440 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $33,460,311 $33,460,311 $33,460,311 $33,460,311 $33,460,311 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $25,034,840 $25,034,840 $25,034,840 $25,034,840 $25,034,840 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $20,822,104 $20,822,104 $20,822,104 $20,822,104 $20,822,104 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $16,609,368 $16,609,368 $16,609,368 $16,609,368 $16,609,368 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $12,396,632 $12,396,632 $12,396,632 $12,396,632 $12,396,632 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 346,258 350,981 355,703 359,190 362,676 76,593 76,593 76,593 76,593 76,593 76,593 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $43.25 $43.25 $43.25 $43.25 $43.25 $58.00 $58.00 $58.00 $58.00 $58.00 $58.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $14,975,660 $15,179,912 $15,384,164 $15,534,956 $15,685,747 $4,442,405 $4,442,405 $4,442,405 $4,442,405 $4,442,405 $4,442,405 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan$451,629$457,789$463,948$468,496$473,043$128,860$128,860$128,860$128,860$128,860$128,860 O&M Tug + Barges $1,770,000 $1,770,000 $1,770,000 $1,770,000 $1,770,000 $423,750 $423,750 $423,750 $423,750 $423,750 $423,750 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $18,771,003 $19,002,879 $19,234,755 $19,405,940 $19,577,125 $5,274,507 $5,274,507 $5,274,507 $5,274,507 $5,274,507 $5,274,507O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,200,000 5,200,000 5,200,000 5,200,000 5,200,000 2,700,000 2,700,000 2,700,000 2,700,000 2,700,000 2,700,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $8,066,985 $8,069,372 $8,071,759 $8,073,521 $8,075,283 $4,523,078 $4,523,078 $4,523,078 $4,523,078 $4,523,078 $4,523,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.057 $0.056 $0.055 $0.054 $0.054 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.042 $0.042 $0.041 $0.041 $0.040 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.035 $0.035 $0.034 $0.034 $0.033 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.028 $0.028 $0.027 $0.027 $0.027 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.021 $0.021 $0.020 $0.020 $0.020 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.032 $0.032 $0.032 $0.031 $0.031 $0.054 $0.054 $0.054 $0.054 $0.054 $0.054 O&M $/kWh $0.014 $0.013 $0.013 $0.013 $0.013 $0.046 $0.046 $0.046 $0.046 $0.046 $0.046 Total $0.045 $0.045 $0.045 $0.045 $0.044 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.102 $0.101 $0.100 $0.099 $0.098 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.088 $0.087 $0.086 $0.085 $0.084 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.081 $0.080 $0.079 $0.078 $0.078 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.074 $0.073 $0.072 $0.072 $0.071 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.066 $0.066 $0.065 $0.065 $0.064 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.107 0.106 0.105 0.104 0.103 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.093 0.092 0.091 0.090 0.089 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.086 0.085 0.084 0.083 0.083 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.079 0.078 0.077 0.077 0.076 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.071 0.071 0.070 0.070 0.069 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $63,250,508 $63,532,503 $63,814,498 $64,022,684 $64,230,870 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$100 M Grants, Bal. 5% $54,825,037 $55,107,032 $55,389,026 $55,597,212 $55,805,398 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$150 M Grants, Bal. 5% $50,612,301 $50,894,296 $51,176,291 $51,384,476 $51,592,662 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$200 M Grants, Bal. 5% $46,399,565 $46,681,560 $46,963,555 $47,171,741 $47,379,927 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$250 M Grants, Bal. 5% $42,186,829 $42,468,824 $42,750,819 $42,959,005 $43,167,191 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735Accumulated WholeSale Cost of Power5% 63,250,508 379,785,045 697,729,556 1,017,010,232 1,337,331,838 1,604,543,053 1,655,981,730 1,707,420,407 1,758,859,084 1,810,297,761 1,861,736,438$100 M Grants, Bal. 5% 54,825,037 329,232,215 605,049,367 882,202,685 1,160,396,933 1,393,906,261 1,445,344,938 1,496,783,616 1,548,222,293 1,599,660,970 1,651,099,647$150 M Grants, Bal. 5% 50,612,301 303,955,800 558,709,273 814,798,912 1,071,929,481 1,288,587,866 1,340,026,543 1,391,465,220 1,442,903,897 1,494,342,574 1,545,781,251$200 M Grants, Bal. 5% 46,399,565 278,679,385 512,369,179 747,395,139 983,462,028 1,183,269,470 1,234,708,147 1,286,146,824 1,337,585,501 1,389,024,178 1,440,462,856$250 M Grants, Bal. 5% 42,186,829 253,402,970 466,029,085 679,991,366 894,994,576 1,077,951,074 1,129,389,751 1,180,828,429 1,232,267,106 1,283,705,783 1,335,144,460Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,126,088,188$100 M Grants, Bal. 5% $976,084,269$150 M Grants, Bal. 5% $901,082,310$200 M Grants, Bal. 5% $826,080,350$250 M Grants, Bal. 5% $751,078,39143/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeLuscar Coal Valley Mine 97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 00000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 00000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $1,990 $1,990 $1,990 $1,990 $1,990 $1,990 $1,990 $1,990 $1,990 $1,990 $1,990Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $193,030,000 $193,030,000 $193,030,000 $193,030,000 $193,030,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $210,050,000 $210,050,000 $210,050,000 $210,050,000 $210,050,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $374,337,800 $374,337,800 $374,337,800 $374,337,800 $374,337,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $18,716,890 $18,716,890 $18,716,890 $18,716,890 $18,716,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $13,716,890 $13,716,890 $13,716,890 $13,716,890 $13,716,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $11,216,890 $11,216,890 $11,216,890 $11,216,890 $11,216,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,716,890 $8,716,890 $8,716,890 $8,716,890 $8,716,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $6,216,890 $6,216,890 $6,216,890 $6,216,890 $6,216,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $393,054,690 $393,054,690 $393,054,690 $393,054,690 $393,054,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $288,054,690 $288,054,690 $288,054,690 $288,054,690 $288,054,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $235,554,690 $235,554,690 $235,554,690 $235,554,690 $235,554,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $183,054,690 $183,054,690 $183,054,690 $183,054,690 $183,054,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $130,554,690 $130,554,690 $130,554,690 $130,554,690 $130,554,690 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $31,539,725 $31,539,725 $31,539,725 $31,539,725 $31,539,725 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $23,114,254 $23,114,254 $23,114,254 $23,114,254 $23,114,254 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,901,518 $18,901,518 $18,901,518 $18,901,518 $18,901,518 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,688,782 $14,688,782 $14,688,782 $14,688,782 $14,688,782 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $10,476,046 $10,476,046 $10,476,046 $10,476,046 $10,476,046 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 346,258 350,981 355,703 359,190 362,676 76,593 76,593 76,593 76,593 76,593 76,593 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $43.25 $43.25 $43.25 $43.25 $43.25 $58.00 $58.00 $58.00 $58.00 $58.00 $58.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $14,975,660 $15,179,912 $15,384,164 $15,534,956 $15,685,747 $4,442,405 $4,442,405 $4,442,405 $4,442,405 $4,442,405 $4,442,405 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan$451,629$457,789$463,948$468,496$473,043$128,860$128,860$128,860$128,860$128,860$128,860 O&M Tug + Barges $1,770,000 $1,770,000 $1,770,000 $1,770,000 $1,770,000 $423,750 $423,750 $423,750 $423,750 $423,750 $423,750 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $18,771,003 $19,002,879 $19,234,755 $19,405,940 $19,577,125 $5,274,507 $5,274,507 $5,274,507 $5,274,507 $5,274,507 $5,274,507O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,200,000 5,200,000 5,200,000 5,200,000 5,200,000 2,700,000 2,700,000 2,700,000 2,700,000 2,700,000 2,700,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $8,066,985 $8,069,372 $8,071,759 $8,073,521 $8,075,283 $4,523,078 $4,523,078 $4,523,078 $4,523,078 $4,523,078 $4,523,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.053 $0.053 $0.052 $0.051 $0.051 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.039 $0.039 $0.038 $0.037 $0.037 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.032 $0.032 $0.031 $0.031 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.025 $0.024 $0.024 $0.024 $0.024 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.018 $0.017 $0.017 $0.017 $0.017 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.032 $0.032 $0.032 $0.031 $0.031 $0.054 $0.054 $0.054 $0.054 $0.054 $0.054 O&M $/kWh $0.014 $0.013 $0.013 $0.013 $0.013 $0.046 $0.046 $0.046 $0.046 $0.046 $0.046 Total $0.045 $0.045 $0.045 $0.045 $0.044 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.099 $0.098 $0.097 $0.096 $0.095 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.085 $0.084 $0.083 $0.082 $0.081 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.077 $0.077 $0.076 $0.075 $0.075 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.070 $0.070 $0.069 $0.068 $0.068 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.063 $0.063 $0.062 $0.062 $0.061 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.104 0.103 0.102 0.101 0.100 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.090 0.089 0.088 0.087 0.086 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.082 0.082 0.081 0.080 0.080 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.075 0.075 0.074 0.073 0.073 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.068 0.068 0.067 0.067 0.066 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $61,329,922 $61,611,917 $61,893,912 $62,102,098 $62,310,284 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$100 M Grants, Bal. 5% $52,904,450 $53,186,445 $53,468,440 $53,676,626 $53,884,812 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$150 M Grants, Bal. 5% $48,691,715 $48,973,709 $49,255,704 $49,463,890 $49,672,076 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$200 M Grants, Bal. 5% $44,478,979 $44,760,974 $45,042,968 $45,251,154 $45,459,340 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$250 M Grants, Bal. 5% $40,266,243 $40,548,238 $40,830,233 $41,038,419 $41,246,605 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735Accumulated WholeSale Cost of Power5% 61,329,922 368,261,527 676,603,107 986,280,852 1,296,999,526 1,556,528,396 1,607,967,073 1,659,405,750 1,710,844,428 1,762,283,105 1,813,721,782$100 M Grants, Bal. 5% 52,904,450 317,708,697 583,922,919 851,473,305 1,120,064,621 1,345,891,605 1,397,330,282 1,448,768,959 1,500,207,636 1,551,646,313 1,603,084,990$150 M Grants, Bal. 5% 48,691,715 292,432,282 537,582,824 784,069,532 1,031,597,169 1,240,573,209 1,292,011,886 1,343,450,563 1,394,889,240 1,446,327,918 1,497,766,595$200 M Grants, Bal. 5% 44,478,979 267,155,867 491,242,730 716,665,759 943,129,717 1,135,254,813 1,186,693,490 1,238,132,168 1,289,570,845 1,341,009,522 1,392,448,199$250 M Grants, Bal. 5% 40,266,243 241,879,452 444,902,636 649,261,985 854,662,264 1,029,936,418 1,081,375,095 1,132,813,772 1,184,252,449 1,235,691,126 1,287,129,803Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,091,894,795$100 M Grants, Bal. 5% $941,890,876$150 M Grants, Bal. 5% $866,888,917$200 M Grants, Bal. 5% $791,886,957$250 M Grants, Bal. 5% $716,884,99843/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeLuscar Coal Valley Mine 80 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,0000000 00Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,0000000 00Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000 80,000Combustion Turbine Bethel 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000CCK 000000000 00 Mine000000000 00Bethel Utilities Plant 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000Total Capacity in KWs 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000 115,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK 000000000 00 Mine 000000000 00Purchased Power000000000 002. Capital Cost(1)Plant CostsCoal Plant $/kW $2,240 $2,240 $2,240 $2,240 $2,240 $2,240 $2,240 $2,240 $2,240 $2,240 $2,240Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant $250 $250 $250 $250 $250 $250 $250 $250 $250 $250 $250138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $179,200,000 $179,200,000 $179,200,000 $179,200,000 $179,200,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $9,250,000 $9,250,000 $9,250,000 $9,250,000 $9,250,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities Plant $2,500,000 $2,500,000 $2,500,000 $2,500,000 $2,500,000Total $190,950,000 $190,950,000 $190,950,000 $190,950,000 $190,950,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK 000000000 00 Mine000000000 00Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $355,237,800 $355,237,800 $355,237,800 $355,237,800 $355,237,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $17,761,890 $17,761,890 $17,761,890 $17,761,890 $17,761,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $12,761,890 $12,761,890 $12,761,890 $12,761,890 $12,761,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,261,890 $10,261,890 $10,261,890 $10,261,890 $10,261,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $7,761,890 $7,761,890 $7,761,890 $7,761,890 $7,761,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,261,890 $5,261,890 $5,261,890 $5,261,890 $5,261,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $372,999,690 $372,999,690 $372,999,690 $372,999,690 $372,999,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $267,999,690 $267,999,690 $267,999,690 $267,999,690 $267,999,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $215,499,690 $215,499,690 $215,499,690 $215,499,690 $215,499,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $162,999,690 $162,999,690 $162,999,690 $162,999,690 $162,999,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $110,499,690 $110,499,690 $110,499,690 $110,499,690 $110,499,690 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $29,930,460 $29,930,460 $29,930,460 $29,930,460 $29,930,460 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $21,504,988 $21,504,988 $21,504,988 $21,504,988 $21,504,988 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $17,292,253 $17,292,253 $17,292,253 $17,292,253 $17,292,253 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $13,079,517 $13,079,517 $13,079,517 $13,079,517 $13,079,517 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $8,866,781 $8,866,781 $8,866,781 $8,866,781 $8,866,781 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 346,258 350,981 355,703 359,190 362,676 76,593 76,593 76,593 76,593 76,593 76,593 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine000000000 00Coal $/Ton $43.25 $43.25 $43.25 $43.25 $43.25 $58.00 $58.00 $58.00 $58.00 $58.00 $58.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $14,975,660 $15,179,912 $15,384,164 $15,534,956 $15,685,747 $4,442,405 $4,442,405 $4,442,405 $4,442,405 $4,442,405 $4,442,405 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan$451,629$457,789$463,948$468,496$473,043$128,860$128,860$128,860$128,860$128,860$128,860 O&M Tug + Barges $1,770,000 $1,770,000 $1,770,000 $1,770,000 $1,770,000 $423,750 $423,750 $423,750 $423,750 $423,750 $423,750 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $18,771,003 $19,002,879 $19,234,755 $19,405,940 $19,577,125 $5,274,507 $5,274,507 $5,274,507 $5,274,507 $5,274,507 $5,274,507O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,200,000 5,200,000 5,200,000 5,200,000 5,200,000 2,700,000 2,700,000 2,700,000 2,700,000 2,700,000 2,700,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $8,066,985 $8,069,372 $8,071,759 $8,073,521 $8,075,283 $4,523,078 $4,523,078 $4,523,078 $4,523,078 $4,523,078 $4,523,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.051 $0.050 $0.049 $0.049 $0.048 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.036 $0.036 $0.035 $0.035 $0.034 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.029 $0.029 $0.028 $0.028 $0.028 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.022 $0.022 $0.021 $0.021 $0.021 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.015 $0.015 $0.015 $0.014 $0.014 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.032 $0.032 $0.032 $0.031 $0.031 $0.054 $0.054 $0.054 $0.054 $0.054 $0.054 O&M $/kWh $0.014 $0.013 $0.013 $0.013 $0.013 $0.046 $0.046 $0.046 $0.046 $0.046 $0.046 Total $0.045 $0.045 $0.045 $0.045 $0.044 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.096 $0.095 $0.094 $0.093 $0.092 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.082 $0.081 $0.080 $0.079 $0.079 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.075 $0.074 $0.073 $0.073 $0.072 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.068 $0.067 $0.066 $0.066 $0.065 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.060 $0.060 $0.059 $0.059 $0.059 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.101 0.100 0.099 0.098 0.097 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.087 0.086 0.085 0.084 0.084 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.080 0.079 0.078 0.078 0.077 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.073 0.072 0.071 0.071 0.070 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.065 0.065 0.064 0.064 0.064 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $59,720,657 $60,002,652 $60,284,647 $60,492,833 $60,701,019 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$100 M Grants, Bal. 5% $51,295,185 $51,577,180 $51,859,175 $52,067,361 $52,275,547 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$150 M Grants, Bal. 5% $47,082,449 $47,364,444 $47,646,439 $47,854,625 $48,062,811 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$200 M Grants, Bal. 5% $42,869,714 $43,151,709 $43,433,703 $43,641,889 $43,850,075 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735$250 M Grants, Bal. 5% $38,656,978 $38,938,973 $39,220,968 $39,429,153 $39,637,339 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735 $10,287,735Accumulated WholeSale Cost of Power5% 59,720,657 358,605,937 658,901,191 960,532,610 1,263,204,959 1,516,296,769 1,567,735,446 1,619,174,123 1,670,612,800 1,722,051,477 1,773,490,155$100 M Grants, Bal. 5% 51,295,185 308,053,107 566,221,003 825,725,064 1,086,270,055 1,305,659,978 1,357,098,655 1,408,537,332 1,459,976,009 1,511,414,686 1,562,853,363$150 M Grants, Bal. 5% 47,082,449 282,776,692 519,880,908 758,321,291 997,802,602 1,200,341,582 1,251,780,259 1,303,218,936 1,354,657,613 1,406,096,290 1,457,534,968$200 M Grants, Bal. 5% 42,869,714 257,500,277 473,540,814 690,917,517 909,335,150 1,095,023,186 1,146,461,863 1,197,900,540 1,249,339,218 1,300,777,895 1,352,216,572$250 M Grants, Bal. 5% 38,656,978 232,223,862 427,200,720 623,513,744 820,867,697 989,704,791 1,041,143,468 1,092,582,145 1,144,020,822 1,195,459,499 1,246,898,176Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,063,244,046$100 M Grants, Bal. 5% $913,240,127$150 M Grants, Bal. 5% $838,238,168$200 M Grants, Bal. 5% $763,236,209$250 M Grants, Bal. 5% $688,234,24943/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeUsibelli Coal 97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000000000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000000000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK 0 0 0 0 0000000 Mine 0 0 0 0 0000000Bethel Utilities Plant 0 0 0 0 0000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK 0 0 0 0 0000000 Mine 0 0 0 0 0000000Purchased Power 0 0 0 0 00000002. Capital Cost(1)Plant CostsCoal Plant $/kW $2,300 $2,300 $2,300 $2,300 $2,300 $2,300 $2,300 $2,300 $2,300 $2,300 $2,300Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $223,100,000 $223,100,000 $223,100,000 $223,100,000 $223,100,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $240,120,000 $240,120,000 $240,120,000 $240,120,000 $240,120,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK 0 0 0 0 0000000 Mine 0 0 0 0 0000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $404,407,800 $404,407,800 $404,407,800 $404,407,800 $404,407,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $20,220,390 $20,220,390 $20,220,390 $20,220,390 $20,220,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $15,220,390 $15,220,390 $15,220,390 $15,220,390 $15,220,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $12,720,390 $12,720,390 $12,720,390 $12,720,390 $12,720,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $10,220,390 $10,220,390 $10,220,390 $10,220,390 $10,220,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $7,720,390 $7,720,390 $7,720,390 $7,720,390 $7,720,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $424,628,190 $424,628,190 $424,628,190 $424,628,190 $424,628,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $319,628,190 $319,628,190 $319,628,190 $319,628,190 $319,628,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $267,128,190 $267,128,190 $267,128,190 $267,128,190 $267,128,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $214,628,190 $214,628,190 $214,628,190 $214,628,190 $214,628,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $162,128,190 $162,128,190 $162,128,190 $162,128,190 $162,128,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $34,073,265 $34,073,265 $34,073,265 $34,073,265 $34,073,265 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $25,647,793 $25,647,793 $25,647,793 $25,647,793 $25,647,793 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $21,435,057 $21,435,057 $21,435,057 $21,435,057 $21,435,057 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $17,222,321 $17,222,321 $17,222,321 $17,222,321 $17,222,321 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $13,009,585 $13,009,585 $13,009,585 $13,009,585 $13,009,585 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 581,245 589,172 597,100 602,952 608,805 103,229 103,229 103,229 103,229 103,229 103,229 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine 0 0 0 0 0000000Coal $/Ton $28.70 $28.70 $28.70 $28.70 $28.70 $43.66 $43.66 $43.66 $43.66 $43.66 $43.66 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $16,681,722 $16,909,243 $17,136,764 $17,304,735 $17,472,705 $4,506,999 $4,506,999 $4,506,999 $4,506,999 $4,506,999 $4,506,999 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan$498,187$504,982$511,776$516,793$521,809$130,622$130,622$130,622$130,622$130,622$130,622 O&M Tug + Barges $2,695,000 $2,695,000 $2,695,000 $2,695,000 $2,695,000 $645,000 $645,000 $645,000 $645,000 $645,000 $645,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $21,448,624 $21,704,404 $21,960,183 $22,149,016 $22,337,848 $5,562,115 $5,562,115 $5,562,115 $5,562,115 $5,562,115 $5,562,115O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,500,000 5,500,000 5,500,000 5,500,000 5,500,000 2,700,000 2,700,000 2,700,000 2,700,000 2,700,000 2,700,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $8,366,985 $8,369,372 $8,371,759 $8,373,521 $8,375,283 $4,523,078 $4,523,078 $4,523,078 $4,523,078 $4,523,078 $4,523,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.058 $0.057 $0.056 $0.055 $0.055 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.043 $0.043 $0.042 $0.042 $0.041 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.036 $0.036 $0.035 $0.035 $0.034 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.029 $0.029 $0.028 $0.028 $0.028 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.022 $0.022 $0.021 $0.021 $0.021 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.036 $0.036 $0.036 $0.036 $0.036 $0.057 $0.057 $0.057 $0.057 $0.057 $0.057 O&M $/kWh $0.014 $0.014 $0.014 $0.014 $0.013 $0.046 $0.046 $0.046 $0.046 $0.046 $0.046 Total $0.050 $0.050 $0.050 $0.050 $0.049 $0.103 $0.103 $0.103 $0.103 $0.103 $0.103 BreakEven Cost $/kWh5% $0.108 $0.107 $0.106 $0.105 $0.104 $0.103 $0.103 $0.103 $0.103 $0.103 $0.103 $100 M Grants, Bal. 5% $0.094 $0.093 $0.092 $0.091 $0.090 $0.103 $0.103 $0.103 $0.103 $0.103 $0.103 $150 M Grants, Bal. 5% $0.087 $0.086 $0.085 $0.084 $0.084 $0.103 $0.103 $0.103 $0.103 $0.103 $0.103 $200 M Grants, Bal. 5% $0.080 $0.079 $0.078 $0.077 $0.077 $0.103 $0.103 $0.103 $0.103 $0.103 $0.103 $250 M Grants, Bal. 5% $0.073 $0.072 $0.071 $0.071 $0.070 $0.103 $0.103 $0.103 $0.103 $0.103 $0.103 Wholesale Cost$/kWh5% 0.113 0.112 0.111 0.110 0.109 0.108 0.108 0.108 0.108 0.108 0.108$100 M Grants, Bal. 5% 0.099 0.098 0.097 0.096 0.095 0.108 0.108 0.108 0.108 0.108 0.108$150 M Grants, Bal. 5% 0.092 0.091 0.090 0.089 0.089 0.108 0.108 0.108 0.108 0.108 0.108$200 M Grants, Bal. 5% 0.085 0.084 0.083 0.082 0.082 0.108 0.108 0.108 0.108 0.108 0.108$250 M Grants, Bal. 5% 0.078 0.077 0.076 0.076 0.075 0.108 0.108 0.108 0.108 0.108 0.108Annual WholeSale Cost of Power5% $66,841,082 $67,146,981 $67,452,879 $67,678,713 $67,904,546 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343$100 M Grants, Bal. 5% $58,415,610 $58,721,509 $59,027,408 $59,253,241 $59,479,074 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343$150 M Grants, Bal. 5% $54,202,874 $54,508,773 $54,814,672 $55,040,505 $55,266,338 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343$200 M Grants, Bal. 5% $49,990,139 $50,296,037 $50,601,936 $50,827,769 $51,053,603 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343$250 M Grants, Bal. 5% $45,777,403 $46,083,301 $46,389,200 $46,615,034 $46,840,867 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343 $10,575,343umulated WholeSale Cost of Power5% 66,841,082 401,352,390 737,393,192 1,074,883,422 1,413,502,819 1,695,696,345 1,748,573,060 1,801,449,774 1,854,326,488 1,907,203,203 1,960,079,917$100 M Grants, Bal. 5% 58,415,610 350,799,560 644,713,004 940,075,876 1,236,567,914 1,485,059,554 1,537,936,268 1,590,812,983 1,643,689,697 1,696,566,412 1,749,443,126$150 M Grants, Bal. 5% 54,202,874 325,523,145 598,372,909 872,672,102 1,148,100,461 1,379,741,158 1,432,617,873 1,485,494,587 1,538,371,301 1,591,248,016 1,644,124,730$200 M Grants, Bal. 5% 49,990,139 300,246,730 552,032,815 805,268,329 1,059,633,009 1,274,422,762 1,327,299,477 1,380,176,191 1,433,052,906 1,485,929,620 1,538,806,335$250 M Grants, Bal. 5% 45,777,403 274,970,315 505,692,721 737,864,556 971,165,557 1,169,104,367 1,221,981,081 1,274,857,796 1,327,734,510 1,380,611,224 1,433,487,939Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,190,013,404$100 M Grants, Bal. 5% $1,040,009,486$150 M Grants, Bal. 5% $965,007,526$200 M Grants, Bal. 5% $890,005,567$250 M Grants, Bal. 5% $815,003,60843/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine Line97 MW Barge-Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat Sales, 35% EfficiencyBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 00000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 00000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK 00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK 00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LineYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK 00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $369,487,800 $369,487,800 $369,487,800 $369,487,800 $369,487,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $18,474,390 $18,474,390 $18,474,390 $18,474,390 $18,474,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $13,474,390 $13,474,390 $13,474,390 $13,474,390 $13,474,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,974,390 $10,974,390 $10,974,390 $10,974,390 $10,974,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,474,390 $8,474,390 $8,474,390 $8,474,390 $8,474,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,974,390 $5,974,390 $5,974,390 $5,974,390 $5,974,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $387,962,190 $387,962,190 $387,962,190 $387,962,190 $387,962,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $282,962,190 $282,962,190 $282,962,190 $282,962,190 $282,962,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $230,462,190 $230,462,190 $230,462,190 $230,462,190 $230,462,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $177,962,190 $177,962,190 $177,962,190 $177,962,190 $177,962,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $125,462,190 $125,462,190 $125,462,190 $125,462,190 $125,462,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LineYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $31,131,090 $31,131,090 $31,131,090 $31,131,090 $31,131,090 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $22,705,618 $22,705,618 $22,705,618 $22,705,618 $22,705,618 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,492,882 $18,492,882 $18,492,882 $18,492,882 $18,492,882 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,280,147 $14,280,147 $14,280,147 $14,280,147 $14,280,147 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $10,067,411 $10,067,411 $10,067,411 $10,067,411 $10,067,411 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 270,480 274,170 277,859 280,582 283,306 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $14,876,427 $15,079,326 $15,282,225 $15,432,017 $15,581,810 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $448,921 $455,044 $461,166 $465,687 $470,207 $136,099 $136,099 $136,099 $136,099 $136,099 $136,099 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $18,466,063 $18,696,548 $18,927,034 $19,097,192 $19,267,351 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LineTotal O&M $7,866,985 $7,869,372 $7,871,759 $7,873,521 $7,875,283 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.053 $0.052 $0.051 $0.050 $0.050 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.038 $0.038 $0.037 $0.037 $0.036 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.031 $0.031 $0.030 $0.030 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.024 $0.024 $0.023 $0.023 $0.023 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.017 $0.017 $0.017 $0.016 $0.016 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.031 $0.031 $0.031 $0.031 $0.031 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.013 $0.013 $0.013 $0.013 $0.013 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.045 $0.044 $0.044 $0.044 $0.044 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.097 $0.096 $0.095 $0.094 $0.093 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.083 $0.082 $0.081 $0.081 $0.080 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.076 $0.075 $0.074 $0.074 $0.073 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.069 $0.068 $0.067 $0.067 $0.066 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.062 $0.061 $0.060 $0.060 $0.060 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.102 0.101 0.100 0.099 0.098 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.088 0.087 0.086 0.086 0.085 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.081 0.080 0.079 0.079 0.078 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.074 0.073 0.072 0.072 0.071 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.067 0.066 0.065 0.065 0.065 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $60,416,346 $60,696,951 $60,977,555 $61,184,715 $61,391,874 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $51,990,875 $52,271,479 $52,552,084 $52,759,243 $52,966,402 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $47,778,139 $48,058,743 $48,339,348 $48,546,507 $48,753,667 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $43,565,403 $43,846,007 $44,126,612 $44,333,771 $44,540,931 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $39,352,667 $39,633,272 $39,913,876 $40,121,036 $40,328,195 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 60,416,346 362,778,682 666,544,039 971,638,975 1,277,769,708 1,533,648,703 1,585,206,196 1,636,763,689 1,688,321,182 1,739,878,676 1,791,436,169$100 M Grants, Bal. 5% 51,990,875 312,225,852 573,863,851 836,831,428 1,100,834,803 1,323,011,911 1,374,569,405 1,426,126,898 1,477,684,391 1,529,241,884 1,580,799,377$150 M Grants, Bal. 5% 47,778,139 286,949,437 527,523,757 769,427,655 1,012,367,350 1,217,693,516 1,269,251,009 1,320,808,502 1,372,365,995 1,423,923,488 1,475,480,982$200 M Grants, Bal. 5% 43,565,403 261,673,022 481,183,663 702,023,882 923,899,898 1,112,375,120 1,163,932,613 1,215,490,106 1,267,047,600 1,318,605,093 1,370,162,586$250 M Grants, Bal. 5% 39,352,667 236,396,607 434,843,569 634,620,109 835,432,446 1,007,056,724 1,058,614,217 1,110,171,711 1,161,729,204 1,213,286,697 1,264,844,190Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,075,629,834$100 M Grants, Bal. 5% $925,625,915$150 M Grants, Bal. 5% $850,623,956$200 M Grants, Bal. 5% $775,621,997$250 M Grants, Bal. 5% $700,620,03743/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine Line97 MW Barge-Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat Sales, 40% EfficiencyBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 0 0 0 0 0Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 0 0 0 0 0Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine 0 0 0 0 0 0 0 0 0 0 0Bethel Utilities Plant 0 0 0 0 0 0 0 0 0 0 0Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 0 0 0 0 0 0 0 0 0 0 0Purchased Power 0 0 0 0 0 0 0 0 0 0 02. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LineYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine 0 0 0 0 0 0 0 0 0 0 0Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $369,487,800 $369,487,800 $369,487,800 $369,487,800 $369,487,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $18,474,390 $18,474,390 $18,474,390 $18,474,390 $18,474,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $13,474,390 $13,474,390 $13,474,390 $13,474,390 $13,474,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,974,390 $10,974,390 $10,974,390 $10,974,390 $10,974,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,474,390 $8,474,390 $8,474,390 $8,474,390 $8,474,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,974,390 $5,974,390 $5,974,390 $5,974,390 $5,974,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $387,962,190 $387,962,190 $387,962,190 $387,962,190 $387,962,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $282,962,190 $282,962,190 $282,962,190 $282,962,190 $282,962,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $230,462,190 $230,462,190 $230,462,190 $230,462,190 $230,462,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $177,962,190 $177,962,190 $177,962,190 $177,962,190 $177,962,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $125,462,190 $125,462,190 $125,462,190 $125,462,190 $125,462,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LineYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $31,131,090 $31,131,090 $31,131,090 $31,131,090 $31,131,090 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $22,705,618 $22,705,618 $22,705,618 $22,705,618 $22,705,618 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,492,882 $18,492,882 $18,492,882 $18,492,882 $18,492,882 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,280,147 $14,280,147 $14,280,147 $14,280,147 $14,280,147 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $10,067,411 $10,067,411 $10,067,411 $10,067,411 $10,067,411 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 236,636 239,863 243,091 245,473 247,856 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine 0 0 0 0 0 0 0 0 0 0 0Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $13,014,966 $13,192,477 $13,369,987 $13,501,037 $13,632,086 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 $4,707,679 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $398,122 $403,552 $408,982 $412,991 $416,999 $136,099 $136,099 $136,099 $136,099 $136,099 $136,099 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $16,553,803 $16,758,208 $16,962,612 $17,113,516 $17,264,420 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270 $5,498,270O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,866,985 $7,869,372 $7,871,759 $7,873,521 $7,875,283 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,07833/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LinePCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.053 $0.052 $0.051 $0.050 $0.050 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.038 $0.038 $0.037 $0.037 $0.036 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.031 $0.031 $0.030 $0.030 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.024 $0.024 $0.023 $0.023 $0.023 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.017 $0.017 $0.017 $0.016 $0.016 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.028 $0.028 $0.028 $0.028 $0.028 $0.056 $0.056 $0.056 $0.056 $0.056 $0.056 O&M $/kWh $0.013 $0.013 $0.013 $0.013 $0.013 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.041 $0.041 $0.041 $0.041 $0.040 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 BreakEven Cost $/kWh5% $0.094 $0.093 $0.092 $0.091 $0.090 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $100 M Grants, Bal. 5% $0.080 $0.079 $0.078 $0.077 $0.077 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $150 M Grants, Bal. 5% $0.073 $0.072 $0.071 $0.071 $0.070 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $200 M Grants, Bal. 5% $0.066 $0.065 $0.064 $0.064 $0.063 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 $250 M Grants, Bal. 5% $0.058 $0.058 $0.057 $0.057 $0.056 $0.100 $0.100 $0.100 $0.100 $0.100 $0.100 Wholesale Cost$/kWh5% 0.099 0.098 0.097 0.096 0.095 0.105 0.105 0.105 0.105 0.105 0.105$100 M Grants, Bal. 5% 0.085 0.084 0.083 0.082 0.082 0.105 0.105 0.105 0.105 0.105 0.105$150 M Grants, Bal. 5% 0.078 0.077 0.076 0.076 0.075 0.105 0.105 0.105 0.105 0.105 0.105$200 M Grants, Bal. 5% 0.071 0.070 0.069 0.069 0.068 0.105 0.105 0.105 0.105 0.105 0.105$250 M Grants, Bal. 5% 0.063 0.063 0.062 0.062 0.061 0.105 0.105 0.105 0.105 0.105 0.105Annual WholeSale Cost of Power5% $58,504,087 $58,758,610 $59,013,133 $59,201,038 $59,388,943 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$100 M Grants, Bal. 5% $50,078,615 $50,333,138 $50,587,662 $50,775,566 $50,963,471 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$150 M Grants, Bal. 5% $45,865,879 $46,120,403 $46,374,926 $46,562,831 $46,750,735 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$200 M Grants, Bal. 5% $41,653,143 $41,907,667 $42,162,190 $42,350,095 $42,537,999 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499$250 M Grants, Bal. 5% $37,440,408 $37,694,931 $37,949,454 $38,137,359 $38,325,264 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499 $10,311,499Accumulated WholeSale Cost of Power5% 58,504,087 351,279,043 645,326,617 940,580,188 1,236,773,282 1,484,640,552 1,536,198,045 1,587,755,538 1,639,313,032 1,690,870,525 1,742,428,018$100 M Grants, Bal. 5% 50,078,615 300,726,214 552,646,428 805,772,641 1,059,838,378 1,274,003,761 1,325,561,254 1,377,118,747 1,428,676,240 1,480,233,733 1,531,791,227$150 M Grants, Bal. 5% 45,865,879 275,449,799 506,306,334 738,368,868 971,370,925 1,168,685,365 1,220,242,858 1,271,800,351 1,323,357,845 1,374,915,338 1,426,472,831$200 M Grants, Bal. 5% 41,653,143 250,173,384 459,966,240 670,965,095 882,903,473 1,063,366,969 1,114,924,462 1,166,481,956 1,218,039,449 1,269,596,942 1,321,154,435$250 M Grants, Bal. 5% 37,440,408 224,896,969 413,626,146 603,561,322 794,436,021 958,048,573 1,009,606,067 1,061,163,560 1,112,721,053 1,164,278,546 1,215,836,040Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,041,584,688$100 M Grants, Bal. 5% $891,580,769$150 M Grants, Bal. 5% $816,578,810$200 M Grants, Bal. 5% $741,576,851$250 M Grants, Bal. 5% $666,574,89143/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat Sales97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, with 1 million Equivalent diesel gallons Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 0 0 0 0 0Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 0 0 0 0 0Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat SalesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050District Heating System $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $381,087,800 $381,087,800 $381,087,800 $381,087,800 $381,087,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $19,054,390 $19,054,390 $19,054,390 $19,054,390 $19,054,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $14,054,390 $14,054,390 $14,054,390 $14,054,390 $14,054,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $11,554,390 $11,554,390 $11,554,390 $11,554,390 $11,554,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $9,054,390 $9,054,390 $9,054,390 $9,054,390 $9,054,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $6,554,390 $6,554,390 $6,554,390 $6,554,390 $6,554,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $400,142,190 $400,142,190 $400,142,190 $400,142,190 $400,142,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $295,142,190 $295,142,190 $295,142,190 $295,142,190 $295,142,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $242,642,190 $242,642,190 $242,642,190 $242,642,190 $242,642,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $190,142,190 $190,142,190 $190,142,190 $190,142,190 $190,142,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $137,642,190 $137,642,190 $137,642,190 $137,642,190 $137,642,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat SalesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $32,108,445 $32,108,445 $32,108,445 $32,108,445 $32,108,445 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $23,682,973 $23,682,973 $23,682,973 $23,682,973 $23,682,973 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $19,470,237 $19,470,237 $19,470,237 $19,470,237 $19,470,237 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $15,257,501 $15,257,501 $15,257,501 $15,257,501 $15,257,501 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $11,044,765 $11,044,765 $11,044,765 $11,044,765 $11,044,765 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 305,157 309,320 313,482 316,554 319,627 67,253 67,253 67,253 67,253 67,253 67,253Additional Coal for WH 6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000Total Coal 311,157 315,320 319,482 322,554 325,627 73,253 73,253 73,253 73,253 73,253 73,253 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $17,113,661 $17,342,573 $17,571,484 $17,740,481 $17,909,478 $5,127,679 $5,127,679 $5,127,679 $5,127,679 $5,127,679 $5,127,679 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $509,974 $516,807 $523,640 $528,684 $533,728 $147,561 $147,561 $147,561 $147,561 $147,561 $147,561 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $20,764,351 $21,021,559 $21,278,767 $21,468,654 $21,658,540 $5,929,732 $5,929,732 $5,929,732 $5,929,732 $5,929,732 $5,929,732O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset ($1,000,000) ($1,000,000) ($1,000,000) ($1,000,000) ($1,000,000) ($1,000,000) ($1,000,000) $1,000,000 $1,000,000$1,000,000 $1,000,000Total O&M $6,866,985 $6,869,372 $6,871,759 $6,873,521 $6,875,283 $3,323,078 $3,323,078 $5,323,078 $5,323,078 $5,323,078 $5,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat SalesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.054 $0.054 $0.053 $0.052 $0.051 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.040 $0.039 $0.039 $0.038 $0.038 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.033 $0.032 $0.032 $0.032 $0.031 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.026 $0.025 $0.025 $0.025 $0.024 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.019 $0.018 $0.018 $0.018 $0.018 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.035 $0.035 $0.035 $0.035 $0.035 $0.060 $0.060 $0.060 $0.060 $0.060 $0.060 O&M $/kWh $0.012 $0.011 $0.011 $0.011 $0.011 $0.034 $0.034 $0.054 $0.054 $0.054 $0.054 Total $0.047 $0.046 $0.046 $0.046 $0.046 $0.094 $0.094 $0.115 $0.115 $0.115 $0.115 BreakEven Cost $/kWh5% $0.101 $0.100 $0.099 $0.098 $0.097 $0.094 $0.094 $0.115 $0.115 $0.115 $0.115 $100 M Grants, Bal. 5% $0.087 $0.086 $0.085 $0.084 $0.084 $0.094 $0.094 $0.115 $0.115 $0.115 $0.115 $150 M Grants, Bal. 5% $0.080 $0.079 $0.078 $0.078 $0.077 $0.094 $0.094 $0.115 $0.115 $0.115 $0.115 $200 M Grants, Bal. 5% $0.073 $0.072 $0.071 $0.071 $0.070 $0.094 $0.094 $0.115 $0.115 $0.115 $0.115 $250 M Grants, Bal. 5% $0.066 $0.065 $0.064 $0.064 $0.063 $0.094 $0.094 $0.115 $0.115 $0.115 $0.115 Wholesale Cost$/kWh5% 0.106 0.105 0.104 0.103 0.102 0.099 0.099 0.120 0.120 0.120 0.120$100 M Grants, Bal. 5% 0.092 0.091 0.090 0.089 0.089 0.099 0.099 0.120 0.120 0.120 0.120$150 M Grants, Bal. 5% 0.085 0.084 0.083 0.083 0.082 0.099 0.099 0.120 0.120 0.120 0.120$200 M Grants, Bal. 5% 0.078 0.077 0.076 0.076 0.075 0.099 0.099 0.120 0.120 0.120 0.120$250 M Grants, Bal. 5% 0.071 0.070 0.069 0.069 0.068 0.099 0.099 0.120 0.120 0.120 0.120Annual WholeSale Cost of Power5% $62,691,989 $62,999,316 $63,306,643 $63,533,531 $63,760,418 $9,742,960 $9,742,960 $11,742,960 $11,742,960 $11,742,960 $11,742,960$100 M Grants, Bal. 5% $54,266,517 $54,573,844 $54,881,171 $55,108,059 $55,334,947 $9,742,960 $9,742,960 $11,742,960 $11,742,960 $11,742,960 $11,742,960$150 M Grants, Bal. 5% $50,053,781 $50,361,108 $50,668,435 $50,895,323 $51,122,211 $9,742,960 $9,742,960 $11,742,960 $11,742,960 $11,742,960 $11,742,960$200 M Grants, Bal. 5% $45,841,045 $46,148,373 $46,455,700 $46,682,587 $46,909,475 $9,742,960 $9,742,960 $11,742,960 $11,742,960 $11,742,960 $11,742,960$250 M Grants, Bal. 5% $41,628,310 $41,935,637 $42,242,964 $42,469,851 $42,696,739 $9,742,960 $9,742,960 $11,742,960 $11,742,960 $11,742,960 $11,742,960Accumulated WholeSale Cost of Power5% 62,691,989 376,459,260 691,763,166 1,008,523,268 1,326,417,809 1,591,202,442 1,639,917,244 1,690,632,046 1,749,346,847 1,808,061,649 1,866,776,451$100 M Grants, Bal. 5% 54,266,517 325,906,430 599,082,978 873,715,721 1,149,482,904 1,380,565,651 1,429,280,452 1,479,995,254 1,538,710,056 1,597,424,858 1,656,139,660$150 M Grants, Bal. 5% 50,053,781 300,630,015 552,742,883 806,311,948 1,061,015,451 1,275,247,255 1,323,962,057 1,374,676,859 1,433,391,660 1,492,106,462 1,550,821,264$200 M Grants, Bal. 5% 45,841,045 275,353,600 506,402,789 738,908,175 972,547,999 1,169,928,859 1,218,643,661 1,269,358,463 1,328,073,265 1,386,788,066 1,445,502,868$250 M Grants, Bal. 5% 41,628,310 250,077,185 460,062,695 671,504,402 884,080,547 1,064,610,464 1,113,325,265 1,164,040,067 1,222,754,869 1,281,469,671 1,340,184,472Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,116,144,516$100 M Grants, Bal. 5% $966,140,597$150 M Grants, Bal. 5% $891,138,638$200 M Grants, Bal. 5% $816,136,679$250 M Grants, Bal. 5% $741,134,71943/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat Sales97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, with 2 million Equivalent diesel gallons Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 0 0 0 0 0Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 0 0 0 0 0Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat SalesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $381,087,800 $381,087,800 $381,087,800 $381,087,800 $381,087,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $19,054,390 $19,054,390 $19,054,390 $19,054,390 $19,054,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $14,054,390 $14,054,390 $14,054,390 $14,054,390 $14,054,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $11,554,390 $11,554,390 $11,554,390 $11,554,390 $11,554,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $9,054,390 $9,054,390 $9,054,390 $9,054,390 $9,054,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $6,554,390 $6,554,390 $6,554,390 $6,554,390 $6,554,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $400,142,190 $400,142,190 $400,142,190 $400,142,190 $400,142,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $295,142,190 $295,142,190 $295,142,190 $295,142,190 $295,142,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $242,642,190 $242,642,190 $242,642,190 $242,642,190 $242,642,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $190,142,190 $190,142,190 $190,142,190 $190,142,190 $190,142,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $137,642,190 $137,642,190 $137,642,190 $137,642,190 $137,642,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat SalesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $32,108,445 $32,108,445 $32,108,445 $32,108,445 $32,108,445 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $23,682,973 $23,682,973 $23,682,973 $23,682,973 $23,682,973 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $19,470,237 $19,470,237 $19,470,237 $19,470,237 $19,470,237 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $15,257,501 $15,257,501 $15,257,501 $15,257,501 $15,257,501 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $11,044,765 $11,044,765 $11,044,765 $11,044,765 $11,044,765 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 305,157 309,320 313,482 316,554 319,627 67,253 67,253 67,253 67,253 67,253 67,253Additional Coal for WH 12,000 12,000 12,000 12,000 12,000 12,000 12,000 12,000 12,000 12,000 12,000Total Coal 317,157 321,320 325,482 328,554 331,627 79,253 79,253 79,253 79,253 79,253 79,253 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $17,443,661 $17,672,573 $17,901,484 $18,070,481 $18,239,478 $5,547,679 $5,547,679 $5,547,679 $5,547,679 $5,547,679 $5,547,679 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $518,980 $525,813 $532,645 $537,690 $542,734 $159,022 $159,022 $159,022 $159,022 $159,022 $159,022 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $21,103,356 $21,360,564 $21,617,772 $21,807,659 $21,997,546 $6,361,194 $6,361,194 $6,361,194 $6,361,194 $6,361,194 $6,361,194O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset ($2,000,000) ($2,000,000) ($2,000,000) ($2,000,000) ($2,000,000) ($2,000,000) ($2,000,000) ($2,000,000) ($2,000,000) ($2,000,000) ($2,000,000)Total O&M $5,866,985 $5,869,372 $5,871,759 $5,873,521 $5,875,283 $2,323,078 $2,323,078 $2,323,078 $2,323,078 $2,323,078 $2,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat SalesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.054 $0.054 $0.053 $0.052 $0.051 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.040 $0.039 $0.039 $0.038 $0.038 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.033 $0.032 $0.032 $0.032 $0.031 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.026 $0.025 $0.025 $0.025 $0.024 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.019 $0.018 $0.018 $0.018 $0.018 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.036 $0.036 $0.035 $0.035 $0.035 $0.065 $0.065 $0.065 $0.065 $0.065 $0.065 O&M $/kWh $0.010 $0.010 $0.010 $0.010 $0.009 $0.024 $0.024 $0.024 $0.024 $0.024 $0.024 Total $0.046 $0.045 $0.045 $0.045 $0.045 $0.089 $0.089 $0.089 $0.089 $0.089 $0.089 BreakEven Cost $/kWh5% $0.100 $0.099 $0.098 $0.097 $0.096 $0.089 $0.089 $0.089 $0.089 $0.089 $0.089 $100 M Grants, Bal. 5% $0.086 $0.085 $0.084 $0.083 $0.083 $0.089 $0.089 $0.089 $0.089 $0.089 $0.089 $150 M Grants, Bal. 5% $0.079 $0.078 $0.077 $0.076 $0.076 $0.089 $0.089 $0.089 $0.089 $0.089 $0.089 $200 M Grants, Bal. 5% $0.072 $0.071 $0.070 $0.070 $0.069 $0.089 $0.089 $0.089 $0.089 $0.089 $0.089 $250 M Grants, Bal. 5% $0.064 $0.064 $0.063 $0.063 $0.062 $0.089 $0.089 $0.089 $0.089 $0.089 $0.089 Wholesale Cost$/kWh5% 0.105 0.104 0.103 0.102 0.101 0.094 0.094 0.094 0.094 0.094 0.094$100 M Grants, Bal. 5% 0.091 0.090 0.089 0.088 0.088 0.094 0.094 0.094 0.094 0.094 0.094$150 M Grants, Bal. 5% 0.084 0.083 0.082 0.081 0.081 0.094 0.094 0.094 0.094 0.094 0.094$200 M Grants, Bal. 5% 0.077 0.076 0.075 0.075 0.074 0.094 0.094 0.094 0.094 0.094 0.094$250 M Grants, Bal. 5% 0.069 0.069 0.068 0.068 0.067 0.094 0.094 0.094 0.094 0.094 0.094Annual WholeSale Cost of Power5% $62,030,994 $62,338,321 $62,645,649 $62,872,536 $63,099,424 $9,174,422 $9,174,422 $9,174,422 $9,174,422 $9,174,422 $9,174,422$100 M Grants, Bal. 5% $53,605,523 $53,912,850 $54,220,177 $54,447,065 $54,673,952 $9,174,422 $9,174,422 $9,174,422 $9,174,422 $9,174,422 $9,174,422$150 M Grants, Bal. 5% $49,392,787 $49,700,114 $50,007,441 $50,234,329 $50,461,216 $9,174,422 $9,174,422 $9,174,422 $9,174,422 $9,174,422$9,174,422$200 M Grants, Bal. 5% $45,180,051 $45,487,378 $45,794,705 $46,021,593 $46,248,481 $9,174,422 $9,174,422 $9,174,422 $9,174,422 $9,174,422$9,174,422$250 M Grants, Bal. 5% $40,967,315 $41,274,642 $41,581,969 $41,808,857 $42,035,745 $9,174,422 $9,174,422 $9,174,422 $9,174,422 $9,174,422$9,174,422Accumulated WholeSale Cost of Power5% 62,030,994 372,493,293 684,492,228 997,947,358 1,312,536,927 1,574,109,044 1,619,981,155 1,665,853,265 1,711,725,375 1,757,597,486 1,803,469,596$100 M Grants, Bal. 5% 53,605,523 321,940,463 591,812,039 863,139,811 1,135,602,022 1,363,472,253 1,409,344,363 1,455,216,474 1,501,088,584 1,546,960,694 1,592,832,805$150 M Grants, Bal. 5% 49,392,787 296,664,048 545,471,945 795,736,038 1,047,134,570 1,258,153,857 1,304,025,968 1,349,898,078 1,395,770,188 1,441,642,299 1,487,514,409$200 M Grants, Bal. 5% 45,180,051 271,387,633 499,131,851 728,332,265 958,667,117 1,152,835,462 1,198,707,572 1,244,579,682 1,290,451,793 1,336,323,903 1,382,196,013$250 M Grants, Bal. 5% 40,967,315 246,111,219 452,791,757 660,928,492 870,199,665 1,047,517,066 1,093,389,176 1,139,261,287 1,185,133,397 1,231,005,507 1,276,877,618Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,77043/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat Sales97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, with 3 million Equivalent diesel gallons Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 0 0 0 0 0Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 0 0 0 0 0Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 206013/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat SalesPlant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $381,087,800 $381,087,800 $381,087,800 $381,087,800 $381,087,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $19,054,390 $19,054,390 $19,054,390 $19,054,390 $19,054,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $14,054,390 $14,054,390 $14,054,390 $14,054,390 $14,054,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $11,554,390 $11,554,390 $11,554,390 $11,554,390 $11,554,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $9,054,390 $9,054,390 $9,054,390 $9,054,390 $9,054,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $6,554,390 $6,554,390 $6,554,390 $6,554,390 $6,554,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $400,142,190 $400,142,190 $400,142,190 $400,142,190 $400,142,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $295,142,190 $295,142,190 $295,142,190 $295,142,190 $295,142,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $242,642,190 $242,642,190 $242,642,190 $242,642,190 $242,642,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $190,142,190 $190,142,190 $190,142,190 $190,142,190 $190,142,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $137,642,190 $137,642,190 $137,642,190 $137,642,190 $137,642,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat SalesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $32,108,445 $32,108,445 $32,108,445 $32,108,445 $32,108,445 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $23,682,973 $23,682,973 $23,682,973 $23,682,973 $23,682,973 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $19,470,237 $19,470,237 $19,470,237 $19,470,237 $19,470,237 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $15,257,501 $15,257,501 $15,257,501 $15,257,501 $15,257,501 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $11,044,765 $11,044,765 $11,044,765 $11,044,765 $11,044,765 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 305,157 309,320 313,482 316,554 319,627 67,253 67,253 67,253 67,253 67,253 67,253Additional Coal for WH 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000 18,000Total Coal 323,157 327,320 331,482 334,554 337,627 85,253 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000000Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $17,773,661 $18,002,573 $18,231,484 $18,400,481 $18,569,478 $5,967,679 $0 $0 $0 $0 $0 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $527,986 $534,818 $541,651 $546,695 $551,740 $170,484 $7,627 $7,627 $7,627 $7,627 $7,627 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $21,442,362 $21,699,570 $21,956,778 $22,146,665 $22,336,552 $6,792,655 $662,120 $662,120 $662,120 $662,120 $662,120O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset ($3,000,000) ($3,000,000) ($3,000,000) ($3,000,000) ($3,000,000) ($3,000,000) ($3,000,000) ($3,000,000) ($3,000,000) ($3,000,000) ($3,000,000)Total O&M $4,866,985 $4,869,372 $4,871,759 $4,873,521 $4,875,283 $1,323,078 $1,323,078 $1,323,078 $1,323,078 $1,323,078 $1,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine -60 MW Average Demand, 20 Year Life, with Waste Heat SalesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.054 $0.054 $0.053 $0.052 $0.051 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.040 $0.039 $0.039 $0.038 $0.038 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.033 $0.032 $0.032 $0.032 $0.031 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.026 $0.025 $0.025 $0.025 $0.024 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.019 $0.018 $0.018 $0.018 $0.018 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.036 $0.036 $0.036 $0.036 $0.036 $0.069 $0.007 $0.007 $0.007 $0.007 $0.007 O&M $/kWh $0.008 $0.008 $0.008 $0.008 $0.008 $0.013 $0.013 $0.013 $0.013 $0.013 $0.013 Total $0.045 $0.044 $0.044 $0.044 $0.044 $0.083 $0.020 $0.020 $0.020 $0.020 $0.020 BreakEven Cost $/kWh5% $0.099 $0.098 $0.097 $0.096 $0.095 $0.083 $0.020 $0.020 $0.020 $0.020 $0.020 $100 M Grants, Bal. 5% $0.085 $0.084 $0.083 $0.082 $0.082 $0.083 $0.020 $0.020 $0.020 $0.020 $0.020 $150 M Grants, Bal. 5% $0.078 $0.077 $0.076 $0.075 $0.075 $0.083 $0.020 $0.020 $0.020 $0.020 $0.020 $200 M Grants, Bal. 5% $0.070 $0.070 $0.069 $0.069 $0.068 $0.083 $0.020 $0.020 $0.020 $0.020 $0.020 $250 M Grants, Bal. 5% $0.063 $0.063 $0.062 $0.062 $0.061 $0.083 $0.020 $0.020 $0.020 $0.020 $0.020 Wholesale Cost$/kWh5% 0.104 0.103 0.102 0.101 0.100 0.088 0.025 0.025 0.025 0.025 0.025$100 M Grants, Bal. 5% 0.090 0.089 0.088 0.087 0.087 0.088 0.025 0.025 0.025 0.025 0.025$150 M Grants, Bal. 5% 0.083 0.082 0.081 0.080 0.080 0.088 0.025 0.025 0.025 0.025 0.025$200 M Grants, Bal. 5% 0.075 0.075 0.074 0.074 0.073 0.088 0.025 0.025 0.025 0.025 0.025$250 M Grants, Bal. 5% 0.068 0.068 0.067 0.067 0.066 0.088 0.025 0.025 0.025 0.025 0.025Annual WholeSale Cost of Power5% $61,370,000 $61,677,327 $61,984,654 $62,211,542 $62,438,430 $8,605,884 $2,475,349 $2,475,349 $2,475,349 $2,475,349 $2,475,349$100 M Grants, Bal. 5% $52,944,528 $53,251,855 $53,559,182 $53,786,070 $54,012,958 $8,605,884 $2,475,349 $2,475,349 $2,475,349 $2,475,349 $2,475,349$150 M Grants, Bal. 5% $48,731,793 $49,039,120 $49,346,447 $49,573,334 $49,800,222 $8,605,884 $2,475,349 $2,475,349 $2,475,349 $2,475,349$2,475,349$200 M Grants, Bal. 5% $44,519,057 $44,826,384 $45,133,711 $45,360,599 $45,587,486 $8,605,884 $2,475,349 $2,475,349 $2,475,349 $2,475,349$2,475,349$250 M Grants, Bal. 5% $40,306,321 $40,613,648 $40,920,975 $41,147,863 $41,374,750 $8,605,884 $2,475,349 $2,475,349 $2,475,349 $2,475,349$2,475,349Accumulated WholeSale Cost of Power5% 61,370,000 368,527,327 677,221,290 987,371,448 1,298,656,045 1,557,015,647 1,593,914,531 1,606,291,273 1,618,668,016 1,631,044,759 1,643,421,501$100 M Grants, Bal. 5% 52,944,528 317,974,497 584,541,101 852,563,901 1,121,721,140 1,346,378,856 1,383,277,739 1,395,654,482 1,408,031,225 1,420,407,967 1,432,784,710$150 M Grants, Bal. 5% 48,731,793 292,698,082 538,201,007 785,160,128 1,033,253,688 1,241,060,460 1,277,959,343 1,290,336,086 1,302,712,829 1,315,089,572 1,327,466,314$200 M Grants, Bal. 5% 44,519,057 267,421,667 491,860,913 717,756,355 944,786,235 1,135,742,064 1,172,640,948 1,185,017,690 1,197,394,433 1,209,771,176 1,222,147,919$250 M Grants, Bal. 5% 40,306,321 242,145,252 445,520,819 650,352,582 856,318,783 1,030,423,668 1,067,322,552 1,079,699,295 1,092,076,038 1,104,452,780 1,116,829,523Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,77043/22/2004
Donlin Creek Mine - 60 MW Average Load, 50 Year Mine Life97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 70,000 70,000 70,000 70,000 70,000 70,000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 15,559 16,715 18,007 19,298 20,590 21,881Line Loss 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000In Plant Use 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500Total KW 94,361 96,125 97,890 99,029 100,169 101,409 102,648 103,940 105,231 106,523 107,814KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 17,032,550 18,044,309 18,232,998 18,421,686 18,610,375 18,799,063Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 97,614,444 113,219,524 121,047,966 128,876,408 136,704,850 144,533,292Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 640,246,993 656,863,833 664,880,963 672,898,094 680,915,224 688,932,355T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 749,746,993 766,363,833 774,380,963 782,398,094 790,415,224 798,432,355 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK000000000 0 0 Mine000000000 0 0Bethel Utilities Plant000000000 0 0Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 731,003,318 747,204,737 755,021,439 762,838,141 770,654,844 778,471,546Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 18,743,675 19,159,096 19,359,524 19,559,952 19,760,381 19,960,809CCK000000000 0 0 Mine 000000000 0 0Purchased Power000000000 0 02. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load, 50 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK000000000 0 0 Mine000000000 0 0Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $369,487,800 $369,487,800 $369,487,800 $369,487,800 $369,487,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $18,474,390 $18,474,390 $18,474,390 $18,474,390 $18,474,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $13,474,390 $13,474,390 $13,474,390 $13,474,390 $13,474,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,974,390 $10,974,390 $10,974,390 $10,974,390 $10,974,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,474,390 $8,474,390 $8,474,390 $8,474,390 $8,474,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,974,390 $5,974,390 $5,974,390 $5,974,390 $5,974,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $387,962,190 $387,962,190 $387,962,190 $387,962,190 $387,962,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $282,962,190 $282,962,190 $282,962,190 $282,962,190 $282,962,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $230,462,190 $230,462,190 $230,462,190 $230,462,190 $230,462,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $177,962,190 $177,962,190 $177,962,190 $177,962,190 $177,962,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $125,462,190 $125,462,190 $125,462,190 $125,462,190 $125,462,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load, 50 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $31,131,090 $31,131,090 $31,131,090 $31,131,090 $31,131,090 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $22,705,618 $22,705,618 $22,705,618 $22,705,618 $22,705,618 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,492,882 $18,492,882 $18,492,882 $18,492,882 $18,492,882 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,280,147 $14,280,147 $14,280,147 $14,280,147 $14,280,147 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $10,067,411 $10,067,411 $10,067,411 $10,067,411 $10,067,411 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 305,157 309,320 313,482 316,554 319,627 326,871 334,116 337,611 341,106 344,602 348,097 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 1,404,746 1,435,879 1,450,901 1,465,922 1,480,943 1,495,964CCKMine000000000 0 0Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $16,783,661 $17,012,573 $17,241,484 $17,410,481 $17,579,478 $22,880,998 $23,388,116 $23,632,785 $23,877,454 $24,122,123 $24,366,792 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $1,685,695 $1,723,055 $1,741,081 $1,759,106 $1,777,131 $1,795,157CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $500,969 $507,801 $514,634 $519,678 $524,723 $670,420 $685,278 $692,447 $699,616 $706,785 $713,954 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $20,425,345 $20,682,553 $20,939,761 $21,129,648 $21,319,535 $25,612,113 $26,171,450 $26,441,313 $26,711,176 $26,981,040 $27,250,903O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $187,437 $191,591 $193,595 $195,600 $197,604 $199,608PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,866,985 $7,869,372 $7,871,759 $7,873,521 $7,875,283 $7,879,437 $7,883,591 $7,885,595 $7,887,600 $7,889,604 $7,891,60833/22/2004
Donlin Creek Mine - 60 MW Average Load, 50 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Power CostsCapital Cost $/kWh5% $0.053 $0.052 $0.051 $0.050 $0.050 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.038 $0.038 $0.037 $0.037 $0.036 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.031 $0.031 $0.030 $0.030 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.024 $0.024 $0.023 $0.023 $0.023 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.017 $0.017 $0.017 $0.016 $0.016 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.035 $0.034 $0.034 $0.034 $0.034 $0.040 $0.040 $0.040 $0.040 $0.040 $0.040 O&M $/kWh $0.013 $0.013 $0.013 $0.013 $0.013 $0.012 $0.012 $0.012 $0.012 $0.012 $0.011 Total $0.048 $0.048 $0.047 $0.047 $0.047 $0.052 $0.052 $0.052 $0.051 $0.051 $0.051 BreakEven Cost $/kWh5% $0.101 $0.099 $0.098 $0.098 $0.097 $0.052 $0.052 $0.052 $0.051 $0.051 $0.051 $100 M Grants, Bal. 5% $0.086 $0.085 $0.085 $0.084 $0.083 $0.052 $0.052 $0.052 $0.051 $0.051 $0.051 $150 M Grants, Bal. 5% $0.079 $0.078 $0.078 $0.077 $0.076 $0.052 $0.052 $0.052 $0.051 $0.051 $0.051 $200 M Grants, Bal. 5% $0.072 $0.071 $0.071 $0.070 $0.070 $0.052 $0.052 $0.052 $0.051 $0.051 $0.051 $250 M Grants, Bal. 5% $0.065 $0.064 $0.064 $0.063 $0.063 $0.052 $0.052 $0.052 $0.051 $0.051 $0.051 Wholesale Cost$/kWh5% 0.106 0.104 0.103 0.103 0.102 0.057 0.057 0.057 0.056 0.056 0.056$100 M Grants, Bal. 5% 0.091 0.090 0.090 0.089 0.088 0.057 0.057 0.057 0.056 0.056 0.056$150 M Grants, Bal. 5% 0.084 0.083 0.083 0.082 0.081 0.057 0.057 0.057 0.056 0.056 0.056$200 M Grants, Bal. 5% 0.077 0.076 0.076 0.075 0.075 0.057 0.057 0.057 0.056 0.056 0.056$250 M Grants, Bal. 5% 0.070 0.069 0.069 0.068 0.068 0.057 0.057 0.057 0.056 0.056 0.056Annual WholeSale Cost of Power5% $62,375,628 $62,682,955 $62,990,283 $63,217,170 $63,444,058 $36,692,784 $37,339,360 $37,651,313 $37,963,266 $38,275,219 $38,587,173$100 M Grants, Bal. 5% $53,950,157 $54,257,484 $54,564,811 $54,791,699 $55,018,586 $36,692,784 $37,339,360 $37,651,313 $37,963,266 $38,275,219 $38,587,173$150 M Grants, Bal. 5% $49,737,421 $50,044,748 $50,352,075 $50,578,963 $50,805,850 $36,692,784 $37,339,360 $37,651,313 $37,963,266 $38,275,219 $38,587,173$200 M Grants, Bal. 5% $45,524,685 $45,832,012 $46,139,339 $46,366,227 $46,593,115 $36,692,784 $37,339,360 $37,651,313 $37,963,266 $38,275,219 $38,587,173$250 M Grants, Bal. 5% $41,311,949 $41,619,276 $41,926,603 $42,153,491 $42,380,379 $36,692,784 $37,339,360 $37,651,313 $37,963,266 $38,275,219 $38,587,173Accumulated WholeSale Cost of Power5% 62,375,628 374,561,098 688,283,202 1,003,461,502 1,319,774,241 1,610,243,258 1,794,353,755 1,981,362,507 2,169,931,024 2,360,059,309 2,551,747,359$100 M Grants, Bal. 5% 53,950,157 324,008,268 595,603,014 868,653,956 1,142,839,337 1,399,606,466 1,583,716,964 1,770,725,715 1,959,294,233 2,149,422,517 2,341,110,568$150 M Grants, Bal. 5% 49,737,421 298,731,853 549,262,920 801,250,183 1,054,371,884 1,294,288,071 1,478,398,568 1,665,407,320 1,853,975,837 2,044,104,122 2,235,792,172$200 M Grants, Bal. 5% 45,524,685 273,455,438 502,922,826 733,846,409 965,904,432 1,188,969,675 1,373,080,172 1,560,088,924 1,748,657,442 1,938,785,726 2,130,473,776$250 M Grants, Bal. 5% 41,311,949 248,179,023 456,582,731 666,442,636 877,436,979 1,083,651,279 1,267,761,777 1,454,770,528 1,643,339,046 1,833,467,330 2,025,155,381Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 3,201,235 3,284,319 3,324,405 3,364,490 3,404,576 3,444,662Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 91,454,331 110,744,825 130,490,826 150,477,340 170,704,369 191,171,91143/22/2004
Donlin Creek Mine - 60 MW Average Load 1st 20 Years, 30 MW Thereafter 97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 35,000 35,000 35,000 35,000 35,000 35,000Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 15,559 16,715 18,007 19,298 20,590 21,881Line Loss 5,000 5,000 5,000 5,000 5,000 1,500 1,500 1,500 1,500 1,500 1,500In Plant Use 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500Total KW 94,361 96,125 97,890 99,029 100,169 62,909 64,148 65,440 66,731 68,023 69,314KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 262,800,000 262,800,000 262,800,000 262,800,000 262,800,000 262,800,000Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 17,032,550 18,044,309 18,232,998 18,421,686 18,610,375 18,799,063Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 97,614,444 113,219,524 121,047,966 128,876,408 136,704,850 144,533,292Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 377,446,993 394,063,833 402,080,963 410,098,094 418,115,224 426,132,355T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 13,140,000 13,140,000 13,140,000 13,140,000 13,140,000 13,140,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 456,286,993 472,903,833 480,920,963 488,938,094 496,955,224 504,972,355 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK0000000000 0 Mine0000000000 0Bethel Utilities Plant0000000000 0Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 444,879,818 461,081,237 468,897,939 476,714,641 484,531,344 492,348,046Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 11,407,175 11,822,596 12,023,024 12,223,452 12,423,881 12,624,309CCK0000000000 0 Mine 0000000000 0Purchased Power0000000000 02. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $013/22/2004
Donlin Creek Mine - 60 MW Average Load 1st 20 Years, 30 MW Thereafter Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK0000000000 0 Mine0000000000 0Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $369,487,800 $369,487,800 $369,487,800 $369,487,800 $369,487,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $18,474,390 $18,474,390 $18,474,390 $18,474,390 $18,474,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $13,474,390 $13,474,390 $13,474,390 $13,474,390 $13,474,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,974,390 $10,974,390 $10,974,390 $10,974,390 $10,974,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,474,390 $8,474,390 $8,474,390 $8,474,390 $8,474,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,974,390 $5,974,390 $5,974,390 $5,974,390 $5,974,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $387,962,190 $387,962,190 $387,962,190 $387,962,190 $387,962,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $282,962,190 $282,962,190 $282,962,190 $282,962,190 $282,962,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $230,462,190 $230,462,190 $230,462,190 $230,462,190 $230,462,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $177,962,190 $177,962,190 $177,962,190 $177,962,190 $177,962,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $125,462,190 $125,462,190 $125,462,190 $125,462,190 $125,462,190 $0 $0 $0 $0 $0 $023/22/2004
Donlin Creek Mine - 60 MW Average Load 1st 20 Years, 30 MW Thereafter Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $31,131,090 $31,131,090 $31,131,090 $31,131,090 $31,131,090 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $22,705,618 $22,705,618 $22,705,618 $22,705,618 $22,705,618 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,492,882 $18,492,882 $18,492,882 $18,492,882 $18,492,882 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,280,147 $14,280,147 $14,280,147 $14,280,147 $14,280,147 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $10,067,411 $10,067,411 $10,067,411 $10,067,411 $10,067,411 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 305,157 309,320 313,482 316,554 319,627 198,930 206,175 209,670 213,165 216,660 220,156 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 854,911 886,045 901,066 916,087 931,108 946,130CCKMine0000000000 0Coal $/Ton $55.00 $55.00 $55.00 $55.00 $55.00 $70.00 $70.00 $70.00 $70.00 $70.00 $70.00 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $16,783,661 $17,012,573 $17,241,484 $17,410,481 $17,579,478 $13,925,100 $14,432,218 $14,676,887 $14,921,556 $15,166,225 $15,410,894 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $1,025,894 $1,063,254 $1,081,279 $1,099,305 $1,117,330 $1,135,355CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $500,969 $507,801 $514,634 $519,678 $524,723 $408,009 $422,868 $430,037 $437,206 $444,375 $451,544 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $20,425,345 $20,682,553 $20,939,761 $21,129,648 $21,319,535 $15,734,003 $16,293,340 $16,563,203 $16,833,066 $17,102,930 $17,372,793O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $114,072 $118,226 $120,230 $122,235 $124,239 $126,243PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 $400,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $033/22/2004
Donlin Creek Mine - 60 MW Average Load 1st 20 Years, 30 MW Thereafter Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Total O&M $7,868,995 $7,871,387 $7,873,779 $7,875,546 $7,877,313 $7,808,107 $7,812,266 $7,814,275 $7,816,285 $7,818,294 $7,820,303PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Power CostsCapital Cost $/kWh5% $0.053 $0.052 $0.051 $0.050 $0.050 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.038 $0.038 $0.037 $0.037 $0.036 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.031 $0.031 $0.030 $0.030 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.024 $0.024 $0.023 $0.023 $0.023 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.017 $0.017 $0.017 $0.016 $0.016 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.035 $0.034 $0.034 $0.034 $0.034 $0.042 $0.041 $0.041 $0.041 $0.041 $0.041 O&M $/kWh $0.013 $0.013 $0.013 $0.013 $0.013 $0.021 $0.020 $0.019 $0.019 $0.019 $0.018 Total $0.048 $0.048 $0.047 $0.047 $0.047 $0.062 $0.061 $0.061 $0.060 $0.060 $0.059 BreakEven Cost $/kWh5% $0.101 $0.099 $0.098 $0.098 $0.097 $0.062 $0.061 $0.061 $0.060 $0.060 $0.059 $100 M Grants, Bal. 5% $0.086 $0.085 $0.085 $0.084 $0.083 $0.062 $0.061 $0.061 $0.060 $0.060 $0.059 $150 M Grants, Bal. 5% $0.079 $0.078 $0.078 $0.077 $0.076 $0.062 $0.061 $0.061 $0.060 $0.060 $0.059 $200 M Grants, Bal. 5% $0.072 $0.071 $0.071 $0.070 $0.070 $0.062 $0.061 $0.061 $0.060 $0.060 $0.059 $250 M Grants, Bal. 5% $0.065 $0.064 $0.064 $0.063 $0.063 $0.062 $0.061 $0.061 $0.060 $0.060 $0.059 Wholesale Cost$/kWh5% 0.106 0.104 0.103 0.103 0.102 0.067 0.066 0.066 0.065 0.065 0.064$100 M Grants, Bal. 5% 0.091 0.090 0.090 0.089 0.088 0.067 0.066 0.066 0.065 0.065 0.064$150 M Grants, Bal. 5% 0.084 0.083 0.083 0.082 0.081 0.067 0.066 0.066 0.065 0.065 0.064$200 M Grants, Bal. 5% 0.077 0.076 0.076 0.075 0.075 0.067 0.066 0.066 0.065 0.065 0.064$250 M Grants, Bal. 5% 0.070 0.069 0.069 0.068 0.068 0.067 0.066 0.066 0.065 0.065 0.064Annual WholeSale Cost of Power5% $62,377,638 $62,684,970 $62,992,303 $63,219,195 $63,446,088 $25,429,345 $26,075,925 $26,387,883 $26,699,841 $27,011,800 $27,323,758$100 M Grants, Bal. 5% $53,952,167 $54,259,499 $54,566,831 $54,793,724 $55,020,616 $25,429,345 $26,075,925 $26,387,883 $26,699,841 $27,011,800 $27,323,758$150 M Grants, Bal. 5% $49,739,431 $50,046,763 $50,354,095 $50,580,988 $50,807,880 $25,429,345 $26,075,925 $26,387,883 $26,699,841 $27,011,800 $27,323,758$200 M Grants, Bal. 5% $45,526,695 $45,834,027 $46,141,359 $46,368,252 $46,595,145 $25,429,345 $26,075,925 $26,387,883 $26,699,841 $27,011,800 $27,323,758$250 M Grants, Bal. 5% $41,313,959 $41,621,291 $41,928,623 $42,155,516 $42,382,409 $25,429,345 $26,075,925 $26,387,883 $26,699,841 $27,011,800 $27,323,758Accumulated WholeSale Cost of Power5% 62,377,638 374,573,163 688,305,347 1,003,493,752 1,319,816,621 1,599,030,318 1,726,823,621 1,857,515,204 1,989,766,578 2,123,577,743 2,258,948,700$100 M Grants, Bal. 5% 53,952,167 324,020,333 595,625,159 868,686,206 1,142,881,717 1,388,393,527 1,516,186,830 1,646,878,413 1,779,129,787 1,912,940,952 2,048,311,908$150 M Grants, Bal. 5% 49,739,431 298,743,918 549,285,065 801,282,433 1,054,414,264 1,283,075,131 1,410,868,434 1,541,560,017 1,673,811,391 1,807,622,556 1,942,993,513$200 M Grants, Bal. 5% 45,526,695 273,467,503 502,944,971 733,878,659 965,946,812 1,177,756,735 1,305,550,039 1,436,241,621 1,568,492,995 1,702,304,160 1,837,675,117$250 M Grants, Bal. 5% 41,313,959 248,191,088 456,604,876 666,474,886 877,479,359 1,072,438,339 1,200,231,643 1,330,923,226 1,463,174,599 1,596,985,765 1,732,356,721Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 1,887,235 1,970,319 2,010,405 2,050,490 2,090,576 2,130,662Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 90,140,331 101,546,825 113,408,826 125,511,340 137,854,369 150,437,91143/22/2004
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine Life97 MW Barge Mounted Coal Plant Bethel +46 MW Combustion Turbine + 138 KV T-Line to mine, No Waste Heat Sales, Coal @ $57.25 /tonBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 0 0 0 0 0 0Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 7,500 7,500 7,500 7,500 7,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 94,361 96,125 97,890 99,029 100,169 20,753 20,836 20,836 20,836 20,836 20,836KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 0 0 0 0 0 0Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000In Plant Use 65,700,000 65,700,000 65,700,000 65,700,000 65,700,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000Total kWh Generated 699,941,628 709,488,100 719,034,571 726,082,362 733,130,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000 97,000Combustion Turbine Bethel 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000 46,000CCK00000000 000 Mine00000000 000Bethel Utilities Plant00000000 000Total Capacity in KWs 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000 143,000Generation KWHsCoal Plant 682,443,088 691,750,897 701,058,707 707,930,303 714,801,900 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400 121,202,400Combustion Turbine Bethel 17,498,541 17,737,202 17,975,864 18,152,059 18,328,254 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754 3,107,754CCK00000000 000 Mine 00000000 000Purchased Power00000000 0002. Capital Cost(1)Plant CostsCoal Plant $/kW $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940 $1,940Combustion Turbine $/kW Bethel $370 $370 $370 $370 $370 $370 $370 $370 $370 $370 $370CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Plant Costs $Coal Plant $188,180,000 $188,180,000 $188,180,000 $188,180,000 $188,180,000 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $17,020,000 $17,020,000 $17,020,000 $17,020,000 $17,020,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $205,200,000 $205,200,000 $205,200,000 $205,200,000 $205,200,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $11,600,000 $11,600,000 $11,600,000 $11,600,000 $11,600,000 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000 3,000,000CCK00000000 000 Mine00000000 000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $4,110,000 $4,110,000 $4,110,000 $4,110,000 $4,110,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $369,487,800 $369,487,800 $369,487,800 $369,487,800 $369,487,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $18,474,390 $18,474,390 $18,474,390 $18,474,390 $18,474,390 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $13,474,390 $13,474,390 $13,474,390 $13,474,390 $13,474,390 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $10,974,390 $10,974,390 $10,974,390 $10,974,390 $10,974,390 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,474,390 $8,474,390 $8,474,390 $8,474,390 $8,474,390 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $5,974,390 $5,974,390 $5,974,390 $5,974,390 $5,974,390 $0 $0 $0 $0 $0 $0Total Capital Cost5% $387,962,190 $387,962,190 $387,962,190 $387,962,190 $387,962,190 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $282,962,190 $282,962,190 $282,962,190 $282,962,190 $282,962,190 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $230,462,190 $230,462,190 $230,462,190 $230,462,190 $230,462,190 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $177,962,190 $177,962,190 $177,962,190 $177,962,190 $177,962,190 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $125,462,190 $125,462,190 $125,462,190 $125,462,190 $125,462,190 $0 $0 $0 $0 $0 $0
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060 3. ExpensesAnnual Debt Service5% $31,131,090 $31,131,090 $31,131,090 $31,131,090 $31,131,090 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $22,705,618 $22,705,618 $22,705,618 $22,705,618 $22,705,618 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,492,882 $18,492,882 $18,492,882 $18,492,882 $18,492,882 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,280,147 $14,280,147 $14,280,147 $14,280,147 $14,280,147 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $10,067,411 $10,067,411 $10,067,411 $10,067,411 $10,067,411 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons 305,157 309,320 313,482 316,554 319,627 67,253 67,253 67,253 67,253 67,253 67,253 #1 Fuel Oil GallonsBethel 1,311,429 1,329,316 1,347,202 1,360,407 1,373,612 232,911 232,911 232,911 232,911 232,911 232,911CCKMine00000000 000Coal $/Ton $68.75 $68.75 $68.75 $68.75 $68.75 $87.50 $87.50 $87.50 $87.50 $87.50 $87.50 #1 Fuel Oil $/GallonsBethel $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 $1.20CCKMineAnnual Fuel CostsCoal $20,979,577 $21,265,716 $21,551,856 $21,763,101 $21,974,347 $5,884,598 $5,884,598 $5,884,598 $5,884,598 $5,884,598 $5,884,598 #1 Fuel OilBethel $1,573,715 $1,595,179 $1,616,643 $1,632,488 $1,648,334 $279,493 $279,493 $279,493 $279,493 $279,493 $279,493CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $615,474 $623,869 $632,263 $638,461 $644,658 $168,217 $168,217 $168,217 $168,217 $168,217 $168,217 O&M Tug + Barges $1,567,000 $1,567,000 $1,567,000 $1,567,000 $1,567,000 $375,000 $375,000 $375,000 $375,000 $375,000 $375,000 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $24,735,766 $25,051,764 $25,367,761 $25,601,050 $25,834,339 $6,707,308 $6,707,308 $6,707,308 $6,707,308 $6,707,308 $6,707,308O&MCoal-PlantPersonnel 2,100,000 2,100,000 2,100,000 2,100,000 2,100,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000 1,400,000Equipment/Supplies 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 2,500,000Combustion Turbine $174,985 $177,372 $179,759 $181,521 $183,283 $31,078 $31,078 $31,078 $31,078 $31,078 $31,078PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $7,866,985 $7,869,372 $7,871,759 $7,873,521 $7,875,283 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078 $4,323,078PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Power CostsCapital Cost $/kWh5% $0.053 $0.052 $0.051 $0.050 $0.050 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.038 $0.038 $0.037 $0.037 $0.036 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.031 $0.031 $0.030 $0.030 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.024 $0.024 $0.023 $0.023 $0.023 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.017 $0.017 $0.017 $0.016 $0.016 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.042 $0.042 $0.042 $0.042 $0.041 $0.068 $0.068 $0.068 $0.068 $0.068 $0.068 O&M $/kWh $0.013 $0.013 $0.013 $0.013 $0.013 $0.044 $0.044 $0.044 $0.044 $0.044 $0.044 Total $0.055 $0.055 $0.055 $0.054 $0.054 $0.113 $0.113 $0.113 $0.113 $0.113 $0.113 BreakEven Cost $/kWh5% $0.108 $0.107 $0.106 $0.105 $0.104 $0.113 $0.113 $0.113 $0.113 $0.113 $0.113 $100 M Grants, Bal. 5% $0.094 $0.093 $0.092 $0.091 $0.090 $0.113 $0.113 $0.113 $0.113 $0.113 $0.113 $150 M Grants, Bal. 5% $0.087 $0.086 $0.085 $0.084 $0.084 $0.113 $0.113 $0.113 $0.113 $0.113 $0.113 $200 M Grants, Bal. 5% $0.079 $0.079 $0.078 $0.077 $0.077 $0.113 $0.113 $0.113 $0.113 $0.113 $0.113 $250 M Grants, Bal. 5% $0.072 $0.072 $0.071 $0.071 $0.070 $0.113 $0.113 $0.113 $0.113 $0.113 $0.113 Wholesale Cost$/kWh5% 0.113 0.112 0.111 0.110 0.109 0.118 0.118 0.118 0.118 0.118 0.118$100 M Grants, Bal. 5% 0.099 0.098 0.097 0.096 0.095 0.118 0.118 0.118 0.118 0.118 0.118$150 M Grants, Bal. 5% 0.092 0.091 0.090 0.089 0.089 0.118 0.118 0.118 0.118 0.118 0.118$200 M Grants, Bal. 5% 0.084 0.084 0.083 0.082 0.082 0.118 0.118 0.118 0.118 0.118 0.118$250 M Grants, Bal. 5% 0.077 0.077 0.076 0.076 0.075 0.118 0.118 0.118 0.118 0.118 0.118Annual WholeSale Cost of Power5% $66,686,049 $67,052,166 $67,418,283 $67,688,573 $67,958,862 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536$100 M Grants, Bal. 5% $58,260,578 $58,626,694 $58,992,811 $59,263,101 $59,533,391 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536$150 M Grants, Bal. 5% $54,047,842 $54,413,959 $54,780,075 $55,050,365 $55,320,655 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536$200 M Grants, Bal. 5% $49,835,106 $50,201,223 $50,567,339 $50,837,629 $51,107,919 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536$250 M Grants, Bal. 5% $45,622,370 $45,988,487 $46,354,604 $46,624,893 $46,895,183 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536 $11,520,536Accumulated WholeSale Cost of Power5% 66,686,049 400,482,413 736,109,360 1,073,471,063 1,412,184,216 1,695,540,202 1,753,142,883 1,810,745,563 1,868,348,244 1,925,950,925 1,983,553,606$100 M Grants, Bal. 5% 58,260,578 349,929,583 643,429,172 938,663,517 1,235,249,311 1,484,903,410 1,542,506,091 1,600,108,772 1,657,711,453 1,715,314,134 1,772,916,815$150 M Grants, Bal. 5% 54,047,842 324,653,168 597,089,077 871,259,744 1,146,781,859 1,379,585,015 1,437,187,695 1,494,790,376 1,552,393,057 1,609,995,738 1,667,598,419$200 M Grants, Bal. 5% 49,835,106 299,376,753 550,748,983 803,855,970 1,058,314,406 1,274,266,619 1,331,869,300 1,389,471,981 1,447,074,661 1,504,677,342 1,562,280,023$250 M Grants, Bal. 5% 45,622,370 274,100,338 504,408,889 736,452,197 969,846,954 1,168,948,223 1,226,550,904 1,284,153,585 1,341,756,266 1,399,358,947 1,456,961,627Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770
COMBUSTION TURBINE - BETHEL
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine Life150 MW Barge Mounted Combined-Cycle Plant @ Bethel - #2 Fuel Oil + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000.00 70,000.00 70,000.00 70,000.00 70,000.00 - - - - - - Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 0.5 0.5 0.5 0.5 0.5 0.5In Plant Use 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 89,361.24 91,125.44 92,889.63 94,029.37 95,169.10 20,253.05 20,336.50 20,336.50 20,336.50 20,336.50 20,336.50 KWHsDonlin Gold Mine 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 - - - - - - Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000.00 43,800,000.00 43,800,000.00 43,800,000.00 43,800,000.00 4,380.00 4,380.00 4,380.00 4,380.00 4,380.00 4,380.00 In Plant Use 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 Total kWh Generated 656,141,628.49 665,688,099.85 675,234,571.20 682,282,362.43 689,330,153.66 119,934,533.66 119,934,533.66 119,934,533.66 119,934,533.66 119,934,533.66 119,934,533.66 Generation Capacity KWs CFB Coal Plant 0 0 0 00000000Combustion Turbine Bethel 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Bethel Utilities Plant 0 0 0 00000000Total Capacity in KWs 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000Generation KWHsCoal Plant 0 0 0 00000000Combustion Turbine Bethel 656,141,628 665,688,100 675,234,571 682,282,362 689,330,154 119,934,534 119,934,534 119,934,534 119,934,534 119,934,534 119,934,534CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Purchased Power 0 0 0 000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $820 $820 $820 $820 $820 $820 $820 $820 $820 $820 $820CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0Plant Costs $Coal Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $123,000,000 $123,000,000 $123,000,000 $123,000,000 $123,000,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $123,000,000 $123,000,000 $123,000,000 $123,000,000 $123,000,000 $0 $0 $0 $0 $0 $0111/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Fuel Storage Costs $/Gallon Bethel $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00CCK MineFuel Storage Costs Bethel $25,000,000 $25,000,000 $25,000,000 $25,000,000 $25,000,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $25,000,000 $25,000,000 $25,000,000 $25,000,000 $25,000,000 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $296,577,800 $296,577,800 $296,577,800 $296,577,800 $296,577,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $14,828,890 $14,828,890 $14,828,890 $14,828,890 $14,828,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $9,828,890 $9,828,890 $9,828,890 $9,828,890 $9,828,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $7,328,890 $7,328,890 $7,328,890 $7,328,890 $7,328,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $4,828,890 $4,828,890 $4,828,890 $4,828,890 $4,828,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $2,328,890 $2,328,890 $2,328,890 $2,328,890 $2,328,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $311,406,690 $311,406,690 $311,406,690 $311,406,690 $311,406,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $206,406,690 $206,406,690 $206,406,690 $206,406,690 $206,406,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $153,906,690 $153,906,690 $153,906,690 $153,906,690 $153,906,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $101,406,690 $101,406,690 $101,406,690 $101,406,690 $101,406,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $48,906,690 $48,906,690 $48,906,690 $48,906,690 $48,906,690 $0 $0 $0 $0 $0 $0 3. ExpensesAnnual Debt Service5% $24,988,078 $24,988,078 $24,988,078 $24,988,078 $24,988,078 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $16,562,607 $16,562,607 $16,562,607 $16,562,607 $16,562,607 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $12,349,871 $12,349,871 $12,349,871 $12,349,871 $12,349,871 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,137,135 $8,137,135 $8,137,135 $8,137,135 $8,137,135 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $3,924,399 $3,924,399 $3,924,399 $3,924,399 $3,924,399 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - - - - - - - #1 Fuel Oil GallonsBethel 31,292,908.44 31,748,201.68 32,203,494.93 32,539,620.36 32,875,745.79 7,864,937.69 7,864,937.69 7,864,937.69 7,864,937.69 7,864,937.69 7,864,937.69 CCKMine - - - - - - - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 #1 Fuel Oil $/GallonsBethel 1.04$ 1.04$ 1.04$ 1.04$ 1.04$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ CCKMine211/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual Fuel CostsCoal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 #1 Fuel OilBethel $32,544,625 $33,018,130 $33,491,635 $33,841,205 $34,190,776 $9,437,925 $9,437,925 $9,437,925 $9,437,925 $9,437,925 $9,437,925CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $888,136 $901,058 $913,979 $923,519 $933,059 $257,559 $257,559 $257,559 $257,559 $257,559 $257,559 O&M Tug + Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $33,432,760 $33,919,187 $34,405,614 $34,764,724 $35,123,834 $9,695,484 $9,695,484 $9,695,484 $9,695,484 $9,695,484 $9,695,484O&MCoal-PlantPersonnelEquipment/SuppliesCombustion TurbinePersonnel $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000Equipment/Supplies $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000Nuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $6,292,000 $6,292,000 $6,292,000 $6,292,000 $6,292,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.042 $0.042 $0.041 $0.041 $0.040 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.028 $0.028 $0.027 $0.027 $0.027 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.021 $0.021 $0.020 $0.020 $0.020 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.014 $0.014 $0.013 $0.013 $0.013 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.007 $0.007 $0.006 $0.006 $0.006 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.057 $0.057 $0.056 $0.056 $0.056 $0.099 $0.099 $0.099 $0.099 $0.099 $0.099 O&M $/kWh $0.011 $0.010 $0.010 $0.010 $0.010 $0.035 $0.035 $0.035 $0.035 $0.035 $0.035 Total $0.067 $0.067 $0.067 $0.067 $0.066 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 BreakEven Cost $/kWh5% $0.110 $0.109 $0.108 $0.107 $0.106 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 $100 M Grants, Bal. 5% $0.095 $0.095 $0.094 $0.093 $0.093 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 $150 M Grants, Bal. 5% $0.088 $0.088 $0.087 $0.087 $0.086 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 $200 M Grants, Bal. 5% $0.081 $0.081 $0.080 $0.080 $0.079 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 $250 M Grants, Bal. 5% $0.074 $0.074 $0.073 $0.073 $0.073 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 Wholesale Cost$/kWh5% 0.115 0.114 0.113 0.112 0.111 0.139 0.139 0.139 0.139 0.139 0.139$100 M Grants, Bal. 5% 0.100 0.100 0.099 0.098 0.098 0.139 0.139 0.139 0.139 0.139 0.139$150 M Grants, Bal. 5% 0.093 0.093 0.092 0.092 0.091 0.139 0.139 0.139 0.139 0.139 0.139$200 M Grants, Bal. 5% 0.086 0.086 0.085 0.085 0.084 0.139 0.139 0.139 0.139 0.139 0.139$250 M Grants, Bal. 5% 0.079 0.079 0.078 0.078 0.078 0.139 0.139 0.139 0.139 0.139 0.139311/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual WholeSale Cost of Power5% $67,665,047 $68,199,206 $68,733,365 $69,127,715 $69,522,064 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635$100 M Grants, Bal. 5% $59,239,575 $59,773,735 $60,307,894 $60,702,243 $61,096,592 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635$150 M Grants, Bal. 5% $55,026,840 $55,560,999 $56,095,158 $56,489,507 $56,883,856 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635$200 M Grants, Bal. 5% $50,814,104 $51,348,263 $51,882,422 $52,276,771 $52,671,120 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635$250 M Grants, Bal. 5% $46,601,368 $47,135,527 $47,669,686 $48,064,035 $48,458,385 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635Accumulated WholeSale Cost of Power5% 67,665,047 406,524,442 748,054,632 1,092,115,809 1,438,148,731 1,729,814,620 1,797,702,795 1,865,590,969 1,933,479,144 2,001,367,318 2,069,255,493$100 M Grants, Bal. 5% 59,239,575 355,971,612 655,374,444 957,308,262 1,261,213,826 1,519,177,829 1,587,066,003 1,654,954,178 1,722,842,352 1,790,730,527 1,858,618,701$150 M Grants, Bal. 5% 55,026,840 330,695,197 609,034,350 889,904,489 1,172,746,373 1,413,859,433 1,481,747,608 1,549,635,782 1,617,523,957 1,685,412,131 1,753,300,306$200 M Grants, Bal. 5% 50,814,104 305,418,782 562,694,256 822,500,716 1,084,278,921 1,308,541,037 1,376,429,212 1,444,317,386 1,512,205,561 1,580,093,736 1,647,981,910$250 M Grants, Bal. 5% 46,601,368 280,142,367 516,354,162 755,096,942 995,811,469 1,203,222,642 1,271,110,816 1,338,998,991 1,406,887,165 1,474,775,340 1,542,663,514Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,204,682,971$100 M Grants, Bal. 5% $1,054,679,052$150 M Grants, Bal. 5% $979,677,093$200 M Grants, Bal. 5% $904,675,133$250 M Grants, Bal. 5% $829,673,174411/15/2003
Donlin Creek Mine - 50 MW Average Load, 20 Year Mine Life150 MW Barge Mounted Combined-Cycle Plant @ Bethel - #2 Fuel Oil + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 60,000 60,000 60,000 60,000 60,000 - - - - - - Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 3,500 3,500 3,500 3,500 3,500 500 500 500 500 500 500In Plant Use 2,500 2,500 2,500 2,500 2,500 1,000 1,000 1,000 1,000 1,000 1,000Total KW 77,861.24 79,625.44 81,389.63 82,529.37 83,669.10 19,252.55 19,336.00 19,336.00 19,336.00 19,336.00 19,336.00 KWHsDonlin Gold Mine 438,000,000.00 438,000,000.00 438,000,000.00 438,000,000.00 438,000,000.00 - - - - - - Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 502,841,628 512,388,100 521,934,571 528,982,362 536,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 30,660,000.00 30,660,000.00 30,660,000.00 30,660,000.00 30,660,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 In Plant Use 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 8,760,000.00 8,760,000.00 8,760,000.00 8,760,000.00 8,760,000.00 8,760,000.00 Total kWh Generated 555,401,628.49 564,948,099.85 574,494,571.20 581,542,362.43 588,590,153.66 111,170,153.66 111,170,153.66 111,170,153.66 111,170,153.66 111,170,153.66 111,170,153.66 Generation Capacity KWs CFB Coal Plant00000000000Combustion Turbine Bethel 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000CCK00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000Generation KWHsCoal Plant 00000000000Combustion Turbine Bethel 555,401,628 564,948,100 574,494,571 581,542,362 588,590,154 111,170,154 111,170,154 111,170,154 111,170,154 111,170,154 111,170,154CCK00000000000 Mine 00000000000Purchased Power000000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $820 $820 $820 $820 $820 $820 $820 $820 $820 $820 $820CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0Plant Costs $Coal Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $123,000,000 $123,000,000 $123,000,000 $123,000,000 $123,000,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $123,000,000 $123,000,000 $123,000,000 $123,000,000 $123,000,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0111/16/2003
Donlin Creek Mine - 50 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 25,000,000 21,000,000 21,000,000 21,000,000 21,000,000 21,000,000 21,000,000 21,000,000 21,000,000 21,000,000 21,000,000CCK00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00CCK MineFuel Storage Costs Bethel $25,000,000 $21,000,000 $21,000,000 $21,000,000 $21,000,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $25,000,000 $21,000,000 $21,000,000 $21,000,000 $21,000,000 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $296,577,800 $292,577,800 $292,577,800 $292,577,800 $292,577,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $14,828,890 $14,628,890 $14,628,890 $14,628,890 $14,628,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $9,828,890 $9,628,890 $9,628,890 $9,628,890 $9,628,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $7,328,890 $7,128,890 $7,128,890 $7,128,890 $7,128,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $4,828,890 $4,628,890 $4,628,890 $4,628,890 $4,628,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $2,328,890 $2,128,890 $2,128,890 $2,128,890 $2,128,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $311,406,690 $307,206,690 $307,206,690 $307,206,690 $307,206,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $206,406,690 $202,206,690 $202,206,690 $202,206,690 $202,206,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $153,906,690 $149,706,690 $149,706,690 $149,706,690 $149,706,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $101,406,690 $97,206,690 $97,206,690 $97,206,690 $97,206,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $48,906,690 $44,706,690 $44,706,690 $44,706,690 $44,706,690 $0 $0 $0 $0 $0 $0 3. ExpensesAnnual Debt Service5% $24,988,078 $24,651,060 $24,651,060 $24,651,060 $24,651,060 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $16,562,607 $16,225,588 $16,225,588 $16,225,588 $16,225,588 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $12,349,871 $12,012,852 $12,012,852 $12,012,852 $12,012,852 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,137,135 $7,800,116 $7,800,116 $7,800,116 $7,800,116 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $3,924,399 $3,587,380 $3,587,380 $3,587,380 $3,587,380 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - - - - - - - #1 Fuel Oil GallonsBethel 26,488,385.36 26,943,678.61 27,398,971.86 27,735,097.29 28,071,222.71 7,290,196.62 7,290,196.62 7,290,196.62 7,290,196.62 7,290,196.62 7,290,196.62 CCKMine - - - - - - - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 #1 Fuel Oil $/GallonsBethel 1.04$ 1.04$ 1.04$ 1.04$ 1.04$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ CCKMine211/16/2003
Donlin Creek Mine - 50 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual Fuel CostsCoal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 #1 Fuel OilBethel $27,547,921 $28,021,426 $28,494,931 $28,844,501 $29,194,072 $8,748,236 $8,748,236 $8,748,236 $8,748,236 $8,748,236 $8,748,236CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $751,777 $764,699 $777,620 $787,160 $796,700 $238,737 $238,737 $238,737 $238,737 $238,737 $238,737 O&M Tug + Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $28,299,698 $28,786,124 $29,272,551 $29,631,661 $29,990,771 $8,986,973 $8,986,973 $8,986,973 $8,986,973 $8,986,973 $8,986,973O&MCoal-PlantPersonnelEquipment/SuppliesCombustion TurbinePersonnel $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000Equipment/Supplies $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000Nuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $6,292,000 $6,292,000 $6,292,000 $6,292,000 $6,292,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.050 $0.048 $0.047 $0.047 $0.046 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.033 $0.032 $0.031 $0.031 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.025 $0.023 $0.023 $0.023 $0.022 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.016 $0.015 $0.015 $0.015 $0.015 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.008 $0.007 $0.007 $0.007 $0.007 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.056 $0.056 $0.056 $0.056 $0.056 $0.092 $0.092 $0.092 $0.092 $0.092 $0.092 O&M $/kWh $0.013 $0.012 $0.012 $0.012 $0.012 $0.035 $0.035 $0.035 $0.035 $0.035 $0.035 Total $0.069 $0.068 $0.068 $0.068 $0.068 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 BreakEven Cost $/kWh5% $0.118 $0.117 $0.115 $0.115 $0.114 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 $100 M Grants, Bal. 5% $0.102 $0.100 $0.099 $0.099 $0.098 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 $150 M Grants, Bal. 5% $0.093 $0.092 $0.091 $0.091 $0.090 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 $200 M Grants, Bal. 5% $0.085 $0.084 $0.083 $0.083 $0.082 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 $250 M Grants, Bal. 5% $0.077 $0.075 $0.075 $0.075 $0.074 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 Wholesale Cost$/kWh5% 0.123 0.122 0.120 0.120 0.119 0.131 0.131 0.131 0.131 0.131 0.131$100 M Grants, Bal. 5% 0.107 0.105 0.104 0.104 0.103 0.131 0.131 0.131 0.131 0.131 0.131$150 M Grants, Bal. 5% 0.098 0.097 0.096 0.096 0.095 0.131 0.131 0.131 0.131 0.131 0.131$200 M Grants, Bal. 5% 0.090 0.089 0.088 0.088 0.087 0.131 0.131 0.131 0.131 0.131 0.131$250 M Grants, Bal. 5% 0.082 0.080 0.080 0.080 0.079 0.131 0.131 0.131 0.131 0.131 0.131311/16/2003
Donlin Creek Mine - 50 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual WholeSale Cost of Power5% $62,093,984 $62,291,124 $62,825,284 $63,219,633 $63,613,982 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124$100 M Grants, Bal. 5% $53,668,512 $53,865,653 $54,399,812 $54,794,161 $55,188,510 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124$150 M Grants, Bal. 5% $49,455,777 $49,652,917 $50,187,076 $50,581,425 $50,975,774 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124$200 M Grants, Bal. 5% $45,243,041 $45,440,181 $45,974,340 $46,368,689 $46,763,039 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124$250 M Grants, Bal. 5% $41,030,305 $41,227,445 $41,761,604 $42,155,954 $42,550,303 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124Accumulated WholeSale Cost of Power5% 62,093,984 372,761,045 684,750,826 999,271,594 1,315,764,106 1,583,089,158 1,647,434,779 1,711,780,399 1,776,126,020 1,840,471,641 1,904,817,262$100 M Grants, Bal. 5% 53,668,512 322,208,215 592,070,638 864,464,047 1,138,829,202 1,372,452,367 1,436,797,987 1,501,143,608 1,565,489,229 1,629,834,850 1,694,180,470$150 M Grants, Bal. 5% 49,455,777 296,931,800 545,730,544 797,060,274 1,050,361,749 1,267,133,971 1,331,479,592 1,395,825,212 1,460,170,833 1,524,516,454 1,588,862,075$200 M Grants, Bal. 5% 45,243,041 271,655,385 499,390,450 729,656,501 961,894,297 1,161,815,575 1,226,161,196 1,290,506,817 1,354,852,438 1,419,198,058 1,483,543,679$250 M Grants, Bal. 5% 41,030,305 246,378,970 453,050,356 662,252,728 873,426,845 1,056,497,180 1,120,842,800 1,185,188,421 1,249,534,042 1,313,879,663 1,378,225,283Annual Net Income 2,514,208 2,561,940 2,609,673 2,644,912 2,680,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,514,208 15,132,981 30,552,357 46,245,633 62,150,342 76,041,247 78,982,152 81,923,056 84,863,961 87,804,866 90,745,770Mine 20 yearPower cost5% $1,081,738,802$100 M Grants, Bal. 5% $934,958,728$150 M Grants, Bal. 5% $861,568,691$200 M Grants, Bal. 5% $788,178,653411/16/2003
Donlin Creek Mine -70 MW Average Load, 20 Year Mine Life150 MW Barge Mounted Combined-Cycle Plant @ Bethel - #2 Fuel Oil + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 80,000 80,000 80,000 80,000 80,000 - - - - - - Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,800 6,700 6,700 6,700 6,700 500 500 500 500 500 500In Plant Use 2,500 2,500 2,500 2,500 2,500 1,000 1,000 1,000 1,000 1,000 1,000Total KW 100,161.24 102,825.44 104,589.63 105,729.37 106,869.10 19,252.55 19,336.00 19,336.00 19,336.00 19,336.00 19,336.00 KWHsDonlin Gold Mine 600,685,714.29 600,685,714.29 600,685,714.29 600,685,714.29 600,685,714.29 - - - - - - Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 665,527,343 675,073,814 684,620,285 691,668,077 698,715,868 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 50,808,000.00 58,692,000.00 58,692,000.00 58,692,000.00 58,692,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 In Plant Use 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 8,760,000.00 8,760,000.00 8,760,000.00 8,760,000.00 8,760,000.00 8,760,000.00 Total kWh Generated 738,235,342.78 755,665,814.13 765,212,285.49 772,260,076.72 779,307,867.95 111,170,153.66 111,170,153.66 111,170,153.66 111,170,153.66 111,170,153.66 111,170,153.66 Generation Capacity KWs CFB Coal Plant 0 0 0 00000000Combustion Turbine Bethel 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Bethel Utilities Plant 0 0 0 00000000Total Capacity in KWs 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000Generation KWHsCoal Plant 0 0 0 00000000Combustion Turbine Bethel 738,235,343 755,665,814 765,212,285 772,260,077 779,307,868 111,170,154 111,170,154 111,170,154 111,170,154 111,170,154 111,170,154CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Purchased Power 0 0 0 000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $820 $820 $820 $820 $820 $820 $820 $820 $820 $820 $820CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0Plant Costs $Coal Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $123,000,000 $123,000,000 $123,000,000 $123,000,000 $123,000,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $123,000,000 $123,000,000 $123,000,000 $123,000,000 $123,000,000 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0111/16/2003
Donlin Creek Mine -70 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 29,000,000 29,000,000 29,000,000 29,000,000 29,000,000 29,000,000 29,000,000 29,000,000 29,000,000 29,000,000 29,000,000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Fuel Storage Costs $/Gallon Bethel $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00CCK MineFuel Storage Costs Bethel $29,000,000 $29,000,000 $29,000,000 $29,000,000 $29,000,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $29,000,000 $29,000,000 $29,000,000 $29,000,000 $29,000,000 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $300,577,800 $300,577,800 $300,577,800 $300,577,800 $300,577,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $15,028,890 $15,028,890 $15,028,890 $15,028,890 $15,028,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $10,028,890 $10,028,890 $10,028,890 $10,028,890 $10,028,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $7,528,890 $7,528,890 $7,528,890 $7,528,890 $7,528,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $5,028,890 $5,028,890 $5,028,890 $5,028,890 $5,028,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $2,528,890 $2,528,890 $2,528,890 $2,528,890 $2,528,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $315,606,690 $315,606,690 $315,606,690 $315,606,690 $315,606,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $210,606,690 $210,606,690 $210,606,690 $210,606,690 $210,606,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $158,106,690 $158,106,690 $158,106,690 $158,106,690 $158,106,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $105,606,690 $105,606,690 $105,606,690 $105,606,690 $105,606,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $53,106,690 $53,106,690 $53,106,690 $53,106,690 $53,106,690 $0 $0 $0 $0 $0 $0 3. ExpensesAnnual Debt Service5% $25,325,097 $25,325,097 $25,325,097 $25,325,097 $25,325,097 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $16,899,626 $16,899,626 $16,899,626 $16,899,626 $16,899,626 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $12,686,890 $12,686,890 $12,686,890 $12,686,890 $12,686,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,474,154 $8,474,154 $8,474,154 $8,474,154 $8,474,154 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $4,261,418 $4,261,418 $4,261,418 $4,261,418 $4,261,418 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - - - - - - - #1 Fuel Oil GallonsBethel 35,208,147.12 36,039,446.52 36,494,739.77 36,830,865.20 37,166,990.63 7,290,196.62 7,290,196.62 7,290,196.62 7,290,196.62 7,290,196.62 7,290,196.62 CCKMine - - - - - - - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 #1 Fuel Oil $/GallonsBethel 1.04$ 1.04$ 1.04$ 1.04$ 1.04$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ CCKMine211/16/2003
Donlin Creek Mine -70 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual Fuel CostsCoal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 #1 Fuel OilBethel $36,616,473 $37,481,024 $37,954,529 $38,304,100 $38,653,670 $8,748,236 $8,748,236 $8,748,236 $8,748,236 $8,748,236 $8,748,236CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $999,256 $1,022,849 $1,035,771 $1,045,311 $1,054,850 $238,737 $238,737 $238,737 $238,737 $238,737 $238,737 O&M Tug + Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $37,615,729 $38,503,873 $38,990,300 $39,349,410 $39,708,520 $8,986,973 $8,986,973 $8,986,973 $8,986,973 $8,986,973 $8,986,973O&MCoal-PlantPersonnelEquipment/SuppliesCombustion TurbinePersonnel $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000Equipment/Supplies $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000Nuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $6,292,000 $6,292,000 $6,292,000 $6,292,000 $6,292,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.038 $0.038 $0.037 $0.037 $0.036 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.025 $0.025 $0.025 $0.024 $0.024 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.019 $0.019 $0.019 $0.018 $0.018 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.013 $0.013 $0.012 $0.012 $0.012 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.006 $0.006 $0.006 $0.006 $0.006 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.057 $0.057 $0.057 $0.057 $0.057 $0.092 $0.092 $0.092 $0.092 $0.092 $0.092 O&M $/kWh $0.009 $0.009 $0.009 $0.009 $0.009 $0.035 $0.035 $0.035 $0.035 $0.035 $0.035 Total $0.066 $0.066 $0.066 $0.066 $0.066 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 BreakEven Cost $/kWh5% $0.104 $0.104 $0.103 $0.103 $0.102 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 $100 M Grants, Bal. 5% $0.091 $0.091 $0.091 $0.090 $0.090 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 $150 M Grants, Bal. 5% $0.085 $0.085 $0.085 $0.084 $0.084 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 $200 M Grants, Bal. 5% $0.079 $0.079 $0.079 $0.078 $0.078 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 $250 M Grants, Bal. 5% $0.072 $0.073 $0.072 $0.072 $0.072 $0.126 $0.126 $0.126 $0.126 $0.126 $0.126 Wholesale Cost$/kWh5% 0.109 0.109 0.108 0.108 0.107 0.131 0.131 0.131 0.131 0.131 0.131$100 M Grants, Bal. 5% 0.096 0.096 0.096 0.095 0.095 0.131 0.131 0.131 0.131 0.131 0.131$150 M Grants, Bal. 5% 0.090 0.090 0.090 0.089 0.089 0.131 0.131 0.131 0.131 0.131 0.131$200 M Grants, Bal. 5% 0.084 0.084 0.084 0.083 0.083 0.131 0.131 0.131 0.131 0.131 0.131$250 M Grants, Bal. 5% 0.077 0.078 0.077 0.077 0.077 0.131 0.131 0.131 0.131 0.131 0.131311/16/2003
Donlin Creek Mine -70 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual WholeSale Cost of Power5% $72,560,463 $73,496,340 $74,030,499 $74,424,848 $74,819,197 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124$100 M Grants, Bal. 5% $64,134,991 $65,070,868 $65,605,027 $65,999,376 $66,393,725 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124$150 M Grants, Bal. 5% $59,922,255 $60,858,132 $61,392,291 $61,786,641 $62,180,990 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124$200 M Grants, Bal. 5% $55,709,519 $56,645,396 $57,179,556 $57,573,905 $57,968,254 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124$250 M Grants, Bal. 5% $51,496,783 $52,432,661 $52,966,820 $53,361,169 $53,755,518 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124 $12,869,124Accumulated WholeSale Cost of Power5% 72,560,463 436,298,653 804,314,511 1,174,861,355 1,547,379,944 1,859,525,857 1,923,871,477 1,988,217,098 2,052,562,719 2,116,908,340 2,181,253,960$100 M Grants, Bal. 5% 64,134,991 385,745,823 711,634,323 1,040,053,808 1,370,445,039 1,648,889,065 1,713,234,686 1,777,580,307 1,841,925,927 1,906,271,548 1,970,617,169$150 M Grants, Bal. 5% 59,922,255 360,469,408 665,294,228 972,650,035 1,281,977,587 1,543,570,670 1,607,916,290 1,672,261,911 1,736,607,532 1,800,953,153 1,865,298,773$200 M Grants, Bal. 5% 55,709,519 335,192,993 618,954,134 905,246,262 1,193,510,134 1,438,252,274 1,502,597,895 1,566,943,515 1,631,289,136 1,695,634,757 1,759,980,378$250 M Grants, Bal. 5% 51,496,783 309,916,578 572,614,040 837,842,488 1,105,042,682 1,332,933,878 1,397,279,499 1,461,625,120 1,525,970,740 1,590,316,361 1,654,661,982Annual Net Income 3,327,637 3,375,369 3,423,101 3,458,340 3,493,579 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 3,327,637 20,013,553 40,313,499 60,887,347 81,672,628 99,630,676 102,571,580 105,512,485 108,453,389 111,394,294 114,335,199Mine 20 yearPower cost5% $1,309,819,462$100 M Grants, Bal. 5% $1,157,727,726$150 M Grants, Bal. 5% $1,081,681,858$200 M Grants, Bal. 5% $1,005,635,989411/16/2003
Donlin Creek Mine -60 MW Average Load, 20 Year Mine Life150 MW Barge Mounted Combined-Cycle Plant @ Bethel - Propane + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000.00 70,000.00 70,000.00 70,000.00 70,000.00 - - - - - - Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 500 500 500 500 500 500In Plant Use 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 89,361.24 91,125.44 92,889.63 94,029.37 95,169.10 20,752.55 20,836.00 20,836.00 20,836.00 20,836.00 20,836.00 KWHsDonlin Gold Mine 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 - - - - - - Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000 43,800,000 43,800,000 43,800,000 43,800,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 In Plant Use 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 Total kWh Generated 656,141,628 665,688,100 675,234,571 682,282,362 689,330,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 Generation Capacity KWs CFB Coal Plant 0 0 0 00000000Combustion Turbine Bethel 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Bethel Utilities Plant 0 0 0 00000000Total Capacity in KWs 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000Generation KWHsCoal Plant 0 0 0 00000000Combustion Turbine Bethel 656,141,628 665,688,100 675,234,571 682,282,362 689,330,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154 124,310,154CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Purchased Power 0 0 0 000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $820 $820 $820 $820 $820 $820 $820 $820 $820 $820 $820CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0Plant Costs $Coal Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $123,000,000 $123,000,000 $123,000,000 $123,000,000 $123,000,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $123,000,000 $123,000,000 $123,000,000 $123,000,000 $123,000,000 $0 $0 $0 $0 $0 $0111/16/2003
Donlin Creek Mine -60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 38,000,000 38,000,000 38,000,000 38,000,000 38,000,000 38,000,000 38,000,000 38,000,000 38,000,000 38,000,000 38,000,000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Fuel Storage Costs $/Gallon Bethel $0.75 $0.75 $0.75 $0.75 $0.75 $0.75 $0.75 $0.75 $0.75 $0.75 $0.75CCK MineFuel Storage Costs Bethel $28,500,000 $28,500,000 $28,500,000 $28,500,000 $28,500,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $28,500,000 $28,500,000 $28,500,000 $28,500,000 $28,500,000 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $300,077,800 $300,077,800 $300,077,800 $300,077,800 $300,077,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $15,003,890 $15,003,890 $15,003,890 $15,003,890 $15,003,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $10,003,890 $10,003,890 $10,003,890 $10,003,890 $10,003,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $7,503,890 $7,503,890 $7,503,890 $7,503,890 $7,503,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $5,003,890 $5,003,890 $5,003,890 $5,003,890 $5,003,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $2,503,890 $2,503,890 $2,503,890 $2,503,890 $2,503,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $315,081,690 $315,081,690 $315,081,690 $315,081,690 $315,081,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $210,081,690 $210,081,690 $210,081,690 $210,081,690 $210,081,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $157,581,690 $157,581,690 $157,581,690 $157,581,690 $157,581,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $105,081,690 $105,081,690 $105,081,690 $105,081,690 $105,081,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $52,581,690 $52,581,690 $52,581,690 $52,581,690 $52,581,690 $0 $0 $0 $0 $0 $0 3. ExpensesAnnual Debt Service5% $25,282,970 $25,282,970 $25,282,970 $25,282,970 $25,282,970 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $16,857,498 $16,857,498 $16,857,498 $16,857,498 $16,857,498 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $12,644,762 $12,644,762 $12,644,762 $12,644,762 $12,644,762 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $8,432,027 $8,432,027 $8,432,027 $8,432,027 $8,432,027 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $4,219,291 $4,219,291 $4,219,291 $4,219,291 $4,219,291 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - - - - - - - #1 Fuel Oil GallonsBethel 47,859,742 48,556,073 49,252,404 49,766,478 50,280,552 12,467,577 12,467,577 12,467,577 12,467,577 12,467,577 12,467,577CCKMine - - - - - - - - - - - 211/16/2003
Donlin Creek Mine -60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 #1 Fuel Oil $/GallonsBethel 0.65$ 0.65$ 0.65$ 0.65$ 0.65$ 0.78$ 0.78$ 0.78$ 0.78$ 0.78$ 0.78$ CCKMineYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual Fuel CostsCoal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 #1 Fuel OilBethel $31,108,833 $31,561,448 $32,014,063 $32,348,211 $32,682,359 $9,724,710 $9,724,710 $9,724,710 $9,724,710 $9,724,710 $9,724,710CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $848,953 $861,305 $873,657 $882,776 $891,894 $265,385 $265,385 $265,385 $265,385 $265,385 $265,385 O&M Tug + Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $31,957,786 $32,422,753 $32,887,719 $33,230,986 $33,574,253 $9,990,095 $9,990,095 $9,990,095 $9,990,095 $9,990,095 $9,990,095O&MCoal-PlantPersonnelEquipment/SuppliesCombustion TurbinePersonnel $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000Equipment/Supplies $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000Nuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $6,292,000 $6,292,000 $6,292,000 $6,292,000 $6,292,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.043 $0.042 $0.041 $0.041 $0.041 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.029 $0.028 $0.028 $0.027 $0.027 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.021 $0.021 $0.021 $0.021 $0.020 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.014 $0.014 $0.014 $0.014 $0.014 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.007 $0.007 $0.007 $0.007 $0.007 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.054 $0.054 $0.054 $0.054 $0.054 $0.102 $0.102 $0.102 $0.102 $0.102 $0.102 O&M $/kWh $0.011 $0.010 $0.010 $0.010 $0.010 $0.035 $0.035 $0.035 $0.035 $0.035 $0.035 Total $0.065 $0.065 $0.064 $0.064 $0.064 $0.137 $0.137 $0.137 $0.137 $0.137 $0.137 BreakEven Cost $/kWh5% $0.108 $0.107 $0.106 $0.105 $0.104 $0.137 $0.137 $0.137 $0.137 $0.137 $0.137 $100 M Grants, Bal. 5% $0.093 $0.093 $0.092 $0.091 $0.091 $0.137 $0.137 $0.137 $0.137 $0.137 $0.137 $150 M Grants, Bal. 5% $0.086 $0.086 $0.085 $0.085 $0.084 $0.137 $0.137 $0.137 $0.137 $0.137 $0.137 $200 M Grants, Bal. 5% $0.079 $0.079 $0.078 $0.078 $0.077 $0.137 $0.137 $0.137 $0.137 $0.137 $0.137 $250 M Grants, Bal. 5% $0.072 $0.072 $0.071 $0.071 $0.071 $0.137 $0.137 $0.137 $0.137 $0.137 $0.137 Wholesale Cost$/kWh5% 0.113 0.112 0.111 0.110 0.109 0.142 0.142 0.142 0.142 0.142 0.142$100 M Grants, Bal. 5% 0.098 0.098 0.097 0.096 0.096 0.142 0.142 0.142 0.142 0.142 0.142$150 M Grants, Bal. 5% 0.091 0.091 0.090 0.090 0.089 0.142 0.142 0.142 0.142 0.142 0.142$200 M Grants, Bal. 5% 0.084 0.084 0.083 0.083 0.082 0.142 0.142 0.142 0.142 0.142 0.142$250 M Grants, Bal. 5% 0.077 0.077 0.076 0.076 0.076 0.142 0.142 0.142 0.142 0.142 0.142311/16/2003
Donlin Creek Mine -60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual WholeSale Cost of Power5% $66,484,964 $66,997,663 $67,510,362 $67,888,868 $68,267,374 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246$100 M Grants, Bal. 5% $58,059,492 $58,572,191 $59,084,891 $59,463,397 $59,841,903 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246$150 M Grants, Bal. 5% $53,846,756 $54,359,456 $54,872,155 $55,250,661 $55,629,167 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246$200 M Grants, Bal. 5% $49,634,021 $50,146,720 $50,659,419 $51,037,925 $51,416,431 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246$250 M Grants, Bal. 5% $45,421,285 $45,933,984 $46,446,683 $46,825,189 $47,203,695 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246 $13,872,246Accumulated WholeSale Cost of Power5% 66,484,964 399,422,482 734,923,497 1,072,853,814 1,412,676,661 1,699,618,404 1,768,979,635 1,838,340,866 1,907,702,097 1,977,063,328 2,046,424,559$100 M Grants, Bal. 5% 58,059,492 348,869,652 642,243,309 938,046,267 1,235,741,756 1,488,981,613 1,558,342,844 1,627,704,075 1,697,065,306 1,766,426,536 1,835,787,767$150 M Grants, Bal. 5% 53,846,756 323,593,237 595,903,214 870,642,494 1,147,274,304 1,383,663,217 1,453,024,448 1,522,385,679 1,591,746,910 1,661,108,141 1,730,469,372$200 M Grants, Bal. 5% 49,634,021 298,316,823 549,563,120 803,238,721 1,058,806,852 1,278,344,821 1,347,706,052 1,417,067,283 1,486,428,514 1,555,789,745 1,625,150,976$250 M Grants, Bal. 5% 45,421,285 273,040,408 503,223,026 735,834,948 970,339,399 1,173,026,426 1,242,387,657 1,311,748,888 1,381,110,118 1,450,471,349 1,519,832,580Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,183,673,214$100 M Grants, Bal. 5% $1,033,669,295$150 M Grants, Bal. 5% $958,667,336$200 M Grants, Bal. 5% $883,665,377$250 M Grants, Bal. 5% $808,663,417411/16/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine Life150 MW Land-Based Combined-Cycle Plant @ Bethel - #2 Diesel + 138 KV T-Line to mine, No Waste Heat SalesBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000.00 70,000.00 70,000.00 70,000.00 70,000.00 - - - - - - Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 5,000 5,000 5,000 5,000 5,000 0.5 0.5 0.5 0.5 0.5 0.5In Plant Use 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500Total KW 89,361.24 91,125.44 92,889.63 94,029.37 95,169.10 20,253.05 20,336.50 20,336.50 20,336.50 20,336.50 20,336.50 KWHsDonlin Gold Mine 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 - - - - - - Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 43,800,000.00 43,800,000.00 43,800,000.00 43,800,000.00 43,800,000.00 4,380.00 4,380.00 4,380.00 4,380.00 4,380.00 4,380.00 In Plant Use 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 21,900,000.00 Total kWh Generated 656,141,628.49 665,688,099.85 675,234,571.20 682,282,362.43 689,330,153.66 119,934,533.66 119,934,533.66 119,934,533.66 119,934,533.66 119,934,533.66 119,934,533.66 Generation Capacity KWs CFB Coal Plant 0 0 0 0000097,000 0 97,000Combustion Turbine Bethel 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Bethel Utilities Plant 0 0 0 00000000Total Capacity in KWs 150,000 150,000 150,000 150,000 150,000 150,000 150,000 150,000 247,000 150,000 247,000Generation KWHsCoal Plant 0 0 0 00000000Combustion Turbine Bethel 656,141,628 665,688,100 675,234,571 682,282,362 689,330,154 119,934,534 119,934,534 119,934,534 119,934,534 119,934,534 119,934,534CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Purchased Power 0 0 0 000000002. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $890 $890 $890 $890 $890 $890 $890 $890 $890 $890 $890CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0Plant Costs $Coal Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $133,500,000 $133,500,000 $133,500,000 $133,500,000 $133,500,000 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $133,500,000 $133,500,000 $133,500,000 $133,500,000 $133,500,000 $0 $0 $0 $0 $0 $0111/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800 $0 $0 $0 $0 $0 $0Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $142,577,800 $142,577,800 $142,577,800 $142,577,800 $142,577,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Fuel Storage Costs $/Gallon Bethel $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00 $1.00CCK MineFuel Storage Costs Bethel $25,000,000 $25,000,000 $25,000,000 $25,000,000 $25,000,000 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $25,000,000 $25,000,000 $25,000,000 $25,000,000 $25,000,000 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $307,077,800 $307,077,800 $307,077,800 $307,077,800 $307,077,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $15,353,890 $15,353,890 $15,353,890 $15,353,890 $15,353,890 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $10,353,890 $10,353,890 $10,353,890 $10,353,890 $10,353,890 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $7,853,890 $7,853,890 $7,853,890 $7,853,890 $7,853,890 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $5,353,890 $5,353,890 $5,353,890 $5,353,890 $5,353,890 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $2,853,890 $2,853,890 $2,853,890 $2,853,890 $2,853,890 $0 $0 $0 $0 $0 $0Total Capital Cost5% $322,431,690 $322,431,690 $322,431,690 $322,431,690 $322,431,690 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $217,431,690 $217,431,690 $217,431,690 $217,431,690 $217,431,690 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $164,931,690 $164,931,690 $164,931,690 $164,931,690 $164,931,690 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $112,431,690 $112,431,690 $112,431,690 $112,431,690 $112,431,690 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $59,931,690 $59,931,690 $59,931,690 $59,931,690 $59,931,690 $0 $0 $0 $0 $0 $0 3. ExpensesAnnual Debt Service5% $25,872,753 $25,872,753 $25,872,753 $25,872,753 $25,872,753 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $17,447,281 $17,447,281 $17,447,281 $17,447,281 $17,447,281 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $13,234,546 $13,234,546 $13,234,546 $13,234,546 $13,234,546 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $9,021,810 $9,021,810 $9,021,810 $9,021,810 $9,021,810 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $4,809,074 $4,809,074 $4,809,074 $4,809,074 $4,809,074 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - - - - - - - #1 Fuel Oil GallonsBethel 31,292,908.44 31,748,201.68 32,203,494.93 32,539,620.36 32,875,745.79 7,864,937.69 7,864,937.69 7,864,937.69 7,864,937.69 7,864,937.69 7,864,937.69 CCKMine - - - - - - - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 #1 Fuel Oil $/GallonsBethel 1.04$ 1.04$ 1.04$ 1.04$ 1.04$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ CCKMine211/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual Fuel CostsCoal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 #1 Fuel OilBethel $32,544,625 $33,018,130 $33,491,635 $33,841,205 $34,190,776 $9,437,925 $9,437,925 $9,437,925 $9,437,925 $9,437,925 $9,437,925CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $888,136 $901,058 $913,979 $923,519 $933,059 $257,559 $257,559 $257,559 $257,559 $257,559 $257,559 O&M Tug + Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total $33,432,760 $33,919,187 $34,405,614 $34,764,724 $35,123,834 $9,695,484 $9,695,484 $9,695,484 $9,695,484 $9,695,484 $9,695,484O&MCoal-PlantPersonnelEquipment/SuppliesCombustion TurbinePersonnel $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000Equipment/Supplies $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000 2,000,000Nuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +100KV DC Line $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $6,292,000 $6,292,000 $6,292,000 $6,292,000 $6,292,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000 $3,392,000PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.044 $0.043 $0.042 $0.042 $0.041 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.030 $0.029 $0.029 $0.028 $0.028 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.022 $0.022 $0.022 $0.021 $0.021 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.015 $0.015 $0.015 $0.015 $0.014 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.008 $0.008 $0.008 $0.008 $0.008 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.057 $0.057 $0.056 $0.056 $0.056 $0.099 $0.099 $0.099 $0.099 $0.099 $0.099 O&M $/kWh $0.011 $0.010 $0.010 $0.010 $0.010 $0.035 $0.035 $0.035 $0.035 $0.035 $0.035 Total $0.067 $0.067 $0.067 $0.067 $0.066 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 BreakEven Cost $/kWh5% $0.111 $0.110 $0.109 $0.109 $0.108 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 $100 M Grants, Bal. 5% $0.097 $0.096 $0.095 $0.095 $0.094 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 $150 M Grants, Bal. 5% $0.090 $0.089 $0.088 $0.088 $0.088 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 $200 M Grants, Bal. 5% $0.083 $0.082 $0.082 $0.081 $0.081 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 $250 M Grants, Bal. 5% $0.075 $0.075 $0.075 $0.074 $0.074 $0.134 $0.134 $0.134 $0.134 $0.134 $0.134 Wholesale Cost$/kWh5% 0.116 0.115 0.114 0.114 0.113 0.139 0.139 0.139 0.139 0.139 0.139$100 M Grants, Bal. 5% 0.102 0.101 0.100 0.100 0.099 0.139 0.139 0.139 0.139 0.139 0.139$150 M Grants, Bal. 5% 0.095 0.094 0.093 0.093 0.093 0.139 0.139 0.139 0.139 0.139 0.139$200 M Grants, Bal. 5% 0.088 0.087 0.087 0.086 0.086 0.139 0.139 0.139 0.139 0.139 0.139$250 M Grants, Bal. 5% 0.080 0.080 0.080 0.079 0.079 0.139 0.139 0.139 0.139 0.139 0.139311/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual WholeSale Cost of Power5% $68,549,722 $69,083,881 $69,618,040 $70,012,389 $70,406,738 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635$100 M Grants, Bal. 5% $60,124,250 $60,658,409 $61,192,568 $61,586,917 $61,981,267 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635$150 M Grants, Bal. 5% $55,911,514 $56,445,673 $56,979,832 $57,374,182 $57,768,531 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635$200 M Grants, Bal. 5% $51,698,778 $52,232,937 $52,767,097 $53,161,446 $53,555,795 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635$250 M Grants, Bal. 5% $47,486,042 $48,020,202 $48,554,361 $48,948,710 $49,343,059 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635 $13,577,635Accumulated WholeSale Cost of Power5% 68,549,722 411,832,489 757,786,052 1,106,270,601 1,456,726,896 1,751,931,483 1,819,819,658 1,887,707,832 1,955,596,007 2,023,484,181 2,091,372,356$100 M Grants, Bal. 5% 60,124,250 361,279,659 665,105,864 971,463,055 1,279,791,991 1,541,294,692 1,609,182,866 1,677,071,041 1,744,959,215 1,812,847,390 1,880,735,565$150 M Grants, Bal. 5% 55,911,514 336,003,244 618,765,770 904,059,281 1,191,324,538 1,435,976,296 1,503,864,471 1,571,752,645 1,639,640,820 1,707,528,994 1,775,417,169$200 M Grants, Bal. 5% 51,698,778 310,726,829 572,425,676 836,655,508 1,102,857,086 1,330,657,900 1,398,546,075 1,466,434,250 1,534,322,424 1,602,210,599 1,670,098,773$250 M Grants, Bal. 5% 47,486,042 285,450,414 526,085,581 769,251,735 1,014,389,634 1,225,339,505 1,293,227,679 1,361,115,854 1,429,004,028 1,496,892,203 1,564,780,377Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,220,433,382$100 M Grants, Bal. 5% $1,070,429,463$150 M Grants, Bal. 5% $995,427,504$200 M Grants, Bal. 5% $920,425,545$250 M Grants, Bal. 5% $845,423,585411/15/2003
COMBUSTION TURBINE - CROOKED CREEK
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine Life110 MW Combined-Cycle Plant @ Crooked Creek - #2 Fuel Oil + 138 KV T-Line to mine, No Waste Heat SalesYear 2010 2015 2020 2025 20301. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000.00 70,000.00 70,000.00 70,000.00 70,000.00 Villages 0 1,490 2,980 3,123 3,266Bethel 0 6,205 12,410 13,407 14,403Line Loss 0.5 0.5 0.5 0.5 0.5In Plant Use 2,500 2,500 2,500 2,500 2,500Total KW 72,500.5 80,195.3 87,890.1 89,029.9 90,169.6 KWHsDonlin Gold Mine 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000 Villages 0 0 0 0 0Bethel 0 0 0 0 0Total KWH Sales 525,600,000 525,600,000 525,600,000 525,600,000 525,600,000T-Line losses 4,380 4,380 4,380 4,380 4,380 In Plant Use 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 Total kWh Generated 547,504,380 547,504,380 547,504,380 547,504,380 547,504,380 Generation Capacity KWs CFB Coal Plant 0 0 0 0 0Combustion Turbine Bethel 110,000 110,000 110,000 110,000 110,000CCK00000 Mine 0 0 0 0 0Bethel Utilities Plant 0 0 0 0 0Total Capacity in KWs 110,000 110,000 110,000 110,000 110,000Generation KWHsCoal Plant 0 0 0 0 0Combustion Turbine Bethel 547,504,380 547,504,380 547,504,380 547,504,380 547,504,380CCK00000 Mine 0 0 0 0 0Purchased Power 0 0 0 0 02. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $900 $900 $900 $900 $900CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900111/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030Plant Costs $Coal Plant $0 $0 $0 $0 $0Combustion Turbine Bethel $99,000,000 $99,000,000 $99,000,000 $99,000,000 $99,000,000CCK Mine $0 $0 $0 $0 $0Bethel Utilities PlantTotal $99,000,000 $99,000,000 $99,000,000 $99,000,000 $99,000,000138 kV T-Line @ 14 miles $9,532,600 $9,532,600 $9,532,600 $9,532,600 $9,532,600Bethel Diesel Plant $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000Village Sub.+ Dist. Lines $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0Total $13,632,600 $13,632,600 $13,632,600 $13,632,600 $13,632,600Tug + 3 Barges $0 $0 $0 $0 $0Enviormental Studies $3,000,000 $3,000,000 $3,000,000 $3,000,000 $3,000,000Fuel Storage Gallons BethelCCK 25,000,000 25,000,000 25,000,000 25,000,000 25,000,000 Mine 0 0 0 0 0Fuel Storage Costs $/Gallon BethelCCK $1.00 $1.00 $1.00 $1.00 $1.00 MineFuel Storage Costs BethelCCK $25,000,000 $25,000,000 $25,000,000 $25,000,000 $25,000,000 Mine $0 $0 $0 $0 $0Total Fuel Oil Storage $25,000,000 $25,000,000 $25,000,000 $25,000,000 $25,000,000Year 2010 2015 2020 2025 2030District Heating System $0 $0 $0 $0 $0SubTotal Capital Costs $140,632,600 $140,632,600 $140,632,600 $140,632,600 $140,632,600Interest During Constuction5% $7,031,630 $7,031,630 $7,031,630 $7,031,630 $7,031,630$100 M Grants, Bal. 5% $2,031,630 $2,031,630 $2,031,630 $2,031,630 $2,031,630$140 M Grants, Bal. 5% $0 $0 $0 $0 $0Total Capital Cost5% $147,664,230 $147,664,230 $147,664,230 $147,664,230 $147,664,230$100 M Grants, Bal. 5% $42,664,230 $42,664,230 $42,664,230 $42,664,230 $42,664,230$140 M Grants, Bal. 5% $0 $0 $0 $0 $0211/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 3. ExpensesAnnual Debt Service5% $11,848,960 $11,848,960 $11,848,960 $11,848,960 $11,848,960$100 M Grants, Bal. 5% $3,423,488 $3,423,488 $3,423,488 $3,423,488 $3,423,488$140 M Grants, Bal. 5% $0 $0 $0 $0 $0$0 $0 $0 $0 $0$0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - #1 Fuel Oil GallonsBethelCCK 29,919,710.51 29,919,710.51 29,919,710.51 29,919,710.51 29,919,710.51 Mine - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 #1 Fuel Oil $/GallonsBethel 1.25$ 1.25$ 1.25$ 1.25$ 1.25$ CCKMineAnnual Fuel CostsCoal $0 $0 $0 $0 $0 #1 Fuel OilBethelCCK $37,399,638 $37,399,638 $37,399,638 $37,399,638 $37,399,638Mine $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $1,020,628 $1,020,628 $1,020,628 $1,020,628 $1,020,628 O&M Tug + Barges $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0Total $38,420,266 $38,420,266 $38,420,266 $38,420,266 $38,420,266O&MCoal-PlantPersonnelEquipment/SuppliesCombustion TurbinePersonnel $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000Equipment/Supplies $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000Nuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 138 kV T-Line $14,000 $14,000 $14,000 $14,000 $14,000 +100KV DC Line $0 $0 $0 $0 $0Waste Heat Sales Offset $0 $0 $0 $0 $0Total O&M $6,114,000 $6,114,000 $6,114,000 $6,114,000 $6,114,000311/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030PCE Payments $0 $0 $0 $0 $0Power CostsCapital Cost $/kWh5% $0.023 $0.023 $0.023 $0.023 $0.023$100 M Grants, Bal. 5% $0.007 $0.007 $0.007 $0.007 $0.007$140 M Grants, Bal. 5% $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.073 $0.073 $0.073 $0.073 $0.073 O&M $/kWh $0.012 $0.012 $0.012 $0.012 $0.012 Total $0.085 $0.085 $0.085 $0.085 $0.085 BreakEven Cost $/kWh5% $0.107 $0.107 $0.107 $0.107 $0.107 $100 M Grants, Bal. 5% $0.091 $0.091 $0.091 $0.091 $0.091 $140 M Grants, Bal. 5% $0.085 $0.085 $0.085 $0.085 $0.085 Wholesale Cost$/kWh5% 0.112 0.112 0.112 0.112 0.112$100 M Grants, Bal. 5% 0.096 0.096 0.096 0.096 0.096$140 M Grants, Bal. 5% 0.090 0.090 0.090 0.090 0.090Annual WholeSale Cost of Power5% $59,011,226 $59,011,226 $59,011,226 $59,011,226 $59,011,226$100 M Grants, Bal. 5% $50,585,754 $50,585,754 $50,585,754 $50,585,754 $50,585,754$140 M Grants, Bal. 5% $47,162,266 $47,162,266 $47,162,266 $47,162,266 $47,162,266Accumulated WholeSale Cost of Power5% 59,011,226 354,067,356 649,123,485 944,179,615 1,239,235,745$100 M Grants, Bal. 5% 50,585,754 303,514,526 556,443,297 809,372,069 1,062,300,840$140 M Grants, Bal. 5% 47,162,266 282,973,597 518,784,927 754,596,257 990,407,588Annual Net Income 2,628,000 2,628,000 2,628,000 2,628,000 2,628,000Accumulated Net Income 2,628,000 15,768,000 31,536,000 47,304,000 63,072,000Mine 20 yearPower cost5% $1,180,224,519$100 M Grants, Bal. 5% $1,011,715,086$140 M Grants, Bal. 5% $943,245,322411/15/2003
Donlin Creek Mine - 50 MW Average Load, 20 Year Mine Life110 MW Combined-Cycle Plant @ Crooked Creek - #2 Fuel Oil + 138 KV T-Line to mine, No Waste Heat SalesYear 2010 2015 2020 2025 20301. Power RequirementsKWs Peak DemandDonlin Gold Mine 60,000 60,000 60,000 60,000 60,000 Villages 0 1,490 2,980 3,123 3,266Bethel 0 6,205 12,410 13,407 14,403Line Loss 500 500 500 500 500In Plant Use 2,500 2,500 2,500 2,500 2,500Total KW 63,000.0 70,694.8 78,389.6 79,529.4 80,669.1 KWHsDonlin Gold Mine 438,000,000.00 438,000,000.00 438,000,000.00 438,000,000.00 438,000,000.00 Villages00000Bethel00000Total KWH Sales 438,000,000 438,000,000 438,000,000 438,000,000 438,000,000T-Line losses 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 In Plant Use 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 Total kWh Generated 464,280,000 464,280,000 464,280,000 464,280,000 464,280,000 Generation Capacity KWs CFB Coal Plant00000Combustion Turbine Bethel 110,000 110,000 110,000 110,000 110,000CCK00000 Mine00000Bethel Utilities Plant00000Total Capacity in KWs 110,000 110,000 110,000 110,000 110,000Generation KWHsCoal Plant 00000Combustion Turbine Bethel 464,280,000 464,280,000 464,280,000 464,280,000 464,280,000CCK00000 Mine 00000Purchased Power000002. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $900 $900 $900 $900 $900CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900111/16/2003
Donlin Creek Mine - 50 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030Plant Costs $Coal Plant $0 $0 $0 $0 $0Combustion Turbine Bethel $99,000,000 $99,000,000 $99,000,000 $99,000,000 $99,000,000CCK Mine $0 $0 $0 $0 $0Bethel Utilities PlantTotal $99,000,000 $99,000,000 $99,000,000 $99,000,000 $99,000,000138 kV T-Line @ 14 miles $9,532,600 $9,532,600 $9,532,600 $9,532,600 $9,532,600Bethel Diesel Plant $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000Village Sub.+ Dist. Lines $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0Total $13,632,600 $13,632,600 $13,632,600 $13,632,600 $13,632,600Tug + 3 Barges $0 $0 $0 $0 $0Enviormental Studies $3,000,000 $3,000,000 $3,000,000 $3,000,000 $3,000,000Fuel Storage Gallons BethelCCK 21,000,000 21,000,000 21,000,000 21,000,000 21,000,000 Mine00000Fuel Storage Costs $/Gallon BethelCCK $1.00 $1.00 $1.00 $1.00 $1.00 MineFuel Storage Costs BethelCCK $21,000,000 $21,000,000 $21,000,000 $21,000,000 $21,000,000 Mine $0 $0 $0 $0 $0Total Fuel Oil Storage $21,000,000 $21,000,000 $21,000,000 $21,000,000 $21,000,000Year 2010 2015 2020 2025 2030District Heating System $0 $0 $0 $0 $0SubTotal Capital Costs $136,632,600 $136,632,600 $136,632,600 $136,632,600 $136,632,600Interest During Constuction5% $6,831,630 $6,831,630 $6,831,630 $6,831,630 $6,831,630$100 M Grants, Bal. 5% $1,831,630 $1,831,630 $1,831,630 $1,831,630 $1,831,630$140 M Grants, Bal. 5% $0 $0 $0 $0 $0Total Capital Cost5% $143,464,230 $143,464,230 $143,464,230 $143,464,230 $143,464,230$100 M Grants, Bal. 5% $38,464,230 $38,464,230 $38,464,230 $38,464,230 $38,464,230$140 M Grants, Bal. 5% $0 $0 $0 $0 $0211/16/2003
Donlin Creek Mine - 50 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 3. ExpensesAnnual Debt Service5% $11,511,941 $11,511,941 $11,511,941 $11,511,941 $11,511,941$100 M Grants, Bal. 5% $3,086,469 $3,086,469 $3,086,469 $3,086,469 $3,086,469$140 M Grants, Bal. 5% $0 $0 $0 $0 $0$0 $0 $0 $0 $0$0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - #1 Fuel Oil GallonsBethelCCK 25,371,711.54 25,371,711.54 25,371,711.54 25,371,711.54 25,371,711.54 Mine - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 #1 Fuel Oil $/GallonsBethel 1.25$ 1.25$ 1.25$ 1.25$ 1.25$ CCKMineAnnual Fuel CostsCoal $0 $0 $0 $0 $0 #1 Fuel OilBethelCCK $31,714,639 $31,714,639 $31,714,639 $31,714,639 $31,714,639Mine $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $865,486 $865,486 $865,486 $865,486 $865,486 O&M Tug + Barges $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0Total $32,580,125 $32,580,125 $32,580,125 $32,580,125 $32,580,125O&MCoal-PlantPersonnelEquipment/SuppliesCombustion TurbinePersonnel $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000Equipment/Supplies $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000Nuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 138 kV T-Line $14,000 $14,000 $14,000 $14,000 $14,000 +100KV DC Line $0 $0 $0 $0 $0311/16/2003
Donlin Creek Mine - 50 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030Waste Heat Sales Offset $0 $0 $0 $0 $0Total O&M $6,116,010 $6,116,015 $6,116,020 $6,116,025 $6,116,030PCE Payments $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030Power CostsCapital Cost $/kWh5% $0.026 $0.026 $0.026 $0.026 $0.026$100 M Grants, Bal. 5% $0.007 $0.007 $0.007 $0.007 $0.007$140 M Grants, Bal. 5% $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.074 $0.074 $0.074 $0.074 $0.074 O&M $/kWh $0.014 $0.014 $0.014 $0.014 $0.014 Total $0.088 $0.088 $0.088 $0.088 $0.088 BreakEven Cost $/kWh5% $0.115 $0.115 $0.115 $0.115 $0.115 $100 M Grants, Bal. 5% $0.095 $0.095 $0.095 $0.095 $0.095 $140 M Grants, Bal. 5% $0.088 $0.088 $0.088 $0.088 $0.088 Wholesale Cost$/kWh5% 0.120 0.120 0.120 0.120 0.120$100 M Grants, Bal. 5% 0.100 0.100 0.100 0.100 0.100$140 M Grants, Bal. 5% 0.093 0.093 0.093 0.093 0.093Annual WholeSale Cost of Power5% $52,398,076 $52,398,081 $52,398,086 $52,398,091 $52,398,096$100 M Grants, Bal. 5% $43,972,604 $43,972,609 $43,972,614 $43,972,619 $43,972,624$140 M Grants, Bal. 5% $40,886,135 $40,886,140 $40,886,145 $40,886,150 $40,886,155Accumulated WholeSale Cost of Power5% 52,398,076 314,388,461 576,378,871 838,369,306 1,100,359,766$100 M Grants, Bal. 5% 43,972,604 263,835,631 483,698,683 703,561,759 923,424,861$140 M Grants, Bal. 5% 40,886,135 245,316,815 449,747,520 654,178,250 858,609,005Annual Net Income 2,190,000 2,190,000 2,190,000 2,190,000 2,190,000Accumulated Net Income 2,190,000 13,140,000 26,280,000 39,420,000 52,560,000Mine 20 yearPower cost5% $1,047,961,520$100 M Grants, Bal. 5% $879,452,087$140 M Grants, Bal. 5% $817,722,700411/16/2003
Donlin Creek Mine -70 MW Average Load, 20 Year Mine Life110 MW Combined-Cycle Plant @ Crooked Creek - #2 Fuel Oil + 138 KV T-Line to mine, No Waste Heat SalesYear 2010 2015 2020 2025 20301. Power RequirementsKWs Peak DemandDonlin Gold Mine 80,000 80,000 80,000 80,000 80,000 Villages00000Bethel00000Line Loss 0.5 0.5 0.5 0.5 0.5In Plant Use 2,500 2,500 2,500 2,500 2,500Total KW 82,500.5 82,500.5 82,500.5 82,500.5 82,500.5 KWHsDonlin Gold Mine 613,200,000 613,200,000 613,200,000 613,200,000 613,200,000 Villages00000Bethel00000Total KWH Sales 613,200,000 613,200,000 613,200,000 613,200,000 613,200,000T-Line losses 4,380 4,380 4,380 4,380 4,380 In Plant Use 21,900,000 21,900,000 21,900,000 21,900,000 21,900,000 Total kWh Generated 635,104,380 635,104,380 635,104,380 635,104,380 635,104,380 Generation Capacity KWs CFB Coal Plant00000Combustion Turbine Bethel 110,000 110,000 110,000 110,000 110,000CCK00000 Mine00000Bethel Utilities Plant00000Total Capacity in KWs 110,000 110,000 110,000 110,000 110,000Generation KWHsCoal Plant 00000Combustion Turbine Bethel 635,104,380 635,104,380 635,104,380 635,104,380 635,104,380CCK00000 Mine 00000Purchased Power000002. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $900 $900 $900 $900 $900CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900111/16/2003
Donlin Creek Mine -70 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030Plant Costs $Coal Plant $0 $0 $0 $0 $0Combustion Turbine Bethel $99,000,000 $99,000,000 $99,000,000 $99,000,000 $99,000,000CCK Mine $0 $0 $0 $0 $0Bethel Utilities PlantTotal $99,000,000 $99,000,000 $99,000,000 $99,000,000 $99,000,000138 kV T-Line @ 14 miles $9,532,600 $9,532,600 $9,532,600 $9,532,600 $9,532,600Bethel Diesel Plant $0 $0 $0 $0 $0138 kV Substations $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000Village Sub.+ Dist. Lines $0 $0 $0 $0 $0 +100 kV DC Line @ 385 miles $0 $0 $0 $0 $0Total $13,632,600 $13,632,600 $13,632,600 $13,632,600 $13,632,600Tug + 3 Barges $0 $0 $0 $0 $0Enviormental Studies $3,000,000 $3,000,000 $3,000,000 $3,000,000 $3,000,000Fuel Storage Gallons BethelCCK 29,000,000 29,000,000 29,000,000 29,000,000 29,000,000 Mine00000Fuel Storage Costs $/Gallon BethelCCK $1.00 $1.00 $1.00 $1.00 $1.00 MineFuel Storage Costs BethelCCK $29,000,000 $29,000,000 $29,000,000 $29,000,000 $29,000,000 Mine $0 $0 $0 $0 $0Total Fuel Oil Storage $29,000,000 $29,000,000 $29,000,000 $29,000,000 $29,000,000Year 2010 2015 2020 2025 2030District Heating System $0 $0 $0 $0 $0SubTotal Capital Costs $144,632,600 $144,632,600 $144,632,600 $144,632,600 $144,632,600Interest During Constuction5% $7,231,630 $7,231,630 $7,231,630 $7,231,630 $7,231,630$100 M Grants, Bal. 5% $2,231,630 $2,231,630 $2,231,630 $2,231,630 $2,231,630$140 M Grants, Bal. 5% $0 $0 $0 $0 $0Total Capital Cost5% $151,864,230 $151,864,230 $151,864,230 $151,864,230 $151,864,230$100 M Grants, Bal. 5% $46,864,230 $46,864,230 $46,864,230 $46,864,230 $46,864,230$140 M Grants, Bal. 5% $0 $0 $0 $0 $0211/16/2003
Donlin Creek Mine -70 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 3. ExpensesAnnual Debt Service5% $12,185,979 $12,185,979 $12,185,979 $12,185,979 $12,185,979$100 M Grants, Bal. 5% $3,760,507 $3,760,507 $3,760,507 $3,760,507 $3,760,507$140 M Grants, Bal. 5% $0 $0 $0 $0 $0$0 $0 $0 $0 $0#REF! #REF! #REF! #REF! #REF!O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - #1 Fuel Oil GallonsBethelCCK 34,706,825.89 34,706,825.89 34,706,825.89 34,706,825.89 34,706,825.89 Mine - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 #1 Fuel Oil $/GallonsBethel 1.25$ 1.25$ 1.25$ 1.25$ 1.25$ CCKMineAnnual Fuel CostsCoal $0 $0 $0 $0 $0 #1 Fuel OilBethelCCK $43,383,532 $43,383,532 $43,383,532 $43,383,532 $43,383,532Mine $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $1,183,927 $1,183,927 $1,183,927 $1,183,927 $1,183,927 O&M Tug + Barges $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KWEnergy Charge $/kwhCost of Purchased Pwr $0 $0 $0 $0 $0Total $44,567,459 $44,567,459 $44,567,459 $44,567,459 $44,567,459O&MCoal-PlantPersonnelEquipment/SuppliesCombustion TurbinePersonnel $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000Equipment/Supplies $4,100,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000Nuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 138 kV T-Line $14,000 $14,000 $14,000 $14,000 $14,000 +100KV DC Line $0 $0 $0 $0 $0311/16/2003
Donlin Creek Mine -70 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030Waste Heat Sales Offset $0 $0 $0 $0 $0Total O&M $6,116,010 $6,116,015 $6,116,020 $6,116,025 $6,116,030PCE Payments $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030Power CostsCapital Cost $/kWh5% $0.020 $0.020 $0.020 $0.020 $0.020$100 M Grants, Bal. 5% $0.006 $0.006 $0.006 $0.006 $0.006$140 M Grants, Bal. 5% $0.000 $0.000 $0.000 $0.000 $0.000Fuel $/kWh $0.073 $0.073 $0.073 $0.073 $0.073 O&M $/kWh $0.010 $0.010 $0.010 $0.010 $0.010 Total $0.083 $0.083 $0.083 $0.083 $0.083 BreakEven Cost $/kWh5% $0.103 $0.103 $0.103 $0.103 $0.103 $100 M Grants, Bal. 5% $0.089 $0.089 $0.089 $0.089 $0.089 $140 M Grants, Bal. 5% $0.083 $0.083 $0.083 $0.083 $0.083 Wholesale Cost$/kWh5% 0.108 0.108 0.108 0.108 0.108$100 M Grants, Bal. 5% 0.094 0.094 0.094 0.094 0.094$140 M Grants, Bal. 5% 0.088 0.088 0.088 0.088 0.088Year 2010 2015 2020 2025 2030Annual WholeSale Cost of Power5% $65,935,448 $65,935,453 $65,935,458 $65,935,463 $65,935,468$100 M Grants, Bal. 5% $57,509,977 $57,509,982 $57,509,987 $57,509,992 $57,509,997$140 M Grants, Bal. 5% $53,749,469 $53,749,474 $53,749,479 $53,749,484 $53,749,489Accumulated WholeSale Cost of Power5% 65,935,448 395,612,694 725,289,965 1,054,967,261 1,384,644,582$100 M Grants, Bal. 5% 57,509,977 345,059,864 632,609,777 920,159,715 1,207,709,677$140 M Grants, Bal. 5% 53,749,469 322,496,822 591,244,199 859,991,602 1,128,739,029Annual Net Income 3,066,000 3,066,000 3,066,000 3,066,000 3,066,000Accumulated Net Income 3,066,000 18,396,000 36,792,000 55,188,000 73,584,000Mine 20 yearPower cost5% $1,318,708,964$100 M Grants, Bal. 5% $1,150,199,531$150 M Grants, Bal. 5% $1,074,989,390411/16/2003
TRANSMISSION LINES FROM RAILBELT
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine Life230 kV, AC, Transmission Line From Nenana to Crooked Ck + 138 KV T-Line to Cooked Ck to Bethel, with Demand ChargeBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 - - - - - - Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 4,200 4,200 4,200 4,200 4,200 500.0 500.0 500.0 500.0 500.0 500.0In Plant Use00000000000Total KW 86,061.24 87,825.44 89,589.63 90,729.37 91,869.10 18,252.55 18,336.00 18,336.00 18,336.00 18,336.00 18,336.00 KWHsDonlin Gold Mine 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 - - - - - - Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 36,792,000.00 36,792,000.00 36,792,000.00 36,792,000.00 36,792,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 In Plant Use - - - - - - - - - - - Total kWh Generated 627,233,628.49 636,780,099.85 646,326,571.20 653,374,362.43 660,422,153.66 102,410,153.66 102,410,153.66 102,410,153.66 102,410,153.66 102,410,153.66 102,410,153.66 Generation Capacity KWs CFB Coal Plant00000000000Combustion Turbine Bethel00000000000CCK 00000000000 Mine00000000000Bethel Utilities Plant00000000000Total Capacity in KWs00000000000Generation KWHsCoal Plant 00000000000Combustion Turbine Bethel 00000000000CCK 00000000000 Mine 00000000000Purchased Power 627,233,628 636,780,100 646,326,571 653,374,362 660,422,154 102,410,154 102,410,154 102,410,154 102,410,154 102,410,154 102,410,1542. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0 +100kV DC T-Line/Mile $930,185 $930,185 $930,185 $930,185 $930,185Plant Costs $Coal Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0230 KV Substation $4,000,000 $4,000,000 $4,000,000 $4,000,000 $4,000,000 $0 $0 $0 $0 $0 $0138 kV Substations $2,000,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 +230kV AC Line @ 370 miles $344,168,450 $344,168,450 $344,168,450 $344,168,450 $344,168,450 $0 $0 $0 $0 $0 $0111/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Total $488,648,260 $490,746,250 $490,746,250 $490,746,250 $490,746,250 $0 $0 $0 $0 $0 $0Tug + 3 Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel00000000000CCK 00000000000 Mine00000000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $494,648,260 $496,746,250 $496,746,250 $496,746,250 $496,746,250 $0 $0 $0 $0 $0 $0Interest During Constuction5% $24,732,413 $24,837,313 $24,837,313 $24,837,313 $24,837,313 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $19,732,413 $19,837,313 $19,837,313 $19,837,313 $19,837,313 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $17,232,413 $17,337,313 $17,337,313 $17,337,313 $17,337,313 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,732,413 $14,837,313 $14,837,313 $14,837,313 $14,837,313 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $12,232,413 $12,337,313 $12,337,313 $12,337,313 $12,337,313 $0 $0 $0 $0 $0 $0Total Capital Cost5% $519,380,673 $521,583,563 $521,583,563 $521,583,563 $521,583,563 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $414,380,673 $416,583,563 $416,583,563 $416,583,563 $416,583,563 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $361,880,673 $364,083,563 $364,083,563 $364,083,563 $364,083,563 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $309,380,673 $311,583,563 $311,583,563 $311,583,563 $311,583,563 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $256,880,673 $259,083,563 $259,083,563 $259,083,563 $259,083,563 $0 $0 $0 $0 $0 $0 3. ExpensesAnnual Debt Service5% $41,676,449 $41,853,214 $41,853,214 $41,853,214 $41,853,214 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $33,250,977 $33,427,743 $33,427,743 $33,427,743 $33,427,743 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $29,038,241 $29,215,007 $29,215,007 $29,215,007 $29,215,007 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $24,825,506 $25,002,271 $25,002,271 $25,002,271 $25,002,271 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $20,612,770 $20,789,535 $20,789,535 $20,789,535 $20,789,535 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - - - - - - - #1 Fuel Oil GallonsBethel - - - - - - - - - - - CCKMine - - - - - - - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 #1 Fuel Oil $/GallonsBethel 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ CCKMine211/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual Fuel CostsCoal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 #1 Fuel OilBethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 O&M Tug + Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KW $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250Energy Charge $/kwh $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045Cost of Purchased Pwr $36,325,513 $36,755,104 $37,184,696 $37,501,846 $37,818,997 $6,633,457 $6,633,457 $6,633,457 $6,633,457 $6,633,457 $6,633,457Total $36,325,513 $36,755,104 $37,184,696 $37,501,846 $37,818,997 $6,633,457 $6,633,457 $6,633,457 $6,633,457 $6,633,457 $6,633,457O&MCoal-PlantPersonnel00000000000Equipment/Supplies00000000000Combustion Turbine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +230 KV AC Line $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $962,000 $962,000 $962,000 $962,000 $962,000 $762,000 $762,000 $762,000 $762,000 $762,000 $762,000PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.071 $0.070 $0.069 $0.068 $0.067 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.056 $0.056 $0.055 $0.054 $0.054 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.049 $0.049 $0.048 $0.047 $0.047 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.042 $0.042 $0.041 $0.041 $0.040 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.035 $0.035 $0.034 $0.034 $0.033 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Purchased Power $0.062 $0.061 $0.061 $0.061 $0.061 $0.068 $0.068 $0.068 $0.068 $0.068 $0.068 O&M $/kWh $0.002 $0.002 $0.002 $0.002 $0.002 $0.008 $0.008 $0.008 $0.008 $0.008 $0.008 Total $0.063 $0.063 $0.063 $0.062 $0.062 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 BreakEven Cost $/kWh5% $0.134 $0.133 $0.131 $0.130 $0.129 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 $100 M Grants, Bal. 5% $0.119 $0.119 $0.117 $0.117 $0.116 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 $150 M Grants, Bal. 5% $0.112 $0.112 $0.111 $0.110 $0.109 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 $200 M Grants, Bal. 5% $0.105 $0.105 $0.104 $0.103 $0.102 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 $250 M Grants, Bal. 5% $0.098 $0.098 $0.097 $0.096 $0.096 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 Wholesale Cost$/kWh5% 0.139 0.138 0.136 0.135 0.134 0.080 0.080 0.080 0.080 0.080 0.080$100 M Grants, Bal. 5% 0.124 0.124 0.122 0.122 0.121 0.080 0.080 0.080 0.080 0.080 0.080$150 M Grants, Bal. 5% 0.117 0.117 0.116 0.115 0.114 0.080 0.080 0.080 0.080 0.080 0.080$200 M Grants, Bal. 5% 0.110 0.110 0.109 0.108 0.107 0.080 0.080 0.080 0.080 0.080 0.080$250 M Grants, Bal. 5% 0.103 0.103 0.102 0.101 0.101 0.080 0.080 0.080 0.080 0.080 0.080311/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual WholeSale Cost of Power5% $81,916,170 $82,570,259 $83,047,583 $83,399,973 $83,752,362 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$100 M Grants, Bal. 5% $73,490,699 $74,144,788 $74,622,111 $74,974,501 $75,326,891 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$150 M Grants, Bal. 5% $69,277,963 $69,932,052 $70,409,376 $70,761,765 $71,114,155 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$7,885,608$200 M Grants, Bal. 5% $65,065,227 $65,719,316 $66,196,640 $66,549,029 $66,901,419 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$7,885,608$250 M Grants, Bal. 5% $60,852,491 $61,506,580 $61,983,904 $62,336,293 $62,688,683 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$7,885,608Accumulated WholeSale Cost of Power5% 81,916,170 492,151,111 905,479,732 1,321,070,037 1,738,422,290 2,081,317,346 2,120,745,385 2,160,173,423 2,199,601,461 2,239,029,500 2,278,457,538$100 M Grants, Bal. 5% 73,490,699 441,598,281 812,799,544 1,186,262,491 1,561,487,385 1,870,680,555 1,910,108,593 1,949,536,632 1,988,964,670 2,028,392,708 2,067,820,747$150 M Grants, Bal. 5% 69,277,963 416,321,866 766,459,450 1,118,858,717 1,473,019,933 1,765,362,159 1,804,790,197 1,844,218,236 1,883,646,274 1,923,074,313 1,962,502,351$200 M Grants, Bal. 5% 65,065,227 391,045,451 720,119,356 1,051,454,944 1,384,552,480 1,660,043,763 1,699,471,802 1,738,899,840 1,778,327,879 1,817,755,917 1,857,183,955$250 M Grants, Bal. 5% 60,852,491 365,769,036 673,779,262 984,051,171 1,296,085,028 1,554,725,368 1,594,153,406 1,633,581,444 1,673,009,483 1,712,437,521 1,751,865,560Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,458,404,593$100 M Grants, Bal. 5% $1,308,400,674$150 M Grants, Bal. 5% $1,233,398,715$200 M Grants, Bal. 5% $1,158,396,756$250 M Grants, Bal. 5% $1,083,394,796411/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine Life230 kV, AC, Transmission Line From Nenana to Crooked Ck + 138 KV T-Line to Cooked Ck to Bethel, No Demand ChargeBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 - - - - - - Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 4,200 4,200 4,200 4,200 4,200 500.0 500.0 500.0 500.0 500.0 500.0In Plant Use 0 0 0 00000000Total KW 86,061.24 87,825.44 89,589.63 90,729.37 91,869.10 18,252.55 18,336.00 18,336.00 18,336.00 18,336.00 18,336.00 KWHsDonlin Gold Mine 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 - - - - - - Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 36,792,000.00 36,792,000.00 36,792,000.00 36,792,000.00 36,792,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 4,380,000.00 In Plant Use - - - - - - - - - - - Total kWh Generated 627,233,628.49 636,780,099.85 646,326,571.20 653,374,362.43 660,422,153.66 102,410,153.66 102,410,153.66 102,410,153.66 102,410,153.66 102,410,153.66 102,410,153.66 Generation Capacity KWs CFB Coal Plant 0 0 0 00000000Combustion Turbine Bethel 0 0 0 00000000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Bethel Utilities Plant 0 0 0 00000000Total Capacity in KWs 0 0 0 00000000Generation KWHsCoal Plant 0 0 0 00000000Combustion Turbine Bethel 0 0 0 00000000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Purchased Power 627,233,628 636,780,100 646,326,571 653,374,362 660,422,154 102,410,154 102,410,154 102,410,154 102,410,154 102,410,154 102,410,1542. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0230 AC T-Line/Mile $930,185 $930,185 $930,185 $930,185 $930,185Plant Costs $Coal Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0230 KV Substation $4,000,000 $4,000,000 $4,000,000 $4,000,000 $4,000,000 $0 $0 $0 $0 $0 $0138 kV Substations $2,000,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 230 kV AC Line @ 370 miles $344,168,450 $344,168,450 $344,168,450 $344,168,450 $344,168,450 $0 $0 $0 $0 $0 $0111/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeTotal $488,646,250 $490,746,250 $490,746,250 $490,746,250 $490,746,250 $0 $0 $0 $0 $0 $0Tug + 3 Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 0 0 0 00000000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $494,646,250 $496,746,250 $496,746,250 $496,746,250 $496,746,250 $0 $0 $0 $0 $0 $0Interest During Constuction5% $24,732,313 $24,837,313 $24,837,313 $24,837,313 $24,837,313 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $19,732,313 $19,837,313 $19,837,313 $19,837,313 $19,837,313 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $17,232,313 $17,337,313 $17,337,313 $17,337,313 $17,337,313 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $14,732,313 $14,837,313 $14,837,313 $14,837,313 $14,837,313 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $12,232,313 $12,337,313 $12,337,313 $12,337,313 $12,337,313 $0 $0 $0 $0 $0 $0Total Capital Cost5% $519,378,563 $521,583,563 $521,583,563 $521,583,563 $521,583,563 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $414,378,563 $416,583,563 $416,583,563 $416,583,563 $416,583,563 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $361,878,563 $364,083,563 $364,083,563 $364,083,563 $364,083,563 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $309,378,563 $311,583,563 $311,583,563 $311,583,563 $311,583,563 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $256,878,563 $259,083,563 $259,083,563 $259,083,563 $259,083,563 $0 $0 $0 $0 $0 $0 3. ExpensesAnnual Debt Service5% $41,676,280 $41,853,214 $41,853,214 $41,853,214 $41,853,214 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $33,250,808 $33,427,743 $33,427,743 $33,427,743 $33,427,743 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $29,038,072 $29,215,007 $29,215,007 $29,215,007 $29,215,007 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $24,825,336 $25,002,271 $25,002,271 $25,002,271 $25,002,271 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $20,612,600 $20,789,535 $20,789,535 $20,789,535 $20,789,535 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - - - - - - - #1 Fuel Oil GallonsBethel - - - - - - - - - - - CCKMine - - - - - - - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 #1 Fuel Oil $/GallonsBethel 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ CCKMine211/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual Fuel CostsCoal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 #1 Fuel OilBethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 O&M Tug + Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KW $0.000 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Energy Charge $/kwh $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045Cost of Purchased Pwr $28,225,513 $28,655,104 $29,084,696 $29,401,846 $29,718,997 $4,608,457 $4,608,457 $4,608,457 $4,608,457 $4,608,457 $4,608,457Total $28,225,513 $28,655,104 $29,084,696 $29,401,846 $29,718,997 $4,608,457 $4,608,457 $4,608,457 $4,608,457 $4,608,457 $4,608,457O&MCoal-PlantPersonnel 0 0 0 00000000Equipment/Supplies 0 0 0 00000000Combustion Turbine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +230 KV AC Line $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $962,000 $962,000 $962,000 $962,000 $962,000 $762,000 $762,000 $762,000 $762,000 $762,000 $762,000PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.071 $0.070 $0.069 $0.068 $0.067 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.056 $0.056 $0.055 $0.054 $0.054 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.049 $0.049 $0.048 $0.047 $0.047 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.042 $0.042 $0.041 $0.041 $0.040 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.035 $0.035 $0.034 $0.034 $0.033 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Purchased Power $0.048 $0.048 $0.048 $0.048 $0.048 $0.047 $0.047 $0.047 $0.047 $0.047 $0.047 O&M $/kWh $0.002 $0.002 $0.002 $0.002 $0.002 $0.008 $0.008 $0.008 $0.008 $0.008 $0.008 Total $0.049 $0.049 $0.049 $0.049 $0.049 $0.055 $0.055 $0.055 $0.055 $0.055 $0.055 BreakEven Cost $/kWh5% $0.120 $0.119 $0.118 $0.117 $0.116 $0.055 $0.055 $0.055 $0.055 $0.055 $0.055 $100 M Grants, Bal. 5% $0.106 $0.105 $0.104 $0.103 $0.103 $0.055 $0.055 $0.055 $0.055 $0.055 $0.055 $150 M Grants, Bal. 5% $0.099 $0.098 $0.097 $0.097 $0.096 $0.055 $0.055 $0.055 $0.055 $0.055 $0.055 $200 M Grants, Bal. 5% $0.091 $0.091 $0.090 $0.090 $0.089 $0.055 $0.055 $0.055 $0.055 $0.055 $0.055 $250 M Grants, Bal. 5% $0.084 $0.084 $0.083 $0.083 $0.083 $0.055 $0.055 $0.055 $0.055 $0.055 $0.055 Wholesale Cost$/kWh5% 0.125 0.124 0.123 0.122 0.121 0.060 0.060 0.060 0.060 0.060 0.060$100 M Grants, Bal. 5% 0.111 0.110 0.109 0.108 0.108 0.060 0.060 0.060 0.060 0.060 0.060$150 M Grants, Bal. 5% 0.104 0.103 0.102 0.102 0.101 0.060 0.060 0.060 0.060 0.060 0.060$200 M Grants, Bal. 5% 0.096 0.096 0.095 0.095 0.094 0.060 0.060 0.060 0.060 0.060 0.060$250 M Grants, Bal. 5% 0.089 0.089 0.088 0.088 0.088 0.060 0.060 0.060 0.060 0.060 0.060311/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual WholeSale Cost of Power5% $73,816,001 $74,470,259 $74,947,583 $75,299,973 $75,652,362 $5,860,608 $5,860,608 $5,860,608 $5,860,608 $5,860,608 $5,860,608$100 M Grants, Bal. 5% $65,390,529 $66,044,788 $66,522,111 $66,874,501 $67,226,891 $5,860,608 $5,860,608 $5,860,608 $5,860,608 $5,860,608 $5,860,608$150 M Grants, Bal. 5% $61,177,794 $61,832,052 $62,309,376 $62,661,765 $63,014,155 $5,860,608 $5,860,608 $5,860,608 $5,860,608 $5,860,608$5,860,608$200 M Grants, Bal. 5% $56,965,058 $57,619,316 $58,096,640 $58,449,029 $58,801,419 $5,860,608 $5,860,608 $5,860,608 $5,860,608 $5,860,608$5,860,608$250 M Grants, Bal. 5% $52,752,322 $53,406,580 $53,883,904 $54,236,293 $54,588,683 $5,860,608 $5,860,608 $5,860,608 $5,860,608 $5,860,608$5,860,608Accumulated WholeSale Cost of Power5% 73,816,001 443,550,265 816,378,886 1,191,469,190 1,568,321,443 1,876,791,499 1,906,094,538 1,935,397,576 1,964,700,615 1,994,003,653 2,023,306,691$100 M Grants, Bal. 5% 65,390,529 392,997,435 723,698,697 1,056,661,644 1,391,386,538 1,666,154,708 1,695,457,746 1,724,760,785 1,754,063,823 1,783,366,862 1,812,669,900$150 M Grants, Bal. 5% 61,177,794 367,721,020 677,358,603 989,257,871 1,302,919,086 1,560,836,312 1,590,139,351 1,619,442,389 1,648,745,428 1,678,048,466 1,707,351,504$200 M Grants, Bal. 5% 56,965,058 342,444,605 631,018,509 921,854,097 1,214,451,633 1,455,517,917 1,484,820,955 1,514,123,993 1,543,427,032 1,572,730,070 1,602,033,109$250 M Grants, Bal. 5% 52,752,322 317,168,190 584,678,415 854,450,324 1,125,984,181 1,350,199,521 1,379,502,559 1,408,805,598 1,438,108,636 1,467,411,675 1,496,714,713Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,314,192,234$100 M Grants, Bal. 5% $1,164,188,315$150 M Grants, Bal. 5% $1,089,186,356$200 M Grants, Bal. 5% $1,014,184,396$250 M Grants, Bal. 5% $939,182,437411/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine Life +100 kV, DC, Transmission Line From Nenana to Crooked Ck + 138 KV T-Line to Cooked Ck to Bethel, with Demand ChargeBethel+8 villagesYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 20601. Power RequirementsKWs Peak DemandDonlin Gold Mine 70,000 70,000 70,000 70,000 70,000 - - - - - - Villages 2,281 2,630 2,980 3,123 3,266 3,350 3,433 3,433 3,433 3,433 3,433Bethel 9,580 10,995 12,410 13,407 14,403 14,403 14,403 14,403 14,403 14,403 14,403Line Loss 6,900 6,900 6,900 6,900 6,900 500.0 500.0 500.0 500.0 500.0 500.0In Plant Use 0 0 0 00000000Total KW 88,761.24 90,525.44 92,289.63 93,429.37 94,569.10 18,252.55 18,336.00 18,336.00 18,336.00 18,336.00 18,336.00 KWHsDonlin Gold Mine 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 525,600,000.00 - - - - - - Villages 10,295,423 11,782,606 13,269,790 14,645,290 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790 16,020,790Bethel 54,546,206 62,605,493 70,664,781 76,337,072 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364 82,009,364Total KWH Sales 590,441,628 599,988,100 609,534,571 616,582,362 623,630,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154 98,030,154T-Line losses 60,444,000 60,444,000 60,444,000 60,444,000 60,444,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 4,380,000 In Plant Use - - - - - - - - - - - Total kWh Generated 650,885,628 660,432,100 669,978,571 677,026,362 684,074,154 102,410,154 102,410,154 102,410,154 102,410,154 102,410,154 102,410,154 Generation Capacity KWs CFB Coal Plant 0 0 0 00000000Combustion Turbine Bethel 0 0 0 00000000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Bethel Utilities Plant 0 0 0 00000000Total Capacity in KWs 0 0 0 00000000Generation KWHsCoal Plant 0 0 0 00000000Combustion Turbine Bethel 0 0 0 00000000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Purchased Power 650,885,628 660,432,100 669,978,571 677,026,362 684,074,154 102,410,154 102,410,154 102,410,154 102,410,154 102,410,154 102,410,1542. Capital Cost(1)Plant CostsCoal Plant $/kW $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine $/kW Bethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK Mine Bethel Utilities Plant138 kV T-Line/Mile $680,900 $680,900 $680,900 $680,900 $680,900 $0 $0 $0 $0 $0 $0230 AC T-Line/Mile $733,700 $733,700 $733,700 $733,700 $733,700Plant Costs $Coal Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Combustion Turbine Bethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Bethel Utilities PlantTotal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0111/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060138 kV T-Line @ 192 miles $130,732,800 $130,732,800 $130,732,800 $130,732,800 $130,732,800Bethel Diesel Plant $500,000 $500,000 $500,000 $500,000 $500,000 $0 $0 $0 $0 $0 $0230 KV Substation $4,000,000 $4,000,000 $4,000,000 $4,000,000 $4,000,000 $0 $0 $0 $0 $0 $0138 kV Substations $2,000,000 $4,100,000 $4,100,000 $4,100,000 $4,100,000 $0 $0 $0 $0 $0 $0Village Sub.+ Dist. Lines $7,245,000 $7,245,000 $7,245,000 $7,245,000 $7,245,000 $0 $0 $0 $0 $0 $0 + 100 kV DC Line @ 370 miles $271,469,000 $271,469,000 $271,469,000 $271,469,000 $271,469,000 $0 $0 $0 $0 $0 $0AC-DC Conversion Equip. $100,000,000 $100,000,000 $100,000,000 $100,000,000 $100,000,000Total $515,946,800 $418,046,800 $418,046,800 $418,046,800 $418,046,800 $0 $0 $0 $0 $0 $0Tug + 3 Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Enviormental Studies $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $0 $0 $0 $0 $0 $0Fuel Storage Gallons Bethel 0 0 0 00000000CCK 0 0 0 0 0000000 Mine 0 0 0 00000000Fuel Storage Costs $/Gallon Bethel $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37 $1.37CCK MineFuel Storage Costs Bethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total Fuel Oil Storage $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0District Heating System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0SubTotal Capital Costs $521,946,800 $424,046,800 $424,046,800 $424,046,800 $424,046,800 $0 $0 $0 $0 $0 $0Interest During Constuction5% $26,097,340 $21,202,340 $21,202,340 $21,202,340 $21,202,340 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $21,097,340 $16,202,340 $16,202,340 $16,202,340 $16,202,340 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $18,597,340 $13,702,340 $13,702,340 $13,702,340 $13,702,340 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $16,097,340 $11,202,340 $11,202,340 $11,202,340 $11,202,340 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $13,597,340 $8,702,340 $8,702,340 $8,702,340 $8,702,340 $0 $0 $0 $0 $0 $0Total Capital Cost5% $548,044,140 $445,249,140 $445,249,140 $445,249,140 $445,249,140 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $443,044,140 $340,249,140 $340,249,140 $340,249,140 $340,249,140 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $390,544,140 $287,749,140 $287,749,140 $287,749,140 $287,749,140 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $338,044,140 $235,249,140 $235,249,140 $235,249,140 $235,249,140 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $285,544,140 $182,749,140 $182,749,140 $182,749,140 $182,749,140 $0 $0 $0 $0 $0 $0 3. ExpensesAnnual Debt Service5% $43,976,480 $35,727,943 $35,727,943 $35,727,943 $35,727,943 $0 $0 $0 $0 $0 $0$100 M Grants, Bal. 5% $35,551,008 $27,302,471 $27,302,471 $27,302,471 $27,302,471 $0 $0 $0 $0 $0 $0$150 M Grants, Bal. 5% $31,338,272 $23,089,735 $23,089,735 $23,089,735 $23,089,735 $0 $0 $0 $0 $0 $0$200 M Grants, Bal. 5% $27,125,536 $18,877,000 $18,877,000 $18,877,000 $18,877,000 $0 $0 $0 $0 $0 $0$250 M Grants, Bal. 5% $22,912,801 $14,664,264 $14,664,264 $14,664,264 $14,664,264 $0 $0 $0 $0 $0 $0O&M CostsAnnual Fuel RequirementsCoal Tons - - - - - - - - - - - #1 Fuel Oil GallonsBethel - - - - - - - - - - - CCKMine - - - - - - - - - - - Coal $/Ton $45.80 $45.80 $45.80 $45.80 $45.80 $60.00 $60.00 $60.00 $60.00 $60.00 $60.00 #1 Fuel Oil $/GallonsBethel 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ 1.20$ CCKMine211/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual Fuel CostsCoal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 #1 Fuel OilBethel $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0CCK $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Mine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Annual Interest Fuel Supply Loan $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 O&M Tug + Barges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Purchased PwrDemand Charge $/KW $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250 $11.250Energy Charge $/kwh $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045 $0.045Cost of Purchased Pwr $37,389,853 $37,819,444 $38,249,036 $38,566,186 $38,883,337 $6,633,457 $6,633,457 $6,633,457 $6,633,457 $6,633,457 $6,633,457Total $37,389,853 $37,819,444 $38,249,036 $38,566,186 $38,883,337 $6,633,457 $6,633,457 $6,633,457 $6,633,457 $6,633,457 $6,633,457O&MCoal-PlantPersonnel 0 0 0 00000000Equipment/Supplies 0 0 0 00000000Combustion Turbine $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0PersonnelEquipment/SuppliesNuvista Administration $400,000 $400,000 $400,000 $400,000 $400,000 $200,000 $200,000 $200,000 $200,000 $200,000 $200,000 138 kV T-Line $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 $192,000 +230 KV AC Line $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000 $370,000Waste Heat Sales Offset $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total O&M $962,000 $962,000 $962,000 $962,000 $962,000 $762,000 $762,000 $762,000 $762,000 $762,000 $762,000PCE Payments $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0Year 2010 2015 2020 2025 2030 2035 2040 2045 2050 2045 2050Power CostsCapital Cost $/kWh5% $0.074 $0.060 $0.059 $0.058 $0.057 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$100 M Grants, Bal. 5% $0.060 $0.046 $0.045 $0.044 $0.044 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$150 M Grants, Bal. 5% $0.053 $0.038 $0.038 $0.037 $0.037 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$200 M Grants, Bal. 5% $0.046 $0.031 $0.031 $0.031 $0.030 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000$250 M Grants, Bal. 5% $0.039 $0.024 $0.024 $0.024 $0.024 $0.000 $0.000 $0.000 $0.000 $0.000 $0.000Purchased Power $0.063 $0.063 $0.063 $0.063 $0.062 $0.068 $0.068 $0.068 $0.068 $0.068 $0.068 O&M $/kWh $0.002 $0.002 $0.002 $0.002 $0.002 $0.008 $0.008 $0.008 $0.008 $0.008 $0.008 Total $0.065 $0.065 $0.064 $0.064 $0.064 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 BreakEven Cost $/kWh5% $0.139 $0.124 $0.123 $0.122 $0.121 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 $100 M Grants, Bal. 5% $0.125 $0.110 $0.109 $0.108 $0.108 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 $150 M Grants, Bal. 5% $0.118 $0.103 $0.102 $0.102 $0.101 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 $200 M Grants, Bal. 5% $0.111 $0.096 $0.095 $0.095 $0.094 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 $250 M Grants, Bal. 5% $0.104 $0.089 $0.088 $0.088 $0.087 $0.075 $0.075 $0.075 $0.075 $0.075 $0.075 Wholesale Cost$/kWh5% 0.144 0.129 0.128 0.127 0.126 0.080 0.080 0.080 0.080 0.080 0.080$100 M Grants, Bal. 5% 0.130 0.115 0.114 0.113 0.113 0.080 0.080 0.080 0.080 0.080 0.080$150 M Grants, Bal. 5% 0.123 0.108 0.107 0.107 0.106 0.080 0.080 0.080 0.080 0.080 0.080$200 M Grants, Bal. 5% 0.116 0.101 0.100 0.100 0.099 0.080 0.080 0.080 0.080 0.080 0.080$250 M Grants, Bal. 5% 0.109 0.094 0.093 0.093 0.092 0.080 0.080 0.080 0.080 0.080 0.080311/15/2003
Donlin Creek Mine - 60 MW Average Load, 20 Year Mine LifeYear 2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060Annual WholeSale Cost of Power5% $85,280,541 $77,509,328 $77,986,651 $78,339,041 $78,691,431 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$100 M Grants, Bal. 5% $76,855,069 $69,083,856 $69,561,180 $69,913,569 $70,265,959 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$150 M Grants, Bal. 5% $72,642,334 $64,871,120 $65,348,444 $65,700,834 $66,053,223 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$7,885,608$200 M Grants, Bal. 5% $68,429,598 $60,658,385 $61,135,708 $61,488,098 $61,840,487 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$7,885,608$250 M Grants, Bal. 5% $64,216,862 $56,445,649 $56,922,972 $57,275,362 $57,627,751 $7,885,608 $7,885,608 $7,885,608 $7,885,608 $7,885,608$7,885,608Accumulated WholeSale Cost of Power5% 85,280,541 503,912,033 891,935,997 1,282,221,644 1,674,269,239 1,996,920,569 2,036,348,607 2,075,776,646 2,115,204,684 2,154,632,722 2,194,060,761$100 M Grants, Bal. 5% 76,855,069 453,359,204 799,255,809 1,147,414,097 1,497,334,334 1,786,283,777 1,825,711,816 1,865,139,854 1,904,567,893 1,943,995,931 1,983,423,969$150 M Grants, Bal. 5% 72,642,334 428,082,789 752,915,714 1,080,010,324 1,408,866,881 1,680,965,382 1,720,393,420 1,759,821,459 1,799,249,497 1,838,677,535 1,878,105,574$200 M Grants, Bal. 5% 68,429,598 402,806,374 706,575,620 1,012,606,551 1,320,399,429 1,575,646,986 1,615,075,024 1,654,503,063 1,693,931,101 1,733,359,140 1,772,787,178$250 M Grants, Bal. 5% 64,216,862 377,529,959 660,235,526 945,202,778 1,231,931,977 1,470,328,590 1,509,756,629 1,549,184,667 1,588,612,706 1,628,040,744 1,667,468,782Annual Net Income 2,952,208 2,999,940 3,047,673 3,082,912 3,118,151 490,151 490,151 490,151 490,151 490,151 490,151Accumulated Net Income 2,952,208 17,760,981 35,808,357 54,129,633 72,662,342 88,743,247 91,684,152 94,625,056 97,565,961 100,506,866 103,447,770Mine 20 yearPower cost5% $1,518,302,581$100 M Grants, Bal. 5% $1,368,298,662$150 M Grants, Bal. 5% $1,293,296,702$200 M Grants, Bal. 5% $1,218,294,743$250 M Grants, Bal. 5% $1,143,292,784411/15/2003
APPENDIX H
1. Loss of Load Expectation Calculation
2. Coal Cost Projections
3. Coal Plant Efficiencies and Reliability Information
4. EMF Information
5. Permafrost Information
6. Bethel River Bank Erosion Sketch
1. Loss of Load Expectation Calculation
Coal-Fired Plant
Loss of Load Expectation Calculations
For each Steam Generator process line assume FOR of 5%
For combustion turbine assume FOR of 1%
For Existing Bethel Diesel Plant FOR 2%
2x48.6 MW Coal Units+46 MW CT Unit 2x40 MW Coal Units+46 MW CT Unit
+ 10 MW Bethel Diesel Plant
Probability Table for Coal Units Probability Table for Coal Units
Cap. In Cap. Out Probability Cap. In Cap. Out Probability
110 0 0.9025 110 0 0.9025
55 55 0.095 55 55 0.095
0 100 0.0025 0 100 0.0025
Add in 46 MW CT in Service Add in 46 MW CT in Service
Cap. Out Probability Cap. Out Probability
0 0.893475 0 0.893475
55 0.09405 45 0.09405
110 0.002475 90 0.002475
46 MW CT out of Service 46 MW CT out of Service
Cap. Out Probability Cap. Out Probability
46 0.009025 46 0.009025
101 0.00095 91 0.00095
156 0.000025 136 0.000025
Combined Probability Table Combined Probability Table
Cap. Out Cap. In Probability Loss of Load Cap. Out Cap. In Probability Loss of Load
hours/yr hours/yr
0 156 0.893475 0 136 0.893475
55 101 0.09405 45 91 0.09405
46 110 0.009025 79.059 46 90 0.009025 0
101 55 0.00095 8.322 8.322 90 46 0.002475 21.681
110 46 0.002475 21.681 21.681 91 45 0.00095 8.322
156 0 0.000025 0.219 0.219 136 0 0.000025 0.219
Cumulative Total 1 38.544 109.281 1 30.222
Add in 10 MW Diesel Plant in Service
Cap. Out
0 0.8756055
45 0.092169
46 0.0088445
90 0.0024255
91 0.000931
136 0.0000245
Add in 10 MW Diesel Plant iOut of Service
Cap Out.
10 0.0178695
55 0.001881
56 0.0001805
100 0.0000495
101 0.000019
146 0.0000005
Cumulativie Probability Table
Cap. Out Cap. In
0 146 0.8756055
45 101 0.092169
10 136 0.0178695
46 100 0.0088445 77.47782
90 56 0.0024255 21.24738
55 91 0.001881 16.47756
56 90 0.0001805 8.15556
91 55 0.000931 8.15556 1.58118
100 46 0.0000495 0.43362 0.43362
101 45 0.000019 0.16644 0.16644
136 10 0.0000245 0.21462 0.21462
146 0 0.0000005 0.00438 0.00438
8.97462 125.7586
Combine-Cycle Plant
Loss of Load Expectation Calculations
For each combustion turbine assume FOR of 1%
For steam turbine assume FOR of 1%
Bethel Plant Crooked Creek Plant
3x42 MW Simple Cycle Units+25 MW CT Unit 2x42 MW Turbien Units+25 MW CT Unit
Probability Table for Simple Cycle Units Probability Table for Coal Units
Cap. Out Cap. In Probability Cap. Out Cap. In Probability
126 0 0.970299 84 0 0.9801
84 42 0.029403 42 55 0.0198
42 84 0.000297 0 100 0.0001
0 126 0.000001
Add in 25 MW STG in Service Add in 13 MW STG in Service
Cap. Out Probability Cap. Out Cap In. Probability
0 0.9683584 0 0.970299
42 0.02910897 42 0.019602
84 0.00029403 84 0.000099
126 0.00000099
25 MW SGT out of Service 13 MW SGT out of Service
Cap. Out Probability Cap. Out Cap In. Probability
25 0.00970299 13 0.009801
67 0.00029403 57 0.000198
109 0.00000297 97 0.000001
151 0.00000001
Combined Probability Table Combined Probability Table
Cap. Out Cap. In Probability Loss of Load Cap. Out Cap. In Probability Loss of Load
hours/yr hours/yr
0 151 0.9683584 0 97 0.970299
42 109 0.02910897 42 57 0.019602
25 126 0.00970299 84.99819 13 84 0.009801 85.85676 85.857
67 84 0.00029403 2.575703 2.575703 57 42 0.000198 1.73448 1.734
84 67 0.00029403 2.575703 2.575703 2.575703 84 13 0.000099 0.86724 0.867
109 42 0.00000297 0.026017 0.026017 0.026017 97 0 0.000001 0.00876 0.009
126 25 0.00000099 0.008672 0.008672 0.008672 88.46724 88.467
151 0 0.00000001 8.76E-05 8.76E-05 8.76E-05
2.61048 5.186183 90.18438
2. Coal Cost Projections
Table 16. Coal Supply, Disposition, and Prices (Million Short Tons per Year, Unless Otherwise Noted) Supply, Disposition, and Prices 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2001-2025 Production 1/ Appalachia 430 443 407 409 405 414 424 433 429 425 422 418 412 413 415 418 416 415 418 418 419 416 415 418 423 431 -0.1% Interior 144 147 149 154 156 165 168 167 168 167 158 150 147 149 147 150 152 154 153 152 150 152 153 154 156 159 0.3% West 510 548 529 536 541 545 563 588 604 622 651 672 688 696 706 718 731 749 758 775 790 797 813 828 835 850 1.8% East of the Mississippi 518 539 505 513 506 521 534 541 538 534 528 522 513 518 520 526 525 526 529 531 529 529 530 535 542 553 0.1% West of the Mississippi 566 599 580 586 596 603 622 647 662 680 703 718 733 739 748 760 774 792 800 815 829 835 851 866 872 887 1.7% Total 1084 1138 1085 1099 1102 1124 1156 1188 1200 1214 1231 1239 1247 1258 1268 1286 1299 1318 1329 1346 1359 1364 1381 1400 1414 1440 1.0% Net Imports
Imports 13 20 16 16 17 17 18 18 19 19 20 20 21 21 22 22 23 23 24 24 25 26 26 27 27 28 1.4% Exports 58 49 41 40 40 39 38 37 37 36 35 32 31 32 31 29 28 28 28 28 29 27 26 26 26 26 -2.6% Total -46 -29 -25 -24 -23 -22 -21 -19 -18 -17 -15 -11 -10 -10 -9 -6 -5 -4 -4 -4 -4 -1 0 0 1 2 N/A Total Supply 2/ 1038 1109 1060 1075 1080 1103 1135 1169 1182 1197 1215 1228 1236 1248 1259 1280 1294 1313 1325 1342 1355 1363 1381 1400 1415 1442 1.1% Consumption by Sector Residential and Commercial 4 4 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 1.2% Industrial 3/ 65 63 63 64 64 64 64 65 66 66 66 67 67 68 68 68 68 69 69 69 69 70 70 70 71 71 0.5% of which: Coal to Liquids 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N/ACoke Plants 29 26 23 25 25 25 25 25 25 24 24 24 23 23 22 22 22 21 21 20 20 20 19 19 19 18 -1.5% Electric Generators 4/ 983 957 949 966 989 1012 1044 1077 1090 1105 1123 1135 1144 1155 1166 1187 1202 1221 1233 1250 1263 1271 1290 1309 1323 1350 1.4% Total 1081 1050 1040 1059 1082 1106 1138 1172 1185 1200 1218 1231 1239 1250 1261 1282 1297 1316 1328 1345 1358 1366 1384 1403 1418 1444 1.3%
Discrepancy and Stock Change 5/ -43 59 20 16 -3 -3 -3 -3 -3 -3 -3 -2 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 N/A Average Minemouth Price (2001 dollars per short ton) 17.18 17.59 17.01 16.91 16.60 16.50 16.34 16.05 15.68 15.37 14.99 14.78 14.60 14.65 14.63 14.67 14.59 14.49 14.51 14.48 14.38 14.32 14.28 14.24 14.32 14.36 -0.8% (2001dollars per million Btu) 0.81 0.83 0.82 0.81 0.80 0.80 0.79 0.77 0.76 0.75 0.73 0.72 0.71 0.71 0.71 0.72 0.71 0.71 0.71 0.71 0.71 0.70 0.70 0.70 0.70 0.71 -0.7% Delivered Price (2001 dollars per short ton) 6/ Industrial 32.20 32.83 31.96 31.69 31.30 31.14 31.12 30.89 30.53 30.27 29.97 29.80 29.55 29.53 29.39 29.33 29.16 28.96 28.87 28.69 28.40 28.23 28.16 28.00 27.98 27.92 -0.7% Coke Plants 45.43 46.42 44.40 44.08 43.60 43.17 42.93 42.46 42.01 41.67 41.38 40.81 40.67 40.54 40.39 40.03 39.66 39.33 39.20 38.80 38.62 37.93 37.72 37.48 37.37 37.09 -0.9% Electric Generators
(2001 dollars / short ton) 24.85 25.06 24.79 24.89 24.70 24.92 24.67 24.39 24.09 23.81 23.61 23.55 23.39 23.33 23.24 23.16 23.02 22.84 22.76 22.65 22.45 22.33 22.30 22.21 22.22 22.17 -0.5% (2001 dollars / million Btu) 1.23 1.25 1.22 1.22 1.22 1.22 1.21 1.20 1.19 1.18 1.17 1.17 1.16 1.16 1.15 1.15 1.14 1.14 1.13 1.13 1.12 1.11 1.11 1.11 1.11 1.10 -0.5% Average 25.85 26.06 25.67 25.75 25.52 25.70 25.43 25.13 24.82 24.53 24.31 24.22 24.05 23.98 23.87 23.78 23.62 23.43 23.33 23.21 23.00 22.86 22.81 22.71 22.71 22.64 -0.6% Exports 7/ 35.72 36.97 35.52 35.14 34.70 34.33 34.17 33.85 33.45 33.19 32.88 32.18 32.09 32.14 32.30 32.58 32.27 32.12 32.13 31.96 31.89 31.26 31.13 30.99 30.96 30.85 -0.8% 1/ Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 10.1 million tons in 2000 and 10.6 million tons in 2001. 2/ Production plus net imports and net storage withdrawals. 3/ Includes consumption for combined heat and power plants, except those plants whose primary business is to sell electricity, or electricity and heat, to the public. 4/ Includes electricity-only and combined heat and power (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public. 5/ Balancing item: the sum of production, net imports, and net storage withdrawals minus total consumption. 6/ Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7/ F.a.s. price at U.S. port of exit. Btu = British thermal unit. N/A = Not applicable. Note: Totals may not equal sum of components due to independent rounding. Data for 2000 and 2001 are model results and may differ slightly from official EIA data reports. Sources: 2000: Energy Information Administration (EIA), Coal Industry Annual 2000, DOE/EIA-0584(2000) (Washington, DC, January 2002). 2001 data based on EIA, Quarterly Coal Report, October-December 2001, DOE/EIA-0121(2001/4Q) (Washington, DC, May 2002) and EIA, AEO2003 National Energy Modeling System run aeo2003.d110502c. Projections: EIA, AEO2003 National Energy Modeling System run aeo2003.d110502c.
3. Coal Plant Efficiencies and Reliability Information
Energy Power Plan Generating Resources Advisory Committee
DRAFT
Northwest Power Planning Council
New Resource Characterization for the Fifth Power Plan
Coal-fired Power Plants
May 17, 2002
This paper describes the technical characteristics and cost and performance assumptions
to be used by the Northwest Power Planning Council for assessments involving new coal-
fired power plants. The intent is to characterize a typical facility, recognizing that actual
facilities will differ from these assumptions in the particulars. We anticipate using these
assumptions in price forecasting and system reliability assessment models. Others may
use the Council s technology characterizations for their own purposes.
Coal-fired steam-electric power plants are a mature technology, in use for over a century.
Coal-fired power plants are the major source of power in eastern electricity supply
systems and the second largest component of the western grid. Currently, over 36,000
megawatts of coal steam-electric power plants are in service on the western electricity
grid, comprising about 23% of generating capacity. In recent years, however, the
economic and environmental advantages of combined-cycle gas turbines, low load growth
and promise of advanced coal-based technologies with superior efficiency and
environmental characteristics eclipsed conventional coal-fired steam-electric technology,
at least in the United States. Since 1990, less than 500 megawatts of new coal-fired
steam electric plant entered service on the western grid.
The future prospects for coal-fired steam-electric power plants may be changing. Like
reciprocating internal combustion engines, another mature technology, the economic and
environmental characteristics of coal-fired steam-electric power plants have greatly
improved. These factors, combined with the prospect of stable or declining coal prices
may reinvigorate the competition between coal and natural gas and lessen the near-term
prospects for revolutionary coal-based technologies.
The capital cost of coal-fired steam-electric plants has declined about 25% (constant
dollars) since the early 1990s with little or no sacrifice to thermal efficiency, reliability or
environmental performance. This cost reduction is attributable to plant performance
improvements, automation and reliability improvements, equipment cost reduction,
reduced construction schedule, and increased market competition (DOE, 1999). Coal
prices also have declined during this period as a result of stagnant demand and
productivity improvements in mining and transportation. By way of comparison, the
Council s 1991 power plan estimated the overnight capital cost of a new coal-fired
steam-electric plant to be $1775/kW and the cost of Powder River coal at $0.68/MMBtu
(year 2000 dollars). The capital and fuel costs proposed for the Fifth Power Plan are
$1468/kW and $0.71/MMBtu, respectively.
Though the economics have improved, other issues associated with future development
of coal-fired power plants remain largely unchanged. The issues cited in the Fourth Power
Plan - air quality impacts, carbon dioxide and global climate change, water impacts, solid
waste, site availability, coal transportation, electric power transmission and impacts of
coal mining and transportation - remain significant.
The proposed reference plant is a subcritical 400 megawatt pulverized coal-fired unit. It is
one of two or more co-located similar units. Because of increasing constraints on the
availability of water, we assume the plant is equipped with dry mechanical draft cooling.
The plant would be equipped with flue gas desulfurization, fabric filter particulate control
and would use combustion NOx control. In view of cost and performance improvements
achieved in recent years with conventional technology, the potential for further
improvements, and difficulties experienced with development of advanced technologies,
future improvements in cost and performance is based on evolutionary improvements to
conventional technology.
Issues:
• In previous power plans, location-specific coal-fired power plant costs (including
transmission interconnection and site infrastructure) were based on actual
Northwest sites that had been proposed for development. The availability of
capacity for future development was based on the same approach. This approach
no longer appears practical now that power price forecasting and other Council
analyses demand a west-wide view. What approach should the Council use in
expanding the basis plant assumptions to the various load-resource areas used in
the Council s models? What are the important variables among prospective
sites? Do we need to assess possible constraints on resource development?
• What should we assume with respect to future environmental requirements for
coal-fired capacity? Will mercury and other air toxins be controlled and how
would plant cost and performance be affected? The reference design does not
include selective catalytic reduction (SCR) for additional NOx control. Should we
assume that SCR would be typically installed on new plants.
• The proposed scheduled outage factor seems high (~30 days/yr) but is consistent
with GADS data and new plant design objectives. Do this assumption require
revision?
• Our current assumption regarding future technology development is limited to
heat rate improvement and is taken from the Energy Information Administration
Annual Energy Outlook 2002. The basis is unclear. Should we look at an
alternative approach, e.g. adoption of some advanced technology or achievement
of US DOE performance goals by some future date?
• Capital replacement assumptions affect the retirement of existing capacity in
power price forecasting and other modeling. Are the proposed assumptions
realistic?
References
DOE (1999): US Department of Energy. Market-based Advanced Coal Power Systems.
March 1999.
EIA (2001): US Department of Energy, Energy Information Administration. Assumptions
to the Annual Energy Outlook 2002. December 2001.
Table 1: Resource characterization: Coal-fired power plants
Facility 400 MW (nominal) pulverized coal-fired subcritical steam-
electric plant, 2400 psig/1000oF/1000oF reheat. Dry
mechanical draft cooling. Low-NOx burners; lime spray
Reference plant from DOE, 1999,
modified to suit western coal and
site conditions.
dryer; fabric particulate filter. Reference plant design.
Co-sited with one or more additional units.
Fuel Western subbituminous coal. 9300 Btu/lb, 0.4% S. Characteristics are for Powder River
Basin coal.
Technology
base year
2000 Fifth plan base year.
Price base
year
2000 Fifth plan base year.
Net power
output
New & clean: 385 MW
Lifetime average: 374 MW
DOE (1999) Derated 3% for dry
cooling.
Average degradation based on 4th
plan GT values.
Lead time Development: 36 months
Construction: 36 months
Development shortened from 4th
plan 48 months.
Availability Scheduled outage factor: 9%
Forced outage rate: 7%
Mean time to repair: 40 hours
Availability: 85%
Availability factors based on 1995 -
99 GADS, but consistent w/DOE
(1999) reduced redundancy design.
Heat rate
(HHV)
New & clean: 9350 Btu/kWh
Lifetime average: 9550 Btu/kWh
Vintage improvement: -0.34%/yr
DOE (1999), increased 3% for dry
cooling.
Average degradation based on 4th
plan GT values.
Vintage improvement From EIA
(2001)
Service life 30 years DOE (1999). Reduced from 4th
Power plan (40 yrs).
Capital cost Development: $25/kW
Construction (Overnight): $1403/kW
Startup: $26/kW
Working capital: $14/kW
Development cost factors from 4th
Plan.
Construction, startup & working
capital from DOE (1999) plus
estimated dry cooling, land &
owner s admin costs. No allowance
for site infrastructure.
Capital
replacement
To 30 yrs: $15/kW/yr
Over 30 yrs: $20/kW/yr
EIA (2001).
Non-fuel O&M
cost
Fixed O&M : $25/kW/yr
Property Tax: $20/kW/yr
Insurance: $4/kW/yr
Variable: $0.5/MWh
Vintage improvement: 0%/yr
DOE (1999) except prop tax &
insurance. Prop tax & insurance
1.4% & 0.25% assessed value,
respectively.
Financing IPP See Table 2 (To follow)
SOx Calculation to be supplied 95% removal
NOx 4.09 lb/Mwh (2.05 T/GWh) DOE (1999) Est. 2005 BACT
Particulates 0.272 lb/Mwh (0.136 T/GWh) DOE (1999) Est. 2005 BACT
CO2 Calculation to be supplied
Site
Availability
The current AURORA run (with no limits on new capacity)
result in the following build levels by 2020: AB - 700 MW,
CO 1750 MW, ID 3150 MW, MT 350 MW, WY 1140 MW.
April 17, 2001
Review of Potential Efficiency Improvements
at Coal-Fired Power Plants
Introduction
The Clean Air Markets Division, U.S. Environmental Protection Agency requested
that Perrin Quarles Associates, Inc., perform a review of readily available data on potential
and actual efficiency improvements at coal-fired utilities. The objective was to identify
heat rate reductions or efficiency improvements that have taken place due to either
optimization efforts at existing utility boilers or due to the use of newer advanced
technologies for coal combustion.
A unit’s efficiency in this context refers to its thermal efficiency and is defined as a
percentage determined by the electrical energy export divided by the fuel energy input.
Fuel energy input can be defined either on a higher heating value (HHV) or lower heating
value (LHV) basis. HHV is the full energy content of a fuel including the latent heat of
vaporization of water, while LHV excludes the energy in the water vapor from the fuels
hydrogen. The HHV will be about 5 to 10 percent higher than LHV. In the United States,
fuel energy content is generally measured in terms of HHV, and HHV is used in Energy
Information Agency statistics. Internationally, LHV is more often used. For this report,
all efficiencies are reported on an HHV basis. Efficiency is also commonly represented by
the heat rate, which is the reciprocal of the thermal efficiency and is described in the units
of Btu/kWh.
This document discusses the range of heat rates and efficiencies associated with
coal-fired power plants including the improved heat rates that have been achieved at some
of the more recently constructed state-of-the-art coal-fired facilities. The following is a
general discussion of this issue in the context of several different types of coal-fired
plants. Note that the information in this report is based on a search of documents currently
available on the Internet. More extensive research that may lead to additional data and
supporting documentation could entail contacting EIA at DOE or individual facilities for
additional information, particularly with respect to actual heat rates or efficiency
percentages.
Conventional Pulverized Coal Plants
Current Heat Rates
Unit efficiency, or heat rate, is a function of unit design, size, capacity factor, the
fuel fired, maintenance condition of the unit, and operating and ambient conditions
(cooling water temperature). Existing pulverized coal boilers operating today in the U.S.
use subcritical or supercritical steam cycles. A supercritical steam cycle normally operates
above the water critical temperature (705 F) and critical pressure (3210 psia) where water
can exist only in the gaseous phase. Subcritical systems historically have achieved
thermal efficiencies of 33 to 34 percent ( 10,300 Btu/kWh to 10,000 Btu/kWh).
Supercritical systems achieve thermal efficiencies 3 to 5 percent higher than subcritical
Efficiency Improvements
April 17, 2001
Page 2
1Kitto, J.B., Babcock & Wilcox, Developments in Pulverized Coal-Fired Boiler
Technology, presented to the Missouri Valley Electric Association Engineering Conference, April
1996. http://www.babcock.com/pgg/tt/pdf/BR-1610.pdf
2Burr, M. T., Holding companies rule; top 10 sell 28% of U.S. electricity, Electric Light
and Power, October 1999.
3Levy, E. and N. Sarunac, Technical Review of EPA's Proposed Output Monitoring
System, Lehigh University Energy Research Center, September 2000.
systems.1 Table 1 summarizes heat rate data for the 25 best performing utility coal-fired
plants, and 50 best performing utility company coal-fired fleets in the U.S. The data were
prepared for Electric Light and Power’s annual top 100 utility operating report.2
Table 1: Best Coal Fired Heat Rates -- U.S. Utilities
Lowest Reported
Annual Average
Heat Rate
(Btu/kWh)
Highest Reported
Annual Average
Heat Rate
(Btu/kWh)
Average of the
Reported Annual
Average Heat Rates
(Btu/kWh)
25 Best Performing
Coal-Fired Plants
8996 9486 9309
50 Best Performing
Coal-Fired Fleets
9382 10,146 9854
Data on heat rates are taken from Electric Light and Power’s annual top 100 utility operating
report (EL&P, 1999), and were prepared by Navigant Consulting. Heat rates are from 1998
or 1997. The report noted that utility methods for determining the heat rate values are
inconsistent.
Heat Rate Improvements at Existing Plants
Many conventional pulverized coal-fired power plants have made improvements to
their systems that have, in turn, led to improvements in the plant’s efficiency or heat rate.
The extent to which heat rates can be improved at existing plants is estimated to be at best
3 to 5 percent.3 This is because heat rate is primarily dependent on unit design, fuel, and
capacity factor, and the design of a plant can not be changed once built. The literature
reviewed reported heat rate improvements consistent with the 3 to 5 percent improvement
estimate.
Table 2 summarizes some of the potential actions that could be taken to improve
plant efficiencies. Even though these data are based on the higher moisture "brown coal"
or lignite typically used only in certain areas, such as Australia, Germany, Russia, and
certain portions of the U.S., some of the actions may also be applied in the context of the
lower moisture "black coal" or bituminous that is typically used in the U.S. These actions
include those that would help restore the plant to its design conditions, change existing
operational settings, or install retrofit improvements.
Efficiency Improvements
April 17, 2001
Page 3
4Sinclair Knight Merz Pty. Ltd., Integrating Consultancy - Efficiency Standards for
Power Generation, Australian Greenhouse Office, January 2000, p. 38.
http://www.greenhouse.gov.au/markets/gen_eff/skmreport.pdf
Table 2: Measures that may Improve the Efficiency of Coal-Fired Power Plants4
Action* Efficiency Improvement (%)
Restore Plant to Design Conditions
Minimize boiler tramp air 0.42
Reinstate any feedheaters out of service 0.46 - 1.97
Refurbish feedheaters 0.84
Reduce steam leaks 1.1
Reduce turbine gland leakage 0.84
Changes to Operational Settings
Low excess air operation 1.22
Improved combustion control 0.84
Retrofit Improvements
Extra airheater surface in the boiler 2.1
Install new high efficiency turbine blades 0.98
Install variable speed drives** 1.97
Install on-line condenser cleaning system 0.84
Install new cooling tower film pack** 1.97
Install intermittent energisation to ESPs 0.32
* Note that the efficiency improvements expected as a result of implementation of these actions may not be
additive and the feasibility and improvements associated with each action may vary based on plant
configuration.
** The expected efficiency improvements associated with these actions may be overestimated.
Wisconsin Electric Power Company (WEPCO) has implemented a number of
actions to improve the efficiency or heat rate at certain coal-fired plants, some of which
are included in Table 2 above. The efficiency improvements as reported in the Climate
Challenge Participation Accord between WEPCO and the Department of Energy (DOE)
are summarized in Table 3. Efficiency improvements over a 5 year period ranged from
2.3 percent to 4.1 percent. In the Accord, WEPCO also committed to other efforts to
improve heat rates including: various equipment control upgrades such as distributed
control systems, precipitators and turbine controls; metering upgrades; boiler chemical
cleaning; feedwater heater improvements; reduced condenser air in-leakage; and reduced
Efficiency Improvements
April 17, 2001
Page 4
5Wisconsin Electric Power Company Climate Challenge Participation Accord (agreement
with DOE), Appendix A (Wisconsin Energy Emission Reduction/Sequestration Project
Descriptions), Section 2 - Supply Side Energy Efficiency.
http://www.eren.doe.gov/climatechallenge/cc_accordxWISCEL.htm
thermal losses. WEPCO estimated a 0.5 percent annual company-wide heat rate
improvement due to these additional efforts over a period from 1995 - 2000.
Table 3: Example Heat Rate Improvements at Wisconsin Electric Plants
Due to Operational Changes (1990 - 1994)5
Plant
Original
Heat Rate
(Btu/kWh
HHV)
Improved
Heat Rate
(Btu/kWh
HHV)
Efficienc
y
Increase
(%)
Description of Efficiency
Improvement Projects
Oak Creek 9,802 9,424 3.9 Variable pressure operation,
distributed control system, retractable
turbine packing, variable speed drives
on the forced and induced draft fans,
reduced air in-leakage, feedwater
heater replacements, increased
availability and capacity factor and
precipitator energy management
system
Pleasant
Prairie
11,157 10,796 3.2 Variable pressure operation, unit and
equipment performance monitoring,
retractable turbine packing, reduced air
in-leakage, increased availability and
variable speed drive make-up water
pumps
Presque Isle 11,565 11,089 4.1 Retractable turbine packing, increased
availability and capacity factor,
reduced air in-leakage, reduced excess
boiler O2, boiler chemical cleaning,
CO monitors on the boiler, improved
turbine pressure and updated or
additional instrumentation
Efficiency Improvements
April 17, 2001
Page 5
6Perrin Quarles Associates, Inc., Review of Utility Coal-Fired Boiler Optimization
Papers, Appendix, August 2000.
7Lester, E., Minimization of Global Climate Change Using Clean Coal Technology,
American Institute of Chemical Engineers, August 1998, p. 5.
http://www.aiche.org/government/pdfdocs/cleancoal.pdf
Table 3: Example Heat Rate Improvements at Wisconsin Electric Plants
Due to Operational Changes (1990 - 1994) (cont.)
Plant
Original
Heat Rate
(Btu/kWh
HHV)
Improved
Heat Rate
(Btu/kWh
HHV)
Efficienc
y
Increase
(%)
Description of Efficiency
Improvement Projects
Valley 13,938 13,623 2.3 Last row turbine blade replacement,
retractable turbine packing, variable
speed drives for the forced and
induced draft fans, superheater surface
change, reduced air in-leakage,
reduced pulverizer primary air velocity
and increased availability and capacity
factor
PQA has previously reviewed literature for CAMD on NOx reductions and
efficiency improvements resulting from the installation of combustion optimization
software, such as NeuSIGHT, ULTRAMAX, and GNOCIS. The software works with a
boiler's digital control system to optimize and control boiler settings. Efficiency
improvements from the combustion optimization ranged from 0.3 to 3 percent.6
New Pulverized Coal Plants
In addition to the potential for efficiency improvements at existing conventional
pulverized coal-fired plants through operational changes and equipment upgrades, there is
also the potential for dramatically reduced heat rates through the use of pulverized coal-
fired power plants built with more advanced technologies.
A Low Emissions Boiler System (LEBS) based on the direct combustion of
pulverized coal emphasizes improvements in technology and processes that are already
widely accepted. These types of facilities include a high-efficiency pulverized coal boiler
integrated with other more efficient combustion techniques and advancements in emission
control technologies. The more advanced versions of these facilities may achieve up to 44
percent efficiency and are expected to be currently commercially available.7
In the context of these newer units, a 400 MW pulverized coal power plant design
based on the utilization of pulverized coal feeding a conventional steam boiler and steam
Efficiency Improvements
April 17, 2001
Page 6
8U.S. Department of Energy, Office of Fossil Energy, Market Based Advanced Coal
Power Systems, Section 3 -- Pulverized Coal-Fired Plants, May 1999, DOE/FE-0400, p. 3.1-5,
3.2-2, and 3.3-2.
http://www.fetc.doe.gov/coal_power/special_rpts/market_systems/market_sys.html
9Sinclair Knight Merz Pty. Ltd., Integrating Consultancy -- Efficiency Standards for
Power Generation, Australian Greenhouse Office, January 2000, p. 6.
turbine, as well as state-of-the-art technology and components currently available in the
market, could achieve heat rates as low as 8,251 Btu/kWh, depending on the specific
design of the facility. Design data for these types of facilities are summarized in Table 4
below.
Table 4: Heat Rate Data for Subcritical, Supercritical, and Ultra-Supercritical
Coal-Fired Power Plants (Design Data Based on a 400 MW Facility)8
Type of Plant
Steam
Pressure
(psig)
Steam
Temperature (F)
Expected Heat
Rate (Btu/kWh)
Subcritical (conventional
pulverized coal plant with
emission control systems to
meet current air quality
standards)
2400 psig 1000F/1000F 9,077
Supercritical (single reheat
configuration with emissions
control systems to meet air
quality standards expected in
2005)
3500 psig 1050F/1050F 8,568
Ultra-Supercritical (double
reheat configuration with
emissions control systems to
meet air quality standards
expected in 2010)
4500 psig 1100F/1100F/1100F 8,251
Another source includes data from coal-fired plants in North America, Europe, and
Japan, and cites the best practice thermal efficiency rates at 37.7 percent and 41.7 percent
for subcritical and supercritical plants, respectively, for facilities similar in size to those
referenced above.9
An examination of this new generation of coal burning plants internationally have
revealed that several are capable of achieving efficiencies above 40 percent through the
use of low condenser pressures, high steam pressures and temperatures, double reheat
cycles, up to ten stages of feed heating and other changes to station parameters and
Efficiency Improvements
April 17, 2001
Page 7
10Sinclair Knight Merz Pty. Ltd., p. 59.
configuration of equipment. These plants and their corresponding efficiencies are
summarized in Table 5 below.
Table 5 - International "Black Coal" Power Plants
with High Design Thermal Efficiencies10
Plant Online
Size
(MW)Steam Temperature (F)Design Thermal
Efficiency (%) HHV
Staudinger 5 1992 550 1004/1040 41.1*
Rostock 1994 550 1004/1040 42
Esbjerg 1992 400 1036/1040 43.2*
Nordjylland-
svaerket
1998 400 1076/1076/1076
(double reheat cycle)
44.9
Lubeck 1998 440 1076/1112 43.6
Bexbach II 2002
(projected)
750 1067/1103 44.2
* Note that these estimated thermal efficiencies have been confirmed through testing and/or operating
experience.
Combined Cycle Operations at Coal-Fired Power Plants
Coal-fired power plants have historically been limited to the simple cycle method.
However, recent technological developments have led to the capability of powering
"combined-cycle" generators. Under DOE Initiatives, two new technologies -- Pressurized
Fluid Bed Combustion and Integrated Gasification Combined Cycle (IGCC) -- have
allowed for combined cycle operations in the context of coal-fired facilities. These
facilities have dramatically improved efficiencies or heat rates as compared to
conventional pulverized coal-fired facilities.
Pressurized Fluid Bed Combustor
One study examined the efficiency benefits of using more advanced technologies
such as the pressurized fluid bed combustor. Using a standard pulverized coal plant (294
MW with a heat rate of 9009 Btu/kWh) as a reference point, the efficiency benefits of
using more advanced technologies were evaluated. A facility similar to the reference plant
that utilizes a pressurized fluid bed combustor system may be able to achieve heat rates
between 7,040 Btu/kWh and 8,679 Btu/kWh depending on the type of technology. A
"bubbling bed" pressurized fluid bed combustor could lead to a heat rate of about 8,679
Btu/kWh, while a "first generation" or "second generation" pressurized fluid bed
Efficiency Improvements
April 17, 2001
Page 8
11Bonk, D., and M. Freier, U.S. Department of Energy, and Buchanan, et. al., Parsons
Power, Assessment of Opportunities for Advanced Technology Repowering, p. 3. , Proceedings of
the Advanced Coal Based and Environmental Systems Conference, Pittsburgh, July 22 - 24, 1997.
http://www.fetc.doe.gov/publications/proceedings/97/97ps/ps_pdf/PS1-7.PDF
12Market Based Advanced Coal Power Systems, Section 5 -- Circulating Pressurized Fluid
Bed Combustor, U.S. Department of Energy, May 1999, p.5-5.
13Sinclair Knight Merz Pty. Ltd., pp. 59-60, 66-67.
14Bonk, D. and M. Freier, and Buchanan, et. al., p. 3-4.
15DOE Fossil Energy Techline, "Fourth Clean Coal Plant to Win Powerplant Award Sets
Record Operation for Coal Gasifier in Early 1997." February 18, 1997.
http://www.fe.doe.gov/techline/tl_wab96.html
16Clean Coal Today, "Tampa Electric's Greenfield IGCC Ready for Demonstration,"
Office of Fossil Energy, U.S. Department of Energy, DOE/FE-0215 P-24, No. 24, Winter 1996.
combustor could lead to heat rates of 8,506 Btu/kWh and 7,040 Btu/kWh, respectively.11
Another DOE study also confirms heat rates in this range for a pressurized fluid bed
combustor.12
Combustors the size of 70 to 80 MW have been in operation for a number of years.
Recently, some larger combustors have been constructed. A 350 MW combustor is under
construction in Japan and the expected efficiency is 41 percent. There is the potential to
reach 43 percent in future plants. However, based on operational data from one existing
plant, the overall net efficiency is approximately 38.2 percent.13
Integrated Gasification Combined Cycle
The DOE/Parsons study referenced above also examined the benefits of using an
Integrated Gasification Combined Cycle (IGCC) system, which is capable of achieving
heat rates between 7,374 Btu/kWh and 7,581 Btu/kWh, depending again, on the type of
technology used.14
There have been some successful examples of plants that have recently
demonstrated the IGCC technology. The Wabash River Coal Gasification Power Plant in
West Terre Haute, IN and the Polk Power Plant in Polk County, Florida are two IGCC
systems that have been successful at improving efficiencies. The Wabash River project
repowered the oldest of six pulverized coal units using a "next-generating" coal gasifier,
an advanced gas turbine and a heat-recovery steam generator. The 265 MW unit began
operation in December 1995 and the design heat rate for the repowered unit is 9,034
Btu/kWh (approximately 38 percent efficiency).15 The Polk Power Plant has a similar
efficiency estimated at 39.7 percent and the heat rate is estimated at approximately 8,600
Btu/kWh.16
Efficiency Improvements
April 17, 2001
Page 9
17"The Wabash River Coal Gasification Repowering Project - An Update," Clean Coal
Technology, Topical Report #20, September 2000.
http://www.lanl.gov/projects/cctc/topicalreports/documents/topical20.pdf
18"Tampa Electric Integrated Gasification Combined-Cycle Project - An Update," Clean
Coal Technology, Topical Report #19, July 2000.
http://www.lanl.gov/projects/cctc/topicalreports/documents/topical19.pdf
19Sinclair Knight Merz Pty. Ltd., pp. 59, 66.
20Market Based Advanced Coal Power Systems, Section 4 -- Integrated Gasification
Combined Cycle, DOE, May 1999, p. 4.3-5.
Recent data on actual operational results shows that these facilities have achieved
efficiencies that are similar to the design values. The overall net thermal efficiency for the
Wabash River IGCC facility has been 39.7 percent.17 The overall net thermal efficiency
for the Polk Power Station has been 36.5 percent with an overall heat rate of 9350
Btu/kWh. The efficiency for the Polk Station has been slightly lower than expected due to
problems with the gasifier and low carbon conversion. These and other issues have been
recently addressed and certain operational changes are expected to lead to a thermal
efficiency of around 38 percent.18
One study notes that the efficiency of IGCC plants is expected to be around 42
percent and there is the potential to achieve 49 percent when higher efficiency gas turbines
become available.19 One DOE study estimates the thermal efficiency of an IGCC plant
slightly lower at 40.1 percent with a heat rate of 8,522 Btu/kWh. This estimate assumes a
540 MW facility with a plant configuration based on the technology demonstrated at the
Wabash IGCC facility but incorporates a new steam turbine. However, this study also
describes IGCC facilities of similar size based on more advanced technologies (some of
which of which are not yet commercially available) that could achieve an efficiency and
heat rate of up to 49.7 percent and 6,870 Btu/kWh, respectively.20
4. EMF Information
ACCURATE FORMULAE OF POWER LINE MAGNETIC FIELDS
83
ACCURATE FORMULAE OF POWER LINE MAGNETIC FIELDS
G. FILIPPOPOULOS D. TSANAKAS
gfilippo@eeae.nrcps.ariadne-t.gr Tsanakas@ee.upatras.gr
DEPARTMENT OF ELECTRICAL AND COMPUTER ENGINEERING
UNIVERSITY OF PATRAS
26500, RION, GREECE
Abstract
Accurate mathematical formulae of the magnetic field around some commonly used configurations of power
lines are derived. This is achieved by the use of two copies of the complex numbers set. The one copy, named
Ci, is used to represent the vectors in the vertical plane (where the magnetic flux density vector is considered).
The other copy, named Cj, is used to represent the sinusoidal varying quantities as phasors. The rotating vector
of the magnetic flux density occurs as a combination of the two complex number sets, belonging to the set of the
Cartesian product Ci x Cj, named double complex numbers. The magnetic flux density vector, as a double
complex number is described through remarkably simple relations, making the development of accurate
mathematical formulae for it possible. These formulae express the magnetic flux density vector as a function of
the line geometrical parameters and the relative distance from it. Similar formulae for the resultant value of the
magnetic field, a commonly used quantity to describe the magnetic field, are also derived. As examples accurate
formulae of the magnetic field around single circuit power lines in flat, vertical and delta configurations and
hexagon lines in various configurations are presented.
1 Introduction
The last decades, the magnetic fields produced around power lines are considered as an environmental factor.
The calculation of the magnetic field values at ground level under a power line is usually made arithmetically
with the use of a computer [1]. However, the arithmetic calculation does not allow an insight at the magnetic
field properties and its dependencies of the various parameters of the setting. For example, the magnetic field at
ground level is calculated at a specific distance from the line axis and considering a specific height of the
conductors to the ground. This calculation is repeated for various distances in order to get the magnetic field
profile. For different conductor heights or if there is a change in the line arrangement, the whole process must be
repeated. Also the results refer to a specific line and cannot be easily generalized. However, computational
investigations are made in order to reach some general conclusions about the ability of some power line
configurations to reduce the produced magnetic fields. For example, double circuit lines in low reactance
configuration and compact lines were found to reduce the magnetic fields in [2, 3].
In [4] some approximate formulae of the magnetic field were presented. These formulae were based on the
multipole expansion of the magnetic field and are precise at relative big distances from the line in comparison to
the distances between its conductors. These formulae are very useful in the determination of the way the
magnetic field decays away from a power line. For example, the fast reduction of the magnetic field away from a
double circuit line in low reactance phasing was explained: placing the conductors in such a way that the first
terms of the multipole expansion is zeroed, the magnetic field far from the line is minimized. However, these
formulae do not show the behaviour of the magnetic field under the line, where there usually is an increased
interest. In most cases it is important to know the magnetic field maximum value under the line and where it
appears. In this paper accurate mathematical formulae of the magnetic field around some commonly used
configurations of power lines are derived.
G. FILIPPOPOULOS D. TSANAKAS
84
In [1,2,3,4] the complex numbers were preserved as phasors to represent the sinusoidal varying quantities. In this
paper, complex numbers are also used to represent the vectors in the traverse plane to the conductors, where the
magnetic field is considered. This is possible if a system with two imaginary units is used. In [5] many
imaginary units are used, reaching to systems of hypercomplex numbers. So the innovation of this approach is
the simultaneous use of complex numbers to represent plane vectors and phasors. After this representation the
magnetic field rotating vector is represented by a new set of numbers, named double complex numbers. These
numbers are a combination of the complex numbers representing plane vectors with the complex numbers
representing sinusoidal varying quantities. The double complex numbers and their basic properties, from a
mathematical point of view, are briefly discussed in the Appendix.
As to denotation bold letters are used for vectors, underlined letters for phasors and bold underlined letters for
double complex numbers. Also small letters indicate instantaneous values and capital letters rms values.
2 Magnetic field calculation using double complex numbers
Figure 1 shows the space arrangement of the
conductors of a power line in relation to the
xyz axes system. The line route is considered
straight and parallel to the z-axis. The line
conductors are not straight but they are
sagged by their weight. The curve that is
drawn by each conductor at a span between
two sequential suspension points is known as
the catenary curve. In order to simplify the
calculations and the analysis of the magnetic
field produced by the line; the model of an
assembly of horizontal conductors in z-axis
is used. This model is precise in the
prediction of the magnetic fields if the
conductor sag is small in comparison to the
span. A typical value for high voltage line
conductor sag is 10m for a span of 350m.
z
x
y
z = zo
h(z)
Figure 1. Space arrangement of the conductors of a power line.
Figure 2 shows a traverse section of a power line modelled as an assembly of three conductors parallel to z-axis.
This section is actually the xy plane, where the conductors are shown as single points. The conductor k is caring
the current ik towards the positive z-axis direction. The magnetic flux density bk which is created by the k
conductor, is given by the Ampere law:
()kz2
k
k0
k ˆRπ2
iµReb×= (2-1)
where mA
sV10π4µ7
o
−= is the magnetic permeability of free space, kˆe is the unit vector in the direction of z-
axis, kR is the vector distance from the k conductor to the point of interest P and the symbol × denotes the
cross product of the vectors kˆe and kR .
In the general case a line with n conductors may be considered.
Using the superposition theorem, the magnetic flux density b
produced by the line is the vector sum of the fields produced by
each conductor separately:
()∑∑
==
×==n
1k
2
k
kzko
n
1k
k R
ˆi
π2
µRebb (2-2)
Equation (2-2) could be simplified if the
vector distances on the xy plane were
represented as complex numbers. On the
other hand, for ac lines the conductor
currents are sinusoidal quantities
represented by phasors, which are also
complex numbers. It is clear that having
only one set of complex numbers does
ACCURATE FORMULAE OF POWER LINE MAGNETIC FIELDS
85
not allow the simultaneous representation of the vectors in the
xy plane and the current phasors. In order to solve this problem
two copies of the complex numbers set are used: 1) The set Ci
of the complex numbers with the imaginary unit i (1i2−=)
and 2) the set Cj of the complex numbers with the imaginary
unit j and (1j2−=). It is noted that ji≠.
i3
i2
P
R1
y
x
b1
z
i1
Figure 2. Traverse section of a power
line model.
The set Ci is used for the representation of vectors on the xy plane. Each vector on the xy plane R = yxˆyˆx ee+
(xˆe and yˆe are the unit vectors on x and y axis) is represented by the complex number =R x + iy. Using this
representation, the factor ()2
kkzRˆRe× in (2-2) is written as kiR , where kR is the conjugate complex
number of kR (kR = x - iy) and the factor i is used to enter a π/2 rotation instead of the outer product with the
unit vector zˆe .
The set Cj is used for the representation of sinusoidal quantities as phasors. Each sinusoidal quantity
()kkkφtωcosI2i+= is represented by the complex number kφj
kkeII= through the relation
()tωj
kk eIRe2i=. Using these representations, (2-2) gives:
()tωj
j eRe2Bb= (2-3)
where ∑
=
=n
1k k
koI
π2
µi
RB (2-4)
The vector b is represented by B , which is a double complex number (described in the Appendix). The term
jRe is an expansion of the real function, meaning the real part of the double complex number as to the
imaginary unit j: ()ibaijdjcibaRej+=+++.
The double complex number B may be written in the following forms:
yxBiB+=B irjBB+=yixiyrxrBijBjBiB+++= (2-5)
The phasors xB and yB represent the
components of b on x and y-axis, respectively,
which are sinusoidal quantities. The vectors rB
and iB are refer to the real and imaginary part
of b, expressed by the relations:
∑
=
=n
1k k
r,ko
R
I
π2
µi
RB ∑
=
=n
1k k
i,ko
i
I
π2
µi
RB (2-6)
where r,kI and i,kI are the real and the imaginary part of
the current kI.
The vector b as a function of time (2-3), traces an
ellipse. Figure 3 shows this ellipse defined by its major
G. FILIPPOPOULOS D. TSANAKAS
86
semi-axis Ba and its minor semi-axis Bb. The
factor 21 is used to convert the maximum
instant values to rms values. However, a very
significant parameter of the magnetic flux
density is its resultant value B, which is equal to
the magnitude of the double complex number
B :
x
y
Ba
Bb
Bax
Bay
Bbx
Bby 2
b
Figure 3. The ellipse described by the vector b.
()()()2
1
2
yi
2
xi
2
yr
2
xr2
1
2
i
2
r2
1
2
y
2
x BBBBBBBBB+++=+=+==B (2-7)
3 Multipole expansion of the magnetic flux density
Figure 4 shows again the traverse section of a power line. The currents are characterized by their phasors kI and
the place of the k conductor is characterized by its vector distance dk from a reference point Ο, which is a central
point of the line. The point O is close to but not necessarily the centre of the conductor arrangement.
The vector R defines the distance from the point O to the point
of interest P. Replacing the distance of the point of interest P
from the conductor k: kkdRR−=, and using the equation
()∑∞
=
−−=−
1λ
λ1λ
k
1
k RddR (valid for kdR>) in (2-4), it results
the multipole expansion of the magnetic field flux density:
B ()∑∞
=
=
1λ
λB (3-1)
where: ()λB λ
λο
π2
µi
R
M= (3-2)
and ∑
=
−Ι=n
1k
1λ
kkλdM (3-3)
I2
P
R
y
x
B1
I1
I3
Od1
Figure 4. Traverse section of a power line
model noting the reference point O.
The multipole expansion is the expression
of the magnetic flux density as a sum of
succeeding terms that inversely depend with an increasing force
of the distance R. Each term ()λB of this sum is called λ order
ACCURATE FORMULAE OF POWER LINE MAGNETIC FIELDS
87
term of the magnetic flux density and is
expressed through (3-2). The factor ëM
is called the λ order moment of the
magnetic flux density. Both double
complex numbers ()λB and λM express
elliptical rotating vectors. The term ()λB
may be calculated through the calculation
of the moment λM and the distance from
the line R. Figure 5 shows the relation
between the ellipse traced by 2M and the
ellipse traced by ()2B at deferent places
around the line.
The general expression of the magnetic
flux density λ order term is due to the
capabilities of the double complex to
express the elliptical rotating vectors. It
should be noted that in [4] only the first
four terms of the magnetic flux density
multipole expansion were derived. Also
in [4] the magnetic field away from the
power line was approximated with the
first non-zero term of the multipole
expansion.
R
M2
B(2)
φR
2φR
Figure 5. Relation between the ellipses defined by 2M and
)2(B .
4 Single circuit lines
The magnetic flux density around a single circuit line consisting of three phase conductors (a, b and c) is derived
from (2-4) as
B
−
Ι+−
Ι+−
Ι=
c
c
b
b
a
aο
π2
µi
dRdRdR (4-1)
Making some manipulations, (4-1) is written as:
()()()()[]
()()cbabacacb
2
cba
3
cbabcaacbcbabcaacb
2
cbaο
π2
µi
dddRddddddRdddR
ddddddRddddddRB++++++−
Ι+Ι+Ι+Ι++Ι++Ι+−Ι+Ι+Ι= (4-2)
Considering the phases abc consist a positive sequence system, their currents are related according to:
IIa=, IaI2
b = and IaIc= (4-3)
where 3/π2jea=.
Replacing these equations in (4-2), it becomes:
G. FILIPPOPOULOS D. TSANAKAS
88
()
()()cbabacacb
2
cba
3
baca
2
cbcb
2
aο aaaa
π2
µi
dddRddddddRdddR
ddddddRdddB−+++++−
+++++Ι= (4-4)
The resultant value of the magnetic flux density is calculated by (4-3) as B=B.
()
()()cbabacacb
2
cba
3
baca
2
cbcb
2
aο aaaa
π2
IµB dddRddddddRdddR
ddddddRddd
−+++++−
+++++= (4-5)
Equations (4-4) and (4-5) get much simpler forms when they refer to specific configurations of lines. Table 1
gives the expressions for the magnetic flux density vector and its resultant value for the three most commonly
used configurations of single circuit lines.
Table 1. Accurate formulae of the magnetic flux density vector B and resultant value B for single circuit lines
Line configuration Accurate formulae
ss
b a c
R
φ
Flat arrangement
B ()22
ο
s
s3j
π2
sIµi
−
−=R
R
R
B 2
1
4224
22
ο
sφ2cossR2R
sR3
Rπ2
sIµ
+−
+=
s
s
b
a
c
R
φ
Vertical arrangement
B ()22
ο
s
is3j
π2
sIµ
+
−−=R
R
R
B 2
1
4224
22
ο
sφ2cossR2R
sR3
Rπ2
sIµ
++
+=
R
b c
a
O φ
s3
s
Delta arrangement
B ()()
33
ο
is
jisij1
π4
sIµ3
+
+−+−=R
R
B 2
1
6336
22
ο
sφ3sinsR2R
sR
π4
sIµ23
+−
+=
5 Hexagon line
Figure 6 shows the traverse section of a hexagon line. The conductors of this line are placed on the corners of a
regular hexagon. The advantage of hexagon lines for the magnetic field calculation is their symmetry.
ACCURATE FORMULAE OF POWER LINE MAGNETIC FIELDS
89
Considering the reference point O at the centre of the hexagon, the vector distances of the corners from O is
given by similar expressions:
()6
π21ki
k es −
=d (5-1)
s
s
O 1
23
4
56
R
φ
Figure 6. A hexagon line
Equation (3-3) gives the λ order moment. Replacing (5-1) in (3-3) it results:
λM ()()∑
=
−−−−Ι=n
1k
3
π1k1λi
k
1λ es (5-2)
This relation results that there is a general recursive relation between the λ+6ν and the λ order moment of the
magnetic flux density. So, calculating the 6 first moments, the rest are derived:
λν6+M λ
ν6s M= (5-3)
The recursiveness of the moments results similar relations between the magnetic flux density terms. The λ order
term of the magnetic flux density id given by (3-2). Equation (3-2) in combination with (5-3) results:
()λν6+B λν6
v6
λο s
π2
µi
+=R
M (5-4)
So all the terms of the multipole expansion of the magnetic flux density in (3-1), may be separated in 6 groups,
as shown in the following relation:
B ()()()()()()∑∑∑∑∑∑∞
=
+
∞
=
+
∞
=
+
∞
=
+
∞
=
+
∞
=
++++++=
0ν
6ν6
0ν
5ν6
0ν
4ν6
0ν
3ν6
0ν
2ν6
0ν
1ν6 BBBBBB (5-5)
Each of the 6 sums appearing as terms in the former equation are calculated as:
()∑∞
=
+
0ν
λν6B 66
λ6
λο
sπ2
µi
−=
−
R
RM (5-6)
Replacing this in (5-6) it gives:
B 66
65
2
4
3
3
4
2
5
1ο
sπ2
µi
−
+++++=R
MRMRMRMRMRM
66
ο
sπ2
µi
−=R
N (5-7)
G. FILIPPOPOULOS D. TSANAKAS
90
where: ∑
=
−=6
1λ
λ6
λ RMN (5-8)
The resultant value of the magnetic flux density occurs as the magnitude of the above expression:
=Β ()2
1
126612
ο
sφ6cossR2R
N
π2
µ
+−
(5-10)
where the distance s and the angle φ are shown in figure 6.
The calculation of the magnetic field flux density vector consists in the calculation of N from the 6 first
moments. The calculation of the magnetic field flux density rms value consists in the calculation of N=N. The
value of N depends on the line configuration. In table 2 three common configurations of a hexagon line are
examined. It should be noted that even though the presented method assumes that R>s, these formulae are also
valid for sR≤.
6 Conclusions
Accurate formulas of the magnetic field vector and its resultant value for commonly used configurations of
power lines have been developed. These formulas may be used in the accurate estimation and the analysis of the
magnetic field values around these lines. As an example, for a flat power line, it is possible to calculate for the
magnetic field profile at ground level, its maximum value and the exact distance from the line axis where it
appears, keeping the distances between the phase conductors and the distance from the conductors to ground as
parameters. Also the magnetic field levels of different power line configurations can be compared.
Double complex numbers proved to be very efficient for the representation of the magnetic field vectors. Their
use simplified the expressions of the magnetic field produced by power lines and allowed the development of the
accurate formulae. Also the magnetic field multipole expansion terms were simplified and a general expression
of the λ-order term was presented. However, it remains for a future paper to show how the properties of the
ellipse described by the magnetic field vector, such as the major semi-axis, are related to the double complex
number representing the field and how these parameters can be extracted from this number.
It remains for future work to examine some more complicated cases of power line magnetic fields. A true double
circuit line conductor arrangement may decline significantly from the examined case of hexagonal lines. Further
more the currents might not be well balanced or some significant harmonics levels may have been introduced.
7 References
[1] D. W. Deno, L. E. Zaffanella: “Filed effects of overhead transmission lines and stations” Chapter 8 of
the “Transmission Line Reference Book- 345kV and Above”, 2nd ed. Electric Power Research Institute,
California 1982.
[2] D. Tsanakas, G. Filippopoulos, J. Voyatzakis, G. Kouvarakis: Compact and optimum phase conductor
arrangement for the reduction of electric and magnetic fields of overhead lines, CIGRE Report 36-103,
Session 2000.
[3] G. Filippopoulos, D. Tsanakas, G. Kouvarakis: Overhead and underground power line electric and
magnetic field reduction techniques, Millennium International Workshop on Biological Effects of
Electromagnetic Fields, Crete, Greece, October 2000.
[4] W. T. Kaune, L. E. Zaffanella: Analysis of magnetic fields produced far from electric power lines,
IEEE Transactions on Power Delivery, Vol. 7, No 4, pp. 2082 – 2091, October 1992.
ACCURATE FORMULAE OF POWER LINE MAGNETIC FIELDS
91
[5] I. L. Kantor, A. S. Solodovnikov: “Hypercomplex Numbers – An Elementary Introduction to Algebras”
Springer-Verlag 1989, ISBN: 0-387-96980-2, ISBN: 3-540-96980-2 (Translated from Russian to
English language by A. Shenitzer).
G. FILIPPOPOULOS D. TSANAKAS
92
Table 2. Accurate formulae of the magnetic flux density vector B and resultant value B for hexagon lines.
Line configuration Accurate formulae
s a
bb
a
cc
R
φ
super-bundle double circuit line
66
4334
ο
s
sijssij
π2
sIµi3
−
−++=R
RRRB
()2
1
126612
82644628
ο
sφ6cossR2R
sRsφ4cosφ2cosRs2RsR
π2
Isµ3B
+−
++−++=
s a
cb
a
cb
R
φ
low-reactance double circuit line
()()
66
222
ï
s
sij1ij1
π2
sIµi3
−
++−=R
RRB
2
1
126612
442
ο
sφ6cossR2R
sR
π2
RIsµ23B
+−
+=
s a
bc
d
ef
R
φ
six phase line
()()
66
44
ï
s
sij1ij1
π2
sIµi3
−
−++=R
RB
2
1
126612
88
ο
sφ6cossR2R
sR
π2
Isµ23B
+−
+=
Appendix: Double Complex Numbers and their properties
General
The double complex may be used when there is a need to use simultaneously two sets of complex numbers. In
this case, two copies of the complex numbers set is used the set Ci with the imaginary unit i, and the set Cj with
the imaginary unit j (1i2−=, 1j2−= and ji≠). The set of double complex numbers D is the Cartesian product
of the set Ci to the Cj (D = CixCj=R4). A double complex number f may be written in the forms:
f 21jz+=z 21ζiζ+=ijdjciba+++= (A-1)
ACCURATE FORMULAE OF POWER LINE MAGNETIC FIELDS
93
where 1z = a + ib and 2z = c + id are complex numbers in the set Ci, 1ζ = a + jc and 2ζ = b + jd are complex
numbers in the set Cj and a, b, c and d are real numbers (in the set R). Considering a second double complex
number dijcjbia ′+′+′+′=′f the product of f with f ′ occurs as shown in (A-2). Assuming the usual
operations of real numbers apply and replacing 1i2−=, 1j2−= where they appear).
ddcidbjdaijddicccbjicajc
djbcijbbbaibdijacjabiaaa
′+′−′−′+′−′−′+′+
+′−′+′−′+′+′+′+′=′ff (A-2)
This relation shows that the product of two double complex numbers is also a double complex number. Equation
(A-2) is used as a multiplication rule, allowing the axiomatic definition of double complex numbers as a
commutative ring.
Axiomatic definition
Double complex numbers are ordered quadruplets of real numbers with some operation rules. Considering the
quadruplets ()d,c,b,a and ()d,c,b,a ′′′′ where the a, b, c, d, a΄, b΄, c΄ and d΄ are real numbers the rules for
equality, addition are component like and the multiplication rule are defined as:
()d,c,b,a=()d,c,b,a ′′′′ ⇔ (a = a΄, b = b΄, c = c΄ and d = d΄) (A-3)
()( )( )dd,cc,bb,aad,c,b,ad,c,b,a ′+′+′+′+=′′′′+ (A-4)
()( )
()adbccbda,bdacdbca,cddcabba,ddccbbaa
d,c,b,ad,c,b,a
′+′+′+′′−′+′−′′−′−′+′′+′−′−′=
=′′′′ (A-5)
Defining ()0,0,0,11=, ()0,0,1,0i= and ()0,1,0,0j=, the product ij occurs ()1,0,0,0ij=. Based on these
equalities, and considering the product of any real number r with ()d,c,b,a as r()d,c,b,a=()rd,rc,rb,ra any
double complex number ()d,c,b,a may be written in the familiar form ijdjciba+++. The subset of D for c =
0 and d = 0, is the set Ci. Similarly, the subset of D for b = 0 and d = 0 is the set Cj. Further more, the subset of D
for b = 0, c = 0 and d = 0 is the set of the real numbers R. The defined operation rules are consistent with the
well known operations in the two sets of complex and the real numbers Ci, Cj and R.
Based on the rules for addition and multiplication it can be easily derived that the set of double complex numbers
is a commutative ring (addition is commutative: 1221ffff+=+, multiplication is commutative: 1221ffff=,
addition is associative: ()()321321ffffff++=++, multiplication is associative: ()()321321ffffff=,
multiplication is distributive with respect to addition: ()2121321fffffff+=+, the zero element is the real
number 0: ff=+0 and the unitary element is the real number 1: ff=⋅1, where 1f , 2f and 3f stand for
double complex numbers). That means that the basic operation rules for double complex numbers addition and
multiplication are the same as the known ones (as for real numbers). So there is no need to memorize special
operation rules. Also, there is no need to remember the multiplication rule; it is enough to replace i2 = -1 and j2 =
-1 where they appear.
Inversion of double complex numbers
However, there is a significant difference between the set of double complex numbers and the sets of complex
and real numbers. Double complex numbers is not a division system i.e. there are some double complex numbers
without an inverse (called non-invertible numbers). An inverse of a double complex number f is any double
complex number invf for which the following relation is valid f invf = 1. It can be proven that if f has an
inverse this is a unique double complex number. The cancellation low does not apply for non-invertible
G. FILIPPOPOULOS D. TSANAKAS
94
numbers, i.e. if f is a non-invertible number, equation yfxf= may be true and for yx≠. This would be
impossible if f had an inverse. So the expression f1 is not valid, unless it is known that f is invertible (for
example if it is a real or a complex number).
The magnitude of a double complex number
The magnitude f of a double complex number f expressed in the forms of (A-1) is a real number that occurs
according to the relations:
()()()2
1
22222
1
2
2
2
1
2
1
2
2
2
1 dcbaζζ+++=+=+=zzf (A-6)
This relation is consistent with the definition of the magnitude of complex numbers.
A useful relation for the calculation of the product of two double complex numbers 1f and 2f is the following:
2121ffff= (A-7)
However, this relation is valid only if at least one of 1f and 2f is a real number or a complex number in Ci or Cj
or a product of a complex number in Ci with a complex number in Cj.
Electric & Magnetic
Fields
Electric & Magnetic Fields
(EMFs)
Over the years, the issue of electric and
magnetic fields (EMFs) has drawn the
interest of scientists, government researchers,
energy companies, consumers, the news
media, and others. New studies and reports
on EMFs will certainly continue to spur
interest and debate regarding this important
issue.
Presently, research studies about the
correlation between EMF exposure and
adverse health effects are inconclusive. Since
Allegheny Energy is committed to providing
safe and reliable electric service to customers,
we have prepared this brochureto provide the
most current information available on EMFs.
We hope the information within this brochure
helps answer your questions regarding EMFs.
What are EMFs?
EMFs are invisible lines of force that are
present wherever electricity exists.
Electric fields are produced by voltage, which
is the presence of an electrical charge. The
higher the voltage of the power supply, the
greater the electric field. An electric field is
produced any time a conductor, or wire, is
energized. For example, when a lamp in your
home is plugged into an electrical outlet, an
electric field exists, whether or not the lamp is
turned on. Electric fields are also a natural
phenomenon and can come in the form of
lightning from a thunderstorm or the static
charge you sometimes feel on dry days.
Magnetic fields are produced by current,
which is the flow of electrical charges. As the
current increases, the strength of the mag-
netic field also increases. For example, the
current drawn by a lamp, and the resulting
magnetic fields, will be stronger on the lamp’s
high setting than they will be when the lamp
is operated on its low setting. The wires
produce a magnetic field only when the lamp
is turned on.
Magnetic fields pass through objects such as
buildings, plants, and the ground. They are
measured in units named for 18th-century
mathematician Karl Friedrich Gauss and
19th-century electrician and inventor Nicola
Tesla. The units of the tesla are equal to
10,000 gauss. The gauss is a measure of the
number of magnetic lines of force passing
through an area equal to one square inch. The
earth’s magnetic field averages 500 milligauss
or 0.5 gauss (1 gauss =1000 milligauss).
Where are EMFs found?
The largest natural source of magnetic fields
that we are exposed to is created by our Earth.
In nature, magnetic fields are what keep
compass needles pointed north and can be
strong enough in some parts of the world to
pull an automobile uphill.
In your home, appliances produce the highest
magnetic field levels. At work, computers and
other electrical equipment produce magnetic
fields. Outside of your home or office, electric
transmission and distribution lines produce
magnetic and electric fields as they carry
electricity from power stations to your home,
business, and community. The following
charts show typical levels of magnetic fields,
measured in milligauss, produced by
common household appliances and electric
transmission and distribution lines.
Magnetic field strength decreases as the
distance from the source increases. This chart
shows magnetic field levels, measured in
milligauss, from three distances.
Electric Field Only
Electric & Magnetic Fields
Common Appliances
120 Volts, 1 Ampere
Lamp On
100 Watts
120 Volts, No Current
Lamp Off
1.2 in. 12 in. 39 in.
Source: Edison Electric Institute
Microwave
Oven 750-2000 40-80 3-8
Clothes
Washer 8-400 2-30 0.1-2
Electric
Range 60-2000 4-40 0.1-1
Hair
Dryer 60-20000 1-70 0.1-3
Television 25-500 0.4-20 0.1-2
Electric and Magnetic Fields
What factors determine
EMF exposure?
Distance: As the charts illustrate, exposure
is greater the closer you are to the field
source.
Time: The more time you spend near the
field source, the greater the exposure.
Field Strength: The stronger the field at its
source, the greater the exposure. Voltage
levels for electric fields and current levels
for magnetic fields determine source
strength.
Wiring Configuration: Some wiring con-
figurations produce magnetic fields that fall
rapidly with distance, while others create
fields that fall off less rapidly. For example,
electric motors produce magnetic fields that
fall rapidly, while household wiring produces
fields that fall less rapidly.
Do EMFs affect human health?
Studies to determine the effects of electric
and magnetic fields on humans have been
inconclusive.
Can electric power lines be
built without producing EMFs?
No. A magnetic field is present when electric
current is present. An electric field is present
when voltage is present.
Do underground electric power
lines have lower magnetic
fields at ground level?
Burying electric power lines will not reduce
magnetic fields at ground level. Measure-
ments taken at ground level over under-
ground distribution lines show magnetic
fields comparable to those beneath overhead
distribution and transmission lines. The
determining factors for these field levels are
current in the wires, depth of wire burial,
geometry of the wires, and whether shielding
practices are employed.
Have exposure limits been set
for EMFs?
No limits by federal, state, or local authorities
have been set for exposures to magnetic or
electric field levels. National and interna-
tional industrial guidelines have been
published for workers that operate welders
and other equipment that use large amounts
of electricity.
Transmission & Distribution Lines
28 3 1 .2
124 32 9 2
92 29 8 2
142 82 25 6
12 kV†
138 kV
230 kV**
500 kV
centerline 50 ft.* 100 ft.* 200 ft.*
Source: Allegheny Energy field calculations at normal
conductor height and load. Readings may vary with
changes in height and line loading.
**While the structures are frequently the same as 138 kV,
the 230-kV lines are higher.
* Distance from center of right-of-way.
† kV: Kilovolt
This chart shows magnetic field levels, measured
in milligauss, at ground level near electric
transmission and distribution lines. These
calculations were taken under normal weather
conditions. Readings may vary with changes in
the height of the line and temperature.
Where can I learn more about
EMF studies?
The following agencies and organizations
can provide information on EMF research
through your local library or on the
internet: The National Academy of Science,
www.nationalacademies.org; the National
Institute of Environmental Health Sciences,
www.niehs.nih.gov; the Environmental
Protection Agency, www.epa.gov; and the
Electric Power Research Institute,
www.epri.com.
Call Allegheny Energy toll-free at
1-800-ALLEGHENY (1-800-255-3443) for
more information. Allegheny Energy will
continue to keep you informed as new
information regarding the effects of EMFs
becomes available.
Stock # 090116
1 EMF Basics
This chapter reviews terms you need to know to have a basic understanding of electric
and magnetic fields (EMF), compares EMF with other forms of electromagnetic
energy, and briefly discusses how such fields may affect us.
· What are electric and magnetic fields?
· How is the term EMF used in this booklet?
· How are power-frequency EMF different from other types of electromagnetic energy?
· How are alternating current sources of EMF different from direct current sources?
· What happens when I am exposed to EMF?
· Doesn't the earth produce EMF?
Q What are electric and magnetic fields?
A Electric and magnetic fields
(EMF) are invisible lines of
force that surround any
electrical device. Power
lines, electrical wiring, and
electrical equipment all
produce EMF. There are
many other sources of EMF
as well. The focus of this
booklet is on power-
frequency EMF--that is,
EMF associated with the
generation, transmission,
and use of electric power.
Electric fields are produced
by voltage and increase in
strength as the voltage
increases. The electric field
strength is measured in
units of volts per meter
(V/m). Magnetic fields result
from the flow of current
through wires or electrical
devices and increase in
strength as the current
increases. Magnetic fields
are measured in units of
gauss (G) or tesla (T).
Most electrical equipment
has to be turned on, i.e.,
current must be flowing, for
a magnetic field to be
produced. Electric fields are
often present even when
the equipment is switched
off, as long as it remains
connected to the source of
electric power. Brief bursts
of EMF (sometimes called
"transients") can also occur
when electrical devices are
turned on or off.
Electric fields are shielded
or weakened by materials
that conduct electricity--
even materials that conduct
poorly, including trees,
buildings, and human skin.
**Click Here to See Large Image**
Voltage produces an electric field and current produces a
magnetic field.
**Click Here to See Large Image**
An appliance that is plugged in and therefore connected to
a source of electricity has an electric field even when the
appliance is turned off. To produce a magnetic field, the
appliance must be plugged in and turned on so that the
current is flowing.
**Click Here to See Large Image**
You cannot see a magnetic field, but this illustration
Q How is the term EMF used in this booklet?
A The term "EMF" usually refers to electric and magnetic fields at extremely low
frequencies such as those associated with the use of electric power. The term
EMF can be used in a much broader sense as well, encompassing
electromagnetic fields with low or high frequencies.
Measuring EMF: Common Terms
Electric fields: Electric field strength is measured in volts per meter (V/m) or in
kilovolts per meter (kV/m). 1 kV = 1000 V
Magnetic fields: Magnetic fields are measured in units of gauss (G) or tesla (T).
Gauss is the unit most commonly used in the United States.
Tesla is the internationally accepted scientific term. 1 T = 10,000
G Since most environmental EMF exposures involve magnetic
fields that are only a fraction of a tesla or a gauss, these are
commonly measured in units of microtesla (µT) or milligauss
(mG). A milligauss is 1/1,000 of a gauss. A microtesla is
1/1,000,000 of a tesla. 1 G = 1,000 mG; 1 T = 1,000,000 µT To
convert a measurement from microtesla (µT) to milligauss (mG),
multiply by 10. 1 µT = 10 mG; 0.1 µT = 1 mG
When we use EMF in this booklet, we mean extremely low frequency (ELF)
electric and magnetic fields, ranging from 3 to 3,000 Hz (see page 8). This range
includes power-frequency (50 or 60 Hz) fields. In the ELF range, electric and
magnetic fields are not coupled or interrelated in the same way that they are at
higher frequencies. So, it is more useful to refer to them as "electric and
magnetic fields" rather than "electromagnetic fields." In the popular press,
however, you will see both terms used, abbreviated as EMF.
This booklet focuses on extremely low frequency EMF, primarily power-
frequency fields of 50 or 60 Hz, produced by the generation, transmission, and
use of electricity.
Q How are power-frequency EMF different from other types of
electromagnetic energy?
A X-rays, visible light, microwaves, radio waves, and EMF are all forms of
electromagnetic energy. One property that distinguishes different forms of
electromagnetic energy is the frequency, expressed in hertz (Hz). Power-
frequency EMF, 50 or 60 Hz, carries very little energy, has no ionizing effects,
and usually has no thermal effects. Just as various chemicals affect our bodies
in different ways, various forms of electromagnetic energy can have very
different biological effects.
Some types of equipment or operations simultaneously produce electromagnetic
energy of different frequencies. Welding operations, for example, can produce
electromagnetic energy in the ultraviolet, visible, infrared, and radio-frequency
ranges, in addition to power-frequency EMF. Microwave ovens produce 60-Hz
fields of several hundred milligauss, but they also create microwave energy
inside the oven that is at a much higher frequency (about 2.45 billion Hz). We
are shielded from the higher frequency fields inside the oven by its casing, but
we are not shielded from the 60-Hz fields.
Cellular telephones communicate by emitting high-frequency electric and
magnetic fields similar to those used for radio and television broadcasts. These
radio-frequency and microwave fields are quite different from the extremely low
frequency EMF produced by power lines and most appliances.
Q How are alternating current sources of EMF different from direct current
sources?
A Some equipment can run on either alternating current (AC) or direct current
(DC). In most parts of the United States, if the equipment is plugged into a
household wall socket, it is using AC electric current that reverses direction in
the electrical wiring--or alternates--60 times per second, or at 60 hertz (Hz). If
the equipment uses batteries, then electric current flows in one direction only.
This produces a "static" or stationary magnetic field, also called a direct current
field. Some battery-operated equipment can produce time -varying magnetic
fields as part of its normal operation.
**Click Here to See Large Image**
The wavy line at the right illustrates
the concept that the higher the
frequency, the more rapidly the field
varies. The fields do not vary at 0
Hz (direct current) and vary trillions
of times per second near the top of
the spectrum. Note that 104 means
10 x 10 x 10 x 10 or 10,000 Hz. 1
kilohertz (kHz) = 1,000 Hz. 1
megahertz (MHz) = 1,000,000 Hz
Q What happens when I am exposed to EMF?
A In most practical situations, DC electric power does not induce electric currents
in humans. Strong DC magnetic fields are present in some industrial
environments, can induce significant currents when a person moves, and may
be of concern for other reasons, such as potential effects on implanted medical
devices.
AC electric power produces electric and magnetic fields that create weak electric
currents in humans. These are called "induced currents." Much of the research
on how EMF may affect human health has focused on AC-induced currents.
Electric fields
A person standing directly under a high-voltage transmission line may feel a mild
shock when touching something that conducts electricity. These sensations are
caused by the strong electric fields from the high-voltage electricity in the lines.
They occur only at close range because the electric fields rapidly become
weaker as the distance from the line increases. Electric fields may be shielded
and further weakened by buildings, trees, and other objects that conduct
electricity.
Magnetic fields
Alternating magnetic fields produced by AC electricity can induce the flow of
weak electric currents in the body. However, such currents are estimated to be
smaller than the measured electric currents produced naturally by the brain,
nerves, and heart.
Q Doesn't the earth produce EMF?
A Yes. The earth produces EMF, mainly in the form of static fields, similar to the
fields generated by DC electricity. Electric fields are produced by air turbulence
and other atmospheric activity. The earth's magnetic field of about 500 mG is
thought to be produced by electric currents flowing deep within the earth's core.
Because these fields are static rather than alternating, they do not induce
currents in stationary objects as do fields associated with alternating current.
Such static fields can induce currents in moving and rotating objects.
The wavy line at the right illustrates the concept that the higher the frequency,
the more rapidly the field varies. The fields do not vary at 0 Hz (direct current)
and vary trillions of times per second near the top of the spectrum. Note that 104
means 10 x 10 x 10 x 10 or 10,000 Hz. 1 kilohertz (kHz) = 1,000 Hz. 1
megahertz (MHz) = 1,000,000 Hz.
You cannot see a magnetic field, but this illustration represents how the strength
of the magnetic field can diminish just 1-2 feet (30-61 centimeters) from the
source. This magnetic field is a 60-Hz power-frequency field.
On to Evaluating Potential Health Effects
EMF Questions & Answers Home | Introduction | EMF Basics | Evaluating Potential Health
Effects | Results of EMF Research | Your EMF Environment | EMF Exposure Standards |
National and International EMF Reviews | References
EMFRAPID Home | NIEHS Home
For More Information About EMF: Web Center
2 Evaluating Potential Health
Effects
This chapter explains how scientific studies are conducted and evaluated to assess
potential health effects.
· How do we evaluate whether EMF exposures cause health effects?
· How do we evaluate the results of epidemiological studies of EMF?
· How do we characterize EMF exposure?
· What is the average field strength?
· How is EMF exposure measured in epidemiological studies?
Q How do we evaluate whether EMF exposures cause health effects?
A Animal experiments, laboratory studies of cells, clinical studies, computer
simulations, and human population (epidemiological) studies all provide valuable
information. When evaluating evidence that certain exposures cause disease,
scientists consider results from studies in various disciplines.No single study or
type of study is definitive.
Laboratory studies
Laboratory studies with cells and animals
can provide evidence to help determine if an
agent such as EMF causes disease. Cellular
studies can increase our understanding of
the biological mechanisms by which disease
occurs. Experiments with animals provide a
means to observe effects of specific agents
under carefully controlled conditions. Neither
cellular nor animal studies, however, can
recreate the complex nature of the whole
human organism and its environment.
Therefore, we must use caution in applying
the results of cellular or animal studies
directly to humans or concludi ng that a lack
of an effect in laboratory studies proves that
an agent is safe. Even with these limitations,
cellular and animal studies have proven very useful over the years for identifying
and understanding the toxicity of numerous chemicals and physical agents.
Very specific laboratory conditions are needed for researchers to be able to
detect EMF effects, and experimental exposures are not easily comparable to
human exposures. In most cases, it is not clear how EMF actually produces the
effects observed in some experiments. Without understanding how the effects
occur, it is difficult to evaluate how laboratory results relate to human health
effects.
Some laboratory studies have reported that EMF exposure can produce
biological effects, including changes in functions of cells and tissues and subtle
changes in hormone levels in animals. It is important to distinguish between a
biological effect and a health effect. Many biological effects are within the normal
range of variation and are not necessarily harmful. For example, bright light has
a biological effect on our eyes, causing the pupils to constrict, which is a normal
response.
Laboratory studies and human studies
provide pieces of the puzzle, but no
single study can give us the whole
picture.
Clinical Studies
In clinical studies, researchers use sensitive
instruments to monitor human physiology during
controlled exposure to environmental agents. In
EMF studies, volunteers are exposed to electric
or magnetic fields at higher levels than those
commonly encountered in everyday life.
Researchers measure heart rate, brain activity,
hormonal levels, and other factors in exposed
and unexposed groups to look for differences
resulting from EMF exposure.
Epidemiology
A valuable tool to identify human health risks is to
study a human population that has experienced
the exposure. This type of research is called epidemiology.
The epidemiologist observes and compares groups of people who have had or
have not had certain diseases and exposures to see if the risk of disease is
different between the exposed and unexposed groups. The epidemiologist does
not control the exposure and cannot experimentally control all the factors that
might affect the risk of disease.
Most researchers agree that
epidemiology - the study of
patterns and possible causes of
diseases - is one of the most
valuable tools to identify human
health risks.
Q How do we evaluate the results of epidemiological studies of EMF?
A Many factors need to be considered when determining whether an agent causes
disease. An exposure that an epidemiological study associates with increased
risk of a certain disease is not always the actual cause of the disease. To judge
whether an agent actually causes a health effect, several issues are considered.
Strength of Association
The stronger the association between an exposure and disease, the more
confident we can be that the disease is due to the exposure being studied. With
cigarette smoking and lung cancer, the association is very strong--20 times the
normal risk. In the studies that suggest a relationship between EMF and certain
rare cancers, the association is much weaker.
Dose-response
Epidemiological data are more convincing if disease rates increase as exposure
levels increase. Such dose-response relationships have appeared in only a few
EMF studies.
Consistency
Consistency requires that an association found in one study appears in other
studies involving different study populations and methods. Associations found
consistently are more likely to be causal. With regard to EMF, results from
different studies sometimes disagree in important ways, such as what type of
cancer is associated with EMF exposure. Because of this inconsistency,
scientists cannot be sure whether the increased risks are due to EMF or other
factors.
Biological Plausibility
When associations are weak in an epidemiological study, results of laboratory
studies are even more important to support the association. Many scientists
remain skeptical about an association between EMF exposure and cancer
because laboratory studies thus far have not shown any consistent evidence of
adverse health effects, nor have results of experimental studies revealed a
plausible biological explanation for such an association.
Reliability of Exposure Information
Another important consideration with EMF epidemiological studies is how the
exposure information was obtained. Did the researchers simply estimate
people's EMF exposures based on their job titles or how their houses were
wired, or did they actually conduct EMF measurements? What did they measure
(electric fields, magnetic fields, or both)? How often were the EMF
measurements made and at what time? In how many different places were the
fields measured? More recent studies have included measurements of magnetic
field exposure. Magnetic fields measured at the time a study is conducted can
only estimate exposures that occurred in previous years (at the time a disease
process may have begun). Lack of comprehensive exposure information makes
it more difficult to interpret the results of a study, particularly considering that
everyone in the industrialized world has been exposed to EMF.
Confounding
Epidemiological studies show relationships or correlations between disease and
other factors such as diet, environmental conditions, and heredity. When a
disease is correlated with some factor, it does not necessarily mean that the
correlated factor causes the disease. It could mean that the factor occurs
together with some other factor, not measured in the study, that actually causes
the disease. This is called confounding.
For example, a study might show that alcohol consumption is correlated with
lung cancer. This could occur if the study group consists of people who drink and
also smoke tobacco, as often happens. In this example, alcohol use is correlated
with lung cancer, but cigarette smoking is a confounding factor and the true
cause of the disease.
Statistical Significance
Researchers use statistical methods to determine the likelihood that the
association between exposure and disease is due simply to chance. For a result
to be considered "statistically significant," the association must be stronger than
would be expected to occur by chance alone.
Meta-analysis
One way researchers try to get more information from epidemiological studies is
to conduct a meta-analysis. A meta-analysis combines the summary statistics of
many studies to explore their differences and, if appropriate, calculates an
overall summary risk estimate. The main challenge faced by researchers
performing meta-analyses is that populations, measurements, evaluation
techniques, participation rates, and potential confounding factors vary in the
original studies. These differences in the studies make it difficult to combine the
results in a meaningful way.
Pooled Analysis
Pooled analysis combines the original data from several studies and conducts a
new analysis on the primary data. It requires access to the original data from
individual studies and can only include diseases or factors included in all the
studies, but it has the advantage that the same parameters can be applied to all
studies. As with meta-analysis, pooled analysis is still subject to the limitations of
the experimental design of the original studies (for example, evaluation
techniques, participation rates, etc.). Pooled analysis differs from meta-analysis,
which combines the summary statistics from different studies, not their original
data.
Q How do we characterize EMF exposure?
A No one knows which aspect of EMF exposure, if any, affects human health.
Because of this uncertainty, in addition to the field strength, we must ask how
long an exposure lasts, how it varies, and at what time of day or night it occurs.
House wiring, for example, is often a significant source of EMF exposure for an
individual, but the magnetic fields produced by the wiring depend on the amount
of current flowing. As heating, lighting, and appliance use varies during the day,
magnetic field exposure will also vary.
For many studies, researchers describe EMF exposures by estimating the
average field strength. Some scientists believe that average exposure may not
be the best measurement of EMF exposure and that other parameters, such as
peak exposure or time of exposure, may be important.
Q What is the average field strength?
A In EMF studies, the information reported most often has been a person's EMF
exposure averaged over time (average field strength). With cancer-causing
chemicals, a person's average exposure over many years can be a good way to
predict his or her chances of getting the disease.
There are different ways to calculate average magnetic field exposures. One
method involves having a person wear a small monitor that takes many
measurements over a work shift, a day, or longer. Then the average of those
measurements is calculated. Another method involves placing a monitor that
takes many measurements in a residence over a 24-hour or 48-hour period.
Sometimes averages are calculated for people with the same occupation, people
working in similar environments, or people using several brands of the same
type or similar types of equipment.
Q How is EMF exposure measured in epidemiological studies?
A Epidemiologists study patterns and possible causes of diseases in human
populations. These studies are usually observational rather than experimental.
This means that the researcher observes and compares groups of people who
have had certain diseases and exposures and looks for possible "associations."
The epidemiologist must find a way to estimate the exposure that people had at
an earlier time.
Association
In epidemiology, a positive association between an exposure (such as EMF) and a
disease is not necessarily proof that the exposure caused the disease. However,
the more often the exposure and disease occur together, the stronger the
association, and the stronger is the possibility that the exposure may increase the
risk of the disease.
Some exposure estimates for residential studies have been based on
designation of households in terms of "wire codes." In other studies,
measurements have been made in homes, assuming that EMF levels at the time
of the measurement are similar to levels at some time in the past. Some studies
involved "spot measurements." Exposure levels change as a person moves
around in his or her environment, so spot measurements taken at specific
locations only approximate the complex variations in exposure a person
experiences. Other studies measured magnetic fields over a 24-hour or 48-hour
period. Exposure levels for some occupational studies are measured by having
certain employees wear personal monitors. The data taken from these monitors
are sometimes used to estimate typical exposure levels for employees with
certain job titles. Researchers can then estimate exposures using only an
employee's job title and avoid measuring exposures of all employees.
Methods to Estimate EMF Exposure
Wire Codes - A classification of homes based on characteristics of power lines
outside the home (thickness of the wires, wire configuration, etc.) and their
distance from the home. This information is used to code the homes into groups
with higher and lower predicted magnetic field levels.
Spot Measurement - An instantaneous or very short-term (e.g., 30-second)
measurement taken at a designated location.
Time-Weighted Average - A weighted average of exposure measurements taken
over a period of time that takes into account the time interval between
measurements. When the measurements are taken with a monitor at a fixed
sampling rate, the time-weighted average equals the arithmetic mean of the
measurements.
Personal Monitor - An instrument that can be worn on the body for measuring
exposure over time.
Calculated Historical Fields - An estimate based on a theoretical calculation of
the magnetic field emitted by power lines using historical electrical loads on those
lines.
On to Results of EMF Research
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3 Results of EMF Research
This chapter summarizes the results of EMF research worldwide, including
epidemiological studies of children and adults, clinical studies of how humans react to
typical EMF exposures, and laboratory research with animals and cells.
· Is there a link between EMF exposure and childhood leukemia?
· What is the epidemiological evidence for evaluating a link between EMF exposure and
childhood leukemia?
· Is there a link between EMF exposure and childhood brain cancer or other forms of
cancer in children?
· Is there a link between residential EMF exposure and cancer in adults?
· Have clusters of cancer or other adverse health effects been linked to EMF exposure?
· If EMF does cause or promote cancer, shouldn’t cancer rates have increased along with
the increased use of electricity?
· Is there a link between EMF exposure in electrical occupations and cancer?
· Have studies of workers in other industries suggested a link between EMF exposure and
cancer?
· Is there a link between EMF exposure and breast cancer?
· What have we learned from clinical studies?
· What effects of EMF have been reported in laboratory studies of cells?
· Have effects of EMF been reported in laboratory studies in animals?
· Can EMF exposure damage DNA?
Q Is there a link between EMF exposure and childhood leukemia?
A Despite more than two decades of research to determine whether elevated EMF
exposure, principally to magnetic fields, is related to an increased risk of
childhood leukemia, there is still no definitive answer. Much progress has been
made, however, with some lines of research leading to reasonably clear answers
and others remaining unresolved. The best available evidence at this time leads
to the following answers to specific questions about the link between EMF
exposure and childhood leukemia:
· Is there an association between power line configurations (wire codes)
and childhood leukemia? No.
· Is there an association between measured fields and childhood leukemia?
Yes, but the association is weak, and it is not clear whether it represents
a cause-and-effect relationship.
Q What is the epidemiological evidence for evaluating a link between EMF
exposure and childhood leukemia?
A The initial studies, starting with the pioneering research of Dr. Nancy Wertheimer
and Ed Leeper in 1979 in Denver, Colorado, focused on power line
configurations near homes. Power lines were systematically evaluated and
coded for their presumed ability to produce elevated magnetic fields in homes
and classified into groups with higher and lower predicted magnetic field levels.
Although the first study and two that followed in Denver and Los Angeles
showed an association between wire codes indicative of elevated magnetic
fields and childhood leukemia, larger, more recent studies in the central part of
the United States and in several provinces of Canada did not find such an
association. In fact, combining the evidence from all the studies, we can
conclude with some confidence that wire codes are not associated with a
measurable increase in the risk of childhood leukemia.
The other approach to assessing EMF exposure in homes focused on the
measurements of magnetic fields. Unlike wire codes, which are only applicable
in North America due to the nature of the electric power distribution system,
measured fields have been studied in relation to childhood leukemia in research
conducted around the world, including Sweden, England, Germany, New
Zealand, and Taiwan. Large, detailed studies have recently been completed in
the United States, Canada, and the United Kingdom that provide the most
evidence for making an evaluation. These studies have produced variable
findings, some reporting small associations, others finding no associations.
National Cancer Institute Study
In 1997, after eight years of work, Dr. Martha Linet and colleagues at the National
Cancer Institute (NCI) reported the results of their study of childhood acute
lymphoblastic leukemia (ALL). The case-control study involved more than 1,000
children living in 9 eastern and midwestern U.S. states and is the largest
epidemiological study of childhood leukemia to date in the United States. To help
resolve the question of wire code versus measured magnetic fields, the NCI
researchers carried out both types of exposure assessment. Overall, Linet reported
little evidence that living in homes with higher measured magnetic-field levels was a
disease risk and found no evidence that living in a home with a high wire code
configuration increased the risk of ALL in children.
United Kingdom Childhood Cancer Study
In December 1999, Sir Richard Doll and colleagues in the United Kingdom
announced that the largest study of childhood cancer ever undertaken-involving
nearly 4,000 children with cancer in England, Wales, and Scotland-found no
evidence of excess risk of childhood leukemia or other cancers from exposure to
power-frequency magnetic fields. It should be noted, however, that because most
power lines in the United Kingdom are underground, the EMF exposures of these
children were mostly lower than 0.2 microtesla or 2 milligauss.
After reviewing all the data, the U.S. National Institute of Environmental Health
Sciences (NIEHS) concluded in 1999 that the evidence was weak, but that it was
still sufficient to warrant limited concern. The NIEHS rationale was that no
individual epidemi ological study provided convincing evidence linking magnetic
field exposure with childhood leukemia, but the overall pattern of results for
some methods of measuring exposure suggested a weak association between
increasing exposure to EMF and increasing risk of childhood leukemia. The
small number of cases in these studies made it impossible to firmly demonstrate
this association. However, the fact that similar results had been observed in
studies of different populations using a variety of study designs supported this
observation.
A major challenge has been to determine whether the most highly elevated, but
rarely encountered, levels of magnetic fields are associated with an increased
risk of leukemia. Early reports focused on the risk associated with exposures
above 2 or 3 milligauss, but the more recent studies have been large enough to
also provide some information on levels above 3 or 4 milligauss. It is estimated
that 4.5% of homes in the United States have magnetic fields above 3
milligauss, and 2.5% of homes have levels above 4 milligauss.
What is Cancer?
Cancer
"Cancer" is a term used to describe at least 200 different diseases, all involving
uncontrolled cell growth. The frequency of cancer is measured by the incidence-the
number of new cases diagnosed each year. Incidence is usually described as the
number of new cases diagnosed per 100,000 people per year. The incidence of
cancer in adults in the United States is 382 per 100,000 per year, and childhood
cancers account for about 1% of all cancers. The factors that influence risk differ
among the forms of cancer. Known risk factors such as smoking, diet, and alcohol
contribute to specific types of cancer. (For example, smoking is a known risk factor
for lung cancer, bladder cancer, and oral cancer.) For many other cancers, the
causes are unknown.
Leukemia
Leukemia describes a variety of cancers that arise in the bone marrow where blood
cells are formed. The leukemias represent less than 4% of all cancer cases in
adults but are the most common form of cancer in children. For children age 4 and
under, the incidence of childhood leukemia is approximately 6 per 100,000 per
year, and it decreases with age to about 2 per 100,000 per year for children 10 and
older. In the United States, the incidence of adult leukemia is about 10 cases per
100,000 people per year. Little is known about what causes leukemia, although
genetic factors play a role. The only known causes are ionizing radiation, benzene,
and other chemicals and drugs that suppress bone marrow function, and a human
T-cell leukemia virus.
Brain Cancer
Cancer of the central nervous system (the brain and spinal cord) is uncommon, with
incidence in the United States now at about 6 cases in 100,000 people per year.
The causes of the disease are largely unknown, although a number of studies have
reported an association with certain occupational chemical exposures. Ionizing
radiation to the scalp is a known risk factor for brain cancer. Factors associated
with an increased risk for other types of cancer-such as smoking, diet, and
excessive alcohol use-have not been found to be associated with brain cancer.
To determine what the integrated information from all the studies says about
magnetic fields and childhood leukemia, two groups have conducted pooled
analyses in which the original data from relevant studies were integrated and
analyzed. One report (Greenland et al., 2000) combined 12 relevant studies with
magnetic field measurements, and the other considered 9 such studies (Ahlbom
et al., 2000). The details of the two pooled analyses are different, but their
findings are similar. There is weak evidence for an association (relative risk of
approximately 2) at exposures above 3 mG. However, few individuals had high
exposures in these studies; therefore, even combining all studies, there is
uncertainty about the strength of the association.
The following table summarizes the results for the epidemiological studies of
EMF exposure and childhood leukemia analyzed in the pooled analysis by
Greenland et al. (2000). The focus of the summary review was the magnetic
fields that occurred three months prior to diagnosis. The results were derived
from either calculated historical fields or multiple measurements of magnetic
fields. The North American studies (Linet, London, McBride, Savitz) were 60 Hz;
all other studies were 50 Hz. Results from the recent study from the United
Kingdom are also included in the table. This study was included in the analysis
by Ahlbom et al. (2000). The relative risk estimates from the individual studies
show little or no association of magnetic fields with childhood leukemia. The
study summary for the pooled analysis by Greenland et al. (2000) shows a weak
association between childhood leukemia and magnetic field exposures greater 3
mG.
Residential Exposure to Magnetic Fields and Childhood Leukemia
Magnetic field category (mG)
>1 -<2 mG >2 -<3 mG >3 mG
First author
Coghill
Dockerty
Feychting
Linet
London
McBride
Michaelis
Olsen
Savitz
Tomenius
Tynes
Verkasalo
Estimate
0.54
0.65
0.63
1.07
0.96
0.89
1.45
0.67
1.61
0.57
1.06
1.11
95% CL
0.17, 1.74
0.26, 1.63
0.08, 4.77
0.82, 1.39
0.54, 1.73
0.62, 1.29
0.78, 2.72
0.07, 6.42
0.64, 4.11
0.33, 0.99
0.25, 4.53
0.14, 9.07
Estimate
No controls
2.83
0.90
1.01
0.75
1.27
1.06
No cases
1.29
0.88
No cases
No cases
95% CL
No controls
0.29, 27.9
0.12, 7.00
0.64, 1.59
0.22, 2.53
0.74, 2.20
0.27, 4.16
No cases
0.27, 6.26
0.33, 2.36
No cases
No cases
Estimate
No controls
No controls
4.44
1.51
1.53
1.42
2.48
2.00
3.87
1.41
No cases
2.00
95% CL
No controls
No controls
1.67, 11.7
0.92, 2.49
0.67, 3.50
0.63, 3.21
0.79, 7.81
0.40, 9.93
0.87, 17.3
0.38, 5.29
No cases
0.23, 17.7
Study
summary 0.95 0.80, 1.12 1.06 0.79, 1.42 1.69* 1.25, 2.29
1 - <2 mG 2 - <4 mG >4 mG
**United
Kingdom 0.84 0.57, 1.24 0.98 0.50, 1.93 1.00 0.30, 3.37
95% CL = 95% confidence limits.
Source: Greenland et al., 2000.
* Mantel -Haenszel analysis (p = 0.01). Maximum-likelihood summaries differed by less than 1%
from these summaries; based on 2,656 cases and 7,084 controls. Adjusting for age, sex, and
other variables had little effect on summary results
**These data are from a recent United Kingdom study not included in the Greenland analysis but
included in another pooled analysis (Ahlbom et al. 2000). The United Kingdom study included
1,073 cases and 2,224 controls.
For this table, the column headed "estimate" describes the relative risk. Relative risk is the ratio of
the risk of childhood leukemia for those in a magnetic field exposure group compared to persons
with exposure levels of 1.0 mG or less. For example, Coghill estimated that children with
exposures between 1 and 2 mG have 0.54 times the risk of children whose exposures were less
than 1 mG. London's study estimates that children whose exposures were greater than 3 mG
have 1.53 times the risk of children whose exposures were less than 1 mG. The column headed
"95% CL" (confidence limits) describes how much random variation is in the estimate of relative
risk. The estimate may be off by some amount due to random variation, and the width of the
confidence limits gives some notion of that variation. For example, in Coghill's estimate of 0.54 for
the relative risk, values as low as 0.17 or as high as 1.74 would not be statistically significantly
different from the value of 0.54. Note there is a wide range of estimates of relative risk across the
studies and wide confidence limits for many studies. In light of these findings, the pooling of
results can be extremely helpful to calculate an overall estimate, much better than can be
obtained from any study taken alone.
Q Is there a link between EMF exposure and childhood brain cancer or other
forms of cancer in children?
A Although the earliest studies suggested an association between EMF exposure
and all forms of childhood cancer, those initial findings have not been confirmed
by other studies. At present, the available series of studies indicates no
association between EMF exposure and childhood cancers other than leukemia.
Far fewer of these studies have been conducted than studies of childhood
leukemia.
Q Is there a link between residential EMF exposure and cancer in adults?
A The few studies that have been conducted to address EMF and adult cancer do
not provide strong evidence for an association. Thus, a link has not been
established between residential EMF exposure and adult cancers, including
leukemia, brain cancer, and breast cancer (see table below).
Residential Exposure to Magnetic Fields and Adult Cancer
Results (odds ratios)
First author Location Type of exposure data Leuke
mia CNS tumors
All
cance
rs
Coleman
Feychting and
Ahlbom
Li
Li
McDowall
Severson
Wrensch
Youngson
United
Kingdom
Sweden
Taiwan
Taiwan
United
Kingdom
Seattle, US
San
Francisco, US
United
Kingdom
Calculated historical fields
Calculated & spot measure
ments
Calculated historical fields
Calculated historical fields
Calculated historical fields
Wire codes & spot
measurements
Wire codes & spot
measurements
Calculated historical fields
0.92
1.5*
1.4*
1.43
0.75
NA
1.88
NA
0.7
1.1
1.1 (breast can
cer)
NA
NA
0.9
NA
NA
NA
NA
1.03
NA
NA
NA
CNS = central nervous system.
*The number is statistically significant (greater than expected by chance).
Study results are listed as "odds ratios" (OR). An odds ratio of 1.00 means there was no increase
or decrease in risk. In other words, the odds that the people in the study who had the disease (in
this case, cancer) and were exposed to a particular agent (in this case, EMF) are the same as for
the people in the study who did not have the disease. An odds ratio greater than 1 may occur
simply by chance, unless it is statistically significant.
Q Have clusters of cancer or other adverse health effects been linked to EMF
exposure?
A An unusually large number of cancers, miscarriages, or other adverse health
effects that occur in one area or over one period of time is called a "cluster."
Sometimes clusters provide an early warning of a health hazard. But most of the
time the reason for the cluster is not known. There have been no proven
instances of cancer clusters linked with EMF exposure.
The definition of a “cluster” depends
on how large an area is included.
Cancer cases (x’s in illustration) in a
city, neighborhood, or workplace
may occur in ways that suggest a
cluster due to a common
environmental cause. Often these
patterns turn out to be due to
chance. Delineation of a cluster is
subjective—where do you draw the
circles?
Q If EMF does cause or promote cancer, shouldn't cancer rates have
increased along with the increased use of electricity?
A Not necessarily. Although the use of electricity has
increased greatly over the years, EMF exposures
may not have increased. Changes in building wiring
codes and in the design of electrical appliances have
in some cases resulted in lower magnetic field levels.
Rates for various types of cancer have shown both
increases and decreases through the years, due in
part to improved prevention, diagnosis, reporting,
and treatment.
Q Is there a link between EMF exposure in electrical occupations and
cancer?
A For almost as long as we have been concerned with residential exposure to
EMF and childhood cancers, researchers have been studying workplace
exposure to EMF and adult cancers, focusing on leukemia and brain cancer.
This research began with surveys of job titles and cancer risks, but has
progressed to include very large, detailed studies of the health of workers,
especially electric utility workers, in the United States, Canada, France, England,
and several Northern European countries. Some studies have found evidence
that suggests a link between EMF exposure and both leukemia and brain
cancer, whereas other studies of similar size and quality have not found such
associations.
· California - A 1993 study of 36,000 California electric utility workers
reported no strong, consistent evidence of an association between
magnetic fields and any type of cancer.
· Canada/France - A 1994 study of more than 200,000 utility workers in 3
utility companies in Canada and France reported no significant
association between all leukemias combined and cumulative exposure to
magnetic fields. There was a slight, but not statistically significant,
increase in brain cancer. The researchers concluded that the study did
not provide clear-cut evidence that magnetic field exposures caused
leukemia or brain cancer.
· North Carolina - Results of a 1995 study involving more than 138,000
utility workers at 5 electric utilities in the United States did not support an
association between occupational magnetic field exposure and leukemia,
but suggested a link to brain cancer.
· Denmark - In 1997 a study of workers employed in all Danish utility
companies reported a small, but statistically significant, excess risk for all
cancers combined and for lung cancer. No excess risk was observed for
leukemia, brain cancers, or breast cancer.
· United Kingdom - A 1997 study among electrical workers in the United
Kingdom did not find an excess risk for brain cancer. An extension of this
work reported in 2001 also found no increased risk for brain cancer.
Efforts have also been made to pool the findings across several of the above
studies to produce more accurate estimates of the association between EMF
and cancer (Kheifets et al., 1999). The combined summary statistics across
studies provide insufficient evidence for an association between EMF exposure
in the workplace and either leukemia or brain cancer.
Q Have studies of workers in other industries suggested a link between EMF
exposure and cancer?
A One of the largest studies to report an association between
cancer and magnetic field exposure in a broad range of industries
was conducted in Sweden (1993). The study included an
assessment of EMF exposure in 1,015 different workplaces and
involved more than 1,600 people in 169 different occupations. An
association was reported between estimated EMF exposure and
increased risk for chronic lymphocytic leukemia. An association
was also reported between exposure to magnetic fields and brain
cancer, but there was no dose-response relationship.
Another Swedish study (1994) found an excess risk of lymphocytic leukemia
among railway engine drivers and conductors. However, the total cancer
incidence (all tumors included) for this group of workers was lower than in the
general Swedish population. A study of Norwegian railway workers found no
evidence for an association between EMF exposure and leukemia or brain
cancer. Although both positive and negative effects of EMF exposure have been
reported, the majority of studies show no effects.
Q Is there a link between EMF exposure and breast cancer?
A Researchers have been interested in the possibility that EMF exposure might
cause breast cancer, in part because breast cancer is such a common disease
in adult women. Early studies identified a few electrical workers with male breast
cancer, a very rare disease. A link between EMF exposure and alterations in the
hormone melatonin was considered a possible hypothesis. This idea provided
motivation to conduct research addressing a possible link between EMF
exposure and breast cancer. Overall, the published epidemiological studies have
not shown such an association.
Q What have we learned from clinical studies?
A Laboratory studies with human volunteers have attempted to answer questions
such as,
· Does EMF exposure alter normal brain and heart function?
· Does EMF exposure at night affect sleep patterns?
· Does EMF exposure affect the immune system?
· Does EMF exposure affect hormones?
The following kinds of biological effects have been reported. Keep in mind that a
biological effect is simply a measurable change in some biological response. It
may or may not have any bearing on health.
· Heart rate
An inconsistent effect on heart rate by EMF exposure has been reported.
When observed, the biological response is small (on average, a slowing
of about three to five beats per minute), and the response does not
persist once exposure has ended.
Two laboratories, one in the United States and one in Australia, have
reported effects of EMF on heart rate variability. Exposures used in these
experiments were relatively high (about 300 mG), and lower exposures
failed to produce the effect. Effects have not been observed consistently
in repeated experiments.
· Sleep electrophysiology
A laboratory report suggested that overnight exposure to 60-Hz magnetic
fields may disrupt brain electrical activity (EEG) during night sleep. In this
study subjects were exposed to either continuous or intermittent magnetic
fields of 283 mG. Individuals exposed to the intermittent magnetic fields
showed alterations in traditional EEG sleep parameters indicative of a
pattern of poor and disrupted sleep. Several studies have reported no
effect with continuous exposure.
· Hormones, immune system, and blood chemistry
Several clinical studies with human volunteers have evaluated the effects
of power-frequency EMF exposure on hormones, the immune system,
and blood chemistry. These studies provide little evidence for any
consistent effect.
· Melatonin
The hormone melatonin is secreted mainly at night and primarily by the
pineal gland, a small gland attached to the brain. Some laboratory
experiments with cells and animals have shown that melatonin can slow
the growth of cancer cells, including breast cancer cells. Suppressed
nocturnal melatonin levels have been observed in some studies of
laboratory animals exposed to both electric and magnetic fields. These
observations led to the hypothesis that EMF exposure might reduce
melatonin and thereby weaken one of the body's defenses against
cancer.
Many clinical studies with human volunteers have now examined whether
various levels and types of magnetic field exposure affect blood levels of
melatonin. Exposure of human volunteers at night to power-frequency
EMF under controlled laboratory conditions has no apparent effect on
melatonin. Some studies of people exposed to EMF at work or at home
do report evidence for a small suppression of melatonin. It is not clear
whether the decreases in melatonin reported under environmental
conditions are related to the presence of EMF exposure or to other
factors.
Q What effects of EMF have been reported in laboratory studies of cells?
A Over the years, scientists have conducted more than 1,000 laboratory studies to
investigate potential biological effects of EMF exposure. Most have been in vitro
studies; that is, studies carried out on cells isolated from animals and plants, or
on cell components such as cell membranes. Other studies involved animals,
mainly rats and mice. In general, these studies do not demonstrate a consistent
effect of EMF exposure.
Most in vitro studies have used magnetic fields of 1,000 mG (100 µT) or higher,
exposures that far exceed daily human exposures. In most incidences, when
one laboratory has reported effects of EMF exposure on cells, other laboratories
have not been able to reproduce the findings. For such research results to be
widely accepted by scientists as valid, they must be replicated--that is, scientists
in other laboratories should be able to repeat the experiment and get similar
results. Cellular studies have investigated potential EMF effects on cell
proliferation and differentiation, gene expression, enzyme activity, melatonin,
and DNA. Scientists reviewing the EMF research literature find overall that the
cellular studies provide little convincing evidence of EMF effects at
environmental levels.
Q Have effects of EMF been reported in laboratory studies in animals?
A Researchers have published more than 30 detailed reports on both long-term
and short-term studies of EMF exposures in laboratory animals (bioassays).
Long-term animal bioassays constitute an important group of studies in EMF
research. Such studies have a proven record for predicting the carcinogenicity of
chemicals, physical agents, and other suspected cancer-causing agents. In the
EMF studies, large groups of mice or rats were continuously exposed to EMF for
two years or longer and were then evaluated for cancer. The U.S. National
Toxicology Program (http://ntp-server.niehs.nih.gov/) has an extensive
historical database for hundreds of different chemical and physical agents
evaluated using this model. EMF long-term bioassays examined leukemia, brain
cancer, and breast cancer--the diseases some epidemiological studies have
associated with EMF exposure.
Several different approaches have been used to evaluate effects of EMF
exposure in animal bioassays. To investigate whether EMF could promote
cancer after genetic damage had occurred, some long-term studies used cancer
initiators such as ultraviolet light, radiation, or certain chemicals that are known
to cause genetic damage. Researchers compared groups of animals treated with
cancer initiators to groups treated with cancer initiators and then exposed to
EMF, to see if EMF exposure promoted the cancer growth (initiation-promotion
model). Other studies tested the cancer promotion potential of EMF using mice
that were predisposed to cancer because they had defects in the genes that
control cancer.
Animal Leukemia Studies: Long-Term, Continuous Exposure Studies, Two
or More Years in Length
First author Sex/species Exposure/animal numbers Results
Babbitt (U.S.)
Boorman (U.S.)
McCormick (U.S.)
Mandeville (Canada
Female mice
Male and female rats
Male and female mic
e
14,000 mG, 190 or 380 mice per group.
Some groups treated with ionizing radiatio
n.
20 to 10,000 mG, 100 per group
20 to 10,000 mG, 100 per group
No effec
t
No
effect
)
Yasui (Japan)
Female rats
Male and female rats
20 to 20,000 mG, 50 per group
In utero exposure
5,000 to 50,000 mG, 50 per group
No
effect
No
effect
No
effect
Leukemia
Fifteen animal leukemia studies have been completed and reported. Most tested
for effects of exposure to power-frequency (60-Hz) magnetic fields using
rodents. Results of these studies were largely negative. The Babbitt study
evaluated the subtypes of leukemia. The data provide no support for the
reported epidemiology findings of leukemia from EMF exposure. Many scientists
feel that the lack of effects seen in these laboratory leukemia studies significantly
weakens the case for EMF as a cause of leukemia.
Breast Cancer
Researchers in the Ukraine, Germany, Sweden, and the United States have
used initiation-promotion models to investigate whether EMF exposure promotes
breast cancer in rats.
The results of these studies are mixed; while the German studies showed some
effects, the Swedish and U.S. studies showed none. Studies in Germany
reported effects on the numbers of tumors and tumor volume. A National
Toxicology Program long-term bioassay performed without the use of other
cancer-initiating substances showed no effects of EMF exposure on the
development of mammary tumors in rats and mice.
The explanation for the observed difference among these studies is not readily
apparent. Within the limits of the experimental rodent model of mammary
carcinogenesis, no conclusions are possible regarding a promoting effect of
EMF on chemically induced mammary cancer.
Other Cancers
Tests of EMF effects on skin cancer, liver cancer, and brain cancer have been
conducted using both initiation-promotion models and non-initiated long-term
bioassays. All are negative.
Three positive studies were reported for a co-promotion model of skin cancer in
mice. The mice were exposed to EMF plus cancer-causing chemicals after
cancers had already been initiated. The same research team as well as an
independent laboratory were unable to reproduce these results in subsequent
experiments.
Non-cancer Effects
Many animal studies have investigated whether EMF can cause health problems
other than cancer. Researchers have examined many endpoints, including birth
defects, immune system function, reproduction, behavior, and learning. Overall,
animal studies do not support EMF effects on non-cancer endpoints.
Q Can EMF exposure damage DNA?
A Studies have attempted to determine whether EMF has genotoxic potential; that
is, whether EMF exposure can alter the genetic material of living organisms. This
question is important because genotoxic agents often also cause cancer or birth
defects. Studies of genotoxicity have included tests on bacteria, fruit flies, and
some tests on rats and mice. Nearly 100 studies on EMF genotoxicity have been
reported. Most evidence suggests that EMF exposure is not genotoxic. Based on
experiments with cells, some researchers have suggested that EMF exposure
may inhibit the cell's ability to repair normal DNA damage, but this idea remains
speculative because of the lack of genotoxicity observed in EMF animal studies.
On to Your EMF Environment
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Effects | Results of EMF Research | Your EMF Environment | EMF Exposure Standards |
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For More Information About EMF: Web Center
4 Your EMF Environment
Part 2
This chapter discusses typical magnetic field exposures in home and work
environments and identifies common EMF sources and field intensities associated with
these sources.
· How do we define EMF exposure?
· How is EMF exposure measured?
· What are some typical EMF exposures?
· What are typical EMF exposures for people living in the United States?
· What levels of EMF are found in common environments?
· What EMF field levels are encountered in the home?
· What are EMF levels close to electrical appliances?
· What EMF levels are found near power lines?
· How strong is the EMF from electric power substations?
· Do electrical workers have higher EMF exposure than other workers?
· What are possible EMF exposures in the workplace?
· What are some typical sources of EMF in the workplace?
· What EMF exposure occurs during travel?
· How can I find out how strong the EMF is where I live and work?
· How much do computers contribute to my EMF exposure?
· What can be done to limit EMF exposure?
Q What EMF levels are found near power lines?
A Power transmission lines bring power from a generating station to an electrical
substation. Power distribution lines bring power from the substation to your
home. Transmission and distribution lines can be either overhead or
underground. Overhead lines produce both electric fields and magnetic fields.
Underground lines do not produce electric fields above ground but may produce
magnetic fields above ground.
Power transmission lines
Typical EMF levels for transmission lines are shown in the chart on page 37. At
a distance of 300 feet and at times of average electricity demand, the magnetic
fields from many lines can be similar to typical background levels found in most
homes. The distance at which the magnetic field from the line becomes
indistinguishable from typical background levels differs for different types of
lines.
Power Distribution Lines
Typical voltage for power distribution lines in North America ranges from 4 to 24
kilovolts (kV). Electric field levels directly beneath overhead distribution lines
may vary from a few volts per meter to 100 or 200 volts per meter. Magneti c
fields directly beneath overhead distribution lines typically range from 10 to 20
mG for main feeders and less than 10 mG for laterals. Such levels are also
typical directly above underground lines. Peak EMF levels, however, can vary
considerably depending on the amount of current carried by the line. Peak
magnetic field levels as high as 70 mG have been measured directly below
overhead distribution lines and as high as 40 mG above underground lines.
Q How strong is the EMF from electric power substations?
A In general, the strongest EMF around the outside of a substation comes from the
power lines entering and leaving the substation. The strength of the EMF from
equipment within the substations, such as transformers, reactors, and capacitor
banks, decreases rapidly with increasing distance. Beyond the substation fence
or wall, the EMF produced by the substation equipment is typically
indistinguishable from background levels.
Q Do electrical workers have higher EMF exposure than other workers?
A Most of the information we have about occupational EMF exposure comes from
studies of electric utility workers. It is therefore difficult to compare electrical
workers' EMF exposures with those of other workers because there is less
information about EMF exposures in work environments other than electric
utilities. Early studies did not include actual measurements of EMF exposure on
the job but used job titles as an estimate of EMF exposure among electrical
workers. Recent studies, however, have included extensive EMF exposure
assessments.
A report published in 1994 provides some information about estimated EMF
exposures of workers in Los Angeles in a number of electrical jobs in electric
utilities and other industries. Electrical workers had higher average EMF
exposures (9.6 mG) than did workers in other jobs (1.7 mG). For this study, the
category "electrical workers" included electrical engineering technicians,
electrical engineers, electricians, power line workers, power station operators,
telephone line workers, TV repairers, and welders.
****Click Here to See Large Image****
Q What are possible EMF exposures in the workplace?
A The figures below are examples of magnetic field exposures determined with
exposure meters worn by four workers in different occupations. These
measurements demonstrate how EMF exposures vary among individual
workers. They do not necessarily represent typical EMF exposures for workers
in these occupations.
Magnetic Field Exposures of Workers (mG)
The sewing machine operator worked all day,
took a 1-hour lunch break at 11:15 am, and
took 10-minute breaks at 8:55 am and 2:55 pm.
The mechanic repaired a compressor at 9:45
am and 11:10 am.
The electrician repaired a large air-conditioning
motor at 9:10 am and at 11:45 am.
The government worker was at the copy
machine at 8:00 am, at the computer from
11:00 am to 1:00 pm and also from 2:30 pm to
4:30 pm.
*The geometric mean is calculated by squaring the values, adding the squares, and then taking
the square root of the sum. Source: National Institute for Occupational Safety and Health and
U.S. Department of Energy.
****Click Here to See Large Image****
The tables below can give you a general idea about magnetic field levels for
different jobs and around various kinds of electrical equipment. It is important to
remember that EMF levels depend on the actual equipment used in the
workplace. Different brands or models of the same type of equipment can have
different magnetic field strengths. It is also important to keep in mind that the
strength of a magnetic field decreases quickly with distance.
EMF Measurements During a Workday
ELF magnetic fields
measured in mG
Industry and occupation
Median for
occupation*
Range for 90%
of workers**
ELECTRICAL WORKERS IN VARIOUS INDUSTRIES
Electrical engineers
Construction electricians
TV repairers
1.7
3.1
4.3
0.5-12.0
1.6-12.1
0.6-8.6
Welders 9.5 1.4-66.1
ELECTRIC UTILITIES
Clerical workers without computers
Clerical workers with computers
Line workers
Electricians
Distribution substation operators
Workers off the job (home, travel, etc.)
0.5
1.2
2.5
5.4
7.2
0.9
0.2-2.0
0.5-4.5
0.5-34.8
0.8-34.0
1.1-36.2
0.3-3.7
TELECOMMUNICATIONS
Install, maintenance, & repair technicians
Central office technicians
Cable splicers
1.5
2.1
3.2
0.7-3.2
0.5-8.2
0.7-15.0
AUTO TRANSMISSION MANUFACTURE
Assemblers
Machinists
0.7
1.9
0.2-4.9
0.6-27.6
HOSPITALS
Nurses
X-ray technicians
1.1
1.5
0.5-2.1
1.0-2.2
SELECTED OCCUPATIONS FROM ALL ECONOMIC SECTORS
Construction machine operators
Motor vehicle drivers
School teachers
Auto mechanics
Retail sales
Sheet metal workers
Sewing machine operators
Forestry and logging jobs
0.5
1.1
1.3
2.3
2.3
3.9
6.8
7.6
0.1-1.2
0.4-2.7
0.6-3.2
0.6-8.7
1.0-5.5
0.3-48.4
0.9-32.0
0.6-95.5***
If you have questions or want more information about your EMF exposure at
work, your plant safety officer, industrial hygienist, or other local safety official
can be a good source of information. The National Institute for Occupational
Safety and Health (NIOSH) is asked occasionally to conduct health hazard
evaluations in workplaces where EMF is a suspected cause for concern. For
further technical assistance contact NIOSH at 800-356-4674.
Q What are some typical sources of EMF in the workplace?
A Exposure assessment studies so far have shown that most people's
EMF exposure at work comes from electrical appliances and tools and
from the building's power supply. People who work near transformers,
electrical closets, circuit boxes, or other high-current electrical
equipment may have 60-Hz magnetic field exposures of hundreds of
milligauss or more. In offices, magnetic field levels are often similar to
those found at home, typically 0.5 to 4.0 mG. However, these levels can
increase dramatically near certain types of equipment.
EMF Spot Measurements
Industry and sources
ELF
magneti
c fields
(mG)
Other frequencies Comments
ELECTRICAL EQUIPMENT USED IN MACHINE MANUFACTURING
Electric resistance
heater
Induction heater
Hand-held grinder
Grinder
Lathe, drill press, etc.
6,000-
14,000
10-460
3,000
110
1-4
VLF
High VLF
-
-
-
Tool exposures measured at
operator's chest.
Tool exposures measured at
operator's chest.
Tool exposures measured at
operator's chest.
ALUMINUM REFINING
Aluminum pot rooms
Rectification room
3.4-30
300-
3,300
Very high static field
High static field
Highly-rectified DC current (with an
ELF ripple)
refines aluminum.
STEEL FOUNDRY
Ladle refinery
Furnace active
Furnace inactive
Electrogalvanizing unit
170-
1,300
0.6-3.7
2-1,100
High ULF from the
ladle's big
magnetic stirrer
High ULF from the
ladle's big
magnetic stirrer
High VLF
Highest ELF field was at the
chair of control room operator.
Highest ELF fiel d was at the
chair of control room operator.
TELEVISION BROADCASTING
Video cameras
(studio and minicams)
Video tape degaussers
Light control centers
Studio and newsrooms
7.2-24.0
160-
3,300
10-300
2-5
VLF
-
-
-
Measured 1 ft away.
Walk-through survey.
Walk-through survey.
HOSPITALS
Intensive care unit
Post-anesthesia care
unit
Magnetic resonance
imaging (MRI)
0.1-220
0.1-24
0.5-280
VLF
VLF
Very high static field,
VLF and RF
Measured at nurse's chest.
Measured at technician's work
locations.
TRANSPORTATION
Cars, minivans, and
trucks
Bus (diesel powered)
Electric cars
Chargers for electric
cars
Electric buses
0.1-125
0.5-146
0.1-81
4-63
0.1-88
0.1-330
0.8-24.2
Most frequencies less
than 60 Hz
Most frequencies less
than 60 Hz
Some elevated static
fields
-
Steel-belted tires are the principal
ELF source
for gas/diesel vehicles.
Measured 2 ft from charger.
Measured at waist. Fields at ankles
2-5 times higher.
Electric train passenger
cars
Airliner
-
25 & 60 Hz power on
U.S. trains
400 Hz power on
airliners
Measured at waist. Fields at ankles
2-5 times higher.
Measured at waist.
GOVERNMENT OFFICES
Desk work locations
Desks near power
center
Power cables in floor
Building power supplies
Can opener
Desktop cooling fan
Other office appliances
0.1-7
18-50
15-170
25-1,800
3,000
1,000
10-200
-
-
-
-
-
-
-
Peaks due to laser printers.
Appliance fields measured 6 in.
away.
Appliance fields measured 6 in.
away.
Source: National Institute for Occupational Safety and Health, 2001.
ULF (ultra low frequency)-frequencies above 0, below 3 Hz.
ELF (extremely low frequency)-frequencies 3-3,000 Hz.
VLF (very low frequency)-frequencies 3,000-30,000 Hz (3-30 kilohertz).
Q What EMF exposure occurs during travel?
A Inside a car or bus, the main sources of magnetic field exposure are those you
pass by (or under) as you drive, such as power lines. Car batteries involve direct
current (DC) rather than alternating current (AC). Alternators can create EMF,
but at frequencies other than 60 Hz. The rotation of steel-belted tires is also a
source of EMF.
Most trains in the United States are diesel powered. Some electri cally powered
trains operate on AC, such as the passenger trains between Washington, D.C.
and New Haven, Connecticut. Measurements taken on these trains using
personal exposure monitors have suggested that average 60-Hz magnetic field
exposures for passengers and conductors may exceed 50 mG. A U.S.
government-sponsored exposure assessment study of electric rail systems
found average 60-Hz magnetic field levels in train operator compartments that
ranged from 0.4 mG (Boston high speed trolley) to 31.1 mG (North Jersey
transit). The graph below shows average and maximum magnetic field
measurements in operator compartments of several electric rail systems. It
illustrates that 60 Hz is one of several electromagnetic frequencies to which train
operators are exposed.
Workers who maintain the tracks on electric rail lines, primarily in the
northeastern United States, also have elevated magnetic field exposures at both
25 Hz and 60 Hz. Measurements taken by the National Institute for Occupational
Safety and Health show that typical average daily exposures range from 3 to 18
mG, depending on how often trains pass the work site.
Rapid transit and light rail systems in the United States, such as the Washington
D.C. Metro and the San Francisco Bay Area Rapid Transit, run on DC electricity.
These DC-powered trains contain equipment that produces AC fields. For
example, areas of strong AC magnetic fields have been measured on the
Washington Metro close to the floor, during braking and acceleration,
presumably near equipment located underneath the subway cars.
****Click Here to See Large Image****
These graphs illustrate that 60 Hz is one of several electromagnetic
frequencies to which train operators are exposed. The maximum
exposure is the top of the blue (upper) portion of the bar; the
average exposure is the top of the red (lower) portion.
Q How can I find out how strong the EMF is where I live and work?
A The tables throughout this chapter can give you a general idea about magnetic
field levels at home, for different jobs, and around various kinds of electrical
equipment. For specific information about EMF from a particular power line,
contact the utility that operates the line. Some will perform home EMF
measurements.
You can take your own EMF measurements with a magnetic field meter. For a
spot measurement to provide a useful estimate of your EMF exposure, it should
be taken at a time of day and location when and where you are typically near the
equipment. Keep in mind that the strength of a magnetic field drops off quickly
with distance.
Independent technicians will conduct EMF measurements for a fee. Search the
Internet under "EMF meters" or "EMF measurement." You should investigate the
experience and qualifications of commercial firms, since governments do not
standardize EMF measurements or certify measurement contractors.
At work, your plant safety officer, industrial hygienist, or other local safety official
can be a good source of information. The National Institute for Occupational
Safety and Health (NIOSH) sometimes conducts health hazard evaluations in
workplaces where EMF is a suspected cause for concern. For further technical
assistance, contact NIOSH at 800-356-4674.
Q How much do computers contribute to my EMF exposure?
A Personal computers themselves produce very little EMF. However,
the video display terminal (VDT) or monitor provides some
magnetic field exposure unless it is of the new flat-panel design.
Conventional VDTs containing cathode ray tubes use magnetic
fields to produce the image on the screen, and some emission of
those magnetic fields is unavoidable. Unlike most other appliances
which produce predominantly 60-Hz magnetic fields, VDTs emit magnetic fields
in both the extremely low frequency (ELF) and very low frequency (VLF)
frequency ranges. Many newer VDTs have been designed to minimize magnetic
field emissions, and those identified as "TCO'99 compliant" meet a standard for
low emissions.
Q What can be done to limit EMF exposure?
A Personal exposure to EMF depends on three things: the strength of the
magnetic field sources in your environment, your distance from those sources,
and the time you spend in the field.
If you are concerned about EMF exposure, your first step should be to find out
where the major EMF sources are and move away from them or limit the time
you spend near them. Magnetic fields from appliances decrease dramatically
about an arm's length away from the source. In many cases, rearranging a bed,
a chair, or a work area to increase your distance from an electrical panel or
some other EMF source can reduce your EMF exposure.
Another way to reduce EMF exposure is to use equipment designed to have
relatively low EMF emissions. Sometimes electrical wiring in a house or a
building can be the source of strong magnetic field exposure. Incorrect wiring is
a common source of higher-than-usual magnetic fields. Wiring problems are also
worth correcting for safety reasons.
In its 1999 report to Congress, the National Institute of Environmental Health
Sciences suggested that the power industry continue its current practice of siting
power lines to reduce EMF exposures.
There are more costly actions, such as burying power lines, moving out of a
home, or restricting the use of office space that may reduce exposures. Because
scientists are still debating whether EMF is a hazard to health, it is not clear that
the costs of such measures are warranted. Some EMF reduction measures may
create other problems. For instance, compacting power lines reduces EMF but
increases the danger of accidental electrocution for line workers.
We are not sure which aspects of the magnetic field exposure, if any, to reduce.
Future research may reveal that EMF reduction measures based on today's
limited understanding are inadequate or irrelevant. No action should be taken to
reduce EMF exposure if it increases the risk of a known safety hazard.
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5 EMF Exposure Standards
This chapter describes standards and guidelines established by state, national, and
international safety organizations for some EMF sources and exposures.
· Are there exposure standards for 60-Hz EMF?
· Does EMF affect people with pacemakers or other medical devices?
· What about products advertised as producing low or reduced magnetic fields?
· Are cellular telephones and towers sources of EMF exposure?
Q Are there exposure standards for 60-Hz EMF?
A In the United States, there are no federal standards limiting occupational or
residential exposure to 60-Hz EMF.
At least six states have set standards for transmission line electric fields; two of
these also have standards for magnetic fields (see table below). In most cases,
the maximum fields permitted by each state are the maximum fields that existing
lines produce at maximum load-carrying conditions. Some states further limit
electric field strength at road crossings to ensure that electric current induced
into large metal objects such as trucks and buses does not represent an electric
shock hazard.
State Transmission Line Standards and Guidelines
Electric Field Magnetic Field
State On R.O.W.* Edge R.O.W. On R.O.W. Edge R.O.W.
Florida 8 kV/ma
10 kV/mb
2 kV/m - 150 mGa (max. load)
200 mGb (max. load)
250 mGc (max. load)
Minnesota 8 kV/m - - -
Montana 7 kV/m 1 kV/me - -
New Jersey - 3 kV/m - -
New York 11.8 kV/m
11.0 kV/mf
7.0 kV/m d
1.6 kV/m - 200 mG (max. load)
Oregon 9 kV/m - - -
*R.O.W. = right-of -way (or in the Florida standard, certain additional areas adjoining the right-
of -way).
kV/m = kilovolt per meter. One kilovolt = 1,000 volts.
a For lines of 69-230 kV.
b For 500 kV lines.
c For 500 kV lines on certain existing R.O.W.
d Maximum for highway crossings.
e May be waived by the landowner.
f Maximum for private road crossings.
Two organizations have developed voluntary occupational exposure guidelines
for EMF exposure. These guidelines are intended to prevent effects, such as
induced currents in cells or nerve stimulation, which are known to occur at high
magnitudes, much higher (more than 1,000 times higher) than EMF levels found
typically in occupational and residential environments. These guidelines are
summarized in the tables on the right.
ICNIRP Guidelines for EMF Exposure
Exposure (60 Hz) Electric field Magnetic field
Occupational
General Public
8.3 kV/m
4.2 kV/m
4.2 G (4,200 mG)
0.833 G (833 mG)
International Commission on Non-Ionizing Radiation Protection (ICNIRP) is an organization of
15,000 scientists from 40 nations who specialize in radiation protection.
Source: ICNIRP, 1998.
ACGIH Occupational Threshold Limit Values for 60-Hz EMF
Electric field Magnetic field
Occupational exposure should not exceed
Prudence dictates the use of protective
clothing above
Exposure of workers with cardiac
pacemakers should not exceed
25 kV/m
15 kV/m
1 kV/m
10 G (10,000 mG)
-
1 G (1,000 mG)
American Conference of Governmental Industrial Hygienists (ACGIH) is a professional
organization that facilitates the exchange of technical information about worker health
protection. It is not a government regulatory agency.
Source: ACGIH, 2001.
The International Commission on Non-Ionizing Radiation Protection (ICNIRP)
concluded that available data regardingpotential long-term effects, such as
increased risk of cancer, are insufficient to provide a basis for setting exposure
restrictions.
The American Conference of Governmental Industrial Hygienists (ACGIH)
publishes "Threshold Limit Values" (TLVs) for various physical agents. The TLVs
for 60-Hz EMF shown in the table are identified as guides to control exposure;
they are not intended to demarcate safe and dangerous levels.
Q Does EMF affect people with pacemakers or other medical devices?
A According to the U.S. Food and Drug Administration (FDA), interference from
EMF can affect various medical devices including cardiac pacemakers and
implantable defibrillators. Most current research in this area focuses on higher
frequency sources such as cellular phones, citizens band radios, wireless
computer links, microwave signals, radio and television transmitters, and paging
transmitters.
Sources such as welding equipment, power lines at electric generating plants,
and rail transportation equipment can produce lower frequency EMF strong
enough to interfere with some models of pacemakers and defibrillators. The
occupational exposure guidelines developed by ACGIH state that workers with
cardiac pacemakers should not be exposed to a 60-Hz magnetic field greater
than 1 gauss (1,000 mG) or a 60-Hz electric field greater than 1 kilovolt per
meter (1,000 V/m) (see ACGIH guidelines above). Workers who are concerned
about EMF exposure effects on pacemakers, implantable defibrillators, or other
implanted electronic medical devices should consult their doctors or industrial
hygienists.
Nonelectronic metallic medical implants (such as artificial joints, pins, nails,
screws, and plates) can be affected by high magnetic fields such as those from
magnetic resonance imaging (MRI) devices and aluminum refining equipment,
but are generally unaffected by the lower fields from most other sources.
The FDA MedWatch program is collecting information about medical device
problems thought to be associated with exposure to or interference from EMF.
Anyone experiencing a problem that might be due to such interference is
encouraged to call and report it (800-332-1088).
Q What about products advertised as producing low or reduced magnetic
fields?
A Virtually all electrical appliances and devices emit electric and magnetic fields.
The strengths of the fields vary appreciably both between types of devices and
among manufacturers and models of the same type of device. Some appliance
manufacturers are designing new models that, in general, have lower EMF than
older models. As a result, the words "low field" or "reduced field" may be relative
to older models and not necessarily relative to other manufacturers or devices.
At this time, there are no domestic or international standards or guidelines
limiting the EMF emissions of appliances.
The U.S. government has set no standards for magnetic fields from computer
monitors or video display terminals (VDTs). The Swedish Confederation of
Professional Employees (TCO) established in 1992 a standard recommending
strict limits on the EMF emissions of computer monitors. The VDTs should
produce magnetic fields of no more than 2 mG at a distance of 30 cm (about 1 ft)
from the front surface of the monitor and 50 cm (about 1 ft 8 in) from the sides
and back of the monitor. The TCO'92 standard has become a de facto standard
in the VDT industry worldwide. A 1999 standard, promulgated by the Swedish
TCO (known as the TCO'99 standard), provides for international and
environmental labeling of personal computers. Many computer monitors
marketed in the U.S. are certified as compliant with TCO'99 and are thereby
assured to produce low magnetic fields.
Beware of advertisements claiming that the federal government has certified that
the advertised equipment produces little or no EMF. The federal government has
no such general certification program for the emissions of low-frequency EMF.
The U.S. Food and Drug Administration's Center for Devices and Radiological
Health (CDRH) does certify medical equipment and equipment producing high
levels of ionizing radiation or microwave radiation. Information about certain
devices as well as general information about EMF is available from the CDRH at
888-463-6332.
Q Are cellular telephones and towers sources of EMF exposure?
A Cellular telephones and towers involve radio-frequency and microwave-
frequency electromagnetic fields. These are in a much higher frequency range
than are the power-frequency electric and magnetic fields associated with the
transmission and use of electricity.
The U.S. Federal Communications Commission (FCC) licenses communications
systems that use radio-frequency and microwave electromagnetic fields and
ensures that licensed facilities comply with exposure standards. Public
information on this topic is published on two FCC Internet sites:
http://www.fcc.gov/oet/info/documents/bulletins/#56 and
http://www.fcc.gov/oet/rfsafety/
The U.S. Food and Drug Administration also provides information about cellular
telephones on its web site (http://www.fda.gov/cdrh/ocd/mobilphone.html).
On to National and International EMF Reviews
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6 National and International EMF
Reviews
This chapter presents the findings and recommendations of major EMF research
reviews, including the U.S. government's EMF RAPID Program.
· What have national and international agencies concluded about the impact of EMF
exposure on human health?
· What other U.S. organizations have reported on EMF?
· What can we conclude about EMF at this time?
Q What have national and international agencies concluded about the impact
of EMF exposure on human health?
A Since 1995, two major U.S. reports have concluded that limited evidence exists
for an association between EMF exposure and increased leukemia risk, but that
when all the scientific evidence is considered, the link between EMF exposure
and cancer is weak. The World Health Organization in 1997 reached a similar
conclusion.
The two reports were the U.S. National Academy of Sciences report in 1996
and, in 1999, the National Institute of Environmental Health Sciences report to
the U.S. Congress at the end of the U.S. EMF Research and Public Information
Dissemination (RAPID) Program.
The U.S. EMF RAPID Program
Initiated by the U.S. Congress and established by law in 1992, the U.S. EMF
Research and Public Information Dissemination (EMF RAPID) Program set out
to study whether exposure to electric and magnetic fields produced by the
generation, transmission, or use of electric power posed a risk to human health.
For more information about the EMF RAPID Program, visit the web site
(http://www.niehs.nih.gov/emfrapid/).
The U.S. Department of Energy (DOE) administered the overall EMF RAPID
Program, but health effects research and risk assessment were supervised by
the National Institute of Environmental Health Sciences (NIEHS), a branch of the
U.S. National Institutes of Health (NIH). Together, DOE and NIEHS oversaw
more than 100 cellular and animal studies, as well as engineering and exposure
assessment studies. Although the EMF RAPID Program did not fund any
additional epidemiological studies, an analysis of the many studies already
conducted was an important part of its final report.
The electric power industry contributed about half, or $22.5 million, of the $45
million eventually spent on EMF research over the course of the EMF RAPID
Program. The NIEHS received $30.1 million from this program for research,
public outreach, administration, and the health assessment evaluation of
extremely low frequency (ELF) EMF. The DOE received approximately $15
million from this program for engineering and EMF mitigation research. The
NIEHS contributed an additional $14.5 million for support of extramural and
intramural research including long-term toxicity and carcinogenicity studies
conducted by the National Toxicology Program.
EMF RAPID Program
Interagency Committee
· National Institute of Environmental Health Sciences
· Department of Energy
· Department of Defense
· Department of Transportation
· Environmental Protection Agency
· Federal Energy Regulatory Commission
· National Institute of Standards and Technology
· Occupational Safety and Health Administration
· Rural Electrification Administration
An interagency committee was established by the President of the United States
to provide oversight and program management support for the EMF RAPID
Program. The interagency committee included representatives from NIEHS,
DOE, and seven other federal agencies with EMF-related responsibilities.
The EMF RAPID Program also received advice from a National EMF Advisory
Committee (NEMFAC), which included representatives from citizen groups,
labor, utilities, the National Academy of Sciences, and other groups. They met
regularly with DOE and NIEHS staff to express their views. NEMFAC meetings
were open to the public. The EMF RAPID Program sponsored citizen
participation in some scientific meetings as well. A broad
group of citizens reviewed all major public information
materials produced for the program.
NIEHS Working Group Report 1998
In preparation for the EMF RAPID Program's goal of
reporting to the U.S. Congress on possible health effects
from exposure to EMF from power lines, the NIEHS
convened an expert working group in June 1998. Over 9
days, about 30 scientists conducted a complete review of
EMF studies, including those sponsored by the EMF RAPID Program and
others. Their conclusions offered guidance to the NIEHS as it prepared its report
to Congress.
Using criteria developed by the International Agency for Research on Cancer, a
majority of the members of the working group concluded that exposure to power-
frequency EMF is a possible human carcinogen.
The majority called their opinion "a conservative public health decision based on
limited evidence for an increased occurrence of childhood leukemias and an
increased occurrence of chronic lymphocytic leukemia (CLL) in occupational
settings." For these diseases, the working group reported that animal and
cellular studies neither confirm nor deny the epidemiological studies' suggestion
of a disease risk. This report is available on the NIEHS EMF RAPID web site
(http://www.niehs.nih.gov/emfrapid/).
NIEHS Report to Congress at Conclusion of EMF RAPID Program
In June 1999, the NIEHS reported to the U.S. Congress that scientific evidence
for an EMF-cancer link is weak.
The following are excerpts from the 1999 NIEHS report:
The NIEHS believes that the probability that ELF-EMF
exposure is truly a health hazard is currently small. The weak
epidemiological associations and lack of any laboratory
support for these associations provide only marginal,
scientific support that exposure to this agent is causing any
degree of harm.
The scientific evidence suggesting that extremely low
frequency EMF exposures pose any health risk is weak. The
strongest evidence for health effects comes from associations
observed in human populations with two forms of cancer: childhood leukemia
and chronic lymphocytic leukemia in occupationally exposed adults. While the
support from individual studies is weak, the epidemiological studies
demonstrate, for some methods of measuring exposure, a fairly consistent
pattern of a small, increased risk with increasing exposure that is somewhat
weaker for chronic lymphocytic leukemia than for childhood leukemia. In
contrast, the mechanistic studies and the animal toxicology literature fail to
demonstrate any consistent pattern across studies, although sporadic findings of
biological effects (including increased cancers in animals) have been reported.
No indication of increased leukemias in experimental animals has been
observed.
The full report is available on the NIEHS EMF RAPID web site
(http://www.niehs.nih.gov/emfrapid/).
No regulatory action was recommended or taken based on the NIEHS report.
The NIEHS director, Dr. Kenneth Olden, told the Congress that, in his opinion,
the conclusion of the NIEHS report was not sufficient to warrant aggressive
regulatory action.
The NIEHS did not recommend adopting EMF standards for electric appliances
or burying electric power lines. Instead, it recommended providing public
information about practical ways to reduce EMF exposure. The NIEHS also
suggested that power companies and utilities "continue siting power lines to
reduce exposures and . . . explore ways to reduce the creation of magnetic fields
around transmission and distribution lines without creating new hazards." The
NIEHS encouraged manufacturers to reduce magnetic fields at a minimal cost,
but noted that the risks do not warrant expensive redesign of electrical
appliances.
The NIEHS also encouraged individuals who are concerned about EMF in their
homes to check to see if their homes are properly wired and grounded, since
incorrect wiring or other code violations are a common source of higher-than-
usual magnetic fields.
National Academy of Sciences Report
In October 1996, a National Research Council committee of the National
Academy of Sciences (NAS) released its evaluation of research on potential
associations between EMF exposure and cancer, reproduction, development,
learning, and behavior. The r eport concluded:
Based on a comprehensive evaluation of published studies relating to the effects
of power-frequency electric and magnetic fields on cells, tissues, and organisms
(including humans), the conclusion of the committee is that the current body of
evidence does not show that exposure to these fields presents a human-health
hazard. Specifically, no conclusive and consistent evidence shows that
exposures to residential electric and magnetic fields produce cancer, adverse
neurobehavioral effects, or reproductive and developmental effects.
The NAS report focused primarily on the association of childhood leukemia with
the proximity of the child's home to power lines. The NAS panel found that
although a link between EMF exposure and increased risk for childhood
leukemia was observed in studies that had estimated EMF exposure using the
wire code method (distance of home from power line), such a link was not found
in studies that had included actual measurements of magnetic fields at the time
of the study. The panel called for more research to pinpoint the unexplained
factors causing small increases in childhood leukemia in houses close to power
lines.
World Health Organization International EMF Project
The World Health Organization (WHO) International EMF Project, with
headquarters in Geneva, Switzerland, was launched at a 1996 meeting with
representatives of 23 countries attending. It was intended to respond to growing
concerns in many member states over possible EMF health effects and to
address the conflict between such concerns and technological and economic
progress. In its advisory role, the WHO International EMF Project is now
reviewing laboratory and epidemiological evidence,
identifying gaps in scientific knowledge,developing an
agenda for future research, and developing risk
communication booklets and other public information. The
WHO International EMF Project is funded with
contributions from governments and institutions and is
expected to provide an overall EMF health risk assessment. Additional
information about this program can be found on the WHO EMF web site
(http://www.who.int/peh-emf/).
As part of this project, in 1997 a working group of 45 scientists from around the
world surveyed the evidence for adverse EMF health effects. They reported that,
"taken together, the findings of all published studies are suggestive of an
association between childhood leukemia and estimates of ELF (extremely low
frequency or power-frequency) magnetic fields."
Much like the 1996 U.S. NAS report, the WHO report noted that living in homes
near power lines was associated with an approximate 1.5-fold excess risk of
childhood leukemia. But unlike the NAS panel, WHO scientists had seen the
results of the 1997 U.S. National Cancer Institute study of EMF and childhood
leukemia. This work showed even more strongly the inconsistency between
results of studies that used a wire code to estimate EMF exposure and studies
that actually measured magnetic fields.
Regarding health effects other than cancer, the WHO scientists reported that the
epidemiological studies "do not provide sufficient evidence to support an
association between extremely-low-frequency magnetic-field exposure and adult
cancers, pregnancy outcome, or neurobehavioural disorders."
World Health Organization International Agency for Research on Cancer
The WHO International Agency for Research on Cancer (IARC) produces a
monograph series that reviews the scientific evidence regardi ng potential
carcinogenicity associated with exposure to environmental agents. An
international scientific panel of 21 experts from 10 countries met in June 2001 to
review the scientific evidence regarding the potential carcinogenicity of static and
ELF (extremely low frequency or power-frequency) EMF. The panel categorized
its conclusions for carcinogenicity based on the IARC classification system--a
system that evaluates the strength of evidence from epidemiological, laboratory
(human and cellular), and mechanistic studies. The panel classified power-
frequency EMF as "possibly carcinogenic to humans" based on a fairly
consistent statistical association between a doubling of risk of childhood
leukemia and magnetic field exposure above 0.4 microtesla (0.4 µT, 4 milligauss
or 4 mG).
In contrast, they found no consistent evidence that childhood EMF exposures
are associated with other types of cancer or that adult EMF exposures are
associated with increased risk for any kind of cancer. The IARC panel reported
that no consistent carcinogenic effects of EMF exposure have been observed in
experimental animals and that there is currently no scientific explanation for the
observed association between childhood leukemia and EMF exposure. Further
information can be obtained at the IARC web sites (http://www.iarc.fr/ and
http://monographs.iarc.fr/).
International Commission on Non-Ionizing Radiation Protection
The International Commission on Non-Ionizing Radiation Protection (ICNIRP)
issued exposure guidelines to guard against known adverse effects such as
stimulation of nerves and muscles at very high EMF levels, as well as shocks
and burns caused by touching objects that conduct electricity. In April 1998,
ICNIRP revised its exposure guidelines and characterized as "unconvincing" the
evidence for an association between everyday power-frequency EMF and
cancer.
European Union
In 1996, a European Union (EU) advisory panel provided an overview of the
state of science and standards among EU countries. With respect to power-
frequency EMF, the panel members said that there is no clear evidence that
exposure to EMF results in an increased risk of cancer.
Australia--Radiation Advisory Committee Report to Parliament
In 1997, Australia's Radiation Advisory Committee briefly reviewed the EMF
scientific literature and advised the Australian Parliament that, overall, there is
insufficient evidence to come to a firm conclusion regarding possible health
effects from exposure to power-frequency magnetic fields.
The committee also reported that "the weight of opinion as expressed in the U.S.
National Academy of Sciences report, and the negative results from the National
Cancer Institute study (Linet et al., 1997) would seem to shift the balance of
probability more towards there being no identifiable health effects".
Canada--Health Canada Report
In December 1998, a working group of public health officers at Health Canada,
the federal agency that manages Canada's health care system, issued a review
of the scientific literature regarding power-frequency EMF health effects. They
found the evidence to be insufficient to conclude that EMF causes a risk of
cancer.
The report concluded that while EMF effects may be observed in biological
systems in a laboratory, no adverse health effects have been demonstrated at
the levels to which humans and animals are typically exposed.
As for epidemiology, 25 years of study results are inconsistent and inconclusive,
the panel said, and a plausible EMF-cancer mechanism is missing. Health
Canada pledged to continue monitoring EMF research and to reassess this
position as new information becomes available.
Germany--Ordinance 26
On January 1, 1997, Germany became the first nation to adopt a national rule on
EMF exposure for the general public. Ordinance 26 applies only to facilities such
as overhead and underground transmission and distribution lines, transformers,
switchgear and overhead lines for electric-powered trains. Both electric (5 kV/m)
and magnetic field exposure limits (1 Gauss) are high enough that they are
unlikely to be encountered in ordinary daily life. The ordinance also requires that
precautionary measures be taken on a case-by-case basis when electric
facilities are sited or upgraded near homes, hospital, schools, day care centers,
and playgrounds.
Great Britain--National Radiological Protection Board Report
The National Radiological Protection Board (NRPB) in Great Britain advises the
government of the United Kingdom regarding standards of protection for
exposure to non-ionizing radiation. The NRPB's advisory group on non-ionizing
radiation periodically reviews new developments in EMF research and reports its
findings. Results of the advisory group's latest review were published in 2001.
The report reviewed residential and occupational epidemiological studies, as
well as cellular, animal, and human volunteer studies that had been published.
The advisory group noted that there is "some epidemiological evidence that
prolonged exposure to higher levels of power frequency magnetic fields is
associated with a small risk of leukaemia in children." Specifically, the NRPB
advisory group's analysis suggests "that relatively heavy average exposures of
0.4 µT [4 mG] or more are associated with a doubling of the risk of leukaemia in
children under 15 years of age." The group pointed out, however, that laboratory
experiments have provided "no good evidence that extremely low frequency
electromagnetic fields are capable of producing cancer."
Scandinavia--EMF Developments
In October 1995, a group of Swedish researchers and government officials
published a report about EMF exposure in the workplace. This "Criteria Group"
reviewed EMF scientific literature and, using the IARC classification system,
ranked occupational EMF exposure as "possibly carcinogenic to humans." They
also endorsed the Swedish government's 1994 policy statement that public
exposure limits to EMFs were not needed, but that people might simply want to
use caution with EMFs.
In 1996, five Swedish government agencies further explained their precautionary
advice about EMF. EMF exposure should be reduced, they said, but only when
practical, without great inconvenience or cost.
Health experts in Norway, Denmark, and Finland generally agreed in reviews
published in the 1990s that if an EMF health risk exists, it is small. They
acknowledged that a link between residential magnetic fields and childhood
leukemia cannot be confirmed or denied. In 1994, several Norwegian
government ministries also recommended increasing the distance between
residences and electrical facilities, if it could be done at low cost and with little
inconvenience.
Q What other U.S. organizations have reported on EMF?
A American Medical Association
In 1995, the American Medical Association advised physicians that no
scientifically documented health risk had been associated with "usually
occurring" EMF, based on a review of EMF epidemiological, laboratory studies,
and major literature reviews.
American Cancer Society
In 1996, the American Cancer Society released a review of 20 years of EMF
epidemiological research including occupational studies and residential studies
of adult and childhood cancer. The society noted that some data support a
possible relationship of magnetic field exposure with leukemia and brain cancer,
but further research may not be justified if studies continue to find uncertain
results. Of particular interest is the summary of results from eight studies of risk
from use of household appliances with relatively high magnetic fields, such as
electric blankets and electric razors. The summary suggested that there is no
persuasive evidence for increased risk with more frequent or longer use of these
appliances.
American Physical Society
The American Physical Society (APS) represents thousands of U.S. physicists.
Responding to the NIEHS Working Group's conclusion that EMF is a possible
human carcinogen, the APS executive board voted in 1998 to reaffirm its 1995
opinion that there is "no consistent, significant link between cancer and power
line fields."
California's Department of Health Services
In 1996, California's Department of Health Services (DHS) began an ambitious
five-year effort to assess possible EMF public health risk and offer guidance to
school administrators and other decision-makers. The California Electric and
Magnetic Fields (EMF) Program is a research, education, and technical
assistance program concerned with the possible health effects of EMF from
power lines, appliances, and other uses of electricity. The program's goal is to
find a rational and fair approach to dealing with the potential risks, if any, of
exposure to EMF. This is done through research, policy analysis, and education.
The web site has educational materials on EMF and related health issues for
individuals, schools, government agencies, and professional organizations
(http://www.dhs.ca.gov/ps/deodc/ehib/emf/).
Q What can we conclude about EMF at this time?
A Electricity is a beneficial part of our daily lives, but whenever electricity is
generated, transmitted, or used, electric and magnetic fields are created. Over
the past 25 years, research has addressed the question of whether exposure to
power-frequency EMF might adversely affect human health. For most health
outcomes, there is no evidence that EMF exposures have adverse effects. There
is some evidence from epidemiology studies that exposure to power-frequency
EMF is associated with an increased risk for childhood leukemia. This
association is difficult to interpret in the absence of reproducible laboratory
evidence or a scientific explanation that links magnetic fields with childhood
leukemia.
EMF exposures are complex and come from multiple sources in the home and
workplace in addition to power lines. Although scientists are still debating
whether EMF is a hazard to health, the NIEHS recommends continued
education on ways of reducing exposures. This booklet has identified some EMF
sources and some simple steps you can take to limit your exposure. For your
own safety, it is important that any steps you take to reduce your exposures do
not increase other obvious hazards such as those from electrocution or fire. At
the current time in the United States, there are no federal standards for
occupational or residential exposure to 60-Hz EMF.
On to References
EMF Questions & Answers Home | Introduction | EMF Basics | Evaluating Potential Health
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For More Information About EMF: Web Center
7 References
Selected references on EMF topics.
· Basic Science
· EMF Levels and Exposures
· EMF Standards and Regulations
· Residential Childhood Cancer Studies
· Residential Adult Cancer Studies
· Occupational EMF Cancer Studies
· Laboratory Animal EMF Studies
· Laboratory Cellular EMF Studies
· National Reviews of EMF Research
Basic Science
· Kovetz A. Electromagnetic Theory. New York: Oxford University Press (2000).
· Vanderlinde J. Classical Electromagnetic Theory. New York: Wiley (1993).
EMF Levels and Exposures
· Dietrich FM & Jacobs WL. Survey and Assessment of Electric and Magnetic
(EMF) Public Exposure in the Transportation Environment. Report of the U. S.
Department of Transportation. NTIS Docume nt PB99-130908. Arlington, VA:
National Technical Information Service (1999).
· Kaune WT. Assessing human exposure to power-frequency electric and
magnetic fields. Environmental Health Perspectives 101:121-133 (1993).
· Kaune WT & Zaffanella L. Assessing historical exposure of children to power
frequency magnetic fields. Journal of Exposure Analysis Environmental
Epidemiology 4:149-170 (1994).
· Tarone RE, Kaune WT, Linet MS, Hatch EE, Kleinerman RA, Robison LL, Boice
JD & Wacholder S. Residential wire codes: Reproducibility and relation with
measured magnetic fields. Occupational and Environmental Medicine 55:333-
339 (1998).
· U.S. Environmental Protection Agency. EMF in your environment: magnetic
field measurements of everyday electrical devices. Washington, DC: Office of
Radiation and Indoor Air, Radiation Studies Division, U.S. Environmental
Protection Agency, Report No. 402-R-92-008 (1992).
· Zaffanella L. Survey of residential magnetic field sources. Volume 1: Goals,
Results and Conclusions. EPRI Report No. TR-102759. Palo Alto, CA:Electric
Power Research Institute (EPRI), 1993;1-224.
EMF Standards and Regulations
· Documentation of the Threshold Limit Values and Biological Exposure Indices,
7th Ed. Publication No. 0100. Cincinnati, OH: American Conference of
Governmental Industrial Hygienists (2001).
· ICNIRP International Commission on Non -Ionizing Radiation Protection.
Guidelines for Limiting Exposure to Time -Varying Electric, Magnetic, and
Electromagnetic Fields (up to 300 GHz). Health Physics 74:494-522 (1998).
· Swedish National Board of Occupational Safety and Health. Low-Frequency
Electrical and Magnetic Fields (SNBOSH): The Precautionary Principle for
National Authorities. Guidance for Decision-Makers. Solna (1996).
· U.S. Department of Transportation, F.R.A. Safety of High Speed Guided
Ground Transportation Systems, Magnetic and Electric Field Testing of the
Amtrak Northeast Corridor and New Jersey Coast Line Rail Systems, Volume I:
Analysis. Washington, DC: Office of Research and Development (1993).
Residential Childhood Cancer Studies
· Ahlbom A, Day N, Feychting M, Roman E, Skinner J, Dockerty J, Linet M,
McBride M, Michaelis J, Olsen JH, Tynes T & Verkasalo PK. A pooled analysis
of magnetic fields and childhood leukemia. British Journal of Cancer 83:692-
698 (2000).
· Coghill RW, Steward J & Philips A. Extra low frequency electric and magnetic
fields in the bedplace of children diagnosed with leukemia: A case-control
study. European Journal of Cancer Prevention 5:153-158 (1996).
· Dockerty JD, Elwood JM, Skegg DC, & Herbison GP. Electromagnetic field
exposures and childhood cancers in New Zealand. Cancer Causes and Control
9:299-309 (1998).
· Feychting M & Ahlbom A. Magnetic fields and cancer in children residing near
Swedish high-voltage power lines. American Journal of Epidemiology 138:467-
481 (1993).
· Greenland S, Sheppard AR, Kaune WT, Poole C & Kelsh MA. A pooled
analysis of magnetic fields, wire codes and childhood leukemia. EMF Study
Group. Epidemiology 11:624-634 (2000).
· Linet MS, Hatch EE, Kleinerman RA, Robison LL, Kaune WT, Friedman DR,
Severson RK, Haines CM, Hartsock CT, Niwa S, Wacholder S & Tarone RE.
Residential exposure to magnetic fields and acute lymphoblastic leukemia in
children. New England Journal of Medicine 337:1-7 (1997).
· London SJ, Thomas DC, Bowman JD, Sobel E, Cheng TC & Peters JM.
Exposure to residential electric and magnetic fields and risk of childhood
leukemia. American Journal of Epidemiology 134:923-937 (1991).
· McBride ML, Gallagher RP, Thériault G, Armstrong BG, Tamaro S, Spinelli JJ,
Deadman JE, Fincham B, Robson D & Choi W. Power-frequency electric and
magnetic fields and risk of childhood leukemia in Canada. American Journal of
Epidemiology 149:831-842 (1999).
· Michaelis J, Schuz J, Meinert R, Zemann E, Grigat JP, Kaatsch P, Kaletsch U,
Miesner A, Brinkmann K, Kalkner W, & Karner H. Combined risk estimates for
two German population-based case-control studies on residential magnetic
fields and childhood leukemia. Epidemiology 9:92-94 (1998).
· Olsen JH, Nielsen A & Schulgen G. Residence near high voltage facilities and
risk of cancer in children. British Medical Journal 307:891 -895 (1993).
· Savitz DA, Wachtel H, Barnes FA, John EM & Tvrdik JG. Case-control study of
childhood cancer and exposure to 60-Hz magnetic fields. American Journal of
Epidemiology 128:21-38 (1988).
· Tomenius L. 50-Hz electromagnetic environment and the incidence of childhood
tumors in Stockholm county. Bioelectromagnetics 7:191-207 (1986).
· Tynes T & Haldorsen T. Electromagnetic fields and cancer in children residing
near Norwegian high-voltage power lines. American Journal of Epidemiology
145:219-226 (1997).
· UK Childhood Cancer Study Investigators. Exposure to power frequency
magnetic fields and the risk of childhood cancer: a case/control study. Lancet
354:1925-1931 (1999).
· Verkasalo PK, Pukkala E, Hongisto MY, Valjus JE, Jarvinen PJ, Heikkila KV &
Koskenvuo M. Risk of cancer in Finnish children living close to power lines.
British Medical Journal 307:895-899 (1993).
Residential Adult Cancer Studies
· Coleman MP, Bell CM, Taylor HL & Primie-Zakelj M. Leukemia and residence
near electricity transmission equipment: a case-control study. British Journal of
Cancer 60:793-798 (1989).
· Feychting M & Ahlbom A. Magnetic fields, leukemia, and central nervous
system tumors in Swedish adults residing near high-voltage power lines.
Epidemiology 5:501-509 (1994).
· Li CY, Theriault G & Lin RS. Residential exposure to 60-hertz magnetic fields
and adult cancers in Taiwan. Epidemiology 8:25-30 (1997).
· McDowall ME. Mortality of persons resident in the vicinity of electricity
transmission facilities. British Journal of Cancer 53:271-279 (1986).
· Severson RK, Stevens RG, Kaune WT, Thomas DB, Heuser L, Davis S &
Sever LE. Acute nonlymphocytic leukemia and residential exposure to power
frequency magnetic fields. American Journal of Epidemiology 128:10-20 (1988).
· Wrensch M, Yost M, Miike R, Lee G & Touchstone J. Adult glioma in relation to
residential power-frequency electromagnetic field exposures in the San
Francisco Bay area. Epidemiology 10:523-527 (1999).
· Youngson JH, Clayden AD, Myers A & Cartwright RA. A case/control study of
adult haematological malignancies in relation to overhead powerlines. British
Journal of Cancer 63:977-985 (1991).
Occupational EMF Cancer Studies
· Coogan PF, Clapp RW, Newcomb PA, Wenzl TB, Bogdan G, Mittendorf R,
Baron JA & Longnecker MP. Occupational exposure to 60-Hertz magnetic fields
and risk of breast cancer in women. Epidemiology 7:459-464 (1996).
· Floderus B, Persson T, Stenlund C, Wennberg A, Ost A, & Knave B.
Occupational exposure to electromagnetic fields in relation to leukemia and
brain tumors: a case-control study in Sweden. Cancer Causes Control 4:465-
476 (1993).
· Floderus B, Tornqvist S, & Stenlund C. Incidence of selected cancers in
Swedish railway workers, 1961-79. Cancer Causes Control 5:189-194 (1994).
· Sorahan T, Nichols L, van Tongeren M, & Harrington JM. Occupational
exposure to magnetic fields relative to mortality from brain tumours: updated
and revised findings from a study of United Kingdom electricity generation and
transmission workers, 197397. Occupational and Environmental Medicine
58(10):626-630 (2001).
· Johansen C, & Olsen JH Risk of cancer among Danish utility workers - A
nationwide cohort study. American Journal of Epidemiology, 147:548-555
(1998).
· Kheifets LI, Gilbert ES, Sussman SS, Guenel P, Sahl JD, Savitz DA, & Theriault
G.Comparative analyses of the studies of magnetic fields and cancer in electric
utility workers: studies from France, Canada, and the United States.
Occupational and Environmental Medicine 56(8):567-574 (1999).
· London SJ, Bowman JD, Sobel E, Thomas DC, Garabrant DH, Pearce N,
Bernstein L & Peters JM . Exposure to magnetic fields among electrical workers
in relation to leukemia risk in Los Angeles County. American Journal of
Industrial Medicine 26:47-60 (1994).
· Matanoski GM, Breysse PN & Elliott EA. Electromagnetic field exposure and
male breast cancer. Lancet 337:737 (1991).
· Sahl JD, Kelsh MA, & Greenland S. Cohort and nested case-control studies of
hematopoietic cancers and brain cancer among utility worker. Epidemiology
4:21-32 (1994).
· Savitz DA & Loomis DP. Magnetic field exposure in relation to leukemia and
brain cancer mortality among electric utility workers. American Journal of
Epidemiology 141:123-134 (1995).
· Sorahan T, Nichols L, van Tongeren M, & Harrington JM. Occupational
exposure to magnetic fields relative to mortality from brain tumours: updated
and revised findings from a study of United Kingdom electricity generation and
transmission workers, 197397. Occupational and Environmental Medicine
58:626-630 (2001).
· Thériault G, Goldberg M, Miller AB, Armstrong B, Guénel P, Deadman J,
Imbernon E, To T, Chevalier A, Cyr D, & Wall C. Cancer risks associated with
occupational exposure to magnetic fields among electric utility workers in
Ontario and Quebec, Canada and France: 19701989.American Journal of
Epidemiology 139:550-572 (1994).
· Tynes T, Jynge H, & Vistnes AI. Leukemia and brain tumors in Norwegian
railway workers, a nested case-control study. American Journal of
Epidemiology 139:645-653 (1994).
Laboratory Animal EMF Studies
· Anderson LE, Boorman GA, Morris JE, Sasser LB, Mann PC, Grumbein SL,
Hailey JR, McNally A, Sills RC & Haseman JK. Effect of 13-week magnetic field
exposures on DMBA-initiated mammary gland carcinomas in female Sprague-
Dawley rats. Carcinogenesis 20:1615-1620 (1999).
· Baum A, Mevissen M, Kamino K, Mohr U & Löscher W. A histopathological
study on alterations in DMBA-induced mammary carcinogenesis in rats with 50
Hz, 100 mT magnetic field exposure. Carcinogenesis 16:119-125 (1995).
· Babbitt JT, Kharazi AI, Taylor JMG, Rafferty CN, Kovatch R, Bonds CB, Mirell
SG, Frumkin E, Dietrich F, Zhuang D & Hahn TJM. Leukemia/lymphoma in
mice exposed to 60-Hz magnetic fields: Results of the chronic exposure study
TR-110338. Los Angeles: Electric Power Research Institute (EPRI) (1998).
· Babbitt JT, Kharazi AI, Taylor JMG, Rafferty CN, Kovatch R, Bonds CB, Mirell
SG, Frumkin E, Dietrich F, Zhuang D & Hahn TJM. Leukemia/lymphoma in
mice exposed to 60-Hz magnetic fields: Results of the chronic exposure study,
Second Edition. Electric Power Research Institute (EPRI) and B. C. Hydro, Palo
Alto, California and Burnaby, British Columbia, Canada (1999).
· Boorman GA, Anderson LE, Morris JE, Sasser LB, Mann PC, Grumbein SL,
Hailey JR, McNally A, Sills RC & Haseman JK. Effect of 26-week magnetic field
exposures in a DMBA initiation-promotion mammary gland model in Sprague-
Dawley rats. Carcinogenesi s 20:899-904 (1999).
· Boorman GA, McCormick DL, Findlay JC, Hailey JR, Gauger JR, Johnson TR,
Kovatch RM, Sills RC & Haseman JK. Chronic toxicity/oncogenicity of 60 Hz
(power frequency) magnetic fields in F344/N rats. Toxicological Pathology
27:267-278 (1999).
· Boorman GA, McCormick DL, Ward JM, Haseman JK & Sills RC. Magnetic
fields and mammary cancer in rodents: A critical review and evaluation of
published literature. Radiation Research 153:617-626 (2000).
· Boorman GA, Rafferty CN, Ward JM & Sills RC. Leukemia and lymphoma
incidence in rodents exposed to low-frequency magnetic fields. Radiation
Research 153:627-636 (2000).
· Ekström T, Mild KH & Holmberg B. Mammary tumours in Sprague-Dawley rats
after initiation with DMBA followed by exposure to 50 Hz electromagnetic fields
in a promotional scheme. Cancer Letters 123:107-111 (1998).
· Mandeville R, Franco E, Sidrac-Ghali S, Paris-Nadon L, Rocheleau N, Mercier
G, Desy M & Gaboury L. Evaluation of the potential carcinogenicity of 60 Hz
linear sinusoidal continuous-wave magnetic fields in Fisher F344 rats.
Federation of the American Society of Experimental Biology Journal 11:1127 -
1136 (1997).
· McCormick DL, Boorman GA, Findlay JC, Hailey JR, Johnson TR, Gauger JR,
Pletcher JM, Sills RC & Haseman JK. Chronic toxicity/oncogenicity of 60 Hz
(power frequency) magnetic fields in B6C3F1 mice. Toxicological Pathology
27:279-285 (1999).
· Mevissen M, Lerchl A, Szamel M & Löscher W. Exposure of DMBA-treated
female rats in a 50-Hz, 50 microTesla magnetic field: Effects on mammary
tumor growth, melatonin levels and T-lymphocyte activation. Carcinogenesis
17:903-910 (1996).
· Yasui M, Kikuchi T, Ogawa M, Otaka Y, Tsuchitani M & Iwata H.
Carcinogenicity test of 50 Hz sinusoidal magnetic fields in rats.
Bioelectromagnetics 18:531-540 (1997).
Laboratory Cellular EMF Studies
· Balcer-Kubiczek EK, Harrison GH, Zhang XF, Shi ZM, Abraham JM, McCready
WA, Ampey LL, III, Meltzer SJ, Jacobs MC, & Davis CC. Rodent cell
transformation and immediate early gene expression following 60-Hz magnetic
field exposure. Environmental Health Perspectives 104:1188-1198 (1996).
· Boorman GA, Owen RD, Lotz WG & Galvin MJ, Jr. Evaluation of in vitro effects
of 50 and 60 Hz magnetic fields in regional EMF exposure facilities. Radiation
Research 153:648-657 (2000).
· Lacy-Hulbert A, Metcalfe JC, & Hesketh R. Biological responses to
electromagnetic fields. Federation of the American Society of Experimental
Biology (FASEB) Journal 12:395-420 (1998).
· Morehouse CA & Owen RD. Exposure of Daudi cells to low-frequency magnetic
fields does not elevate MYC steady-state mRNA levels. Radiation Research
153:663-669 (2000).
· Snawder JE, Edwards RM, Conover DL & Lotz WG. Effect of magnetic field
exposure on anchorage-independent growth of a promoter-sensitive mouse
epidermal cell line (JB6). Environmental Health Perspectives 107:195-198
(1999).
· Wey HE, Conover DL, Mathias P, Toraason MA & Lotz WG. 50-Hz magnetic
field and calcium transients in Jurkat cells: Results of a research and public
information dissemination (RAPID) program study. Environmental Health
Perspectives 108:135-140 (2000).
National Reviews of EMF Research
· American Medical Association. Council on Scientific Affairs. Effects of Electric
and Magnetic Fields. Chicago: American Medical Association (December
1994).
· National Institute for Occupational Safety and Health, National Institute of
Environmental Health Sciences, U.S. Department of Energy. Questions and
Answers: EMF in the Workplace. Electric and Magnetic Fields Associated with
the Use of Electric Power. Report No. DOE/GO-10095-218 (September 1996).
· National Radiological Protection Board. ELF Electromagnetic Fields and the
Risk of Cancer. Volume 12:1, Chilton, Didcot, Oxon, UK OX11 ORQ (2001).
· National Research Council, Committee on the Possible Effects of
Electromagnetic Fields on Biologic Systems. Possible Health Effects of
Exposure to Residential Electric and Magnetic Fields. Washington: National
Academy Press (1997).
· National Institute of Environmental Health Sciences Report on Health Effects
from Exposure to Power-Line Frequency Electric and Magnetic Fields. NIH
Publication No. 99-4493. Research Triangle Park, National Institute of
Environmental Health Sciences (1999).
· Portier CJ & Wolfe MS, Eds. Assessment of Health Effects from Exposure to
Power-Line Frequency Electric and Magnetic Fields--NIEHS Working Group
Report NIH Publication No. 98-3981. Research Triangle Park, National Institute
of Environmental Health Sciences (1998).
On to EMF Basics
EMF Questions & Answers Home | Introduction | EMF Basics | Evaluating Potential Health
Effects | Results of EMF Research | Your EMF Environment | EMF Exposure Standards |
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5. Permafrost Information
Alaska Science Forum
January 23, 1997
Thawing Permafrost Threatens Alaska's
Foundation
Article #1321
by Ned Rozell
This article is provided as a public service by the Geophysical Institute, University
of Alaska Fairbanks, in cooperation with the UAF research community. Ned Rozell
is a science writer at the institute.
Is Kipnuk sinking?
Eskimo elders in the coastal Alaska village think it might be. Tom Osterkamp
thinks he might know one of the reasons why--Alaska's permafrost is warming.
Osterkamp, a Geophysical Institute professor of physics who has studied
Alaska's permafrost for 25 years, recently received an e-mail message from a
colleague who told him of the Kipnuk elders' concerns.
Kipnuk, located about 100 miles west of Bethel, is a treeless village where
about 500 people live. The topographic map for the Kipnuk area looks like
Swiss cheese because the village sits amid hundreds of lakes. Kipnuk's
elevation is only about five feet above the level of the Bering Sea.
Ian Parks, the principal of Chief Paul Memorial School at Kipnuk, said
buildings in the village show signs of an unstable ground surface--walls
develop cracks, doors stick, and floors rise and fall.
"If you put a marble on the floor, in one year it'll roll in one direction; in the
next year it'll go the other direction," Parks said.
The symptoms Parks described are consistent with those of an area that sits on
top of thawing permafrost, Osterkamp said. Permafrost occurs under about 85
percent of Alaska's surface area; patches of permafrost can be found as far
south as Anchorage.
If thawing permafrost is Kipnuk's problem, the villagers aren't alone.
Osterkamp's recent measurements show that all permafrost south of the Yukon
River is warming, and in most cases there isn't one degree left between ice and
water.
Osterkamp monitors the temperature of permafrost with a network of one-inch
holes drilled in permafrost throughout the state. The holes, located near
Fairbanks, Anchorage, Bethel, Glennallen, Eagle, and other towns and villages,
have all been telling the same story. Since 1989, each time Osterkamp has
checked the temperatures of permafrost at depths from 10 to 25 meters, the
permafrost has crept closer to the melting point.
A test site off Stampede Trail in Healy provides an example of what's
happening to permafrost south of the Yukon River. In 1989, the permafrost
temperature 10 meters under the surface was about -1.27 degrees Celsius.
In 1990, the Stampede Trail permafrost warmed to -1.07 degrees. The
permafrost has warmed steadily since. When Osterkamp checked in July, 1996,
the permafrost 10 meters deep was about -0.7 degrees Celsius. These tenths of
a degree might not seem significant, but Osterkamp pointed out there's not
much more warming that can occur before the Stampede Trail permafrost is no
longer frozen.
There are two possible reasons why the permafrost has warmed south of the
Yukon River, Osterkamp said. Permafrost may be responding to a warmer
climate, or it may reflect the amount of snow that insulates the ground.
Whatever the cause, permafrost or a sudden lack thereof may catch the
attention of many Alaskans in the near future.
"If this (widespread permafrost thaw) comes about, it will change the face of
southern Alaska," Osterkamp said. In addition to creating roller coaster roads
and tilting buildings, thawing permafrost often causes large sections of forest to
collapse, killing trees and other vegetation that live on a foundation of
permafrost.
The future of permafrost south of the Yukon River isn't promising, Osterkamp
said. He cited computer models that predict a 3- to 5-degree Celsius warming in
the next 50 years.
"If that really occurs, it will thaw all of the permafrost south of the Yukon and
most of it south of the Brooks Range," he said.
That's a chilling thought.
[Water, Snow and Ice Index][Main Index]
6. Bethel River Bank Erosion Sketch
APPENDIX I
1. Agency and Public Comments
REPLY TO
ATTENTION OF:
DEPARTMENT OF THE ARMY
S. ARMY ENGINEER DISTRICT, ALASKA
O. BOX 6898
ELMENDORF AFB , ALASKA 99506-6898
MA'JJ 1 0 2004
TI IE
lE 0 \f lE r;:;'\
Regulatory Branch
North Section
POA-2003-0375
Mr. Bob Charles
President
Nuvista Light and Power Company
301 Calista Court, Suite A
Anchorage, AK 99518-3028
Dear Mr. Charles:
This letter is in response to your request for our review of the Donlin
Creek Mine Power Supply Feasibility Study We appreciate being kept apprised
of the proj ect development and schedule.
A cursory review of the Executive Summary identified several comment
items.
As noted on page 1-1.23, the Corps of Engineers (Corps) feels that the
Bethel power plant and transmission line are an integral component of the
Donlin Creek Mine proj ect and should be included in the National
Environmental Policy Act (NEPA) assessment. The onus of responsibility to
demonstrate that the Donlin Creek Mine Power Supply Project is a stand alone
proj ect and would be considered economically feasible separate from the
Donlin Creek Mine project, is upon you. You must convince the Corps that the
power plant in Bethel has independent utility and is not dependent upon the
economic development of the Donlin Creek Mine.
Tiering the NEPA analysis of the mine project off the power
plant/transmission line Environmental Impact Statement would be satisfactory
to the Corps.
Table 1-12 notes that Section 10 permits are required for work performed
in navigable waters below the ordinary high water mark. Permits are required
tor work "over " navigable waters as well, and in tidal waters the regulated
area is below the mean high water line. This is pertinent to the
transmission line and activities associated with the "transload point"
development.
If you have any questions, please contact me at 753-2716 or e-mail me at
mary. f .leykom. usace. army .mil.
Sincerely,
Mary Leykom
Regulatory Sp ~ ialist/Biologist
DENALI COMMISSION
510 "L" Street , Suite 410
Anchorage AK 99501
Matthew Nicolai
President/CEO
Calista Corportation
301 Calista Court, Suite A
Anchorage , AK 99518-3028
Dear .~Nicolai:
This is in response to your April 1 , 2004 letter which transmitted the Donlin Creek Mine Power
Supply Feasibility Study. While we believe the study provides some excellent information and
analysis , the Commission chose not to offer specific comments on the study at this time because
the context for the decisions regarding energy supply for the Donlin Creek Mine is still evolving.
(907) 271-1414
Fax (907) 271-1415
Toll Free (888) 480-4321
www.denali,gov
May 24 , 2004
We understand that Calista s interest in energy for the region is much broader than just the Donlin
Creek mine. The same is true for the Denali Commission. However, the mine is the driver for
the immediate decisions that must be made. We therefore believe is prudent to allow Placer
Dome , Inc. and Nova Gold , Inc. to evaluate available alternatives and decide how their energy
needs can best be met. There may then be some role the Commission can play in helping to make
that choice become a reality though the cost of the energy supply for the project needs to
primarily be borne by the project. Additionally we are hopeful that the energy choice made for
the mine will result in some new opportunities to lower the cost of energy for communities in the
regIOn.
We are advised that Placer Dome , Inc. and Nova Gold , Inc. will be making preliminary energy
supply issues in the next few months. We look forward to those decisions and to working with
you and others to make the mine a reality and to bring lower cost energy to the region.
nce lY'
C-)
~~~
Chief of Staff
cc:J Bob Charles , President
Nuvista Light & Power Company
Ron Miller , Executive Director
AIDEA/ AEA
BUREAU OF LAND MANAGEMENT
Alaska State Office
222 West Seventh Avenue, #13
Anchorage , Alaska 99513-7599
http://www.ak.blm.gov
TAKE PRIDE-INAMERICA
United States Department of the Interior
MAY 2 6 2004
Mr. Bob Charles, President
Nuvista Light and Power
301 Calista Court, Suite A
Anchorage AK 99518
Dear Mr. Charles:
Thank you for the opportunity to review the Donlin Creek Mine Power Supply Feasibility Study
of March 24 , 2004. It is a very comprehensive document and obviously the result of
considerable effort by your company.
It appears the potential routes shown for the power lines avoided BLM administered federal land
to the extent possible. Our rough calculations indicate that approximately 23 miles of the total
191 miles are on BLM administered public land. Of the 23 miles, all but approximately one mile
are on federal land selected by the TKC Native Corporation. If any of the selected lands are not
conveyyd by the time the power line construction begins and for the one mile of power line on
the un selected public land , a right of way from BLM would be required.
The power line, Donlin Creek Mine and the State of Alaska Yukon-Kuskowim road projects will
require that environmental impact statements or environmental assessments be prepared for each
or combined into one or more documents since they are potentially interrelated. At this time , it
has not been detennined which agencies would be involved and how comprehensive an analysis
would be required since the scope of the projects has not been fully detennined.
We appreciate that you are keeping us informed of the status of your project and request that you
continue to do so. It is important that we work together to assure your project continues on
schedule. Please contact June Bailey, the Anchorage Field Office Manager with any information
regarding the progress of your project and the need for rights of way or other authorizations on
BLM administered federal land.
ACllNG
Sincerely,
h~ e-
ASSOCIATE Henri Bisson
State Director
n reCEIVE
May 7 , 2004
~ ~~ ~
!YI1TIVE CO~~
Calista Corporation
Axel C. Johnson Building
301 Calista Court
Suite A
Anchorage , AK 99518-3028
Attn: Matthew Nicolai , President
RE: Proposed Coal-Fired Generation Plant in Bethel
Dear Matthew:
Bethel Native Corporation (BNC) held its Thirtieth Annual Shareholders meeting
this past weekend in Bethel. There were approximately two hundred people
attendance.
During the question and answer portion of the agenda , the subject of Calista
Corporation constructing a coal-fired generation plant in Bethel was discussed.
After considerable discussion concerning the environmental and health impact of
this project , the Shareholders unanimously approved a motion to oppose the
construction and operation of a coal-fired generation plant in Bethel.
The Shareholders asked that I personally inform you of their decision.
BOX 719 . BETHEL, ALASKA 99559 . (907) 543-2124 FAX (907) 543-2897
Nuvista Light & Power
May 5, 2004, Page 1 of 2
USIBELLI COAL MINE, INC.
PO Box 1000 • Healy, Alaska 99743
Telephone (907) 683-2226 • Facsimile (907) 683-2253
May 5, 2004
Mr. Bob Charles, President
Nuvista Light and Power Company
301 Calista Court, Suite A
Anchorage, Alaska 99518
Re: Donlin Creek Mine Power Supply Feasibility Study
Dear Mr. Charles,
I am in receipt of the Public Draft of the above referenced study. Although I was not able to
perform a thorough review of the total report, following are a few comments, which hopefully
will be useful and improve the project’s feasibility.
In general, I am disappointed that Usibelli coal did not measure up to imported coal in your
analysis, though I do understand the economic challenges the project faces and the necessity to
minimize project costs. We continue to look at ways to improve the economics for Alaskan coal
so that it is a cost effective fuel for reducing the cost of energy for Western Alaska residents.
Hopefully, your consultant can agree with some of the comments herein, which will tend to
improve the economics of utilizing coal from our Healy mine.
In any event, it would be a big mistake to design the boilers so that they are restricted to using
high grade bituminous coal. With the exception of the Western Arctic coal field, the vast
majority of Alaskan, and world, coal resources potentially accessible to the coast (such as in
Cook Inlet) are low rank coals. High rank bituminous coals are becoming more and more in
demand and a recent doubling of coal prices in the Pacific Rim should serve as a stark
demonstration that maintaining fuel flexibility in the plant would yield substantial savings in the
long run, regardless of where you source fuel supplies.
Usibelli coal quality used in the analysis is below normal specifications. The study uses an as
mined quality of 7,128 Btu/lb and an MAF value of 10,800 Btu/lb. I do not know the source of
the information on coal quality, however, all of the data published by ourselves pegs typical as-
mined quality at 7,800 Btu/lb and our data and various government reports lists MAF values of
11,800 to 12,100 Btu/lb for coals in the Healy area, Suntrana Formation.
Nuvista Light & Power
May 5, 2004, Page 2 of 2
The need for a covered storage pile is questionable. I have visited many power plants, coal
mines and ship loading facilities and I am not aware of any which store the volume of coal you
will be storing under cover. Some of our customers have stockpiles that have been static for
decades and we routinely build stockpiles that store coal in excess of one year. The remark that
it cannot be stored more than 60 days “without extensive monitoring and safety measures” is
overly pessimistic. Proper shaping and a little compaction, such as that achieved by spreading
with a bull dozer can adequately prepare a pile for a year’s storage. Proper shaping and
compaction will reduce the potential for spontaneous combustion and infiltration of water and
snow to an acceptable level. If additional protection is needed, a relatively low cost surface
spray can be applied.
Covering the storage pile will increase risk of loss due to fire. Any high volatile coal is subject
to spontaneous heating and ignition, though low rank coals are clearly more susceptible.
Another issue with bituminous coals is that they are more likely to release methane gas and the
oxidation of any coal in a stockpile can create potentially explosive gas concentrations. Even
with aggressive ventilation, there may be dead spots where gasses could accumulate. If
spontaneous heating occurs in the pile, it will be difficult and dangerous to deal with the hot spot
in a closed structure. In total, a covered stockpile is probably not a good idea and substantial
cost savings would result from utilizing a more conventional approach in both stockpile/reclaim
equipment cost and operating cost.
Wind loss assumption appears excessive. It seems rather far fetched that a coal pile could loose
up to 5% of its volume from wind. The mine mouth plant in Healy works from an open stockpile
and I would be surprised if the wind losses are a fraction of one percent and this area is called
Windy Pass for good reason.
The assumed ocean freight rate of $12.50 is low for today’s market. Current freight rates for
Panamax coal cargos from Roberts Bank to Japan are around $24 per metric ton. For
comparison, assume about 2/3’rds of the cost would be transit cost and the remainder is
load/unload cost. Since the voyage to Security Bay is about half the distance to Japan, this
would suggest a cost of around $16 per ton if you were using Panamax size vessels. The
proposed geared handy size vessels would cost more, so a price of $20 to $25 per ton would be
more likely.
Thank you for the opportunity to comment on this report. Time constraints prevented me from
looking outside coal supply related issues or doing the depth of review I might have liked.
Hopefully, these comments will be useful to you and help improve project economics in a few
areas.
Sincerely,
Steve W. Denton
VP Business Development
From: Bob Charles [bcharles@calistacorp.com]
Sent: Friday, April 09, 2004 9:16 AM
To: fbettine@acsalaska.net
Cc: June McAtee; Jeff Foley
Subject: FW: Proposed Nuvista Power Line Route
FYI
-----Original Message-----
From: Mark Leary [mailto:napaimute@avcp.org]
Sent: Friday, April 09, 2004 8:53 AM
To: Bob Charles
Cc: msherer@gci.net; platinum@alaska.net; bobby_kristovich@hotmail.com;
BriKare@gci.net; bobkris@gci.net; msherer@citci.com; kmmcintire@anmc.org
Subject: Proposed Nuvista Power Line Route
Good Morning Bob,
I've been studying the Public Draft Donlin Creek Mine Power Supply Feasibility
Study. One thing that has come to my attention is the proposed route of the
power line - especially segment J - K. This proposed segment shows the power
line running to Napaimute or very close to it. This is very appealing to us and
something that I believe Napaimute would support, but we need to be included in
the planning process. Napaimute isn't mentioned any where in the feasiblity
study.
I have attached a map of Napaimute's land selections that demonstrate the need
for us to be involved. We have been working on this for three years, long before
we heard any thing about supplying power to Donlin Creek from Bethel, yet you
can see that we selected right of ways that coincide almost exactly with parts
of the proposed power line route. We did this in anticipation that any future
road or utility corridor would most likely run very close to Napaimute or at
least to the north of us.
The final draft of Napaimute's Comprehensive Development Plan should be
completed in June. A copy will be provided to Calista that will show in greater
detail the extensive planning that has been done for Napaimute that will allow
the community to develop in conjunction with the up coming large scale regional
developments.
We look forward to working closely with Calista to help bring these developments
to reality.
Thank you.
Mark Leary
Tribal Administrator
Native Village of Napaimute
P.O. Box 1301
Bethel, Alaska 99559
Ph: (907) 543-2887 or (907) 467-6170 (Napaimute Office)
Fax: (907) 543-2892 or (907) 467-6171 (Napaimute Office)
email: napaimute@avcp.org (Bethel Office)
napaimute@starband.net (Napaimute Office)
From: Bob Charles [bcharles@calistacorp.com]
Sent: Wednesday, April 14, 2004 10:22 AM
To: Frank Bettine
Subject: FW: Donlin Power Study
-----Original Message-----
From: Mark Teitzel [mailto:mteitzel@avec.org]
Sent: Wednesday, April 14, 2004 10:09 AM
To: Bob Charles
Cc: Mark Teitzel
Subject: RE: Donlin Power Study
Bob: Thank you for the Section on Alternatives. It seems to mirror the excellent presentation
that Frank Bettine gave at the Economic Summit. I am very impressed with the level of
thought and detail that went into the overall report and hope to find time to read it in more
detail. Mark
-----Original Message-----
From: Bob Charles [mailto:bcharles@calistacorp.com]
Sent: Wednesday, April 14, 2004 9:51 AM
To: Mark Teitzel
Subject: FW: Donlin Power Study
Hi,
Attached is Section III-4 Other Power Alternatives for Volume I of the 2004 Donlin
Creek Power Supply Feasibility Study. This section was not included in the draft
report on CD that was sent earlier. It will be included in the final report. Volume I of
the report is available for download at our website:
http://www.calistacorp.com/energy.html
Regards,
Bob Charles
Vice-President, Government and Corporate Relations
Calista Corporation
301 Calista Court, Suite A
Anchorage, AK 99518
ph (907) 279-5516
fax (907) 272-5060
cell (907) 242-5715
-----Original Message-----
From: Bob Charles [mailto:bcharles@calistacorp.com]
Sent: Thursday, May 06, 2004 2:33 PM
To: fbettine@acsalaska.net
Cc: Jeff Foley; June McAtee
Subject: FW: Donlin Creek Study
Importance: High
FYI
-----Original Message-----
From: Donald Bonk [mailto:DONALD.BONK@NETL.DOE.GOV]
Sent: Thursday, May 06, 2004 12:48 PM
To: Bob Charles
Subject: Donlin Creek Study
Importance: High
** High Priority **
Dear Bob,
I have had a chance to review the Donlin Creek Power Study and it
appears to be an extremely well done comprehensive analysis of the
options for this power project. My comments are few.
The report states that PFBCs have never been built. That is totally
incorrect. Eight commercial size bubbling bed PFBCs have been built
around the world and 7 are still in operation. These units range in
size from 80 to 300 MWe. The single 79MWe unit built in the United
States is not in service. It was a demonstration unit only and not
intended to operate pass its demonstration period. At this time a
Pennsylvania firm is considering building the ninth PFBC type power
plant.
US DOE suggested the use of a circulating bed PFBC and only one of these
has been built and successfully operated at a 15 MWth size in
Germany. This unit demonstrated that operation and performance of the
pressurized circulating design with filters is superior to the bubbling
bed designs. This finding is consistent with the experience of the
power industry on the over 400 Atmospheric Fluidized Bed Combustor
(AFBC). The number of commercial circulating FBC outnumbers bubbling
FBC units by a factor approaching 12 to 1.
While the conclusion by Nuvista Light and Power Company to build 2-48
MWe Pulverized Coal (PC) power plants represent a very good choice, but
maybe not the best choice. I believe it is shortsighted. The proposed
PC units will provide excellent service when fired with the specified
British Columbian coal. PC units have some degree of fuel flexibility,
but a not as fuel flexible as the over 400 circulating atmospheric
fluidized bed (ACFB) unit now in operation. If price and/or other
factors hamper the use of the specified coal, switching to other coals
or solid fuel can be difficult with PC units.
It is my understanding that disposal of municipal waste and sewage
(sludge) are major issues for the city of Bethel, Alaska. ACFB units,
demonstrate superior fuel flexibility would allow the city to dispose of
these troublesome byproducts of modern life while producing power and
reducing the amount of coal imported. Grant use of these fuel sources
would slightly increase capital and operating costs but, the benefits to
the Bethel region and Kuskokwim river delta far outweigh these costs.
These additional costs can be displaced by tripping fees.
Thank You for the opportunity to comment on this excellent study that
demonstrates once again that coal is the most economical fuel and that
it can be used in an environmental acceptable manner.
Donald Bonk
Public Hearing –Bethel, Alaska
May 13, 2004
Audio tapes of the Bethel Public Hearing are on file at the Nuvista Light & Power,
Co./Calista Corporation Offices located at 301 Calista Court, Anchorage, AK.