HomeMy WebLinkAboutVolume I ReportDonlin Creek Mine Power
Supply Feasibility Study
Nuvista Light & Power, Co.
301 Calista Ct.
Anchorage, AK 99518-2038
Volume 1
Coal-Fired Power - The Preferred Alternative Final Report
June 11, 2004
Bettine, LLC 1120 E. Huffman Rd. Pmb 343
Anchorage, AK 99501
907-336-2335
DISCLAIMER
The information provided in this document is intended as a general reference for
Calista Corporation and Nuvista Light & Power Co. All parties that participated in
preparation of this document have made reasonable efforts to insure the
information and cost estimates contained herein are consistent with the level of
accuracy anticipated in a feasibility level study. No warranty or guarantee of any
kind is made that the power costs developed in this study will accurately reflect the
actual power costs that may be ultimately charged to wholesale customers.
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TABLE OF CONTENTS
VOLUME I
PAGE NO.
SECTION I - EXECUTIVE SUMMARY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.1
1. CONCLUSION & RECOMMENDATIONS. . . . . . . . . . . . . . . . . . . . . . . . . I-1.1
2. INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.3
A. BACKGROUND . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.3
B. PURPOSE OF STUDY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.5
C. STUDY METHODOLOGY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.5
3. DESCRIPTION OF POWER SUPPLY ALTERNATIVES . . . . . . . . . . . I-1.6
A. COAL-FIRED PLANT AT BETHEL. . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.7
1. Site Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.8
2. Coal Selection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.9
3. Coal Demand and Storage Requirement . . . . . . . . . . . . . . . . . . . . . . . I-1.10
4. Coal Transportation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.10
B. COMBINED-CYCLE COMBUSTION TURBINE PLANT . . . . . . . . . . I-1.11
1. Site Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.12
2. Fuel Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.12
C. OTHER POWER SUPPLY ALTERNATIVES. . . . . . . . . . . . . . . . . . . . . I-1.13
1. Importing Rail-belt Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.13
2. Holitna Basin or Cook Inlet Natural Gas I-1.13
D. BETHEL TO DONLIN CREEK 138-kV TRANSMISSION LINE. . . . . .I-1.14
E. PROJECT SCHEDULE. I-1.15
F. ECONOMIC ANALYSIS and COST ESTIMATES. . . . . . . . . . . . . . . . . I-1.15
1. Capital Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.15
2. Wholesale Power Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.16
3. 20 Year Accumulated Donlin Creek Mine Power Costs. . . . . . . . . . . I-1.18
4. Fuel Price Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.19
5. Mine Demand Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.20
6. Coal-fired Plant Generation Efficiency . . . . . . . . . . . . . . . . . . . . . . . . I-1.20
7. Waste Heat Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.21
8. 50-Year Regional Power Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.21
G. ENVIRONMENTAL ASSESSMENT REVIEW . . . . . . . . . . . . . . . . . . . I-1.23
1. NEPA Compliance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.23
2. Scope of NEPA Consistency Review . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.24
3. Land Ownership. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.25
4. Project Permits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.26
4. AGENCY AND PUBLIC COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . .I-1.29
Table I-1.1 Power Costs $ per KW-Selected coals . . . . . . . . . . . . . . I-1.9
Table I-1.2 Fuel Price Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.13
Table I-1.3 Capital Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.15
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Table I-1.4 Wholesale Costs Years 1-20 . . . . . . . . . . . . . . . . . . . . . I-1.16
Table I-1.5 Donlin Creek Mine Accumulated Power
Costs Years 1-20. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.18
Table I-1.6 60MW Average Mine Demand - $150 Million Grants. . I-1.19
Table I-1.7 Savings Associated With Coal Fired Generation. . . . . . I-1.20
Table I-1.8 Mine Demand Sensitivity . . . . . . . . . . . . . . . . . . . . . . . . I-1.20
Table I-1.9 Generation Efficiency. . . . . . . . . . . . . . . . . . . . . . . . . . . I-1.21
Table I-1.10 50 Year Regional Savings Associated With Coal
Fired Generation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1-23
Table I-1.11 Segments With Landownership . . . . . . . . . . . . . . . . . . . I-1.26
Table I-1.12 Transmission Line Permits. . . . . . . . . . . . . . . . . . . . . . . I-1.27
Table I-1.13 Bethel Power Plant Permits. . . . . . . . . . . . . . . . . . . . . . . I-1.28
Figure I-1.1 Calista Region/Location Map
Figure I-1.2 Route Overview Donlin Creek Transmission Line
Figure I-1.3 Proposed Bethel Power Plant Location
Figure I-1.4 Power Cost Comparison Years 1-20
Figure I-1.5 50 Year Regional Power Costs
SECTION II – INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1.1
1. BACKGROUND . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1.1
2. PURPOSE OF STUDY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1.3
3. STUDY METHODOLOGY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1.4
SECTION III - POWER SUPPLY ALTERNATIVES III-1.1
1. BETHEL COAL-FIRED POWER PLANT. . . . . . . . . . . . . . . . . . . . . . . . . III-1.1
A. BACKGROUND . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.1
1. General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.1
B. LAND-BASED COAL-FIRED PLANT . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.2
1. Design Philosophy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.3
2. Site Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.4
C. BARGE-MOUNTED POWER PLANT . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.4
1. Transporting Barges to Bethel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.5
2. Barge Mooring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.6
D. TECHNICAL DISCUSSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.7
1. Coal Selection, Procurement and Transportation. . . . . . . . . . . . . . . . . . III-1.7
a. Coal Selection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.7
b. Coal Demand and Storage Requirement . . . . . . . . . . . . . . . . . . . . . III-1.10
c. Shipping Coal to Bethel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.10
i. Ocean Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.10
ii. Lightering by Specialized Marine Contractors. . . . . . . . . . . . . . III-1.11
iii. Lightering by Nuvista Light & Power . . . . . . . . . . . . . . . . . . . . III-1.12
2. Coal Unloading Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.12
3. Coal Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.13
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4. Fire Prevention and Coal Dust Control. . . . . . . . . . . . . . . . . . . . . . . . . . III-1.13
5. Description of Power Plant Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.14
a. General Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.14
b. Generation Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.14
c. Make-up Water Source, Treatment, Filtering and
Blow-down Disposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.14
d. Steam Turbine and Generator System. . . . . . . . . . . . . . . . . . . . . . . . III-1.15
e. Environmental Control System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.16
1. Effluent Discharge. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.17
2. Solid Waste & Sewage Sludge Disposal . . . . . . . . . . . . . . . . . . III-1.17
3. Ash Handling and Utilization System. . . . . . . . . . . . . . . . . . . . . III-1.18
f. Standby Turbine System and Diesel Fired Boiler. . . . . . . . . . . . . . . III-1.18
g. Instrumentation and Controls, Central Control.
Room and Motor Control Center . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.19
h. Fire Protection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.19
i. Maintenance Shop . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.19
E. REDUCED GENERATION OPTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.20
F. RELIABILITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.20
Table III-1.1 Comparison of Selected Coal . . . . . . . . . . . . . . . . . . . . . III-1.8
Table III-1.2 ADEC Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-1.16
Table III-1.3 Loss of Load Expectations . . . . . . . . . . . . . . . . . . . . . . .III-1.21
Figure III-1.1 Gillette Twin 90 MW Coal Plant
Figure III-1.2 Proposed Bethel Power Plant Location
Figure III-1.3 Bethel Wind Rose
Figure III-1.4 Photo of Air-Supported Coal Storage Structure
Figure III-1.5 Location Map – Goodnews Bay and Security Cove
Figure III-1.6 Hely-Patterson Barge Unloader
Figure III-1.7 Dry Tow Vessel
Drawings: Overall Site General Arrangements
Coal Fired Plant General Arrangements
Barge Concept Site Plan
Barge Concept General Arrangement Plan
SECTION III-2.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .III-2.1
2. COMBINED-CYCLE COMBUSTION TURBINE PLANT. . . . . . . . . . . . . .III-2.1
A. LAND-BASED MODULAR PLANT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.1
1. Bethel Combined-Cycle Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.1
a. Design Philosophy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.2
b. Site Location. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.3
B. BARGE-MOUNTED POWER PLANT. . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.4
C. TECHNICAL DISCUSSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.5
1. Fuel Selection, Procurement and Transportation . . . . . . . . . . . . . . . . . . III-2.5
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a. Comparison of Various Fuels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.5
b. Fuel Shipping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.6
1. Fuel Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.6
2. Propane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.6
c. Fuel Receiving and Storage System Propane . . . . . . . . . . . . . . . . . III-2.7
1. Fuel Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.7
2. Propane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.7
2. Description of Power Plant Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.8
a. General Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.8
b. Prime Movers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.9
c. Comparison of Combustion Turbines with Diesel Engines . . . . . . . III- 2.10
1. Combustion Turbine Advantages . . . . . . . . . . . . . . . . . . . . . . . . III-2.11
a. High Efficiency When Applied in the Combined-Cycle. . . . III-2.11
b. High Reliability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.11
c. Multi-Fuel Capability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.11
d. Low Weight. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.11
2. Combustion Turbine Disadvantages . . . . . . . . . . . . . . . . . . . . . . III-2.11
a. Lower Efficiency. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.11
b. Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.12
3. Advantages of Slow Speed Diesel Engines. . . . . . . . . . . . . . . . . III-2.12
a. High Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.12
b. Multi Fuel Capability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.12
4. Drawbacks of Diesel Engines. . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.12
a. Weight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.12
b. Foundation Construction Cost III-2.12
c. Lower Combined-Cycle Efficiency . . . . . . . . . . . . . . . . . . . .III-2.13
d. Lubrication Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.13
e. Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.13
f. NOx. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .III-2.13
d. Comparison Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.13
e. Comparison of the Alstom GTX100 & GE LM 6000 Turbine. . . . . . III-2.14
f. Heat Recovery Steam Generator System . . . . . . . . . . . . . . . . . . . . . . III-2.15
g. Steam Turbine and Generator Module. . . . . . . . . . . . . . . . . . . . . . . . III-2.15
h. Steam Condensing (cooling) System. . . . . . . . . . . . . . . . . . . . . . . . . III-2.15
i. Demineralizing System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.15
j. Phosphate Feed System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .III-2.15
k. Instrumentation and Controls including the DCS System. . . . . . . . . III-2.16
l. Environment Protection System . . . . . . . . . . . . . . . . . . . . . . . . . . . .III-2.16
1. Emissions to the Ambient Air . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.16
2. Liquid and Solid Waste. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.17
m. Auxiliary Boiler. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.18
n. Fire Protection System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.18
o. Civil Works, Buildings and Other Enclosures. . . . . . . . . . . . . . . . . . III-2.18
p. Maintenance Shop. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.19
C. RELIABILITY ANALYSIS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.19
v
Table III-2.1 Fuel Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-2.5
Table III-2.2 Bethel Power Plant Alternatives. . . . . . . . . . . . . . . . . .III-2.10
Table III-2.3 Crooked Creek Power Plant Alternatives . . . . . . . . . . . III-2.10
Table III-2.4 Loss of Load Expectation. . . . . . . . . . . . . . . . . . . . . . . III-2.19
Figure III-2.1 Alstom Gas Turbine With Heat Recovery Steam Generator
Figure III-2.2 Proposed Location of Crooked Creek Power Plant
Figure III-2.3 Sound Pressure Levels
Drawings: District Heating/Trunk Lines
Bethel Modular Facility General Arrangement
Crooked Creek CT Modular Facility General Arrangement
SECTION III-3.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-3.1
3. DISTRICT HEATING SYSTEM. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-3.1
A. INTRODUCTION.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-3.1
B. System Specifics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-3.3
1. Pipes & Pumps. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-3.3
2. Heat Exchangers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-3.3
3. Backup System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-3.4
C. SYSTEM INSTALLATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-3.4
D. WASTE HEAT SALES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-3.4
SECTION III-4.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .III-4.1
4. OTHER POWER SUPPLY ALTERNATIVES. . . . . . . . . . . . . . . . . . . . . . . III-4.1
A. INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-4.1
B. TRANSMISSION LINES BUILT FROM NENANA. . . . . . . . . . . . . . . . . . III-4.1
1. + 100-kV, DC Transmission Line. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-4.1
a. Option 1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-4.1
b. Option 2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-4.2
2. 230-kV, AC Line Built from Nenana . . . . . . . . . . . . . . . . . . . . . . . . . . . III-4.2
a. Option 1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-4.2
b. Option 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-4.2
C. NATURAL GAS SUPPLY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .III-4.3
1. Cook Inlet Pipeline. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .III-4.3
2. Holitna Basin Natural Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III-4.3
Figure III-4.1 Cook Inlet Historic & Forecast Gas Production 1958-2022
Figure III-4.2 Cook Inlet Gas Production Forecast
vi
SECTION IV - 138-kV TRANSMISSION LINE & SUBSTATIONS . . . . . . IV-1.1
SECTION IV-1 - ROUTE SELECTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.1
A. INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.1
B. METHODOLOGY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.1
1. General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.1
C. TRANSMISSION LINE CHARACTERISTICS. . . . . . . . . . . . . . . . . . . . . . IV-1.2
1. General Characteristics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.2
2. R.O.W. Requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.3
3. Visual Impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.3
4. EMF Affects. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IV-1.4
D. CORRIDOR CHARACTERISTICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IV-1.8
1. Soil Conditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IV-1.8
2. Wetlands. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IV-1.9
3. Forest Cover. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.10
4. Fish and Wildlife Habitat. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.11
5. Navigable Rivers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.11
6. Floodplain. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.12
7. Threatened and Endangered Species . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.12
8. Essential Fish Habitat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.12
9. Anadromous Fish Streams. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.12
E. TRANSMISSION LINE CONSTRUCTION IMPACTS . . . . . . . . . . . . . . . IV-1.13
F. ROUTE SELECTION CRITERIA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.14
G. DESCRIPTION OF ROUTE SEGMENTS . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.14
1. Segment A-B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.15
2. Segment B-C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.15
3. Segment C-D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.16
4. Segment D-E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.17
5. Segment E-F . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.17
6. Segment F-G. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.17
7. Segment G-H. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.17
8. Segment H-I. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.18
9. Segment I-J. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.18
10. Segment J-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.18
11. Segment K-L. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.18
12. Segment L-M. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.19
13. Segment M-N. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.19
Table IV-1.1 Magnetic Field Levels Common Appliances. . . . . . . . . . IV-1.6
Table IV-1.2 Magnetic Field Levels Near Transmission
and Distribution Lines. . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.7
Table IV-1.3 Magnetic Field Strength at Ground Level. . . . . . . . . . . . IV-1.8
Table IV-1.4 Summary of Selected Information for Each
Route Segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-1.16
vii
Map Donlin Creek Route Overview
Map 1 Map1 of 13
Map 1A
Map 1B
Map 1C
Maps 2 through 13
SECTION IV-2 - TRANSMISSION LINE FEASIBILITY DESIGN . . . . . . IV-2.1
A. INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.1
B. VOLTAGE SELECTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.1
1. Donlin Creek Mine Transmission Line. . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.1
C. SUMMARY OF ELECTRIC POWER SYSTEMS, INC. (EPS) STUDY . . IV-2.1
1. Power Flow Simulations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.2
2. Transient Stability Simulations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.3
a. Loss of Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.3
b. Loss of Mine Load. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.3
c. Motor Starting. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.4
d. 138-kV Line Energization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.4
3. Short Circuit Simulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.5
D. DESIGN CRITERIA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.5
1. Electric Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.5
2. Ampacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.5
E. WEATHER DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IV-2.6
1. General. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.6
2. Ambient Temperature. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.7
3. Snow Ground Cover. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.8
4. Conductor Ice and Snow Accumulation. . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.8
5. Extreme Wind . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.9
F. DESIGN LOADING AND LOADING ZONES . . . . . . . . . . . . . . . . . . . . . . IV-2.10
1. Overload Capacity Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.11
2. Conductor Sag and Tension Limits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.11
G. ELECTRICAL CLEARANCES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.13
1. Foundations, Guys and Anchors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.13
2. Insulator Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.14
3. R.O.W. Width. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.14
H. CONDUCTOR SELECTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.16
1. Voltage Drop and Power Loss Comparison . . . . . . . . . . . . . . . . . . . . . IV-2.16
2. Conductor Sag & Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.16
3. Phase Spacing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.17
4. Optical Ground Wire (OPGW) Selection . . . . . . . . . . . . . . . . . . . . . . . IV-2.17
5. Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.18
I. STRUCTURE SELECTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.18
1. Single Wood and Steel Pole Structures. . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.18
2. H-frame Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.20
3. Steel X-frame Towers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.22
viii
J. DONLIN CREEK TRANSMISSION LINE DESIGN ALTERNATIVES. . IV-2.23
1. Single Pole + H-frame Structures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.23
2. Single Pole + Combination of X-towers and H-frame Structures . . . . . IV-2.23
3. Life-Cycle Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.24
4. Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.24
K. STRUCTURE FOUNDATIONS AND ANCHOR SELECTION. . . . . . . . IV-2.24
1. Structure Foundations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.24
2. Anchors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.25
L. FEASIBILITY STUDY CONSTRUCTION PLAN . . . . . . . . . . . . . . . . . . IV-2.26
1. Construction Zones. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.26
2. River Access. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.27
3. Road and Trail Access. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.27
4. Foundations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.28
5. Structure Erection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.29
6. Conductor and OPGW Stringing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.30
Table IV-2.1 Temperature and Snow Depths. . . . . . . . . . . . . . . . . . . . . IV-2.7
Table IV-2.2 Wind Speeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.9
Table IV-2.3 Assumed Study Design Criteria . . . . . . . . . . . . . . . . . . . IV-2.10
Table IV-2.4 Overload Capacity Factors . . . . . . . . . . . . . . . . . . . . . . . IV-2.11
Table IV-2.5 Conductor Tension Limits. . . . . . . . . . . . . . . . . . . . . . . . IV-2.12
Table IV-2.6 OHGW Tension Limits. . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.12
Table IV-2.7 Electrical Clearances. . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-2.13
Table IV-2.8 ROW Width Requirement for Given Span . . . . . . . . . . . IV-2.15
Table IV-2.9 Maximum Sag Comparison . . . . . . . . . . . . . . . . . . . . . . .IV-2.16
Table IV-2.10 Pole Length With and Without Dampening . IV-2.17
Table IV-2.11 Single Wood & Steel Pole Structures Comparison. . . IV-2.19
Table IV-2.12 H-Frame Wood & Steel Structure Comparison. . . . IV-2.21
Table IV-2.13 Number of Structures/Pile Foundations. . . . . . . . . . . . . . IV-2.24
Sketches: Typical Single Pole Structure Type A
Typical Single Pole Structure Type B
Typical H-Frame Tangent Structure
Typical X-Frame Tangent Structure
Right-of-Way Cross-Section
SECTION IV-3 - SUBSTATION FEASIBILITY DESIGN.. . . . . . . . . . . . . . .IV-3.1
A. BACKGROUND. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-3.1
B. BETHEL POWER PLANT SUBSTATION. . . . . . . . . . . . . . . . . . . . . . . . . IV-3.2
1. Land-Based Power Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-3.2
2. Barge-Mounted Power Plan. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IV-3.2
C. DONLIN CREEK MINE SUBSTATION . . . . . . . . . . . . . . . . . . . . . . . . . .IV-3.3
D. VILLAGE SUBSTATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IV-3.3
E. INTERFACE WITH EXISTING VILLAGES
ix
DISTRIBUTION SYSTEMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IV-3.4
F. BETHEL UTILITIES EXISTING DIESEL PLANT SUBSTATION . . . . .IV-3.5
Figure IV-3.1 System Oneline Diagram Coal-Fired Generation Alternative
Figure IV-3.2 System Oneline Diagram Combined-Cycle Generation Alternative
Figure IV-3.3 Substation Conceptual Layout Land-Based Generation Plant
Alternative
Figure IV-3.4 Substation Conceptual Layout Barge-Mounted
Generation Plant Alternative
Figure IV-3.5 Substation Conceptual Layout Donlin Creek Mine
Figure IV-3.6 Village Stepdown Substation Conceptual Layout
Figure IV-3.7 Aniak Stepdown Substation Conceptual Layout
SECTION V - PRELIMINARY ENVIRONMENTAL PLANNING. . . . . . V-1.1
SECTION V-1 – TRANSMISSION LINE ENVIRONMENTAL
PLANNING. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.1
A. INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.1
B. TRANSMISSION LINE ENVIRONMENTAL REQUIREMENTS
ASSESSMENT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .V-1.1
1. Land Use Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .V-1.2
2. Wetlands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .V-1.4
3. Navigable Rivers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.4
4. Floodplain Management. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.4
5. Threatened and Endangered Species . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.5
6. Essential Fish Habitat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.5
7. Anadromous Fish Streams. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.5
8. State Lands/State Parks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.6
9. Coastal Zone Management. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.6
10. Historic, Architectural, Archaeological, and Cultural Resources . . . . . . V-1.6
11. Construction Impacts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.6
12. Cumulative and Secondary Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.7
13. Federal Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.8
14. Anticipated Permits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.9
Table V-1.1 Landownership Rights. . . . . . . . . . . . . . . . . . . . . . . . . . . . V-1.4
Table V-1.2 Potential Permits and Approvals . . . . . . . . . . . . . . . . . . . . V-1.9
SECTION V-2 – POWER PLANT ENVIRONMENTAL PLANNING. . . . V-2.1
A. BETHEL POWER PLANT ENVIRONMENTAL REQUIREMENTS
ASSESSMENT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.1
1. NEPA Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.1
2. Scope of NEPA Compliance Review . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.2
3. Agency Comments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .V-2.3
a. State of Alaska. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.3
x
b. federal Agencies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.4
c. Others. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.6
B. ENVIRONMENTAL ISSUES & MAJOR PERMITTING
REQUIREMENTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .V-2.6
1. Alaska Coastal Zone Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.6
2. Air Quality. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.7
3. Water Quality. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.8
4. Wetlands and Navigable Waters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.9
5. Fish Habitat. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.10
6. Floodplain Development. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.10
7. FAA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.11
8. Permits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . V-2.11
Table V-2.1 Potential Permits and Approvals for Bethel Power Plant. . . V-2.11
SECTION VI- PROJECT COST ESTIMATES. . . . . . . . . . . . . . . . . . . . . . . . VI-1.1
1. INTRODUCTION & BACKGROUND. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.1
A. INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.1
B. COAL-FIRED GENERATION PLANT LOCATED AT BETHEL . . . . . . VI-1.1
1. Land-Based Power Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.2
2. Barge-Mounted Power Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.2
3. Capital Cost Implications of the Application of Usibelli Coal . . . . . . . VI-1.3
4. Possible Savings from Utilization of Healy Clean Coal Power Plant
Equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.4
5. Coal-Fired Plant O&M Estimates, Less Fuel Costs . . . . . . . . . . . . . . . . VI-1.5
C. COMBINED-CYCLE COMBUSTION TURBINE PLANT . . . . . . . . . . . . VI-1.7
1. Bethel Power Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.7
2. Bethel Land-Based Power Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.8
3. Bethel Barge-Mounted Power Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.10
4. Crooked Creek Power Plant -Land-Based Option Only. . . . . . . . . . . . . VI-1.9
5. Combustion Turbine Plant O&M Estimates, Less Fuel Costs . . . . . . . . VI-1.9
D. DISTRICT HEATING SYSTEM. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.11
E. FOUNDATION AND FUEL STORAGE COSTS . . . . . . . . . . . . . . . . . . . VI-1.11
1. Coal-Fired Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.11
2. Combustion Turbine Plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VI-1.12
F. TRANSMISSION LINE COSTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.13
1. Construction Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VI-1.13
2. Transmission Line O&M Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . VI-1.15
3. Transmission Line Costs for Other Alaska Projects . . . . . . . . . . . . . . . . VI-1.16
G. SUBSTATION COSTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.17
1. 138 kV Bethel to Donlin Creek Mine Transmission
Line Substation Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI-1.17
2. Nenana to Donlin Creek Mine Transmission Line Substation Costs . . . VI-1.18
xi
Table VI-1.1 Bethel-Donlin Creek 138 KV Transmission Line
Alternatives Pre-Design Construction Cost Estimate . . . VI-1.14
Table VI-1.2 Nenana-Donlin Creek Transmission Line Alternatives
Pre-Design Construction Cost Estimate . . . . . . . . . . . . .VI-1.15
Table VI-1.3 Cost Comparison of Tranmission Lines in Central
Alaska. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VI-1.17
Table VI-1.4 Bethel-Donlin Creek Mine Substation Costs. . . . . . . . . VI-1.18
Table VI-1.5 Nenana-Donlin Creek Mine Substation Costs. . . . . . . . VI-1.18
SECTION VII - PROJECT MANAGMENT & SCHEDULING VII-1.1
1. PROJECT OPTIONS AND ASSUMPTIONS. . . . . . . . . . . . . . . . . . . . . . . . . VII-1.1
A. INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VII-1.1
B. PROJECT MANAGEMENT OPTIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . VII-1.1
1. Nuvista Acts as Project Manager. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VII-1.1
2. Nuvista Contracts with Project Management Firm. . . . . . . . . . . . . . . . . VII-1.2
3. Nuvista acts as Project Manager + Turnkey (Design/Build). . . . . . . . . . VII-1.2
C. SCHEDULE ASSUMPTIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VII-1.2
1. Project Financing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VII-1.2
2. Environmental Impact Statement/Permitting. . . . . . . . . . . . . . . . . . . . . VII-1.2
3. Right-of-way Easement and Power Plant Site Acquisition . . . . . . . . . . VII-1.3
4. Preliminary Design. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VII-1.3
5. Final Design. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VII-1.3
6. Major Equipment Lead Times. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VII-1.4
D. PROJECT SCHEDULE SUMMARY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VII-1.4
Figure VII-1.1 Donlin Creek Abbreviated Project Schedule
Figure VII-1.2 Donlin Creek Transmission Line Project Schedule
Figure VII-1.3 Bethel Barge Based Coal Plant Schedule
Figure VII-1.4 Bethel Land Based Schedule
Figure VII-1.5 Bethel CT Modular Power Plant Schedule
SECTION VIII - PROJECT FINANCING. . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.1
1. FINANCING ALTERNATIVES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.1
A. INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.1
B. CONGRESSIONAL APPROPRIATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.1
C. RURAL UTILITY SERVICE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.1
1. Rural Electrification Loans. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.2
a. Hardship Loans. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.2
b. Municipal Rate Loans. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.2
c. Treasury Rate Loans. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VIII-1.3
d. Guaranteed Loans. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.3
2. Direct Learning and Telemedicine Program . . . . . . . . . . . . . . . . . . . . . VIII-1.3
D. AIDEA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.5
E. ALASKA RAILROAD BONDS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.6
xii
F. STATE OF ALASKA GENERAL OBLIGATION BONDS . . . . . . . . . . . . VIII-1.6
G. LEGISLATIVE APPROPRIATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VIII-1.7
H. PCE FUNDING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .VIII-1.7
SECTION IX - ECONOMIC ANALYSIS OF POWER
SUPPLY ALTERNATIVES. . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.1
1. ECONOMIC ANALYSIS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.1
A. OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.1
B. POWER REQUIREMENTS OF DONLIN MINE, BETHEL
& 8 VILLAGES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . IX-1.1
C. PRINCIPAL ASSUMPTIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.2
1. General Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.2
2. Capital Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.4
3. Annual O&M Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.5
D. COMPARISON OF ECONOMIC RESULTS . . . . . . . . . . . . . . . . . . . . . . . IX-1.6
1. Capital Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.7
2. Coal Supply Sensitivity Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.7
3. Wholesale Power Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.8
4. 20-Year Accumulated Donlin Creek Mine Power Costs. . . . . . . . . . IX-1.10
5. 50-Year Accumulated Regional Power Costs. . . . . . . . . . . . . . . . . . . . . IX-1.12
6. Fuel Price Sensitivity Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.14
7. Mine Demand Sensitivity Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.15
8. Coal-fired Plant Generation Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . .IX-1.15
9. Waste Heat Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.16
10. Transmission Line Routing Bethel Direct Point K . . . . . . . . . . . . . . . . IX-1.16
E. CONCLUSION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.16
Table IX-1.1 Projected kWh Requirements. . . . . . . . . . . . . . . . . . . . . .IX-1.2
Table IX-1.2 Projected KW Demand. . . . . . . . . . . . . . . . . . . . . . . . . . .IX-1.2
Table IX-1.3 Capital Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IX-1.7
Table IX-1.4 $/kWh Selected Coals . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.8
Table IX-1.5 Wholesale Power Costs Years 1-20 . . . . . . . . . . . . . . . . IX-1.9
Table IX-1.6 Donlin Creek Mine Accumulated Power Costs 1-20 . . . IX-1.11
Table IX-1.7 Savings Associated with Coal-Fired Generation 1-20 . . IX-1.10
Table IX-1.8 Accumulated Regional Power Costs Years 1-50. . . . . . . IX-1.13
Table IX -1.9 50 Year Regional Savings Associated with Coal Fired
Generation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.14
Table IX-1.10 Fuel Costs Sensitivity Analysis. . . . . . . . . . . . . . . . . . . . IX-1.14
Table IX-1.11 Mine Demand Sensitivity . . . . . . . . . . . . . . . . . . . . . . . . IX-1.15
Table IX-1.12 Generation Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . IX-1.16
Figure IX -1.1 Power Cost Comparison - Years 1-20
Figure IX -1.2 50 Year Regional Power Costs
Figure IX -1.3 Power Cost Breakdown
xiii
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 - Public Comments
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.1
SECTION I EXECUTIVE SUMMARY
1. CONCLUSION & RECOMMENDATIONS
One of the largest undeveloped gold deposits in the world is located near Donlin
Creek in the Calista region of southwestern Alaska. A Calista Region/location map is
attached at the end of this section as Figure I-1.1. Of the numerous power supply
alternatives investigated to provide power to the proposed Donlin Creek mine and the
Calista region, the power supply alternative that produces the lowest wholesale power
cost is the construction of coal-fired generation plant at Bethel plus construction of a 191
mile long, 138-kV transmission line between Bethel and the Donlin Creek mine. This
power supply alternative would provide power to the Donlin Creek mine, Bethel and 8
villages located between Bethel and the mine as shown in Figure I-1.2.1 It is, therefore,
recommended that Nuvista proceed with the initial environmental studies, data
acquisition, permitting and design processes for this power supply alternative.
Importing power from the rail-belt via a transmission line built between Nenana
and Crooked Creek results in the highest wholesale power cost. The combined-cycle
combustion turbine plant alternatives, whether constructed at Crooked Creek or Bethel,
provide power at essentially the same cost. Wholesale power costs for the combined-
cycle alternatives average ten percent higher than the coal-fired plant alternative.
Assuming the coal-plant and the transmission line are financed using $150 million
in grant funds with the balance of the $370 million project financed at an interest rate of
five percent, wholesale power cost would be in the range of 8.1 cents per kWh using
Luscar Coal Valley coal from British Columbia. It may be possible to decrease the
wholesale power cost by as much as one cent per kWh by slightly reducing generation
capacity, improving plant efficiency, selling waste heat from the plant and lowering
design loadings on the transmission line. The decisions concerning these factors and their
effect on power costs and reliability are, however, best reserved for the final design phase
and it would be premature to assume power could be produced for less than 8.1 cent per
kWh at this stage of study.
Eight coals, including Usibelli coal from Alaska, were evaluated as part of this
study. Canadian coals from either the Fording Black Bear mine or the Luscar Coal Valley
mine produce the lowest cost power. Because of the high moisture content and the
relatively low Btu value of Usibelli coal, a power plant requiring approximately 300,000
tons of Canadian coal per year will require approximately 500,000 tons of Usibelli coal to
produce the same amount of power. The larger volume of coal would require physically
larger and more costly coal storage facilities, boilers, ducts, emission control equipment
and higher expenses for moving coal, air and combustion gases, all of which increase
1 The village of Napaimute is being reestablished and may also be served from the transmission line.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.2
capital costs by approximately $35,000,000. In addition, the increased volume of Usibelli
coal that must be handled will increase O&M by approximately $500,000 per year and
lightering cost between Security Cove or Goodnews Bay and Bethel by approximately
$1,100,000 per year. These additional costs combine to increase power costs when using
Usibelli coal.
Coal is by far the cheapest source of fuel per million BTU. Delivered to Bethel,
coal averages less that 1/3 the cost of petroleum based products. Today 23 of the 25
lowest operating cost electric generation plants America are fueled by coal. Coal
generates more than 50 percent of America’s electricity and 40% worldwide.
The transmission line between Bethel and the proposed Donlin Creek mine would
be built using an overhead ground wire that contains a fiber optic cable. This would
allow the mine and the villages located along the route of the transmission line to be
interconnected with each other and Bethel by a high speed and highly reliable fiber optic
communication systems.
The alternative of routing the transmission line from Bethel directly to point K, as
that point is defined on the proposed transmission line route, was also examined. Point K
is located east of Chauthbaluk where the river turns north. From Point K, the transmission
line would follow the proposed route to the mine. See Figure I-1.2. This route is
approximately 25 miles shorter than the proposed route. This alternative assumes only
Bethel and the Donlin Creek mine are served from the generation/transmission facilities.
Routing the transmission line in this manner reduces power cost by only two tenth of one
cent per kWh for all financing alternatives. Given this small reduction in power cost it
would not seem prudent to route the power line in a manner that bypasses the villages.
There are numerous reasons why Bethel is the location of choice for constructing
a coal-fired power plant to supply the energy needs of the mine and the Calista region.
Bethel is a thriving community with a population of approximately 5,900 people. It is the
ninth largest community in Alaska and the largest community in western Alaska.2 It has
a substantial infrastructure including an all-weather airport and port facilities. Bethel has
all the amenities of a large community, but on a smaller scale. Bethel is the transshipment
point for all cargo and fuel moving up the Kuskokwim River. Ten thousand ton ocean
going barges can readily be towed up the Kuskokwim to Bethel, where the cargo is off-
loaded on to smaller river barges for transportation further up-river.
The waste heat captured from a power plant located at Bethel could be distributed
throughout the community via a district heating system to lower the cost of space heating
in the community. The waste heat would displace fuel oil presently used for space
heating. Utilization of waste heat for space heating has the potential to lower the total
costs paid by consumers for heating their homes and business in excess of one-million
dollars annually. The revenues generated by the sales of waste heat would be used to
offset power costs which, in turn, would lower the cost of power to all consumers.
2 http://eire.census.gov/popest/data/cities/tables/SUB-EST2002-10-02.pdf
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.3
Some of the benefits and business opportunities associated with the construction
of a coal-fired generation plant at Bethel can be summarized as follows:
Benefits of Coal-Fired Generation
• Reduced Regional Power Costs
• 50+ year power infrastructure
• Reduced Dependence on Fuel Oil
• Lower Space Heating Costs
• Construction Jobs
• Donlin Creek Mine
• Power Plant
• Transmission Line
• Long term highly skilled jobs
• Donlin Creek Mine
• Power Plant
• Improved Communications
• Improved Quality of Life
• Disposal of Regional Burnable Landfill Waste and Sewage Sludge
Business Opportunities
• District Heating Utility
• Concrete/Ash-Aggregate Sales
• Lightering Coal from freighters into Bethel
• Machine Shop Support of Power Plant & Mine
• Janitorial Services for the Power Plant
• New Housing Construction for plant personnel
2. INTRODUCTION
A. BACKGROUND
One of the largest undeveloped gold deposits in the world is located in the Calista
region of southwestern Alaska. The proposed Donlin Creek mine project is located
approximately 280 miles west of Anchorage and 14 miles north of Crooked Creek on
Calista Corporation lands. The village of Crooked Creek is located on the Kuskokwim
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.4
River, approximately 180 river miles upstream of Bethel. A Calista Region/location map
is attached at the end of this section as Figure I-1.1.
The Placer Dome, Inc and Nova Gold, Inc. joint venture is presently evaluating
the feasibility of developing a mine to extract the gold resources. Resource estimates
include, Measured and Indicated Resources of 11.1 million ounces of gold grading an
average of 3.0 g/t (grams/tonne) gold. The Inferred Resource is estimated at 14.3 million
ounces of gold grading 3.1 g/t.
To date, the joint venture has spent in excess of US$50 million on the project and
Placer Dome will be spending an additional US$30+ million to complete a Feasibility
Study and make a decision, prior to November 2007, whether to construct a mine.
It is anticipated that the Donlin Creek mine project will have a maximum load
demand of approximately 70+ megawatts with an average load demand in the range of 60
megawatts. There are no existing power supply facilities in the region that can provide
this power demand and new power supply facilities must be constructed. These new
facilities must provide the mine with low cost power for the Donlin Creek mine project to
be economically feasible to develop.
Nuvista Light & Power, Inc. (Nuvista), using grant funds provided by the Alaska
Legislature, commissioned an energy-needs study, which was completed in July 2002.
The study identifies a comprehensive energy strategy that will provide low cost power to
the Donlin Creek mine project and to the 40+ villages in the Calista region.3 Nuvista is a
non-profit organization formed by Calista Corporation to function as a regional
Generation and Transmission Utility. Nuvista would wholesale power directly to the
Donlin Creek mine, and to existing utilities for resale to their customers.
The Energy-Needs Study forecasted the power and energy requirements of the
Calista region both with and without the development of the Donlin Creek mine project.
The forecasted power demand with development of the Donlin Creek mine project, in the
year 2020, is 96 MW as compared to 30 MW projected load without the mine
development. Energy requirements are forecast at approximately 700,000 MWHs with
the mine as compared to 150,000 MWHs without the Donlin Creek mine development.
Development of the Donlin Creek mine project will triple the power demand in the region
and energy requirements will increase by almost five fold when compared with power
and energy requirements without the mine development.
Two general categories of alternatives were investigated to satisfy the electric
power and energy requirements of the proposed Donlin Creek Mine project and the
Calista region. These categories include:
• Constructing a Power Supply in the Calista Region
• Importing Power from the Rail-belt Region
3 Calista Region Energy Needs Study, Part I and II, July 1, 2002.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.5
Of the numerous power supply alternatives evaluated in the Energy Needs Study,
the identified preferred alternative for supplying the power needs of the Donlin Creek
mine project and the Calista region was: Construction of a Coal-Fired Plant at Bethel
+191 mile long 138-kV transmission line to the mine site. The study recommended that
Nuvista proceed immediately with the planning, development and implementation of the
preferred alternative, commencing with the commissioning of a feasibility study. Based
on this recommendation Nuvista obtained additional grant funding, from the Alaska
legislature, to proceed with this Feasibility Study.
B. PURPOSE OF STUDY
A primary goal of this Feasibility Study is to explore the feasibility of
constructing a power plant in Bethel, Alaska and a 138-kV transmission line from Bethel
to the proposed Donlin Creek gold mine project site. The proposed transmission line
would be located along the northern bank of the Kuskokwim River. The proposed
transmission line routing is shown in Figure I-1.2, located at the end of this section.
Power will be supplied from a power plant at Bethel, to serve Bethel, Akiachak, Akiak,
Tuluksak, Lower/Upper Kalskag, Aniak, Chuathbaluk, Crooked Creek and the proposed
Donlin Creek gold mine.
This study defines the basic design criteria and estimated costs associated with the
construction of the preferred power supply alternative, which has been identified as the
construction of 100+ MW coal-fired plant at Bethel and a 191 mile long, 138-kV
transmission line (the Donlin Creek Transmission Line) from Bethel to the Donlin Creek
mine. As an alternative to the coal-fired plant at Bethel the study will also identify the
basic design and cost associated with the construction of a combined-cycle combustion
turbine plant at Bethel or Crooked Creek. The study will compare and assess the capital
costs and power costs associated with these three alternatives with each other and with
other selected power supply alternatives.
C. STUDY METHODOLOGY
The feasibility study involved the efforts of several engineering firms and
environmental specialists. Bettine, LLC served as project manager and developed the
Donlin Creek transmission line route alignment, preliminary transmission line and
substation designs, evaluated power supply alternatives, conducted the economic
analysis, and prepared the draft and final report. Precision Energy Systems, Inc. (PES)
developed the designs, construction and operational cost estimates and construction
schedules for the Bethel coal-fired plant and combined-cycle combustion turbine power
supply alternatives. Dryden and LaRue, Inc. (D&L) prepared cost estimates for the 138-
kV Donlin Creek transmission line and substations. In addition D&L prepared cost
estimates for a + 100-kV DC and a 230-kV AC transmission line built from Nenana to
the Donlin Creek mine. The engineering firm of LCMF prepared preliminary designs and
costs estimates for power plant foundations and fuel storage facilities. Electric Power
Systems, Inc. (EPS) conducted electrical systems studies. Travis/Peterson, Inc. and
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.6
Steigers Corporation provided separate environmental reports addressing basic
environmental factors and permitting requirements for the transmission line and power
plant, respectively.
This study assumes the Donlin Creek gold mine will begin full scale mining
operations in mid-year 2010, with a peak demand of 70+ MWs and an average demand of
60 MWs. Placer Dome, Inc. has, however, indicated that it may want power at the mine
prior to 2010. Realistically it will be difficult to construct a coal-fired power plant at
Bethel and a 191 mile transmission line to provide 70+ MWs of power to the mine site
prior to 2010.
Several practical criteria were established to provide a guide for selecting a
transmission line route between Bethel and the Donlin Creek mine site. However, the
overriding directive followed for locating the transmission line was to avoid crossing
lands administered by the U.S. Fish and Wildlife Service, (i.e. lands within the Yukon-
Delta Wildlife Refuge) by placing the power line within the corridor of private lands
owned by the various native corporations.
This study did not prepare an independent power requirements forecast but will
instead rely on the forecast prepared in the Calista Region Energy Needs Study, Part I,
dated July 1, 2002.
3. DESCRIPTION OF POWER SUPPLY ALTERNATIVES
The primary purpose of this study is to examine the technical and economic
feasibility of constructing either a coal-fired power plant or a combined-cycle combustion
turbine plant at Bethel along with a 138-kV transmission line from Bethel to the Donlin
Creek mine. The generation/transmission system would provide power to the Donlin
Creek mine, Bethel, and eight villages located along the transmission line route.
The report also briefly discusses several other power supply alternatives that have
been previously evaluated and determined to produce more expensive power than the
Bethel coal-fired generation alternative. These alternatives include:
• Combined-Cycle Power Plant at Crooked Creek
• Oil Fired
• Natural gas-fired from a pipeline built from Cook Inlet to
Crooked Creek or using gas produced in the Holitna Basin
• + 100-kV, DC transmission line built between mine site and Nenana
• 230-kV, AC transmission line built between mine site and Nenana
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.7
A. COAL-FIRED PLANT AT BETHEL
The proposed coal-fired power plant would utilize Pulverized Coal (PC)
combustion technology. PC is a proven technology that has been used in the USA for the
last 40 years and is characterized by high combustion efficiency and low-cost emission
controls. Coal pulverized in specially designed crusher/grinders is blown into the boilers
combustion chamber and the coal behaves like a gaseous fuel.4
Both land-based and barge-mounted power plant alternatives were investigated.
The coal-fired power plant would consist of two atmospheric pulverized coal-fired
boilers each powering a 48.5 MW steam turbine, plus one 46 MW diesel-fired simple-
cycle combustion turbine, for a total installed capacity of 143 MW. To improve
reliability, the coal-fired portion of the plant will consist of two separate process lines,
each including one boiler and steam turbine-generator set and ancillary equipment. Each
process line and steam turbine-generator set can, however, be operated at a maximum
output of 55 MW for moderate periods. Under normal operating conditions the steam
turbines will provide the required output. If one steam turbine is off-line, the remaining
steam turbine will be operated at its maximum output of 55 MW and the simple-cycle
turbine will be placed on-line to supply the additional output. The power plant would
initially generate approximately 700,000 MWh annually. The two coal-fired steam
turbines would provide primary power, with the combustion turbine providing
standby/backup and peaking generation. It is estimated that the combustion turbine will
generate approximately 3 percent of the annual generation.
The barge-mounted power plant alternative would occupy two barges. The
dimensions of each barge would be approximately 110 feet wide by 440 feet long, with a
draft of about eight feet. The barges would be equipped with the intended systems, at a
shipyard on the West Coast USA or Canada and shipped on dry dock vessels to the
vicinity of Security Cove or Goodnews Bay, Alaska, from where the barges will be
offloaded and towed to Bethel.
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
towed and pushed into place, an armored berm would be built between the barge channel
and the river to protect the barges from ice flow during spring breakup and to provide an
earthen platform for unloading supplies. The barges would be located in the river
floodplain at a location where there is little elevation difference between the bank and the
river.
Currently, barge mounted power plants include combustion turbines or diesel
engines as motive power, working in simple or combined cycle. They are predominant in
4 Others have suggested that the coal-plant should be constructed using fluidized bed technology rather than
pulverized coal technology, as recommended in this report, because fluidized bed boilers can burn a wider
range of fuels. There are advantages and disadvantages to both technologies. Combustion technologies will
be reevaluated during the EIS and design phase and the most appropriate technology will be selected.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.8
areas with developing power grids and areas without access to sources of low-cost and
clean fuels such as natural gas and coal. Barge-mounting of a coal-fired power plant has
not yet been done, however, there are many possible examples including steam ships and
barge-mounted Kraft pulp plants with recovery boilers.
The U.S. Department of Energy, National Energy Technology Laboratory
(NETL) has proposed a similar barge mounted coal-fired power plant concept using a
circulating bed Pressurized Fluidized Bed Combustor (PFBC) Design. The circulating
bed PFBC design was investigated by the feasibility team and it was determined the
design represents new and relatively unproven technology. Due to the substantial
unknowns and uncertainties associated with the technical performance of such a plant and
the cost of constructing, operating and maintaining a circulating bed PFBC power plant,
it is recommended that circulating bed PFBC plant design not be used in this project.
In the event Placer Dome reduces mine power demand, a reduced generation
alternative was investigated. Under this alternative, a plant with only 80 + MW of coal-
fired capacity would be built. The plant would consist of two atmospheric pulverized
coal-fired boilers each powering a 40 MW steam turbine, a 25 MW diesel-fired simple-
cycle combustion turbine, plus this option would rely on the existing Bethel diesel plant
for 10 MW of diesel generation, for a total installed capacity of 115 MW. In all other
respects it would be identical to the coal-fired plant described above. The capital cost of
this reduced capacity plant would be approximately $18 million dollars less than the 100
+ MW land-based plant and $13 million less than a 100 + MW barge mounted plant.
1. Site Location
The preferred location for the Bethel Power Plant is a site approximately one mile
south of Bethel in Section 20 of Township 8 North, Range 71 West of the Seward
Meridian. See Figure I-1.3 at the end of this section. The proposed site, of the plant and
dock facilities, is located on private lands. Elevation of the site varies between 50 and
100 feet mean sea level. The proposed land-based power plant site will be located
approximately 500-1000 feet west of the Kuskokwim River. The dock will be used to
offload equipment and materials during and after plant construction and to offload annual
coal shipments. The dock will be connected with the site by a road and with the coal
storage building by a covered conveyor system. A road will also be constructed from the
site to the existing fuel dock area where it will interconnect with Bethel’s road system.
The coal plant facilities will require an area of approximately 80 acres. The barge
mounted alternative would be located slightly further south. The two barges would be
located in the floodplain, while coal storage and other facilities would be located on
higher ground.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.9
2. Coal Selection
Eight coals from various mines and seams were evaluated. The evaluated coals
include:
a. Fording Coal Type A, thermal, Black Bear Mine
b. Fording Coal Type B, thermal, Coal Mountain Mine
c. Luscar Obed Mountain Mine
d. Luscar Coal Valley Mine
e. Usibelli Coal Mines
f. Quinsam Coal
g. Kennecott Energy, Spring Creek Mine
h. Kennecott Energy, Colowyo Mine
Quinsam, Fording and Luscar are Western Canadian coal mines located in British
Columbia. The Kennecott Energy Coal Mines are located on the Wyoming/Colorado
border. Usibelli coal is mined at Healy, Alaska. Fording Coal from the Black Bear seam
was selected as the baseline coal for this study. All other coals are compared against the
Black Bear coal.
Of the coals examined, Black Bear coal has the lowest potential risk for
spontaneous combustion, while Usibelli coal is at higher risk. According to Westshore
Terminals, Black Bear coal can be stored without compacting or other major fire
prevention means for periods exceeding one year. Based on budgetary costs provided by
coal producers, it is estimated that Black Bear coal can be delivered to Goodnews Bay or
Security Cove for $55.00 per ton or approximately $2.25 per million Btu. Luscar Coal
Valley coal for 43.25 per ton or $1.99 per million Btu. Usibelli coal at $28.70 per ton or
$2.00 per million Btu. These prices were effective as of January 2004.
TABLE I-1.1
60 MW Average Mine Demand
Power Costs $/kWh - Selected Coals
97 MW Barge-Mounted Coal Plant
Fording @ $55.00/ton Luscar @ $43.25/ton Usibelli @ $28.70/ton
5%$0.103 $0.102 $0.111
$100 M Grants, Bal. 5%$0.090 $0.088 $0.097
$150 M Grants, Bal. 5%$0.083 $0.081 $0.090
$200 M Grants, Bal. 5%$0.076 $0.074 $0.083
$250 M Grants, Bal. 5%$0.069 $0.067 $0.076
Coal Cost per U.S. ton delivered to Security Cove or Goodnews Bay Prices as of January 2004
Although Usibelli coal is essentially the same cost per million Btu as Luscar coal
delivered to Security Cove or Goodnews Bay, a review of Table I-1.1 reveals that
Usibelli coal produces the highest power costs of the three coals averaging nine-tenths of
a cent greater than Luscar coal and seven-tenths of a cent greater than Fording coal.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.10
The heating value of Usibelli coal, as mined, is 7,128 Btu/lb vs. 12,284 Btu/lb of
Fording coal and 10,843 Btu/lb for Luscar Coal Valley coal. In addition, the high
moisture content of Usibelli coal reduces boiler efficiency. A power plant requiring
approximately 300,000 tons of Fording coal will require approximately 500,000 tons of
Usibelli coal to produce the same amount of power. This larger volume of Usibelli coal
would require physically larger and more costly coal storage facilities, boilers, ducts,
emission control equipment and higher expenses on moving coal, air and combustion
gases, all of which increase capital costs by approximately $35,000,000. In addition, the
increased volume of Usibelli coal that must be handled will increase O&M by
approximately $500,000 per year and lightering cost between Security Cove or
Goodnews Bay and Bethel by approximately $1,100,000 per year. These factors combine
to increase power costs when using Usibelli coal.
3. Coal Demand and Storage Requirement
Coal demand of the Bethel Power Plant, based on using Fording Coal Type A, is
estimated in excess of 300,000 tons per year at 80% of plant demand, and 375,000 tons
when operating a full plant capacity of 97 MW. Since the navigation season on the
Kuskokwim River is approximately three months, storage capacity must provide space
for storing nine months worth of coal usage or approximately 300,000 tons.
To minimize coal-dust pollution and keep the coal pile free of rain and snow, the
coal will be stored in an enclosed, air-supported or modular steel structure approximately
1400 ft. x 300 ft. x 30 ft. in height. With uncovered outdoor storage, the winds will pick
up coal dust and deposit it on adjacent lands. The estimated amount of dust that could be
blown away from an uncovered coal pile is up to 5%, especially during stacking and
reclaiming operations. This represents a loss of 15,000 tons or an estimated $800,000
annually. The cost of a covered structure, estimated at $7.5 million, will pay for itself, in
coal savings, in approximately nine years.
4. Coal Transportation
Coal will be transported by 35,000 DWT bulk freighters to Security Cove or
Goodnews Bay. The freighters will be equipped with continuous unloading capabilities.
Goodnews Bay is located approximately 135 miles south of Bethel on the western coast
of Alaska. Security Cove is approximately 25 miles further south than Goodnews Bay. At
either of these transload points the coal will be off-loaded from the freighters into barges
and lightered into Bethel. Security Cove and/or Goodnews Bay were chosen as possible
transloading point because waters of the Kuskokwim Bay and the mouth of the
Kuskokwim River are too shallow for deep water freighters to enter. Either of these two
bays should provide reasonable protection from rough seas.
To minimize coal lightering cost it is recommended that Nuvista lighter the coal
from Security Cove or Goodnews Bay to Bethel. To accomplish this, Nuvista would
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.11
purchase 3 (three) pre-owned barges with 10,000 to 12,000 DWT capacity, maximum
draft 12.5 feet, and one pre-owned tug boat with a 3000 to 4000 hp engine. The Nuvista
transport option results in significant savings as compared to contracting with an
independent barging firm to lighter the coal.
A continuous barge unloader will be used to unload coal from barges arriving at
Bethel. The unloader would be mounted on a catamaran. It will be capable of off-loading
2000 ton per hour. The catamaran and unloader combination will be towed into position
by a tug each spring and secured to the dock. Each fall it will be towed to a slough for
winter storage.
B. COMBINED-CYCLE COMBUSTION TURBINE PLANT
The study evaluates two sites for a modular combined-cycle combustion turbine
power plant, Bethel and Crooked Creek. The Modular Power Plant (MPP) at Bethel or
Crooked Creek will consist of a combined-cycle combustion turbine plant, equipped with
three simple-cycle combustion turbines plus a heat recovery boiler and steam turbine
generator. The use of low–speed diesel generation was examined as part of the study, but
this alternative was rejected in favor of combustion turbines. The Power Plant will use a
modular design, to the extent practicable, to reduce on-site construction costs, minimize
construction time and facilitate handling and transporting of major equipment.
The power plant would burn #2 diesel fuel or possibly propane. Installed
generation capacity at Bethel would be 150+2 MW depending whether Alstrom or GE
turbines are selected. At Crooked Creek the plant capacity is 110 MW. The Bethel plant
would generate approximately 650,000 Mwh annually, the Crooked Creek plant 550,000
MWh annually. The Bethel plant would consume approximately 32 million gallons of
diesel fuel or 50 million gallons of propane annually. The Crooked Creek plant would
consume 31 million gallons of diesel fuel. Propane was not considered for use at the
Crooked Creek plant. The large amount of fuel needed to fire the combustion turbine
plant would be delivered by barge to the facility dock and pumped to the above-ground
diesel storage tanks via an above-ground pipeline. Annual fuel storage requirements at
Bethel are 25 million gallons of diesel fuel or 38 million gallons of propane. Annual fuel
storage requirements at Bethel and Crooked Creek are essentially the same. Fuel oil
would be stored in eight, 3.1 million gallon tanks. Propane will be stored in three, 13
million gallon tanks.
The use of a barge-mounted plant was investigated as a means of reducing the
high cost associated with constructing a land-based power plant. Barge mounted
combustion turbine power plants are common. A barge-mounted power plant is suitable
for Bethel, but not Crooked Creek. Barge mounting the power-plant is estimated to
reduce Bethel plant construction cost by approximately $11 million. The barge-mounted
power plant alternative would occupy one barge 100 feet wide by 350 feet long. As with
the land-based turbine plant, the total installed capacity for the barge-mounted alternative
would be 150 MW.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.12
The barge would be equipped with the intended systems at a shipyard on the West
Coast USA or Canada and shipped on dry dock vessels to the vicinity of Security Cove or
Goodnews Bay, Alaska, from where the barge will be offloaded and towed to Bethel.
Fuel storage would be located on the adjacent river bank directly above the barge,
and these would be connected to the generating facilities by a short pipeline. Other
auxiliary features of the barge-mounted power plant alternative, including the blowdown
pond and the electrical switchyard, would also be located in this area, which would
occupy approximately 80 acres. The barge would occupy less than 1 acre.
As with the barge mounted coal plant, the barge would be set in place by digging
a channel into the river bank of sufficient width, length, and depth to float the barge into
position. Once the barge is towed and pushed into place, an armored berm would be built
between the barge channel and the river to protect the barge from ice flows during spring
breakup and to provide an earthen platform for unloading supplies. The barge would be
located in the floodplain of the river at a location where there is little elevation difference
in the bank and the river.
1. Site Location
The preferred Bethel location for modular power plant is the same as for the coal-
fired plant. See Figure I-1.3. An alternative location for the plant is Crooked Creek, AK,
about 180 miles up river from Bethel.
2. Fuel Alternatives
Table I-1.2 summarizes the evaluation of various applicable fuels for the MPP.
All of the listed fuels can be used for firing the combustion turbines.
Transporting the fuel oil from Cook Inlet or West Coast USA/Canada to Bethel or
Crooked Creek requires up to three steps: (1) Linehaul barge transportation from Seattle
or Cook Inlet into the Kuskokwim River to Bethel and if transported to Crooked Creek
then it will be necessary to (2) off-load, temporary storage and transfer the fuel to smaller
barges, (3) transport in smaller barges from Bethel to Crooked Creek. The shallow nature
of the Kuskokwim above Aniak (between Bethel and Crooked Creek) provides the
greatest challenge, both physically and financially, to this endeavor. The cost estimate
for delivering, with specialized shallow-draft tugs and barges that can operate between
Bethel and Crooked Creek, approximately 32,000,000 gallons to Crooked Creek is
$12,800,000, not including fuel cost. Delivery of the same quantity of fuel oil to Bethel
will cost approximately $6,720,000 less – a large incentive for the Bethel location.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.13
Table I-1.2
Fuel cost per MM Btu gross
All Btu/lb or gallon values are
NET
Btu/lb
Btu/gal
LHV
lb / gal $ / gal
at refinery
$/MM Btu
excl.
shipping
$ / gal incl
shipping to
Bethel
$/MM Btu
in Bethel
$ / gal incl.
shipping to
CC
$/MM Btu
including
shipping to
CC
Diesel Fuel No. 2 (TESORO) 18,421
130,236 7.07 0.85 6.53 1.04 7.99 1.25 9.60
Diesel Fuel No. 1 gross 18,561
125,101 6.74 0.90 7.19 1.09 8.71 1.30 10.39
Pour 40 Heating Oil (DF1 75%,
DF2 25%)
18,461
126,679 6.86 0.87 6.87 1.06 8.37 1.27 10.03
Jet B 17,931
112,929 6.30 0.88 7.79 1.07 9.47 1.28 11.33
# 2 DIESEL FUEL (WILLIAMS
ALASKA)
18,380
131,399 7.15 0.87 6.58 1.06 8.03 1.265 9.63
JP-4 17,973
113,194 6.30 0.87 7.69 1.06 9.36 1.27 11.22
Naphtha 19,743
120,277 6.09 0.82 6.82 1.01 8.40 1.22 10.14
Heating fuel Product Nr. 43 18,194
126,630 6.96 0.86 6.79 1.05 8.29 1.26 9.95
Propane 20,238
85,000 4.20 .50 .10 .65 7.65 .80 9.41
Fuel Prices as of January 2003.
C. OTHER POWER SUPPLY ALTERNATIVES
1. Importing Rail-belt Power
Two transmission line alternatives capable of delivering power to the Donlin
Creek mine from the rail-belt were previously investigated as part of the Calista Region
Energy Needs Study, dated July 1, 2000. These alternatives include a 230-kV, AC
transmission line or a + 100-kV, DC, transmission line from Nenana to the mine site.
These power line alternatives are revisited as part of this study. Both of these alternatives
provide substantially more expensive power than a coal-fired plant located at Bethel.
2. Holitna Basin or Cook Inlet Natural Gas
Holitna Energy, a newly formed company, has recently announced its intention to
explore the Holitna Basin for natural gas. Three major oil companies, ARCO, Unocal and
Sohio (now BP) independently evaluated the Holitna basin during the 1980s. At the time
this report was printed virtually no physical exploration of the basin by Holitna Energy,
has been accomplished. Presently no natural gas resource has been demonstrated. The
potential for finding an economic and commercially developable natural gas deposit is
unknown and the Holitna basin cannot presently be considered a natural gas resource.
The Cook Inlet alternative involves constructing a natural gas pipeline from the
Cook Inlet gas fields to Crooked Creek. The pipeline would be 300 miles long and
essentially follow the Iditarod trail through the Alaska Range. After exiting the Alaska
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EXECUTIVE SUMMARY Section I-1.14
Range on the north, the pipeline would turn southwest to Crooked Creek. A combined-
cycle combustion turbine plant would be constructed at Crooked Creek to supply electric
power to the Donlin mine project, Bethel and eight villages via a 138-kV transmission
line. Not only is this alternative one of the most capital intensive examined, production
from the Cook Inlet gas fields is expected to decline dramatically in 2010, which is the
very time the Donlin Creek mine will need power. Because of the high cost of this
alternative, the steep decline in gas production and the uncertainty as to the availability
and cost of natural gas from the Cook Inlet field, this alternative is not considered to be
practicable.
D. BETHEL TO DONLIN CREEK 138-kV TRANSMISSION LINE
The 191 mile long, 138-kV transmission line would be located along the northern
bank of the Kuskokwim River. (Figure I-1.2). The power line would serve Bethel,
Akiachak, Akiak, Tuluksak, Lower/Upper Kalskag, Aniak, Chuathbaluk Crooked Creek
and the proposed Donlin Creek gold mine. As discussed above the proposed power plant
would be located south of Bethel.
Two basic transmission structures could be used for constructing the 138-kV
transmission line. Single pole structures would be used for the initial 6 miles of the power
line, i.e. line Segment A-B, as it traverses south to north through the City of Bethel.
Using single pole structures would limit right-of-way requirements to less than 50 feet.
Typical structure height would be 50-60 feet and span length, i.e. distance between
structures, would be in the order of 300 feet.
The next 80 miles of power line, i.e. line Segments B-C through F-G, extends
between Bethel and Upper Kalskag. This portion of line traverses marshy, tundra covered
lowlands underlain with permafrost. Terrain elevation for this portion of the line varies
from a minimum of 13 feet to a maximum of 73 feet. A driven pipe-pile supported, steel
H-frame structure, is recommended for use on this portion of the line. The driven pile
supported steel structure has been used in the construction of most major power lines in
Alaska, in this type of terrain. R.O.W. width requirements when using H-frame structures
would be 125 feet. Using a nominal structure height of 70+20 feet, a typical span length
of 1,200 feet can easily be achieved along this portion of the route.
The portion of power line located between Kalskag and Donlin Creek Mine, i.e.
line segments G-H through L-N, traverses hilly terrain and better drained soils. It is
anticipated that granular, moderately drained soils will be encountered, along this portion
of the route and therefore, it would be possible to utilize direct imbedded steel H-frame
structures, rather than driven pile supported structures. Typical R.O.W. width
requirements when using the H-frame structures would be 125 feet. Terrain elevation for
this portion of the line varies between a minimum of 59 feet to a maximum of 950 feet.
Due to the hilly terrain along this portion of the route, a typical span length along this
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.15
portion of the route would decrease to 1,000 feet. Typical tower heights would be 70+ 20
feet.
E. PROJECT SCHEDULE
It is estimated the permitting, design and construction of a coal-fired plant at
Bethel and a 138-kV transmission line from Bethel to the Donlin Creek mine site will
required approximately 6 to 6-1//2 years. If the goal is to deliver power to the mine
project by 2010, the EIS process must begin early in the year 2004.
The above schedule assumes the project does not encounter any unexpected
delays or impediments. Few projects of this magnitude are, however, permitted, designed
and built without encountering some unexpected delays.
F. ECONOMIC ANALYSIS and COST ESTIMATES
1. Capital Costs
Eight different generation alternatives were investigated as part of this study.
These eight alternatives, along with their respective capital costs are listed in Table I-1.3.
Alternatives 1, 2 & 3 investigate various scenarios for a coal-plant located at Bethel,
while alternatives 4 & 5 investigate two combined-cycle combustion turbine alternatives
located at Bethel. These alternatives include the cost of constructing a 138-kV
transmission line between Bethel and the Donlin Creek mine and associated substations.
Alternative 6 examines a combined-cycle combustion turbine plant at Crooked Creek.
The last two alternatives, 7 & 8, examine importing power from the rail-belt. These two
alternatives include the cost of constructing a 138-kV transmission line between the
Donlin Creek mine and Bethel. Except for Alternative 6, all alternatives are evaluated
with the premise that each alternative must supply power to the Donlin Creek mine,
Bethel and the eight villages located between Bethel and the mine site. Alternative 6
supplies power only to Crooked Creek and the mine.
Table I-1.3
Capital Costs
Does Not Include Interest During Construction
97 MW Coal Plant 97 MW Coal Plant 80 MW Coal Plant 150 MW CT Plant
+ 46 MW CT + 46 MW CT + 25 MW CT Bethel
Bethel-Land Based Bethel-Barge Mounted Bethel- Barge Mounted Land-Based
Alt. 1 Alt. 2 Alt. 3 Alt. 4
$392,282,800 $369,487,800 $351,237,800 $307,077,800
150 CT Plant 110 MW CT Plant 230 kV, AC +100 kV, DC
Bethel Crooked Ck T-Line T-Line
Barge Mounted Land-Based from Nenana from Nenana
Alt. 5 Alt. 6 Alt. 7 Alt. 8
$296,577,800 $140,632,600 $494,648,260 $521,946,800
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EXECUTIVE SUMMARY Section I-1.16
Table I-1.3 reveals that importing power from the rail-belt using either a 230-kV,
AC transmission line or a + 100-kV, DC transmission line are the two most capital
intensive alternatives proposed, while constructing a power plant at Crooked Creek to
serve only the mine load is the least capital intensive alternative.
2. Wholesale Power Costs
Table I-1.4 summarizes and allows for a ready comparison of the wholesale
power cost, expressed in dollars per kilowatt hour, for the various alternatives, based on
an average mine demand of 60 megawatts. Wholesale power costs are derived by adding
one-half cent to power production costs. Power costs for five different financing options
are included. The table only contains the power cost for the Bethel barge-mounted power
plant alternatives. The Bethel land-based power plant alternatives (Alt. 1 and Alt. 4) are
not included as they are more expensive to construct and would, therefore, produce more
expensive power than their barge-mounted counterparts.
A review of Table I-1.4 discloses that the Bethel coal-fired plant alternatives
produce the lowest cost power for all financing options, while importing power from the
rail-belt results in the highest cost power. Alternatives 7 and 8 assume firm power can be
purchased at the Nenana substation for 4.5 cents per kWh and $11.25 kW demand
charge. Alternative 7A assumes non-firm power can be purchased at the Nenana
substation for 4.5 cents per kWh with no demand charge. Even when purchasing non-
firm power (Alternative 7A) the cost of power imported from the rail-belt is 2 cents per
kWh more expensive than power produced by the Bethel coal plant alternative, for all
financing options.
Table I-1.4
60 MW Average Mine Demand
Wholesale Power Costs Years 1-20
97 MW Coal Plant 80 MW Coal Plant 150 MW CT Plant 150 MW CT Plant
+ 46 MW CT + 25 MW CT Bethel - #2 Fuel oil Bethel - Propane
Bethel-Barge Mounted Bethel-Barge Mounted Barge Mounted Barge Mounted
Financing Option Alt. 2 Alt. 3 Alt. 5 Alt. 5A
5%$0.103 $0.101 $0.113 $0.111
$100 M Grants, Bal. 5%$0.090 $0.087 $0.099 $0.097
$150 M Grants, Bal. 5%$0.083 $0.080 $0.092 $0.090
$200 M Grants, Bal. 5%$0.076 $0.073 $0.085 $0.083
$250 M Grants, Bal. 5%$0.069 $0.066 $0.078 $0.076
110 MW CT Plant 230 kV, AC 230 kV, AC +100 kV, DC
Crooked Ck T-Line T-Line T-Line
Land-Based w/Demand Charge w/o Demand Charge w/Demand Charge
Financing Option Alt. 6 Alt. 7 Alt. 7A Alt. 8
5%$0.112 $0.136 $0.123 $0.128
$100 M Grants, Bal. 5%$0.096 $0.122 $0.109 $0.114
$150 M Grants, Bal. 5%$0.090 $0.116 $0.102 $0.107
$200 M Grants, Bal. 5%$0.090 $0.109 $0.095 $0.100
$250 M Grants, Bal. 5%$0.090 $0.102 $0.088 $0.093
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.17
Power costs associated with two different coal plant sizes are listed in
Alternatives 2 and 3. Alternative 2 represents power cost for a plant with a total installed
capacity of 143 MW, while Alternative 3 is for a plant with an installed capacity of 105
MW. The power cost for these two alternatives are identical for all practical purposes,
varying by no more than three-tenths of a cent. Reducing the installed generation
capacity of the coal plant by 39 MW or 27% has only a minor impact on the cost of
power. Since the power costs associated with Alt. 2 and 3 are essentially equal, Alt. 3
will no longer be included in this discussion as a separate alternative. The final installed
capacity of the coal plant will be determined after Placer Dome more accurately
ascertains the peak and average mine demand, however, it is expected to fall between the
upper and lower limits established by Alt. 2 and Alt. 3.
Alternative 5 and 5A examine the cost of power associated with a Bethel-based
combined-cycle combustion turbine plant. The two alternatives differ only in that
Alternative 5 examines power cost associated with using #2 fuel oil, while 5A scrutinizes
the cost of power connected with using propane fuel. An examination of the power costs
associated with these two alternatives discloses propane produces power at two-tenths of
one cent lower than fuel oil.
Finally, Alternative 6 lists the cost of power associated with constructing and
operating a combined-cycle power plant at Crooked Creek to supply the Donlin Creek
mine and the village of Crooked Creek. Power costs for this alternative are effectively
equal to the cost of power from Alternative 5A. Power costs for the Cooked Creek plant
remain constant for the last three financing options. This is because the capital cost of the
Crooked Creek plant is less than $150 million.
Figure I-1.4 graphically displays power cost, in dollars per kWh, associated with four
selected alternatives for the five financing options. This graph clearly illustrates that the
Figure I-1.4
Power Cost Comparison- Years 1-20
$0.000
$0.020
$0.040
$0.060
$0.080
$0.100
$0.120
$0.140
$/kwH97 MW Coal Plant(ALT. 2)$0.103 $0.090 $0.083 $0.076 $0.069
150 MW CT Plant (Alt. 5A)$0.111 $0.097 $0.090 $0.083 $0.076
110 Crooked Ck Plant (Alt.6)$0.112 $0.096 $0.090 $0.090 $0.090
230 kV, AC Tline (Alt 7A)$0.123 $0.109 $0.102 $0.095 $0.088
5% $100 M Grants, Bal. 5% $150 M Grants, Bal. 5% $200 M Grants, Bal. 5% $250 M Grants, Bal. 5%
60 MW Average Mine Load
20 Year Mine Life
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.18
coal-plant alternative provides the lowest cost power, at any financing option, and
importing power from the rail-belt via a transmission line produces the highest cost
power.
3. 20 Year Accumulated Donlin Creek Mine Power Costs
Table I-1.5 lists the accumulated mine power cost for the various generation
alternatives and financing options for 60 MW average mine load and a 20 year mine life.
The magnitude of 20 years of accumulated power cost are truly astonishing. The
accumulated costs range between a maximum of $1,520 million ($1.52 billion) dollars for
Alt. 8 to a low of $735 million for Alt. 2. Assuming $150 million in grant funds5 can be
obtained to finance construction of Alternative 2, a coal-plant at Bethel + the 138-kV
transmission line, the projected 20 year accumulated mine power cost would be
approximately $885 million dollars, for an average power cost of $44 million dollars per
year.
Table I-1.5
60 MW Average Mine Demand
20 Year Mine Life
Donlin Ck Mine Accumulated Power Costs Years 1-20
97 MW Coal Plant 150 MW CT Plant 150 MW CT Plant 110 MW CT Plant
+ 46 MW CT Bethel - #2 Fuel oil Bethel - Propane Crooked Ck
Barge Mounted Barge Mounted Barge Mounted Land-Based
Financing Option Alt. 2 Alt. 5 Alt. 5A Alt. 6
5%$1,110,512,156 $1,204,682,971 $1,183,673,214 $1,180,224,519
$100 M Grants, Bal. 5%$960,508,237 $1,054,679,052 $1,033,669,295 --
$150 M Grants, Bal. 5%$885,506,278 $979,677,093 $958,667,336 --
$200 M Grants, Bal. 5%$810,504,319 $904,675,133 $883,665,377 --
$250 M Grants, Bal. 5%$735,502,359 $829,673,174 $808,663,417 --
230 kV, AC 230 kV, AC +100 kV, DC
T-Line T-Line T-Line
w/Demand Charge w/o Demand Charge w/Demand Charge
Alt. 7 Alt. 7A Alt. 8
5%$1,458,404,593 $1,314,192,234 $1,518,302,581
$100 M Grants, Bal. 5%$1,308,400,674 $1,164,188,315 $1,368,298,662
$150 M Grants, Bal. 5%$1,233,398,715 $1,089,186,356 $1,293,296,702
$200 M Grants, Bal. 5%$1,158,396,756 $1,014,184,396 $1,218,294,743
$250 M Grants, Bal. 5%$1,083,394,796 $939,182,437 $1,143,292,784
Table I-1.6 illustrates the saving associated with Alternative 2, the 97 MW barge-
mounted coal-fired generation alternative, as compared to other generation alternatives,
for the same twenty year period. When compared to the Crooked Creek alternative (Alt.
6), the coal plant (Alt. 2) is estimated to save the mine $295 million dollars in power
costs, or $14.7 million dollars a year. Compared to the least cost combined-cycle
generation alternative (Alt. 5A), the coal plant (Alt. 2) is estimated to save the mine $94
5 The $150 million grant fund option was selected as it produces power cost for Alt. 2 in the price range
that may be economically acceptable to Placer Dome.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.19
million dollars in power costs, or $4.7 million dollars per year. Comparing Alt. 2 to the
230 kV transmission line non-firm power option, (Alt. 7A), the estimated savings are
$203 million, or $10.1 million per year.
Table I-1.6
60 MW Average Mine Demand
20 Year Mine Life - $150 Million in Grants
Saving Associated with 97 MW Coal-Fired Generation vs. Other Alternatives
97 MW Coal Plant 150 MW CT Plant 150 MW CT Plant 110 MW CT Plant
+ 46 MW CT Bethel - #2 Fuel oil Bethel - Propane Crooked Ck
Barge Mounted Barge Mounted Barge Mounted Land-Based
Alt. 2 Alt. 5 Alt. 5A Alt. 6 (1)
Total Saving $0 $94,170,815 $73,161,058 $294,718,241
Average Annual Savings $0 $4,708,541 $3,658,053 $14,735,912
230 kV, AC 230 kV, AC +100 kV, DC
T-Line T-Line T-Line
w/Demand Charge w/o Demand Charge w/Demand Charge
Alt. 7 Alt. 7A Alt. 8
Total Saving $347,892,437 $203,680,078 $407,790,424
Average Annual Savings $17,394,622 $10,184,004 $20,389,521
(1) Savings calculated using accumulated power cost for 5% Financing Option for Crooked Creek alternative,
as it is presumed only minimal grant funding will be available for this alternative
The costs shown in Table I-1.6 were calculated using a 60 MW average mine
demand, 20 year mine life and $150 million in grant fund financing, except for
Alternative 6. The Crooked Creek column assumes this alternative must be entirely
funded with 5% interest loans. It is presumed that since a power plant at Crooked Creek
would essentially only serve the mine load, little if any grant funding would be available
for the Crooked Creek plant alternative. Savings for other finance options can be
determined from using the data in Table I-1.5.
4. Fuel Price Sensitivity Analysis
The sensitivity of wholesale power cost to fuel cost is examined in Table I-1.7.
The table lists wholesale power costs for both the “base” fuel price used in this study and
for base price plus 25 percent, for the five financing options. An examination of the data
reveals that the percentage increase in wholesale power costs for combined-cycle
combustion turbine plant is approximately 1.75 times that of a coal plant. This is because
fuel cost represents a greater portion of the wholesale power cost for a turbine plant than
it does for a coal-plant.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.20
Table I-1.7
60 MW Average Mine Demand
20 Year Mine Life
Fuel Cost Sensitivity Analysis - 25% Fuel Price Increase
Coal Plant (Alt. 2) CT Plant (Alt. 5A)
25% Price Increase % Increase 25% Price Increase % Increase
Financing Alternatives $55.00/ton $68.75/ton Wholesale Power $0.65/gal $0.82/gal Wholesale Power
5%$0.103 $0.111 7.8% $0.111 $0.124 11.7%
$100 M Grants, Bal. 5%$0.090 $0.097 7.8% $0.097 $0.110 13.4%
$150 M Grants, Bal. 5%$0.083 $0.090 8.4% $0.090 $0.104 15.6%
$200 M Grants, Bal. 5%$0.076 $0.083 9.2% $0.083 $0.097 16.9%
$250 M Grants, Bal. 5%$0.069 $0.076 10.1% $0.076 $0.090 18.4%
5. Mine Demand Sensitivity Analysis
To determine the effects of variations in mine demand, wholesale power cost for
Alt. 2 were examined using average mine demands of 50, 60 and 70 MW for three
financing options. The results of this analysis are summarized in Table I-1.8. On
average, wholesale power costs will increase nine-tenths of a cent if the mine demand
decreases from 60 MW to 50 MW, and cost will decrease by six-tenths of a cent if mine
demand increases from 60 MW to 70 MW. Other alternatives would experience similar
cost changes.
Table I-1.8
Mine Demand Sensitivity
Mine Demand
Wholesale Power Cost 50 MW 60 MW 70 MW
5% $.119 $0.103 $0.093
$150 Grants, Bal. 5% $0.095 $0.083 $0.075
$250 Grants, Bal. 5% $0.079 $0.069 $0.063
6. Coal-fired Plant Generation Efficiency
A coal-fired plant generation efficiency of 31% was used to calculate power costs
for the various coal-fired power plant alternatives investigated in this study. This
nominal efficiency was calculated by PES, as being typical of coal-fired plants using
common off-the-shelf equipment. However, it is possible, through careful engineering, to
readily increase generation efficiency to 35% and in some cases to 40%. These include
installing boilers that operate at higher pressures, using a second reheat stage and
installing variable speed drives. Efficiency in the range of 40% can be achieved using
supercritical steam systems, however, operating such a system requires highly skilled
personnel. Increasing efficiency is one of the less expensive ways of reducing pollution
emissions. Appropriate equipment will be selected during the actual design process that
achieves a balance between thermal efficiency, capital costs, and personnel requirements.
Table I-1.9 shows the relationship between power costs and generation efficiency.
Increasing efficiency to 35% will reduce wholesale power cost by approximately $0.004
cents per kWh. While this may not seem like a substantial reduction, it would reduce
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.21
power cost to the mine by $2.4 million dollars annually or by $48 million dollars over the
20 year life of the mine. Increasing plant efficiency to 40% would reduced power costs
by $0.007 per kWh or by $4.9 million dollars annually, which equates to $98 million
dollars over the 20 year life of the mine.
Table I-1.9
Generation Efficiency
Wholesale Power Cost 31% 35% 40%
5% $.103 $0.10 $0.097
$150 Grants, Bal. 5% $0.083 $0.079 $0.076
$250 Grants, Bal. 5% $0.069 $0.065 $0.062
7. Waste Heat Recovery
The effect of waste heat recovery and sales on wholesale power costs was also
examined. The analysis indicated that for every one million dollars of waste heat sales,
power cost were lowered by one-tenth of a cent.
8. 50-Year Regional Power Costs
The useful life of the transmission and generation facilities presented and
discussed in this study is projected to be 50 years. Therefore, it is necessary to investigate
the power costs associated with the proposed alternatives for the entire 50 year period.
Figure I-1.5 illustrates the power cost for selected alternatives for a 50 year period,
beginning in 2010
Figure I-1.5
50 Year Regional Power Costs
$0.000
$0.020
$0.040
$0.060
$0.080
$0.100
$0.120
$0.140
2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060
Year$/kWhCP(Alt. 2)- 20 Yr Mine Life CP(Alt. 2) - 50 Yr Mine Life
CP(Alt. 2) - 50Yr Mine Life, 30 MW in 2031 CT(Alt. 5A) - 20 Yr Mine Life
230kV Tline(Alt. 7A) -20 Yr Mine Life
$150 M illion Grant Funding, Bal . @ 5%
60 MW Average Mine Demand
Unless Noted Otherwise
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.22
The graph demonstrates that wholesale power costs remain relatively constant
over the first twenty years for all alternatives. This corresponds to the estimated life of
the mine. After 20 years, when capital costs are fully amortized, there is a step change in
power cost. The graph shows power cost changing gradually over a five year period
between 2030 and 2035. However, in reality the power costs will change to the 2035 cost
levels in 2031. However, the graphics software cannot easily show this step change.
Wholesale power costs after 2030 are calculated by adjusting fuel cost, operational and
maintenance cost as appropriate, to reflect cost changes in these items associated with
reduced generation requirements.
The following can be determined from reviewing Figure I-1.5. When the Donlin
Creek mine ceases operations at the end 20 years, in the year 2030, the wholesale power
cost for the coal-plant alternative (Alt. 2) and the combined-cycle alternative (Alt. 3) will
increase to 10.5 cents and 13.7 cents per kWh, respectively. The power cost for the 230-
kV transmission line alternative (Alt. 7A) will decrease to 5.5 cents per kWh, assuming
no demand charge. These costs assume that no other loads but Bethel and the eight
villages are served by the power system after 2030.
If the mine life extends for 50 years, power cost for Alt. 2 would decrease to 5.7
cents per kWh. The graph also establishes that if the mine remains operational after 2030,
but at a reduced demand of 30 MW, or if a new load or loads equal to 30 MW can be
served, wholesale power costs will decrease to approximately 6.6 cents per kWh. This is
not an unlikely scenario as it is most probable that additional villages in the region will be
connected to the power system prior to 2030 and that additional gold deposits located in
the Calista region will be developed and mined once low cost power is available.
Table I-1.10 illustrates the Fifty Year Regional Power cost saving associated with
Alternative 2, the 97 MW barge-mounted coal-fired generation alternative, as compared
to other generation alternatives. Implementation of Alt. 2 results in the lowest 50-year
accumulated power costs, saving the region over $181 million when compared to the next
lowest cost alternative, which is Alt. 7A. Although Alt. 7A provides lower cost power to
the region following closure of the mine (See Figure I-1.5) it cannot be economically
implemented because power costs, for this alternative during the initial 20-year period,
are significantly in excess of those provided by Alt. 2. No costs are listed in the Crooked
Creek Plant column (Alt. 6) as it is assumed this alternative would only serve the mine
load and would be decommissioned at the end of 20 years.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
Power Supply Feasibility Study Final Report 06/11/04
EXECUTIVE SUMMARY Section I-1.23
TABLE I-1.10
60 MW Average Mine Demand
20 Year Mine Life - $150 Million in Grants
50 Year Regional Saving Associated with 97 MW Coal-Fired Generation vs. Other Alternatives
97 MW Coal Plant 150 MW CT Plant 150 MW CT Plant 110 MW CT Plant
+ 46 MW CT Bethel - #2 Fuel oil Bethel - Propane Crooked Ck
Barge Mounted Barge Mounted Barge Mounted Land-Based
Alt. 2 Alt. 5 Alt. 5A Alt. 6
Total Saving $0 $227,606,055 $204,775,121 --
Average Annual Savings $0 $4,552,121 $4,095,502 --
230 kV, AC 230 kV, AC +100 kV, DC
T-Line T-Line T-Line
w/Demand Charge w/o Demand Charge w/Demand Charge
Alt. 7 Alt. 7A Alt. 8
Total Saving $436,808,100 $181,657,253 $352,411,323
Average Annual Savings $8,736,162 $3,633,145 $7,048,226
G. ENVIRONMENTAL ASSESSMENT REVIEW
As part of the environmental assessment review process, input from interested
parties was solicited. To accomplish this, separate letters were developed and presented
to potentially interested parties, one for the transmission line project and a second for the
Bethel power plant project. These parties include the State of Alaska, 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, and solicited input from recipients.
1. 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 Project would be provided through the U.S. Department of
Agriculture (USDA), Division of Rural Utilities (RUS). Thus, federal funding would
likely be one of the triggers for NEPA compliance. “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 …” Therefore, an Environmental Impact Statement
(EIS) must be prepared for the transmission line and power plant. Agencies responding
to the feasibility letter agreed that the proposed project will require an EIS.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.24
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).
2. Scope of NEPA Consistency Review
An issue that has arisen in assessing the feasibility and permittability of 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
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.25
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. The Corps has
suggested that tiering the NEPA analysis of the mine project off the power
plant/tranmission line EIS would be satifactory to the Corps. Tiering would allow the
EIS and permitting of the power plant and transmission line to 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 the agencies reject a tiering approach, 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 effectively preclude the
need for an alternative power source and would likely preempt development of the Bethel
Power Plant/transmission line project as proposed in this report.
For the purpose of this study it is assumed that the agencies will agree to a tiering
approach and the scope of the initial NEPA review will only include the Bethel Power
Plant Project, its appurtenances and the associated transmission line.
3. Land Ownership
The USFWS indicated that any lands in a NWR that have been selected but not
conveyed to a native corporation are managed as any other refuge lands under their
jurisdiction. The development on those lands will require a R.O.W. permit.
The USFWS will require a review of the alternatives, along with their impacts, 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).
This project will affect mainly the surface estate, but some subsurface lands will
be affected due to required material sources. Table I-1.11 displays a breakdown of the
transmission line and the ownership rights within each segment of the affected lands. See
Figure I-1.2 for map of transmission line route and segments.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.26
PROPOSED ROUTE SEGMENTS
with Land Ownership
TABLE I-1.11
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
Mile 26.2
D-E 16.6 56.5 39 61 Tuluksarmute Tuluksak Substation at
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 Ck
Mine Substation at Mile
191.2
4. Project Permits
Project permits will require detailed design information. Project specifics,
alternatives, and work time frames will need to be completed according to permit
specifications. Tables I-1.12 and 13 summarize the potential permits required for this
project and the regulatory agencies that approve them.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.27
Table I-1.12
Transmission Line Permits
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.
Food Service A permit must be obtained for permanent, temporary,
limited or mobile food service operations serving 11
or more persons per day. (May apply to construction
camp)
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.
Alaska Department of
Environmental
Conservation
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.
Alaska Department of
Natural Resources,
Land Use A land use permit is required for use of state lands
along the proposed ROW.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.28
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.
Table I-1.13
Bethel Power Plant Permits
Agency Name Permit/Approval
Federal Agencies
U.S. Environmental Protection Agency National Pollutant Discharge Elimination System
(NPDES) Wastewater Discharge Permit.
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.
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.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION I
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EXECUTIVE SUMMARY Section I-1.29
Agency Name Permit/Approval
State Agencies
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.
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.
Alaska Department of Natural Resources,
Office of Habitat Management and Permitting
Fish Habitat Permit.
Alaska Department of Natural Resources,
State Historic Preservation Officer
National Historic Preservation Act (NHPA) Section 107
Consultation.
4. AGENCY AND PUBLIC COMMENTS
Over three hundred copies of the full report with supporting appendices were sent out
on compact disks, in PDF format, to various private organizations, individuals, federal and
state agencies for review and comment. Written comments were received from several
agencies and organizations. These comments are included in Appendix I. Public
meetings were conducted in Aniak and Bethel on May 12 and 13, 2004, respectively.
Only seventeen individuals, total, attended the two public meetings. A list of attendees in
included in Appendix I. Individuals attending the meeting expressed support for and
opposition to the proposed coal-fired plant. The comments from those individuals
opposing the proposed coal-fired plant centered on the emission emitted from plant.
Those favoring the construction of the proposed coal-fired plant focused on the benefits
that lower cost power would bring to the region.
Agency comments tended to focus on the need to comprehensively evaluate both
the mine project and the power project together, as required by NEPA, to include direct,
indirect and cumulative impacts. This evaluation would include the power plant at
Bethel, the transmission line, the road to the mine, the Donlin Creek mine and secondary
power distribution to the villages.
Comments were also received that suggested that the coal-plant should be
constructed using fluidized bed technology rather than pulverized coal technology, as
recommended in this report, because fluidized bed boilers can burn a wider range of
fuels. There are advantages and disadvantages to both technologies. Combustion
technologies will be reevaluated during the EIS and design phase and the most
appropriate technology will be selected.
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentRoute OverviewBettine, LLCBethelAniakDonlin CreekFigure I-1.2
Proposed Location of
Land-Based Coal
Fired Plant Alternative
80 Acres
Combustion Turbine
Alternative 40 Acres
Proposed Cooling Pond
78 Surface Acres
Barge Unloading
Station and Dock
Proposed Road
Proposed Location of
Coal Storage for Barge-
Mounted Coal Plant
Proposed Location of
Barge-Mounted Coal Plant
Proposed Road
Figure I-1.3- Aerial Photo of Bethel and Vicinity
Showing Proposed Bethel Power Plant Locations
NORTH.Kuskokwi
m Ri
ver
Fl
ow
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION II
Power Supply Feasibility Study Final Report 06/11/04
INTRODUCTION Section II-1.1
SECTION II INTRODUCTION
1. BACKGROUND
One of the largest undeveloped gold deposits in North America and in the world
is located in the Calista region, of southwestern Alaska. The Donlin Creek gold deposit
is located on Calista Native Corporation's 6.5 million acres of private lands.
The proposed Donlin Creek mine project is located approximately 280 miles west
of Anchorage and 14 miles north of Crooked Creek. The village of Crooked Creek is
located on the Kuskokwim River approximately 180 river miles upstream of Bethel. A
location map is attached at the end of Section I as Figure I-1.1.
The joint venture of Placer Dome, Inc and Nova Gold, Inc. is presently evaluating
the feasibility of developing a mine to extract the gold resources. Resource estimates
confirm a Measured and Indicated Resource of 11.1 million ounces of gold grading an
average of 3.0 g/t (grams/tonne) gold. In addition, the Inferred Resource is estimated at
14.3 million ounces of gold grading 3.1 g/t. The resource remains open, with potential to
define additional ounces with further drilling. Seven additional potential resource areas
occur on the property, all of which have significant high-grade drill results of >5 g/t over
significant widths that are not inc luded
in the current resource estimate.
Currently, the joint venture has
spent in excess of US$40 million on the
project and Placer Dome will be
spending an additional +US$30 million
to complete a Feasibility Study and
make a decision to construct the mine
prior to November 2007.
It is anticipated that the Donlin
Creek mine project would have a
maximum load demand of
approximately 70 megawatts with an
average load demand of in the range of 60 megawatts. There are no existing power
supply facilities in the region that can provide this power demand and new power supply
facilities must be constructed. In order for the Donlin Creek mine project to be
economically feasible these new power facilities must provide the mine with reasonably
cost power.
Donlin Creek Project looking north at the main resource area.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION II
Power Supply Feasibility Study Final Report 06/11/04
INTRODUCTION Section II-1.2
Nuvista Light & Power, Inc. (Nuvista), using grant funds provided by the Alaska
legislature, commissioned an energy needs study, in the year 2000, to identify a
comprehensive energy strategy that would provide low cost power to the Donlin Creek
mine project and to the 40+ villages in the Calista region.1 Nuvista is a non-profit
organization formed by Calista Corporation to function as a regional Generation and
Transmission utility. Nuvista would wholesale power directly to the Donlin Creek mine,
and to existing utilities for resale to their customers.
The energy needs study forecasted the power and energy requirements of the
Calista region both with and without the development of the Donlin Creek mine project.
The forecasted power demand with development of the Donlin Creek mine project, in the
year 2020, is 96 MW as compared to 30 MW projected load without the mine
development. Energy requirements are forecast at approximately 700,000 MWHs with
the mine as compared to 150,000 MWHs without the Donlin Creek mine development.
Development of the Donlin Creek mine project would triple the power demand in the
region and energy requirements would increase by almost five fold when compared with
power and energy requirements without the mine development.
Two general categories of alternatives were investigated to satisfy the electric
power and energy requirements of the proposed Donlin Creek mine project and the
Calista region. These included:
· Construct Power Supply in the Calista Region.
· Import Power From the Railbelt Region.
In-region power supply alternatives investigated to satisfy the electric power and
energy requirements of the proposed Donlin Creek Mine project, Bethel and the regional
villages include:
· Coal-Fired Plant at Bethel +191 mile long transmission line to the mine site.
· Combined-cycle combustion turbine plant located at Bethel ut ilizing fuel oil
or propane +191 mile long transmission line to the mine site.
· Combined-cycle combustion turbine plant at the mine site + coal plant at
Bethel+191 mile transmission line to mine site.
· Coal-Fired Plant at Railroad City +50 mile long transmission line to the
mine site.
· Combined-cycle combustion turbine plant located at Railroad City powered
by fuel oil or propane +50 mile long transmission line to the mine site.
1 Calista Region Energy Needs Study, Part I and II, July 1, 2002.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION II
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INTRODUCTION Section II-1.3
· Combined-cycle combustion turbine plant at mine site powered by fuel oil.
Power supply alternatives investigated that import power from the railbelt
include:
· The Construction of either an AC or DC transmission line, from Anchorage
or the Fairbanks region, to supply the power requirements of the mine
project and the region.
· Natural gas pipeline from Cook Inlet to Crooked Creek
Of the numerous power supply alternatives evaluated, in the energy needs study,
the identified preferred alternative for supplying the power needs of the Donlin Creek
mine project and the region is: Construct a Coal-Fired Plant at Bethel +191 mile long
138-kV transmission line to the mine site. The study recommended that Nuvista proceed
immediately with the planning, development and implementation of the preferred
alternative, commencing with the commissioning of a feasibility study. Based on this
recommendation, Nuvista obtained additional grant funding from the Alaska legislature
to proceed with this Feasibility Study.
2. PURPOSE OF STUDY
A primary goal of this Feasibility Study is to explore the feasibility of
constructing a power plant in Bethel, Alaska and a 138-kV transmission line from Bethel
to the proposed Donlin Creek gold mine project site. The transmission line would be
located along the northern bank of the Kuskokwim River. Power would be supplied from
a power plant at Bethel, to serve Bethel, Akiachak, Akiak, Tuluksak, Lower/Upper
Kalskag, Aniak, Chuathbaluk, Crooked Creek and the proposed Donlin Creek gold mine.
This study will define the basic design criteria and estimated costs associated with
the construction of the preferred power supply alternative, which has been identified as
the construction of 100 MW coal-fired plant at Bethel and a 191 mile long, 138-kV
trans mission line (the Donlin Creek transmission line) from Bethel to the Donlin Creek
mine. As an alternative to the coal-fired plant at Bethel the study will also identify the
basic design and cost associated with the construction of a combined-cycle combustion
turbine plant at Bethel. The study will assess and compare the capital costs and power
costs associated with these two alternatives with each other and with other selected power
supply alternatives. This feasibility study includes the following principal tasks:
1. Review routing alternatives for the 138-kV Donlin Creek Transmission line
and define a preferred alternative.
2. Develop a feasibility level design for the Donlin Creek transmission line.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION II
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INTRODUCTION Section II-1.4
3. Develop a feasibility level design for a 100+ MW coal-fired plant at Bethel.
4. Develop a feasibility level design for a 100+ MW combined-cycle combustion
turbine plant at Bethel.
5. Develop construction cost estimates for the Donlin Creek transmission line,
the coal-fired plant and the combined-cycle plant at Bethel.
6. Develop construction and operating cost estimates for the Donlin Creek
transmission line, the coal-fired plant and the combined-cycle plant at Bethel.
7. Develop a design and construction schedule including environmental review
8. Conduct a basic review of environmental factors and permitting requirements
rela ted to construction of the transmission line and power plants.
9. Conduct electrical system studies to evaluate the steady-state and transient
responses of the power systems.
10. Conduct an economic analysis comparing the 40 year costs of the Bethel coal
plant and the combined-cycle plant alternatives with each other and with other
selected power supply alternatives.
11. Identify potential financing sources and options.
12. Prepare a draft report summarizing the findings of the feasibility study.
13. Conduct a public meeting at Bethel and Aniak to present findings contained in
the draft feasibility study and solicit public comments.
14. Prepare a final report following the receipt of comments on the draft report.
3. STUDY METHODOLOGY
The feasibility study involved the efforts of several engineering firms and
environmental specialists. Bettine, LLC developed the Donlin Creek transmission line
route alignment, preliminary transmission line and substation designs, evaluated power
supply alternatives, conducted the economic analysis, and prepared the draft and final
report. Precision Energy Systems, Inc. developed the designs, construction and
operational cost estimates and construction schedule s for the Bethel coal-fired plant and
combined-cycle combustion turbine power supply alternatives. Two separate reports, one
for each power plant alternative, are included in a separate appendix. Dryden and LaRue,
Inc. (D&L) prepared cost estimates for the 138-kV Donlin Creek transmission line. In
addition D&L prepared cost estimates for a + 100-kV DC and a 230-kV AC transmission
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION II
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INTRODUCTION Section II-1.5
line from Nenana to the Donlin Creek mine. These costs will be used in the economic
analysis. The engineering firm of LCMF prepared preliminary designs and costs
estimates for power plant foundations and fuel storage facilities, which are included in a
separate appendix. Electric Power Systems, Inc. conducted electrical systems studies and
provided a report, which is included in a separate appendix. Travis/Peterson, Inc. and
Steigers Corporation provided separate environmental reports addressing basic
environmental factors and permitting requirements for the transmission line and power
plant, respectively. These are included in a separate appendix.
This study assumes the Donlin Creek gold mine would begin full scale mining
operations in mid-year 2010, with a peak demand of 70 MW and an average demand of
approximately 60 MW. Placer Dome, Inc. has, however, indicated that the mine may be
operational prior to 2010. Realistically it will be difficult to permit and construct a coal-
fired power plant at Bethel and a 191 mile long transmission line to provide 70 MW of
power to the mine site prior to this date. It may, however, be possible to provide power to
the mine by mid-2009 if environmental studies and preliminary engineering beginning no
later than the first quarter of 2004.
Several practical criteria were established to provide a guide in the route selection
process, which are discussed in Section IV-1. However, the overriding directive
followed for siting the transmission line was to avoid crossing federal lands within the
Yukon-Delta National Wildlife Refuge, by placing the power line within the corridor of
private lands owned by the various native corporations that are located adjacent to the
Kuskokwim River.
This study did not prepare an independent power requirements forecast but will
instead rely on the forecast prepared in the Calista Region Energy Needs Study, Part I,
dated July 1, 2002.
The economic analysis conducted for this study determines the power cost per
kWh associated with each of the various power supply alternatives for a 50-year period,
beginning in 2010 and ending in 2060. The economic analysis assumes a 20 year mine
life.
Methodologies and assumptions used in the study are ident ified in the applicable
sections.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
Power Supply Feasibility Study Final Report 06/11/04
BETHEL COAL-FIRED POWER PLANT Section III-1.1
SECTION III POWER SUPPLY ALTERNATIVES
1. BETHEL COAL-FIRED POWER PLANT
A. BACKGROUND
1. General
The primary purpose of this study is to examine the technical and economic
feasibility of constructing either a coal-fired power plant or a combined-cycle combustion
turbine plant at Bethel along with a 138-kV transmission line from Bethel to the Donlin
Creek mine. The generation/transmission system would provide power to the Donlin
Creek mine, Bethel and eight other villages located along the path of the transmission
line. The firm of Precision Energy Services (PES), located in Coeur d’Alene, Idaho, was
retained to provide feasibility level design and cost estimates for constructing the coal-
fired plant alternative and the combustion turbine plant alternative. The complete reports
from PES for each of these two alternatives are attached as Appendix A and B,
respectively. These two reports are summarized in the subsequent pages. A short
discussion of the proposed district-heating system is also included. The 138-kV
transmission line is discussed in detail in Section IV of this report.
This section of the report also briefly discusses several other power supply
alternatives that were previously evaluated and determined to produce more expensive
power than the Bethel coal-fired generation alternative. However, these alternatives are
included for comparison purposes and include:
• Combined-Cycle Combustion Turbine Power Plant at Crooked Creek
• Oil Fired
• Natural gas fired from a pipeline built from Cook Inlet to
Crooked Creek
• + 100-kV, DC transmission line between mine site and Nenana
• 230-kV, AC transmission line between mine site and Nenana
One additional alternative, a natural gas-fired combined-cycle plant at Crooked
Creek, using gas production from the Holitna Basin, is also briefly discussed.
Figures referenced in the subsequent discussion, if not located in the text body,
can be found at the end of each subsection. Reference drawings are attached after the
Figures.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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BETHEL COAL-FIRED POWER PLANT Section III-1.2
B. LAND-BASED COAL-FIRED PLANT
The power plant would utilize Pulverized Coal (PC) combustion technology. PC
is a proven technology that has been used in the USA in the last 40 years and is
characterized by high combustion efficiency and low-cost emission controls. Coal
pulverized in specially designed crusher/grinders is blown into the boiler’s combustion
chamber. The coal behaves like a gaseous fuel.
Both pulverized coal combustion and fluidized-bed combustion technologies
were examined. The pulverized coal combustion technology was selected as the most
appropriate for a Bethel based coal-fired plant. See Appendix A for a more thorough
comparison of these two combustion technologies.
The proposed land-based coal-fired power plant would consist of two atmospheric
pulverized coal-fired boilers each powering a 48.5 MW steam turbine, plus one 46 MW
diesel-fired simple cycle combustion turbine, for a total installed capacity of 143 MW.
The power plant would initially generate approximately 700,000 MWh annually. The two
coal-fired steam turbines would provide primary power, with the combustion turbine
providing standby/backup and peaking 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 proposed land-based coal-fired power plant facility would occupy
approximately 80 acres. Exhaust stack height is estimated at approximately 120 feet.
The coal-fired portion of the plant will consist of two separate process lines, each
including one boiler and steam turbine-generator set and ancillary equipment. Each
process line and steam turbine-generator set can, however, be operated at a maximum
output of 55 MW for moderate periods. A photograph of a modern 100 MW coal plant is
shown in Figure III-1.1.
The Power Plant will include the following primary systems:
• Coal receiving and unloading dock.
• Coal storage area including stacking and retrieving equipment, and
conveyors for delivering fuel to the boilers.
• Two pulverized coal combustors with integrated boiler, superheater,
economizer and air heater, and feedwater system.
• Two steam turbine and generator process lines including switchgear as
well as steam condensers with cooling towers and cooling water
circulating pumps.
• Air pollution control system including baghouse, SCR system, ducting and
stack.
• Simple-cycle combustion turbine with 3 million gallons of fuel oil
storage.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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BETHEL COAL-FIRED POWER PLANT Section III-1.3
• Auxiliary equipment and installations such as loaders, diesel fuel storage
tank, stand-by diesel fired combustion turbine, diesel fired boiler for start
up and auxiliary steam demand.
• Instrumentation and controls, central control room and motor control
center.
• Maintenance shop with tools.
Buildings for the power plant will be modular steel construction with appropriate
thermal insulation. The buildings will house all equipment and systems except for
cooling towers.
The buildings will also include facilities for the office personnel – locker rooms,
lunchroom, etc. The plant may also be partially housed on power barges in which case
the on-shore power plant buildings will be reduced to modular structures to house the
related needs.
1. Design Philosophy
The Bethel Coal-Fired Power Plant design philosophy is based on the following
principles:
a. Utilize modularized design to the extent reasonably possible to minimize
on-site construction cost. This includes the alternative of constructing two
power barges in a West Coast port that could be towed to Bethel.
b. Utilize a coal with a both a high Btu and low sulfur content to minimize
both operating and capital cost.
c. Construct a power plant with utility grade reliability.
d. Construct the coal-fired portion of the power plant with sufficient installed
capacity to supply the long term power and energy needs of the Calista
region. Regional generation requirements have been determined to be as
follows:
Required electric power supply at the Donlin Mine MWe 601 (Avg)
Transmission line losses MWe 5
Local usage (Bethel, villages) MWe 22
In plant usage MWe 8
Required electric power output, net at transformer MWe 97
1 Estimated at 80% of connected load.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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BETHEL COAL-FIRED POWER PLANT Section III-1.4
2. Site Location
The preferred location for Bethel Power Plant is a site approximately one mile
south of Bethel in Section 20 of Township 8 North, Range 7 West of the Seward
Meridian. The proposed site is located on private lands. Elevation of the site varies
between 50 and 100 feet mean sea level. A photograph showing the proposed location of
the facility and the associated facility dock, access roads, and potential cooling pond is
shown in Figure III-1.2. The proposed site is located approximately 1000 feet west of the
Kuskokwim River. The proposed plant site may be shifted to the east, toward the river,
by 500+ feet following detailed soil investigations. The dock will be used to offload
equipment and materials during and after plant construction and to offload annual coal
shipments. The dock will be connected with the site by a road and with the coal storage
building by a covered conveyor system. A road will also be constructed from the site to
the existing fuel dock area where it will interconnect with Bethel’s road system. Two
drawings of the site layout are attached at the end of this subsection.
The site is also close to a 78-acre pond, which could be utilized for disposal of
plant’s waste water, mainly inert blow down from the cooling towers, or it could possibly
be used as a cooling pond. The pond is located generally southwest of the proposed
facility site. Use of a cooling pond rather than forced-air cooling towers could reduce
construction costs and could also substantially reduce annual operating costs. The
determination of whether to using cooling towers or a cooling pond will be made during
the final design and permitting process.
A 3-million-gallon fuel tank will also be built at the site to store fuel oil for the
combustion turbine.
C. BARGE-MOUNTED POWER PLANT
A second option that was investigated and evaluated to reduce the high cost
associated with constructing a land-based power plant is barge mounting of the power
plant. Barge mounting the power-plant is estimated to reduce plant construction cost by
approximately $20 million. The barge-mounted coal-fired power plant alternative would
occupy two barges. Each barge is 100 feet wide by 300 feet long and has a draft of about
8 feet. Each barge would accommodate a 48.5 MW atmospheric pulverized coal-fired
power plant. One of the two barges would also accommodate a 46 MW diesel-fired
simple-cycle combustion turbine for standby/peaking generation. As with the land-based
coal plant, the total installed capacity for the barge-mounted alternative would be 143
MW. See Figure III-1.2 and attached drawings for conceptual design and site plan for
barge-mounted power plant concept.
The barges would be equipped with the intended systems, at a shipyard on the
West Coast USA or Canada and shipped on dry dock vessels to the vicinity of Security
Cove or Goodnews Bay, Alaska, from where the barges will be offloaded and towed to
Bethel.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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BETHEL COAL-FIRED POWER PLANT Section III-1.5
The 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. The barges would occupy less than 2 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.
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
towed and pushed into 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.
Currently barge-mounted power plants include combustion turbines or diesel
engines as motive power, working in simple or combined cycle. They are predominant in
areas with developing power grids and areas without access to sources of low-cost and
clean fuels such as coal and natural gas. Barge-mounting of a coal-fired power plant has
not been done yet, however, there are many examples of this being possible, for example:
steam ships, and a barge-mounted Kraft pulp plant with a recovery boiler.
The U.S. Department of Energy, National Energy Technology Laboratory
(NETL) has proposed a similar barge-mounted coal-fired power plant concept using a
circulating bed Pressurized Fluidized Bed Combustor (PFBC) Design. However, the
circulating bed PFBC design represents a relatively new technology. Only one 15 MW
unit has been built worldwide.2 Due to the substantial unknowns and uncertainties
associated with not only the technical performance of such a plant but also the cost of
constructing, operating and maintaining a circulating bed PFBC power plant, it is
recommended that circulating bed PFBC plant design not be used in this project.
1. Transporting Barges to Bethel
There are two methods for transporting barges. The first simply involves towing
the completed power plant barge from the construction/assembly port to Bethel. Barges
towed from construction/assembling port would have to be built to satisfy the Standards
and requirements for ocean navigating vessels, including US Coast Guard regulations and
other. This requirement makes the barge significantly more costly and heavier due to
strength requirements, even though the barges will only make one trip.
On the other hand, shipping barges on a "Dry Tow" vessel eliminates all of the
above requirements because the power barges are cargo. The navigability requirements of
2 Source: Donald Bonk, Department of Energy
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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BETHEL COAL-FIRED POWER PLANT Section III-1.6
the barges are reduced to those for river shipping; these requirements are significantly
less demanding than for ocean-going barges. A “Dry Tow” vessel is capable of
transporting fully loaded barges on its deck. To load the barge on the Dry Tow vessel,
the elevator deck of the Dry Tow vessel is lowered below the level of the barge bottom
and the barge or barges are positioned over the deck of the Dry Tow vessel. The deck is
then elevated to lift the barges above the water line. The reverse occurs to offload the
barge(s). A photograph of a “Dry Tow: vessel is attached as Figure III-1.7 Using this
scenario, the power plant barges would be Dry Towed from their construction/assembly
ports to the vicinity of Security Cove or Goodnews Bay where they would be offloaded
and towed to Bethel.
At present, practically all dry-dock type vessels are foreign flagged and because
of the Jones Act cannot be used for shipping between U.S. ports. From a practical
standpoint, the barges would have to be built and assembled in an overseas location,
preferably Canada. One company, Jumbo Shipping, has been looking into getting a U.S.
flagged heavy lift vessel built in the next few years. Depending on the project timeline,
this company may be able to accommodate our needs.
2. Barge Mooring
Two options for mooring the barges are being considered. In both options the
harbor canal would be trenched so the barges would be out of the main channel of the
Kuskokwim River. After the barges are towed and pushed into the canal, the inlet would
be sealed off from the main river.
The first option involves pumping out the water in the harbor channel and letting
the barges settle on the bottom of the canal. A support structure will have to be designed
so the barge is settled as deemed vital by the requirements of a steam power plant. Since
the bottom of the canal would be below the level of the river, it would be necessary to
continually operate pumps to keep the canal free of water.
The second option involves letting the barge float on the water in the canal, where
the temperature of the water in the canal would be maintained above freezing through the
year using waste heat from the plant.
The second option is attractive in that this is a steam generation plant and there is
a substantial amount of low-temperature waste heat (for instance, from steam
condensing) that can be easily utilized for maintaining the water surface free of ice and at
a constant level. Proper anchoring and stabilization of the barges would be an important
task for barge engineers. For the purpose of mounting the power plant, pre-owned (used)
barges can be procured. The structure of the barges will be enhanced appropriately to
facilitate mounting of the heavy equipment. Preferably, the construction could take place
in one of the U.S. or Canadian West Coast shipyards, such as: Shipyards on the Coast of
the Gulf of Mexico (Texas, Louisiana) have also been considered, however, barges built
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there will have to be towed through the Panama Canal, where the allowable width of <
105 ft precludes the use of dry-dock vessels with 100 foot wide barges set on top. This
adds to the significant cost of transportation.
Far East shipyards in China (specifically Shanghai, with the world known
Shanghai Boiler Works, that manufactures boilers for North American boiler makers, and
which is located at the Yangtze River waterfront) or Indonesia may also be a
consideration.
The barge sizes evaluated for this purpose are 300’ x 100’ up to 450’ x 100’.
These barge sizes are presently very popular with the barge shipping companies; as a
result, their availability on the pre-owned barge market is almost non-existent. Barge cost
is in the range of $2,250 to $2,500 per short ton of barge weight, which translates into
$7.5 to $9.5 million per barge. On the pre-owned barge market, appropriate equipment
can be purchased at $750,000 to $1,250,000 per barge; repairs, enhancing the structure
and preparation for mounting the power plant equipment will cost up to $1,500,000.
Effectively, the suitable equipment will cost between $2 million and $3 million. In the
Capital Cost estimate, the cost for two barges was assumed at $5 million each plus
$2,500,000 for dry shipping.
D. TECHNICAL DISCUSSION
1. Coal Selection, Procurement and Transportation
Fuel selection is the most important activity in the development of a new power
plant. The cost of fuel is the largest portion of the plant’s operating and maintenance cost.
The characteristics of the fuel are very important in the selection of the combustion
technology; not every fuel is suitable for the most efficient technology. For instance, high
moisture coal should not be used in pulverized coal furnaces. The fuel composition,
specifically its Sulfur, Nitrogen and Chlorine content, is very important to the selection of
emission control systems. Also, the fuel properties have a large impact on the method and
cost of storage.
a. Coal Selection
Eight coals from various mines and seams have been evaluated. The coal cost data
has been obtained in the form of budgetary quotes. The evaluated coals include:
1. Fording Coal Type A, thermal, Black Bear Mine
2. Fording Coal Type B, thermal, Coal Mountain Mine
3. Luscar Obed Mountain Mine
4. Luscar Coal Valley Mine
5. Usibelli Coal Mines
6. Quinsam Coal
7. Kennecott Energy, Spring Creek Mine
8. Kennecott Energy, Colowyo Mine
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Quinsam, Fording and Luscar are Western Canadian coal mines located in British
Columbia. The cost of shipping these coals to a sea port would therefore be lower than
that for Kennecott Energy Coal Mines, which are located on the Wyoming/Colorado
border.
The most feasible coal is the one that has the highest heating value and the lowest
sulfur content, such as the type A thermal coal from Fording’s Black Bear seam. The
sulfur content is sufficiently low so that no SO2 scrubbing is required to perform
according to applicable Alaska emissions standards.
Table III-1.1 Comparison of Selected Coals
1 Usibelli Coal Usibelli Coal
2 Type A, thermal
(Black Bear)Coal Valley Sub-bituminous, as-
mined
Sub-bituminous,
washed & dried
Estimated
Composition and
Costs
3 Heating value, net as received Btu/lb 12,284 10,800
4 HHV as received Btu/lb 10,500
5 HV MF (moisture free) Btu/lb 13,352 11,520 7,800
6 MAF (moisture and ash free) Btu/lb 10,800 10,800
7 Calculated (Dulong) HHV Btu/lb 12,264 10,843 7,168 11,124
9 Proximate Analysis
10 Total moisture 8.0% 10.0% 26.0% 12.0%
11 Ash (MF)11.9% 10.2% 9.0% 9.0%
12 Fixed carbon (air dry)65.0% 46.4% 29.0% 29.0%
13 Volatile matter (air dry)23.0% 33.2% 36.0% 36.0%
21
22 Ultimate Analysis Carbon 71.0% 63.5% 45.2% 55.3%
23 Sulphur 0.29% 0.25% 0.20% 0.24%
43 Coal demand for Bethel 92.8 MW plant including district heating
44 Net heat demand MM Btu/hr 1,041 1,041 1,041 1,041
45 Steam generation efficiency (boiler system)89.1% 86.7% 83.44% 86.20%
0.809% 86.67% 83.44% 82.63%
46 Bethel power plant heat energy demand, gross MM Btu/hr 1,168 1,200.73 1,247.20 1,207.27
47 Required fuel lb/hr 95,081 111,178 159,898 114,978
49 US tons @ 99%, reduced summer demand for DH T/Y 412,300 478,005 687,474 494,344
48 MT - metric tons @ 99%, reduced summer demand for DH MT/Y 374,000 433,600 623,700 448,500
50 Lime supply MT/Y 0 0 0
51 Coal cost
52 Cost FOB Sea-going port (MT = metric ton) $ / MT 45.00 32.00 19.00 37.90
53 Cost of lime $ / MT
54 FOB Seward, AK Seward, AK
55 Shipping to Bethel including deep sea bulk freighter, transloading at Security Cove $ / MT 12.50 12.50 12.50 12.50
56 Loading at Roberts Bank, Vancouver BC $ / MT 3.00 3.00 0.00 0.00
57 Total coal cost Security Cove $ / MT 60.50 47.50 31.50 50.40
$/US T 54.88 43.09 28.58 45.72
Lightering to Bethel by Marine Contractor $ / MT 26.00 26.00 26.00 26.00
Total shipping & barging To Bethel $ / MT 86.50 73.50 57.50 76.40
$/US T 78.64 66.82 52.27 69.45
1 Total fuel and lime cost $/year $32,421,773 $31,939,455 $35,936,118 $34,334,404
2 Unit cost at Port site (FOB deep water ship) $ / MM Btu 1.79 1.47 1.11 1.64
3 Total unit cost delivered to Bethel $ / MM Btu $3.23 $3.10 $3.36 $3.31
4 Lightering to Bethel by NUVISTA barges $ / MT $7.60 $7.60 $7.60 $7.60
Total shipping & barging To Bethel $ / MT $68.10 $55.10 $39.10 $58.00
Total cost per US Ton Nuvista Barges $/US T $61.78 $49.99 $35.47 $52.62
Total fuel and lime cost $/year $25,469,400 $23,891,360 $24,386,670 $26,013,000
Cost per MM Btu at 99% availability $ / MM Btu $2.51 $2.29 $2.25 $2.48
Shipping cost savings using Nuvista Barges $ / Year $6,952,373 $8,048,095 $11,549,448 $8,321,404
Westshore Terminals or Roberts Bank, Vancouver BC, Canada
Fording Coal Luscar
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BETHEL COAL-FIRED POWER PLANT Section III-1.9
Black Bear coal also has the lowest content of volatile matter and moisture. This
by itself significantly reduces storage and fire prevention costs. According to Westshore
Terminals, this coal can be stored without compacting or other major fire prevention
means for periods exceeding one year. Young, lignite-type coals (Usibelli coal) exhibit
inherent tendency to localized overheating and auto-ignition after short periods of time.
Table III-1.1 compares the cost and certain other properties of Fording-Black
Bear coal, Luscar-Coal Valley coal and Usibelli coal. There are two columns for Usibelli
coal. The first column is for coal as mined. The second column assumes the coal is
“dried” to reduce its moisture content and increase its BTU content from approximately
7,200 Btu/lb to 11,100 Btu/lb at an estimated cost of $0.90 per million Btu.
PES has carefully investigated the potential for using Usibelli coal rather than
Fording coal. The heating value of Usibelli coal, as mined, is 7,168 Btu/lb vs. 12,284
Btu/lb of Fording coal. In addition we must also take into the account the fact that there is
a 5.5% difference in the boiler efficiency, 89.1% for Fording coal versus 83.4% for
Usibelli coal, due to the higher moisture and oxygen content in the fuel. A power plant
operation that required 412,300 tons of Fording coal would require approximately
687,000 tons of Usibelli coal. This fact dictates a much larger (and more costly) coal
storage facilities, boilers, ducts, emission control equipment and higher expenses on
moving coal, air and combustion gases, which increases capital cost by approximately
$35,000,000. If Usibelli coal were dried, to obtain an energy content of 11,100 BTU/lb,
which would approximate the BTU content found in Luscar coal from Canada, capital
cost would increase by less than 5 million dollars.
In addition Usibelli coal, as mined, is high in moisture and oxygen content and
volatile matter. Coal with a high volatile matter, oxygen and moisture content will
naturally produce combustible gas and heat in an exothermic process when stored in
undisturbed piles for periods as short as a few weeks. This creates localized gas pockets
and hot spots within the coal pile. These hot spots are extremely prone to spontaneous
ignition, which in addition to causing a fire in the coal pile, may cause combustible gases
trapped in the small pockets within the coal pile to explode.
According to Fording, they have stored the Black Bear coal for up to two years
without detecting hot spots or auto-ignition of the coal pile. Base on comparable data of
other coals (Envirocoal from Indonesia), the Usibelli coal cannot be stored without
extensive monitoring and safety measures for a period of more than 60 days.
The Luscar-Valley coal and the dried Usibelli coal will need to be compacted to
reduce air infiltration into the pile during long term storage. However, when properly
compacted it will be possible to store these coals for a minimum period of 9 months, as
will be required at Bethel.
Use of Usibelli coal, as mined, will also increase O&M cost by approximately
$500,000 per year. This increase would be the direct result for having to handle the
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additional volume of Usibelli coal and the constant requirement to locate and uncover hot
spots within the coal pile and then re-compact the coal pile. This cost would be reduced
to roughly $270,000 per year if the coal were dried.
As a design baseline, the Black Bear coal supplied by Fording (Elk Valley Coal
Corporation) will be used. Other coals can be used but at increased capital cost.
b. Coal Demand and Storage Requirement
The coal demand of the Bethel Power Plant based on using Fording Coal Type A,
from the Black Bear Mine is as follows:
At 99% availability 412,300 short ton (ST)
374,000 metric ton (MT)
At 80% demand 333,170 ST
and 99% availability 301,700 MT
Since the navigation season on the Kukokwim River is approximately three
months, storage capacity must provide space for storing nine months worth of coal usage
or approximately 310,500 ST. The balance, approximately 101,800 ST, will be delivered
directly to the coal bunkers or used to replenish the coal in storage during periods of
waiting for incoming barges.
Coal will have to be stored in an enclosed, air-supported or modular steel
structure approximately 1400 ft. x 300 ft. x 130 ft. in height. This is a requirement
resulting from continuous winds that blow in the Bethel area and the desire to keep the
coal pile free of moisture. The average annual wind speed in Bethel is 12.7 mph. A wind
rose for the Bethel area is shown in Figure III-1.3. A wind rose displays the percentage
of time the wind blows from a given direction with a given velocity. With uncovered
outdoor storage, the winds will pick up coal dust. The estimated amount of dust that
could be blown away from an uncovered coal pile is up to 5%, especially during stacking
and reclaiming operations. At eight percent demand, this represents a loss of 17,000 ST
or an estimated $1,180,000. The cost of a cover structure, estimated at $7.5 million, will
pay for itself, in coal savings, in less than seven years. Equally as important, a covered
storage will prevent coal dust from entering and polluting the air-shed. A photograph of
an air-supported structure is shown in Figure III-1.4.
c. Shipping Coal to Bethel
i. Ocean Transportation
Two options of shipping coal from Canada to Bethel were considered. These
are shipping coal in barges or shipping coal in larger ocean going freighters:
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BETHEL COAL-FIRED POWER PLANT Section III-1.11
Barge Shipping - Barges would be loaded at Vancouver Port, Roberts Bank,
or Westshore Terminal, and towed directly to Bethel. After a brief evaluation of
this option, it was decided not to proceed with further research for barge shipping
as it became apparent, at a very early stage, that this approach would result in the
highest shipping costs, estimated at $42.50 per ton.
Deep-Sea Bulk Freighters For ocean shipping from the coal ports near
Vancouver, BC, Canada it is recommended to employ 35,000 DWT bulk
freighters with continuous unloading capabilities. This type of ship will be able to
transport 30,000 tons of coal. Five thousand DWT is dedicated to the weight of
the ship’s own personnel and supplies, fuel, food and other items. The freighters
would travel to Security Cove or Goodnews Bay. See Figure III-1.5. Security
Cove and/or Goodnews Bay were chosen as the transloading point because waters
of the Kuskokwim Bay and the mouth of the Kuskokwim River are too shallow
for deep water freighters to enter. Either of these two bays should provide
reasonable protection from rough seas.
Goodnews Bay is approximately 25 miles closer to Bethel and would be the
preferred transloading point. At this transload point the coal will be off-loaded
from the freighters into barges and towed to Bethel. The distance from Goodnews
Bay to Bethel is approximately 135 miles.
The cost of shipping from Vancouver, BC to Security Cove or Goodnew Bay
was determined to be in the range of $12.50 per ton. The cost for shipping
Usibelli coal from Seward to Bethel via freighter is also estimated to be in this
range.
ii. Lightering by Specialized Marine Contractors
Two options for transporting coal from Security Cove or Goodnews Bay to
Bethel to barge have been evaluated as discussed below.
Under this option Nuvista would contract with an existing barge company to
lighter the coal from Security Cove and/or Goodnews Bay to Bethel. Lightering
costs for this option are estimated in the range of $23-24 per ton. The following
companies are capable of providing the lightering services.
Seabulk Systems, Inc.
Crowley Maritime Corporation
Bering Marine Corporation, a Division of Lynden Incorporated
Northland Services, Inc.
Foss Maritime Company
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iii. Lightering by Nuvista Light & Power
There are significant questions regarding the accuracy and reliability of the
quotes provided by the marine contractors for lightering the coal. Therefore, a
second option for lightering coal was investigated. The second option is for
Nuvista or a subsidiary of Nuvista to lighter the coal from Security Cove or
Goodnews Bay to Bethel. Nuvista would purchase 3 (three) pre-owned barges
with 10,000 to 12,000 DWT capacity, maximum draft 12.5 feet, and one pre-
owned tug boat with a 3000 to 4000 hp engine. The Nuvista transport option
results in significant savings. Lightering costs are calculated at approximately
$6.90 per ton using this approach.
2. Coal Unloading Equipment
Once the loaded barges arrive at Bethel the coal must be unloaded. Three options
were examined for unloading the coal.
Self-unloading barges – barges that are equipped with unloading equipment. Coal
is stowed in large hoppers that discharge onto a conveyor at the bottom of the barge. The
conveyor delivers the coal to an elevator (bucket or two-belt conveyor), which discharges
the coal to a transporter delivering the coal to a place on the shore most often being a
hopper for a subsequent conveyor. This would be the most expensive of the three options
as the unloading equipment would be built into each barge. This would increase the
weight of each barge and reduce the tonnage that it could carry.
Crane un-loaders - are usually simple and the initial cost is most likely the
lowest; however they are relatively slow. Crane unloading rate is in the range of up to
500 ton/hr. Evaluation of the system has lead us to conclude that the minimum unloading
rate should not be lower than 1,500 tons/hr. The equipment cost of cranes for an
application of this size is very close to that of a continuous unloader.
Continuous barge unloader – A barge unloading system suitable for the
application at Bethel would be similar to the Hely-Patterson unloader shown in Figure
III-1.6 except the unloader would be mounted on a catamaran rather than installed in a
fixed position. It will be capable of off-loading 2,000 TPH. The catamaran and unloader
combination will be towed into position by a tug each spring and secured to the dock and
each fall it will be towed to a slough for winter storage.
Although slightly more expensive than cranes, continuous unloaders have many
advantages. They are much faster than other unloading methods; continuous un-loaders
will be able to sustain an unloading rate of 2,000 TPH. Continuous un-loaders require
only 1-2 operators to run, thereby reducing manpower costs compared to other unloading
methods. Currently the cost of a catamaran mounted un-loader is in the range of 5-7
million dollars.
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BETHEL COAL-FIRED POWER PLANT Section III-1.13
3. Coal Storage
The delivery conveyor from the continuous unloader discharges into a receiving
hopper and onto the main coal conveyor to the coal storage yard. For this task a covered
belt conveyor 60” wide by the appropriate length will be used. The belt will deliver the
coal to the storage yard via a stacking system.
The bucket-wheel stacker/reclaimer can reclaim coal from both packed and un-
compacted piles; however, being two-in-one systems, it can not stack and simultaneously
reclaim. During the shipping season when it will be stacking coal, a portion of the coal
flow from the barge unloader will bypass the stacker and be conveyed directly to the coal
bunkers for feeding the boilers.
Also, as indicated earlier, coal will have to be stored in a covered facility,
primarily to prevent coal fines from being blown and lost due to high winds blowing
continuously in the area. Covering of the coal pile will also protect coal from
deterioration under the influence of the elements and prevent weathering and absorption
of moisture from precipitation. This should eliminate coal-pile runoff and the need for a
sophisticated and expensive water drainage, collection and disposal system.
Four options were investigated to house coal. These are Pre-Fabricated Steel
Building, Air Supported Structures, Concrete Domes and Aluminum Frame Domes.
Most likely either a pre-fabricated steel building or an air supported structure will be used
to house the coal. Selection of the most appropriate building will be made during final
design phase.
From the storage building, the coal will be reclaimed and delivered to two
bunkers per each boiler via a system with dual conveyors, one conveyor will be stand-by.
The conveyors will deliver coal to the bunkers via grizzlies, which will serve as a backup
system for filling the bunkers in case of a reclaimer breakdown. There will also be
auxiliary feed hoppers that can be used in the event the stacking and reclaiming system is
down for maintenance. For this purpose, the plant will be equipped with CAT 980G or
comparable front-end loaders.
4. Fire Prevention and Coal Dust Control
The coal storage building will also include a fire prevention and suppression
system. The most important issue in fire/explosion prevention is controlling coal dust.
For this purpose, a detailed procedure will be developed. Prevention of coal dust
explosions and fire will be the most important safety precaution undertaken in the Bethel
Coal-Fired Power Plant, therefore, the coal storage and handling system will include
several dust control methods and equipment.
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BETHEL COAL-FIRED POWER PLANT Section III-1.14
5. Description of Power Plant Facilities
a. General Description
The proposed land-based coal-fired power plant would consist of two atmospheric
pulverized coal-fired boilers each powering a 48.5 MW steam turbine, plus one 46 MW
diesel-fired simple cycle combustion turbine, for a total installed capacity of 143 MW.
The power plant will include two pulverized coal combustors with boilers and auxiliary
equipment (superheater, economizer, air heater; fans and blowers for combustion air, flue
gas induced draft, and feedwater system). The superheated steam generation and steam
turbine system works in simple Rankine cycle without or with reheat. The two coal-fired
steam turbines would provide primary power, with the combustion turbine providing
standby/backup and peaking generation.
The coal-fired portion of the plant will consist of two separate process lines, each
including one boiler and steam turbine-generator set and ancillary equipment. Each
process line and steam turbine-generator set can, however, be operated at a maximum
output of 55 MW for moderate periods.
Under normal operating conditions the steam turbines will provide the required
output. If one steam turbine is offline, the remaining steam turbine can be operated at its
maximum output of 55 MW and the simple-cycle turbine will be placed on-line to supply
the additional output.
b. Generation Efficiency
Using standard off-the-shelf components in the plant, as described in this section,
is calculated to operate at a 31 percent overall thermal efficiency. A kWh of electricity is
equivalent to 3,412 Btu. For every kWh of electricity generated, 11,006 Btu of fuel,
which equates to approximately 0.9 lbs of Black Bear coal, must be consumed. However,
there are many improvements that can be integrated into the final plant design that will
increase the plant’s overall thermal efficiency to the range of 35-36 percent, with only a
deminimus increase in capital costs. These include installing boilers that operate at higher
pressures, using a second reheat stage and installing variable speed drives. Efficiency in
the range of 40 percent can be achieved using supercritical steam systems. Increasing
efficiency is one of the less expensive ways of reducing pollution emissions. Appropriate
equipment will be selected during the actual design process to maximize thermal
efficiency. The effects of thermal efficiency on power costs will be examined in Section
IX. Generation efficiency of the simple-cycle turbine will be in the range of 35 percent.
c. Make-up Water Source, Treatment, Filtering and Blow-Down
Disposal
Total make-up water requirement is estimated at 1,475 gpm. The plant will
include a boiler make-up water treatment system, which will include at a minimum, a
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dual ion bed system. The possible sources of make-up water for the Bethel power plant
include:
Drilling of water wells. This option may provide water that is low in impurities
and would likely require the least treatment.
The second option is drawing water from the Kuskokwim River. This option
could prove to be more difficult than drilling wells. Due to the large percentage of
suspended and dissolved solids in the river water the cost of treating this water will be
substantial.
The third option is drawing water from a natural or artificial (built) cooling pond.
This option will experience problems similar to drawing water from the Kuskokwim
River. Unless the pond is sufficiently deep, water in the pond may freeze over during
winter and require thawing. Also, excavation of a sufficiently large pond may be
significantly more expensive that drilling a water well or upgrading the quality of the
Kuskokwim River water.
Water supply may also be a combination of two methods; for instance drawing
boiler make up water from a well and obtaining cooling tower make up water from the
cooling pond.
Geotechnical and hydrological investigations will have to be conducted to
determine related items, such as water availability and required treatment.
d. Steam Turbine and Generator System
As with the boilers, two trains of Steam Turbine and Generator systems will be
included in the Power Plant; each train will consist of:
Turbine 1, HP16 – high speed, high efficiency turbine
Turbine 2, LP190 – synchronous speed turbine receiving lower
pressure steam from the HP turbine.
Complete stand-alone digital control system
Cooling Tower System - one per train; fiberglass structure,
stainless steel connecting hardware, heavy duty PVC film pack fill,
fans, fire-retardant, FRP fan cylinders for velocity recovery, etc.
As an alternative to the cooling tower system, the use of once-through condenser
cooling should be considered, in which the water will be taken from the pond located
south of the plant site in Bethel. This option will be evaluated in the environmental
impact study.
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e. Environmental Control System
The Bethel Coal-fired Power Plant will be built to satisfy stringent ADEC air and
water quality standards. With today’s technology coal-fired power plants can provide
inexpensive and environmentally friendly electric power. Table III-1.2 lists ADEC
standards along with the expected performance of the coal power plant.
TABLE III-1.2 ADEC Performance Standards
Alaska State Standard Expected
Performance
Comments
Sulfur dioxide SO2 500 ppm dry volume less than 250
ppmdv
To achieve this performance the
plant will need to use Fording’s
Black Bear coal with a sulfur
content of 0.29% or an equivalent
coal.
Sulfuric Acid To prevent precipitation of sulfuric
acid the minimum flue gas exhaust
temperature will be limited to
272oF.
Particulate matter
PM
0.05 gr/dscf 0.05 gr/dscf To achieve this performance the
plant will include a cyclonic type
collector (single cyclone or multi-
cyclone) and a baghouse (filter)
type collector.
Opacity
20% for less than 3
minutes in 1 hour.
20% for less than 3
minutes in 1 hour.
To reduce opacite excursions the
boilers will include acoustic
cleaning systems working
continuously instead of soot
blowers, which cause excursions
during soot blowing operations.
CO None 0.10 lb/million Btu
fired = 118 ppmdv
NOx
None 0.30 lb/million Btu
fired = 215 ppmdv
CO reduction is achieved by boiler chamber design that will provide a minimum
of 0.5 seconds residence time for the combustion gases before entering the water-walled
section. The longer the residence time the better probability of CO reacting with oxygen
and or using catalytic converter for afterburning CO to CO2.
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For NOx reduction, flue gas recirculation can be used, which reduces the amount
of free ionized oxygen in the flame zone, thereby reducing the amount of oxygen
available for reaction with nitrogen. Selective catalytic or non-catalytic reduction (SCR
or SNCR) could also be used to substantially reduce NOx and CO.
1. Effluent Discharge
The continuous liquid discharges (effluents) from the plant are:
Boiler blow-down water
Cooling tower blow-down water
Ion exchange regeneration waste water
Sanitary (sewage) water
The intermittent discharge wastewater includes:
Boiler and condenser chemical cleaning solvents
Boiler fire-side wash water
Boiler blow-down, cooling tower blow-down water and ion exchange
regeneration waste water are neutralized with chemicals and deposited in a settling pond.
Neutralization results in large quantities of precipitating solids, which settle in the settling
pond. Water from the pond can be reused in the cooling tower system or can be disposed
of to a local waterway – Kuskokwim River or a nearby pond.
The settling pond solids will be periodically removed and deposited locally in a
landfill or quarry. The solids are neutral and do not require disposal in a sanitary landfill.
2. Solid waste and Sewage Sludge disposal
One of the power plant boilers will include a capability to feed and burn local
municipal solid waste (MSW) and partially dried sewage sludge excavated from a drying
lagoon. The plants Emission Control System will be capable of handling the extremely
small additional load, which is in the range of 0.11% of the weight fuel input or 0.03% of
the thermal input.
To facilitate this feature the plant will need to be equipped with:
• MSW and sludge receiving station,
• Sorting station to remove tramp metals, rocks and non-combustible demolition
waste (concrete pieces)
• Shredder
• Pneumatic system for conveying and injecting the refuse derived fuel into the
furnace.
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The Power Plant’s solid waste includes ash from coal combustion and general
human-generated garbage (municipal solid waste: trash, locker and lunch room waste). If
the plant is equipped to burn municipal waste and sludge, it can consume most of the
solid waste generated at the plant. If the plant is not equipped to burn waste and sludge,
the general waste produced by the plant shall be collected and disposed of by the City of
Bethel Sanitary Services.
Sanitary water includes only effluent from facilities for the personnel at the power
plant. It is recommended that sanitary water disposal is contracted to the sanitary services
of the City of Bethel.
3. Ash Handling and Utilization System
The Black Bear coal to be utilized in the Power Plant contains on average 11%
ash. The content of silica (SiO2) and alumina (AI2O3) in this ash is high; as a result of
this, the ash is suitable for the production of concrete aggregate that can be used as a
substitute for gravel.
The above ash composition is of good quality for utilization both as cement
substitute and as filler material. The ash production is estimated at 36,000 tons annually.
The ash can be mixed with Portland cement and water to produce an aggregate with
characteristics similar to small gravel. It is estimated that approximately 60,000 tons
(40,000 cubic yards) of concrete aggregate can be produced annually from the ash
generated by the plant. In order to increase to volume of the aggregate, some local sand
and gravel could be used to reduce the percentage of this highly cementaceous ash. The
specific formula for aggregate production will be determined at a cement laboratory
based on physical tests.
The system will include:
Pneumatic ash collection system extracting fly ash from various
points on the boiler, economizer, baghouse and other. The system
will include appropriate low pressure rotary blowers equipped with
intake filter/silencer and exhaust mufflers.
Ash silo capable of holding eight-month supply of ash.
Portland cement silo with holding capacity for 3,700 tons.
Agglomerating machine that will produce the aggregate.
Aggregate storage.
The aggregate can be produced from ash coming straight from the collection system or
from the silo. It is proposed to produce the aggregate seasonally for direct usage locally.
f. Standby Turbine System and Diesel Fired Boiler
One 46+ MW diesel fired combustion turbine, such as an Alstom GTX100 or a
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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BETHEL COAL-FIRED POWER PLANT Section III-1.19
GE LM6000, will provide stand-by and peaking capacity. The system will be activated in
case of outage or routine maintenance of one of the steam powered generation process
lines, boilers or steam turbine generators or for peaking. As a stand-by/peaking system,
the combustion turbine will not include a heat recovery steam generator. The combustion
turbine start-up time could be as short as 2 minutes.
A diesel-fired boiler will be installed to provide for start up and auxiliary steam
demand, including district heating steam during outage of one boiler. Steam produced by
the stand-by boiler will be used at plant start-up for steam blows (cleaning of steam
lines), turbine trials and district heating system start-up.
g. Instrumentation and Controls, Central Control Room and Motor
Control Center
The Power Plant will be equipped with all instrumentation and controls
necessary for trouble-free operation of the Plant. The central control room (CCR) will
include operator stations with color monitors, keyboards, track balls and event and alarm
printers. The CCR will also house the output and monitoring devices of the steam turbine
power generating system.
h. Fire Protection System
The fire protection systems will include redundant water pumps including a diesel
engine-driven unit. The 100,000-gallon raw water storage tank will serve as a source of
fire-fighting water. As an alternative, water from the cooling pond or make-up water well
will be used. Appropriate detection and alarms will be included in strategic locations and
system actuation will be automatic when and where necessary. For the main electric
systems, automatic extinguishers will be used.
i. Maintenance Shop
Due to the limited capabilities for local fabrication and repair, the plant will have
to include a reasonably sized and well-equipped maintenance facility. This facility will be
able to service both basic plant equipment and the rolling stock on the premises.
It is planned that the maintenance facility will be housed in a land-based building
with an area of 100’ x 240’. Housing a portion of the shop on the power barges should
also be considered. The facility will include appropriate equipment and tools.
In addition to the above shop, a rolling stock garage is planned and will be
equipped with the necessary equipment to maintain the rolling stock.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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BETHEL COAL-FIRED POWER PLANT Section III-1.20
E. REDUCED GENERATION OPTION
Under this option a plant with only 80 + MW of coal-fired capacity would be
built. This option was developed to explore the economics of an 80 + MW plant as
compared to the 100 + MW plant. The economic comparison of the two plants is
discussed in Section IX. The plant would consist of two atmospheric pulverized coal-
fired boilers each powering a 40 MW steam turbine, a 46 MW diesel-fired simple-cycle
combustion turbine, plus this option would rely on the existing Bethel diesel plant for 10
MW of diesel generation, for a total installed capacity of 136 MW. In all other respects it
would be identical to the coal-fired plant described above. The cost of this reduced
capacity plant would be approximately $18 million dollars less than the 100 + MW land-
based plant and $13 million less than a 100 + MW barge mounted plant. Power demand
would be as follows:
Net, at the Donlin Mine MW 60.0
Available to Bethel & villages MW 8.0
Transmission losses MW 5.0
Plant parasitic power MW 7.0
Total power demand MW 80.0
Subtracting parasitic power used in-plant and line losses, the net available power
is 68 MW. The estimated combined demand, in the year 2010, for the mine, Bethel and
the villages is 70 MW. To make up the 2 MW generation deficit, the coal-fired plant can
be operated at slightly in excess of its nominal output rating of 80 MW. However, as the
load continues to increase it will be necessary to operate the existing Bethel diesel plant.
F. RELIABILITY
The 100 + MW coal fired power plant will be designed to operate with a
reliability consistent with a utility grade power plant. Total installed plant capacity will
be 143 MW. There will be two independent process lines, each including one boiler and
steam turbine-generator set. Each steam turbine-generator set will have a rated design
output of 48.5 MW, for a total output of 97 MW under normal operating conditions.
Each process line and steam turbine-generator set can, however, be operated at a
maximum output of 55 MW for moderate periods of time. One simple-cycle 46 MW
“standby” combustion turbine will provide hot standby and peaking power and can be
placed on-line in less than two minutes. A reliability analysis performed by PES has
determined the availability of the plant to generate at least 100 MW of power at 99
percent, which means the plant will be unavailable to serve the load for 1% of the time.
On an annual basis a 1% unavailability rate equates to a period of 87.6 hours per year or
3.7 days per year.
Bettine, LLC conducted an independent reliability analysis to determine the
number of hours per year the plant could not adequately serve the mine demand and the
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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BETHEL COAL-FIRED POWER PLANT Section III-1.21
total system demand. The results of this analysis are shown in Table III-3. This basic
reliability analysis assumes a forced outage rate of 5% for each of the steam turbines and
their respective process line, and a forced outage rate of 2% for the combustion turbine.
These are typical forced outage or unavailability rates for well maintained plants. Two
alternatives are investigated. The 100 + MW “Base-Case” option assumes 97 MW of
coal-fired generation capacity plus a 46 MW standby/peaking combustion turbine. The
80+ MW “Reduced-Generation” option assumes 80 MW of coal-fired generation
capacity, a 46 MW standby/peaking combustion turbine and relies on the existing Bethel
diesel plant for 10 MW of diesel generation. The analysis also assumes that during forced
outage conditions, the steam turbines in the Base-Case option can be operated at a
maximum rated output of 55 MW and in the Reduced-Generation option at a maximum
rated output of 45 MW. A modified binomial distribution model was used to calculate
the number of hours per year the plant would be unable to generate a specified MW
output. The results of the analysis are listed in the Loss of Load Expectation (LOLE)
table, designated as Table III-1.3. LOLE is the number of hours per year the power
system cannot serve the expected system demand. Supporting calculations can be found
in Appendix H.
Also included in the table is the estimated forced outage time associated with the
190 mile transmission line. This estimate is based on data obtained from Chugach
Electric Association. Chugach experiences on average about six outages a year on the
three transmission lines, totaling 150 line-miles, that extend between its Beluga power
plant and the Teeland substation located just south of Wasilla.3 This line section is
considered representative of the terrain conditions along the route of the Donlin Creek
transmission line. Most of these outages are of short duration, 30 minutes of less, and are
the result of birds contacting the center phase conductor, which is located within the
upper basket of the X-tower formed by the cross-arm and angled upper leg assemblies.
Assuming 30 minutes per outage this equates to 6 hours of outage annually for 150 line-
miles. For 190 mile transmission line the proportional number of hours would be 7.6
hours or say 8 hours annually.
TABLE III-1.3
LOSS OF LOAD EXPECTATION IN HOURS PER YEAR
Total
System
Demand4
100+ MW Base-
Case Option
T-Line
Total
80+ MW
Reduced Gen.
Option
T-Line
Total
50 MW 39 8 47 9 8 17
100 MW 109 8 117 125 8 133
A review of Table III-1.3 reveals that both the Reduced Generation and for the
Base-Case alternative can reliably supply a 50 MW system-demand. LOLE is in the
range of 1 to 2 days per year. At 100 MW system-demand the calculated LOLE for the
3 Source: Dora Gropp, Transmission Dept., Chugach Electric Association.
4 Includes line losses and in-plant usage.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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BETHEL COAL-FIRED POWER PLANT Section III-1.22
Reduced Generation Case is 133 hours per year. For the Base-Case Alternative, the
LOLE for 100 MW system-demand is 117 hours with the transmission line and 109 hours
without the transmission line. This equates to an unavailability rate of 1.2% per year as
compared to 1.0 percent by PES. Differing methodologies used by PES and Bettine, LLC
to predict LOLE has produced these slightly different results.
The above LOLE are representative of the two generation options. A more in-
depth reliability analysis will need to be conducted as the project moves from the
feasibility stage toward the final design phase. As with any plant design, an acceptable
compromise between reliability and capital cost will need to be achieved. However, until
the Donlin Creek mine power requirements are better defined, it is pointless to refine the
analysis.
FIGURE III-1.1
Proposed Location of
Land-Based Coal
Fired Plant Alternative
80 Acres
Combustion Turbine
Alternative 40 Acres
Proposed Cooling Pond
78 Surface Acres
Barge Unloading
Station and Dock
Proposed Road
Proposed Location of
Coal Storage for Barge-
Mounted Coal Plant
Proposed Location of
Barge-Mounted Coal Plant
Proposed Road
Figure III-1.2- Aerial Photo of Bethel and Vicinity
Showing Proposed Bethel Power Plant Locations
NORTH.Kuskokwi
m Ri
ver
Fl
ow
Figure III-1.3
Bethel Wind Rose
Figure III-1.4 - Photo of an Existing Air-Supported Coal Storage Structure
FIGURE III-1.5
Location Map – Goodnews Bay and Security Cove
Goodnews Bay
Security Cove
Kuskokwim River
FIGURE III-1.6
Hely –Patterson Barge Unloader
FIGURE III-1.7
Dry Tow Vessel
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.1
SECTION III-2
2. COMBINED-CYCLE COMBUSTION TURBINE PLANT
A. LAND-BASED MODULAR PLANT
The study evaluates two sites for the location of the Power Plant, one at
Bethel and one at Crooked Creek. Two technologies for power generation are
assessed. These are 1) generation of power by combined-cycle combustion turbine,
and 2) power generation by diesel engines. The power plant will be modularized to
the highest possible degree, such that it can be shipped in major assemblies
minimizing field installation work. Figures referenced in the subsequent discussions,
if not located in the text body, can be found at the end of each subsection.
Referenced drawing s are attached after the Figures.
1. Bethel Combined-Cycle Plant
The Modular Power Plant (MPP) at Bet hel or Crooked Creek will consist of a
combined-cycle combustion turbine plant , equipped with three simple-cycle
combustion turbines plus a heat recovery boiler and steam turbine generator. The use
of low–speed diesel generation was examined as part of this study, but this alternative
was rejected in favor of combustion turbines for reasons subsequent ly discussed. The
Power Plant will use a modular design, to the extent practicable, to reduce on-site
construction costs, minimize construction time and facilitate handling and
transporting of major equipment. The complete report from PES for Modular Plant
Alternative is attached as Appendix B. A photograph of a modern combined-cycle
combustion turbine plant is shown in Figure III-2.1.
The power plant would burn #2 diesel fuel or possibly propane. The economic
impact of firing the plant with diesel fuel oil versus propane will be examined in
Section IX. Installed generation capacity at Bethel is 150+2 MW depending whether
Alstrom or GE turbines are selected. At Crooked Creek the plant capacity, will be 110
MW. The Bethel Plant plant will generate approximately 650,000 MWh annually, the
Crooked Creek plant 550,000 MWh annually. The Bethel plant would consume
approximately 32 million gallons of diesel fuel or 50 million gallons of propane
annually. The Crooked Creek plant would consume 31 million gallons of fuel oil or
47 million gallons of propane. The large amount of fuel needed to fire the combustion
turbine plant would be delivered by barge to the facility dock and pumped to the
facility above-ground diesel storage tanks via an above-ground 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. Annual fuel storage requirements at Bethel are 25 million
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.2
gallons of diesel fuel or 38 million gallons of propane. Annual fuel storage
requirements at Bethel and Crooked Creek are essentially the same. Fuel oil would
be st ored in eight, 3.1 million gallon tanks. Propane will be stored in three 13 million
gallon tanks.
The Power Plant will include the following primary systems:
• Fuel oil receiving and unloading dock.
• 25 million gallon fuel oil storage tank farm or 39 million gallons of
propane storage.
• Three simple-cycle turbines, one heat recovery steam generator and
one steam turbine, with switchgear, steam condensers with cooling
towers and cooling water circulating pumps.
• Air pollution control system including SCR system, ducting and stack
as required.
• Auxiliary equipment.
• Instrumentation and controls, central control room and motor control
center.
• Maintenance shop with tools.
Buildings for the power plant will be modular steel construction with
appropriate thermal insulation. The buildings will house all equipment and systems
except the cooling towers. The buildings will also include facilities for the office
personnel – locker rooms, lunchroom, etc. The plant may also be partially housed on
power barges, in which case, the on-shore power plant buildings will be reduced to
modular structures to house the related needs.
a. Design Philosophy
The Bethel Power Plant design philosophy is based on the following
principles:
1. Utilize modular design to the extent reasonably possible to minimize on-
site construction cost.
2. Construct a power plant with utility grade reliability.
3. Construct the power plant with sufficient installed capacity to supply the
long term power and energy needs of the Calista region. The region’s
generation demand with the Donlin Creek mine was determined to be
as follows:
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.3
Required electric power supply at the Donlin Mine MWe 601
(Avg)
Transmission line losses MWe 5
Local usage (Bethel, villages) MWe 22
In plant usage MWe 3
Required electric power output, net at transformer MWe 92
a. If the plant is constructed at Crooked Creek to serve only the mine load,
the demand is as follows:
Required electric power supply at the Donlin Mine MWe 60
(Avg)
Transmission line losses MWe 0.5
Local usage Crooked Creek MWe 0.5
In-plant usage MWe 3
Required electric power output, net at transformer MWe 64
b. Site Location
The preferred location for the Bethel Power Plant is a site approximately one
mile south of Bethel in Section 20 of Township 8 North, Range 7 West of the Seward
Meridian. The proposed site is located on private lands. Elevation of the site varies
between 50 and 100 feet mean sea level. A photograph showing the proposed location
of the facility and the associated facility dock, access roads, and potential cooling
pond is shown in Figure III-1.2. The proposed site is located approximately 1,000 feet
west of the Kuskokwim River. The proposed plant site may be shifted to the east,
toward the river, by 500+ feet following detailed soil investigations. The dock will be
used to offload equipment and materials during and after plant construction and to
offload annual fuel shipments. The dock will be connected with the site by a road and
with a 25 million gallon fuel oil tank farm or a 39 million gallon propane tank farm
by a fuel pipeline that will be elevated 2 feet above the ground. A road will also be
constructed from the site to the existing fuel dock area where it will interconnect with
Bethel’s road system. Two drawings of the site layout are attached at the end of this
subsection.
The site is also close to a 78-acre pond, which could be utilized for disposal of
plant’s waste water, mainly inert blow down from the cooling towers, or it could
possibly be used as a cooling pond. The pond is located generally southwest of the
proposed facility site. Use of a cooling pond rather than forced-air cooling towers
could reduce construction costs and could also substantially reduce annual operating
1 Estimated at 80% of connected load.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.4
costs. The determination of whether to use cooling towers or a cooling pond will be
made during the final design and permitting process.
An alternative location for the plant is Crooked Creek, AK, about 150 miles
up river from Bethel. There are no reliable ground condition data; therefore a full
geotechnical study of the ground conditions will be required. However, an onsite
examination of the borrow pit located at Crooked Creek indicates the soils consist of
fractured rock, sands and silts. Based on these examinations it is expected that the soil
conditions at Crooked Creek will be substantially improved over those at Bethel.
B. BARGE-MOUNTED POWER PLANT
A second option that has been investigated and evaluated to reduce the high
cost associated with constructing a land-based power plant is barge mounting of the
power plant. Barge mounted combustion turbine power plants are common. A barge-
mounted power plant is suitable for Bethel, but not Crooked Creek. Barge mounting
the power-plant is estimated to reduce plant construction cost by approximately $11
million. The barge-mounted power plant alternative would occupy one barge 100
feet wide by 350 feet long. The estimated cost for a refurbished barge of this size is
$4.5 million. As with the land-based turbine plant, the total installed capacity for the
barge-mounted alternative would be 150 MW. The barge mounted turbine plant
would be sited in the same location as the barge-mounted coal plant shown in Figure
III-1.2.
The barge would be equipped with the intended systems at a shipyard on the
West Coast USA or Canada, and shipped on dry dock vessels to the vicinity of
Security Cove or Goodnews Bay, Alaska. At this location the barges will offloaded
and towed to Bethel. It may be possible to install the cooling towers on the barge(s).
This decision will be made during the engineering design phase.
Fuel storage 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 power plant
alternative, including the blowdown pond and the electrical switchyard, would also be
located in this area, which would occupy approximately 80 acres. The barges would
occupy less than 1 acre.
As with the barge-mounted coal plant, the barge 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 barge is towed and pushed into 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
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.5
supplies. The barges would be located in the floodplain of the river at a location
where there is little elevation difference between the bank and the river.
The barge would be transported to Security Cove or Goodnews Bay by a Dry Tow
Vessel. 1, off-load and then towed to Bethel, in the same manner as described in
Section III-1 for the barge mounted coal plant. Barge mooring options would be the
same as for the barge mounted coal plant.
C. TECHNICAL DISCUSSION
1. Fuel Selection, Procurement and Transportation
Fuel selection is the most important activity in the development of a new
power plant. The cost of fuel is the largest portion of the plant’s operating and
maintenance cost. The characteristics of the fuel are very important in the selection of
the combustion technology; not every fuel is suitable for the most efficient
technology. The fuel composition, specifically its sulfur content, is very important to
the selection of emission control systems.
TABLE III-2.1 Fuel Costs (Prices as of Jan 30th, 2003)
Fuel cost per MM Btu gross
All Btu/lb or gallon values are
NET
Btu/lb
Btu/gal
LHV
lb / gal $ / gal
at refinery
$/MM Btu
excl.
shipping
$ / gal incl
shipping to
Bethel
$/MM Btu
in Bethel
$ / gal incl.
shipping to
CC
$/MM Btu
including
shipping to
CC
Diesel Fuel No. 2 (TESORO) 18,421
130,236 7.07 0.85 6.53 1.04 7.99 1.25 9.60
Diesel Fuel No. 1 gross 18,561
125,101 6.74 0.90 7.19 1.09 8.71 1.30 10.39
Pour 40 Heating Oil (DF1 75%,
DF2 25%)
18,461
126,679 6.86 0.87 6.87 1.06 8.37 1.27 10.03
Jet B 17,931
112,929 6.30 0.88 7.79 1.07 9.47 1.28 11.33
# 2 DIESEL FUEL (WILLIAMS
ALASKA)
18,380
131,399 7.15 0.87 6.58 1.06 8.03 1.265 9.63
JP-4 17,973
113,194 6.30 0.87 7.69 1.06 9.36 1.27 11.22
Naphtha 19,743
120,277 6.09 0.82 6.82 1.01 8.40 1.22 10.14
Heating fuel Product Nr. 43 18,194
126,630 6.96 0.86 6.79 1.05 8.29 1.26 9.95
Propane 20,238
85,000 4.20 .50 .10 .65 7.65 .80 9.41
a. Comparison of Various Fuels
Table III-2.1 summarizes the evaluation of various applicable fuels for the
MPP. All of the listed fuels can be used for firing combustion turbines. All fuels
except Naphtha can be used to fire diesel engines. The list was put together as a result
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.6
of evaluating various fuels. Some fuels with prices significantly above the indicated
range were not included.
Other fuels that could be used have not been included due to their low
availability and/or high cost. For example fuel oil No. 4 could be a better fuel than
DF2, however, its availability in Western Alaska is low, therefore, it is more
expensive, expressed in $/MM Btu than DF2 .
The evaluation presented in Table III-2.1 is reduced to the common
denominator of delivered cost per million Btu for each fuel.
As indicated in Table III-2.1, Diesel Fuel No. 2, Fuel Oil No. 2 and propane
are the most feasible fuels. In addition to excellent combustion properties (heating
value, density, flash point), these fuels have good transport properties (low visco sity).
The sulfur content of the diesel fuels is limited to 0.5%; however, the sulfur content
of the Tesoro DF2 is typically in the range of 0.1%. The low percentage of sulfur
results in low SO2 concentration in the flue gas; thus, expensive flue gas
desulfurization systems (FGD) are not needed. Emissions that are significantly below
standard can be used as environmental credits to offset other pollution sources of the
company or to trade with other companies. Propane will produce the lowest emissions
of any of the fuels listed in the table.
b. Fuel Shipping
1. Fuel Oil
Transporting the fuel oil from Cook Inlet or West Coast USA/Canada to
Bethel or Crooked Creek requires the following steps: (1) linehaul barge
transportation from the supply source across open ocean and up the Kuskokwim
River to Bethel, (2) off-load and temporary storage at Bethel, and (3) transfer of fuel
to smaller river barges and delivery to Crooked Creek. The shallow nature of the
Kuskokwim River above Aniak (between Bethel and Crooked Creek) provides the
greatest challenge, both physically and financially, to delivering fuel to Crooked
Creek. The cost estimate for delivering 32,000,000 gallons of fuel to Crooked Creek,
using specialized shallow-draft tugs and barges between Bethel and Crooked Creek is
approximately $12,800,000, not including fuel cost. Delivery of the same quantity of
fuel oil to Bethel will cost approximately $6,720,000 less – a large incentive for the
Bethel location.
Both Yukon Fuel Company and Crowley Marine each operate 10 million gallon
tank farms in Bethel and with some alterations these tank farms could serve as a
safety cushion in case unforeseen events.
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.7
Diesel fuel costs contained herein are based on the assumption that Cook Inlet
or the West Coast would be the source of most of these products. Depending on
world and domestic market conditions, bringing tanker ships into Dutch Harbor,
discharging their cargo into shore-based storage and lightering the product to Bethel
may be a viable alternative.
While the marine operations companies believe that it is possible to move the
required fuel volume from Bethel to Crooked Creek, the operators are nevertheless
concerned about the practicality of fitting all of the additional traffic onto the river.
Fuel barges are much more efficient than freight barges because of their lack of need
for deck strength and unloading equipment, and further, lend themselves more easily
to rafting. The scenarios proposed by Yukon and Crowley assume that they can raft
up to four barges per tug. Any freight operation will be hard pressed to handle more
than two barges per tug. The fuel shipping operations will be conducted annually
between June 1st and September 30th. The project owner may want to consider
purchasing barges and tugs.
2. Propane
Propane will be delivered to either Security Cove or Goodnews Bay by deep-
draft tankers. From these locations the propane will be transloaded into a propane
barge and towed by tug boat into Bethel. Two propane barges with a capacity of 3-
3.5 million gallons each, and a single tug will be needed to lighter the 55 million
gallons of propane required annually. As with fuel oil, shipping operations will be
conducted annually between June 1st and September 30th.
If the power plant were located at Crooked Creek, demand would be reduced
to 50 million gallons annually. Delivery to Cooked Creek would be by 4-6 smaller
river-barges and two tugs. Propane would be transloaded from the tankers into
smaller river-barges and towed directly to Crooked Creek. The estimate of additional
cost of delivering a gallon of propane to Crooked Creek as compared to Bethel is
twelve cents per gallon or $6,000,000 annually for 50 million gallons. As with fuel
oil, this is a large incentive for locating the power plant at Bethel.
c. Fuel Receiving and Storage System
1. Fuel Oil
The Fuel Receiving and Storage System would include a fuel barge off-
loading dock with a marine header located on the west bank of the Kuskokwim River
at Bethel or the north bank of the river at Crooked Creek. The dock design was
developed by Peratrovich, Nottingham and Drage, Inc. for the Donlin Creek Mine
Late Stage Evaluation Study and proposed by LCMF LLC. An 8-inch pipeline would
connect the marine header to the bulk fuel facility. A bulk fuel tank farm facility
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.8
would consist of approximately 25 million gallons of fuel storage at Bethel and 22
million gallons at Crooked Creek. This equates to a nine-month supply of fuel at
either Bethel or Crooked Creek. A fuel reserve of 3.2 million gallons (1 tank) will be
created in the first year of fuel shipping. The tank farm will consist of eight insulated
tanks at Bethel and seven at Crooked Creek, each 120 feet in diameter and 40 feet
high with a nominal storage capacity of 3.2 million gallons. The tanks will be heated
with waste heat from the heat recovery system of the prime movers to keep the fuel
above the specified minimum temperature of 20°F. A 100,000 gallon insulated
intermediate fuel tank will be located near the power plant . The tank wii be heated to
the temperature of 70°F to improve fuel handling and injection into the engines of the
prime movers. A transfer pump will deliver the fuel from the bulk fuel tank facility
headers to the intermediate storage tank via a 4-inch delivery pipe insulated with
removable panels. A standby transfer pump will also be included. The fuel tanks will
require 121,000 Btu/hr, averaged annually to maintain the minimum internal
temperature of 20oF. The intermediate fuel tank will require 7,330 Btu/hr averaged
annually, to maintain the 70oF internal operating temperature. The heat will be
provided by power plant the heat recovery system. Specific information relating to
tank design and construction is provided in the Report: Site Development, Earthworks
Foundations and Bulk Fuel; Conceptual Design Report By LCMF, LLC.
2. Propane
As in the fuel oil option, the propane barge would off-load at a marine header
located on the west bank of the Kuskokwim River at Bethel and the north bank of the
river at Crooked Creek. A pipeline will connect the marine header to the fuel storage
facility. A bulk propane tank farm would store approximately 39 million gallons of
fuel at Bethel or 34 million gallons at Crooked Creek. This equates to a nine-month
supply of fuel at either Bethel or Crooked Creek. The tank farm will consist of three
un-insulated tanks, each with a storage capacity of 13 million gallons. Heating coils
will be placed in the outlet of one of the tanks to warm the propane, should ambient
air temperature drop below -40o F. A transfer pump will deliver the fuel from the
bulk fuel tank facility to the turbines.
2. Description of Power Plant Facilities
a. General Description
The Modular Power Plant (MPP) at Bethel will consist of a combined-cycle
combustion turbine plant, equipped with three simple-cycle combustion turbines plus
a heat recovery boiler and steam turbine generator. The combustion turbine-based
plant is a 2-on-1 non-reheat combined-cycle Power Plant designed to generate the
required electrical power with one train (CT and HRSG) out of service. The normal
plant operating configuration will consist of two combustion turbine generators,
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.9
(CTG), one dual-pressure-level, HRSG with the option of being duct -fired (HRSG),
one induction/condensing steam turbine-generator (STG).
The use of low–speed diesel generation was examined as part of this study,
but this alternative was rejected in favor of combustion turbines for reasons
subsequent ly discussed. The power plant will use a modular design, to the extent
practicable, to reduce on-site construction costs, minimize construction time and
facilitate handling and transporting of major equipment. Installed generation capacity
will be approximately 150 MW if the plant is built at Bethel and 110 MW if built at
Crooked Creek. Each combustion turbine will be fitted with a generator driven
directly by the turbine’s shaft through a gear reducer. Exhaust gases from each CT are
directed via a collector duct to one HRSG for steam generation. The turbine exhaust
gases can be discharged via a diverter damper to the atmosphere. This is required in
case the steam turbine cannot receive the full design flow of steam or the STG is shut
down.
Under normal conditions, the power plant at Bethel will operate with 2
GTX100 or LM6000 combustion turbine generators + 1 HRSG + 1 Steam turbine
generator to achieve nominal output with one stand-by GTX100/LM6000 system.
When the steam turbine is unavailable due to repair/maintenance all three GTX100/
LM600 machines can operate in simple cycle configuration to achieve the nominal
output.
At the Crooked Creek location, under normal conditions two GTX100 or
LM6000 turbines + 1 HRSG + 1 Steam turbine generator will provide the required
power output. When the steam turbine is unavailable, the two GTX100/ LM6000
machines can operate in simple cycle configuration to achieve the required output.
b. Prime Movers
Based on the design philosophy discussed above the following arrangements
of prime movers as listed in Tables III-2.2 and 2.3 were selected for examination:
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.10
TABLE III-2.2
Bethel Power Plant Alternatives
Option
Description
Total Installed
Capacity in
MW
1 3 each, Alstom 42 MW, simple-cycle combustion
turbines + one heat recovery boiler + one 25 MW steam
turbine
151
2 3 each, GE LM6000 46.5 MW, simple-cycle combustion
turbines + one heat recovery boiler + one 10.6 MW steam
turbine
150
3 6 each, MAN B&W 18V48/60, 18.4 MW diesel generator
sets
110
4 7 each, Wartsila 18V46/60, 16.5 MW diesel generator
sets
116
TABLE III-2.3
Crooked Creek Power Plant Alternatives
Option
Description
Total Installed
Capacity in
MW
1 2 each, Alstom 42 MW, simple-cycle combustion
turbines + one heat recovery boiler + one 25 MW steam
turbine
110
2 2 each, GE LM6000 46.5 MW, simple-cycle combustion
turbines + one heat recovery boiler + one 10.6 MW steam
turbine
104
3 5 each, MAN B&W 18V48/60, 18.4 MW diesel generator
sets
92
4 6 each, Wartsila 18V46/60, 16.5 MW diesel generator
sets
99
c. Comparison of Combustion Turbines with Diesel Engines
Combustion turbines have become a widely accepted technology for
producing power, especially when there is a need for small efficient power plants
working in the combined-cycle. Die sel engines have been proven over numerous
years as a reliable source of power in Alaska. Both technologies demonstrate
advantages and disadvantages, as outlined below.
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.11
1. Combustion Turbine Advantages
a. High Efficiency when applied in the combined-cycle
The exhaust gas temperature in a combustion turbine is very high, in the
range of 900oF to 1100oF, which makes recapturing the heat for cogeneration
and production of additional power in a steam turbine relatively easy. Typical
combined-cycle efficiencies are in the range of 48-55 percent. In the case of
the MPP, where there is need for recovering low temperature heat for tank and
space heating, the thermal efficiency depends only on the minimum allowable
stack temperature determined by the SO2 content. In the MPP a total thermal
efficiency of 84% is possible.
b. High Reliability
Combustion turbines are well known for their excellent reliability,
approaching 100% (see attached charts for the GE LM2500 turbine,
Appendix). The reliability of GE’s LM6000 and Alstom’s GTX100 is in the
same range.
c. Multi-Fuel Capability
Combustion turbines offer the ability to burn various fuels ranging from
natural gas, propane, Naphtha and diesel fuel. Relative efficiency remains
comparatively consistent for all fuels and only varies with the heating value of
the fuels. The multi-fuel capability makes the CT a reliable choice for Alaska,
where during certain times some fuels may not be readily available.
d. Low Weight
Combustion turbine s exhibit low unit mass per MW output, especially
when compared with diesel engines.
2. Combustion Turbine Disadvantages
a. Lower Efficiency
The combustion turbine exhibits a lower efficiency when operated in
simple cycle as compared to diesel engines. For a combustion turbine plant to
operate at peak efficiency it must be operated as a combined-cycle.
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.12
b. Maintenance
Requires and experienced and trained staff. Combustion turbines require
specialized parts, which are only obtainable fro m the manufacturer.
3. Advantages of Slow Speed Diesel Engines
a. High Efficiency
Slow-speed diesel engines, operating at 514 RPM, offer the best simple
cycle thermal efficiency of any technology readily available. This means that
even when the heat recovery system is inoperable, the engines can operate
with 48% efficiency. This is much higher than the combustion turbines, which
have a simple cycle efficiency of 37%.
b. Multi Fuel Capability
Slow speed diesels are able to burn every fuel we have investigated
except Naphtha. Again, since fuel availability may change in a remote
location like Bethel, this is a benefit.
4. Drawbacks of Diesel Engines:
a. Weight
The Diesel engines are extremely heavy, which means moving them on and
offsite will require very large cranes. The 18 MW diesel engines evaluated in
this study (18V46 or 18V48) weigh in excess of 260 tonnes (570,000 lbs) each,
or roughly 16 tons of weight per MW of output, which makes moving them
difficult. For comparison; a combustion turbine of twice the output weighs less
than 40 tons or roughly one ton of weight per MW of output.
b. Foundation construction cost
Foundation costs are closely tied to the weight and vibrations generated by
the engines. Due to their low rotational speed in the range of 514 RPM, their
low frequency vibrations are significantly closer to the natural frequency of the
support structures and more likely to cause resonance. The foundations required
for the diesels must be highly engineered; they are significantly larger and more
complicated than those for CTs. There will also be a need for an increased
number of piles to account for the additional weight and vibration loads.
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.13
c. Lower Combined-Cycle Efficiency
In combined cycle with district heating, the thermal efficiency of the diesels
is lower than a combined cycle combustion turbine arrangement. This is due to
the lower temperature exhaust heat available from the diesels and large losses in
the lubricating oil and jacket water cooling systems. With the highest possible
degree of waste heat recovery, the thermal efficiency of the system with the
diesel engine is up to 10% lower than the equivalent thermal efficiency of a
combustion turbine applied in the combined cycle.
d. Lubrication Oil
Slow speed diesels require massive amounts of lubrication oil to operate. At
full load the lubricating oil consumption is 0.8 gram/kWh (0.00176 lb/kWh),
which for the Bethel located plant operating at average 80% capacity will
amount to 556 tons, over 3500 barrels of lubricating oil per year.
e. Maintenance
Diesel engines require more maintenance than combustion turbines. This
means that there is more downtime associated with each engine and more staff
will be required.
f. NOx
Diesel engines generate large quantities of NOX in the range of 940 to over
1,000 ppm. Even if a SCR system is used on the engine, a system which is both
capital and operating cost intensive, it cannot sufficiently reduce the NOx
performance to the level the combustion turbine, which is in the range of 35
ppm vol. This performance is guaranteed by both GE and Alstom without an
SCR system.
d. Comparison Summary
Experience in other Northern countries, such as Sweden, Finland, and
Iceland, has established that combined cycle plants are winning the market
against diesel engines. The significantly lower weight of combustion turbine
plants makes them much easier to transport and install at Bethel or Crooked
Creek. Both Chugach Electric Association and Anchorage Municipal Light and
Power, the two major generating utilities in Alaska, generate their power using
combined-cycle generation. Experience shows that diesel engines require
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.14
substantially more maintenance and continuous supervision by mechanics and
operators, whereas, combustion turbines can work with only once-a-week
supervision. The diesel engines require a staggering amount of lube oil, while
turbines require almost none. Diesel produce substantially more pollutants,
especially NOX. Because combined-cycle techno logy has several advantages
over diesel generation and few disadvantages, it has been selected for
generating the power needs of the Donlin Creek mine and the Calista region.
e. Comparison of the Alstom GTX100 & GE LM 6000 Turbine
The turbines are comparable in size – the rated Alstom CT output is 42 to 43
MW, the equivalent output of GE’s LM6000 is 46.5 MW.
The net heat rates in Btu/kWh generated differ somewhat:
- GTX100 7,683 Btu/kWh (at LHV),
- LM6000 8,323 Btu/kWh (at LHV)
The Alstom GTX100 machine has been engineered for the specific purpose,
combined-cycle power generation. The GE LM6000 machine is aero-derivative
which means that the original design objective was an aircraft engine, where the
weight and turbine shaft output are the predominant requirements. Ability to work in
the combined-cycle was not among the objectives during the design phase.
In the proposed Alstom system the generated steam is routed to a double
steam turbine, which drives the generator. The high-pressure steam supplies the HP
turbine, and the low-pressure steam supplies the LP turbine. Up to 165,000 lb/hr (in
winter) of steam is extracted for district heating. The HRSG also has a supplementary
liquid fuel - fired duct burner section, which will allow the steam output to be
increased if the DH demand increases above available steam supply. For the GTX
100 Turbine, the heat rate remains practically constant when the turbine is loaded
above 73%.
The LM6000 turbine reaches its highest efficiency/lowest heat rate at almost
100% of its output capability, whereas the GTX100 turbine maintains a steady heat
rate/efficiency between 73% and 100% nominal capacity.
The Alstom machine is built for stationary duty therefore it is heavier than the
LM6000. However, the GTX100’s are more efficient over a wider range of operating
loads.
Price wise, the LM6000 is about $680,000 ($16,000/MWe) less expensive
than the GTX100. The cost difference on 3 turbines, of $2,040,000 will be paid off by
fuel savings within 6 months.
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.15
f. Heat Recovery Steam Generator System
The Alstom HRSG will produce superheated steam using heat from the
exhaust stream of the GX100 turbines. The generated steam is routed to high and low
pressure sections of the steam turbine, which drives an electric generator through a
reduction gear box. Maximum output is 25 MW, which requires the exhaust stream
from two GTX100 turbines.
GE proposed an unfired HRSG, single-pressure, two drum, natural circulation,
top supported unit. Heat absorption surfaces will be mounted in factory-assembled
modules to facilitate construction. Output is 10.6 MW at full duct firing, which
requires the exhaust stream from two LM6000 turbines.
g. Steam Turbine and Generator Module
Factory assembled, complete with steam inlet valves and servo motors,
piping, instrumentation and wiring to junction boxes. The STG will be supplied with
standard stand-alone control system handling all closed and open loop turbine
controls.
h. Steam Condensing (cooling) System
Water for the cooling towers will either be drawn from wells or the river. As
an alternative to cooling towers, the cooling system may consist of once-through
water cooling from a nearby pond in Bethel. Although the once-through cooling
system is attractive from the cost and operation point of view, it may have
environmental drawbacks, which will need to be addressed in environmental report s.
A once through cooling system could reduce construction costs and lessen plant
parasitic power.
i. Demineralizing System
Two (2) 100% makeup water demineralizer systems with capacity of 50
USgpm each will be provided. The systems will include a 100,000-gallon makeup
water storage tank from where makeup is pumped to the deaerator. The system will
also provide, if required, water for injection in the CTG to control NOx emissions.
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.16
j. Phosphate Feed System
Phosphate feed to the HRSG steam drum will be controlled to maintain the
desired phosphate residual and alkalinity in the boiler water.
k. Instrumentation and Controls Including the DCS System
The co mbustion turbine generators and steam turbine are controlled through
an advanced distributed control system (DCS) consisting of an ABB Advant DCS
equipment package. The Advant system is designed to provide automated start -up and
shutdown of the CTGs and the STG from the control room. The DCS provides
supervisory oversight, monitoring, and set point regulation for local controls devices.
The supervisory function allows operation of major plant processes and equipment
from the local control room. Processing units function independently and the
exchange of signals across the communications network for control purposes is
avoided wherever possible. Controls for the District Heating system and the BOP
systems will also be integrated into the DCS system.
The CTG will be designed for a “pushbutton” start locally or from the control
room. Its operation is fully automatic. The remote control from the control room is
accomplished from the plant control system CRTs via a digital link from the CTG
control system. The plant control system logs analog and digital data. Under
abnormal conditions the CTG output may be lowered for short durations ; during that
time, the units will operate at a lower efficiency.
All required plant parameters would be monitored and indicated, alarmed
and/or recorded in the control room to facilitate the plant operator with control of the
plant. The gas turbine will be interfaced to the plant control system for monitoring
and trending.
l. Environment Protection System
The Environment Protection System of the combustion turbine-driven Modular
Power Plant is simple and requires little or no controlling systems to maintain highest
performance in Alaska. The Modular Plant will not generate emissions above the best
performance of other type power plants. As a matter of fact, the factual emissions will
comply with the BACT philosophy (best available control technology). It will
generate practically no hazardous liquid or solid waste.
1. Emissions to the Ambient Air
Alstom Power as well as GE Power are ready to guarantee emissions as listed
below using Diesel No. 2. The following table is the performance guarantee issued by
Alstom Power .
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.17
GTX100 AEV Burner System
NOx ppm vol at 15% O2 35
CO ppm vol at 15% O2 5
UHC ppm vol at 15% O2 5
VOC ppm vol at 15% O2 4
PM10 mg/Nm3 8
SO2 ppm vol at 15% O2 <200
UHC Unburned hydrocarbons; components are measured as
C3H8
VOC Non-methane, Volatile organic compounds;
components are measured as C3H8
GE Power Systems’ stated performance is as follows:
NOx ppmdv 42
NOx lb/hr 53
CO ppmdv 6
CO lb/hr 5
HC ppmdv 2
HC lb/hr 1
SO2 ppm <200
The GE values are based on dry volume (commonly used in the USA),
whereas Alstom is based on total volume (commonly used in Europe). The values are
comparable; practically the same.
Neither NOx nor CO emissions need to be controlled. For comparison, the
performance of diesel engines installed in Alaska without a tail-end treatment systems
is in the range of 900 to 1,000 ppm vol. Diesel engines even with a tail end control
system – Selective Catalytic Reduction (SCR) do not perform as well as the
combustion turbines.
Sulfur dioxide (SO2) emissions depend entirely on the sulfur content in the
fuel to be used in the Plant. The selected fuel (DF2 supplied by Tesoro) has an
average measured sulfur content of 0.1% - one fifth of the permitted value.
Particulate matter is produced from the incomplete combustion of fuels,
addit ives in fuels and lubricants, and worn material that accumulates in the engine
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.18
lubricant. These additives and worn materials also contain trace amounts of various
metals and their compounds, which may be released as exhaust emissions.
As the Alstom performance guarantee shows, the PM emissions from a
GTX100 turbine is in the range of 8 mg/Nm3. The most stringent PM emission
standards (for hazardous waste incineration) set the limit at 25 mg/Nm3 (for
Environment Canada Standard).
2. Liquid and Solid Waste
The plant produces negligible amounts of liquid or solid waste:
- Blow down water from the HRSG at the estimated rate of 420 gallons per
hour. This stream can be normally discharged to the sewer system, settling pond or
can be recirculated back into the ma ke-up water demineralization system.
- Blow down (bleed rate) from the cooling tower circulating cooling water at
the estimated rate of 10,000 gallons per hour. This stream is also non-hazardous and
can be normally discharged to the sewer system, to a settling pond or recirculated.
Normally treatment of this stream is not required.
- The plant will generate a very small amount of filtrate from filtering fuel
before injecting to the combustion chamber. This waste will be placed in containers
for disposal at an appropriate disposal facility.
Other waste generated at the plant will be sewage and typical municipal garbage,
which will be disposed of at the City of Bethel disposal facilities.
m. Auxiliary Boiler
Diesel fuel and used lube oil-fired boiler working in standby duty. The boiler
will be used during plant start-up for steam line blowing and to provide heating of the
fuel and plant. During normal operations of the plant, the boiler will be used
sporadically during periods with very low ambient temperatures, when the heat
recovery system cannot provide sufficient heat for space heating and the district
heating system. The paged, water -tube boiler will be equipped with all necessary
controls and instrumentation.
n. Fire Protection System
The fire protection systems will include redundant water pumps including a
diesel engine - driven unit. The 100,000-gallon raw water storage tank will serve as a
source of fire-fighting water. As an alternative, water from the cooling pond or make-
up water well will be used. Appropriate detection, alarms will be included in strategic
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.19
locations and system actuation will be automatic when and where necessary. For the
main electric systems, automatic extinguishers will be used.
o. Civil Works, Buildings and Other Enclosures
To minimize the cost and promote modularization all equipment of the
Modular Power Plant will be housed in modular structures that will allow easy access
to the equipment and also relocation of the plant. The structures will be thermally and
sound insulated as needed. Control Room, office and utility space will also be
provided in modular units.
For a listing and specifications of site development, earthworks, foundations
and tank farm, please see the attached Conceptual Design Report by LCMF, LLC of
Anchorage, Alaska.
p. Maintenance Shop
Due to the limited capabilities for local fabrication and repair, the plant will
include a reasonably sized maintenance facility. This facility will be able to service
both basic plant equipment and the rolling stock on the premises. See attachment
Maintenance and Repair Shops.
C. RELIABILITY ANALYSIS
The CTG power plant s will be designed to operate at a reliability consistent
with a utility grade power plant. Total installed plant capacity at Bethel will be
approximately 150 MW and at Crooked Creek, 110 MW. A reliability analysis
performed by PES determined the availability of the Bethel plant to generate at least
100 MW of power at 99.4 percent, which means the plant is unavailable to serve the
load for 0.6% of the time. On an annual basis, a 0.6% unavailability rate equates to a
period of 52.5 hours per year or 2.2 days per year.
Bettine, LLC conducted an independent reliability analysis to determine the
number of hours per year the plant cannot adequately serve the mine demand and the
total system demand. This basic reliability analysis assumes a forced outage rate of
1% for each for the combustion turbines and 1% for the steam turbine and the HRSG.
These are typical forced outage or unavailability rates for well-maintained plants.
Two alternatives are investigated. A modified binomial distribution model was used
to calculate the number of hours per year the plant would be unable to generate a
specified MW output. The results of the analysis are listed in the Loss of Load
Expectation (LOLE) table, shown in Table III-2.4. LOLE is the number of hours per
year the power system cannot serve the expected system demand. Supporting
calculations can be found in Appendix H.
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COMBINED-CYCLE COMBUSTION TURBINE PLANT Section III-2.20
As discussed in Section III-1 the forced outage time associated with the 190
mile transmission system is estimated a 8 hours per year. For the 15 mile segment
between Crooked Creek and the mine this equates to one hour per year.
TABLE III-2.4
LOSS OF LOAD EXPECTATION IN HOURS PER YEAR
Total
System
Demand2
150 MW
Bethel Plant
T-Line
Total
110 MW
Crooked
Creek
T-Line
Total
50 MW 3 8 11 88 1 89
85 MW 5 8 13 88 1 89
100 MW 90 8 98 -- -- --
A review of Table III-2.4 reveals that the Bethel plant can reliably supply a 50
MW system-demand, suffering a LOLE of less than one-half day per year. The
Crooked Creek plant with its reduced generation capacity would experience a LOLE
of 89 hours per year. At 85 MW system-demand the Bethel plant LOLE increase
slightly, to 13 hours per year. Because of the generation mix at Crooked Creek the
LOLE remains at 89 hours per year. At 100 MW system-demand the Bethel plant
experiences a LOLE, including the transmission line, of 98 hours per year and 90
hour per year when the transmission line is not included. This equates to an
unavailability rate of 1.0% per year as compared to 0.6 percent by PES. Differing
methodologies used by PES and Bettine, LLC to predict LOLE has produced these
slightly different results.
The above LOLE are representative of the two generation options. A more in-
depth reliability analysis will need to be conducted as the project moves fr om the
feasibility stage toward the final design phase. As with any plant design, an
acceptable compromise between reliability and capital cost will need to be achieved.
However, until Placer Dome can better define the Donlin Creek power requirements,
it is pointless to refine the analysis.
2 Includes line losses and in -plant usage.
Figure III-2.2 Proposed Location of Cooked Creek Power Plant and Fuel Storage Facility
FIGURE III-2.3
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DISTRICT HEATING SYSTEM Section III-3.1
SECTION III-3
3. DISTRICT HEATING SYSTEM
A. INTRODUCTION
The generation of electricity using fossil fuels is less than 100 percent efficient.
Typical efficiencies are in the range of 35% for coal-fired plants and 50% for combined-
cycle combustion t urbine plants. The used energy will escape into the atmosphere as used
“waste heat”. However, a large percentage of this waste heat can be recovered and used
to provide space heating in buildings and domestic hot water. To distribute this recovered
heat throughout the community, it is necessary to construct a network of pipes known as
a district heating (DH) system.
The power plant will include provisions for capturing this waste heat and using it
to supply thermal energy to a district heating system that will serve the space and
domestic water heating needs of Bethel. The proposed system will be capable of
supplying every reasonably accessible building in Bethel with heat and hot water. This
includes all residential housing, schools, the community college buildings, government
buildings, city buildings, hospital, jail, airport, and local businesses. The system could
also provide heat to an existing or new swimming pool and sports complex for the
general population of Bethel. Additionally, there will be hu ge quantities of waste heat in
the 85oF temperature range available to heat greenhouses built in the immediate vicinity
of the power plant.
Based on the heating oil usage records and projected city and surroundings
growth, the future thermal energy requirements are estimated as follows:
Yearly average heat supply million Btu/hr 128.9
Average summer supply million Btu/hr 91.1
Average winter supply million Btu/hr 142.2
Maximum winter supply million Btu/hr 169.0
Extremely low winter temperatures million Btu/hr 180.0
Utility water for consumption lb/hr 151,400
Gpm 303
Since the above numbers represent monthly averages, the actual minimums and
maximums may differ significantly from the given amounts. It is planned that during a 2
to 3 week period in July or August, the system will be shut down for maintenance. The
maximum winter demand of 180 million Btu/hr is estimated based on recorded low
temperatures.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION III
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DISTRICT HEATING SYSTEM Section III-3.2
The DH system will use hot water systems. Outgoing water temperature will be
between 170 – 175o F at 100 psi. Return water will be in the range of 125 – 130ºF at 20
psi. Heating of the hot water will be achieved primarily by utilization of condensing heat
exchanger utilizing latent heat of condensation of the steam cycle.
The development of the Bethel Power Plant , coal-fired or combustion turbine,
will include the construction of trunk pipelines shown in drawings attached to the end of
this subsection. Heat will be supplied to one Central Heat Exchange Station located at the
power plant . From there, one main trunk line will serve the airport and one will serve the
City. The pipeline to the City will branch out to the North and East and supply major
loads and several distribution centers. Smaller distribution lines will connect to the
distribution centers to supply buildings or groups of buildings. It is anticipated that these
smaller distribution lines will be constructed by the City or by private enterprise.
Heating of buildings is accomplished by circulating hot water that is heated in a
condensing heat exchanger by steam, which is extracted from the power plant’s steam
turbines, and then piped to receivers around whole districts. Providing both heat and hot
water is an extremely efficient use of fuel and demands coordination of energy supply
with local physical planning. There are over 30,000 district heating systems in the USA.
Hot water district heating meets the thermal energy needs of residential, commercial and
industrial users from the same distribution line.
The overall thermal efficiency of a combined-cycle combustion turbine driven
MPP, can be increased to approximately 84% if waste heat from the plant is used to
supply heat to a district heating system. For the coal-fired plant, thermal efficiency
should exceed 40% if waste heat is used to supply heat to the district heating system.
The Bethel district heating system will be based on using hot water instead of
steam as the thermal energy carrier. Older district heating systems use steam for this
purpose, however, there has been a general movement towards using hot water, which is
recommended by the International Energy Agency – an international body with
headquarters located in Europe that promotes energy efficiency by using district heating
and heat pumps. The advantages of water heating over steam heating are several, the
most important of which are:
1. Safety. Water is used in district heating systems with temperatures in the
range of 170 – 194oF (77 – 90oC), which is sufficiently below the water boiling
temperature. A leak in the piping, whether outside or inside the heated space, will not
result in rapid conversion of water to steam, which reduces the possibility of scalding or a
steam explosion.
2. At working pressures the volume of steam is 180 times larger than the volume
of the same mass of water. This means that water requires smaller diameter piping and
valves, as well as smaller pumping and heat exchange equipment. Smaller diameter
piping results in lower overall heat losses; hot water systems lose only a maximum of
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DISTRICT HEATING SYSTEM Section III-3.3
10% of their energy before it is delivered to the desired location, whereas same duty
steam - based systems lose as much as 30% of their energy to ambient air.
3. Due to safety considerations, pressurized steam systems must be built
according to the ASME Code; as a result, they are significantly more expensive in both
capital and operating cost terms. Steam systems are also more expensive due to larger
pipe sizing and the requirement for larger pumping equipment. The maintenance cost of
steam-based systems is also significantly higher than that of water-based systems.
B. SYSTEM SPECIFICS
1. Pipes & Pumps
Sizing pipe for the district heating system was determined by the estimated heat
usage of the Bethel community. The heat capacity of the Bethel district heating system
was based on the average heating oil usage, accounting for 20% growth over 10 years.
We estimated a heat delivery rate of 128 MM Btu/hr average load in winter, with a
maximum momentary winter load of 180 MM Btu/hr. The heat load also accounts for
utility hot water usage. Heating water delivery rate is based on the heat demand and the
temperature difference between the delivery and return lines.
For supplying pipe we have contacted several manufacturers that are familiar with
district heating pipe. Prices for the pipe ranged from $25 per linear foot for 10-inch pipe
to $83.00 per linear foot for 24-inch pipe. Based on pumping requirements a 16-inch
diameter pipe appears to be the economical choice.
2. Heat Exchangers
The District Heating system will include main heat exchangers where the district
heating water is heated with heat supplied from the power plant. The size of the heat
exchanger was determined by the average winter heat rate of 128 MM Btu/hr. However,
the system will have suffic ient capacity to allow for heating demands during extreme low
temperatures. The heat exchanger is a condensing type that make use of the latent heat of
vaporization.
After the main exchange station at the power plant, there will be several local
exchange stations to deliver heat to individual or groups of houses. These stations will
have heat exchangers that transfer the heat to a lower pressure loop that delivers hot
water below 15 psi. The reason for the low-pressure loop is to meet the 15 psi limit for
ASME building codes. The size of the intermediate heat exchangers will be determined
by the heat requirements of the surrounding structures.
Using water directly from the DH system should be avoided to prevent
contamination of the water in the main trunk lines, and to extend the life of the system.
Contaminated water increases maintenance costs and causes premature failure in the
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DISTRICT HEATING SYSTEM Section III-3.4
main distribution lines. Also, the pressure for delivery water needs to be kept low for
safety reasons. Since the delivery pressure in the main lines will be above 70 psi, an
intermediate loop will allow the pressure to be dropped to a reasonable level for safety.
At the final delivery point, radiant heaters will be installed in individual buildings
for heating. These heaters will run off the intermediate exchangers that are linked to the
main trunk lines. In some cases, forced air heating units can be retrofitted for district
heating.
3. Backup System
A stand-by package oil-fired boiler will be installed to supply heat for district
heating when the plant is shut down for maintenance.
C. SYSTEM INSTALLATION
The scope of the feasibility study only covers the basics of main trunk piping,
primary heat exchangers at the power plant and exchange stations. A more thorough
investigation will be needed to obtain a better knowledge of the customer base and the
engineering specifics of a complete district heating system.
The overall capital equipment cost , estimated at $11 million, includes the main
trunk lines, the delivery pumps and the primary heat exchangers at the power plant and
exchange stations. It does not include the cost of installing the smaller distribution pipes.
The installation costs for a district heating system will be significant, as several
miles of main trunk lines will have to be laid. With our current information, we estimate
that laying the main trunk line, installing the central exchange station, and insulating pipe
joints will take about 40,000 man-hours. Additional residence and hookup costs will
depend on the size and demand on the district heating system.
The only needed regular maintenance for the district heating system will be on the
primary feed pumps and heat exchangers at the power plant. Main trunk lines for district
heating will have to be inspected yearly, as will intermediate heat exchangers.
D. WASTE HEAT SALES
Nuvista does not intend to operate the district heating system. Instead Nuvista
would wholesale the waste heat produced by the plant to a private or public entity that
would be responsible for distribution and retail sales. Based on fuel oil prices for January
2003, wholesale rates are estimated at $7.70 per million Btu, which equates to selling fuel
oil at a price of $1.00 per gallon. Given that fuel oil prices in Bethel are in the range of
$2.00 per gallon for large users and $2.50 per gallon for small users, the capture and use
of waste heat from the power plant has the potential for significantly lowering heating
cost s in the Community of Bethel.
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DISTRICT HEATING SYSTEM Section III-3.5
The income generated from the sale of waste heat will be used to offset plant
operating costs, which will in turn lower the cost of electric power to all consumers.
Using this approach, all consumers will share in the revenues generated from the sale of
waste heat.
Waste heat sales can lo wer the cost of electricity to all consumers. The greater
the amount of waste heat sales the lower the cost of electricity. The economics of waste
heat sales and the impact on electric costs are addressed in Section IX.
.
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SECTION III-4
4. OTHER POWER SUPPLY ALTERNATIVES
A. INTRODUCTION
Two transmission line alternatives that would deliver power to the mine from the
railbelt were previously investigated as part of the Calista Region Energy Needs Study,
dated July 1, 2000. These power lines were determined to provide less economical power
than a coal-fired plant located at Bethel. However, these alternatives are revisited. Two
natural gas supply alternatives are also investigated.
B. TRANSMISSION LINES BUILT FROM NENANA
GVEA (Golden Valley Electric Association) estimated that it would take
approximately eight years to permit, design and construct a power line between Nenana
and the Donlin Creek mine. D&L estimates that it would take four winters to construct
the power line, which is consistent with GVEA’s eight year estimate. In addition, D&L
has serious concerns about the logistics of building this line due to access, weather,
environmental constraints, etc. The most likely scenario for building this line is via ice
roads constructed from both Nenana and Donlin Creek over four winters. Finding
adequate water sources along the route for the ice roads could be problematic. The
logistics of moving men and materials across hundreds of miles of roadless wilderness
will present a monumental task. Also, the uncertainty of weather conditions suitable for
ice road construction and use would add additional risk.
1. + 100-kV, DC Transmission Line
a. Option 1
The option would provide power only to the mine site. The transmission
line would originate at Nenana and proceed southwesterly to Crooked Creek
and then on to the mine site. The estimated 385 mile transmission line would
serve no other load other than the mine. The estimated cost of the power line
is $733,700 per mile for a tot al cost of $282.5 million. This figure includes all
construction, freight, engineering and permitting cost s associated with
building the power line. AC-DC convertor stations must be built at both
Nenana and the mine site for a total cost of $100 million do llars.1 Total
project cost for a power line between Nenana and the mine site would be
$382.5 million. The convertor station located at the mine site would supply
the mine at an AC voltage of 13.8-kV. Power would be purchased from
1 Source: GVEA
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Golden Valley Electric. The cost of power at the Nenana substation would be
4.5 cents per kWh plus $11.25 per kW monthly demand charge.2
b. Option 2
The 370 mile DC transmission line would originate at Nenana and
terminate at a convertor station located at Crooked Creek that would convert
the + 100kV DC voltage to an AC voltage of 138-kV. A 138-kV transmission
line would be built from Crooked Creek to the mine and between Crooked
Creek and Bethel. The 138-kV line would provide power to Bethel and 8
villages. The total cost of this option is $501.5 million. Of this total, $271.5
million is for the DC line, $100 million for the convertor stations and $130
million for the 138-kV transmission line and the village step-down
substations. Power costs are as stated above. This is the most expensive option
examined for providing power to the region.
2. 230-kV, AC Line Built from Nenana
a. Option 1
The transmission line would originate at Nenana and proceed
southwesterly to Crooked Creek and then on to the mine site. The estimated
385 mile transmission line could serve the community of McGrath, Crooked
Creek and the mine site. The cost of this power line is estimated at $930,200
per mile for a total cost of $358 million. This figure includes all construction,
engineering and permitting cost s associated with building the power line.
Substation costs are estimated $5 million dollars. The step-down station
located at the mine site would supply the mine at an AC voltage of 13.8-kV.
Total cost would be $363 million. Power would be purchased from GVEA.
The cost of power at the Nenana substation would be 4.5 cents per kWh plus
$11.25 per kW monthly demand charge.
b. Option 2
The 370 mile AC transmission line would originate at Nenana and
terminate at a step-down substation located at Crooked Creek that would
convert the 230kV AC voltage to an AC voltage of 138kV. A 138-kV
transmission line would be built from Crooked Creek to the mine and
between Crooked Creek and the Bethel. The 138-kV line would provide
power to Bethel and 8 villages. The total cost of this option is $479 million.
Of this total, $344 million is for the 230-kV line, $5 million for substations
and $130 million for the 138-kV transmission line and the village step-down
substations. Power costs are as stated above.
2 Id.
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C. NATURAL GAS SUPPLY
1. Cook Inlet Pipeline
This option was presented by VECO, Inc. It involves constructing a natural gas
pipeline from the Cook Inlet gas fields to Crooked Creek. The pipeline would be 330
miles long and essentially follow the Iditarod trail through the Alaska Range. After
exiting the Alaska Range on the north, the pipeline would turn southwest to Crooked
Creek. A 150 MW combined-cycle combustion turbine plant would be constructed at
Crooked Creek to supply electric power to the Donlin mine project, Bethel and eight
villages via a 138-kV transmission line. The cost of the pipeline is estimated at $210
million in the VECO study. The study estimates the cost of the power plant at $135
million and the transmission line between Crooked Creek and Bethel at $130 million, for
a total cost of $500 million, which is comparable to the DC option at $475 million.
Not only is this option among the most expensive options examined, production
from the Cook Inlet gas fields is predicted to decline dramatically by 2010, which is the
very time the Donlin Creek mine will need power. Figures III-4.1 & 2 clearly show the
decline in the Cook Inlet field production, from a high of 221 Bcf in 2002 to a less than
22 Bcf in 2022. Because of the high cost of this alternative, the steep decline in gas
production, and the uncertainty as to the availability and cost of natural gas from the
Cook Inlet field, this alternative is not considered to be a practical.
2. Holitna Basin Natural Gas
Holitna Energy, a newly formed company, has recently announced its intention to
explore the Holitna Basin for natural gas. The Holitna Basin is located about 50 miles
southeast of Crooked Creek. Three major oil companies, ARCO, Unocal and Sohio (now
BP) independently evaluated the Holitna basin during the 1980s and decided not to drill
any exploratory wells.3 At the time this report was printed, virtually no subsurface
exploration of the basin, of any kind, by Holitna Energy, has been accomplished. The
potential for finding an economic and commercially developable natural gas deposit is
unknown. At this point in time the Holitna Basin cannot rationally be considered a
natural gas resource.
3Source: Petroleum News, November 2, 2003
FIGURE III-4.1
Cooked Inlet Gas Production Forecast
(Alaska Division of Oil and Gas 2002 Report)
FIGURE III-4.2
Cooked Inlet Gas Production Forecast
(Alaska Division of Oil and Gas 2002 Report)
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ROUTE SELECTION Section IV-1.1
SECTION IV 138-kV TRANSMISSION LINE &
SUBSTATIONS
SECTION IV-1 - ROUTE SELECTION
A. INTRODUCTION
A primary goal of this study is to explore the feasibility of constructing a power
plant in Bethel, Alaska and a 138-kV transmission line from Bethel to the proposed
Donlin Creek gold mine project located approximately fourteen miles north of Crooked
Creek, AK. The transmission line would be located along the northern bank of the
Kuskokwim River as shown in Figure IV-1.1. Power would be supplied from a power
plant at Bethel, to serve Bethel, Akiachak, Akiak, Tuluksak, Lower/Upper Kalskag,
Aniak, Chuathbaluk, Crooked Creek and the proposed Donlin Creek gold mine.1 This
section of the study examines the transmission line route alignment and the feasibility
level designs for the transmission line and its associated substations.
There is a possibility that a combined-cycle combustion turbine power plant
would be constructed near Crooked Creek to supply the Donlin Creek mine rather than at
Bethel. This would only occur if sufficient quantities of natural gas were discovered in
the Holitna Basin to supply the energy needs of the project and the natural gas could be
supplied at competitive prices as compared to other fuel sources addressed in this study.2
Under this scenario the 138-kV transmission line as discussed in this report would still be
constructed. The only difference would be that power generated at the Crooked Creek
power plant would flow north to the Donlin Creek mine and south to Bethel and the
above-named eight villages, rather than all power flowing north from Bethel.
B. METHODOLOGY
1. General
The process of route selection requires input from various stakeholders and
decision makers to select a route location. These sources include federal, state and local
government agencies, the general public, environmental groups, land owners, affected
utilities, and transmission line designers. Final route alignment will be made during the
EA/EIS process.
1 Napaimute is being reestablished and may also be served from the transmission line.
2 The potential for the Holitna Basin to produce sufficient quantities of natural gas at competitive prices to
sustain the power generation needs of mining operation for 20-30 years and the region for the next 40 years
is virtually unknown at this time. Efforts to collect preliminary seismic data on the basin may begin in
early spring of 2004.
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The preliminary route alignment is as shown on the seventeen maps included at
the end of this section. In April 2003, a scoping letter was sent out to numerous agencies,
individuals, utilities, and land owners soliciting their comments regarding an initial
alignment for the 138-kV transmission line between Bethel and the Donlin Creek mine
site. In March, 2004 a draft of this report was released for review by the public and
various government agencies. During the second quarter of 2004, public meetings will be
conducted in Bethel and Aniak. The preliminary route alignment will be present ed and
comments will be solic ited. It is important to recognize that modifications to the route
can be expected as a result of the public comment process, the EA/EIS process, and
during the final design phase, as the route alignment is fine tuned.
C. TRANSMISSION LINE CHARACTERISTICS
1. General Characteristics
Various transmission structures that could be used for constructing the 138-kV
transmission line were evaluated. The evaluation suggests that single pole structures be
used for the initial 6 miles of the power line, i.e. line Segment A-B, as it traverses the
City of Bethel. Using single pole structures would limit right -of-way requirements to 50
feet. Typical structure height would be 50 feet and span length, i.e. distance between
structures, would be in the order of 300 feet.
The next 80 miles of power line, i.e. line Segments B-C through F-G, extends
between Bethel and Upper Kalskag. This portion of line traverses marshy, tundra covered
lowlands underlain with permafrost. Terrain elevation for this portion of the line varies
from a minimum of 13 feet to a maximum of 73 feet. A driven pipe-pile supported, steel
H-frame structure is recommended for use on this portion of the line. The driven pile
supported steel structure has been used in the construction of most major power lines in
Alaska, in this type of terrain. R.O.W. width requirements when using H-frame structures
would be 125 feet. Using a nominal structure height of 70 feet, a typical span length of
1,200 feet can easily be achieved along this portion of the route.
The portion of power line located between Kalskag and Crooked Creek, i.e. line
segments G-H through L-M, traverses hilly terrain and better drained soils. It is
anticipated that granular, moderately drained soils will be encountered, along this portion
of the route and therefore, it would be possible to utilize direct imbedded steel H-frame
structures, rather than driven pile supported or X-frame structures. Typical R.O.W. width
requirements when using the H-frame structures would be 125 feet. Terrain elevation for
this portion of the line varies between a minimum of 59 feet to a maximum of 717 feet.
Due to the hilly terrain along this portion of the route, a typical span length along this
portion of the route would decrease to 1,000 feet. Typical tower heights would be 70+ 20
feet.
Between Crooked Creek and the mine site, line segment M-N, available R.O.W.
width will dictate the type of structure that would be used. If the power line must be built
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within the Crooked Creek to Donlin Creek mine road R.O.W., then a single pole design
would be used. Typical span lengths for a single pole line would be in the order of 400
feet. If a separate 125 feet wide R.O.W. can be obtained for the power line, which would
be far more desirable than building in the road right-of-way, direct embedded steel H-
frame structures would be used. Maximum elevation is 950 ft. Typical span length along
this portion of the route would be 1,000 feet. Typical tower heights would be 70+20 feet.
The route alignment for this section presently assumes a separate 125 feet wide R.O.W.
can be obtained.
2. R.O.W. Requirements
Single pole structures would be used in line Segment A-B to limit right -of-way
requirements to 50 feet. Segment A-B is that 6 mile segment of line, which traverses
south-to-north through the community of Bethel. Typical structure height would be 50
feet and span length would be in the order of 300 feet. No clearing should be required in
this section of the transmission line corridor.
It is anticipated that H-frame structures would be used to construct the remaining
185 miles of transmission line. Typical R.O.W. width requirements when using the H-
fr ame structures would be 125 feet. Little if any R.O.W clearing would be needed on line
Segments B-C through F-G, which collectively extend between Bethel and Upper
Kalskag. This portion of line traverses marshy, tundra covered lowlands underlain with
perma frost, which is basically devoid of trees.
The portion of power line located between Kalskag and Crooked Creek, i.e. line
segments G-H through L-M, traverses hilly terrain and better drained soils. Spruce forests
are encountered at Upper Kalskag. The sparse spruce forest of the Kalskag area gives
way to an ever increasing forest cover, with maximum forest density occurring between
Aniak and Crooked Creek. R.O.W. clearing requirements will increase in direct
proportion to the forest density. Between Cooked Creek and the Donlin Creek mine site,
the terrain climbs rapidly in elevation, from 200 feet at Crooked Creek to approximately
1,000 feet above-mean-sea-level at the mine site. The relatively dense forest of the
Cooked Creek area rapidly gives way to sparse forest cover, tundra covered slopes and
barrens as the elevation increases, reducing R.O.W. clearing requirements.
Clearing of the R.O.W. would , to the maximum extent practicable, be limited to
structure locations and danger trees that may contact phase conductors. A sketch of a
typical R.O.W. cross section is attached at the end of this Section.
3. Visual Impact
The visual impact of a transmission line is always an issue. It is recognized that a
power line built along the proposed route wo uld be visible , for the most part, from the
Kuskokwim River. The transmission line has in fact been routed as close to the river as
practicable, to improve access and reduce construction costs. Weathering steel towers,
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which turn a rusty-brown color when exposed to the elements, would be used to reduce
visual impact.
The Kuskokwim River is the second largest drainage in the state of Alaska. The
glacially turbid mainstem is approximately 900 miles long, originating from the interior
headwaters of the Kuskokwim Mountains and the northern foothills of the Alaska Range.
The Kuskokwim River is the major transportation artery in the Calista Region. During the
open water period, generally occurring between mid-May through mid-October, shallow
draft river barges ply the waters of the river, delivering fuel oil and supplies to villages
located upstream of Bethel. Bethel is the furthest inland point on the Kuskokwim
navigable by ocean-going barges and is the primary transshipment point for marine cargo
moving up the river. It has been estimated that about 25 percent of the general cargo and
50 percent of the fuel delivered to Bethel is offloaded onto river barges and redistributed
for shipment to the upstream villages. The most intensive period of inter-village travel is
during the summer months when local residents travel up and down the river in small
boats and skiffs. During the winter months, when the river is frozen, travel between
villages is accomplished by snow machine and all-terrain vehicles.
This visual impact of a transmission line may reduce the opportunities for
wilderness experiences and the appeal to tourist. However, because the Kuskokwim is
glacially turbid river there is little sports fishing on the mainst ream river. Most sports
fishing occurs on the clear water tributaries. Therefore, it is not anticipated existing or
future tourism along the river would suffer, to any significant extent, as a result of
building a transmission line along the northern bank of the Kuskokwim River.
Subsistence fishing, hunting and gathering occurs along the entire length of the river.
However, it is not anticipated that the construction of a power line and the associated
visual impact would, to any measurable degree, affect subsistence activities.
4. EMF Affects
Many people are concerned that exposure to electromagnetic fields (EMF)
represents an increased health risk. EMFs are invisible lines of force that are produced by
power lines and virtually every apparatus that uses electricity. EMFs consist of two
components, an electric field and a magnetic field. The electric field is related to the
magnitude of the voltage, while the magnetic field is related to the magnitude of current
in amperes flowing through the conductors. Studies to determine the affect of EMF on
human health have been inconclusive.
Electric fields from power lines are measured in kilovolts per meter (kV/m).
Electric fields are easily shielded (blocked) by most objects and materials such as trees or
houses. Electric fields decrease rapidly as the distance to the power line increases.
Electric field strengths at ground level, at the edge of a 50 feet R.O.W., for a 138-kV line
are less than one kV/m and typically less than one-half kV/meter for a compact line
design. Public percept ion of health risks associated with EMF from power lines are
generally not associated with electric fields but are focused on the magnetic field
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component. Magnetic field strength is typically measured in milligauss (mG) or
microTeslas (uT) where 1 mG is equal to 0.1 uT. Magnetic fields are not blocked by
most objects or materials. Magnetic field strength also decreases rapidly as the distance to
the power line increases.
No national limits have been established by federal authorities that limit the
public’s exposure to EMF produced from electric power lines. However, other countries
have established exposure guidelines. The Australian exposure guidelines (described as
"interim") were set by the National Health and Medical Research Council in 1989. They
are similar to some other countries. For the general public, the limits are: Electric fields:
5 kV m for 24 hours a day exposure, 10 kV m for a few hours per day, both limits can
be exceeded for a few minutes per day. Magnetic fields: 100 µT (1000 mG) for 24 hours
a day exposure, 1000 µT (10,000 mG) for a few hours per day.
The national Italian EMF limits currently in force were set by Decree of the
Prime Minister in August 2003, replacing a previous decree of 1992. For the general
public, the limits are: Electric fields: 5 kV m-1; Magnet ic fields: 100 µT (1000 mG). In
addition, for magnetic fields, that apply to overhead power lines only, there are two
further values: The attention value: 10 µT (100 mG) applies where exposure is for more
than 4 hours per day. The quality target: 3 µT (30mG) applies to new lines and to new
homes only. (both these values are limits on the daily averages, values at times during the
day can be higher).
Switzerland is, as far as we know, the only country in the world to have set
national limits at power freque ncies based on a precautionary approach to childhood
cancer. The limits were set by an Ordinance of December 1999. It came into force 1 Feb
2001 and existing installations have three years to meet its requirements. The basic limits
are similar to many other countries – 5 kV m and 100 µT (1000 mG).
In 1992, the U.S. Congress authorized the Electric and Magnetic Fields (EMF)
Research and Public Information Dissemination Program. The Congress instructed the
National Institute of Environmental Health Sciences (NIEHS), National Institute of
Health and the DOE to direct and manage a program of research and analysis aimed at
providing scientific evidence to clarify the potential of health risks from exposure to
Electric and Magnetic Fields. In 1999, the NIEHS reported to the U.S. Congress that the
overall scientific evidence for human health risk from EMF exposure is weak.
Many people believe that burying electric power lines will reduce magnetic fields
at ground level. However, this is not the case. Measurements taken at ground level over
underground 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.
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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. In
your home, appliances produce the highest magnetic field levels. At work, computers and
other electrical equipment produce magnetic fields. Table IV-1.1 lists types and levels of
magnetic field strengths in milligauss for common household appliances.
Table IV.1.1
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 earth’s magnetic field averages 500 milligauss.
Table IV-1.2 shows typical levels of magnetic fields, measured in milligauss,
produced by electric transmission and distribution lines.
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Table IV-1.2
The levels of EMF from power lines can be reduced in three primary ways. These
are shielding, field cancellation or through increased distances. Shielding is effective for
electric fields but is of limited effectiveness for magnetic fields. However, field
cancellation and increasing the distance to the power line are both effective in reducing
magnetic field strengths. Magnetic field strength is proportional to the square of the
distance from the line to the point of interest. Therefore, doubling the distance reduces
the field strength by a factor of four. Field cancellation can be achieved by passive and
active means. Passive cancellation is achieved by arrangement and spacing of the phase
conductors. A significant reduction in magnetic field strength at the edge of the R.O.W.
can be achieved by proper arrangement and spacing of the phase conductors. Active
cancellation can be used in certain limited situations. Active cancellation is achieved by
constructing a system of energized electric coils surrounding the area where field
reduction is desired. The system tracks the power line magnetic field and instantaneously
adjusts to compensate for changes. Under optimum conditions, active systems have
reduced the field in the treated area to less than 0.1 mG. Each application is unique
because field intensity, field angles, and available space vary widely.3
3 Source: EMF Services, 3100 Seasons Way #111,Estero, FL 33928, Ph. 888-840-0668, FAX 239-949-
4674, info@emfservices.com
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ROUTE SELECTION Section IV-1.8
It is recommended that between point B to the end of the power line at point N, as
shown on the attached route maps, that steel H-Frame structures, similar to the structure
shown in the above table for a 138-kV transmission line, be used to construct the power
line. (See Section IV-2.). For this type of structure configuration, the power line will rely
primarily on separation between known occupied structures and the centerline of the
R.O.W. to mitigate EMF strength. A review of the attached route maps shows that for
the most part, from point B to the end of the transmission line at point N, the line is
routed some distance away from most villages that are situated along the route of the
transmission line.
In line Section A-B where the transmission line traverses north to south through
Bethel, the power line would be built utilizing single pole structures that would support
both the 138-kV transmission line with a 13.8-kV underbuild circuit . In this section of
line magnetic field strength reduction would primarily be accomplished by proper
arrangement and spacing of the phase conductors. Table IV-1.3 list s the calculated
magnetic field strengths at ground level, at maximum load conditions, for both the 138-
kV transmission line and the 13.8-kV circuit. A significant reduction in magnetic field
strength can be readily achieved by increasing structure height. Supporting calculations
can be found in Appendix C.
Table IV-1.3
Magnetic Field Strength at Ground Level
Distance from
Centerline
0 ft
25 ft
50 ft
100 ft
50 ft Pole Height 75 mg 56 mg 31 mg 11 mg
60 ft Pole Height 49 mg 40 mg 25 mg 10 mg
% Decrease due
to 10’ increase in
Pole Height
35%
29%
20%
10%
D. CORRIDOR CHARACTERISTICS
1. Soil Conditions
The delta lowland area is a lake-dotted marshy plain with many low hills of basalt
and volcanic cinder cones and craters. Elevation is less than 400 feet (120 m). The
lowland is underlain by Quaternary sands and silts to unknown depth. Basalt flows and
cinder cones of Tertiary and Quaternary age exist. Other bedrock consists of Cenozoic
sedimentary rocks with inclusions of various other assemblages. Dominant soils are
Histic Pergelic Cryaquepts and Pergelic Cryofibrists. Soils are shallow over permafrost
and consistently wet.
The river bottomlands represent a collection of flat bottomlands along the larger
rivers of interior Alaska. Although nearly level, broad valleys and basins are typical,
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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some low rolling hills and piedmont slopes do occur. Riparian features, such as
meandering streams and side sloughs, are prevalent. Oxbow, thaw, and morainal lakes are
abundant. Elevation generally ranges from 100 feet (30 m) in the west to 1,640 feet (500
m) in the east. Alluvial fan and basin fill of late Tertiary and Quaternary age are most
common. The bottomlands are underlain mainly by post -accretionary Cenozoic deposits
and various terranes. The dominant soils are Aquepts that have pergelic temperature and
aquic moisture regimes. Specifically, Histic Pergelic Cryaquepts, Pergelic Cryaquepts,
Aquic Cryochepts, Typic Cryochepts, and Typic Cryofluvents predominate. Most soils
were formed by loess and alluvial materials. Loess is a geologic term that refers to
deposits of silt (sediment with particles 2-64 microns in diameter) that have been laid
down by wind action.
2. Wetlands
The proposed transmission line would 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. Alaskan wetlands include salt and freshwater areas influenced by tides,
temperate rain forests and slopes along the southeastern and south central coastlines,
extensive rivers and streams, large river deltas, large and small complexes of lakes and
ponds, and extensive areas of boreal forest and tundra.
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) (USAE,
2003). This includes temporary fills for access roads, boat ramps, and temporary bridges.
Because the overhead lines and support structures will require minimal fill, most of the
impacted wetlands should have negligible or minimal impacts to their overall functions
In order to regulate dredge and fill permits under Section 404 of the 1977 Clean
Water Act, a more concise definition is required: The U.S. Army Corps of Engineers
(Federal Register 1982) and the U.S. Environmental Protection Agency (Federal Register
1980) define wetlands as: Those areas that are inundated or saturated by surface or
ground water at a frequency and duration sufficient to support, and that under normal
conditions do support, a prevalence of vegetation, typically adapted for life in saturated
soil conditions. Wetlands generally include swamps, marshes, bogs, and similar areas.
(Corps Regulation33 CFR 328.3 and EPA Regulations 40 CFR 230.3).
The delta lowlands consists of wet tundra communities co mposed primarily of
sedge mats, moss, and low-growing shrubs. Alder, willows, and scattered, stunted spruce
and birch grow along the major streams. The lowland is crossed by meandering streams
of extremely low gradient. Many are tributaries or former channels of the Kuskokwim
River. Wetlands occupy over 78 percent of the area. Due to the consistently wet soil
conditions the occurrence of wildfires is low. Surface water in streams, lakes, and bogs is
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abundant in most of the area. Permafrost is widespread but discontinuous. Soils are
poorly drained where permafrost exists.
The dominant vegetation in the river bottom communities spans a moisture
gradient from mesic to hydric and includes spruce-poplar forests, open black spruce
forests, floodplain thickets of willow and alder, and graminoid marsh.
3. Forest Cover
Vegetation in the region reflects drainage conditions. The lower poorly drained
soils typically support wet tundra communities of sedge mats and mosses. In moderately
well-drained soils, alder, willow and stunted spruce and birch share the land with wet
herbaceous tundra. Well-drained lowlands usually exhibit stands of white spruce, willow
and paper birch. Alternatively, in the higher elevations, black spruce forest tends to
dominate certain hills and ridges while alder tends to grow along major rivers. Above
treeline, the mountain peaks and ridges support tundra meadows and barrens.
The route between Bethel and Lower/Upper Kalskag lies in the tundra covered
marshy lowlands where the elevation is typically less than 50 feet above mean-sea-level.
This section of the route is essentially barren of trees. There are willow and alder
growths within a quarter to one -half mile corridor along the river that often reach several
feet in height. This section is heavily dotted with numerous large and small lakes. At
Lower/Upper Kalskag there is an abrupt transition between the lowlands and the boreal
forest of the mountainous highlands. From Upper Kalskag to Crooked Creek, white and
black spruce dominate with quaking aspen, balsam poplar and paper birch present locally
as predominate species. The elevation slowly rises from approximately 100 feet at Upper
Kalskag to 200 feet at Crooked Creek. Simultaneously, the sparse forest of the Kalskag
area gives way to an ever increasing forest cover, with maximum forest density occurring
between Aniak and Crooked Creek. Between Cooked Creek and the Donlin Creek mine
site, the terrain climbs rapidly in elevation, from 200 feet at Crooked Creek to
approximately 1,000 feet above mean-sea-level at the mine site. The relatively dense
forest of the Crooked Creek area rapidly gives way to sparse forest cover, tundra covered
slopes and barrens as the elevation increases.
There may be areas between Aniak and Crooked Creek that contain commercial
stands of merchantable timber. The ADNR Division of Forestry will make this
determination during the permitting process. State regulations (Sec. 41.17.082) require
the removal of commercial timber if it is economically feasible to do so. State regulation
11 AAC 95.195 requires special treatment of white spruce to limit the spread of the
spruce bark beetle infestation. For spruce trees or limbs greater than five inches in
diameter, allowable treatment includes manufacturing into cants, lumber, houselogs,
firewood, control burning, chipping and spreading, chemically treated or stored in an
approved manner. No special treatment is required for black spruce.
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4. Fish and Wildlife Habitat
The lakes, streams, and tidal flats of the delta lowlands are interspersed with
tundra and sedge flats, making this area an exceptional habitat for waterfowl, shorebirds,
and furbearers. The Yukon-Kuskokwim Delta supports the highest densities of nesting
tundra swans, most of the world's population of emperor geese, and one-half of the total
population of black brant. All of North America's cackling Canada geese are produced in
these coastal lowlands.
The lakes and wetlands associated with the river bottoms support breeding
populations of common loons, horned grebes, red-necked grebes, and common
goldeneyes. Ruffed grouse, belted kingfishers, alder flycatchers, and Hammond's
flycatchers also frequently breed in the forests of these river valleys. Ptarmigan can be
found both on the tundra covered lowlands and forested regions.
Raptors are uncommon on the delta, but the rough-legged hawk, marsh hawk, and
peregrine falcon in the lowlands and gyrfalcon at higher elevations have been observed.
Bald and golden eagles are rarely seen on the delta although they are common in inland
areas. Sno wy and short-eared owls also occur with the latter more common, particularly
in years when rodents are numerous.
All three forms of Arctic char (anadromous, resident stream, resident lake) occur
here. Sheefish are associated with the Kuskokwim River. All five species of North
American Pacific salmon are indigenous to this area; chum salmon are the most
abundant.
The broad valleys of the middle Kuskokwim River, where tundra begins giving
way to timber, support higher mammal populations than the tundra covered lowlands.
These valleys are covered with mixed spruce-hardwood and muskeg-bog vegetation, and
provide year-round range for moose. Caribou are found in the mountain ridges in the
middle to upper reaches of the Kuskokwim River drainage. This habitat supports red
squirrels and furbearers such as beaver, river otter, muskrat, mink, martin, ermine, fox,
lynx, and wolverine and wolf. Beaver, muskrat, and fox are the primary furbearers
harvested in the region. River otters are abundant; short-tailed and le ast weasels are
common. Wood frogs have been reported in the eastern portion of this area.
Wolves and wolverines forage year-round in various habitats from the main river
channels to high mountain ridges. Brown bear and black bear are encounter in these
same areas.
5. 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
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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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.
6. Floodplain
The power plant and transmission lines would be located within the Kuskokwim
River floodplain. Neither the transmission line nor its support towers would 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.
7. 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. Mr. Greg Balogh and Mr. Michael Jimmy
of the Yukon Delta NWR were contacted to confirm this finding. The USFWS and
National Marine Fisheries Service (NMFS) 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.
8. Essential Fish Habitat
NMFS considers the Kuskokwim River as Essential Fish Habitat (EFH) under the
Magnuson-Stevens Act. Many creeks and rivers 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, chu m
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 be required to
determine EFH impacts and what mitigation measures will required. The construction of
temporary ramps, river access points, small bridges, and river crossings will require EFH
assessments.
9. 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)” 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.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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E. TRANSMISSION LINE 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 would
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 R.O.W. permits will be required
from the land owners to access and perform construction within the transmission line
R.O.W. Temporary ramps, roads, supply and housing structures will be needed to stage
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 to maintain the
transmission line. However, a primitive 12-feet travel way would be grubbed, i.e. stumps
removed, within the R.O.W., to allow movement of construction and maintenance
equipment where terrain permit s. The transmission lines would be maintained via off-
road vehicles, boats and helicopters. Clearing of the R.O.W. will, to the maximum extent
practicable, be limited to structure locations and danger trees that may contact phase
conductors.
Trees and undergrowth would 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
minimize erosion and adverse effects on tundra, birds, fish, wetlands and EFH.
Construction activities may impact water quality due to erosion and runoff. 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.
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ROUTE SELECTION Section IV-1.14
F. ROUTE SELECTION CRITERIA
Several practical criteria were established to provide guidance in the route
selection process. To the maximum extent reasonable, without jeopardizing the economic
or technical feasibility of the transmission line, the following criteria were used:
1. Site the line on private lands owned by the various native corporations.
2. If the line cannot be sited on native corporation owned lands, site the line on
lands that have been selected by the corporations or are owned by the state of
Alaska.
3. Avoid placing the line, to the maximum extent reasonable, on native allotment
lands.
4. Avoid placing the line, to the maximum extent reasonable, on federally owned or
controlled lands.
5. Wherever practical, locate the line within one-half mile of the Kuskokwim River.
6. Site the line to avoid conflicts with known or planned airports and runways.
7. To the extent reasonably possible, avoid river crossing, avalanche chute and
unstable soils.
8. Conform wit h construction recommendations from the public , consistent with
other selection criteria.
G. DESCRIPTION OF ROUTE SEGMENTS
Based on the above criteria this study has identified a single preferred route
alternative, which is approximately 191 miles in length. One purpose of this route
selection is to allow further identification of typical transmission components and
develop cost estimates. The line is divided into thirteen segments. Except for segment
A-B, the segments range between 13 to 17 miles in length. For the most part the route
traverses private lands owned by various native corporations that have either been
conveyed to the various native corporations or have been selected for conveyance. Except
for 11.4 miles of lands selected by TKC that have yet to be conveyed, a mile section of
BLM land and 6.4 miles of State lands, the remainder of the line corridor traverses native
corporation owned lands. To minimize permitting efforts, the transmission line was
intentionally routed to avoid crossing Yukon-Kuskokwim Delta Wildlife Refuge lands
and, to the maximum extent possible, state and other federal lands. At approximately line
mile 113, the transmission line corridor exits the boundaries of the Yukon-Kuskokwim
Delta Wildlife Refuge.
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It is anticipated the entire route between Bethel and Upper Kalskag is underlain
with permafrost soils. At Kalskag the terrain increases in elevation as the route enters the
foothills of the mountainous highlands. It is anticipated that between Kalskag and the
Donlin Creek mine site, granular, moderately drained soils will predominate with
interspersed areas of permafrost. Maps at the end of this section show the various route
segments. Table IV-1.4 summarizes selected information for each segment , including
land ownership status. Each route segment is discussed individually following the table .
1. Segment A-B (Length 6.0+0.2 miles)
This 6.0+0.2 mile segment originates south of Bethel at the proposed location of
the new power plant. Depending on the exact lo cation of the power plant, the
transmission line route will proceed west for approximately 0.5+0.2 mi before turning
north and traversing south to north through the community of Bethel. The route attempts
to follow existing property lines and roadways to the extent reasonable, which produces
several large line angles. In certain locations, it may be difficult to guy these large angles
and self supporting steel towers may be required. However, this decision will be made
during the final design phase. A compact line design will be used in this segment to limit
right -of-way width requirements to fifty feet. A 13.8-kV circuit would be under-built
along the first 2.0+0.2 miles of the transmission line. At this point the under-build
distribution line would turn east for approximately 1,500 feet where it would connect into
the existing Bethel Utilities power plant substation through a step down transformer. This
segment traverses lands owned by the Bethel Native Corporation, privately owned
parcels, including nat ive allotments and the City of Bethel.
2. Segment B-C (Length 15.9 miles)
This segment veers east -northeast for approximately 9.5 miles toward the village
of Akiachak. A step-down substation would be constructed at line mile 19.7, to serve the
electrical needs of the village. A 12.47/7.2-kV distribution line, approximately six-tenths
of a mile in length, would be constructed to connect the village with the step-down
substation. This segment of line then continues on for another 2.2 miles to Point C. This
segment of line crosses marshy lowlands composed of fine grain sands and silts that are
dotted with numerous small lakes and small streams. This segment traverses lands owned
by the Bethel Native Corporation and Akiachak Ltd and avoids native allotments and
privately owned lands.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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ROUTE SELECTION Section IV-1.16
TABLE IV-1.4 – Summary of Selected Information for Each Route Segment
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
Mile 26.2
D-E 16.6 56.5 39 61 Tuluksarmute Tuluksak Substation at
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
Exits Y-K Refuge at Mile
113.2
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 Ck
Mine Substation at Mile
191.2
3. Segment C-D (Length 16.0 miles)
This segment veers east for approximately 4.3 miles to a point near the village of
Akiak. A step-down substation would be constructed at line mile 26.2, to serve the
electric al needs of the village. A 12.47/7.2 kV distribution line, approximately nine-
tenths of a mile in length, would be constructed to connect the village with the step-down
substation. This segment of line then turns north and continues on for another 11.7 miles
to Point D, paralleling the west bank of the Kuskokwim River. This segment of line
crosses marshy lowlands composed of fine grain sands and silts that are dotted with
numerous small lakes, small streams and sloughs. This segment traverses lands owned by
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the Akiachak Ltd., Korarmiut Corp., and Tuluksarmute, Inc. and avoids privately owned
parcels.
4. Segment D-E (Length 16.6 miles)
This segment continues north for approximately 5.7 miles where a proposed step-
down substation will be constructed to serve the electrical needs of Tuluksak at line mile
43.4 A 12.47/7.2-kV distribution line, approximately 2.4 miles in length, would be
constructed to connect the village with the step-down substation. This overhead
distribution line would span the Kuskokwim River. The transmission line then continues
northeast for another 10.9 miles to point E. This segment of line crosses marshy lowlands
composed of fine grain sands and silts that are dotted with numerous small lakes, small
streams and sloughs. This segment traverses lands owned by the Tulu ksarmute, Inc. and
avoids privately owned parcels.
5. Segment E-F (Length 15.6 miles)
This segment continues north for 15.6 miles. This segment of line crosses marshy
lowlands composed of fine grain sands and silts that are dotted with numerous small
lakes, small streams, sloughs and side channels of the Kuskokwim River. This line
segment traverses lands owned by Tuluksarmute, Inc., The Kuskowkwim Corporation as
well as 4.2 miles of land selected by TKC that has not been conveyed. No private parcels
are traversed by this segment of line.
6. Segment F-G (Length 15.5 miles)
This segment continues north for 3 miles before turning northeast toward the
villages of Upper and Lower Kalskag, terminating at Point G, which is located
approximately one-fourth of a mile north of Upper Kalskag. A step-down substation
would be constructed near point G, line mile 85.6, to serve the electrical needs of the
village. A 12.47/7.2-kV distribution line, approximately one-half of a mile in length,
would be constructed to connect the village with the step-down substation. This segment
of line crosses marshy lowlands composed of fine grain sands and silts that are dotted
with numerous small lakes, small streams, sloughs and side channels of the Kuskokwim
River. At Point G the line route climbs out of the lowlands and enters the foothills of the
Portage Mountains. This line segment traverses lands owned by the TKC as well as 2.8
miles of land selected by TKC that has not been conveyed. No private parcels are
traversed by this segment of line.
7. Segment G-H (Length 15.3 miles)
From Point G the line travels east along the north bank of the Kuskokwim River
to Point H. This line segment traverses lands owned by TKC and ele ven native allotment
parcels located on the north bank of the Kuskokwim River. The elevation of this segment
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rises rapidly as the line climbs out of the Kuskokwim River delta lowlands and enters
mountainous terrain.
8. Segment H-I (Length 16.1 miles)
This segment of line proceeds east along the north bank of the Kuskokwim River
for a distance of 9.8 miles where a proposed step-down substation will be constructed to
serve the electrical needs of Aniak at line mile 110.6. A 12.47/7.2-kV distribution line,
approximately 3.2 miles in length, would be constructed to connect the village with the
step-down substation. Approximately one-half mile of this line would be constructed
overhead and would span the Kuskokwim River. The remainder of the line will be
constructed underground to avoid conflict with aircraft traffic arriving and departing the
Aniak airport. From the substation location, the line continues eastward for another 6.3
miles to Point I, traversing lands owned by TKC and ten native allotment parcels located
on the north bank of the Ku skokwim River. The transmission line exits the Y-K Delta
Wildlife Refuge at approximately line mile 113.2
9. Segment I-J (Length 15.8 miles)
This segment of line proceeds east along the north bank of the Ku skokwim River
for a distance of 6.8 miles where a step-down substation will be constructed to serve the
electrical needs of Chuathbaluk at line mile 123.4. A short 12.47/7.2-kV distribution line
will be constructed to connect the village with the step-down substation. The line
continues eastward, from the substation, for another 9 miles to Point J, traversing both
lands owned by TKC and lands selected by TKC that have not been conveyed. The route
also crosses six native allotment parcels located on the nort h bank of the Kuskokwim
River.
10. Segment J-K (Length 13.3 miles)
This segment of line proceeds east along the north bank of the Kuskokwim River
for a distance of 13.3 miles to Point K. The line traverses both lands owned by TKC and
lands selected by TKC that have not been conveyed. The route also crosses five native
allotment parcels located on the north bank of the Kuskokwim River.
11. Segment K-L (Length 14.4 miles)
This segment of line proceeds northeast along the bank of the Kuskokwim River
for a distance of 14.4 miles to Point L. The line traverses over one mile of BLM lands
and 4.2 miles of State lands. The remaining line segment traverses lands owned by TKC
but does not cross any native allotment s.
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12. Segment L-M (Length 17.0 miles)
This segment of line proceeds north along the bank of the Kuskokwim River for a
distance of 17.0 miles to Point M, which is located 1.4 miles southwest of Crooked
Creek. The line crosses 2.1 miles of state lands. The remaining line segment traverses
lands owned by TKC and two native allotments.
13. Segment M-N (Length 13.7 miles)
This segment of line proceeds north for a distance of approximately 0.4 miles
where a proposed substation will be constructed to serve the needs of Crooked Creek at
line mile 177. A 12.47/7.2-kV distribution line, approximately 1.5 miles in length, will
be constructed to connect the village with the step-down substation. The line continues
north from this point to the Donlin Creek mine where the line will terminate in a step-
down substation constructed by Placer Dome, Inc. The line segment traverses lands
owned by TKC and one native allotment.
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentRoute OverviewBettine, LLCBethelAniakDonlin CreekFigure IV-1.1
Land-Based Power Plant This Area
+ 80 Acres
Nuvista Light & Power, Co.
Donlin Creek Transmission Line
Preliminary Route Alignment
Line Section A-B
Map 1 of 13
Bettine, LLC
Barge-Mounted Power Plant
+ Fuel Storage This Area
Point B @ 6.0 mi.
Section A-B @ 6.0 mi.
Point A @ 0.0 mi.3543' @ 270
1500' 13.8 kV
13.8 kV Underbuild
to This Point
Barge Mounted Power Plant+ Fuel Storage This AreaLand-Based Power Plant+ Fuel Storage This AreaDock AreaNuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentExpanded View Line Section A-BMap 1ABettine, LLC01000'SCALEScale in Feet138 kV Transmission Line + 13.8 kV underbuild
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentExpanded View Line Section A-BMap 1BBettine, LLC01000'SCALEScale in FeetBethel PowerPlant138 kV TransmissionLine13.8 kV DistributionEnd Underbuild
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentExpanded View Line Section A-BMap 1CBettine, LLC01000'SCALEScale in Feet
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentLine Section B-CMap 2 of 13Bettine, LLCSection A-B @ 6.0 mi.Point B @ 6.0 mi.Point C @ 21.9 mi.3800' 12.47/7.2 kVDistribution LineProposed AkiachakSubstation@ mi. 19.7
Proposed AkiakSubstation LocationNuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentLine Section C-DMap 3 of 13Bettine, LLCPoint C @ 21.9 mi.Point D @37.9 mi.Akiak4800 ' 12.47/7.2 kVDistribution LineAkiakProposed AniakSubstation @ mi. 26.2
Nuvista Light & Power, Co.
Donlin Creek Transmission Line
Preliminary Route Alignment
Line Section D-E
Map 4 of 13
Bettine, LLC
Point D @ 37.9 mi.
Proposed Tuluksak
Substation @ mi. 43.4
2.35 mi. 12.47/7.2 kV
Distribution Line
Point E @ 54.5 mi.
Nuvista Light & Power, Co.
Donlin Creek Transmission Line
Preliminary Route Alignment
Line Section E-F
Map 5 of 13
Bettine, LLC
Point E @ 54.5 mi.
Point F @ 70.1 mi.
TKC Selected 4.3 mi.
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentLine Section F-GMap 6 of 13Bettine, LLCPoint F @ 70.1 mi.Point G @ 85.6 mi.Proposed KalskagSubstation @ mi. 85.6with 1500' 12.47/7.2 kvDistribution Line TKC Selected 2.8 mi.
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentLine Section G-HMap 7 of 13Bettine, LLCPoint G @ 85.6 mi.Point H @ 100.9 mi.
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentLine Section H-IMap 8 of 13Bettine, LLCPoint H @ 100.9 mi.Point I @ 117.0 mi.Proposed Aniak Substation @ mi. 110.62900' 12.47/7.2kVOverhead Line3+ mi. Underground to Connectwith Exisiting Distribution
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentLine Section I-JMap 9 of 13Bettine, LLCPoint J @ 132.8 mi.Point I @117.0 mi.Proposed ChuathbalukSubstation @ mi. 123.4New Airport LocationTKC Selected1.0 mi.
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentLine Section J-KMap 10 of 13Bettine, LLCTKC Selected 3.4 mi. TKC Selected1.1 mi.Point J @ 132.8 mi.Point K @ 146.1 mi.
Nuvista Light & Power, Co.Donlin Creek Transmission LinePreliminary Route AlignmentLine Section K-LMap 11 of 13Bettine, LLCState Lands 3.8 mi.State Land 0.4 mi.BLM Lands 1.0 mi.Point L @ 160.5 mi.Point K @ 146.1 mi.
Nuvista Light & Power, Co.
Donlin Creek Transmission Line
Preliminary Route Alignment
Line Section L-M
Map 12 of 13
Bettine, LLC
Point L @ 160.5 mi.
Point M @ 177.5 mi.
State Lands 0.6 mi.
State Lands 1.5 mi.
Nuvista Light & Power, Co.
Donlin Creek Transmission Line
Preliminary Route Alignment
Line Section M-N
Map 13 of 13
Bettine, LLC
Point M @ 177.5 mi.
Point N @ 191.2 mi.
Donlin Creek Mine Substation
Proposed Crooked Creek
Substation @ mi. 177.8
1.4 mi. 12.47/7.2 kV
Overhead/Underground
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.1
SECTION IV-2 TRANSMISSION LINE FEASIBILITY
DESIGN
A. INTRODUCTION
Nuvista Light & Power, Co. is proposing to construct a centralized power plant at
Bethel in combination with a 191 mile, 138-kV transmission line from Bethel to Donlin
Creek mine, as a means of providing power to the Donlin Creek mine and eight villages.
The feasibility design for the 138-kV Donlin Creek transmission line portion of this
project is discussed below.
B. VOLTAGE SELECTION
1. Donlin Creek Mine Transmission Line
There were three transmission voltage levels investigated during the conceptual
study1 for supplying power to the Donlin Creek gold mine project, from a centralized
power plant located in Bethel. Voltage levels considered were 69-kV, 138-kV and 230-
kV. Initial power flow studies revealed that a transmission voltage of 69-kV provided
unacceptable performance. Additional power flow studies indicated that a transmission
voltage of either 138-kV or 230-kV would provide satisfactory electrical performance.
Several factors were then examined to determine which of these two voltage levels
should be selected. These factors included system electrical performance, line losses,
transmission line construction costs, and associated substation construction costs. Based
on these factors the 138-kV transmission voltage level was selected as most appropriate
voltage level.
Additional system studies were conducted by Electric Power Systems, Inc. (EPS)
as part of this feasibility study to confirm that a 138-kV transmission voltage would
adequately serve the assumed long -term power needs of the Donlin Creek mine and the
Calista region. These studies have confirmed that an average mine load of up to 70
megawatts can satisfactorily be supplied by a 138-kV transmission line using a conductor
size of 954 ACSR or equivalent. The system studies are discussed in subsequent sections
of the report.
C. SUMMARY OF ELECTRIC POWER SYSTEMS, INC. (EPS) STUDY2
EPS was retained as a subconsultant to perform electrical system studies on the
proposed 138-kV Donlin Creek transmission line, Bethel power plant alternative. These
studies included steady-state power flow, short circuit, switching and transient stability
simulations. The system as modeled for each study included the proposed 138-kV
1 Calista Region Energy Needs Study Part I, July1,2002.
2 See Appendix D for complete EPS study.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.2
transmission line and either a coal-fired or combined-cycle combustion turbine plant
located at Bethel.
Results of the study shows that the proposed 138-kV Donlin Creek transmission
line is technically feasible and provides acceptable steady-state performance under
various load levels. The study assumes a Static Var Compensation (SVC) station is
constructed at the Donlin Mine substation by Placer Dome, Inc.
Transient stability studies indicate that a 10 MVA reactor should be installed at
the Aniak substation to limit voltage rise to acceptable limits when energizing the
transmission line. These studies assume that the 138-kV line is de-energized and all load
and transformers along the load are offline. The line is then energized by closing the 138-
kV breaker at Bethel, picking up the line all the way to Donlin Mine on the 138-kV side.
Should the average mine demand exceed approximately 60 megawatts, the results
of the study show that it would be prudent to install an SVC station at Aniak, although a
series of switchable capacitor banks could be used. While a bank of switchable capacitors
would provide acceptable steady state voltages, an SVC would provide better control of
transient voltage, especially when controlling voltage during mine outages or when
energizing the line.
1. Power Flow Simulations
Power flows were run for the proposed system with Bethel and village loads at
year 2040 project ions and mine loads of 0, 55, 70, and 85 MW. The three mine loads of
55, 70 and 85 MWs were included to span the possible load demand range of the mine.
Placer Dome, Inc. engineers have indicated that the connected mine load would most like
range between 70-85 MWs, with approximately 80% of the connected load operating at
any one time. Therefore, this study assumes that for 70 MWs of connected mine load, the
actually operating demand would be approximately 55 MW, and for 85 MW of connect
load the operating demand would be approximately 70 MWs and that the maximum
possible mine demand would be 85 MWs, which represents the maximum anticipated
connected load.
The initial power flow results indicated a need for additional voltage support
along the 138-kV transmission line during heavy mine loading periods. It was assumed
that Placer Dome, Inc. would install an SVC at the mine substation. The size of the SVC
to be provided at Donlin Mine was unknown. Power flows with the mine load at 55 MW
and only one SVC located at the mine showed low voltages on the 12.47-kV distribution
bus at Crooked Creek of 95.7%, with full tap changer control, with the mine SVC output
of 31.7 MVAR. The SVC was set to regulate the mine 13.8 kV, low-voltage bus, to 1.0
per unit. When the mine load increased to 85 MW, with only one SVC located at the
mine, all voltages decreased with the 12.47-kV bus at Crooked Creek decreasing to
88.5%, with a Donlin Mine SVC output of 81.5 MVAR. Under heavy loading conditions
it would be necessary to install an SVC or a bank of switchable capacitors at the Aniak
substation, which is located roughly midway along the transmission line. While a bank of
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.3
switchable capacitors would provide acceptable steady state voltages, an SVC provides
better control of transient voltage, especially when controlling voltage during mine
outages or when energizing the line.
The calculated voltages on the 12.47-kV buses at the remote village substations
are based on using typical distribution transformer impedances (from American National
Standard C57.12.10 and Industrial Power System Handbook by Beeman) and based on
using a transformer with LTC capability of ±10% tap. All distribution voltages were
regulated to the range from 99% to 101% voltage within available taps. Voltages could
be improved further by improving the load power factor, and/or adding distribution
capacitors. The loads used in these studies are worst case maximum peak scenarios,
expected in the year 2040. The most significant voltage problem occurs at Crooked Creek
on the 12.47-kV bus. The power flow results indicate a need to provide some corrective
action or replace the Crooked Creek transformer with a larger transformer if the mine
load and Crooked Creek loads begin to approach their maximum assumed values.
2. Transient Stability Simulations
Transient stability simulations were conducted using the PSS/E software.
Simulations included loss of generation, loss of mine load, motor starting, and line
energizing. Typical dynamics data from other generators of comparable size were used
for the proposed generating units at Bethel Power Plant.
a. Loss of Generation
Transient stability analysis assuming the loss of the largest on-line unit at Bethel
Power Plant was conducted. This outage was run for the maximum load case, Donlin
mine at 85 MW. In order to survive this outage, load shedding must occur somewhere in
the system. For study purposes, load shedding relays were placed at the Donlin mine, in
3 stages. Each stage sheds 25% of the mine load, with stages set at 59.0, 58.7, and 58.4
Hz. These settings are somewhat arbitrary, but show that a unit loss can be survived with
appropriate load shedding. Load may be shed on the distribution system or at the mine.
The only significant issue is to have enough load on load shedding to exceed the largest
anticipated loss of generation. Transient stability results show a frequency decay to just
below 58.4 Hz, with all three stages of load shedding picked up. The frequency then
recovers to 60 Hz.
b. Loss of Mine Load
The transient stability simulation for the complete lo ss of the mine load represents
a 138- kV breaker opening at Donlin Mine. The mine load is lost along with the Donlin
SVC. Simulations were run at both 55 and 85 MW of mine load. Simulations show a
transient frequency rise to around 61.5 Hz for a mine lo ad of 55 MW, and 62.7 Hz for a
mine load of 85 MW, returning to nominal in 11 seconds. The Aniak SVC regulates the
138-kV line voltage very quickly back to near 1.0 per unit. The transient frequency rise
is significant due to the large percentage of total system load residing at Donlin Mine.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.4
Remedial action schemes have not been studied to reduce the over-frequency conditions,
but a remedial action trip of one or more Bethel units would significantly reduce the
over-frequency magnitude. Alternately, staggered over-frequency relaying of the Bethel
units could be used to trip generation without a transfer trip signal from the mine.
Acceptable over-frequency conditions for the generating units should be discussed with
generator/turbine suppliers.
c. Motor Starting
Transient stability simulations were run for a motor starting condition at Donlin
Mine from preliminary mine load estimates the largest single load appears to be the Sag
Mill, sized at 9.12 MW. It may be unrealistic to expect the total Sag Mill load to be a
single motor, started under full load, but this case was used to define the worst case motor
starting scenario. An induction motor was used to represent the Sag Mill load, and was
started under full load. Typical induction motor parameters were used for the model.
The initial simulations showed a prolonged under -voltage condition during the
motor start. A subsequent simulation was run using a reduced voltage start for the motor,
at 60% nominal voltage. The initial condition power flow case had a mine load of 70
MW, with the motor providing an additional 9.12 MW of load when started. The Donlin
Mine SVC was included in the simulation. Simulations show a prolonged under-voltage
condition in the system during the motor start. Simulations show the Donlin 138-kV bus
voltage below 90% for almost 10 seconds. The motor takes near ly 12 seconds to reach
full speed. In order to refine these studies and determine the actual system impact of a
large mine motor start, a better understanding is needed of the largest expected motor and
its load at startup. A motor start condition at Donlin Mine may be the worst case scenario
in terms of voltage, and may be the defining case for sizing the Donlin Mine SVC
system.
d. 138-kV Line Energization
Transient stability simulations were run to evaluate the system voltage profile
when the 138-kV transmission line is energized. These cases assume that the 138-kV
line is de-energized and all load and transformers along the load are offline. The line is
then energized by closing the 138-kV breaker at Bethel, picking up the line all the way to
Donlin Mine on the 138-kV side. Discussions with SVC manufacturers indicated that the
usual method for starting a line with SVC systems along the line and voltage control
issues was to use a small fixed reactor on the secondary of the SVC transformer, and then
switch out the reactor when the SVC comes online. To simulate this, cases were run with
no fixed reactor at Aniak, and then again with a 10 or 20 MVAR fixed reactor at Aniak,
to determine the line voltage profile and the required size of the secondary reactor. The
case with no reactor showed a transient voltage of near ly 118% at Donlin on the 138-kV
bus, with a steady state voltage of 114%. The case with a 10 MVAR showed a transient
voltage of 110% and a steady state voltage of 108% at Donlin. The case with a 20
MVAR reactor showed a transient voltage of 103% and a steady state voltage of 103% at
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.5
Donlin. The 10 MVAR reactor should provide acceptable voltage performance for the
short time before the mine SVC can come online and regulate voltage.
3. Short Circuit Simulation
Short circuit current analysis was conducted on the system. The primary purpose
was to determine the required short circuit rating of equipment. Of special concern is the
magnitude of short circuit currents at the existing Bethel Utilities diesel substation bus.
EPS has calculated the maximum three-phase short circuit fault current at the Bethel
substation 4.16-kV bus at approximately twenty thousand amperes. Should this fault
current exceed the short-circuit rating of the existing Bethel diesel plant substation
equipment, correct ive measures will need to be undertaken that limits fault current
energy. One method to limit fault current energy is by using current limiting device on
the 4.16-kV bus. A second method would be to increase the impedance of the 4.16-kV
transformer winding.
D. DESIGN CRITERIA
1. Electric Loading
The Donlin Creek transmission line would be designed to serve an average mine
load in the range of 60 MW, with the capability of serving a maximum mine load of 85
megawatts. However, electrical performance at the 85 MW demand level would be
marginal and would require the addition of a large SVC system at the Aniak substatio n.
The basic conductor selected for the transmission line is 954 ACSR, Cardinal, or
equivalent. Based on supplying a steady state mine load of 60 MWs, the anticipated
average mine demand, at 0.95 power factor, line losses are in the range of about 5% and
maximum voltage drop calculated at any of the eight village substation bus is 4.7%,
which occurs at Crooked Creek. These calculations assume an SVC system is installed at
the mine substation to maintain a one per unit voltage at the mine substation under
normal operating conditions and that all village loads connected to the transmission line,
including the Yukon SWGR feeder, are at year 2040 projected load levels. Calculated
line losses of 5% and maximum voltage drop of 4.7% are within the range of acceptable
values for a feasibility level study.
2. Ampacity
The conductor selected for the Donlin Creek transmission line is 954 ACSR or its
equivalent. The approximate ampacity rating of this conductor is 1010 amperes. This
assumes a conductor temperature of 75oC, an air temperature of 25oC, and a 1.4 miles per
hour wind. Resistance of the conductor is 0.1035 ohms per mile. Based on supplying a
steady state mine load of 57.5 MVA, plus village and Yukon Feeder SWGR loads
totaling 10 MVA, for a total of 67.5 MVA, per phase current is calculated at 275
amperes. This is approximately 27% of rate current capacity. Assuming a maximum
mine demand of 85 MWs or 89 MVA, plus village and Yukon Feeder SWGR loads
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.6
totaling 10 MVA, loading on the conductor is calculated at 415 amperes, or about 41% of
rate current capacity. A maximum ambient temperature of 90oF has been selected for
computation of maximum conductor temperature for the 138-kV transmission line. Using
a 90oF ambient temperature and assuming a Donlin Creek mine load of 85 megawatts, the
maximum conductor temperature of 122 oF 3, 4 will not be exceeded for 954 ACSR or an
electrically equivalent conductor.
E. WEATHER DATA
Weather data is critical for determining reasonable physical loading criteria. This
includes information on ambient temperatures, windspeed and direction, ice and snow
accumulations, snow depths, and isokeraunic levels (i.e. thunderstorm activity). Weather
data along the proposed transmission line corridor is limited. Weather data has, however,
been collected from a variety of sources for ten different western Alaska locations that
are listed in Table IV-2.1. Four of these recording stations, Bethel, Aniak, Crooked Creek
and McGrath are considered representative of the weather that will be encountered along
various segments of the route. The collected weather data and its application in
formulating reasonable physical loading criteria are discussed in the subsequent
paragraphs.
1. General
The 138-kV transmission line corrid or spans two distinct climate and topographic
zones. The “southern” portion of the transmission line or zone is defined as the section of
the line located between Bethel and Upper Kalskag. Upper Kalskag is situated on the
Kuskokwim River approximately 75 miles upstream of Bethel and 25 miles down stream
of Aniak. Upper Kalskag is located on the foothills of the Portage Mountain range. The
“southern” zone is located in the Kuskokwim River delta region, with a maximum
elevation of less than 100 feet MSL. The “southern” zone is characterized by somewhat
milder temperatures and decreased snow depths as compared to the “northern” section.
The “northern” zone is the section that extends from Upper Kalsag to the Donlin
Creek mine site. At Kalskag the terrain along the route of the transmission line gradually
rises from 100 feet. above mean sea level (MSL) to an elevation of approximately 1,000
feet above MSL at the Donlin Creek mine site.
Temperature and snow depth records for ten different western Alaska locations
are listed in Table IV-2.1. Four of these recording stations, Bethel, Aniak, Crooked Creek
and McGrath are considered representative of the temperatures and snow depths that
would be encountered along the route of the 138-kV transmission line between Bethel
and the Donlin Creek mine site. Of these four stations, McGrath and Crooked Creek have
3 It is anticipated that the 138-kV transmission line will be built using 954 ACSR or an equivalent
conductor. Final conductor selection will be made during the design phase.
4 Maximum conductor temperature estimated from information discussed in Westinghouse Electrical
Transmission and Distribution Reference Book, Chapter 3, 1964.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.7
recorded the most extreme high ambient temperature of 90oF with McGrath and Aniak
recording extreme low temperatures of -75oF and -72oF, respectively.
TABLE IV-2.1
Temperature (degrees Fahrenheit)
and
Snow Depths (inches)
Station
Period of
Records
Temp.- Extreme
oF
Highest/Lowest
Temp. - Monthly
Mean oF
Highest/Lowest
Temp.- Annual
Mean oF
Highest/Lowest
Snowdepth
(Inches)
Extreme/Max.
Monthly Avg.
Aniak 1949-1990 87/-72 65.2/-7.3 36.8/19.7 75/20
Bethel 1949-2001 86/-48 62.7/-0.8 36.8/22.1 45/10
Crooked Creek 1949-1974 90/-55 69.7/-14.5 38.2/17.3 34/15
McGrath 1939-2001 90/-75 68.5/-17.3 35.4/16.0 70/26
Emmonak 1977-1994 80/-50 60.7/-1.7 36.0/21.4 62/26
Holy Cross 1931-1975 89/-62 66.7/-7.0 37.0/20.4 130/39
Mekoryuk 1949-1973 76/-39 54.5/2.5 34.9/23.5 47/19
Mountain Village 1949-1963 83/-41 61.5/-4.2 35.3/20.8 57/25
Platinum 1949-1964 82/-29 57.5/6.7 37.7/25.6 21/7
St. Mary’s 1967-2000 84/-44 63.7/-0.8 37.5/21.8 42/17
Source: Alaska Climate Summaries at www.wrcc.dri.edu/summary/climsmak.html
2. Ambient Temperature
Several ambient temperatures are of interest in evaluating transmission line
designs. These include maximum summer temperature fo r determining maximum
operating temperature, extreme minimum temperature for evaluating uplift on
transmission structures, and the average annual minimum temperature (AAMT), which is
used to evaluate tension limits to control aeolian vibration for certain types of conductors.
A maximum ambient temperature of 90oF has been selected for computation of
maximum conductor temperature for the 138-kV transmission line. Using a 90oF ambient
temperature and assuming a Donlin Creek mine load of 85 megawatts, the ma ximum
conductor temperature of 122oF 5, 6 will not be exceeded for 954 ACSR or electrically
equivalent conductors.
An extreme minimum temperature of -70oF would typically be used to investigate
sag-tension limits for that “northern” section of the 138-kV transmission line. An extreme
minimum temperature of -50oF would normally be used to investigate sag-tension limits
for that “southern” section of the 138-kV transmission line. However, for the purposes of
this study a single extreme minimum temperature of -70oF will be used. A single extreme
5 It is anticipated that the 138-kV transmission line will be built using 954 ACSR or an equivalent
conductor. Final conductor selection will be made during the design phase.
6 Maximum conductor temperature estimated from information discussed in Westinghouse Electrical
Transmission and Distribution Reference Book, Chapter 3, 1964.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.8
minimum temperature is being used because this temperature extreme will not control
sag-tension limits, except in very short spans and in uplift situations.
The AAMT is used to establish aeolian vibration limits. In areas prone to aeolain
vibration it is recommended that a value of approximately 20 percent at AAMT, if other
means of controlling vibration are not used such as dampers or self-damping conductors.
For this feasibility study an AAMT temperature of -15oF will be used for the entire length
of the 138-kV transmission line.
3. Snow Ground Cover
Table IV-2.1 also list the extreme maximum and maximum monthly snow depth
for the ten recording stations. The extreme maximum snow depth recorded at any of
these locations was 130 inches at Holy Cross, which is located on the northern bank of
the Yukon River some 50 miles north of the nearest approach of the transmission line.
Extreme snow depths for the remaining nine locations range between 21 inches and 75
inches. Using the average of the extreme snow depths for Bethel, Aniak, Crooked Creek
and McGrath, rounded to the nearest foot, design value of 5 feet or 60 inches will be used
for the entire length of the transmission line. This design value will be used to establish
NESC clearances between the overhead conductors and the top of the snow pack.
4. Conductor Ice and Snow Accumulation
The selection of ice and snow loading criteria has long been a subject of
discussion in Alaska. Significant accumulations of ice and snow have been observed on
several lines, including the Healy-Willow intertie, the Glennallen-Valdez intertie, the
Terror Lake transmission line and the Tyee Lake intertie located in Southeast Alaska.
Although each of these lines have experienced excessive sags due to excessive
accumulation of ice and snow, no outright failures have been experienced.
CEA, MEA, CVEA and AVEC design their distribution lines to NESC Heavy
loading conditions and reportedly these utilities have suffered few if any failures
attributable to excessive ice and snow loading. The 8.5 mile SWGR transmission line
built in 1981, between Bethel and Napakiak, was designed to accommodate NESC Heavy
loading and has not suffered any failures attributable to excessive snow and ice loading.
The recently constructed Northern Intertie, built between Healy and Fairbanks
was designed for an extreme ice loading of one (1) inch radial ice along the non-
mountainous Tanana Flats section of the route. The elevation of this section of the
transmission line varies from approximately 400 to 800 feet MSL.
An extreme ice loading design criteria of one (1) inch of radial ice will be used for
the 138-kV transmission line. This is typical of the extreme ice loading design used on
other major transmission lines in Alaska as discussed.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.9
Selecting design criteria always involves a trade-off between reliability and costs.
It is reasoned that, although it is possible to design the 138-kV transmission line to
accommodate a greater ice loading or an equivalent ice and snow loading, it is recognized
that it is better to accept the risk of greater than anticipated ice loading and consequent
conductor snow/ground contact and/or conductor failure than the certainty of increased
capital cost for improved reliability. Although the above-selected extreme ice loading
criteria is representative of the ice loading that could be expected during the life of the
transmission lines, it is recommend ed that a meteorological consultant be hired to
confirm these loading criteria prior to final design.
5. Extreme Wind
Record maximum one-minute hourly winds and average annual wind speeds at 30
feet above ground for six recording stations are listed in Table IV-2.2, columns (2)-(4).
Based on the maximum one-minute hourly winds an estimated extreme 5-second gust has
been calculated and listed in column (5).
TABLE IV-2.2
Wind Speeds
(1)
Location
(2)
Max. Wind
Speed
Speed MPH/Dir.
Through 1998
(3)
Max. Wind
Speed
Speed MPH
Through 1977
(4)
Avg. Annual
Wind
Speed MPH
(5)
Estimated
Extreme
5-Second
Gust MPH
Bethel 77/S 62 12.7 104
McGrath 75/? 75 5.2 101
Kotzebue 72/E 72 12.9 97
St. Paul Island 84/SW 82 17.2 113
King Salmon 71/E 71 10.6 96
Cold Bay 75/S 73 16.9 101
The Rural Utility Services Bulletin (RUS) 1724E-200, Design Manual for High
Voltage Transmission Lines, recommends all transmission lines be designed to meet
extreme wind conditions. Using Figure 11.2 from RUS Bulletin 1724E-200, which
depicts the predicted extreme wind speed at 33 feet above ground for a 50-year mean
recurrence interval, an extreme wind design speed of 100 mph was selected as
appropriate for the entire transmission line. The 100 mph extreme wind design speed
recommended in Figure 11.2, correlates closely with the estimated extreme 5-second
wind gust speeds listed in Table IV-2.2, Column 5.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.10
F. DESIGN LOADING AND LOADING ZONES
Table IV-2.3 summarizes the design loading conditions that will be used for the
two loading zones.
TABLE IV-2.3
Assumed Study Design Criteria
Loading Conditions
Parameter
Units
Southern
Zone
Northern
Zone
NESC HEAVY Radial Ice inches 0.5 0.5
Wind Speed mph 40 40
Wind PSF lbs/sf 4 4
Temperature oF 0 0
High Wind Wind Speed mph 100 100
Wind PSF lbs/sf 25.6 25.6
Temperature oF 32 32
Extreme Ice or Radial Ice inches 1 1
Ice/Snow Wind Speed mph 20 20
Equivalent + Wind Wind PSF lbs/sf 1 1
Temperature oF 30 30
Ambient AAMT oF -15 -15
Temperature Maximum oF 90 90
Minimum oF -70 -70
Snow Depth Maximum inches 60 60
Elevation Maximum ft above
MSL
100 1000
Conductor Temp. Maximum oF 122 oF 122 oF
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.11
1. Overload Capacity Factors
The overload capacity factors listed in Table IV-2.4 will be used to design the
transmission line structures, guys and anchors.
TABLE IV-2.4
Overload Capacity Factors
Steel Structures7
Overload Capacity Factor
Loading Condition
Transverse
Wind
Vertical
Load
Wire
Tension
NESC Heavy, Grade B 2.50 1.50 1.65
Extreme Wind 1.00 1.00 1.00
Wood Structures8
Overload Capacity Factor
Loading Condition
Transverse
Wind
Vertical
Load
Wire
Tension
NESC Heavy, Grade B 4.00 4.00 2.00
Extreme Wind 1.50 1.33 1.33
Guys, Anchors and Foundations4
Overload Capacity Factor
Loading Condition
Transverse
Wind
Longitudinal
Load
Transverse
Tension
NESC Heavy, Grade B 4.00 2.00 2.00
Extreme Wind 1.5 1.33 1.33
2. Conductor Sag and Tension Limits
Conductor tensioning limits are summarized in Table IV-2.5. The selection of
tension limits depends on the type of conductor and the associated risk of aeolian
vibration. For standard ACSR, a non-Self Damping Conductor, installed with out
dampers, in areas that may experience aeolian vibration, RUS recommends an initial
unloaded tension limit of 20% of ultimate rated strength (URS) at the AAMT. However,
use of this limit will result in increased sag and shorter spans, resulting in greater costs.
RUS recommends the initial unloaded tension should not exceed 33% URS or 25% URS
under final unloaded conditions at 0oF for the NESC Heavy loading. The NESC stipulates
a tension limit of 35% initial and 25% final conditions at 60oF. Manufactures have
indicated that self-dampening type conductors can use the NESC limits. Vibration
dampers can be used on non-self dampening conductors to increase tension limits, but a
7 NESC 2002 Edition
8 RUS Bulletin 1724E-200, 8/92 Revision, Table 11-3
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.12
vibration analysis would need to be performed to determine the type, quantity and
placement of dampers on the conductor. This study presumes that vibration dampers will
be installed on the conductor so that the increased tension limits may be used. Increased
tension limits will result in decreased sag and longer spans, and lower construction costs.
Where there is a conflict between NESC and RUS tension limits, RUS tension limits
shall control.
Table IV-2.5
Overhead Ground Wire tensioning limits are summarized in Table IV-2.6. Where
there is a conflict between NESC and RUS tension limits, RUS tension limits shall
control.
Table IV-2.6
OHGW Tension Limits10
9 RUS Bulletin 1724E-200, 8/92 Revision ,Table 9-2
10 RUS Bulletin 1724E -200, 8/92 Revision, Table 9.2
Conductor Tension Limits9
Loading Condition
Self-
Dampening
Types
Southern Zone
Non-Self
Dampening
Conductors
Northern Zone
Non-Self
Dampening
Conductors
NESC Heavy 50% (0oF) 50% (0oF) 50% (0oF)
Extreme Wind, No Ice 60% (32oF) 60% (32oF) 60% (32oF)
Extreme Ice, No wind 60% (32oF 60% (32oF) 60% (32oF)
Combined Extreme Loading 60% (32oF) 60% (32oF) 60% (32oF)
Initial Unloaded Tension 33% (0oF) 20% (-5oF) 20% (-15oF)
Final Unloaded Tension 25% (0oF) --- ---
Loading Condition
OHGW High
Strength
Steel
OHGW Extra
High Strength
Steel
NESC Heavy 50 (0oF) 50% (0oF)
Extreme Wind, No Ice 80% (32oF) 80% (32oF)
Extreme Ice, No wind 80% (32oF 80% (32oF)
Combined Extreme Loading 80% (32oF) 80% (32oF)
Initial Unloaded Tension 25% (-15oF) 20% (-15oF)
Final Unloaded Tension 25% (-15oF) 20% (-15oF)
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.13
G. ELECTRICAL CLEARANCES (FT)
Electrical clearances to grade or top of snow cover, for a transmission line
energized at 138 kV for various locations, are set forth in the NESC Rule 232. Clearance
requirements required by RUS can be found in Table 4-1, RUS Bulletin 1724E-200.
Both sets of clearances are listed in Table IV-2.7, below.
TABLE IV-2.7
Electrical Clearances
Nature of Crossing NESC Section 232
Clearances (ft)11
RUS
Clearances (ft)12
Major Roads 22.2 23.1
Minor Roads & Driveways 22.4 23.1
Land Accessible to Vehicles 22.4 23.1
Land Inaccessible to Vehicles 18.4 18.1
Water Bodies-No Boating 20.9 19.1
The greater of NESC or RUS clearances will be maintained above grade or top of
snow under NESC Heavy loading, i.e. 0.5 radial ice at 32oF and maximum estimated
operating temperature, i.e. 122 oF. Under extreme ice loading condition, i.e. 1.0 radial ice
at 32oF., NESC clearances for land inaccessible to vehicles will be maintained.
1. Foundations, Guys and Anchors
It is anticipated that both direct embedment of structures in granular soils and
driven pipe pile foundations will be used in permafrost and muskeg locations. Pipe piles
were selected over H-Piles due to their omnidirectional strength properties. For the
purpose of this study a typical pile length of 40 feet is assumed to provide for a minimum
of 35 feet of embedment.13 Past design practices have typically assumed pile lengths of
twenty to twenty-five feet, and a corresponding embedment depth of fifteen or twenty
feet. An assumed pile length of 35 feet has been selected for this study for two reasons.
First, inspections conducted by personnel of Golden Valley Electric Association
(GVEA) and Copper Valley Electric Association (CVEA) revealed that anchor and
support pile s for transmission structures that have been driven to twenty feet or less have
significant ly higher “jacking” rates than piles driven in excess of twenty feet. Jacking is
the term used to describe the phenomenon by which piles are pushed upwards out-of-
ground due to forces that are developed in the soils during freeze-thaw cycles. A study
11 NESC 2002 Edition
12 RUS Bulletin 1724E -200, 8/92 Revision, Table 4.1
13 Discussions with personnel from the engineering firm of Dryden & LaRue, Inc., the firm that designed
the recently constructed 230-kV Healy to Fairbanks, “Northern Intertie” transmission line, resulted in the
selection of a typical pipe pile length of 40 feet..
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.14
conducted by CVEA personnel in 198814, as part of the five-year inspection program, for
the Glennallen to Valdez, 138-kV transmission line, revealed that out of 468 anchor piles
driven to a typical depth of 12 feet, 64 piles or eleven percent had jacked one inch or
more within the first five years. Out of 396 support piles driven to depth of 22 feet, 23 or
5.2% had jacked in excess of one-inch, with one pile having jacked 44 inches. Only 0.4%
of piles driven to an embedment depth greater than 22 feet jacked one inch or greater
during the same five year period.
The second reason for increasing pile embedment depth is to insure the pile will
provide adequate support in permafrost locations in the event the permafrost begins to
degrade. The permafrost in the Calista region exists at a temperature that is only slightly
below freezing. A small increase in the average annual air temperature will result in
degradation of the permafrost. Increased pile embedment depths were used on the
recently constructed 230-kV Healy to Fairbanks transmission line to compensate for this
potential problem.15
2. Insulator Assemblies
In the past several high-voltage transmission lines in Alaska and in the “lower 48
states” have been constructed using polymer insulators. However, their history of
performance is short and testing procedures to determine “in-service” conditions are just
beginning to be developed. Porcelain has a long history of excellent performance.
Therefore, the study assumes that porcelain insulator suspension strings will be used,
except for areas that may be at a higher risk from gunshot damage, such as areas located
near villages. In high risk areas, polymer insulators will be used.
3. R.O.W. Width
There is no industry standard for R.O.W. widths. Typical R.O.W. widths for a
138-kV transmission lines located in undeveloped areas range between 100-150 feet. In
developed areas typical R.O.W. widths are 40-50 feet. This study assumes a R.O.W.
width of 125 feet for undeveloped areas and 50 feet for developed areas.
R.O.W. width provides a corridor for construction of a transmission line,
containment of energized conductors under extreme wind conditions, containment of
structure failure, access for maintenance and control over development within the R.O.W.
The R.O.W. must be of sufficient width to contain the line conductors within the R.O.W.
under extreme wind conditions (i.e. conductor blowout) while simultaneously providing
the necessary electrical clearance between the conductor and the edge of the R.O.W..
This requires that wider R.O.W. be acquired for longer spans. Recent perception by the
public that electric and magnetic (EMF) fields, associated with a power line, may pose a
health risk has played a role in determining R.O.W. widths. However, no EMF limits
have been adopted by either the State of Alaska or the federal government and no field
14 Solomon Gulch Transmission Line Inspection Report PS11 Substation to PS12 Substation, March 1988.
15 Source - Dryden & LaRue, Inc.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.15
limits have been used, in this feasibility study, to determine R.O.W. width requirements.
The accompanying tables list the required R.O.W. width for different structure types and
for two different conductors, with and without conductor dampening. Placing dampers
on the conductor allows the conductor to be operated at increased tension, which in turn
reduces both conductor sag and conductor blowout and results in decreased R.O.W.
width requirements.
Table IV-2.8
ROW Width Requirement for Given Span(1)
in feet
Single Pole Structures Types A
Span In Feet 200 300 400 500 600 700 800
No Dampening
795 ACSR Mallard 48.1 51.9 56.5 61.7 67.6 74.2 81.3
954 ACSR Cardinal 48.7 52.8 57.7 63.3 69.8 77 84.7
With Dampening
795 ACSR Mallard 46.9 49.7 53.5 57.6 62.4 67.7 73.4
954 ACSR Cardinal 47.3 50.5 54.5 59.2 64.2 70 76.3
(1) ROW widths controlled by extreme wind blowout
ROW Width Requirement for Given Span(1)
in feet
Single Pole Structures Types B
Span In Feet 200 300 400 500 600 700 800
No Dampening
795 ACSR Mallard 38.1 41.9 46.5 n/a n/a n/a n/a
954 ACSR Cardinal 38.7 42.8 47.7 n/a n/a n/a n/a
With Dampening
795 ACSR Mallard 36.9 39.7 43.5 n/a n/a n/a n/a
954 ACSR Cardinal 37.3 40.5 44.5 n/a n/a n/a n/a
(1) ROW widths controlled by extreme wind blowout
ROW Width Requirement for Given Span(1)
in feet
H-Frame and X-Frame Structures
Span In Feet 600 700 800 900 1000 1100 1200
No Dampening
795 ACSR Mallard 85.6 92.2 99.3 107 115.5 124.6 134.4
954 ACSR Cardinal 87.8 95 102.7 111.4 120.8 130.9 141.7
With Dampening
795 ACSR Mallard 80.4 85.7 91.4 97.5 103.9 110.9 118.4
954 ACSR Cardinal 82.4 88 94.3 101.3 108.7 116.6 125.1
(1) ROW widths controlled by extreme wind blowout
Table IV-2.8 shows that for a R.O.W. width of 125 feet, a 1,200 foot span can be
achieved, if dampers are installed, with 954 ACSR, Cardinal, the conductor selected for
use as the phase conductor on the Donlin Creek transmission line. As stated previously,
this study assumes a 125 feet R.O.W. width in undeveloped areas and a 50 feet R.O.W. in
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.16
developed areas. These R.O.W. widths may be increased or decreased as part of the final
design process.
H. CONDUCTOR SELECTION
Two conductors, 795 ACSR, Mallard, and 954 ACSR, Cardinal, were investigated
for use as phase conductors. These conductor sizes are in common use throughout
Alaska.
1. Voltage Drop and Power Loss Comparison
The resistance of 954 ACSR, Cardinal at 0.1178 ohm per mile is approximately
15% less than the resistance of 795 ACSR, Mallard at 0.1384 ohms per mile.16 This
translates into a 15% decrease in line losses and voltage drop. Line losses using 954
ACSR, Cardinal, were calculated at 4.9 MW in the EPS study with a 55 MW mine load.
Line losses with 795 ACSR, Mallard, would be 15% greater or 5.8 MW. Assuming the
incremental generation cost of energy is $0.03 per kWh for a coal-fired plant and $0.06
per kwh for a combined-cycle combustion turbine plant, the use of 954 ACSR reduces
the cost of line losses by $236,000 to $472,000 per year.
2. Conductor Sag & Characteristics
Sag and tension calculations were made for both 795 ACSR, Mallard and 954
ACSR, Cardinal. The following table IV-2.9 summarizes sags for the two conductors for
span lengths between 200 and 1,200 feet, both with and without dampening. Sag and
tension calculations can be found in Appendix C.
Table IV-2.9
Maximum Sag Comparison(1)
Sag in Feet - No Dampening
Span in feet 200 400 600 800 1000 1200
Mallard 795 ACSR 2 6.4 12.4 19.8 28.7 39
Cardinal 954 ACSR 2.3 7 13.4 21.5 31.2 42.6
(1) Sag at NESC Heavy 0.5 radial ice, 32 degrees F, no wind, final condition.
Maximum Sag Comparison(1)
Sag in Feet - With Dampening
Span in feet 200 400 600 800 1000 1200
Mallard 795 ACSR 1.3 4.6 9.3 15.1 21.8 29.5
Cardinal 954 ACSR 1.5 5.1 10.1 16.4 24.1 32.8
(1) Sag at NESC Heavy 0.5 radial ice, 32 degrees F, no wind, final condition.
16 Source – Aluminum Electrical Conductor Handbook, September 1971.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.17
The use of Cardinal conductor results in slight ly greater sags. For a typical span
length of 1,000 feet, the Cardinal conductor’s sag will be approximately 24.1 feet, or
about 10% greater, than for Mallard conductor. As shown in the following table the
small increase in sag for Cardinal as compared to Mallard does not affect structure height
requirements for dampened conductors.
Table IV-2.10
Pole Lengths With and Without Dampening
H-FRAME STRUCTURES
Calculation of Pole Length for 954 ACSR Cardinal Calculation of Pole Length for 795 ACSR Mallard
No-Dampening With-Dampening No-Dampening With Dampening
Span Length 1000' 1000' 1000' 1000'
To Top of Pole 2 2 2 2
Insulator Length 5 5 5 5
Sag 31.2 24.1 28.7 21.8
Snow Depth 5 5 5 5
Minimum Conductor 23 23 23 23
Height AGL
Minimum Pole Length 66.2 59.1 63.7 56.8
12' Embedment 78.2 71.1 75.7 68.8
Use Pole Length (ft)80 70 75 70
3. Phase Spacing
Phase spacing was computed in two ways: (1) by performing gallop calculations,
and (2) by using RUS methods for computing spacing, which is based on conductor sags.
(Appendix C). For both conductors, phase spacing is in the range of 15 to 17 feet, which
is typical of the phase spacing for a 138-kV transmission line.
4. Optical Ground Wire (OPGW) Selection
A single overhead OPGW will be installed on the transmission structures. OPGW
is an overhead ground wire that contains a fiber-optic bundle in the core of the ground
wire. There are two primary purposes of the OPGW: (1) to provide communications
circuits for relaying, command and control of the power system, and (2) to interconnect
the eight villages located along the transmission line route and Donlin Creek mine, with
the community of Bethel and each other, using fiber-optics, rather than satellite
communications. This should improve the quality and speed of communications and
hopefully lower the cost of communications for consumers living in the eight villages.
The isokeraunic level along the transmission line corridor is very low, therefore, the
OPGW is not required for lightning strike protection.
An optical ground wire such as that provided by Brugg Telecom, similar to
27AW/59ACS, with a 48 or 60 fiber count, is recommended as the OPGW for use on the
trans mission line. Similar OPGW products are available from Corning Cable Systems.
These products have sag and tension characteristics that closely match the sag and
tension characteristics of ACSR conductors. Final OPGW selection will be made during
final design.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.18
5. Conclusion
There is little difference in the sag and tension characteristic of 954 ACSR,
Cardinal conductor and 795 ACSR, Mallard conductor. However, the use of Cardinal 954
ACSR conductor results in decreased line losses and voltage drop. Therefore, 954
ACSR, Cardinal was selected by this feasibility study as the recommended phase
conductor. It should be emphasized that an optimal phase conductor and OPGW selection
will be made during the final design phase, as changes in assumptions used fo r the final
design could affect final conductor and OPGW selection.
I. STRUCTURE SELECTION
Three primary structure types were evaluated as part of this study. These are
single-pole wood or steel, H-frame wood or steel, and X-frame steel structures. Typ ical
structure outlines are shown at the end of this section.
1. Single Wood and Steel Pole Structures
Single pole structures are common on 138-kV transmission lines, especially in
urban areas. Two type of single pole designs, designated Type A and B were examined.
Sketches of these structures are included at the end of this section. Spans of 200-400 feet
are typical. Single-pole structures are used when the structure must accommodate an
underbuild circuit and/or the lines must be built in a reduced R.O.W. widths. The single
pole structure Type B would primarily be used on Line Section A-B, which is the 6.0
mile section of transmission line that extends from the power plant, located south of
Bethel to the north side of Bethel. A compact line design will be used in this segment to
limit R.O.W. width requirements to no more than fifty feet. A 13.8-kV circuit would be
under-built along the first 2 miles of the transmission line. At this point the under-build
would turn east for approximately 1,500 feet where it would connect into the existing
Bethel Utilities diesel plant substation. Structure Type A would be used in line Section
M-N if the power line is built within the Crooked Creek to Donlin Mine road R.O.W.
Tangent single wood pole structures were evaluated based on ground line moment
capacity for Douglas fir. The largest class of wood pole evaluated was H2. This self-
imposed restriction was based on the premise that wood poles in the H2 class are readily
available, while wood poles in the H3 class range and above are in lesser supply. Tangent
steel poles were selected based on applying steel overload factors to determine wood pole
equivalent. Pole sizing was accomplished by performing computations to determine the
proper pole class versus pole height for both NESC Heavy and Extreme Wind condition.
Computations were made to determine maximum span length based on ground line
moment capacity, sags and clearances, and R.O.W. widths. Sample calculations can be
found in Appendix C. Maximum horizontal spans for both wood pole and steel pole are
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.19
shown in Table IV-2.11. Span lengths for steel poles are in the order of 1.6 times the
span lengths for wood poles.
The route through Bethel attempts to follow existing property line and roadways
to the extent reasonable, which produces several large line angles. In certain locations it
may be difficult to guy these large angles and self supporting steel towers may be
required. However, this decision will be made during the final design phase.
TABLE IV-2.11 – Single Wood & Steel Pole Structure Comparison
Wood Pole
NESC Heavy Loading Extreme Wind Loading (100 mph)
Pole Height AGL Pole Height AGL
C2 C1 H1 H2
45' Pole
50' PoleHS
173
167
164
162
207
208
203
199
247
246
247
241
301
297
287
289
æççççè
ö÷÷÷÷ø
ft=55' Pole
60' Pole
C2 C1 H1 H2
45' Pole
50' PoleHS
129
123
118
114
157
156
149
143
189
186
185
177
234
229
217
216
æççççè
ö÷÷÷÷ø
ft=55' Pole
60' Pole
Steel Pole (Wood pole Equivalent )
NESC Heavy Loading Extreme Wind Loading (100 mph)
Pole Height AGL Pole Height AGL
C2 C1 H1 H2
45' Pole
50' PoleHS
282
276
272
270
338
341
334
329
401
401
405
397
488
484
469
474
æççççè
ö÷÷÷÷ø
ft=55' Pole
60' Pole
C2 C1 H1 H2
45' Pole
50' PoleHS
209
201
195
191
253
252
243
237
302
299
299
290
370
364
349
349
æççççè
ö÷÷÷÷ø
ft=55' Pole
60' Pole
Steel poles were selected for use on the single pole line because steel poles exhibit
several advantages over wood poles. These advantages include:
• Steel allows for the design of a product that can be protected against deterioration.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.20
• An additional groundline barrier coating provides extra protection at the most
corrosive location.
• When damaged by overload conditions, steel will tend to yield locally rather than
“break” or “collapse”, often times allowing the line to remain in service.
• Steel poles are readily available in a wide variety of sizes and heights and are
approximately 40% lighter than their wood pole equivalent.
2. H-frame Structures
The selection of a wood H-frame structure was accomplished by performing
computations to determine the proper pole class versus pole height for both NESC Heavy
and Extreme Wind condition. Computations were made to determine maximum span
length based on ground line moment capacity, sags and clearances, and ROW widths.
Sample calculations can be found in Appendix C. Tangent single wood pole structures
were evaluated based on ground line moment capacity for Douglas fir. Tangent steel
poles were selected based on applying steel overload factors to determine a wood pole
equivalent. Maximum horizontal spans for both wood pole and steel pole are shown in
Table IV-2.12. Allowable span leng ths for steel poles are in the order of 1.6 times the
span lengths for wood poles.
The largest class of wood pole class evaluated was H2 the smallest was C2. This
self-imposed restriction was based on the premise that wood poles in the H2 class are
readily available, while wood poles in the H3 class range and above are generally in
lesser supply. Both braced and unbraced wood H-frames were examined. Only unbraced
steel H-frames were considered.
H-frames are simple, standard structures that are used throughout the electric
utility industry. Several utilities in Alaska use H-frame structures. These include GVEA,
HEA, CEA and others. H-frame structures, wood or steel, can be direct-embedded in rock
and good native granular type soils, where the active la yer is shallow. In poor soils, they
can be direct-embedded using gravel or rock backfill, inserted in pipe-piles that are
driven into good soils and backfilled with gravel or other selected materials. Where pile
supports are required, the self-support H-frame requires only two driven piles. Pipe-piles
ranging between 20-30 inches in diameter are typically used because of their omni-
directional strength. Once the pip e-piles are installed, the soil inside the pipe-pile is
removed with an auger , if required, to the appropriate depth and the structure legs are
placed in the pipe-piles and backfilled with gravel, in much the same manner as if the
structure legs were direct -embedded.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.21
Table IV-2.12 – H-frame Wood & Steel Structure Comparison
Wood Pole
NESC Heavy Loading Extreme Wind Loading (100 mph)
Pole Height AGL Pole Height AGL
C2 C1 H1 H2
55' Pole
65' PoleHS
609
605
589
582
753
740
740
725
917
892
857
888
1067
1063
1077
1043
æççççè
ö÷÷÷÷ø
ft=75' Pole
85' Pole
C2 C1 H1 H2
55' Pole
HS
439
418
386
361
556
525
505
473
689
648
598
602
812
787
776
725
æççççè
ö÷÷÷÷ø
ft=65' Pole
75' Pole
85' Pole
Steel Pole
NESC Heavy Loading Extreme Wind Loading (100 mph)
Pole Height AGL Pole Height AGL
C2 C1 H1 H2
55' Pole
65' PoleHS
1017
1020
1003
1001
1250
1238
1248
1235
1515
1486
1440
1501
1758
1764
1797
1755
æççççè
ö÷÷÷÷ø
ft=75' Pole
85' Pole
C2 C1 H1 H2
55' Pole
65' PoleHS
729
712
680
659
909
879
867
835
1115
1070
1012
1037
1304
1284
1287
1230
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85' Pole
There are potential problems associated with using direct-embedded H-frame s in
wet, fine grain silty soils, with deep active layers. These types of soils are highly
susceptible to frost -heaves. Uneven frost jacking action of the legs can create unbalanced
forces and excessive strain on the structures. Unbraced H-frames appear to tolerate these
unbalanced forces better than braced H-frames, whose stiffness is a distinct disadvantage
in frost-heave susceptible soils.
Another disadvantage of H-frames is that repair of a jacked structure leg or
foundation pile will require removal of at least one leg of the structure, to either redrive
the foundation piles or re-auger the hole for direct-embedded structures. These potential
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.22
disadvantages are, however, offset by the fact that using steel H-frame structures results
in the lowest construction cost for the Donlin Creek transmission line. See Section VI.
The calculated average span length using H-frame structures on the Donlin Creek
line is approximately 955 feet.
3. Steel X-frame Towers
The guyed X-tower tangent structure has been widely used throughout Alaska. It
was used on the Glennallen-Valdez, the Tyee Lake, Anchorge-Fairbanks Intertie, the
Northern Intertie, the Bradley Lake, and three Beluga to Anchorage lines. The primary
advantages of the X-tower design are its longitudinal stability, its flexibility and the
relative ease that a tower can be re-leveled when support piles have jacked and the
structure requires re-leveling. Inspection of the Glennallen to Valdez 138-kV
transmission line in 1988 revealed that frost -jacking action on the support piles had
result ed in as much as 44 inches of differential leg height on one particular structure. The
X-frame structure withstood these differential forces without damage.
Originally X-towers were constructed of latticed aluminum and as a result, the
towers were relatively light weight. Aluminum lattice towers were used to construct the
Beluga to Anchorage transmission lines. However, several years past, manufactures
stopped making the aluminum lattice towers. On new transmission line construction the
heavier steel X-tower is used.
The X-frame tower is also a mo re complicated structure to design, fabricate and
assemble than a typical H-frame structure. Normally, loading tables are developed and
provided to the manufacturer. The manufacturer uses the loading tables to design the X-
tower assembles. Unfortunately the recent trend by manufacturers has been toward
designing and fabricating even heavier towers.17 The increased weight of the steel X-
framed towers has largely eliminated the advantages of using X-towers, especially in
remote areas such as western Alaska, where freight and labor costs are substantially
greater than for projects constructed in more developed areas of Alaska.
There are two primary disadvantages of steel X-st ructures as compared to the
steel H-frame structure. First, each X-frame structure typically requires two support
piles, ranging between 8-12 inches in diameter and two anchor piles, ranging between 8-
10 inches in diameter, are required, for a total of four driven piles. Second, X-towers
cannot be direct-embedded in soils, support piles and anchor piles must be installed
regardless of the soil conditions. This requirement increases construction costs, compared
to direct-embedded H-frames, in areas where good granular soils are encountered. The
calculated average span length using X-frame towers on the Donlin Creek line is
approximately 955 feet, which is identical to the average span length for H-frames.
17 Source: Dryden & LaRue, Inc.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.23
J. DONLIN CREEK TRANSMISSION LINE DESIGN ALTERNATIVES
The engineering firm of Dryden & LaRue, Inc. was subcontracted to prepare
construction cost estimates for X-frame and H-frame alternatives. See Appendix C.
These alternatives are discussed in the following paragraphs.
1. Single Pole + H-frame Structures
In this alternative, direct-embedded single poles would be used in Line Section A-
B, which is the 6 mile long section of transmission line that extends from the power plant,
located south of Bethel, to the north side of Bethel. Average span length in the single pole
section is 295 feet. The remaining 185 miles of transmission line will be built using steel
H-frame structures.
Two foundation alternatives were examined for supporting the steel H-frame
structures. Alternat ive 1 assumes pipe-pile foundations would be used to support the H-
frame structures along the entire length of the route. Alternative 2 assumes pipe-pile
foundations would be used to support the H-frame structures in the 80 miles of marshy,
frost -heave susceptible soils found between Bethel and Upper Kalskag and direct-
embedded H-frames would be used for the remainder of the line route. The number of
structures and pile foundation for these two alternat ives are summarized in Table IV-
2.13. Average span length for either of this two foundation alternatives is approximately
955 feet.
2. Single Pole + Combination of X-towers and H-frame Structures
In this alternative, direct-embedded single poles would be used in Line Section A-
B, which is the 6 mile long section of transmission line that extends from the power plant,
located south of Bethel, to the north side of Bethel. Average span length in the single pole
section is 295 feet. The remaining 185 miles of transmission line would be built using
steel H-frame and steel X-towers.
X-tower pipe-pile supported structures would be used to construct the power line
in the 80 miles of marshy, frost -heave susceptible soils found between Bethel and Upper
Kalskag. Pipe-pile supported H-frame structures would be used along the remainder of
the route. The number of structures and pile foundations for this alternative is also
summar ized is also included in Table IV-2.13. Average span length for this alternative is
also approximately 955 feet.
For comparison purposes the average span length for the X-tower section of the
Glennallen-Valdez transmission line is approximately 960 feet, which equates to 5.5
structures per mile. Of the numerous transmission lines previously built in Alaska, the
Glennallen to Valdez 138-kV transmission line is considered the most comparable to the
proposed Donlin Creek transmission line. Soils and weather conditions between
Glennallen and the Thompson Pass area are comparable to the soils and weather
conditions found along the Donlin Creek transmission line route. The Glennallen-Valdez
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.24
line was constructed with a combination of steel X-frame structures and wood H-frame
structures with steel crossarms. X-tower structures were used for a distance of about 50
miles, in the frost-heave susceptible soils found in the Copper River Basin. H-frame
structures were used in the foot-hills of the Chugach Mountains, where soils were
suitable for direct-embedment. Massive steel X-towers and A-frames were used to
traverse the Thompson Pass area where snow depths often reach twenty feet or more.
Such massive structures will not be required on the Donlin Creek transmission line.
Table IV-2.13
Number of Structures/Pile Foundations
Alternative SP H-frame X-towers 3-Pole Angle Pile Fdns
SP+H-frame all Pile Fdns 100 943 0 83 2133
SP+H-frame, Pile Fdns +DE 100 942* 0 83** 893
SP+H-frame+X-towers 100 530 412 83 2133
DE=Direct-Embedded
(*) 412 structures on Pipe-Pile Foundations, 530 structures Direct-Embedded
(**) 23 structures on Pipe-Pile Foundations, 60 structures Direct-Embedded
3. Life-Cycle Costs
Past studies have found the 100 year-life cycle cost for H-frame and X-towers to
be nearly identical.18 Therefore, from a long-term life-cycle perspective, there is no
decided advantage to using steel X-frame structures over steel H-frame structures.
4. Conclusion
Two types of tangent structures would be used to construct the Donlin Creek
Transmission Line. Single pole structures are recommended for use for constructing the
initial 6 miles of power line to limit R.O.W. width requirements for that section of line
that traverses south-to-north through the community of Bethel. Steel H-frame structures
are recommended for use on the remaining 185 miles of the transmission line. The use of
self-supported steel H-frame was evaluated to have the lowest construction cost per mile,
primarily because H-frames can be direct-embedded in granular soils while X-frames
require more costly pile supports in these same soils. The one hundred-year life-cycle
cost of both structure types has been determined to be nearly identical.
K. STRUCTURE FOUNDATIONS AND ANCHOR SELECTION
1. Structure Foundations
The Donlin Creek transmission line corridor traverses two distinct soil zones.
The “southern zone” is defined as the section of the line located between the Bethel
power plant and Upper Kalskag. Except for the immediate area surrounding Bethel, the
18 Copper Valley Intertie Feasibility Study, R.W. Beck, April 1994.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.25
southern zone consists of marshy, tundra and lake covered lowlands, composed of fine
grain sands and silts, and underlain with moderately deep permafrost. It is anticipated the
depth of the active soil layer in this zone would be in the range of 3-5 feet. This type of
soil is typically unsuitable for direct-embedded structures. Deep driven pipe-piles would
be used in this zone to support transmission structures. Pile support ed structures ha ve
been used in the construction of most major power lines in Alaska, in this type of terrain.
Terrain elevation for this portion of the line varies from a minimum of 13 feet to a
maximum of 73 feet. Typical steel pipe pile supports would be 40 feet in length, between
18-24 inches in diameter, with a one-half inch wall thickness, driven 35 feet into the
permafrost. In general the pipe pile inside diameter should be four inches greater than the
diameter of the pole inserted into the pipe. Each H-structure would require two pipe piles.
Driving the pipe pile typically causes the soils within the pile to subside so that augering
to remove soils from within the pipe is not required. After the pile is driven, a pole is
inserted into the pipe pile. The pole is supported by continuous steel strap that extends
from the lip of the pipe and cradles the bottom of the pole to prevent it from settling
below a predetermined depth. Once the steel pole is centered in the pipe, the pipe is
filled with gravel to “lock” the pole into position within the pipe pile. The gravel also
transfers external stress imposed on the pole from various horizontal and vertical loads, to
the pipe pile and the earth.
The community of Bethel is, for the most part, located on slightly “higher” and
“drier” ground than encountered elsewhere along the “southern zone” line corridor. It is
anticipated that direct -embedded foundations, with poles embedded to a depth of 15 feet,
would be used on the first 6 miles of single pole transmission structures (i.e. line Section
A-B). Bethel Utilities, Inc. directly embeds its distribution poles and while the utility ha s
experienced pole jacking problems, the number of poles affected has not been excessive.
The “Northern Zone” is that portion of power line located between Upper Kalskag
and the Donlin Creek mine. The terrain along the transmission corridor in this zone rises
gradually from 100 feet at Upper Kalskag to an elevation of approximately 1,000 feet at
the Donlin Creek mine site. It is anticipated that more granular, moderately drained soils
would be encountered, along this portion of the route and therefore, it would be possible
to direct ly embed structure legs into the earth, rather than using driven pile s to support
the transmission structure. Direct embedment requires augering or digging to sufficient
embedment depth, typically 9 to 15 feet, setting the poles or structure, backfilling and
tamping. There may be areas within the “northern zone” that sound rock is encountered.
Direct embedment in rock generally requires holes to be drilled, blasted, excavated and
then backfilled.
2. Anchors
Anchor selection would be highly influenced by soil conditions. Except for the
initial 6 miles of transmission line (i.e. line Section A-B), anchors in the “southern zone”
would primar ily consist of driven pipe-piles. The typical anchor pipe-pile would have a
diameter of 8 to 10 inches, with a one-half inch wall thickness.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.26
Anchors in the Bethel area could consist of driven pipe piles, log anchors,
expanding anchors, or perhaps deep driven manta ray anchors. Log anchors, where
excavation is practicable, have been in favor in Alaska due to their exceptional holding
capacity. Selection of appropriate anchor type will be made during final design.
Anchor selection in the “northern zone” could consist of log anchors, expanding
anchors, screw anchors, driven manta ray anchors and rock anchors. Selection of
appropriate anchor type(s) will be made during final design, following a more detailed
soil investigation along the route corridor.
L. FEASIBILITY STUDY CONSTRUCTION PLAN
Several factors will determine how the Donlin Creek transmission line will be
constructed. A project schedule is presented in Section VII and is based largely on the
below discussed assumptions.
1. Construction Zones
The Donlin Creek Mine transmission corridor can logically be divided into two
construction zones. The “Southern Construction Zone” and the “Northern Construction
Zone.” The Southern Zone, as previously defined, is the section of the line corridor
located between the Bethel power plant and Upper Kalskag. The southern zone consists
of marshy, tundra and lake covered lowlands, composed of fine grain sands and silts, and
underlain with moderately deep permafrost . It is anticipated that a minimum of two
contractors would be employed to construct the transmission line. One contractor would
be responsible for construction in the Southern Zone and the second contractor for the
Northern Zone.
Structure foundations in the “Southern Zone,” outside the community of Bethel,
would consist primarily of deep driven pipe-piles. Because the southern zone consists of
marshy, tundra and lake covered lowlands, construction activities in this zone could occur
only during the winter months, when the streams and ground are frozen and covered with
a protective layer of snow. Since there are very few trees along this section of the line
corridor, ROW clearing would be minimal. There are several anadromous fish streams
that must be spanned in this section of the corridor.
The “Northern Construction Zone” is that portion of the power line located
between Upper Kalskag and the Donlin Creek mine. It is anticipated that more granular,
moderately drained soils would be encountered along this portion of the corridor and
direct-embedment of structures would be possible. At Upper Kalskag there is an abrupt
transition between the lowlands and the boreal forest of the mountainous highlands. From
Upper Kalskag to Crooked Creek, white and black spruce dominated with quaking aspen,
balsam poplar and paper birch locally present. The elevation slowly rises from
approximately 100 feet at Upper Kalskag to 200 feet at Crooked Creek. Simultaneously,
the sparse forest of the Kalskag area gives way to an ever increasing forest cover, wit h
maximum forest density occurring between Aniak and Crooked Creek. Between Crooked
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.27
Creek and the Donlin Creek mine site, the terrain climbs rapidly in elevation, from 200
feet at Crooked Creek to approximately 1,000 feet above mean-sea-level at the mine site.
The relatively dense forest of the Crooked Creek area rapidly gives way to sparse forest
cover, tundra-covered slopes and barrens as the elevation increases. Construction activity
in this zone could continue year-round.
2. River Access
The proposed transmission line route parallels the north bank of the Kuskokwim
River from it s origin at the power plant substation located south of Bethel to Crooked
Creek, a distance of approximately 178 miles. The Kuskokwim River will be used to
move material, equipment, construction camps and labor to several staging/marshalling
areas along the river. Once construction has move d a few miles outside of Bethel, it will
be necessary to establish marshalling areas at about 10 mile increment s. A total of 18-20
marshalling areas would be required. This would allow the construction contractor to off-
load necessary materials to work 5 miles in either direction from the marshalling areas.
Since the Kuskokwim River freezes during the winter month, all material would need to
be transported and off-loaded at the marshalling areas between late-May to mid-
September. Marshalling sites would need to be located on dry ground sufficient ly
elevated above the river to prevent flooding, during high water periods. This should not
pose a problem in the Northern Construction Zone, but it could be difficult to locate such
sites in the Southern Construction Zone.
Although the corridor parallels the Kuskokwim River, it is located at some
distance from the river in certain areas of the “Southern Construction Zone.” The
maximum distance the line veers away from the main river channel is approximately 4.7
miles. This occurs at a location slightly north of Point F. From just east of Upper
Kalskag to Crooked Creek, the line corridor is typically less than one-half mile from the
river. ( See Maps at the end or Section IV-1.)
At Crooked Creek the route turns north for a distance of approximately 14 miles
to the Donlin Creek mine site.
3. Road and Trail Access
From reviewing topographic maps, supplemented by aerial reconnaissance, it
does not appear that there are many trails that lead from the Kuskokwim River to the
construction corridor. To access the transmission line corridor, the contractor must
construct access roads from the marshalling areas to the transmission line corridor.
Temporary ramps and roads may be needed for staging the construction effort.
Temporary fill may need to be placed in wetlands to build ramps and roads for
construction of the transmission lines. The fill must be removed after the construction is
complete. No permanent roads would be built for maintaining the transmission line.
However, a primitive 12-feet travel way may need to be grubbed in certain areas, i.e.
stumps removed, within the ROW, to allow movement of construction and maintenance
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.28
equipment where terrain permits. Only minimal grubbing, if any, would be required in
the treeless Southern Construction Zone.
Because the terrain in the Southern Construction Zone consists of marshy, tundra
and lake covered lowlands only winter construction is possible. Prior to the
commencement of const ruction access roads, the soils, lakes and rivers must freeze to a
depth sufficient to support heavy equipment and sufficient snow cover must exist to
prevent damages to the vegetation. If snow cover is insufficient, then ice roads must be
constructed. Typically, government agencies will require twelve inches of frost and
twelve inches of snow before allowing construction activity to proceed on wetlands. In a
typ ical winter season, construction activities probably would not commence until
December and would need to end by mid-April, to prevent damage to the vegetation. It is
anticipated that ice roads would be built in December to allow construction activities to
begin by mid -January.
4. Foundations
Direct-embedment and deep driven pipe-pile foundations would be used to
support the transmission structures. Direct-embedment is typically the most cost -effective
foundation. Direct-embedment is, however, only practical where granular soils or
fractured rock allow the soil to be readily augered and the soil provides sufficient
resistance to overturn forces. As discussed in previous sections, direct-embedment
appears to be appropriate for the Northern Construction Zone, which extends from Upper
Kalskag to the Donlin Creek mine, a distance of approximately 106 miles. Due to the
remoteness of the Northern Zone it is anticipated that relatively light weight and easily
transportable augering equipment would be used. This type of augering equipment is
limited in the amount of down-pressure it can apply to auger a hole, which in turn
increases the time required to auger a hole. Based on the augering rates on the recently
constructed Northern Intertie, it is estimated that an augering crew can auger, on average,
two holes per day.19
Deep driven pipe-pile foundations would be used in the Southern Construction
Zones to support transmission structures, except within the community of Bethel where
direct-embedment would be used. Efficient and productive pile -driving depends largely
on the type and size of equipment used for the task. There are two broad categories of
pile drivers that are generally used to install piling on transmission line. The first
category makes use of a vibratory hammer and the second category uses a hydraulic
hammer. There are of, course, variations of each of these categories. Both vibratory and
hydraulic hammers are suitable for installing the 40 feet sections of pipe-pile
recommended by this study.
Regardless of whether a vibrator or hydraulic pile -driving equipment is used, the
equipment is typically large and heavy and travels slowly along the ROW. Based on the
pile driving rates on the recently constructed Northern Intertie, it is estimated that a pile
19 Source: Dryden & LaRue, Inc.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.29
driving crew can, on average, install 2 piles per day.20 As previously discussed a typical
steel pipe-pile foundation would be 40 feet in length, between 18-24 inches in diameter,
with a one-half inch wall thickness, driven 35 feet into the perma frost
5. Structure Erection
Three basic methods for structure erection can be used on H-frame and single
pole structures. The first of the two methods involves delivering the disassembled
structure to the structure site location prior to or at the time the foundation is completed.
The disassemble d structure is field assembled, erected, with travelers, and set in place
immediately after the foundation is completed. The second method can only be used on
sectional steel poles and involves delivering the butt section of the structure to the site
location prior to or at the time the foundation is completed. The butt section of the steel
pole is inserted immediately after the foundation is completed. The remainder of the pole
is attached to the butt section at a later time. The third method involves assembling
structures at a marshalling yard and transporting the fully assembled structure, with
travelers, by helicopter to structure sites after a number of foundations have been
complete.
All three methods are suitable for both pipe-pile and direct-embedment
foundations. However, in soil conditions where direct-embedment is used, but the
augered hole tends to collapse, the first and second method are the most appropriate. If
method three is used with this soil condition, then it would be necessary to shore or case
the augered hole , which would increase construction costs, to prevent its collapse until
the structure is delivered, typically by helicopter, and placed into position.
The first method typically suffers from inefficiencies because uneven terrain and
field conditions, such as snow and mud, make it difficult to assemble structures on-site.
In addition, the structure erection crew may remain idle while waiting for the foundations
to be completed; especially in areas where pipe-pile foundations are installed, as H-frame
structures can be erected in a significantly shorter period of time tha n it takes to install a
pipe-pile foundation.
The second method is probably best suited for direct-embedded structures. This
method allows the butt section of the steel pole to be installed and backfilled immediately
after the hole is augered. Final structure assembly can be completed at a later date by the
erection crew. The remaining pole sections, crossarms, and other H-frame structure
components can be delivered unassembled by vehicle and final assembly of the structure
is accomplished on-site, with the aid of a crane. In the alternative, the remaining portions
of the H-frame structure can be assembled at a marshalling area, transported and installed
with the assistance of a helicopter. This would involve lowering the upper position of the
H-frame onto the previously installed butt sections. This method increases efficiency
because the erection crew need not be dispatched until several structures are ready for
20 id.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
TRANSMISSION LINE FEASIBILITY DESIGN Section IV-2.30
final assembly. It is not unreasonable to expect that a helicopter could deliver, at a
minimum, 2-3 structures per hour, assuming a well-organized operation.
The third method entails the complete assembly of structures at one of the 18-20
marshalling areas required for this project. Assembling structures at a marshalling area is
typically more efficient and cost effective than field assembly. The disadvantage is that a
large area may be needed to sto re the completely assembled structures until they are
helicopter delivered to structure site locations. Assembly would include insulator strings,
stringing travelers and fixed climbing devices for steel structures if required. This method
allows for efficient use of helicopter services, and virtually eliminates standby time for
the helicopter. This method is particularly suited for pipe-pile foundations, since the pile
can be installed early in the project, even before structures have been manufactured and
shipped. Once the structure components are delivered to the marshalling areas they can
be assembled, delivered and placed in the pipe-pile foundations by the helicopter. It is
not unreasonable to expect that a helicopter could deliver , at a minimum, 2-3 structures
per hour, assuming a well organized operation.
The study assumes either the second or third method is used for all structure
erection, except for the immediate vicinity of Bethel, where single pole structures are
used. It is assumed that me thod one would be used to erect single pole structures in
Bethel.
6. Conductor and OPGW Stringing
Conductor and OPGW stringing involves the installation of travelers on the
insulator string, pulling in a pilot line, then pulling in, splicing and sagging the conductor
and OPGW. Later operations include clipping in the conductor/OPGW and installing
vibration dampers if required.
Conductor/OPGW stringing and sagging would normally occur in late spring
through early fall, when the air temperatures are above freezing. Sagging during periods
when the temperature is above freezing is preferred, to avoid the possibility of frost or ice
build up on the conductor/OPGW during sagging operations.
Ground Line
Typical Single Pole Structure Type A
138 kV Phase Conductor
5' - 8' Typical
OPGW
5' Typical
NTS
55'-80' Typical
Nuvista Light & Power, Co.
Typical Type A
Singe-Pole
Tangent Structure
Bettine, LLC
Ground Line
Single Pole Structure Type B
138 kv Phase Conductor
5' Typical
OPGW + Telephone
13.8kv underbuild (as required)
NTS
5' Typical
50'-65' Typical
Nuvista Light & Power, Co.
Typical Type B
Single Pole
Tangent Structure
Bettine, LLC
Ground Line
H-Frame Structure
Optional Bracing
(Wood Pole Only)
OPGW
32' + 2' Typical
5' Typical
138 kV Phase Conductor
5" Typical
50--90' Typical
Nuvista Light & Power, Co.
Typical H-Frame
Tangent Structure
Bettine, LLC
18"-24" Pipe Pile
Foundation As Required
Ground Line
X-Frame Structure
138 kV Phase Conductor
OPGW
NTS
32' + 2' Typical
10" Pipe Pile Footing (Typical)
10" Pipe Pile Anchor
Fore & Aft (Typical)
Pin Connection
5' Typical
Guys Fore & Aft
5' Typical
50'-90' Typical
Nuvista Light & Power, Co.
Typical X-Frame
Tangent Structure
Bettine, LLC
Ground Line
H-Frame Structure
Optional Bracing
OPGW
32' + 2' Typical
5' Typical
138 kV Phase Conductor
5" Typical
50--90' Typical
Danger Tree To Be Removed
If It Could Strike Line
125' Typical
Stable Low Growth
Vegetation Can Remain
Nuvista Light & Power, Co.
Donlin Creek Transmission Line
Right-of-Way Cross-Section
Bettine, LLC
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
SUBSTATION FEASIBILITY DESIGN Section IV-3.1
SECTION IV-3 SUBSTATION FEASIBILITY DESIGN
A. BACKGROUND
The 138-kV transmission line would originate at the Bethel Power Plant
substation located south of Bethel and terminate at the Donlin Creek gold mine
substation, located approximately 14 miles north of Crooked Creek. Seven step-down
village substations would be constructed along the route of the transmission line to serve
the needs of the communities located adjacent to the route of the transmission line. In
addition a 13.8-kV express feeder would be under -built on the transmission line
structures from the power plant substation, for a distance of approximately two miles,
terminating with an interconnection to the existing Bethel Utilities, Inc. diesel plant
substation. In reviewing the following drawings it should be recognized that the
suggested substation layouts represent only one of many possible arrangements and that
the final substation arrangement s will likely differ in detail but not function from the
suggested arrangements. Figures referred to in the discussion can be found at the end of
the Section.
Figures IV-3.1 shows the one-line system configuration of the proposed Bethel to
Donlin Creek mine transmission system with a coal-fired power plant alternative. The
one-line system configuration for a combined-cycle combustion turbine power plant is
shown in Figure IV-3.2. The only difference between the two system configurations is
the amount and type of generation listed.
An optical ground wire (OPGW) would be installed along the full length of the
138-kV transmission line to provide for communication and control with Donlin Creek
Mine substation and the seven village substations, from the Bethel Power plant.
Although the 138-kV transmission line is operated radially from the Bethel Power Plant,
current backfeeding back into the transmission line from various large motors located at
the mine-site and from standby village and mine-site generation will require the system to
be treated as a dual source system for protective rela ying purposes. The recommended
protective relaying system will utilize micro-processor based technology, with
communications required between each terminal. A distance relaying scheme will be
used for protection of the transmission line. Each of the three-phase multi-rated 30/40/50
MVA main power transformers will be protected by use of micro-processor based
transformer differential protection scheme s. Standard generator protection schemes, using
microprocessor based relay technology, will be implemented to provide the necessary
generator protection.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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SUBSTATION FEASIBILITY DESIGN Section IV-3.2
B. BETHEL POWER PLANT SUBSTATION
1. Land-Based Power Plant
Figure IV-3.3 shows a general equipment layout of the substation, for the land-
based power plant alternative. To facilit ate the take-off of the 138-kV transmission line
from the proposed plant site location, it is recommended the substation be located in the
northwest quadrant of the plant site. The substation as proposed would occupy an area of
approximately 115 feet x 135 feet. The layout of the substation would be the same for
both the coal-fired and the combined-cycle combustion turbine generation alternative.
Three each, 30/40/50 MVA transformers operating in parallel would be used to
supply power to the 138-kV bus. To maintain a high degree of reliability, it is
recommended that each of the transformers be connected to the 13.8-kV bus by double
circuit underground feeders and that the 13.8-kV bus be connected to each generator by a
double circuit underground feeder. The transformers would be equipped with multiple
stage forced air cooling fans to provide for continuous operation at up to 50 MVA under
emergency conditions. Using multi-stage cooling, any two of the three transformers
operating in parallel would be capable of supplyin g the 30-year peak load projection.
Station service power would be provided by two 7.5 MVA, 13.8-kV to 4.16-kV
transformers for the coal-plant alternative, one connected at each end of the 13.8-kV bus.
For the combustion-turbine plant alternative, station service would be provided by two
3.5 MVA, 13.8-kV to 4.16-kV transformers. Oil containment for the transformers would
be provided as required.
Indoor metal-clad switch gear, located in the power plant, would be used on the
13.8-kV bus to provide system protection and switching flexibility, while outdoor SF6
breakers would be used on the 138-kV bus. Disconnect switches would be installed on
either side of the three SF6 bus breaker to provide a means of isolating breakers for
maintenance and repair. Bypass switches are not considered necessary on these three bus
breakers. A single disconnect switch is installed on the line side of the SF6 out-going line
breaker. A bypass switch is included on the line breaker to provide for maintenance and
repair on this breaker without having to de-energize the transmission line.
2. Barge-Mounted Power Plant
The main power substation would be located on the bluff area above the barges.
Figure IV-3.4 illustrates the general equipment layout of the substation, for this power
plant alternative. This arrangement differs from the land-based arrangement in three
ways. First, the 138-kV takeoff A-frame structure would be located in-line with the
transformer bus rather than at a ninety degree angle. Second, each barge-mounted
generator would be connected to the 13.8-kV bus by a single overhead circuit consisting
of two 954 ACSR bundled conductors per phase. To accomplish this, a steel A-frame
structure would be constructed on each barge and a similar A-Frame constructed on the
bluff. The overhead conductors installed at a low tension would span between the two
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
Power Supply Alternatives Feasibility Study Final Report 06/11/04
SUBSTATION FEASIBILITY DESIGN Section IV-3.3
sets of A-frames. Metal-clad switch gear, located on the barges, would be used on the
13.8-kV bus to provide system protection and switching flexibility. Lastly, the substation
as proposed would occupy an area of approximately 110 feet x 180 feet, which differs
fr om the dimensions of the substation for the land-based power plant alternative. In all
other aspects this substation would be identical to the main power substation as it is
described in the land-based power plant option.
C. DONLIN CREEK MINE SUBSTATION
A 138-kV to 13.8-kV step-down substation would be constructed at a suitable
location at the Donlin Creek mine site to be selected by Placer Dome, Inc. Electrical
system studies conducted by Electric Power System (EPS), see Appendix D, indicate that
a sizeable Static -Var-Compensation (SVC) system would need to be installed at the
Donlin Creek mine substation to maintain the mine’s power factor and system voltage
fluctuations to within acceptable limits. The substation and SVC system will be designed,
constructed and maintained at Placer Dome’s expense. The substation and SVC system
must be designed in accordance with standards and operating parameters acceptable to
both Placer Dome and Nuvista. A typical equipment layout for the substation is shown in
Figure IV-3.5. The incoming line breaker and bypass switch would remain under the
direct control of Nuvista. This breaker would open automatically in the event of a system
fault or it can be opened manually, by remote control, at the discretion of the Bethel
power plant operator.
D. VILLAGE SUBSTATIONS
Seven villages would be provided power from the 138-kV transmission line. A
typical village substatio n is shown in Figure IV-3.6. The primary equipment at each
substation would consist of a 138-kV circuit switcher, a 138-kV to 12.47-kV step-down
transformer rated at either 500 or 1,000 KVA, an electronically controlled recloser and a
disconnect switch, ne cessary metering and control instrumentation, and a security fence.
Oil containment for the transformer would be provided as required. A typical village
substation would occupy an area of about 35 feet x 70 feet. The Kalskag substation
would include acco mmodations for a future SWGR feeder. The Aniak substation would
also need to accommodate additional equipments as described in the subsequent
paragraph.
The Aniak substation is located roughly half-way between Bethel and the Donlin
mine. This substation would , in addition to the primary equipment found in each village
substation as described in the preceding paragraph, include an additional 138-kV circuit
switcher and a 10 MVA reactor as shown in Figure IV-3.7. A 10 MVA reactor must be
connected to the transmission line to limit peak transient voltages to an acceptable level,
when the transmission line is initially energized. (See Appendix D). The reactor would
be connected and disconnected from the 138-kV bus by a circuit switcher . The above
described design for the Aniak substation assumes a peak connected load at the mine of
70 megawatts with a typical load demand of approximately 55 megawatts. If the load
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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SUBSTATION FEASIBILITY DESIGN Section IV-3.4
demand at the mine and/or the load connect to the northern end of the line increases
appreciably, it would be necessary to install a bank of switchable capacitors at Aniak to
maintain adequate steady state voltages. However, the installation of an SVC system
would be the preferred, but more expensive solution, as an SVC would provide better
voltage support and control than a switchable capacitor bank(s). (See Appendix D).
E. INTERFACE WITH EXISTING VILLAGES DISTRIBUTION SYSTEMS
Except for Aniak, a 3-phase 4-wire 12.47/7.2-kV overhead distribution line, the
interface feeder, would be constructed fr om each of the seven step-down village
substations to connect the substation with the existing village distribution system. The
point -of-connection with the village distribution system or power delivery point, will be
at a location deemed to be reasonable and prudent by Nuvista. In most cases the delivery
point would be at the existing diesel plant substation. The exception to this general
statement may be at Upper/Lower Kalskag, as discussed below. At the delivery point,
Nuvista would install a deadend structure and a three phase disconnect switch.
Connection to the village distribution system, downstream of this switch, would be the
responsibility and at the expense of the village utility.
Alaska Village Electric Cooperative has or is planning to relocate the new diesel-
generation plant about half-way between Upper and Lower Kalskag and rebuild and
operate the overhead distribution system at 12.7/7.2-kV. The step-down substation for
Upper/Lower Kalskag would be located north of Upper Kalskag. The deliver y point for
Upper/Lower Kalskag would most likely be to a point on the northern end of Upper
Kalskag were the distribution line from the step-down substation can be easily connected
to a 12.47/7.2-kV village distribution feeder.
In the case of Ania k, the step-down substation would be located on the north bank
of the Kuskokwim River, slightly downstream of Aniak. A 12.47/7.2-kV overhead
distribution line would be constructed to span the river at this point. The span length
across the Kukokwim at this point is estimated at 1,000 feet. Once on the south side of
the river, the line would convert to a three phase underground feeder and be routed
parallel to the airport into town, where it would be connected the village distribution
system.
The substation for Tuluksak would be located on the west bank of the river. A 2.4
mile overhead interface feeder would be constructed to connect the step-down substation
with the village. The line would span the Kuskokwim River downstream of Tuluksak.
The river-crossing span is estimated at 1,200 feet.
The length of the connecting interface feeder from the step-down substation to the
village would vary from between three-quarters of mile for Akiachak to 5 miles for
Tuluskak.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IV
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SUBSTATION FEASIBILITY DESIGN Section IV-3.5
F. BETHEL UTILITIES EXISTING DIESEL PLANT SUBSTATION
A dedicated 13.8-kV distribution feeder originating at the Bethel Power Plant
Substation will provide power to Bethel Utilities’ existing diesel plant substation. To
interface the 13.8-kV dedicated feeder to the existing Bethel Utilities substation, it would
be necessary to install a 15 MVA three winding transformer at the existing Bethel
Utilities substation, as shown in one-line diagrams in Figures IV-3.1 and 3.2. Bethel
Utilities presently distributes power to the community at 12.47-kV and 4.16-kV, using a
delta connected system. About two -thirds of the community load is served by 12.47-kV
feeders, with the remaining one-third load served by 4.16-kV feeders. This three winding
transformer would step-down the voltage from 13.8-kV to 12.47-kV and 4.16-kV. The
transformer would also provide isolation between the 13.8-kV wye -grounded generation
system and the 12.47-kV delta distribution system operated by Bethel Utilities. Based on
typical transformer and generator impedances, EPS has calculated the maximum three-
phase short circuit fault current at the Bethel substation 4.16-kV bus at approximately
twenty thousand amperes. Should this fault current exceed the short-circuit rating of the
existing Bethel diesel plant substation equipment , corrective measures would be
undertaken to limit fault current energy. One method to limit fault current energy is by
using current limiting fuses on the 4.16-kV bus. A second method would be to increase
the impedance of the 4.16-kV transformer winding.
13.8 kV Bus138 kV Bus13.8kV/138kV40 MVATo Bethel Power Plant13.8 kV BusMine Feeder 1Mine Feeder 2138 kV BusDonlin Creek Mine SubstationTo Be Constructed by Placer Dome55-85 MW loadAkiachak Sub.500 kVA XfmrAkiak Sub.500 kVA XfmrTuluksak Sub.500 kVA XfmrKalskag Sub.500 kVA XfmrAniak Sub.1000 kVA XfmrChuathbaluk Sub.500 kVA XfmrCrooked Creek Sub.500 kVA XfmrSystem Oneline Diagram138kV 10 L-L to 80kV 10 L-G138kVCircuitSwitcher138kVCircuitSwitcherSWGR Transmission Line Yukon River Feeder138 kV/12.47 kV XfmrTo VillageVertical Tap to 138 kV Power LineOneline Diagram - All Village Substations Except Aniak4.16kV/12.47kV -7.5 MVAStation ServiceCombustion Turbine12.47 kV Electronic ControlledReclosure4.16/2.4KV BusTo Donlin Creek Mineand Villages13.8kV/138kV40 MVA13.8kV/138kV40 MVA13.8kV/138kV40 MVA13.8kV/138kV40 MVA4.16kV/12.47kV -7.5 MVAStation Service45 MWCoal-Fired Steam Turbine50 MWCoal-Fired Steam Turbine50 MW13.8kV 10 L-L to 80kV 10 L-G138kVCircuitSwitcher13.8kV 10 L-L to 80kV 10 L-G138kVCircuitSwitcherExpress 13.8 kV Feeder to Bethel UtilitiesExisting Diesel Power Plant Substation SWGR South Feeder SWGR West FeederFuture AdditionsFuture Addition4.16/2.4KV BusNuvista Light & Power Co.Coal-Fired Generation AlternativeBETTINE, LLCFigure IV-3.1138 kV/12.47 kV XfmrTo AniakVertical Tap Oneline Diagram - Aniak Substation12.47 kV Electronic ControlledReclosureVertical Tap 13.8kV-12.47kV-4.16kV12.47kV/10 MVA Motor OperatedDisconnect Swtch138 kV CircuitSwitcher9/04/03-FJB954 ACSR Bethel Power Plantand Substation4.16kV/5 MVAConnect to BU12.47 kV BusConnect to BU 4.16 kV BusADDITIONS TO BETHEL UTILITIES SUBSTATIONSVC SystemMotor OperatedDisconnect Switch138 kV CircuitSwitcherInsert 1Insert 2138 kV CircuitSwitcher10 MVA ReactorTo Donlin Creek138 kV Transmission LineTo Bethel Power Plant138 kV Breaker and Bypass SwitchUnder Nuvista Light & Power Control19 mi. 6.5 mi. 17.3 mi.42.1 mi.25 mi.12.9 mi.54.3 mi.13.5 mi.See Detail BDetail ADetail B
13.8 kV Bus138 kV Bus13.8kV/138kV40 MVATo Bethel Power Plant13.8 kV BusMine Feeder 1Mine Feeder 2138 kV BusDonlin Creek Mine SubstationTo Be Constructed by Placer Dome55-85 MW loadAkiachak Sub.500 kVA XfmrAkiak Sub.500 kVA XfmrTuluksak Sub.500 kVA XfmrKalskag Sub.500 kVA XfmrAniak Sub.1000 kVA XfmrChuathbaluk Sub.500 kVA XfmrCrooked Creek Sub.500 kVA XfmrSystem Oneline Diagram138kV 10 L-L to 80kV 10 L-G138kVCircuitSwitcher138kVCircuitSwitcherSWGR Transmission Line Yukon River Feeder138 kV/12.47 kV XfmrTo VillageVertical Tap to 138 kV Power LineOneline Diagram - All Village Substations Except Aniak4.16kV/12.47kV -3.5 MVAStation Service12.47 kV Electronic ControlledReclosure4.16/2.4KV BusTo Donlin Creek Mineand Villages13.8kV/138kV40 MVA13.8kV/138kV40 MVA13.8kV/138kV40 MVA13.8kV/138kV40 MVA4.16kV/12.47kV -3.5 MVAStation ServiceCombustion Turbine45 MW13.8kV 10 L-L to 80kV 10 L-G138kVCircuitSwitcher13.8kV 10 L-L to 80kV 10 L-G138kVCircuitSwitcherExpress 13.8 kV Feeder to Bethel UtilitiesExisting Diesel Power Plant Substation SWGR South Feeder SWGR West FeederFuture AdditionsFuture Addition4.16/2.4KV BusNuvista Light & Power Co.Combined-Cycle Generation AlternativeBETTINE, LLCFigure IV-3.2138 kV/12.47 kV XfmrTo AniakVertical Tap Oneline Diagram - Aniak Substation12.47 kV Electronic ControlledReclosureCombustion Turbine45 MWCombustion Turbine45 MWSteam Turbine25 MWVertical Tap Switcher13.8kV-12.47kV-4.16kV12.47kV/10 MVA Motor OperatedDisconnect Swtch138 kV CircuitSwitcher9/04/03-FJB954 ACSR Bethel Power Plantand Substation4.16kV/5 MVAConnect to BU12.47 kV BusConnect to BU 4.16 kV BusADDITIONS TO BETHEL UTILITIES SUBSTATIONSVC SystemMotor OperatedDisconnect Switch138 kV CircuitInsert 1Insert 2138 kV CircuitSwitcher10 MVA ReactorTo Donlin Creek138 kV Transmission LineTo Bethel Power Plant138 kV Breaker and Bypass SwitchUnder Nuvista Light & Power Control19 mi. 6.5 mi. 17.3 mi.42.1 mi.25 mi.12.9 mi.54.3 mi.13.5 mi.Detail BSee Detail BDetail A
Double CircuitUG FeederDouble CircuitUG FeederDouble CircuitUG FeederTurbine 1 - DoubleCircuit FeederTurbine 2 - DoubleCircuit FeederTurbine 3 - DoubleCircuit FeederTo Generation 13.8 kV Metal Clad Switch Gear Located in Power PlantDSSF6 CBSubstation Fence LineLEGEND:CB - 138 kV Circuit BreakerDS - 138 kV Disconnect SwitchLA - 138 kV Lightning Arrester- Bus SupportNuvista Light & Power Co.Land-Based Generation Plant AlternativeSUBSTATION CONCEPTUAL LAYOUTBETTINE, LLCNorth20' Double GateFigure IV-3.3DSDSDSDSDS12.47 kV Express Feederto Bethel Utilities' ExistingDiesel Plant Substation To 4.16kVStation BusTo 4.16kV Station Bus13.8kV/4.16kV XFMR7.5 MVA Coal Plant3.5 MVA CT Plant13.8kV/4.16kV XFMR138 kV and 13.8 kvVertical Mount DisconnectSwitchesSF6 CBSF6 CBSF6 CBWith BypassSwitchTurbine 4 - Combution TurbineAlternative Only - DoubleCircuit Feeder7.5 MVA Coal Plant3.5 MVA CT PlantLA13.8kV/138kVXFMR - 40 MVA138 kV Transmission LineTo Donlin Creek Mine & Villageswith 13.8 kV Underbuild to Bethel Utilities' Existing Diesel Plant SubstationA-Frame Takeoff Structurefor 138 kV and 12.47 kV circuits LALALALALALALALA13.8kV/138kVXFMR - 40 MVA13.8kV/138kVXFMR - 40 MVA9/04/03-FJB13.8 kV Bus, Breakers Not Shown
DSSF6 CBSubstation Fence LineLEGEND:CB - 138 kV Circuit BreakerDS - 138 kV Disconnect SwitchLA - 138 kV Lightning Arrester- Bus SupportNuvista Light & Power Co.Barge-Mounted Generation Plant AlternativeSUBSTATION CONCEPTUAL LAYOUTBETTINE, LLCNorth20' Double GateFigure IV-3.4DSDSDSDSDS12.47 kV Express Feederto Bethel Utilities' ExistingDiesel Plant SubstationSF6 CBSF6 CB138 kV and 13.8 kvVertical Mount DisconnectSwitchesSF6 CBWith BypassSwitchTurbine 3 - Overhead FeederSlack Span to Barge MountedA-FrameTurbine 2 - Overhead FeederSlack Span to Barge MountedA-FrameTurbine 1 - Overhead FeederSlack Span to Barge MountedA-FrameLA13.8kV/138kVXFMR - 40 MVALALALALALALALALA13.8kV/138kVXFMR - 40 MVA13.8kV/138kVXFMR - 40 MVA9/04/03-FJB138 kV Transmission LineTo Donlin Creek Mine & Villageswith 13.8 kV Underbuild to Bethel Utilities' Existing Diesel Plant SubstationA-Frame Takeoff Structurefor 138 kV and 12.47 kV circuits A-Frame withDisconnectA-Frame withDisconnectA-Frame withDisconnect13.8 kV Risers13.8 kV Circuit Breakerwith Bypass Switch13.8 kV Circuit Breakerwith Bypass Switch13.8 kV Circuit Breakerwith Bypass Switch
LEGEND:CB - 138 kV Circuit BreakerDS - 138 kV Disconnect SwitchLA - 138 kV Lightning Arrester- Bus SupportNuvista Light & Power Co.Donlin Creek MineSUBSTATION CONCEPTUAL LAYOUTBETTINE, LLCFigure IV-3.5SF6 CBSF6 CBSF6 CBwith BypassSwitchUGUG13.8kV Metal CladSwitch Gear andControl BuildingUG Feeder 1UG Feeder 2LALALALALALA138kV/12.47kV XFMR 40 MVA138kV/12.47kV XFMR 40 MVATo Donlin Creek MinePower Distibution CenterA-Frame with VerticalMount Disconnect SwitchDouble CircuitUG FeederUG Feeder20' Double GateDSDSDSDSSubstation Fence LineIncoming 138 kV Transmission Line9/04/03-FJBDouble CircuitTo SVC System13.8 kV Bus, Brealers Not ShownEquipment upstream of this line to remainunder the direct control of Nuvista
To Village138 kV CircuitSwitcher138 kV/12.47 kV XfmrRecloserFigure IV-3.6Village Stepdown SubstationConceptual LayoutMotor OperatedDisconnect SwitchVertical Tap to 138 kV Power LineNuvista Light & Power Co.Bettine, LLC 9/043/03-FJBLALALALA - 138 kV Lightning Arrestor
To Village138 kV CircuitSwitcher138 kV/12.47 kV XfmrRecloserFigure IV-3.7Aniak Stepdown SubstationConceptual LayoutMotor OperatedDisconnect SwitchVertical Tap to 138 kV Power Line10 MVA Reactor138 kV CircuitSwitcherNuvista Light & Power Co.Bettine, LLC 9/043/03-FJBLALALALALALALA - 138 kV Lightning Arrester
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION V
Power Supply Feasibility Study Final Report 06/11/04
TRANSMISSION LINE ENVIRONMENTAL PLANNING V-1.1
SECTION V PRELIMINARY ENVIRONMENTAL
PLANNING
SECTION V-1 – TRANSMISSION LINE ENVIRONMENTAL
PLANNING
A. INTRODUCTION
Nuvista Light & Power, Co. (Nuvista) is investig ating the feasibility of constructing
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. Nuvista is a non-profit corporation created to serve as a regional generation and
transmission utility for the Calista region. The transmission line would be located along
the northern bank of the Kuskokwim River. The power line would serve Bethel,
Akiachak, Akiak, Tulu ksak, Lower/Upper Kalskag, Aniak, Chuathbaluk Crooked Creek
and the proposed Donlin Creek gold mine. The proposed power plant would be located
south of the Bethel.
Travis/Peterson Environmental, Inc. was retained to conduct a preliminary
environmental planning review of the proposed transmission line project, while the firm
of Steigers, Inc. was retained to conduct a preliminary environmental planning review of
the proposed Bethel power plant alternatives. The report s received from each of these two
firms are contained in Appendix F.
The purpose of the planning reviews is to identify, at the outset of the project, those
issues that could potentially delay or hinder the permitting and construction of the power
generation and transmission facilities. The transmission line project is discussed first
followed by the power plant project.
B. TRANSMISSION LINE ENVIRONMENTAL REQUIREMENTS
ASSESSMENT
A preliminary review was performed by contacting agencies, stakeholders
researching publications and internet web sites, and reviewing comments from agencies
and stakeholders. A letter was sent to environmental agencies, the affected communities,
landowners, and other interest ed groups to introduce the proposed transmission line and
power plant project and request comments. The following summarizes the environmental
issues identified by the environmental agencies and the other interested parties.
· 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;
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION V
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TRANSMISSION LINE ENVIRONMENTAL PLANNING V-1.2
· 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;
· 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;
· NMFS and USF&WS revealed that there are no threatened or endangered species
existing in the vicinity of the proposed project area.
· The Kuskokwim River is considered EFH. Several creeks and rivers draining into the
Kuskokwim River also appear to have EFH. According to the NMFS, and 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.
· 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 ha s 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
· 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 not been conveyed.
· 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;
· Constructio n 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 R.O.W.s across native
lands, private lands, state and federal lands; and
· The trans mission line will require many different permits for its completion.
A more thorough discussion of each of the above issues follows in subsequent
paragraphs.
1. Land Use Impacts
The feasibility study has identified an alternative that is approximately 191 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 the
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION V
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TRANSMISSION LINE ENVIRONMENTAL PLANNING V-1.3
maximum extent possible, to avoid crossing Yukon Delta National Wildlife Refuge
(NWR) lands, state and other federal lands.
The proposed pro ject may affect five groups of land owners. These are regional
corporations, village corporations, native allotments, state and federal land owners. The
majority of the lands over which the transmission line would be built are owned by
private landowners and village corporations. The Kuskokwim Corporation (TKC) owns
the majority of the surface estate along the proposed route. For the most part Calista owns
the subsurface rights along the future route. The proposed transmission route would also
cross native allotments. Two federal agencies administer lands along the proposed route.
The BLM manages unappropriated federal lands and the United States Fish and Wildlife
Service (USFWS) manages the Yukon Delta NWR. Distribution lines feeding power to
the seven villages would cross village corporation lands.
No permanent roads would be maintained on the transmission line right -of-way
(ROW). The transmission line would require a R.O.W. 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 would be maintained using a combination
of helicopters, boats and tracked vehicles.
Landownership consists of surface rights and subsurface rights. This project
would affect mainly the surface estate, but some subsurface lands would be affected due
to required material sources. The ownership rights within each segment of the affected
lands can be found in Section IV, Table IV-1.4.
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 conveyed to a native corporation are managed as any other refuge lands
under their jurisdiction. The development on those lands will require a R.O.W. permit.
The USFWS 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 a R.O.W. 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. There are many private allotments, city-owned
land s, and BNC owned land located near Bethel. Table V-1.1 lists the surface and
subsurface landownership rights.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION V
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TRANSMISSION LINE ENVIRONMENTAL PLANNING V-1.4
TABLE V-1.1
LANDOWNERSHIP RIGHTS
Owner
Surface Rights Subsurface Rights Explanation
Calista Regional Cor poration Yes Yes Calista Owns Both Rights
Village Corporations Yes No Calista Owns Subsurface
City Lands Yes No Calista Owns Subsurface
Native Allotments Yes No Subsurface Ownership Varies
USFWS Yes Yes USFWS Owns Both Rights
State Lands Yes Yes State Owns Both Rights
BLM Yes Yes BLM Owns Both Rights
Federal Townsites transferred
to Municipal Governments
Yes Yes Muni.Governments Own
Both Rights
Federal Townsites held in trust
by Federal Government
Yes Yes Federal Government Owns
Both Rights
2. Wetlands
The proposed transmissio n line would 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 would 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 fill 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 would
require minimal fill. Mitigatio n and minimization measures need to be discussed in the
permit application.
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.
4. Floodplain Management
The power plant and transmission lines would be located within the Kuskokwim
River floodplain. Neither the transmission line nor its support towers would restrict flo w.
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Ice flows are common within the Kuskokwim River floodplain. Support towers
vulnerable to ice flows and flood events would be engineered to withstand these events.
5. Threatened and Endangered Species
According to the USFWS, there are no threatened or endangered species of plants
or animals 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 is not aware of any threatened or
endangered species under their jurisdiction (NMFS, 2003a).
6. Essential Fish Habitat
NMFS considers the Kuskokwim River as Essential Fish Habitat (EFH) under the
Magnuson-Stevens Act. Many creeks and rivers 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 require EFH assessments. 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
recommended mitigation, they will concur with the assessment enabling the construction
effort to proceed. Mitigation may be necessary (NMFS, 2003a).
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
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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.
If ADNR concurs with the results then the project may proceed (ADNR OHMP,
2003b).
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).
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 complet ed 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).
10. Historic, Architectural, Archaeological, and Cultural Resources
The State Historic and Preservation Office (SHPO) anticipates 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).
11. 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 would
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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 R.O.W. permits will required
from land owners to access and perform construction within the transmission line R.O.W.
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 to maintain the
transmission line. The transmission line would be maintained via off-road vehicles, boats
and helicopters.
Trees and undergrowth would 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. 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 could temporarily be impacted during the construction phase from
erosion and runo ff from construction areas. The contractor would 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 would be disposed of in
nearby community landfills or removed off-site to Bethel.
12. 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 a single project.
The proposed power plant and transmission line would supply the power
necessary to operate the Donlin Creek Mine. Donlin Creek Mine would consume over 80
percent of the electrical power transmitted along the new power grid. Donlin Creek Mine
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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 may be built to supply 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.
13. Federal Process
Since it is anticipated that federal money would 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 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). Nuvista, however, disagrees
with the position taken by these agencies.
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;
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· Finalize EIS and circulate the final document for 30 days; and
· Lead agency issues a Record of Decision (ROD).
A copy of the USDA, RUS, and NEPA policies and regulations are attached in
Appendix F. Assuming there are no significant obstacles encountered during the EIS
process, Travis/Peterson estimates the entire environmental process to take approximately
2.5 years to complete.
14. Anticipated Permits
It is anticipated that the required environmental studies and location engineering for
the 138-kV transmission line would begin during early 2004 and would be completed by
the end of 2006. To proceed with construction in a timely manner, it is anticipated that
an approved EIS and all required permits would be required on or before the end of 2006.
It is anticipated final engineering and construction of the selected power supply
alternative and the Bethel to Donlin Creek mine 138-kV transmission line would occur
between 2007-2010, with all systems fully operational by late spring 2010.
Table V-1.2 summarizes the potential permits required for this project and the
regulatory agencies that approve them.
TABLE V-1.2
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
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or more persons per day must. (May apply to
construction camp)
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.
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SECTION V-2 POWER PLANT ENVIRONMENTAL PLANNING
A. BETHEL POWER PLANT ENVIRONMENTAL REQUIREMENTS
ASSESSMENT
As stated previously, Steigers Corporation was retained to conduct a preliminary
environmental requirements assessment for the Bethel power plant alternatives. As part
of the process, input from interested parties was solicited. To accomplish this, a letter was
developed and presented to 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 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.
1. 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 Project would be provided through the U.S. Department of
Agriculture (USDA), Division of Rural Utilities (RUS). Thus, federal funding would
likely be one of the triggers for NEPA compliance. 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.
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2. Scope of NEPA Compliance Review
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.
Therefore, from a NEPA compliance standpoint, of the foremost issue that must be
immediately addressed and resolved 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.
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.
The Corps has since suggested that tiering the NEPA analysis of the mine project
off the power plant/tranmission line EIS would be satifactory to the Corps. Tiering
would allow the EIS and permitting of the power plant and transmission line to 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 the agencies reject a
tiering approach, 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
effectively preclude the need for an alternative power source and would likely preempt
development of the Bethel Power Plant/transmission line project as proposed in this
report.
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, selection of
the lead federal agency will likely be determined by the scope of the NEPA review. The
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most likely lead agency candidates would be the U.S. Department of the Interior or the
Army Corps of Engineers.
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 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. 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.
3. Agency Comments
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 Appendix F.
a. 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
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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 evaluate and certify compliance with
state water quality standards under Section 401 of the Clean Water Act.
b. 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
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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.
• 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
R.O.W. 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 R.O.W. permit is required, feasibility study and
environmental analysis of the project will need to be prepared for the USFWS
permit application.
• 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.
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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.
c. Others
A letter was received from Ms. Meera Kohler, President and CEO, Alaska Village
Electric Cooperative, Inc. (AVEC) in which she provided suggestions for revising
Figure I-1.3 of the project description that was included with the initial
consultation letter. Figure I-1.3 is an aerial photograph of Bethel and vicinity
showing the proposed Bethel power plant locations.
B. ENVIRONMENTAL ISSUES & 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. However, it is anticipated the major
environmental issues likely to be associated with one or more of the power plant
alternatives will include the following:
• Alaska Coastal Zone Management
• Air Quality
• Water Quality
• Wetlands and Navigable Rivers
• Fish Habitat
• Floodplain Development
• Air Traffic
• NEPA Compliance
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
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zone management areas, the City of Bethel Coastal Management District and the
Cenaliulriit Coastal Regional Service Area.
2. Air Quality
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.
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
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.
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 PSD construction permit applicant must perform an AQRV (Air Quality
Related Values) analysis to ensure that environmental values (i.e., visibility, flora, fauna,
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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 (certain 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.
3. Water Quality
All three alternatives for the Bethel power plant have proposed to 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. 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.
An 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 its associated cost.
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
would 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
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Permit. Section 401 Certification will be required. The Section 401 Certification would
be completed concurrently with the draft NPDES permit and would identify any potential
water quality problems with the proposed discharge.
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 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. It is possible to include the analysis and
application for the NPDES Stormwater Discharge Permit with that for the NPDES
Wastewater Discharge Permit.
4. Wetlands and Navigable Waters
The site proposed for construction of the three Bethel power plant alternatives
occupies low-lying tundra areas, wetlands, and ponds. The barge-mounted power plant
option proposes construction and/or dredging and filling within the floodplain of the
Kuskokwim River to accommodate barge-mounted power plant units. These activities
would likely trigger federal permitting under the Clean Water Act and/or the Rivers and
Harbors Act.
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.
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, 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. 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.
Corps jurisdiction under the Rivers and Harbors Act is limited to "navigable
waters" 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.
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All three 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. Fish Habitat
All three alternatives for the Bethel power plant involve aquatic habitats and,
therefore potentially, fish habitat. The Kuskokwim River, which would host at least dock
and barge-unloading facilities under all alternatives and also constructed mooring
accommodations for the 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. NMFS requires the
federal agency authorizing the project to prepare an EFH Assessment for any action that
may adversely affect EFH. Once it has reviewed the EFH Assessment, NMFS may offer
conservation recommendations to protect EFH to the federal action agency. The
Kuskokwim River is also catalogued as an anadromous fish stream by the Alaska
Department of Fish and Game (ADF&G) (ADF&G 2003). Because of its classification
as an anadromous fish stream, construction activities in the Kuskokwim River under any
of the three alternatives would likely require application for a Office of Habitat
Management Permitting (OHMP) Fish Habitat Permit. Depending on the fisheries
characteristics of the proposed cooling pond, wastewater discharges into the pond might
also require this permit.
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. In addition to the “no rise” certification, an Application for
Flood Hazard Permit must be completed and submitted to the local municipality.
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POWER PLANT ENVIRONMENTAL PLANNING V-2.11
7. FAA
The FAA letter expressed concern over possible adverse effects on instrument
procedures to the Bethel 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 any 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 difficulty 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 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.
8. Permits
Table V-2.1 summarizes the potential permits required for power plant and the
regulatory agencies that approve them. Many of the permits required for construction of
the power plant are also required for the construction of transmission line.
TABLE V-2.1 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
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Agency Name Permit/Approval
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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PROJECT COST ESTIMATES Section VI-1.1
SECTION VI PROJECT COST ESTIMATES
1. INTRODUCTION & BACKGROUND
A. INTRODUCTION
This section presents the assumptions and summarizes the project cost estimates
prepared for this report. Project costs include all costs required to plan, develop, engineer,
build, operate and maintain the 138-kV Donlin Creek transmission line and the two
primary generation alternatives investigated as part of this report for supplying power to
the mine, which are: (1) a coal-fired power plant located at Bethel; and (2) a combined-
cycle combustion turbine plant located at Bethel or Crooked Creek.
Project cost estimates were also prepared, but with a lesser degree of accuracy, for
a combined-cycle combustion turbine power plant at Crooked Creek, a + 100-kV DC
transmission line from Nenana to the mine site and a 230-kV AC line built from Nenana
to the mine site. These three power supply alternatives were investigated as part of the
Calista Region Energy Needs Study, dated July 1, 2000, and were determined to provid e
less economical power than a coal-fired plant located at Bethel. However, updated costs
for these three alternatives were prepared as part of this study to re-evaluate the economic
feasibility of these alternatives.
B. COAL-FIRED GENERATION PLANT LOCATED AT BETHEL1
The following cost estimates for the project were based on equipment quotations
obtained from major equipment vendors and estimates. The estimates below include all
cost components such as: engineering, procurement, installation, allocated foundation and
common system cost, construction management and all other related cost items. Cost of
equipment and system installation was based primarily upon vendor estimates; some
costs were estimated as a percentage of equipment cost, based on average industry data.
Start-Up and Commissioning includes labor and consumable cost s during the six months
start up/run-in period. Cost estimates are provided for both a land-based power plant and
a barge-mounted power plant. Land acquisition costs are not included.
1 See report prepared by PES in Appendix A.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.2
1. Land - Based Power Plant
Fuel Receiving and Storage2 $ 33,267,400
Steam Plant $ 55,466,300
Generating System $ 23,509,200
Ash Handling & Disposal System $ 626,200
Environmental Systems & Controls $ 4,085,300
Rolling Stock $ 2,142,500
Plant Utilities & Services $ 13,590,600
Civil & Structural $ 5,253,000
LCMF Foundations and Civil Work $ 39,651,1003
Project Services and Facilities $ 16,793,600
Start-Up and Commissioning $ 4,876,100
Total Systems $ 199,261,300
Contingency 10% $ 15,961,000
Sub-Total Plant $ 215,222,3004
Cost per Kilowatt @ 96.6 MW Gross Output $2,227/ kW
Stand-by Combustion Turbine CTG (GTX100 / LM6000) $ 16,862,000
Total Capital Cost Land-Based Plant $232,084,300
Not included in the above is $3,000,000 in Owner costs for Environmental
Studies and Permitting.
2. Barge - Mounted Power Plant
The following cost schedule is for the Power Barge Option. As above, the cost of
the district heating system, stand-by CTG, and Environmental Impact Study are
listed separately.
Fuel Receiving and Storage $ 33,267,400
Steam Plant $ 47,156,800
Generating System $ 20,896,700
Ash Handling & Disposal System $ 626,200
Environmental Systems & Controls $ 3,003,000
Rolling Stock $ 2,142,500
Plant Utilities & Services $ 9,684,100
Civil & Structural $ 2,123,800
Barges (2) including cargo-shipping to Bethel $ 9,600,000
2 Includes cost of dock facilities
3 Includes 10% Contingency
4 Assumes covered but unlined coal storage.
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PROJECT COST ESTIMATES Section VI-1.3
LCMF Foundations and Civil Work (coal storage & dock only) $ 31,355,3005
Project Services and Facilities $ 13,812,700
Start-Up and Commissio ning $ 3,876,100
Total Systems $ 177,544,600
Contingency 10% 14,618,900
Total Plant $ 192,163,5006
Cost per Kilo watt @ 96.6 MW Gross Output $1,989/kW
Stand-by Combustion Turbine CTG (GTX100 / LM6000) $ 16,862,000
Total Capital Barge-Mounted Plant $209,025,500
Not included in the above is $3,000,000 in Owner costs for Environmental Studies
and Permitting.
The cost difference between the land-based and barge-mounted power plants is
$23,058,800. The difference in cost is the result of savings obtained from eliminating
high-cost foundations, for the steam and power generating plants, and the increased
productivity associated with assembling the power plant at a shipyard rather than in the
field.
3. Capital Cost Implications of the Application of Usibelli Coal
PES has carefully investigated the potential for using Usibelli coal rather than
Fording coal. The heating value of Usibelli coal, as mined, is 7,168 Btu/lb vs. 12,284
Btu/lb (Calculated DuLong HHV) of Fording coal. In addition we must also take into the
account the fact that there is a 5.5% difference in the boiler efficiency, 89.1% for Fording
coal versus 83.4% for Usibelli coal, due to the higher moisture and oxygen content in the
fuel. A power plant operation that required 412,300 tons of Fording coal would require
approximately 687,000 tons of Usibelli coal. This fact dictates a much larger (and more
costly) coal storage facilities, boilers, ducts, emission control equipment and higher
expenses on moving coal, air and combustion gases, which increases capital cost by
approximately $35,000,000. If Usibelli coal were dried, to obtain an energy content of
11,100 BTU/lb, which would approximate the BTU content found in Luscar coal from
Canada, capital cost would increase by less than 5 million dollars.
The cost of the storage building would be about $25,000,000 higher. The storage
building cost increase includes material handling equipment inside the building. Other
additionally required capital items would include:
5 See Footnote 3
6 See Footnote 4
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.4
i. Larger boiler due to larger flows and required larger heat transfer surface
(lower quality coal burns at lower temperature with lower heat transfer
coefficient); estimated cost increase: $5,800,000
ii. Larger flue gas ducts outside boiler, passages and stacks $1,500,000
iii. Higher cost of conveying system $1,000,000
iv. NOx Control System $ 920,000
v. Coal bunkers with dust control $1,000,000
Total estimated Capital Cost increase, including coal storage cost $35,220,000
4. Possible Savings from Utilization of Healy Clean Coal Power Plant
Equipment
Only preliminary investigations were carried out; they consisted of contacting the
persons responsible for the project on the part of AIDEA (Alaska Industrial Development
and Export Authority) and the Federal Department of Energy, as well as reading progress
reports of this project. The conclusions/recommendations presented herein are
preliminary; an in-depth evaluation of the plant is required.
The Healy Clean Coal Power Plant (HCCP) was designed to use 50% Usibelli
run-of-the-mine coal and 50% waste coal. The applied technology is TRW’s “entrained/
slagging” combustion and B&W’s spray drier absorber desulfurization system. The
technology was designed for burning high ash and moisture content coal. The B&W
spray drier absorption system is not suitable for use in the Bethel project. Before actually
inspecting the boiler it is impossible to state its suitability for the Bethel project, however,
for the purpose of this study it is assumed the boiler is not suitable.
Of the steam plant, some of the boiler ancillary equipment may be utilized:
- Combustion air blowers
- Feedwater pumps
- Boiler controls and instrumentation
- Induced draft fan
- Filter baghouse
- De-aerator
- A significant portion of the coal delivery and feeding system
- Portions of the ash handling system – depending on the design of
the existing one.
The turbine generator side of the HCCP can most likely be utilized in its entirety.
During the design and procurement of the second steam-generator line, care must be
applied to equipment selection so that the Bethel Plant will not need to warehouse double
amounts of spare parts.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.5
The equipment would have to be delivered to a Southern Alaska port (Seward)
where it would be put on a barge and shipped to a West Coast shipyard (Vancouver, BC,
Anacortes, WA, or other) where the boiler and the rest of the equipment would be
assembled on the power barge.
The savings are estimated as follows:
Expenses
1. Acquisition at no cost
2. Disassembly, shipping to Seward ($ 1,450,000)
3. Preliminary mounting on barge and shipping to West Coast port ($ 730,000)
Other installation and shipping cost items will be the same as for a new plant.
Avoided equipment cost, estimate $11,700,000
Estimated savings $ 9,520,000
Remark: This amount is an estimate of possible savings. It will be confirmed
only after a thorough investigation of the Healy Plant.
5. Coal-Fired Plant O&M Estimates, Less Fuel Costs
The following estimate was based in part on information obtained from a power
plant in Gillette, WY where B&W PC boilers are working, PES’ experience with a 100
MW CFB coal-fired plant, and other industry sources. Adjustments were made to labor
costs for the plant location. The cost of ash disposal is assumed to be neutral due to
proposed ash utilization option.
Gross Power Produced: 96.6 MW including 5 MW for transmission losses and 8.5
MW parasitic load (for plant internal usage). Net Power Produced for sale: 82.8 MW
including 70 MW to supply peak demand of Donlin Mine and 12.8 MW for the City of
Bethel and the Villages.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.6
Positions No. of Employees Yearly Cost
Management
Plant Manager 1 120,000
Production Manager 1 72,800
Shift Hourly Personnel
Shift Supervisor (4) 4 210,413
Auxiliary Operator (4) 4 190,861
Fuel Handler (4) 4 151,174
Equipment Operator (4) 4 148,595
Scheduled OT 4 shifts 8.8% use 10% 115,672
Hourly personnel
Administrative Assistant 1 42,390
Purchasing and Coal & Ash Administration 1 54,080
Fuel Barge Unloaders (6) Part-time 6 85,442
Journeyman Mechanic 1 51,189
Millwright Machinist 1 52,104
Apprentice Mechanic 1 36,150
Garage Mechanic 1 45,531
Journeyman Welder 1 47,840
Journeyman Electrician 1 48,776
I&C Technician (2) 2 133,120
Total Direct payroll employees and cost 28 1,405,023
Burden Rate % 32% 449,607
Scheduled OT & Part Time 201,114
Non-Scheduled OT 55,579
Total Personnel Cost 2,111,324
Other Operating and Yearly Cost
Fuel for rolling stock and standby utility boiler 118,000
Technical Services and Outside Support 300,000
Testing, outside Lab Analysis, Inside water Lab and testing supplies 25,000
Travel, Training and Safety 50,000
Contact services-Janitorial 24,000
Consumables office 5,000
Consumables plant including water treatment chemicals 200,000
Urea cost 1500 tons per year 150,000
Ash disposal (ash to be made into aggregate, concrete cost) – neutral 0
Replacement tools and equipment 15,000
Phone, mail and express service 12,000
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.7
Parts and materiel shipment to port, annual barge and misc. air 350,000
Water - no cost included in maintenance & station power 0
Spare parts & maintenance cost (Eqt 5%, Bldg 1%, El. 10%, Rolling
Stock 10%) + Reserve of $500,000 Annually 3,200,000
Waste removal & disposal (except ash) 15,000
Property lease 0
Insurance fee (Fire, Accident) 300,000
Taxes 0
Miscellaneous contingency 5% 238,200
Subtotal other operating cost 5,002,200
Total O&M $7,113,524
Power production per year at net 100% sales MWh 99% availability 718,075
O&M cost per net MWh $/MWh 9.91
$/kWh 0.0099
Estimated major additional operating cost resulting from the application of
Usibelli coal:
i. Due to dusting and the tendency to spontaneous
heating and auto-ignition, storage of the Usibelli
coal would require constant monitoring of hot spots
and pile compacting, yearly $ 250,000
ii. Additional maintenance of materials handling
equipment and rolling stock, including spare parts,
yearly $ 280,000
Total additio nal operating cost $530,000
C. COMBINED-CYCLE COMBUSTION TURBINE PLANT7
1. Bethel Power Plant
The following cost estimates for the project were based on equipment quotations
obtained from major equipment vendors and estimates. The estimates below include all
cost components as: engineering, procurement, installation, allocated foundation and
common system cost, construction management and all other related cost items. Cost of
equipment and system installation was based primarily upon vendor estimates; some
costs were estimated as a percentage of equipment cost, based on average industry data.
The position Start -Up and Commissioning includes labor and consumable cost during the
7 See report prepared by PES in Appendix B.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.8
six months start up/run-in period. Cost estimates are provided for both a land-based
power plant and a barge-mounted power plant.
2. Bethel Land-Based Power Plant
Combustion Turbine Equipment $ 51,300,000
Steam Co-Generating System 18,809,600
Combustion & Steam Turbine Additional Equipment 11,162,800
Civil & Structural, including LCMF scope 44,585,000
Plant Services 3,470,650
Rolling Stock 585,000
Project Services and installations 14,771,113
Start up and commissioning 398,420
Total Plant 145,083,000
Contingency 10% 14,508,000
Grand Total Plant $159,591,000
Cost per Kilowatt @ 150 MW Gross Output $1,064/kW
Not included in the above is $3,000,000 in Owner costs for Environmental
Studies and Permitting
The equipment cost of the diesel–based power plant is in the same order as the
cost of the CT–based power plant, however, the installation cost, including bringing in
cranes of sufficient lifting capacity, is significantly higher than that for the CT–based
plant.
3. Bethel Barge-Mounted Power Plant
The following cost schedule is for the cost of a Barge-Mounted Modular Plant.
The fuel storage Tank Farm, the 100,000 gallon water tank, as well as the maintenance
shop will be located on shore.
Combustion Turbine Equipment $ 49,117,500
Steam Co-Generating System 16,112,000
Combustion & Steam Turbine Additional Equipment 9,208,900
Civil & Structural, including LCMF scope 38,335,000
Plant Services 2,674,825
Rolling Stock 385,000
Project Services and installations 14,771,100
Start up and commissioning 398,425
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.9
Cost of barge 4,500,000
Total Plant 135,502,750
Contingency 10% 13,450,250
Grand Total Plant $148,953,000
Cost per Kilowatt @ 150 MW Gross Output $993/kW
The capital cost of the barge mounted power plant is $10,638,000 lower than the
cost of land-mounted plant.
4. Crooked Creek Power Plant -Land-Based Option Only 8
Combustion Turbine Equipment $ 34,500,000
Steam Co-Generating System 18,809,600
Combustion & Steam Turbine Additional Equipment 11,162,800
Civil & Structural, including LCMF scope 32,700,000
Plant Services 3,470,650
Rolling Stock 585,000
Project Services and installations 10,800,000
Start up and commissioning 398,420
Total Plant 112,426,470
Contingency 10% 11,242,000
Grand Total Plant $123,669,000
Cost per Megawatt @ 110 MW Gross Output $1,124,264
Cost per Kilowatt $1124/kW
Not included in the above is $3,000,000 in Owner costs for Environmental Studies
and Permitting
5. Combustion Turbine Plant O&M Estimates, Less Fuel Costs
Personnel # Employees Cost per Year
Management
Plant Manager incl. Safety and Environmental 1 120,000
Production Manager 1 72,800
Shift Hourly Personnel
Shift Supervisor 4 210,413
Auxiliary Operator 4 190,862
8 Estimates based on Bethel Land-Based Combined-Cycle Combustion Turbine Power Plant option. Cost
estimate prepared by Bettine, LLC
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.10
Equipment Operator 4 148,595
Hourly personnel
Administrative Assistant, Purchasing & Records 1 42,390
Millwright Machinist 1 52,104
Journe yman Welder 1 47,840
Journeyman Electrician 1 48,776
I&C Technician (2) 2 133,120
Total Personnel Full Time 22
Total Direct payroll cost 1,066,900
Burden Rate % 32% 341,408
Scheduled OT & Part Time 90,728
Non-Scheduled OT 100,029
Total Personnel Cost 1,599,065
Equipment O&M
Fuel and lube oil for rolling stock and boiler 208,000
Technical Services and Outside Support 300,000
Testing, outside Lab Analysis, Inside water Lab and testing supplies 25,000
Travel, Training and Safety 50,000
Contact services-Janitorial 6,000
Consumables office 4,000
Consumables plant including water treatment chemicals 150,000
Replacement tools and equipment 15,000
Phone, mail and express service 12,000
Parts and Mat'l shipment to port, annual barging and misc. air 150,000
Water-No cost included in Maint. & station power 0
Spare parts & maintenance cost +Reserve of $500,000 Annually 2,650,000
Waste removal & disposal 7,500
Property lease 0
Insurance fee (Fire, Accident) 250,000
Total O&M 3,827,500
Taxes (No taxes in Bethel) 0
Miscellaneous contingency 5% 271,330
Total Annual O&M Cost including labor $5,697,895
O&M cost per kWh generated In Bethel $0.0073
In Crooked Creek $0.0089
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.11
D. DISTRICT HEATING SYSTEM
The plant will include provisions for supplying thermal energy to a district
heating system for the City of Bethel. The system will meet the diverse thermal energy
needs of Bethel’s residential, institutional, commercial and industrial customers. It will
include a heat exchanger for heating water circulating between the plant and the heat
receivers in the neighboring communities. The circulating water will be heated with
extracted steam in condensing heat exchangers. The district heating system will provide
energy for both space heat and hot water consumption. The power plant can supply
sufficient heat to the district heating system to displace the equivalent of 4.5 million
gallons of fuel oil per year, that would be otherwise be burned to by the residents of
Bethel to provide for space heating and hot water consumption.
The overall capital equipment cost includes the main trunk lines, the delivery
pumps and the primary heat exchangers. It does not include the cost of constructing
smaller distribution lines and the costs of connecting the numerous business and
household to the system. It is estimated that laying the main trunk line, installing the
central exchange station, and insulating pipe joints will take about 40,000 man-hours.
Estimated Cost of District Heating System as $11,600,000
described above.
E. FOUNDATION AND FUEL STORAGE COSTS9
1. Coal-Fired Plant
Budgetary construction cost estimates were prepared by LCMF for the construction
of the proposed site development, building fo undations, coal storage area, 3,000,000
gallon bulk fuel facility, intermediate fuel tanks, water tanks, access roads, pipelines, and
coal and fuel barge off-loading dock. These costs have been incorporated into the
overall power plant costs listed above. The estimates were developed based on
historical pricing for similar work in Bethel with a 6.5% overhead for profit, bonding and
insurance. A construction contingency of 15% has been factored into the estimates. A
freight rate of $0.20 per pound, Seattle to Bethel, was provided by Bettine, LLC. These
estimates do not include costs for the buildings, power generation equipment, conveyors,
stacker/reclaimer, or coal barge unloading system; their transportation to Bethel, nor their
mobilization to the site and setup. The estimates do not include the costs of land
purchase, leases or right-of-ways. The Budget Construction Cost Estimates are
summarized below.
9 See Appendix E for Foundation and Fuel Storage Feasibility Design Reports
prepared by LCMF
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.12
Power Plant & Buildings, Founded on Permafrost $21,000,000
Barge Mounted Power Plant Option $13,800,000
3,000,000 Gallon Bulk Fuel Facility $ 4,125,000
Lined Coal Storage w/ Maintaining Permafrost Integrity $19,200,000
Lined Coal Storage w/ Pre-thaw of Permafrost $15,800,000
Unlined Coal Storage w/ Allowing Natural Thaw of Permafrost $ 7,300,000
Cooling Lake Option $ 5,450,000
Cost estimates have also been prepared for the design, permitting and project
management for the proposed power plant facility, coal storage area, bulk fuel facility,
intermediate fuel tank, raw water tank, access roads, pipelines, and coal and fuel barge
off-loading dock. These estimates do not include costs for the power plant equipment,
buildings, conveyor, stacker/reclaimer and barge unloading systems, as well as, land
purchase, lease and right -of-way costs. The estimates were developed based on historical
pricing for similar work in Bethel. The design, permitting and construction management
cost estimates are summarized below. The cost is the same for either the power plant
founded on permafrost or barge mounted option.
Estimated Design Cost $900,000
Estimated Permitting Cost $100,000
Estimated Project Management Cost $350,000
The cooling lake option requires additional design, permitting and project
manageme nt. The following cost estimates were developed for the cooling lake option.
Estimated Design Cost $100,000
Estimated Permitting Cost $ 50,000
Estimated Project Management Cost $100,000
2. Combustion Turbine Plant
Budget Construction Cost Estimates were also prepared by LCMF for the
construction of the proposed bulk fuel facility, module foundations, intermediate fuel
tank, raw water tank, access roads, pipelines and fuel barge off-loading dock. These costs
have been incorporated into the overall power plant costs listed above. The estimates
were developed based on historical pricing for similar work in Bethel with a 6.5%
overhead for profit, bonding and insurance. A construction contingency of 15% has been
factored into the estimates. A freight rate of $0.20 per pound, Seattle to Bethel, was
provided by Bettine, LLC. These estimates do not include costs for the combustion
turbine modules or power generation equipment, their transportation to Bethel, nor their
mobilization to the site and setup. The estimates do not include the costs of land
purchase, leases or right of ways. The Budget Construction Cost Estimates are
summarized below.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.13
Estimated Construction Cost (Power Plant Facility) $ 8,330,000
Estimated Construction Cost (Bulk Fuel Facility) $25,000,000
Estimated Construction Cost (Cooling Lake Option) $ 3,050,000
Cost estimates have also been prepared for the design, permitting and construction
management for the site development, proposed bulk fuel facility, module foundations,
intermediate fuel tank, raw water tank, access roads, pipelines and fuel barge offloading
dock. These estimates do not include costs for the facility design, combustion turbine
modules, power generation equipment, land acquisit ion or leases. The estimates were
developed based on historical pricing for similar work in Bethel. The design, permitting
and project management cost estimates are summarized below.
Power Plant & Bulk Fuel Facilities
Estimated Design Cost $700,000
Estimated Permitting Cost $ 50,000
Estimated Construction Management Cost $350,000
Cooling Lake Option
Estimated Design Cost $100,000
Estimated Permitting Cost $ 25,000
Estimated Project Management Cost $100,000
F. TRANSMISSION LINE COSTS 10
1. Construction Costs
Transmission line costs for the three Donlin Creek transmission line alternatives
investigated are listed in Table VI-1.1. Construction costs cover all the materials, labor
and equipment required to build the transmission line facilities. Overhead and profit are
included. Engineering, construction management, and owner costs are also included as
separate line items. Right -of-way acquisitions costs are not included.
10 Transmission Line Cost Estimates provided by Dryden & LaRue, In c. See Appendix C for detail cost
breakdown.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.14
TABLE VI-1.1
BETHEL - DONLIN CREEK 138 KV TRANSMISSION LINE ALTERNATIVES
PRE-DESIGN CONSTRUCTION COST ESTIMATE
STEEL H-FRAMES,STEEL H-FRAMES, STEEL X & H-FRAMES,
DIRECTED BURIED+All PILE FOUNDATIONS All PILE FOUNDATIONS
ITEM PILE FOUNDATIONS
Clearing $3,435,000 $3,435,000 $3,435,000
Driven Piles $12,807,798 $31,841,302 $31,447,800
H-Frame Structures $35,129,920 $27,834,850 $15,703,750
3-Pole Structures $3,748,975 $2,558,950 $2,558,950
X-Frame Structures $0 $0 $13,588,000
Single-Pole Structures $2,830,600 $2,830,600 $2,830,600
Framing $5,860,310 $5,860,310 $5,904,310
OPGW $7,723,060 $7,723,060 $7,723,060
Conductor $25,833,775 $25,833,775 $25,833,775
Anchors $1,328,700 $1,328,700 $1,328,700
Miscellaneous $1,012,940 $1,012,940 $2,779,740
Subtotal $99,711,078 $110,259,487 $113,133,685
Mobilization, staging, work camps, etc.$4,985,554 $5,512,974 $5,656,684
Planning-level contingency:15%$15,704,495 $17,365,869 $17,818,555
Freight $2,163,800 $2,382,400 $2,254,000
SubTotal $122,564,927 $136,533,671 $138,862,925
Engineering/Design @ 2%$1,994,222 $2,205,190 $2,262,674
Environmental Studies/Permitting $3,000,000 $3,000,000 $3,000,000
Construction Mangement by Owner @2.5%$2,492,777 $2,756,487 $2,828,342
TOTAL $130,051,925 $144,495,347 $146,953,940
Cost/mile $680,900 $756,520 $769,392
Average Span Length 950 ft 950 ft 950 ft
Transmission line costs for the two, 385 mile, Nenana to Donlin Creek
transmission line alternatives investigated are listed in Table VI-1.2. Construction costs
cover all the materials, labor and equipment required to build the transmission line
facilities. Overhead and profit are included. Engineering, construction management, and
owner costs are also included as separate line items. Right -of-way acquisitions costs are
not included.
The reader will observe that a fifteen percent contingency is added to the cost of
the Donlin Creek transmission line while a twenty-five percent contingency is used for
the two Nenana to Donlin Creek transmission lines. The increased contingency for the
Nenana to Donlin Creek lines is justified due to the increased uncertainties associated
with construction of these two lines. (See D&L report in Appendix C.) These
uncertainties include serious concerns about the logistics of building either of these two
lines due to access, weather, environmental constraints, etc. The most likely scenario for
building these lines is via ice roads constructed from both Nenana and Donlin Creek over
an estimated four winters. Finding adequate water sources along the route for the ice
roads could be problematic. Setting up and operating work camps along the route will
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.15
create some challenges. (See D&L report in Appendix C.) The logistics of delivering
equipment and materials will also prove demanding.
TABLE VI-1.2
NENANA - DONLIN CREEK TRANSMISSION LINE Alternatives
PRE-DESIGN CONSTRUCTION COST ESTIMATE
+100 kV DC Line 230 kV AC Line
Single Steel Pole W/Direct Steel H-Frames W/Direct
ITEM Embedded+Pile Foundations Embedded+Pile Foundations
Clearing $7,244,160 $8,753,360
H-Frame Structures Direct Embedded $0 $31,492,638
H-Frame Structures w/piles $0 $79,766,104
Single-Pole Structures Direct Embedded $21,051,710 $0
Single-Pole Structures w/piles $54,919,862 $0
Framing $10,505,410 $14,456,984
OPGW $16,462,278 $16,154,410
Conductor $35,856,118 $48,450,792
Anchors $10,048,598 $12,745,080
Miscellaneous $3,998,992 $3,005,787
Ice Roads $30,464,000 $30,464,000
Subtotal $190,551,128 $245,289,155
Mobilization, staging, work camps, etc.$15,953,812 $18,165,877
Planning-level contingency:25.00%$53,580,226 $68,216,632
Freight $7,815,965 $9,411,494
SubTotal $267,901,131 $341,083,158
Engineering/Design @ 2%$3,811,023 $4,905,783
Environmental Studies/Permitting $6,000,000 $6,000,000
Construction Mangement by Owner @2.5%$4,763,778 $6,132,229
TOTAL $282,475,932 $358,121,170
Cost/mile $733,704 $930,185
Average Span Length 800 ft 950 ft
The above construction costs are representative of transmission lines built with a
50-100 year design life. It is necessary to design and build the transmission line to these
standards for three reasons. First, the actual life of the Donlin Creek mine is uncertain. It
is anticipated the mine will have a minimum life of 20 years, but the maximum life span
of the mine is unknown. It would not be surprising for the mine to remain operational for
a period of 30-40 years as additional deposits are discovered in the area. Secondly,
additional min ing development may occur north of the Donlin Creek. Therefore, it is
necessary to build a transmission line that will serve the long-term needs of the area.
Lastly, it is necessary to construct a transmission line that is exceptionally reliable to
min imize outages and future repair costs. Minimizing future repair cost is an important
design consideration as repairing remote transmission lines in Alaska has historically
proven to be an extremely expensive proposition.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.16
2. Transmission Line O&M Costs
Based on the design parameters used for the Donlin Creek transmission line O&M
costs of $500 per mile per year is assumed to be reasonable for the purposes of this study.
3. Transmission Line Costs for Other Alaska Projects
Transmissio n line cost for projects recently completed in central Alaska are listed
in Table VI-1.3 and provide a basis for comparison with the cost estimates provided for
the 138-kV Donlin Creek transmission line and the 230-AC and + 100-kV DC line
described above. The cost s listed in Table VI-1.3 are actual construction costs obtained
from bid documents. These costs do not include engineering/design, and environmental
study/permitting or construction management costs.
Although the Northern Intertie was built using steel X-towers, it is considered a
representative comparison for the construction costs associated with Donlin Creek
transmission line and the two proposed railbelt intertie alternatives. The soil and terrain
conditions for the Northern Intertie are similar to those that would be encountered along
route of the Bethel-to-Donlin Creek transmission line and the route of a transmission line
from Nenana to the mine. The conductor used on the Northern Intertie is 954 ACSR,
which is the conductor selected for use on the Donlin Creek mine transmission line and
the railbelt intertie alternatives. The average per mile cost for the 89 mile long, 230-kV
Northern Intertie is $710,000. This cost does not include clearing costs,
engineering/design, environmental study/permitting or construction management costs.
This compares to $681,000 per mile for the 138-kV Donlin Creek line, which does
include all of the above mentioned costs. Considering the remote location of the Donlin
Creek transmission line, coupled with the slightly reduced cost associated with steel H-
frame construction and lower operating voltage, a total per mile cost of $681,000 is not
unreasonable.
Similarly a per mile construction cost of $734,000 for a two conductor single pole
+ 100-kV DC line and a per mile cost of $930,000 for a 230-KV AC transmission line,
does not seem unreasonable given the remoteness of the region, the difficult terrain and
complete lack of any road or river transportation systems along the majority of the
transmission line route.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.17
TABLE VI-1.3
COST COMPARISON OF TRANSMISSION LINES
IN CENTRAL ALASKA
Project Name Northern Intertie, Flats Northern Intertie, Foothills Jarvis Creek to GMD Pogo Mine
Nearest City/Town Fairbanks, Alaska Healy, Alaska Delta, Alaska Delta, Alaska
Voltage 230 kV 230 kV 138 kV 138 kV
Line Length 64.1 miles 24.9 miles 6.0 miles 47.0 miles
Construction Period Dec, 01 - March, 03 Aug. 02 - Sept, 03 May, 03 - Sept, 03 Jan, 04 - Oct, 04
Design Life 100 years 100 years 50 years 15 years
Typical Terrain flat, boggy wetlands rolling hills to mountainous flat to rolling hills rolling hills, some wetlands
Typical Soils silts, permafrost dense sands, gravels sands, gravels sands, gravels
Typical Access ice roads mostly helicopter off existing roads spur roads off mine road
Typical Foundation driven pipe piles drilled and grouted pipe piles direct embed direct embed
Typical Structure tubular steel X-tower tubular steel X-tower wood H-frame wood H-frame
Typical Span 970 feet 1060 feet 600 feet 800 feet
Conductor 954 kcmil ACSR, Cardinal 954 kcmil ACSR, Cardinal 795 kcmil ACSR, Drake 336 kcmil ACSR, Oriole
OHSW, fiber optics,
underbuild, etc.
towers designed for double
OPGW, none installed
towers designed for double
OPGW, none installed
one cable of fiber optic
underbuild
none
Clearing Cost $2,000 /acre $1,500 /acre $1,200 /acre
Construction Cost
(excludes clearing)
$40,000,000 $23,250,000 $1,316,000 $10,000,000
Avg. Cost/Mile $624,025 $933,735 $219,333 $212,766
% Foundation Cost 36%41%part of structure cost part of structure cost
% Structure Cost 37%36%24%41%
% Framing Cost 5%3%31%18%
% Wire Cost 17%19%44%40%
% Miscellaneous Cost 5%1%1%1%
Special Considerations all winter construction very difficult fdn. construction
due to access and terrain
4 mi. very high wind, 5 mi.
winter construction
G. SUBSTATION COSTS
Construction costs cover all the materials, labor and equipment required to build
the substation facilities. Overhead and profit are included. Engineering, construction
management, and owner costs are not listed as a separate line item but are included as
part of the overall transmission line and power plant costs previously listed.
1. 138-kV Bethel to Donlin Creek Mine Transmission Line Substation
Costs11
Table VI-1.4 lists the construction costs for the substations and associated 9.5 miles
of distribution feeders required to connect the villages to the step-down substations.
11 Substation Costs Estimates provided by Dryden & LaRue, Inc. See Appendix C for detail cost
breakdown.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VI
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PROJECT COST ESTIMATES Section VI-1.18
TABLE VI-1.4 Bethel-Donlin Creek Mine Substation Costs
DESCRIPTION COST
Bethel Power Plant Substation $ 4,100,000
Bethel Diesel Substation $ 500,000
7 Village Substations 7@$585,000 = $ 4,100,000
10 MVA Reactor at Aniak
Substation12
$ 350,000
9.5 miles of Interface Feeders $ 2,800,000
Donlin Creek Mine Substation To be Provided by Placer Dome $ 0
2. Nenana to Donlin Creek Mine Transmission Line Substation Costs
The cost of the substations associated with these two power line alternatives are
listed below in Table VI-1.5.
TABLE VI-1.5 Nenana-Donlin Creek Mine Substation Costs
Description COST
+ 100-KV AC-DC Conversion Stations
2 Required – Nenana & Donlin Creek
$100,000,00013
230 KV Substation at Nenana $4,000,000
Donlin Creek Mine Substation To be Provided by Placer Dome $ 0
12 Estimate prepared by Bettine, LLC
13 Cost estimate obtained from GVEA letter to Placer Dome, Inc.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VII
Power Supply Feasibility Study Final Report 06/11/04
PROJECT MANAGEMENT & SCHEDULING VII-1.1
SECTION VII PROJECT MANAGMENT &
SCHEDULING
1. PROJECT OPTIONS AND ASSUMPTIONS
A. INTRODUCTION
The following project schedules assume that an EIS must be prepared to comply
with the NEPA process. Five project schedule sheets are presented and are attached as
Figures VII.1-1 through 5. The abbreviated schedule shows the estimated completion
time for each of the three power supply alternatives and 138-kV transmission line,
including the time allocated for the completion of the EIS. A separate schedule for the
138-kV transmission line and each of the three power supply alternatives is provided.
The abbreviated project schedule shown in Figure VII-1.1 assumes the environmental and
permitting work will begin on the transmission line in June/July 2004 and on the
preferred generation alternative on or about October 2004. The schedules, as prepared,
assume that it will take thirty months to prepare and obtain approval of an EIS. The
remaining four schedules display elapsed time from the start of preliminary engineering.
B. PROJECT MANAGEMENT OPTIONS
The project can be organized and managed in three basic ways. Nuvista can act
as the project manager using in-house and/or contract employees to manage the project.
Nuvista could contract with a firm to provide contract -management. It could contract
with a firm for a turnkey design/build of the project after it has obtained the required
permits. The three alternatives are discussed below. The project schedule is, however,
based on Nuvista acting as the project manager.
1. Nuvista Acts as Project Manager
Under this option Nuvista would maintain management control of the project.
This approach would probably result in the lowest project management related costs.
Since Nuvista presently does not have any employees skilled in project management, it
would need to hire highly qualified in-house staff and/or contract employees to
administer project management responsibilities. As project manager, Nuvista would
retain the greatest degree of control over the project. Nuvista would select and contract
with various firms to form a project team to perform the required work. To avoid
adversarial confrontations, as is often present in the owner/contractor relationship,
Nuvista should consider entering into a partnering arrangement with the selected team
members.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VII
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PROJECT MANAGEMENT & SCHEDULING VII-1.2
2. Nuvista Contracts with Project Management Firm
Under this option Nuvista would contract with a single outside project
management (PM) firm. The PM firm would be responsible for all aspects of the project
to include progress, control, environmental permitting, design, construction and
energization of the project. The PM firm would perform some duties and contract out for
others. Nuvista would be relieved of the day-to-day management responsibilities
associated with the project under this option, but would still retain some input and limited
control. The use of a PM firm will, however, add another layer of administration and
cost to the project.
3. Nuvista acts as Project Manager + Turnkey (Design/Build)
Under this option Nuvista would serve as project manager throughout the
permitting and initial design stage of the project and then contract with a single entity for
final design, construction and energization of the project. Once a design/build contract is
selected Nuvista would have very limited input on decisions. This type of contract is also
more difficult and costly to suspend or modify in the event unforeseen circumstances
require an alteration to the design or the scope of the project work.
C. SCHEDULE ASSUMPTIONS
The following assumptions underline the development schedules found in Figures
VII-1.1 through 4.
1. Project Financing
This Feasibility Study in its final form is assumed to be completed on or about
June 1, 2004. Assuming feasibility is demonstrated, a plan of finance would need to be
prepared. However, before proceeding with the development of a finance plan, Nuvista
will need to procure a power purchase agreement with Placer Dome . While several
options for financing have been addressed in Section VIII, it is not clear at this stage how
or where financing will be obtained or how long that it will take to obtain the financing.
2. Environmental Impact Statement/Permitting
Discussions with key environmental agencies and a review of existing regulations
indicate an EIS, which incorporates the cumulative impact of both the transmission line
and preferred power supply alternative, must be prepared to comply with the NEPA
process. The attached schedule assumes that $1.5 million in funds are presently available
to move forward with the environmental permitting of the 138-kV Donlin Creek
transmission line. It further assumes that additional funding will become available on or
about mid-2004 that will allow Nuvista to continue with permit ting the transmission line
and to begin the environmental permitting work for the preferred power plant alternative.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VII
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PROJECT MANAGEMENT & SCHEDULING VII-1.3
It is estimated that securing the necessary permits and processing of the EIS will require
thirty months and be completed by year end 2006.
3. Right-of-way Easement and Power Plant Site Acquisition
It is assumed that acquisition of right-of-ways and property for the plant site will
be accomplished by a skilled land agent or agents. Once the final route corridor and plant
location has been identified, land owner contacts would be made and temporary access
agreements obtained. It is assumed that acquisition of property for the plant site and
right -of-way could be completed in eighteen months. Because the corridor will cross
several native allo tments, BIA will be involved.
4. Preliminary Design
The preliminary design phase includes aerial surveys, geotechnical investigations,
final power plant site selection, final route selection, permitting support, value
engineering, identification and select ion of major system components, additional system
studies, meteorological studies, and plan/profile preparation. Preliminary design is
considered an integral part of the EIS process. It is assumed that the necessary Project
team members, except for the construction contractor(s), have already been retained, at
this stage, under a partnering arrangement, to provide input and supply the essential skills
needed to perform preliminary design.
5. Final Design
This includes final power plant, transmission line and substation design, drawing,
and plant preparation, issuance of procurement contracts. It is assumed that prior to
commencing final design, a construction contractor or contractors will be retained as part
of the Project team under a partnering arrangement. It is assumed that at least four prime
construction contractors will be required to complete the project in a timely manner. It is
assumed that at least two prime contractors will be retained to construct the power plant
and two contractors will be employed to construct the transmission line. One
transmission line contractor will construct the southern portion of the line and the second
contractor the northern portion. It is essential that the construction contractors have input
at this stage of the project design. Coordinating with the contractors at this stage will
typically minimize risks and reduce construction costs.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VII
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PROJECT MANAGEMENT & SCHEDULING VII-1.4
6. Major Equipment Lead Times
Estimated lead times for major equipment items are as follows. Lead times
include Shop Drawing review.
Item Lead Time Weeks
Power Plant Related
Boilers 52
Steam Turbines 52
Combustion Turbines 36
HRSG 36
Barges 36
Cooling Towers 36
Switchgear 36
Transmission Line Related
Power Transformers 48
Switchgear 36
Conductor 24
Steel Structures 24
Pipe Piling 12
Substation Structures 30
Multiple power plant and transmission line contracts are planned, to lower risks of
late completion, and because it is unlikely that any local Alaskan contractor alone could
support the bonding requirements of the full project. Installing the pipe pile foundations
on the section of power line located between Bethel and Upper Kalskag will driving the
transmission line schedule.
D. PROJECT SCHEDULE SUMMARY
This schedule assumes that $1.5 million in funds are presently available to move
forward with the environmental permitting work for the 138-kV Donlin Creek
transmission line. It further assumes that additional funding will become available on or
about mid-2004 that will allow Nuvista to continue with permitting the transmission line
and to begin the environmental permitting work for the preferred power plant alternative.
The schedule assumes that the EIS process will be completed and required permits
issued by year end, 2006. As shown on the attached schedules, and specifically on Figure
VII-1.1, the transmission line will require approximately three additional years to design
and construct following the conclusion of the EIS process. The la nd-based coal-fire plant
alternative will require an additional 3 years and 3 months, the barge-mounted
alternative, 33 months and modular combustion turbine plant 2 years. Scheduled
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VII
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PROJECT MANAGEMENT & SCHEDULING VII-1.5
completion date for the land-based coal plant is July 2010, for the barge-mounted coal-
plant alternative, January 2010, and for the modular combustion turbine plant April,
2009.
The above schedules assume the project does not encounter any unexpected
delays or impediments. Few projects of this magnitude are, however, permitted, designed
and built without encountering some unexpected delays. Allowing for a six month delay
in the project schedule would be prudent.
FIGURE VII-1.1Donlin Creek Power Supply AlternativesAbbreviated Project Schedule2004 2005 2006 2007 2008 2009 2010Task Duration Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3Qtr 4 Qtr 1 Qtr 2EIS/Permitting Transmission Line+Substations30 mth Power Plant30 mthPreliminary Design Transmission Line21 mth Substations13 mth Power Plant19 mthFinal Design Transmission Line12 mth Substations9 mth Power Plant Coal-Fired Land-Based or27 mth Barge Mounted or27 mth Combustion Turbine22 mthConstruction/Procurement/Testing Transmission Line39 mth Substations Power Plant/Bethel/Aniak12 mth Village Substations9 mth Power Plant Coal-Fired Land-Based or39 mth Barge Mounted or33 mth Combustion Turbine24 mthBettine, LLC
FIGURE VII-1.2Donlin Creek Transmission LineProject ScheduleYear 1 Year 2 Year 3 Year 4 Year 5 Year 5Task Duration Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2Preliminary Design Stage Final Route Selection 6 mth T-Line Design 24 mth Geotechnical Investigation 6 mth Meteorological Study 6 mth Substation Design 12 mthFinal Design Stage Final Design Tranmission Line 12 mth Plan & Profile Drawings 9 mth Aerial Survey & Control Panels 6 mth Final Design Major Substations 8 mth Final Design Village Substations 6 mth Structure Staking/ C.L. Survey 8 mth Tranmission Line Equip Specs. 3 mth Substation Equip. Specs 3 mth Final System Studies 3 mthEquipment Purchase Substation Major Equip. 3 mth Pipe Pile for Foundations 6 mth Tranmission Line Major Equip. 6 mth Substation Minor Equipl 3 mth Tranmission Line Minor Equip. 3 mthT-Line Construction Contractor 1 Selection 3 mth Mobilzation 3 mth Pile Pile Delivery 6 mth Foundations Southern Zone 7 mth Structure Delivery 3 mth Structure Installation 4 mth Conductor Stringing 6 mth Contractor 2 Selection 3 mth Mobilzation 3 mth Foundations Northern Zone 15 mth Structure Delivery 6 mth Structure Installation 6 mth Conductor Stringing 6 mth Testing 1 mthSubstation Construction Contractor Selection 3 mth Power Plant, Bethel & Aniak Substation Site Work 6 mth Equipment Erection 3 mth Testing 1 mth Village Substations Site Work 3 mth Equipment Erection 3 mth Testing 1 mthBettine, LLC
IDTask NameDurationStartFinish1Project Go Ahead0 monsSat Jan 1Sat Jan 12Engineering & Design14 monsSat Jan 1Thu Mar 93Engineering for permitting (By others)0 monsSat Jan 1Sat Jan 14Process Engineering PFD, P&ID's4 monsSat Jan 1Wed May 45System, Equipment Specifications12 monsSat Jan 1Fri Jan 66Detailed Design14 monsSat Jan 1Thu Mar 978Procurement: Issue RFQ's, Select Suppliers6.91 monsTue Feb 1Fri Sep 29Fuel Handling & Storage Equipment4 monsTue Feb 1Sat Jun 410Steam Plant Equipment (Boilers)4 monsTue Feb 1Sat Jun 411Steam Turbine Generating System4 monsTue Feb 1Sat Jun 412Instrumentation & Controls5 monsTue Mar 1Tue Aug 213Ash Handling & Disposal System2 monsTue Feb 1Sun Apr 314Environmental System & Controls4 monsFri Apr 1Tue Aug 215Stand-by Generation & Steam System3 monsTue Mar 1Wed Jun 116Plant Utilities and Services6 monsTue Mar 1Fri Sep 217Civil & Structural Work & Equipment6 monsTue Feb 1Fri Aug 518Rolling Stock3 monsTue Feb 1Wed May 419Construction Camp & Utilities incl water supply4 monsTue Feb 1Sat Jun 420District Heating System5 monsTue Mar 1Tue Aug 22122Fabrication Including Shipping to Site16.98 monsTue Mar 1Mon Aug 723Fuel Handling & Storage Equipment9 monsSun May 1Thu Feb 224Steam Plant Equipment (Boilers)15 monsSun May 1Mon Aug 725Steam Turbine Generating System15 monsSun May 1Mon Aug 726Instrumentation & Controls9 monsWed Jun 1Sun Mar 527Ash Handling & Disposal System9 monsTue Mar 1Sat Dec 328Environmental System & Controls8 monsSun May 1Tue Jan 329Stand-by Generation & Steam System9 monsFri Apr 1Tue Jan 330Plant Utilities and Services9 monsSun May 1Thu Feb 231Civil & Structural Work & Equipment9 monsTue Mar 1Sat Dec 332Rolling Stock4 monsSun May 1Thu Sep 133Construction Camp & Utilities incl water supply4 monsTue Mar 1Sat Jul 234District Heating System6 monsFri Apr 1Mon Oct 33536Construction & Installation18.86 monsSun May 1Mon Dec 437Fuel Handling & Storage Equipment6 monsMon May 1Thu Nov 238Steam Plant Equipment (Boilers)3.5 monsMon May 1Wed Aug 1639Steam Turbine Generating System3.5 monsMon May 1Wed Aug 1640Instrumentation & Controls2.5 monsFri Sep 1Fri Nov 1741Ash Handling & Disposal System1.5 monsTue Aug 1Sat Sep 1642Environmental System & Controls3 monsTue Aug 1Wed Nov 143Stand-by Generation & Steam System1 monThu Jun 1Sat Jul 144Plant Utilities and Services4 monsSat Jul 1Wed Nov 145Civil & Structural Work & Equipment6 monsMon May 1Thu Nov 246Rolling Stock1 monFri Jul 1Sun Jul 3147Construction Camp & Utilities incl water supply5 monsSun May 1Sun Oct 248District Heating System12 monsSun May 1Mon Dec 44950Startup & Commissioning2 monsWed Nov 1Mon Jan 151Fuel Line Flushing2 monsWed Nov 1Mon Jan 152Lube Oil Flushing & Dehydration2 monsWed Nov 1Mon Jan 153Steam Blows2 monsWed Nov 1Mon Jan 154Trial Runs of Turbines2 monsWed Nov 1Mon Jan 155Trial Run of Plant2 monsWed Nov 1Mon Jan 156Start of Power Production0 monsMon Jan 1Mon Jan 11/11/11/1Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Year 1Year 2Year 3TaskSplitProgressMilestoneSummaryProject SummaryExternal TasksExternal MilestoneDeadlineFigure VII - 1.3Bethel Barge Based Coal Plant Schedule (Time For Environmental Permitting Not Included)Page 1Project: Constr sched 29 11 18 BargeDate: Tue Jan 27
IDTask NameDurationStartFinish1Project Go Ahead0 monsSat Jan 1Sat Jan 12Engineering & Design23 monsSat Jan 1Tue Dec 123Engineering for permitting (By others)0 monsSat Jan 1Sat Jan 14Process Engineering PFD, P&ID's4 monsSat Jan 1Wed May 45System, Equipment Specifications12 monsSat Jan 1Fri Jan 66Detailed Design23 monsSat Jan 1Tue Dec 1278Procurement: Issue RFQ's, Select Suppliers6.91 monsTue Feb 1Fri Sep 29Fuel Handling & Storage Equipment4 monsTue Feb 1Sat Jun 410Steam Plant Equipment (Boilers)4 monsTue Feb 1Sat Jun 411Steam Turbine Generating System4 monsTue Feb 1Sat Jun 412Instrumentation & Controls5 monsTue Mar 1Tue Aug 213Ash Handling & Disposal System2 monsTue Feb 1Sun Apr 314Environmental System & Controls4 monsFri Apr 1Tue Aug 215Stand-by Generation & Steam System3 monsTue Mar 1Wed Jun 116Plant Utilities and Services6 monsTue Mar 1Fri Sep 217Civil & Structural Work & Equipment6 monsTue Feb 1Fri Aug 518Rolling Stock3 monsTue Feb 1Wed May 419Construction Camp & Utilities incl water supply4 monsTue Feb 1Sat Jun 420District Heating System5 monsTue Mar 1Tue Aug 22122Fabrication Including Shipping to Site18.91 monsTue Mar 1Thu Oct 523Fuel Handling & Storage Equipment9 monsSun May 1Thu Feb 224Steam Plant Equipment (Boilers)15 monsSun May 1Mon Aug 725Steam Turbine Generating System15 monsSun May 1Mon Aug 726Instrumentation & Controls9 monsWed Jun 1Sun Mar 527Ash Handling & Disposal System9 monsTue Mar 1Sat Dec 328Environmental System & Controls8 monsSun May 1Tue Jan 329Stand-by Generation & Steam System9 monsFri Apr 1Tue Jan 330Plant Utilities and Services9 monsSun May 1Thu Feb 231Civil & Structural Work & Equipment9 monsTue Mar 1Sat Dec 332Rolling Stock4 monsSun May 1Thu Sep 133Construction Camp & Utilities incl water supply4 monsTue Mar 1Sat Jul 234District Heating System9 monsWed Jun 1Thu Oct 53536Construction & Installation30.67 monsSun May 1Tue Dec 437Fuel Handling & Storage Equipment6 monsMon May 1Thu Nov 238Steam Plant Equipment (Boilers)7 monsMon May 1Sat Dec 239Steam Turbine Generating System7 monsMon May 1Sat Dec 240Instrumentation & Controls5 monsFri Sep 1Fri Feb 241Ash Handling & Disposal System3 monsTue Aug 1Wed Nov 142Environmental System & Controls6 monsFri Sep 1Mon Mar 543Stand-by Generation & Steam System2 monsThu Jun 1Tue Aug 144Plant Utilities and Services12 monsSat Jul 1Fri Jul 645Civil & Structural Work & Equipment6 monsMon May 1Thu Nov 246Rolling Stock1 monFri Jul 1Sun Jul 3147Construction Camp & Utilities incl water supply5 monsSun May 1Sun Oct 248District Heating System12 monsMon May 1Tue Dec 44950Startup & Commissioning2 monsThu Nov 1Tue Jan 151Fuel Line Flushing2 monsThu Nov 1Tue Jan 152Lube Oil Flushing & Dehydration2 monsThu Nov 1Tue Jan 153Steam Blows2 monsThu Nov 1Tue Jan 154Trial Runs of Turbines2 monsThu Nov 1Tue Jan 155Trial Run of Plant2 monsThu Nov 1Tue Jan 156Start of Power Production0 monsTue Jan 1Tue Jan 11/11/11/1Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Year 1Year 2Year 3Year 4TaskSplitProgressMilestoneSummaryProject SummaryExternal TasksExternal MilestoneDeadlineFigure VII - 1.4Bethel Land Based Coal Plant Schedule (Time for Environmental Permitting Not Included)Page 1Project: Constr sched 29 11 18 landDate: Tue Jan 27
IDTask NameDurationStartFinish1Project Go Ahead0 monsSat Jan 1Sat Jan 12Engineering & Design14 monsSat Jan 1Thu Mar 93Engineering for permitting (By others)0 monsSat Jan 1Sat Jan 14Process Engineering PFD, P&ID's4 monsSat Jan 1Wed May 45System, Equipment Specifications12 monsSat Jan 1Fri Jan 66Detailed Design14 monsSat Jan 1Thu Mar 978Procurement: Issue RFQ's, Select Suppliers6.91 monsTue Feb 1Fri Sep 29Diesel Tank Farm3 monsTue Feb 1Wed May 410Combustion Turbines4 monsTue Feb 1Sat Jun 411Steam Turbine Generating System w/HRSG4 monsTue Feb 1Sat Jun 412Instrumentation & Controls5 monsTue Mar 1Tue Aug 213Environmental System & Controls4 monsFri Apr 1Tue Aug 214Stand-by Generation & Steam System3 monsTue Mar 1Wed Jun 115Plant Utilities and Services6 monsTue Mar 1Fri Sep 216Civil & Structural Work & Equipment6 monsTue Feb 1Fri Aug 517Rolling Stock3 monsTue Feb 1Wed May 418Construction Camp & Utilities incl water supply4 monsTue Feb 1Sat Jun 419District Heating System5 monsTue Mar 1Tue Aug 22021Fabrication Including Shipping to Site16.98 monsTue Mar 1Mon Aug 722Diesel Tank Farm7 monsTue Mar 1Mon Oct 323Combustion Turbines15 monsSun May 1Mon Aug 724Steam Turbine Generating System w/HRSG15 monsSun May 1Mon Aug 725Instrumentation & Controls9 monsWed Jun 1Sun Mar 526Environmental System & Controls8 monsSun May 1Tue Jan 327Stand-by Generation & Steam System9 monsFri Apr 1Tue Jan 328Plant Utilities and Services9 monsSun May 1Thu Feb 229Civil & Structural Work & Equipment9 monsTue Mar 1Sat Dec 330Rolling Stock2 monsSun May 1Fri Jul 131Construction Camp & Utilities incl water supply4 monsTue Mar 1Sat Jul 232District Heating System5 monsFri Apr 1Fri Sep 23334Construction & Installation18.86 monsSun May 1Mon Dec 435Diesel Tank Farm6 monsMon May 1Thu Nov 236Combustion Turbines6 monsMon May 1Thu Nov 237Steam Turbine Generating System w/HRSG5 monsMon May 1Mon Oct 238Instrumentation & Controls2.5 monsFri Sep 1Fri Nov 1739Environmental System & Controls3 monsFri Sep 1Sat Dec 240Stand-by Generation & Steam System2 monsThu Jun 1Tue Aug 141Plant Utilities and Services3 monsSat Jul 1Sun Oct 142Civil & Structural Work & Equipment5 monsMon May 1Mon Oct 243Rolling Stock1 monFri Jul 1Sun Jul 3144Construction Camp & Utilities incl water supply5 monsSun May 1Sun Oct 245District Heating System12 monsSun May 1Mon Dec 44647Startup & Commissioning2 monsWed Nov 1Mon Jan 148Fuel Line Flushing2 monsWed Nov 1Mon Jan 149Lube Oil Flushing & Dehydration2 monsWed Nov 1Mon Jan 150Steam Blows2 monsWed Nov 1Mon Jan 151Trial Runs of Turbines2 monsWed Nov 1Mon Jan 152Trial Run of Plant2 monsWed Nov 1Mon Jan 153Start of Power Production0 monsMon Jan 1Mon Jan 11/11/11/1Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Year 1Year 2Year 3TaskSplitProgressMilestoneSummaryProject SummaryExternal TasksExternal MilestoneDeadlineFigure VII - 1.5Bethel CT Modular Plant Schedule (Time For Environmental Permitting Not Included)Page 1Project: Constr sched 29 11 19 ModulaDate: Tue Jan 27
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VIII
Power Supply Feasibility Study Final Report 06/11/04
PROJECT FINANCING Section VIII-1.1
SECTION VIII PROJECT FINANCING
1. FINANCING ALTERNATIVES
A. INTRODUCTION
This section identifies and briefly discusses the most likely financing sources
potentially available to fund the design and construction of a power plant at Bethel and
the 138-kV Donlin Creek transmission line.
B. CONGRESSIONAL APPROPRIATIONS
Alaska’s Senator Lisa Murkowski has introduced the ‘‘Calista Energy and
Economic Revitalization Act’’ to appropriate $100,000,000 in grants and $50,000,000 for
loan guarantees that are to be used for the purpose of constructing power generation and
transmission facilities within the Calista region. The bill has been read twice and referred
to the Committee on Energy and Natural Resources for further action.
C. RURAL UTILITY SERVICE
Providing reliable, affordable electricity is essential to the economic well-being
and quality of life for all of the nation’s rural residents. The electric program of USDA’s
Rural Utilities Service (RUS) provides leadership and capital to upgrade, expand,
maintain, and replace America’s vast rural electric infrastructure. Under the authority of
the Rural Electrification Act of 1936, RUS makes direct loans and loan guarantees to
electric utilities to serve customers in rural areas. The federal government, through RUS,
is the majority note holder for nearly 750 electric systems.
Since the start of the program, USDA has approved approximately $57 billion in
debt financing to support electric infrastructure in rural areas. Of these rural systems,
about 96 percent are nonprofit cooperatives, owned and operated by the consumers they
serve. The remaining 4 percent include municipal systems, Native American tribal
utilities, and other entities. These electric systems provide service to more than 90
percent of the nation’s counties identified by the Economic Research Service (ERS) as
having persistent poverty, out -migration, and/or other economic hardship.
Most RUS-financed systems have a two -tiered organizational structure. Retail
consumers are members of the distribution cooperative that provides electricity directly
to their homes and businesses. Most distribution cooperatives, in turn, are members of
power supply cooperatives, also called "generation and transmission" or "G&T"
cooperatives, which generat e and/or procure electricity and transmit it to the distribution
member systems.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VIII
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PROJECT FINANCING Section VIII-1.2
The Electric Program makes loans and loan guarantees to finance the construction
of electric distribution, transmission and generation facilities, including system
improvements and replacement required to furnish and improve electric service in rural
areas, and for demand side management, energy conservation programs, and on-grid and
off-grid renewable energy systems.
RUS makes loans to corporations, states, territories and subdivisions and agencies
such as municipalities, people’s utility districts, and cooperative, nonprofit, limited-
dividend, or mutual associations that provide retail electric service needs to rural areas or
supply the power needs of distribution borrowers in rural areas. RUS also provides
financial assistance to rural communities with extremely high energy costs to acquire,
construct, extend, upgrade, and otherwise improve energy generation, transmission, or
distribution facilities. RUS services approximately 686 active electric borrowers in 47
states.
1. Rural Electrification Loans
Specific language on loan eligibility and terms can be found in 7 CFR Part 1714.
Loan policies and application procedures can be found in 7 CFR Part 1710. Information
regarding the various loan programs is summarized below.
a. Hardship Loans
Hardship loans are used to finance electric distribution and sub-transmission
facilities. These direct loans are made to applicants that meet rate disparity thresholds and
whose consumers fall below average per capita and household income thresholds. They
may also be made if the RUS administrator determines that the borrower has suffered a
severe, unavoidable hardship, such as a natural disaster.
On November 1, 1993, the Rural Electrification Loan Restructuring Act,
Pub. L. 103-129, 107 Stat. 1356, (RELRA) amended the Rural Electrification Act of
1936, 7 U.S.C. 901 et seq., (RE Act) to establish a new interest rate structure for insured
electric loans. Insured electric loans approved on or after this date, are either municipal
rate loans or hardship rate loans. Borrowers meeting the criteria set forth in §1714.8 are
eligible for 5 percent hardship rate loans.
b. Municipal Rate Loans
Like hardship loans, municipal rate loans are used to finance electric distribution
and sub-transmission facilities. The interest rate is based on interest rates available in the
municipal bond market for similar maturities. In most cases borrowers are required to
seek supplemental financing for 30 percent of their capital requirements under this
program. Borrowers may choose from several maturities that will determine the interest
rate, which changes quarterly.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VIII
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PROJECT FINANCING Section VIII-1.3
For the fourth quarter of calendar year 2003, interest rates for a 20 year lo an were
5 percent. Interest rates are established in accordance with 7 CFR 1714.5.
c. Treasury Rate Loans
Like hardship and municipal rate loans, Treasury rate loans are used to finance
electric distribution and sub-transmission facilities. The standard interest rate on direct
Treasury rate loans will be established daily by the United States Treasury. The borrower
will select interest rate terms for each advance of funds. The minimum interest rate term
shall be one year. Interest rate terms will be limited to terms published by the Treasury
(i.e. 1, 2, 3, 5, 7, 10, 20, and 30). Interest rate terms to final maturity date, if other than
published by Treasury, will be determined by RUS. Interest rates for terms greater than
30 years will be at the 30-year rate. There will be no interest rate cap on Treasury rate
loans. Unlike the municipal rate loan program, supplemental financing will not be
required in connection with Treasury rate loans.
These rates change daily. Treasury semi-annual interest rates for a 20 year loan
are presently in the range of 5.3 percent, while FFB quarterly rates, for a 20 year loan, are
in the 5.1 percent. The interest rates applied to the loan are the rates in effect at the time
the loan funds are advanced.
d. Guaranteed Loans
RUS will provide guaranteed loans through the Federal Financing Bank (FFB),
Rural Utilities Cooperative Finance Corporation (CFC), and the National Bank for
Cooperatives (CoBank). Guaranteed loans are generally used to finance generation and
transmission facilities. The FFB is an instrument of the Treasury Department, providing
funding in the form of loans for various government lending programs, including the
RUS guaranteed loan program. FFB loans are guaranteed by RUS and are available to all
electric borrowers. The interest rate is the prevailing cost of money to the U.S. Treasury,
plus one-eighth of 1 percent. Under this program, the loan comes from the bank and is
guaranteed by RUS.
These rates change daily. Treasury semi-annual interest rates for a 20 year loan
are presently in the range of 5.3 percent, while FFB quarterly rates, for a 20 year loan, are
in the 5.1 percent. The interest rates applied to the loan are the rates in effect at the time
the loan funds are advanced.
2. Direct Learning and Telemedicine Program
To be eligible to receive financing under the DLT Program, the applicant must be
organized in one of the following corporate structures:
§ Be delivering or proposing to deliver distance learning or telemedicine
services. In this case by using the fiber-optics contained in the overhead
OPGW;
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VIII
Power Supply Feasibility Study Final Report 06/11/04
PROJECT FINANCING Section VIII-1.4
§ Be legally organized as an incorporated organization or partnership; an
Indian tribe or tribal organization, as defined in 25 U.S.C. 450b (b) and
(c); a state or local unit of government, a consortium, as defined in §
1703.102; or other legal entity, including a private corporation organized
on a for profit or not-for profit basis; and
§ Be operating a rural community facility or be delivering distance learning
or telemedicine services to entities that operate a rural community facility
or to residents of rural areas at rates calculated to ensure that the benefit of
the financial assistance is passed through to such entities or to residents of
rural areas.
§ Generally, the maximum amount for a loan that will be considered for
funding during FY 2003 is $10,000,000. However, RUS may fund a
project greater than $10,000,000 subject to the project's feasibility and the
availability of loan funds.
§ Note: RUS electric or telecommunications borrowers are not eligible for
grants.
Combination loan-grant financial assistance can be used for the following
purposes:
1. Purchasing medical and educational equipment (in addition to
telecommunications equipment that directly encodes or decodes data) shown to
be necessary to implement the project;
2. Providing links between teachers and students or medical professionals
located at the same facility as long as the facility is part of a distance learning
and telemedicine network (formerly, single sites could not be funded in this
manner);
3. Providing for site development and alteration of buildings necessary for
the project but not reflecting a major portion of the financial assistance;
5. Purchasing of land and/or buildings, or building construction necessary
but not reflecting a major portion of the financial assistance (the applicant must
demonstrate that the financial assistance for this purpose is not available
elsewhere at an economic cost); and,
6. Acquiring telecommunications transmission facilities where such facilities
cannot be obtained at a cost that does not impact the economic viability of the
project;
7. Fund Operations costs incurred during the first two years of operation of
the project provided they are shown to be necessary, financing is not available
elsewhere, and such costs do not exceed 20 percent of the loan financial
assistance provided. Salaries and administrative expenses are not eligible for
funding; and,
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VIII
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PROJECT FINANCING Section VIII-1.5
8. Costs needed to provide distance learning broadcasting to rural areas
subject to the requirements in the regulation.
The interest rate for the loan (portion) is based on the cost of money to the United
States Treasury at the time of draw down of funds. The maximum amortization period for
the loan (portion) is up to 10 years or t he economic life of the facilities being financed,
whichever is less.
D. AIDEA
The Loan Participation Program provides long-term financing to Alaska
businesses for new or existing projects, or for the refinancing of existing loans. The Loan
Participation Program has been highly successful since its inception in the early 1980’s.
This program has helped diversify the Alaskan economy by providing financing for a
large variety of commercial facilities ranging from office buildings, warehouses and retail
establishments to hotels, fishing vessels and manufacturing facilities. AIDEA is not a
direct lender, but through the Loan Participation Program, AIDEA purchases a portion of
a loan that is sponsored and originated by an eligible financial institution. In most cases
the interest rate on the AIDEA portion of the loan is slightly lower than the rate on the
bank’s portion. The term of the AIDEA portion of the loan can also exceed the term of
the bank portion. This can result in lower scheduled payments for the borrower.
AIDEA provides fully amortizing, long term financing, up to 25 years for real
property, based on a maximum loan-to-value of 75%.)
· AIDEA offers either a fixed or variable interest rate.
· The term of the AIDEA portion of the loan can exceed the bank’s portion, thereby
lowering the scheduled payments.
· AIDEA provides a secondary long-term market for eligible financial institutions.
· The originating financial institution retains a portion of the loan and also services
the entire loan (i.e., payments are made to the bank, not to AIDEA).
· The project must be in Alaska.
· Loan amounts in excess of $10,000,000 must be approved the Legislature.
As of 10/03 the interest rate for a fixed rate loan is approximately 7.3 percent for
a 20 year loan and for a variable rate interest rate it is less than four percent.
Projects which are eligible under the Internal Revenue Code of 1986 can qualify
for tax-exempt financing under AIDEA's Conduit Revenue Bond Program. To qualify
for this program an organization must have first obtained a determination by the IRS that
it qualifies as a 501(c)(3) tax exempt organization. Under this program, AIDEA acts only
as a conduit for the issuance of either taxable or tax-exempt bonds. Neither the assets nor
credit of AIDEA is at risk in this program; the creditworthiness of the project and credit
enhancements offered by the applicant are essential to the underwriting and placement of
bonds.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VIII
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PROJECT FINANCING Section VIII-1.6
· A business enterprise may request the adoption of an eligibility resolution for tax-
exempt financing by submitting a preliminary application and nonrefundable
$500 application fee to AIDEA on a form provided by AIDEA. If the board of
directors adopts an eligibility resolution for a project, an applicant then submits an
application for financing for the project. A preliminary application is also
required for the issuance of taxable bonds, however, the board of directors do not
need to adopt an eligibility resolution. In addition to third-party costs, the
applicant will pay a financing fee to AIDEA.
The interest rate on tax-exempt debt is typically about 2 percent below the cost of
conventional taxable financing.
E. ALASKA RAILROAD BONDS
The railroad has special authority to provide tax-exempt economic development
financing, granted by Congress in 1983 when the railroad was transferred from federal to
state ownership. Congress took away most powers for states and municipalities to issue
tax-exempt industrial development bonds in the 1986 tax reform act, but the special
provision for the Alaska Railroad was one of three exceptions allowed in 1986. Congress
included the provision in enabling legislation that transferred the federally-owned
railroad to state ownership in 1983. The authority was reaffirmed by Congress in 1986 as
one of three exceptions to the elimination of most tax-exempt economic development
financing in the Tax Reform Act of 1986.
The state-owned railroad has the unique ability to do this kind of financing
without limit as to amount or geographic scope. The railroad would issue "conduit" bonds
to provide the financing, meaning that the credit of neither the railroad nor the state
would be at risk. Similar conduit tax-exempt financing has been done for years in Alaska
for various private projects that qualify under the Internal Revenue Service code.
Similar procedures have been used by the state in issuing tax-exempt bonds to
assist mining development and airport-related projects. The state has also carried out tax-
exempt financing to build road and port infrastructure to support mine development, and
docks and harbors.
The interest rate on tax-exempt debt is typically about 2 percent below the cost of
conventional taxable financing.
F. STATE OF ALASKA GENERAL OBLIGATION BONDS
General obligation bonds create a state debt for capital improvements. The State
of Alaska sold $461,935,000 of general obligation bonds in 2003. The bonds were
authorized by voters in the general election to pay for a wide range of new schools,
building upgrades, highway projects, port and harbor improvements and other
transportation projects. This was Alaska’s first GO bond sale in 20 years. The interest
rate for Series A bonds was 4.069%.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION VIII
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PROJECT FINANCING Section VIII-1.7
G. LEGISLATIVE APPROPRIATIONS
The state legislature could directly appropriate funds to construct the proposed
power generation and transmission facilities. The legislature has, over the past two
decades, appropriated millions of dollars, in the form of grants and low interest loans, to
various utilities throughout the State of Alaska to construct generation and transmission
facilities.
H. PCE FUNDING
The State of Alaska spends approximately $4.3 million per year in the Calista
region to finance the Power Cost Equalization Program. Bethel and the seven villages
that would be served directly from the Donlin Creek transmission line account for
approximately $1.2 million of this total. The project goal is to sell power to the Donlin
Creek mine, Bethel and the eight villages at eight cent s per kWh or less. At that power
cost PCE payments for Bethel and the seven villages, if not totally eliminated, should
decrease drastically. As more power lines are built out to connect additional villages to
the power grid, PCE payments to the region would continue to decline. However, to
achieve a delivered power cost in the range of eight cents per kWh the project will need
substantial grant funding. The legislature should consider advancing a portion of
projected future PCE payments as a grant, to aid in constructing the power project.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
Power Supply Feasibility Study Final Report 06/11/04
ECONOMIC ANALYSIS OF POWER Section IX-1.1
SUPPLY ALTERNATIVES
SECTION IX ECONOMIC ANALYSIS OF POWER
SUPPLY ALTERNATIVES
1. ECONOMIC ANALYSIS
A. OVERVIEW
The primary purpose of this section of the report is to examine the economic
feasibility of constructing either a coal-fired or a combined-cycle combustion turbine
plant at Bethel along with a 138-kV transmission line from Bethel to the Donlin Creek
mine. In order to evaluate the economic benefits of the Bethel coal-fired plant or
combustion turbine plant, additional alternatives that supply an equivalent amount of
power to the Calista region are included. In addition, the Crooked Creek generation
alternative that provides power only to the Donlin Creek mine is evaluated. This section
of the report summarizes the economic analysis of the various power supply alternatives.
B. POWER REQUIREMENTS OF DONLIN MINE, BETHEL & 8 VILLAGES
Many assumptions have been used in preparing the economic analysis. Chief
among these are the projected power requirements of the Donlin Creek mine. At this
stage of development, the peak and average mine demand is not known with any degree
of certainty. Information obtained from Placer Dome suggests an average mine demand
in the range of 60 megawatts. Because the average mine demand can greatly influence
the results of the economic analysis, the study will evaluate the financial impact of a 50
MW average mine demand and a 70 MW average mine demand.
The proposed Bethel power plant and Donlin Creek transmission line will serve
Bethel, Akiachak, Akiak, Tuluksak, Lower/Upper Kalskag, Aniak, Chuathbaluk,
Crooked Creek and the proposed Donlin Creek gold mine project.1 The projected kWh
and kW requirements for these 9 communities are listed in the following two tables, IX-
1.1 & 2. These projections were obtained from a previous study.2
1 Napaimute is being reestablished and may be served for the transmission line.
2 See Calista Regional Energy Needs Study, Part I and II, July 2002.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.2
SUPPLY ALTERNATIVES
TABLE IX-1.1 Projected kWh Requirements
KWH REQUIREMENTS
Year 2010 2020 2030 2040
Akiachak 1,432,766 1,861,297 2,160,111 2,506,897
Akiak 1,217,687 1,593,862 1,849,742 2,146,701
Aniak 3,363,400 4,112,668 4,772,919 5,539,168
Chuathbaluk 260,202 311,869 361,937 420,043
Crooked Creek 1,839,600 2,409,000 3,416,400 3,416,400
Tuluksak 685,005 1,031,768 1,197,409 1,389,642
Lower/Upper Kalskag 1,496,763 1,949,325 2,262,272 2,625,459
Total 10,295,423 13,269,790 16,020,790 18,044,309
Bethel 54,546,206 70,664,781 82,009,364 95,175,214
TOTAL 64,841,628 83,934,571 98,030,154 113,219,524
TABLE IX-1.2 Projected KW Demand
KW DEMAND
Year 2010 2020 2030 2040
Akiachak 327 425 448 477
Akiak 278 364 384 408
Aniak 768 939 991 1,054
Chuathbaluk 60 71 75 80
Crooked Creek 350 500 650 650
Tuluksak 156 236 249 264
Lower/Upper Kalskag 342 445 470 500
Total 2,281 2,980 3,266 3,433
Bethel 9,580 12,410 14,403 16,715
TOTAL 11,861 15,390 17,669 20,148
C. PRINCIPAL ASSUMPTIONS
Principal assumptions used in the economic analysis of the power supply
alternatives are summarized below.
1. General Assumptions
• The expected year of commercial operation for the Donlin Creek mine is 2010.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.3
SUPPLY ALTERNATIVES
• The study period begins in 2010 and ends in 2060, a fifty year period, which
covers the expected useful life of the transmission and generation facilities presented
in this study.
• The Donlin Creek mine is assumed to have a minimum commercial life of 20
years.
• A zero percent per year real escalation rate is assumed, therefore all costs are
stated in unescalated 2003 dollars.
• A zero percent per year discount rate is assumed.
• Capital costs are amortized over a 20 year period.
• Regional energy and demand requirements are held constant following
decommissioning of the Donlin Creek mine, assumed to occur at the end of 2030,
except where noted otherwise.
• Plant Efficiency/Heat Rate
Coal Plant
Fording Coal - 31%/11,000 Btu/kWh
Luscar Coal - 31%/11,000 Btu/kWh
Usibelli Coal - 28%/12,140 Btu/kWh
25%/13,645 Btu/kWh - All coals following
shutdown of Donlin Creek mine
Combustion Turbine Plant
Combined-Cycle
Bethel Plant – 55%/6,200 Btu/kWh
Crooked Creek Plant – 48%/ 7,100 Btu/kWh
Simple-Cycle – 35%/9,750 Btu/kWh
• Fuel Btu Content
Coal Btu/lb (Calculated Dulong HHV)
Fording Coal - 12,264 Btu/lb
Luscar Coal - 10,843 Btu/lb
Usibelli Coal as mined – 7,128 Btu/lb
#2 Fuel Oil – 130,000 Btu/gallon
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.4
SUPPLY ALTERNATIVES
Propane – 85,000 Btu/gallon
• Following decommissioning of the Donlin Creek mine, appropriate adjustments to
reflect increases in fuel costs, decreases in O&M costs and generation efficiencies
are made in the analysis.
2. Capital Costs
a. Coal-Fired Plant
97 MW Land-Based Coal-Fired Plant with 46 MW Standby
CombustionTurbine (143 MW total)
97 MW Coal-Fired Plant
Fording Coal - $211.1 million or $2,175/kW
Luscar Coal - $215.8 million or $2,225/kW
Usibelli Coal – Not Considered
46 MW Standby Turbine -$ 17 million or $ 370/kW
97 MW Barge-Mounted Coal-Fired Plant with 46 MW Standby
CombustionTurbine (143 MW total)
97 MW Coal-Fired Plant
Fording Coal - $188.1 million or $1,940/kW
Luscar Coal - $193.0 million or $1,990/kW
Usibelli Coal - $223.1 million or $2,300/kW
46 MW Standby Turbine -$ 17 million or $ 370/kW
80 MW Barge-Mounted Coal-Fired Plant with 25 MW Standby
CombustionTurbine (105 MW total)
80 MW Coal-Fired Plant
Fording Coal - $175.1 million or $2,190/kW
Luscar Coal - $179.2 million or $2,240/kW
Usibelli Coal – Not Considered
25 MW Standby Turbine - $9.9 million or $ 395/kW
10 MW Bethel Utilities diesel plant - $ 2.5 million
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.5
SUPPLY ALTERNATIVES
b. Combined-Cycle Combustion Turbine Plant at Bethel
150 MW Land-Based Combined-Cycle Turbine Plant
$134 million or $890/KW
150 MW Barge-Mounted Combined-Cycle Turbine Plant
$123 million or $820/KW
c. Combined-Cycle Combustion Turbine Plant at Crooked Creek
110 MW Land-Based Combined Cycle Turbine Plant
$98.7 million or $900/KW
d. Coal Lightering Equipment
3 Barges and 1 Tug @ $11.6 million
e. Transmission Lines
138-kV Donlin Creek transmission line @ $680,900/mile
230-kV Nenana to Donlin Creek Transmission line @ $930,185/mile
+ 100-kV, DC, Nenana to Donlin Creek transmission line @
$733,700/mile
f. Substations
Power Plant Substation @ $4.1 million
Bethel Utilities Diesel Plant modifications @ $0.5 million
Aniak Substation @ $0.93 million
6 Village Substations @ $0.585 million each
9.5 miles 12.47 kV interface feeders @ $2.8 million
Donlin Mine SVC and substation to be constructed by Placer Dome
230 kV, AC, Substation at Nenana $4 million
AC-DC Conversion Equipment @ $100 million
g. District Heating System Bethel @ $11.6 million
h. Fuel Oil or Propane Storage
25 million gallon fuel oil tank farm @ $25 million or $1.00 per gallon
3 million gallon fuel oil tank farm @ $4.1 million or $1.37 per gallon
37 million gallon propane tank farm @ $27.8 million or $0.75 per gallon
Coal storage included in item 1.a.
3. Annual O&M Costs
a. Fuel Costs
#2 Fuel Oil delivered to Bethel @ $1.04 per gallon
#2 Fuel Oil delivered to Crooked Creek @ $1.25 per gallon
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.6
SUPPLY ALTERNATIVES
Propane delivered to Bethel @ $0.65 per gallon
Coal price per U.S. ton delivered to Security Cove or Goodnews Bay
i. Fording Coal - $55.00
ii. Luscar Coal - $43.25
iii. Usibelli Coal -$28.70
Coal prices increased $15 per ton following shutdown of Donlin Creek
mine
b. Purchased Power Costs at Nenana Substation
4.5 cents per kWh
$11.25 per KW monthly demand cost
c. Coal Plant
Personnel Cost @ $2.1 million
Equipment/Supply Costs @ 5 million using Fording Coal
Additional Cost for using Usibelli coal @ $500,000
Additional Cost for using Luscar coal @ $200,000
d. Nuvista Barging Option O&M
i. Fording Coal - $1,567,000
ii. Luscar Coal - $1,770,000
iii. Usibelli Coal - $2,695,000
e. Combined-Cycle Combustion Turbine Plant
Personnel Cost @ $1.6 million
Equipment/Supply Costs @ $4.1 million
f. Nuvista Administrative Cost @ $400,000
g. Transmission Line and Substations @ $500 per transmission line mile
h. EIS and Permitting Costs
Donlin Creek Transmission Line @ $3 million
Bethel or Crooked Creek Power Plant @ $3 million
Nenana to Donlin Mine Transmission Line @ $6 million
D. COMPARISON OF ECONOMIC RESULTS
Detailed spreadsheets containing the results of the economic analysis can be
found in Appendix G. The following discussion, tables and graphs summarize the results
of the analysis.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.7
SUPPLY ALTERNATIVES
1. Capital Costs
Eight different generation alternatives were investigated as part of this study.
These eight alternatives, along with their respective capital costs, are listed in Table IX-
1.3. Alternatives 1, 2 & 3 investigate various scenarios for a coal-plant located at Bethel,
while, alternatives 4 & 5 investigate two combined-cycle combustion turbine alternatives
located at Bethel. These alternatives include the cost of constructing a 138-kV
transmission line between Bethel and the Donlin Creek mine and associated substations.
Alternative 6 examines a combined-cycle combustion turbine plant at Crooked Creek.
The last two alternatives, 7 & 8, examine importing power from the rail belt. These two
alternatives include the cost of constructing a 138-kV transmission line between Donlin
Creek mine and Bethel. Except for Alternative 6, all alternatives are evaluated using the
premise that each alternative must supply power to the Donlin Creek mine, Bethel and
the eight villages located between Bethel and the mine site. Alternative 6 supplies power
only to Crooked Creek and the mine.
Table IX-1.3
Capital Costs
Does Not Include Interest During Construction
97 MW Coal Plant 97 MW Coal Plant 80 MW Coal Plant 150 MW CT Plant
+ 46 MW CT + 46 MW CT + 25 MW CT Bethel
Bethel-Land Based Bethel-Barge Mounted Bethel- Barge Mounted Land-Based
Alt. 1 Alt. 2 Alt. 3 Alt. 4
$392,282,800 $369,487,800 $351,237,800 $307,077,800
150 CT Plant 110 MW CT Plant 230 kV, AC +100 kV, DC
Bethel Crooked Ck T-Line T-Line
Barge Mounted Land-Based from Nenana from Nenana
Alt. 5 Alt. 6 Alt. 7 Alt. 8
$296,577,800 $140,632,600 $494,648,260 $521,946,800
Table IX-1.3 reveals that importing power from the rail-belt using either a 230-
kV, AC transmission line or a + 100-kV, DC transmission line are the two most capital
intensive alternatives proposed, while constructing a power plant at Crooked Creek to
serve only the mine load is the least capital intensive alternative.
2. Coal Supply Sensitivity Analysis
Coals from three different mines were examined and compared to determine the
sensitivity of power costs to coal costs and Btu content. The three coals examined are
from the Fording, Luscar and Usibelli mines. The cost per U.S. ton, delivered to Security
Cove or Goodnews Bay and the calculated Dulong HHV in Btu per pound for these three
coals are as listed below. Table IX-1.4 summarizes the results of this comparison.
Fording Coal - $55.00/ton - 12,264 Btu/lb
Luscar Coal - $43.25 - 10,843 Btu/lb
Usibelli Coal - $ 28.70 - 7,128 Btu/lb
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.8
SUPPLY ALTERNATIVES
TABLE IX-1.4
60 MW Average Mine Demand
Power Costs $/kWh - Selected Coals
97 MW Barge-Mounted Coal Plant
Fording @ $55.00/ton Luscar @ $43.25/ton Usibelli @ $28.70/ton
5%$0.103 $0.102 $0.111
$100 M Grants, Bal. 5%$0.090 $0.088 $0.097
$150 M Grants, Bal. 5%$0.083 $0.081 $0.090
$200 M Grants, Bal. 5%$0.076 $0.074 $0.083
$250 M Grants, Bal. 5%$0.069 $0.067 $0.076
Coal Cost per U.S. ton delivered to Security Cove or Goodnews Bay
A review of Table IX-1.4 reveals that Usibelli coal, although the lowest cost per
ton, produces the highest power costs averaging nine-tenths of a cent greater than Luscar
coal. Fording and Luscar coals produce essentially the same power costs, with Luscar
coal producing power at approximately two-tenths of a cent below the cost of power
produced by Fording coal. Because Fording and Luscar coal produce essentially the
same power costs, Fording coal will remain the baseline coal and is utilized in the
calculations to generate the subsequent tables.
3. Wholesale Power Costs
Table IX-1.5 summarizes and allows for a ready comparison of the wholesale
power cost, expressed in dollars per kilowatt hour, for the various alternatives, based on
an average mine demand of 60 megawatts. Wholesale power costs are derived by adding
one-half cent to power production costs. Power costs for five different finance options
are included. The table only contains the power cost for the Bethel barge-mounted power
plant alternatives. The Bethel land-based power plant alternatives are not included as they
are more expensive to construct and would, therefore, obviously produce more expensive
power than their barge-mounted counterparts.
A review of Table IX-1.5 discloses that the Bethel coal-fired plant alternatives
produce the lowest cost power for all financing options, while importing power from the
rail-belt results in the highest cost power. Alternatives 7 and 8 assume firm power can be
purchased at the Nenana substation for 4.5 cents per kWh and $11.25 kW demand
charge. Alternative 7A assumes non-firm power can be purchased at the Nenana
substation for 4.5 cents per kWh but there is no demand charge. Even when purchasing
non-firm power (Alternative 7A) the cost of power imported from the rail-belt is 2 cents
per kWh more expensive than power produced by the Bethel coal plant alternative, for all
financing options.
Power costs associated with two different coal plant sizes are listed in
Alternatives 2 and 3. Alternative 2 represents power cost for a plant with a total installed
capacity of 143 MW, while Alternative 3 is for a plant with an installed capacity of 105
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.9
SUPPLY ALTERNATIVES
MW. The power cost for these two alternatives are identical for all practical purposes,
varying by by no more than three-tenths of a cent. Reducing the installed generation
capacity of the coal plant by 39 MW or 27% has only a minor impact on the cost of
power. Since the power costs associated with Alt. 2 and 3 are essentially equal, Alt. 3
will no longer be included in the discussion as a separate alternative. The final installed
capacity of the coal-plant will be determined after Placer Dome more accurately
ascertains the peak and average mine demand. It is, however, expected to fall between the
upper and lower limits established by Alt. 2 and Alt. 3.
Alternative 5 and 5A examine the cost of power associated with a combined-cycle
combustion turbine plant. The two alternatives differ only in that Alternative 5 examines
power cost associated with using #2 fuel oil, while 5A scrutinizes the cost of power
connected with using propane fuel. An examination of the power costs associated with
these two alternatives discloses propane produces power at two-tenths of one cent lower
than fuel oil.
Table IX-1.5
60 MW Average Mine Demand
Wholesale Power Costs Years 1-20
97 MW Coal Plant 80 MW Coal Plant 150 MW CT Plant 150 MW CT Plant
+ 46 MW CT + 25 MW CT Bethel - #2 Fuel oil Bethel - Propane
Bethel-Barge Mounted Bethel-Barge Mounted Barge Mounted Barge Mounted
Financing Option Alt. 2 Alt. 3 Alt. 5 Alt. 5A
5%$0.103 $0.101 $0.113 $0.111
$100 M Grants, Bal. 5%$0.090 $0.087 $0.099 $0.097
$150 M Grants, Bal. 5%$0.083 $0.080 $0.092 $0.090
$200 M Grants, Bal. 5%$0.076 $0.073 $0.085 $0.083
$250 M Grants, Bal. 5%$0.069 $0.066 $0.078 $0.076
110 MW CT Plant 230 kV, AC 230 kV, AC +100 kV, DC
Crooked Ck T-Line T-Line T-Line
Land-Based w/Demand Charge w/o Demand Charge w/Demand Charge
Financing Option Alt. 6 Alt. 7 Alt. 7A Alt. 8
5%$0.112 $0.136 $0.123 $0.128
$100 M Grants, Bal. 5%$0.096 $0.122 $0.109 $0.114
$150 M Grants, Bal. 5%$0.090 $0.116 $0.102 $0.107
$200 M Grants, Bal. 5%$0.090 $0.109 $0.095 $0.100
$250 M Grants, Bal. 5%$0.090 $0.102 $0.088 $0.093
Finally, Alternative 6 lists the cost of power associated with constructing and
operating a combined-cycle power plant at Cooked Creek to supply the Donlin Creek
mine. Power costs for this alternative are effectively equal to the cost of power from
Alternative 5A. Power costs for the Cooked Creek plant remain constant for the final
three financing options. This is because the capital cost of the Crooked Creek plant is
less than $150 million dollars.
Figure IX-1.1 graphically displays power cost, in dollars per kWh, associated with
four selected alternatives for the five financing options. This graph clearly illustrates that
the coal-plant alternative provides the lowest cost power, at any financing option, and
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.10
SUPPLY ALTERNATIVES
importing power from the rail-belt via a transmission line produces the highest cost
power.
Figure IX-1.1
Power Cost Comparison- Years 1-20
$0.000
$0.020
$0.040
$0.060
$0.080
$0.100
$0.120
$0.140
$/kwH97 MW Coal Plant(ALT. 2)$0.103 $0.090 $0.083 $0.076 $0.069
150 MW CT Plant (Alt. 5A)$0.111 $0.097 $0.090 $0.083 $0.076
110 Crooked Ck Plant (Alt.6)$0.112 $0.096 $0.090 $0.090 $0.090
230 kV, AC Tline (Alt 7A)$0.123 $0.109 $0.102 $0.095 $0.088
5% $100 M Grants, Bal. 5% $150 M Grants, Bal. 5% $200 M Grants, Bal. 5% $250 M Grants, Bal. 5%
60 MW Average Mine Load
20 Year Mine Life
4. 20-Year Accumulated Donlin Creek Mine Power Costs
Tables IX-1.6 lists the accumulated mine power costs for the various generation
alternatives and financing options for 60 MW average mine load and a 20 year mine life.
The magnitude of 20 years of accumulated power cost is truly astonishing. The
accumulated costs range between a maximum of $1,520 million ($1.52 billion) dollars for
Alt. 8 to a low of $735 million for Alt. 2. Assuming $150 million in grant funds3 can be
obtained to finance construction of Alternative 2, a coal-plant at Bethel + the 138-kV
transmission line, the projected 20 year accumulated mine power cost would be
approximately $885.6 million dollars, for an average cost of $44.2 million dollars per
year.
3 The $150 million grant fund option was selected as it produces power cost for Alt. 2 in the price range
that may be economically acceptable to Placer Dome.
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.11
SUPPLY ALTERNATIVES
Table IX-1.6
60 MW Average Mine Demand
20 Year Mine Life
Donlin Ck Mine Accumulated Power Costs Years 1-20
97 MW Coal Plant 150 MW CT Plant 150 MW CT Plant 110 MW CT Plant
+ 46 MW CT Bethel - #2 Fuel oil Bethel - Propane Crooked Ck
Barge Mounted Barge Mounted Barge Mounted Land-Based
Financing Option Alt. 2 Alt. 5 Alt. 5A Alt. 6
5%$1,110,512,156 $1,204,682,971 $1,183,673,214 $1,180,224,519
$100 M Grants, Bal. 5%$960,508,237 $1,054,679,052 $1,033,669,295 --
$150 M Grants, Bal. 5%$885,506,278 $979,677,093 $958,667,336 --
$200 M Grants, Bal. 5%$810,504,319 $904,675,133 $883,665,377 --
$250 M Grants, Bal. 5%$735,502,359 $829,673,174 $808,663,417 --
230 kV, AC 230 kV, AC +100 kV, DC
T-Line T-Line T-Line
w/Demand Charge w/o Demand Charge w/Demand Charge
Alt. 7 Alt. 7A Alt. 8
5%$1,458,404,593 $1,314,192,234 $1,518,302,581
$100 M Grants, Bal. 5%$1,308,400,674 $1,164,188,315 $1,368,298,662
$150 M Grants, Bal. 5%$1,233,398,715 $1,089,186,356 $1,293,296,702
$200 M Grants, Bal. 5%$1,158,396,756 $1,014,184,396 $1,218,294,743
$250 M Grants, Bal. 5%$1,083,394,796 $939,182,437 $1,143,292,784
Table IX-1.7 illustrates the saving associated with Alternative 2, the 97 MW
barge-mounted coal-fired generation alternative, as compared to other generation
alternatives, for the same twenty year period. When compared to the Crooked Creek
alternative (Alt. 6), the coal plant (Alt. 2) is estimated to save $294.7 million dollars in
power costs, or
Table IX-1.7
60 MW Average Mine Demand
20 Year Mine Life - $150 Million in Grants
Saving Associated with 97 MW Coal-Fired Generation vs. Other Alternatives
97 MW Coal Plant 150 MW CT Plant 150 MW CT Plant 110 MW CT Plant
+ 46 MW CT Bethel - #2 Fuel oil Bethel - Propane Crooked Ck
Barge Mounted Barge Mounted Barge Mounted Land-Based
Alt. 2 Alt. 5 Alt. 5A Alt. 6 (1)
Total Saving $0 $94,170,815 $73,161,058 $294,718,241
Average Annual Savings $0 $4,708,541 $3,658,053 $14,735,912
230 kV, AC 230 kV, AC +100 kV, DC
T-Line T-Line T-Line
w/Demand Charge w/o Demand Charge w/Demand Charge
Alt. 7 Alt. 7A Alt. 8
Total Saving $347,892,437 $203,680,078 $407,790,424
Average Annual Savings $17,394,622 $10,184,004 $20,389,521
(1) Savings calculated using accumulated power cost for 5% Financing Option for Crooked Creek alternative,
as it is presumed only minimal grant funding will be available for this alternative
$14.7 million dollars a year. Compared to the Alt. 5A, the next lowest cost alternative,
Alt. 2 is estimated to save $94.2 million dollars in power costs, or $4.7 million dollars a
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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SUPPLY ALTERNATIVES
year. Comparing Alt. 2 to the 230 kV transmission line non-firm power option, (Alt.
7A), the estimated savings are $203 million, or $10.2 million per year.
The costs shown in Table IX-1.7 were calculated using a 60 MW average mine
demand, 20-year mine life and $150 million in grant fund financing, except for
Alternative 6. The Crooked Creek column assumes this alternative must be entirely
funded with 5% interest loans. It is assumed that since a power plant at Crooked Creek
would essentially only serve the mine load, little if any grant funding would be available
for the Crooked Creek plant alternative. Savings for other finance options can be
calculated using the data in Table IX-1.6.
5. 50-Year Accumulated Regional Power Costs
The useful life of the transmission and generation facilities presented and
discussed in this study is projected to be 50 years. Therefore, it is necessary to investigate
the regional power costs associated with the proposed alternatives for the entire 50 year
period. Figure IX-1.2 illustrates the power costs for selected alternatives for a 50 year
period, beginning in 2010.
Figure IX-1.2
50 Year Regional Power Costs
$0.000
$0.020
$0.040
$0.060
$0.080
$0.100
$0.120
$0.140
2010 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060
Year$/kWhCP(Alt. 2)- 20 Yr Mine Life CP(Alt. 2) - 50 Yr Mine Life
CP(Alt. 2) - 50Yr Mine Life, 30 MW in 2031 CT(Alt. 5A) - 20 Yr Mine Life
230kV Tline(Alt. 7A) -20 Yr Mine Life
$150 M illion Grant Funding, Bal . @ 5%
60 MW Average Mine Demand
Unless Noted Otherwise
The graph demonstrates that wholesale power costs remain relatively constant
over the first twenty years for all alternatives. This corresponds to the estimated life of
the mine. After 20 years, when capital costs are fully amortized, there is a step change in
power cost. The graph shows a change in the cost of power occurring gradually between
2030 and 2035, while it actuality this step change would occur in 2031, as soon as the
capital costs are fully paid. However, the graphics software cannot easily show this step
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
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ECONOMIC ANALYSIS OF POWER Section IX-1.13
SUPPLY ALTERNATIVES
change. Wholesale power costs after 2030 are calculated by adjusting fuel cost,
operational and maintenance costs as appropriate, to reflect cost changes in these items
associated with reduced generation requirements.
The following can be determined from reviewing Figure IX-1.2. When the
Donlin Creek mine ceases operations at the end 20 years, in the year 2030, the wholesale
power cost for the coal-plant alternative (Alt. 2) and the combined-cycle alternative (Alt.
3) will increase to 10.5 cents and 13.7 cents per kWh, respectively. The power cost for
the 230-kV transmission line alternative (Alt. 7A) will decrease to 5.5 cents per kWh,
assuming no demand charge. These costs assume that no other loads but Bethel and the
eight villages are served by the power system after 2030.
If the mine life extends for 50 years, power cost for Alt. 2 would decrease to 5.7
cents per kWh. The graph also establishes that if the mine remains operational after 2030,
but at a reduced demand of 30 MW, or if a new load or loads equal to 30 MW can be
served, wholesale power costs will decrease to approximately 6.6 cents per kWh. This is
not an unlikely scenario as it is most probable that additional villages in the region will be
connected to the power system prior to 2030 and that additional gold deposits located in
the Calista region will be developed and mined once low cost power is available.
Table IX-1.8 lists the 50 year accumulated regional power costs for several power
supply alternatives. The highest accumulated power cost are associated with importing
power into the region via a transmission line from Nenana, and the lowest costs with in-
region power supply alternatives. No costs are listed in the Crooked Creek Plant column
as it is assumed this alternative would only serve the mine load and would be
decommissioned at the end of 20 years.
Table IX-1.8
60 MW Average Mine Demand
20 Year Mine Life
Accumulated Regional Power Costs Years 1-50
97 MW Coal Plant 150 MW CT Plant 150 MW CT Plant 110 MW CT Plant
+ 46 MW CT Bethel - #2 Fuel oil Bethel - Propane Crooked Ck
Barge Mounted Barge Mounted Barge Mounted Land-Based
Financing Option Alt. 2 Alt. 5 Alt. 5A Alt. 6
5%$1,841,649,438 $2,069,255,493 $2,046,424,559 --
$100 M Grants, Bal. 5%$1,631,012,647 $1,858,618,701 $1,835,787,767 --
$150 M Grants, Bal. 5%$1,525,694,251 $1,753,300,306 $1,730,469,372 --
$200 M Grants, Bal. 5%$1,420,375,855 $1,647,981,910 $1,625,150,976 --
$250 M Grants, Bal. 5%$1,315,057,460 $1,542,663,514 $1,519,832,580 --
230 kV, AC 230 kV, AC +100 kV, DC
T-Line T-Line T-Line
w/Demand Charge w/o Demand Charge w/Demand Charge
Alt. 7 Alt. 7A Alt. 8
5%$2,278,457,538 $2,023,306,691 $2,194,060,761
$100 M Grants, Bal. 5%$2,067,820,747 $1,812,669,900 $1,983,423,969
$150 M Grants, Bal. 5%$1,962,502,351 $1,707,351,504 $1,878,105,574
$200 M Grants, Bal. 5%$1,857,183,955 $1,602,033,109 $1,772,787,178
$250 M Grants, Bal. 5%$1,751,865,560 $1,496,714,713 $1,667,468,782
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
Power Supply Feasibility Study Final Report 06/11/04
ECONOMIC ANALYSIS OF POWER Section IX-1.14
SUPPLY ALTERNATIVES
Table IX-1.9 illustrates the saving associated with Alternative 2, the 97 MW
barge-mounted coal-fired generation alternative, as compared to other generation
alternatives, for the fifty year period. Implementation of Alt. 2 results in the lowest 50-
year accumulated power costs, saving the region over $181 million when compared to the
next lowest cost alternative, which is Alt. 7A. Although Alt. 7A provides lower cost
power to the region following closure of the mine (See Figure IX-1.2) it cannot be
economically implemented because power costs, for this alternative during the initial 20-
year period, are significantly in excess of those provided by Alt. 2.
Table IX-1.9
60 MW Average Mine Demand
20 Year Mine Life - $150 Million in Grants
50 Year Regional Saving Associated with 97 MW Coal-Fired Generation vs. Other Alternatives
97 MW Coal Plant 150 MW CT Plant 150 MW CT Plant 110 MW CT Plant
+ 46 MW CT Bethel - #2 Fuel oil Bethel - Propane Crooked Ck
Barge Mounted Barge Mounted Barge Mounted Land-Based
Alt. 2 Alt. 5 Alt. 5A Alt. 6
Total Saving $0 $227,606,055 $204,775,121 --
Average Annual Savings $0 $4,552,121 $4,095,502 --
230 kV, AC 230 kV, AC +100 kV, DC
T-Line T-Line T-Line
w/Demand Charge w/o Demand Charge w/Demand Charge
Alt. 7 Alt. 7A Alt. 8
Total Saving $436,808,100 $181,657,253 $352,411,323
Average Annual Savings $8,736,162 $3,633,145 $7,048,226
6. Fuel Price Sensitivity Analysis
The sensitivity of wholesale power cost to fuel cost is examined in Table IX-1.10. The
table lists wholesale power costs for both the “base” fuel price used in this study and for
base price plus 25 percent, for the five financing options. An examination of the data
reveals that the percentage increase in wholesale power costs for combined-cycle
combustion turbine plant is approximately 1.75 times that of a coal plant. This is because
fuel cost represents a greater portion of the wholesale power cost for a turbine plant than
it does for a coal-plant. This relationship is illustrated in Figure IX-1.3, which breaks
Table IX-1.10
60 MW Average Mine Demand
20 Year Mine Life
Fuel Cost Sensitivity Analysis - 25% Fuel Price Increase
Coal Plant (Alt. 2) CT Plant (Alt. 5A)
25% Price Increase % Increase 25% Price Increase % Increase
Financing Alternatives $55.00/ton $68.75/ton Wholesale Power $0.65/gal $0.82/gal Wholesale Power
5%$0.103 $0.111 7.8% $0.111 $0.124 11.7%
$100 M Grants, Bal. 5%$0.090 $0.097 7.8% $0.097 $0.110 13.4%
$150 M Grants, Bal. 5%$0.083 $0.090 8.4% $0.090 $0.104 15.6%
$200 M Grants, Bal. 5%$0.076 $0.083 9.2% $0.083 $0.097 16.9%
$250 M Grants, Bal. 5%$0.069 $0.076 10.1% $0.076 $0.090 18.4%
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
Power Supply Feasibility Study Final Report 06/11/04
ECONOMIC ANALYSIS OF POWER Section IX-1.15
SUPPLY ALTERNATIVES
down the percentage of wholesale power cost allocated to capital cost, O&M (Fuel
included) and profit.
Figure IX-1.3
Power Cost Breakdown
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%% of kWh CostProfit $0.005 0.005
O&M $0.047 0.064
Capital Cost $0.030 0.021
Coal Plant (Alt. 2) CT Plant (Alt. 5A)
$150 Millon Grants, Balance at 5% -Financing Option
7. Mine Demand Sensitivity Analysis
To determine the effects of variations in mine demand, wholesale power costs for
Alt. 2 were examined using average mine demands of 50 MW and 70 MW for three
financing options. The results of this analysis are summarized in Table IX-1.11. On
average wholesale power costs will increase 1.2 cents per kWh if mine demand drops to
50 MW and cost will decrease by seven-tenths of a cent per kWh if mine demand
increases to 70 MW. Other alternatives would experience similar variations is power
costs.
Table IX-1.11 Mine Demand Sensitivity
Mine Demand
Wholesale Power Cost 50 MW 60 MW 70 MW
5% $.119 $0.103 $0.093
$150 Grants, Bal. 5% $0.095 $0.083 $0.075
$250 Grants, Bal. 5% $0.079 $0.069 $0.063
8. Coal-fired Plant Generation Efficiency
A coal-fired plant generation efficiency of 31% has been used to calculate power
costs for the various coal-fired power plant alternatives investigated in this study. This
nominal efficiency was calculated by PES for a coal plant that uses common off-the-shelf
equipment. However, it is possible, through careful engineering and selection of
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
Power Supply Feasibility Study Final Report 06/11/04
ECONOMIC ANALYSIS OF POWER Section IX-1.16
SUPPLY ALTERNATIVES
equipment, to increase generation efficiency to near 40%. However, higher efficiency
plants are more costly to construct and are more sophisticated to operate. Table IX-1.12
shows the relationship between power cost and generation efficiency. Increasing plant
efficiency to thirty-five percent will reduce wholesale power cost by approximately
$0.004 per kWh. While this may not seem like a substantial reduction, it will reduce
power cost to the mine by $2.4 million dollars annually or by $48 million dollars over the
20 year life of the mine.
Table IX-1.12
Generation Efficiency
Wholesale Power Cost 31% 35% 40%
5% $.103 $0.10 $0.097
$150 Grants, Bal. 5% $0.083 $0.079 $0.076
$250 Grants, Bal. 5% $0.069 $0.065 $0.062
9. Waste Heat Recovery
The effects of waste heat sales on wholesale power costs were also examined. The
analysis indicated that for every one million dollars of waste heat sales, power cost were
lowered by one-tenth of a cent.
10. Transmission Line Routing Bethel Direct Point K
The alternative of routing the transmission line from Bethel direct to Point K was
examined. Point K is located east of Chauthbaluk where the river turns north. This route
is approximately 25 miles shorter than the proposed route. This alternative assumes only
Bethel and the Donlin Creek mine are served from the generation/transmission facilities.
Routing the transmission line from Bethel direct to Point K reduces power cost by only
two tenth of one cent per kWh for all financing alternatives. Given this small reduction
in power cost it would not seem prudent to route the power line direct from Bethel to
Point K and by pass all the villages.
E. CONCLUSION
The power supply alternative that produces the lowest wholesale cost power cost
is coal-fired generation at Bethel plus construction of a 191 mile, 138-kV transmission
line between Bethel and the Donlin Creek mine.
The power cost estimates were developed using constant dollars. The cost of
power includes permitting, engineering and design, construction, operation &
maintenance, fuel, annual debt service, interest during construction, and applicable
Nuvista Light & Power, Co. – Donlin Creek Mine SECTION IX
Power Supply Feasibility Study Final Report 06/11/04
ECONOMIC ANALYSIS OF POWER Section IX-1.17
SUPPLY ALTERNATIVES
purchased power costs. This power supply alternative would provide power to the Donlin
Creek mine, Bethel and 8 villages located between Bethel and the mine.4
Importing power from the rail-belt via a transmission line built between Nenana
and Crooked Creek results in the highest wholesale power cost.
A combined-cycle combustion turbine plant, whether constructed at Crooked
Creek or Bethel, provides power at essentially the same cost.
4 Napaimute is being reestablished and may also be served from the transmission line.
Glossary Page 1
GLOSSARY
AAC Alaska Administrative Code
AAMT Average Annual Minimum Temperature
AC Alternating Current
ACMP Alaska Coastal Zone Management Program
ACOE U.S. Army Corp of Engineers
ACSR Aluminum Conductor Steel Reinforced
ADEC Alaska Department of Environmental Conservation
ADF&G Alaska Department of Fish and Game
ADNR Alaska Department of Natural Resources
AGL Above Ground Level
AI2O2 Alumina
AIDEA Alaska Industrial Development and Export Authority
ASME American Standard Mechanical Engineers
AVEC Alaska Village Electric Cooperative
AWC An Atlas to the Catalog of Waters Important to the Spawning, Rearing or
Migration of Anadromous Fishes
BACT Best Available Control Technology
BLM Bureau of Land Management
BMP Best Management Practices
BNC Bethel Native Corporation
BTU British Thermal Unit
CCR Central Control Room
CEA Chugach Electric Association
CFC Cooperative Finance Corporatoin
CFR Code of Federal Regulations
CO Carbon Monoxide
CPQ Coastal Project Questionnaire
CRSA Cenaliulriit Coastal Regional Service Area
CT Combustion Turbine
CTG Combustion Turbine Generators
CVEA Copper Valley Electric Association
dB(A) Decible
DC Direct Current
DCS Distributed Control System
DF2 Diesel Fuel
DH District Heating
DMLW Division of Mining, Land and Water
DWT Dead Weight Tons
EA/EIS Environmental Assessment/Environmental Impact Statement
EFH Essential Fish Habitat
EMF Electromagnetic Field
EPA Environmental Protection Agency
ERS Economic Research Service
Glossary Page 2
ESCP Erosion Control Plan
FAA Federal Aviation Administration
FFB Federal Financing Bank
Gpm Gallons Per Minute
g/t Grams/Tonne
HAP Hazardous Air Pollutants
HC Hydro Carbons
HCCP Healy Clean Coal Power Plant
HP Horse Power
HRSG Heat Recovery Steam Generator
kV Kilovolt
kV/m Kilovolt per meter
LOLE Loss of Load Expectation
LP Liquid Propane
MACT Maximum Achievable Control Technology
MEA Matanuska Electric Association
mG Milligauss
MPP Modular Power Plant
MSL Mean Sea Level
MSW Municipal Solid Waste
MW/MWe Mega Watt
MWH Mega Watt Hours
MT Metric Ton
NESC National Electrical Standards Code
NETL National Energy Technology Laboratory
NMFS National Marie Fisheries Service
NOx Nitrogen Oxide
NOI Notice of Intent
NPDES National Pollution Discharge Elimination System
NRCS Natural Resources Conservation Service
NSPS New Source Performance Standards
NWR National Wildlife Refuge
OHW Ordinary High Water.
OHMP Office of Habitat Management and Permitting
OPGW Optical Ground Wire Selection
OPMP Office of Project Management and Permitting
PC Pulverized Coal
PEC Power Cost Equalization
PES Precision Energy Services
PFBC Pressurized Fluidized Bed Combustor
PM Particulate Matter
ppm Parts Per Million
PSD Prevention of Significant Deterioration
psi Microtesla
RELRA Rural Electrification Loan Restructuring Act
R.O.W. Right of Way
Glossary Page 3
RPM Revolutions Per Minute
RUS Division of Rural Utilities
ROD Record of Decision
SCR Selective Catalytic Reduction
SHPO The State Historic and Preservation Office
SNCR Selective Non-Catalytic Reduction
SiO2 Silica
SO2 Sulfer Dioxide
STG Steam Turbine Generator
ST Short Ton
SUP Special Use Permits
SVC Static Var Compensation
SWPPP Storm Water Pollution Prevention Plan
SWGR Single Wire Ground Return
TKC Kuskokwim Corporation
UHC Unburned Hydro Carbons
USACE U.S. Army Corp of Engineers
USDA U.S. Department of Agriculture, Rural Development
USFWS U.S. Fish and Wildlife Service
VOC Volatile Organic Compounds
uT microtesla