HomeMy WebLinkAboutHVDC P2, Final Report 2012
HVDC TRANSMISSION SYSTEM
FOR RURAL ALASKA APPLICATIONS
Phase II ‐ Prototyping and Testing
May 2012
FINAL REPORT, Version 1.1
prepared by
polarconsult alaska, inc.
1503 West 33rd Avenue, Suite 310
Anchorage, Alaska 99503
Phone: (907) 258‐2420
funding agency
The Denali Commission
510 L St., Suite 410
Anchorage, Alaska 99501
Phone: (907) 271‐1414
project administrator
Alaska Center for Energy and Power
University of Alaska, Fairbanks
814 Alumni Dr.
P.O. Box 755910
Fairbanks, Alaska 99775
Phone: (907) 474‐5402
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012
About the Cover Image:
The cover image is of a demonstration installation in Fairbanks of a guyed fiberglass pole similar in size, height,
and construction to the poles considered in this study for overhead transmission in rural Alaska applications. The
pole is a 12‐inch‐diameter, 60‐foot‐tall fiberglass structure supported by three micro‐thermopiles. The pole’s
four guys are anchored by two micro‐thermopiles and two screw anchors set in silt‐rich permafrost.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE I
EXECUTIVE SUMMARY
Program Objectives
This report presents the achievements and findings of Phase II of the “High‐Voltage Direct Current
(HVDC) Transmission Systems for Rural Alaska” research and development (R&D) program. The
goal of this program is to improve the economic viability of Alaska’s rural communities by
providing more affordable electricity transmission alternatives. Phase II work was funded by the
Denali Commission and completed by Polarconsult Alaska, Inc. (Polarconsult) under contract to the
Alaska Center for Energy and Power (ACEP).
The effect of excessive energy costs continues to degrade the quality of life in Alaska’s rural
communities and places these indigenous populations at severe risk. Nearly 80% of rural
communities are dependent on diesel fuel for their primary energy needs. Some of the poorest
households spent 47% of their income on energy in 2008, more than five times the amount in
Anchorage (CWN, 2012).
HVDC interties will support more cost‐effective development of local energy resources, such as
wind, hydro, biomass, geothermal, hydrokinetic, gas, and coal. Reducing the cost of low‐power (1
megawatt [MW] and less) interties by using HVDC systems can enable increased interconnection of
rural communities to Alaska’s abundant energy resources.
HVDC interties will also benefit rural communities with reduced energy costs by building
economics of scale in rural power grids and allowing utilities to consolidate bulk fuel facilities and
diesel electric power plants into more efficient and lower‐cost configurations.
As a result of ongoing advances in power electronics, small‐scale HVDC interties are now feasible.
This report has identified low‐power overhead and submarine HVDC transmission systems as an
economically superior alternative to conventional alternating current (AC) interties. Additional cost
reductions can be realized by integrating HVDC systems with future expansion of broadband fiber‐
optic telecommunication networks. This synergistic opportunity between the telecommunications
and electric industries is one of several reasons HVDC interties can help surmount the economic
barriers facing Alaska’s rural communities.
Comparative analysis of HVDC transmission systems with conventional AC systems indicates
significant technical and economic advantages of HVDC systems. In many rural Alaska applications,
the use of HVDC systems will significantly lower intertie costs.
Phase II Objectives and Findings
Phase II of this R&D program follows the Phase I – Preliminary Design and Feasibility Analysis Final
Report (Polarconsult, 2009). Phase I tasks included assessing converter technical feasibility and
evaluating the economics of a low‐power HVDC system sized for rural Alaska applications. Based on
the favorable results of the Phase I project, the following Phase II objectives were established:
● Confirmation of the technical feasibility of the HVDC/AC power converter technology by
designing, building, and testing a full‐scale prototype of a 1‐MW bidirectional power
converter and key transmission system elements.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE II
● Confirmation of the economic feasibility of the low‐power HVDC system in rural Alaska
applications by determining the commercial cost of the converter, the converter’s efficiency,
and the estimated overall costs of an HVDC system.
● Development of cost estimates for HVDC transmission systems and comparison with
conventional AC systems to quantify the benefits and savings of HVDC systems.
Phase II has demonstrated that the converter technology is technically viable and the transmission
system is economically feasible. Key Phase II findings are:
● Low‐power HVDC converter technology is expected to be commercially available at $250
per kilowatt per converter.
● Estimates of construction costs for a conceptual 25‐mile overhead HVDC intertie indicate
capital cost savings of approximately 30% compared with a conventional overhead AC
intertie. Estimated life‐cycle costs range from 79% to 107% of the life‐cycle cost of an AC
intertie.
● Longer overhead HVDC interties can expect capital cost savings of up to 40%.
● Phase II analysis also indicates that significant savings are possible for submarine cable and
underground cable applications using HVDC systems. Estimated capital cost savings on a
25‐mile low‐power HVDC submarine cable intertie are over 50% compared to AC
alternatives.
Based on Phase II findings, the benefits of low‐power HVDC systems for Alaska are substantial, and
continued development of this system is recommended.
Opportunities and Barriers
Based on analysis and study conducted during this Phase II project, Polarconsult has concluded that
this HVDC technology presents the following opportunities for Alaska’s utility industry and rural
communities:
● Less expensive rural electric interties, leading to lower‐cost energy and increased energy
independence for rural communities.
● Interconnection to currently stranded local energy resources.
● Interconnection cost savings by combining rural electric and telecommunications interties.
The successful commercialization and adoption of low‐power HVDC technology in Alaska requires
overcoming the following barriers:
● Completion of the commercial development and demonstration of the converter technology.
Continued development of the prototype converters, culminating in independent testing of
the converters and deployment on an Alaska utility system, is needed to prove that the
converters are a commercially viable technology.
● Acceptance and use of low‐power HVDC technology by Alaska’s utility industry. Continued
involvement of in‐state and international stakeholders with the ongoing development of
this technology is considered necessary to surmounting this barrier.
● Development and demonstration of standards and control protocols for low‐power
multiterminal direct‐current (MTDC) transmission networks, which are needed to build
cost‐effective regional HVDC power networks in rural Alaska.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE III
Recommendations
Based on the conclusions and findings of this project, the following actions are recommended:
Phase III program activities:
● Continued development of the power converter technology to commercialize the existing
prototype converter design. Solicitation of additional HVDC converter manufacturers is
warranted to encourage diversity of suppliers and competition;
● Independent testing of the converters to validate efficiency and performance, followed by
deployment on an Alaskan utility system to validate functionality and reliability in a
commercial setting;
● Further development of MTDC transmission systems interconnection and control
technologies; and
● Continued involvement of in‐state stakeholders in the development of this technology.
Stakeholder actions:
● Incorporate low‐power HVDC technology into Alaska’s regional and statewide energy plans
and policies;
● Continue coordination with the State of Alaska to allow a project‐specific waiver of the
National Electrical Safety Code (NESC) to allow the use of single‐wire earth return (SWER)
circuits;
● Encourage planned rural power and telecommunications interties to incorporate HVDC
technology in their economic and technical analysis, as well as their environmental and
permitting review processes;
● Engage the telecommunications industry to raise awareness of the synergies possible
between low‐power HVDC transmission and fiber networks in rural Alaska; and
● Collaborate with international stakeholders to identify synergies and lessons learned from
parallel technology development efforts. Coordinate on development of applicable
policies/standards and identification of markets to help expedite the commercialization and
reduce the costs of low‐power HVDC systems.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE IV
TABLE OF CONTENTS
EXECUTIVE SUMMARY ........................................................................................................................................................... I
1.0 INTRODUCTION ........................................................................................................................................................ 1
1.1 REPORT ORGANIZATION ...................................................................................................................................................2
1.2 ACKNOWLEDGEMENTS ......................................................................................................................................................3
1.3 DISCLAIMER .........................................................................................................................................................................4
1.4 COPYRIGHT NOTICE ...........................................................................................................................................................4
2.0 BACKGROUND ............................................................................................................................................................ 5
2.1 PROGRAM OVERVIEW ........................................................................................................................................................6
2.2 STAKEHOLDER ADVICE ......................................................................................................................................................7
3.0 HVDC TRANSMISSION SYSTEM DESCRIPTION ............................................................................................ 8
3.1 HVDC BACKGROUND ........................................................................................................................................................8
3.2 HVDC SYSTEM CONFIGURATIONS ................................................................................................................................ 10
3.3 COMPARISON OF AC TO HVDC TRANSMISSION ......................................................................................................... 16
3.4 OVERHEAD INTERTIE ALTERNATIVES ......................................................................................................................... 17
3.5 SUBMARINE CABLE INTERTIE ALTERNATIVES ........................................................................................................... 19
4.0 HVDC CONVERTER STATIONS ......................................................................................................................... 20
4.1 OVERVIEW ........................................................................................................................................................................ 20
4.2 CONVERTER DEVELOPMENT OVERVIEW ..................................................................................................................... 20
4.3 ADDITIONAL EQUIPMENT .............................................................................................................................................. 28
5.0 DESIGN CONCEPTS FOR OVERHEAD INTERTIES .................................................................................... 29
5.1 OVERHEAD DESIGN APPROACH .................................................................................................................................... 29
5.2 GEOTECHNICAL CONDITIONS ........................................................................................................................................ 30
5.3 ENVIRONMENTAL LOADS ............................................................................................................................................... 30
5.4 CONSTRUCTION, RUS STANDARD PRACTICE .............................................................................................................. 30
5.5 CONSTRUCTION, ALASKA‐SPECIFIC CONCEPT ............................................................................................................ 31
5.6 TESTING OF OVERHEAD DESIGN CONCEPTS ............................................................................................................... 32
6.0 SYSTEM ECONOMICS ........................................................................................................................................... 37
6.1 COST COMPARISON OF AC AND HVDC OVERHEAD INTERTIES .............................................................................. 37
6.2 CASE STUDIES .................................................................................................................................................................. 41
7.0 CONCLUSIONS AND RECOMMENDATIONS ................................................................................................ 49
7.1 CONCLUSIONS ................................................................................................................................................................... 49
7.2 OPPORTUNITIES AND BARRIERS ................................................................................................................................... 49
7.3 RECOMMENDATIONS ....................................................................................................................................................... 50
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE V
LIST OF TABLES
Table 6‐1 Estimated Life‐Cycle Costs for 25‐mile Overhead AC and HVDC Interties ...................... 39
Table 6‐2 Summary of Case Studies ...................................................................................................................... 42
Table 6‐3 Estimated Cost for a Greens Creek – Hoonah HVDC Intertie ................................................. 44
Table 6‐4 Estimated Benefit‐Cost Ratio of Greens Creek – Hoonah HVDC Intertie .......................... 45
Table 6‐5 Estimated Installed Cost for a 5‐MW Pilgrim Hot Springs – Nome Intertie .................... 48
LIST OF FIGURES
Figure 3‐1 Typical Large HVDC Station .................................................................................................................... 9
Figure 3‐2 Three Types of Interties Used in HVDC Systems ........................................................................ 11
Figure 3‐3 Monopolar HVDC Intertie Using SWER ........................................................................................... 12
Figure 3‐4 Monopolar HVDC Intertie with Return Conductor (SWER‐capable for Backup) .......... 13
Figure 3‐5 Bipolar HVDC Intertie (SWER‐capable for Backup) .................................................................. 14
Figure 4‐1 Low Voltage Alternating Current (LVAC) Enclosure: Mechanical Layout ........................ 22
Figure 4‐2 HVDC Transformer Tank: Mechanical Layout ............................................................................. 23
Figure 4‐3 Central Resonant Link Test Setup ..................................................................................................... 25
Figure 4‐4 Hi–Pot Test Setup for HVDC Transformer ..................................................................................... 25
Figure 4‐5 Dry System Inverter Mode Test Schematic and Setup.............................................................. 26
Figure 4‐6 System #1 HV Tank and LV Enclosure ............................................................................................ 27
Figure 4‐7 System #1 Showing HV Measurement Probes ............................................................................. 27
Figure 5‐1 Installing Micro‐Thermopile for Guy Anchor ............................................................................... 33
Figure 5‐2 Assembling the Prototype GFRP Pole Splice ................................................................................ 34
Figure 5‐3 Prototype GFRP Pole Foundation During Installation .............................................................. 35
Figure 5‐4 Prototype Pole at the Fairbanks Test Site ...................................................................................... 36
Figure 6‐1 Comparative Installed Cost: Overhead 1‐MW HVDC and AC Interties .............................. 38
Figure 6‐2 Comparative Life‐Cycle Cost: Overhead 1‐MW HVDC and AC Interties ............................ 40
Figure 6‐3 Location Map for Potential HVDC Project Sites ........................................................................... 41
Figure 6‐4 Greens Creek – Hoonah Intertie Route ........................................................................................... 43
Figure 6‐5 Prospective Transmission Route from Pilgrim Hot Springs to Nome ................................ 47
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE VI
APPENDICES
APPENDIX A HVDC OVERVIEW ............................................................................................................................ A‐1
APPENDIX B ECONOMIC ANALYSIS ................................................................................................................... B‐1
APPENDIX C CONCEPTUAL DESIGN OF OVERHEAD HVDC INTERTIE LINES ................................. C‐1
APPENDIX D CONCEPTUAL DESIGN FOR SUBMARINE CABLES ............................................................ D‐1
APPENDIX E SWER CIRCUITS AND HVDC SYSTEM GROUNDING ......................................................... E‐1
APPENDIX F HVDC POWER CONVERTER DEVELOPMENT ..................................................................... F‐1
APPENDIX G HVDC SYSTEM PROTECTION, CONTROLS, AND COMMUNICATIONS ...................... G‐1
APPENDIX H CANDIDATE HVDC SYSTEM DEMONSTRATION PROJECTS .......................................... H‐1
APPENDIX I STAKEHOLDER ADVISORY GROUP INVOLVEMENT AND MEETINGS ........................I‐1
APPENDIX J BIBLIOGRAPHY .................................................................................................................................. J‐1
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE VII
ACRONYMS AND TERMINOLOGY
°F degrees Fahrenheit
A, a, i amperes or amps
AC alternating current
ACEP Alaska Center for Energy and Power
ACSR aluminum conductor steel reinforced
ADNR Alaska Department of Natural Resources
AEA Alaska Energy Authority
AEL&P Alaska Electric Light and Power Company
AFI Arctic Foundations, Inc.
AKDOL Alaska Department of Labor
albedo The extent to which an object diffusely reflects light.
alternating
current
The form of electricity commonly used in homes and businesses in which the
current and voltage oscillate at a frequency of 60 cycles per second. (The
frequency in some nations is 50 cycles.)
Alumoweld A type of cable used in electrical systems. Each strand of the cable consists of a
steel core with a layer of aluminum extruded over it during the pulling and
drawing process. The steel core provides increased strength, and the aluminum
exterior provides better corrosion protection and increased electrical
conductivity.
amperes/
amps
A measure of the amount of electrical current flowing through a circuit (a typical
household circuit is rated for 20 amperes).
AP&T Alaska Power and Telephone Company
APA Alaska Power Association
ASCE American Society of Civil Engineers
AVEC Alaska Village Electric Cooperative, Inc.
AVR automatic voltage reference
bandwidth A measure of the data transfer capability of a given communications method.
Units of bandwidth can vary but are generally bits per second.
BEC Bethel Electric Utility
bipolar A type of direct current circuit that uses two wires to transmit energy. Bipolar
circuits operate one wire (“pole”) at a positive potential and the second pole at a
negative potential relative to ground (e.g., +/‐ 600,000 volts). These circuits
normally also have an earth return pathway or a dedicated ground conductor that
is used to compensate for any imbalance on the two poles and serves as a
temporary return pathway if the negative or positive pole is out of service for any
reason.
BSNC Bering Straits Native Corporation
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE VIII
Btu British thermal unit
CEA Chugach Electric Association, Inc.
CIGRE Internationale des Grands Reseaux Electriques
circuit A circuit provides an electrical pathway from a point of energy supply (e.g., a
generator or battery) to a point of energy use (e.g., motor, lighting, etc.), and then
back to the point of supply. Without a complete pathway from supply to use and
back, the circuit will not function. The pathway can take many forms. Most
commonly, it is made of metallic (copper or aluminum) wires, but it can also use
water, the earth, or other materials. These other materials are most often used on
the return pathway back to the point of supply, where the voltage differential
relative to the surrounding environment is low.
conductor A typically metallic wire or cable that is designed and fabricated to conduct
electricity between two locations.
converter An electrical device that converts electricity from AC to DC and/or from DC to AC.
“Converter” is a more general term for a rectifier or inverter.
CVEA Copper Valley Electric Association, Inc.
DC direct current
direct current Direct current is the form of electricity commonly used in battery‐powered
devices such as cars, flashlights, etc. The current does not appreciably vary with
time.
distribution
class
Refers to lower‐voltage electrical systems. Definitions vary, but systems operating
at or below nominal 35 kilovolts (kV) are generally classified as distribution‐class.
Most rural Alaska interties function as transmission systems, but operate at
distribution‐class voltages, typically 14.4 kV.
earth return A means of completing an electrical circuit by using the earth as a return path
instead of a second wire. In many nations, this approach is frequently used in
rural areas where (1) the cost to install a second wire for the return path is
prohibitively high and (2) the lack of buried utilities ensures that technical issues
with ground return are minimized.
EHS extra‐high‐strength
EPR ethylene propylene rubber
fiber optics A communications method that consists of sending pulses of light down glass
fibers.
FO fiber optics
ft‐lb foot‐pound
gal gallon(s)
GEC Gustavus Electric Company
GFRP glass‐fiber‐reinforced polymer
GPS Global Positioning System
GVEA Golden Valley Electric Association, Inc.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE IX
HEA Homer Electric Association, Inc.
hertz A unit of how rapidly something oscillates, rotates, or repeats. One hertz is equal
to one complete cycle per second. Alternating current electrical systems in the U.S.
operate at 60 hertz, or 60 cycles per second.
high‐
impedance
ground fault
A fault or short circuit between a high‐voltage wire and ground. An example of a
high‐impedance ground fault would be a conductor that falls to the ground
without breaking, landing on ice or ice‐rich soils. These soils are very poor
conductors, thus little or no current may short circuit into the ground. Because the
wire did not break, it can continue to transmit energy between the converters.
This energized wire poses a hazard to any people or animals who happen upon it.
high‐voltage
direct current
Direct current electricity at a high voltage relative to the surrounding
environment.
HMI human‐machine interface
hot work Working on electrical equipment while it is energized.
HVDC high‐voltage direct current
IEC International Electro‐technical Commission
IEEE Institute of Electrical and Electronics Engineers
IGBT insulated gate bipolar transistor
inverter An electrical device that can convert DC electricity into AC electricity.
IPEC Inside Passage Electric Cooperative
KEA Kodiak Electric Association, Inc.
kHz kilohertz (1,000 hertz)
kilowatt 1,000 watts. One kW is the power consumed by ten 100‐watt incandescent light
bulbs.
kilowatt‐hour The quantity of energy equal to one kilowatt (kW) expended for one hour.
KoEA Kotzebue Electric Association, Inc.
kV kilovolt (1,000 volts)
kVA kilovolt‐ampere
kW kilowatt (1,000 watts)
kWh kilowatt‐hour
LDE Line Design Engineering, Inc.
LFL line fault locator
LIDAR light detection and ranging
litz wire An electrical wire or cable made of multiple individually insulated strands of wire.
Litz wire is used in high frequency AC applications and is designed to reduce
power losses caused by skin effects and proximity effects that occur at high
frequencies.
LVAC low‐voltage alternating current
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE X
MEA Matanuska Electric Association
MHRC Manitoba HVDC Research Centre
mm2 square millimeters
MOD motor‐operated disconnector
monopolar A direct current circuit that operates one leg of the circuit at an elevated voltage
and the return leg at or near ground voltage. The return leg can use a metallic
conductor or, in the case of earth or sea return systems, can use the earth or sea to
complete the circuit. An HVDC SWER circuit is one type of monopolar circuit.
ms millisecond(s)
MSB Matanuska‐Susitna Borough
MTDC multi‐terminal direct current
MVA megavolt amperes (one million volt amperes)
MW megawatt(s) (1,000 kilowatts)
MWh megawatt‐hours
NCC Nome Chamber of Commerce
NEA Naknek Electric Association, Inc.
NEC Nushagak Electric Cooperative, Inc.
NESC National Electrical Safety Code
NJUS Nome Joint Utility Service
NLP Nuvista Light and Power, Inc.
NRECA National Rural Electric Cooperative Association
NSB North Slope Borough
NWAB Northwest Arctic Borough
O&M operations and maintenance
OED City of Ouzinkie Electric Department
OMR&R Operation and Maintenance, Repair, Replacement, and Rehabilitation
OPGW optical ground wire
PCB printed circuit board
PCE Power Cost Equalization
PLC power line carrier
PPS Princeton Power Systems, Inc.
PSCAD Power Systems Computer Aided Design
psf pounds per square foot
R&D research and development
RCA Regulatory Commission of Alaska
rectifier An electrical device that can convert AC electricity into DC electricity.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE XI
RMS root‐mean‐square
root mean
square
The root mean square voltage is the mean absolute voltage over any whole
number of waveform oscillations. For a sinusoidal waveform (such as normal AC
electricity), the root‐mean‐square (RMS) voltage is the peak voltage divided by
the square root of 2. Nominal 120 volts alternating current (VAC) electricity thus
has a peak voltage of about +/‐170 volts relative to ground.
RUS Rural Utilities Service (USDA)
SAG Stakeholders Advisory Group
SCADA supervisory control and data acquisition
sea return A means of completing an electrical circuit by using the sea (or more generally
rivers, lakes, and other water bodies) as a return path instead of a second wire.
This approach is frequently used on submarine cables where the cost savings
from not installing a second cable justify this approach. Sea return can be used for
single‐phase AC circuits or for DC circuits.
SEAPA Southeast Alaska Power Agency
SEC Southeast Conference
single‐wire
earth return
Another term for an earth return or sea return circuit. The name emphasizes the
fact that these types of circuits only require one wire, as compared with two or
more wires for other types of circuits.
spur and belt A common method of climbing utility poles, trees, and similar objects. Special
climbing spurs are strapped onto the feet and a large belt is fixed around the
climber's waist. The climber loops the belt around the pole and drives the spurs
into the pole. The climber then “walks” up the pole with the spurs, and hitches the
belt along the pole for support.
step potential A voltage gradient that occurs at the ground surface due to earth return currents.
If the voltage gradient is high enough, it can pose a hazard to people or wildlife
stepping in the vicinity.
stranded
energy
resources
Energy resources located in remote, distant, or otherwise isolated areas
“stranded” from either (1) integration into modern energy infrastructure and
supply chains or (2) utilization by local population and industry centers.
SWAMC Southwest Alaska Municipal Conference
SWER single‐wire earth return
transmission‐
class
Refers to higher‐voltage electrical systems. Definitions vary, but in Alaska AC
systems operating above nominal 35 kV line‐to‐ground are generally classified as
transmission‐class. Most rural Alaska interties function as transmission systems,
but are operated at distribution‐class voltages.
twisted pair A generic term for communications cable that uses multiple individually insulated
wires. Each pair of wires is twisted together, hence the name.
TWMR transmission with metallic conductor‐return path
UAF University of Alaska Fairbanks
USDA U.S. Department of Agriculture
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE XII
V volt
VAC volts alternating current
VAR volt‐amperes reactive
VDC volts direct current
VFT variable frequency transformer
volt A unit of electrical potential. Some typical voltages are car battery: 12 volts (DC);
alkaline battery (AAA, C, D, etc.): 1.5 volts (DC); household electricity: 120 volts
(AC RMS).
VSC voltage source converter(s)
ZAE Zarling Aero Consulting
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE 1
1.0 INTRODUCTION
This report presents the achievements and findings of Phase II of the “High‐Voltage Direct Current
(HVDC) Transmission Systems for Rural Alaska” research and development (R&D) program.
The goal of this program is to improve the economic viability of Alaska’s rural communities by
providing more affordable electricity transmission alternatives. The effect of excessive energy costs
continues to degrade the quality of life in Alaska’s rural communities and places these indigenous
populations at severe risk. Nearly 80% of rural communities are dependent on diesel fuel for their
primary energy needs. Some of the poorest households spent 47% of their income on energy in
2008, more than five times the amount in Anchorage (CWN, 2012).
Reducing the cost of low‐power (1 megawatt [MW] and less) interties by using HVDC systems can
enable increased interconnection of rural communities to Alaska’s abundant energy resources.
HVDC interties will support more cost‐effective development of local energy resources, such as
wind, hydro, biomass, geothermal, hydrokinetic, gas, and coal.
Phase II of this program was funded by the Denali Commission and completed by Polarconsult
Alaska, Inc. (Polarconsult) under contract to the Alaska Center for Energy and Power (ACEP). This
Phase II effort and final report follows the results of the Phase I R&D project, completed in 2009
and summarized in Phase I – Preliminary Design and Feasibility Analysis Final Report (Polarconsult,
2009). Phase I of this R&D program included evaluation of the technical and economic feasibility of
the proposed HVDC system, including limited prototyping and testing of the converter technology.
Phase II of the HVDC Transmission System program included design, fabrication, and testing of full‐
scale prototypes of the converter and transmission system elements. The Phase II efforts involved
the evaluation of design, efficiency, and functionality of the HVDC systems. Rural Alaska intertie
alternatives were also investigated, which involved comparing HVDC transmission systems to the
conventional alternating current (AC) alternatives. The Phase II findings were used to further
develop construction cost estimates and refine the economic analysis of the technology developed
in Phase I. Polarconsult is the prime contractor and author of both Phase I and II project reports.
As a result of ongoing advances in power electronics, small‐scale HVDC interties are now feasible.
This report has identified overhead and submarine HVDC transmission systems as economically
superior alternatives to conventional AC interties.
Additional cost reductions can be realized by integrating HVDC systems with future expansion of
broadband fiber‐optic telecommunication networks. This synergistic opportunity between the
telecommunications and electric industries is one of several reasons HVDC interties can help
surmount the economic barriers facing Alaska’s rural communities.
Comparative analysis of HVDC transmission systems with conventional AC systems indicates
significant technical and economic advantages of HVDC systems. In many rural Alaska applications,
the use of HVDC systems will significantly lower intertie costs.
Based on the favorable findings, Polarconsult recommends continued work on this project through
Phase III work activities, including demonstration of the HVDC system on an Alaska utility system.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE 2
1.1 REPORT ORGANIZATION
Phase II of this project addresses a wide range of technical disciplines and subject material. For
brevity, the body of this report focuses on the key findings and conclusions that have resulted from
this work. In‐depth information pertaining to specific topics is included in the report’s appendices.
This report is organized as follows:
● The Executive Summary and the Acronyms and Definitions sections are included at the
beginning.
● Section 1.0 introduces the report.
● Section 2.0 provides background information on Alaska’s rural energy issues and a brief
explanation of the stakeholders’ roles in this phase of the project.
● Section 3.0 is a description of the HVDC transmission system, which includes a comparison
of AC and HVDC transmission, overhead intertie alternatives, and submarine cable intertie
alternatives.
● Section 4.0 discusses HVDC converter stations.
● Section 5.0 evaluates the design concepts for overhead interties.
● Section 6.0 contains the economic evaluation of Phase II.
● Section 7.0 provides the conclusions and recommendations for the Phase II prototyping and
testing study.
In addition, this report contains the following appendices, which include reports generated by
Polarconsult’s subcontractors for this project as attachments:
● Appendix A HVDC Overview
● Appendix B Economic Analysis
● Appendix C Conceptual Design of Overhead HVDC Intertie Lines
● Appendix D Conceptual Design for Submarine Cables
● Appendix E SWER Circuits and HVDC System Grounding
● Appendix F HVDC Power Converter Development
● Appendix G HVDC System Protection, Controls, and Communications
● Appendix H Candidate HVDC System Demonstration Projects
● Appendix I Stakeholder Advisory Group Involvement and Meetings
● Appendix J Bibliography
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE 3
1.2 ACKNOWLEDGEMENTS
Polarconsult acknowledges and appreciates the support and contributions of the many individuals
and entities that have participated in this project. Their support, insights, experience, and technical
analysis remain invaluable to the continuing effort to bring lower‐cost HVDC intertie systems to
Alaskans.
Members of the team involved in the second phase of HVDC intertie development include:
● Denali Commission (Funding Agency)
● ACEP (Grant Management, Economic Analysis, Strategy)
● Polarconsult (Project Management, Strategic Vision, Design)
● Princeton Power Systems, Inc. (PPS) (Converter Development)
● University of Alaska Fairbanks (UAF)/Dr. Richard Wies (UAF Quality Control and Technical
Review)
● Alaska Village Electric Cooperative, Inc. (AVEC) (Alaska Integration/Practicality)
● Stakeholders Advisory Group (Practicality/Industry Acceptance)
● Manitoba HVDC Research Centre (HVDC Expert)
● Line Design Engineering (Structural and Code Expert)
● Golder Associates (Geotechnical Expert)
● Almita, Inc. (Foundation Supplier)
● Arctic Foundations, Inc. (AFI) (Foundation Supplier)
● Zarling Aero Consulting (ZAE) (Thermal Soils Analysis)
● STG, Inc. (Rural Intertie Contractor)
● Cabletricity, Inc. (Submarine Cable/HVDC Expert)
In addition, the Stakeholders Advisory Group (SAG) members have played an instrumental role in
this program by contributing their time and years of experience. The SAG was chaired by the Denali
Commission and facilitated by ACEP. SAG members include:
● Alaska Department of Labor (AKDOL)
● Alaska Energy Authority (AEA)
● Alaska Power & Telephone Company (AP&T)
● Alaska Power Association (APA)
● AVEC
● Bering Straits Native Corporation (BSNC)
● Bethel Electric Utility (BEC)
● Copper Valley Electric Association, Inc. (CVEA)
● Golden Valley Electric Association, Inc. (GVEA)
● Homer Electric Association, Inc. (HEA)
● Inside Passage Electric Cooperative (IPEC)
● Institute of Northern Engineering (INE), UAF
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
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● Kodiak Electric Association, Inc. (KEA)
● Kotzebue Electric Association, Inc. (KoEA)
● Matanuska Electric Association (MEA)
● Naknek Electric Association, Inc. (NEA)
● National Rural Electric Cooperative Association (NRECA)
● Nome Chamber of Commerce (NCC)
● Nome Joint Utility Service (NJUS)
● North Slope Borough (NSB)
● Northwest Arctic Borough (NWAB)
● Nushagak Electric Association
● Nuvista Light and Power, Inc. (NLP)
● Southeast Conference (SEC)
● Southwest Alaska Municipal Conference (SWAMC)
● U.S. Department of Agriculture (USDA) Rural Utilities Service (RUS)
● UAF
1.3 DISCLAIMER
This report was prepared by Polarconsult solely for the UAF. The UAF has the right to reproduce,
use, and rely upon this report for purposes related to investigating the “HVDC Transmission System
for Rural Alaskan Applications,” including, without limitation, the right to deliver this report to
regulatory authorities in support of, or in response to, regulatory inquiries and proceedings. For the
purposes of this Disclaimer, all parties other than Polarconsult and the UAF are “third parties.”
Neither Polarconsult nor the UAF represent, guarantee, or warrant to any third party, expressly or
by implication, the accuracy, suitability, reliability, completeness, relevance, usefulness, timeliness,
fitness, or availability of this report for any purpose or the intellectual or other property rights of
any person or party in this report.
Third parties shall not use any information, product, or process disclosed, described, or
recommended in this report and shall not rely upon any information, statement, or
recommendation contained in this report. Should any third party use or rely upon any
information, statement, recommendation, product, or process disclosed, contained, described, or
recommended in this report, they do so entirely at their own risk. To the maximum extent
permitted by applicable law, in no event shall Polarconsult or the UAF accept any liability of any
kind arising in any way out of the use or reliance by any third party upon any information,
statement, recommendation, product, or process disclosed, contained, described, or
recommended in this report.
1.4 COPYRIGHT NOTICE
This report is copyright protected by Polarconsult and may not be reproduced in whole or part
without the prior written consent of Polarconsult.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE 5
2.0 BACKGROUND
Energy costs throughout most of rural1 Alaska are significantly higher than in the state’s urban
areas. Over the past decade, rural energy costs have escalated dramatically, to the point where life
in many rural Alaskan communities is in a state of economic peril. The primary reasons for these
high energy costs is rural Alaska’s dependence on diesel fuel for power generation and heating, the
lack of economies of scale in rural communities, and the transportation challenges common in rural
Alaska.
For most rural Alaskan communities, a diesel‐electric plant is the power generation resource of
choice since these plants and their supporting infrastructure such as bulk fuel facilities are readily
adapted to the needs of rural localities. However, generating electricity with diesel fuel is expensive
due to these communities’ small scale and geographic isolation. Consequently, rural Alaska has
significantly higher energy costs compared to communities in or connected with Alaska’s urban
centers. The high cost of rural energy negatively affect both the quality and sustainability of life in
rural Alaska.
Many power generation costs are beyond a community’s control. The fuel price for these plants is
determined by an increasingly volatile global energy market. In addition, a substantial component
of the fuel cost is transportation. In recent years, the limited shipping and delivery windows caused
by seasonal ice and low water conditions in many parts of the state have resulted in villages paying
record prices for fuel. Interior communities, located near the upper limits of navigable waterways
and thus susceptible to low water conditions, paid as much as $11 per gallon in 2010 (DCRA, 2010).
Several rural communities frequently fly in fuel due to a lack of reliable barge access or service.
Alternatives to diesel generation often exist in the form of local energy resources such as hydro,
wind, geothermal, tidal, solar, gas, coal, and biomass. However, many of these “stranded energy
resources” are not economically viable due to the cost of the conventional AC electric transmission
systems required to interconnect them and the prohibitively high cost to develop these local energy
resources to serve small loads. HVDC interties can help surmount both of these barriers by
lowering the cost to reach stranded energy resources and by reducing the cost to interconnect
communities (ACEP, 2012).
Although commercial HVDC transmission technology has been available for over 50 years, it has
been limited to large‐scale transmission of tens to thousands of MWs of power. These systems are
far too large and expensive to use for the interconnection of Alaska’s rural communities, which
typically have loads measured in the hundreds to thousands of kilowatts (kWs). Currently, no
commercially available HVDC converter system exists that is suitable for interconnecting these
rural communities. However, innovative technologies in the power electronics industry have made
the development of low‐power, cost‐effective converters feasible.
Polarconsult has investigated alternatives to AC interties and found that in many applications,
HVDC transmission systems using innovative power conversion technologies offer the most
economical solution to interconnect with stranded energy resources. Further, the replacement of a
conventional overhead AC three‐ or four‐wire transmission line with a one‐ or two‐wire HVDC
1 Rural Alaska for the purposes of this report refers to isolated communities off the main road system that have high
energy costs due to their location, size, or other factors.
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transmission line has significant cost advantages. The change in overhead infrastructure results in
reduced structural loads, allowing fewer support structures per mile of transmission line. The
decrease in materials and construction time is one of several reasons that overhead HVDC interties
are less costly than AC interties. Submarine and buried HVDC interties can also be less costly than
their AC alternatives.
2.1 PROGRAM OVERVIEW
The HVDC development effort consists of the following phases:
Phase I – Preliminary Design and Feasibility Analysis (2008‐2009)
During Phase I, Polarconsult evaluated the technical and economic feasibility of the proposed
HVDC system. Tasks included defining the HVDC system’s preliminary design parameters,
defining design considerations for the transmission and converter components, and estimating
costs for these systems. Phase I also included limited prototyping and successful testing of the
converter technology.
Phase II – Prototyping and Testing (2010‐2012)
Phase II included construction and testing of full‐scale prototypes of the transmission and
converter systems. This effort validated the design of these systems and validated the feasibility
of the construction methods necessary to make the system a success in rural Alaska
applications. The information from Phase II testing was used to refine the construction methods
and develop cost estimates used in the economic analysis of the technology described in this
report. This report is the final deliverable for Phase II.
Phase III – Demonstration Project (Proposed)
Phase III will include full testing of the converter system, including the manufacturer and third‐
party functional, compliance, and performance testing needed to move the converter
technology from advanced prototypes to a commercial product. Phase III will also include a full‐
scale field demonstration of the HVDC technology on a utility system in Alaska. The specific
project details are dependant on the candidate location selected for the intertie. Phase III is
intended to be the final proof‐of‐concept project, to be followed by commercial deployment of
the system.
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE 7
2.2 STAKEHOLDER ADVICE
This project seeks to develop a highly innovative power transmission technology for deployment in
rural Alaska applications. Because many aspects of this system mark a departure from accepted
practice in rural power systems, widespread industry understanding, as well as acceptance, of this
technology is considered critical to the success of this effort. Additionally, the overview and
feedback of industry is considered critical to the successful development of the innovative systems
needed for this HVDC technology.
The Denali Commission and ACEP recognized that the best means to achieve this understanding,
acceptance, and feedback would be to directly engage the stakeholders and end‐users of the
proposed system in the development stages of the technology. To this end, a SAG was formed as
part of the Phase II effort to familiarize and facilitate feedback from industry leaders on the
development of this system.
The SAG is an advisory body comprised of representatives of Alaska’s rural electric utility industry
and related professionals. The purpose of the SAG is to provide comments, feedback, review, and
recommendations to the HVDC project. The SAG held the following three meetings over the course
of the project:
● SAG Meeting # 1 – Fairbanks, Alaska ‐‐ April 27, 2010;
● SAG Meeting # 2 – Anchorage, Alaska – January 14, 2011; and
● SAG Meeting # 3 – Anchorage, Alaska – October 25, 2011.
Several additional outreach activities occurred over the course of the project. These included:
● Southeast Conference Mid‐Session Summit – Juneau, Alaska (March 2, 2010);
● Emerging Energy Technology Forum – Juneau, Alaska (February 14, 2011);
● Brown‐Bag Work Session – Anchorage, Alaska (August 29, 2011); and
● HVDC Converter Demonstration – Lawrenceville, New Jersey (November 14, 2011).
Appendix I provides the following detailed information regarding SAG meetings and discussions:
● List of SAG members;
● Summary of SAG role and policies;
● Summary of key informal correspondence between SAG members and Polarconsult over the
course of the project;
● Handouts from the three SAG meetings; and
● Handouts from other meetings and outreach activities conducted over the course of the
project.
Additional details associated with the SAG meetings and proceedings are presented in Appendix I.
Transcripts of the SAG meetings are available upon request.
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE 8
3.0 HVDC TRANSMISSION SYSTEM DESCRIPTION
HVDC transmission systems can take on a wide variety of configurations. This section describes
those configurations relevant to low‐power HVDC applications in rural Alaska applications.
● Section 3.1 provides a general overview of the history of HVDC power transmission and the
major components of an HVDC transmission system.
● Section 3.2 provides a general overview of the different configurations of HVDC systems for
power transmission applications.
● Section 3.3 provides a comparison of HVDC and AC power transmission alternatives.
● Section 3.4 provides a description of overhead line alternatives for AC and HVDC
applications.
● Section 3.5 provides a description of submarine cable line alternatives for AC and HVDC
applications.
3.1 HVDC BACKGROUND
Thomas Edison pioneered the first utility‐scale application of electric power in New York City in the
1880s with a direct current (DC) electric utility system. Concurrently, George Westinghouse was
marketing an AC electric utility system invented by Nikola Tesla. AC was better suited to stepping
up voltages, which is vital to economical electric transmission across town and between cities. By
the 1890s, Westinghouse’s AC system had prevailed over Edison's DC system, and AC became the
industry standard.
In the 1950s, technological advances enabled DC systems to reenter the electric utility industry.
With the commercialization of the mercury arc‐valve, voltage transformation of DC and conversion
between DC and AC electricity on a large scale became cost‐effective. This allowed utilities to begin
using HVDC transmission links in their systems.
Because of the high capital cost of these early HVDC converters, utility usage of HVDC remained
limited to transmission functions. AC remained the industry standard for electricity generation,
distribution, and consumption.
Today, HVDC converter technology has advanced to use high efficiency solid‐state hardware, and
HVDC links are used for electrical transmission throughout the world. The smallest available utility‐
grade HVDC systems are designed to transmit approximately 50 MW 2. As a result, the current
commercially available HVDC converters are oversized and prohibitively expensive for Alaskan
interties that typically require the transfer of less than 1 MW. Figure 3‐1 is an image of a large
HVDC station.
2 “HVDC Lite,” distributed by ABB, is one example of the smaller utility‐grade HVDC systems.
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HVDC transmission systems include the following major components:
● HVDC Converter Stations. Each connection point between the HVDC transmission line and
a load center requires an HVDC converter station. The converter station converts the HVDC
electricity into AC electricity that can be moved through a local power grid and used. The
converter station includes the power converters, grounding stations, communications and
control systems, and protective equipment as required by the particular system design
requirements. The power converters are discussed in Appendix F. The grounding stations
are discussed in Appendix E.
● HVDC Transmission Line. The HVDC transmission line is the overhead wire, submarine
cable, underground cable, or combination of these that connects the converter stations
together and forms the transmission circuit. The configuration and design of the
transmission line will depend on local conditions and system requirements. Overhead
transmission line concepts are discussed in Appendix C. Submarine cable transmission line
concepts are discussed in Appendix D.
● Controls and Communications. The HVDC transmission system requires a means of
communicating between the converter stations and the control the system. The simplest
control and communication scheme would use the DC line voltage as a control signal. This
would be suitable for a point‐to‐point HVDC system that feeds power in one direction.
Power reversal over the intertie would be possible with manual intervention. Control and
communication options for HVDC systems are discussed in Appendix G.
Figure 3-1 Typical Large HVDC Station
5,000 MW +/‐ 800 kV HVDC Yunnan‐Guangdong Converter Station. (TDW, 2012)
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE 10
3.2 HVDC SYSTEM CONFIGURATIONS
The various system configurations for HVDC can be classified into three different categories, with
several options within each category. The three categories and major options are shown below.
Each category is described in more detail in the following sections.
Types of HVDC Utility Power Systems
HVDC Application ‐ How the HVDC technology is used:
● Point‐to‐Point DC Power Transmission
● Multiterminal Direct Current (MTDC) Power Transmission
HVDC Circuit ‐ How the electricity is transported:
● Monopolar with Single‐Wire Earth Return (SWER)
● Monopolar with Metallic Return
● Bipolar
Intertie Type ‐ How the wires transporting the electricity are configured:
● Overhead
● Submarine
● Underground
3.2.1 HVDC System Applications
There are three basic applications of HVDC technology in today’s electric utility industry. These are:
● Point‐to‐point power transmission. The majority of HVDC systems in use today are point‐
to‐point transmission systems. These transport bulk energy (100s or 1,000s of MWs) over
long distances (100s or 1,000s of miles) more efficiently than AC transmission systems.
Point‐to‐point networks will be a significant application for the low‐power HVDC
technology being developed with this project.
● Multiterminal power transmission. MTDC networks are a more flexible and complicated
application of HVDC transmission technology. Instead of the two terminals in a conventional
point‐to‐point HVDC system, MTDC systems have more than two terminals and can route
power to or from these terminals as needed. MTDC systems are currently receiving
significant industry interest as technology evolves to handle these more complicated
systems and regional grids demand the superior performance and enhanced capabilities
that MTDC systems offer over AC transmission networks for certain applications. There are
a handful of large‐scale MTDC systems planned or in operation. Examples include the
Quebec – New England MTDC system and the Sardinia – Corsica – Italy MTDC system.
Many regional energy solutions in rural Alaska using HVDC will be in the form of MTDC
networks. The power converters developed for this project can support MTDC operation,
provided suitable control systems and protective equipment are present. MTDC systems
and control considerations are discussed in greater detail in Appendix G.
At the most abstract level, an electrical circuit requires two current pathways, normally metal
wires. One wire goes from the power supply to the load, and a second wire goes from the load back
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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INCREASING COST
AND COMPLEXITY
1. Monopolar with earth return (SWER)
2. Monopolar with return conductor
3. Bipolar
to the power supply. Both single‐phase AC and DC circuits rely on this basic configuration. The wire
from the power supply to the load is usually at an increased voltage relative to ground, and so it is
insulated for safety and to prevent short circuits. The wire from the load back to the power supply
is usually at a much lower voltage relative to ground and is usually, but not always, insulated.
There are three types of HVDC circuits in use around the world. Each of these circuits may utilize
overhead wires, underground cables, submarine cables, or a combination of these. These three
circuits are listed on Figure 3‐2 and described on the following pages.
Figure 3-2 Three Types of Interties Used in HVDC Systems
More complex HVDC circuit configurations normally incorporate elements of the simpler circuits
for efficiency, reliability, redundancy, and/or safety. For example, all bipolar HVDC systems include
earth electrodes and sometimes a ground conductor so they can operate either pole in monopolar
or monopolar SWER mode during maintenance or emergencies.
Generally, the more complex bipolar circuit configurations are used for large, important interties
where the increased reliability, efficiency, and power throughput capability justify the higher cost
of these systems.
3.2.1.1 Single Wire Earth Return (SWER) Circuits
SWER circuits use the subsurface geology as a return current pathway. Sea return circuits are
similar to earth return circuits. The only difference is that the sea, or any water body, is used as the
predominant return current pathway. Parallel pathways, such as the seabed, are also available for
current flow. The primary advantages offered by SWER circuits include:
● Lower costs (eliminate the second conductor).
● Higher efficiency (lower electrical losses).
The primary concerns associated with SWER circuits include:
● Avoiding accelerated “induced current” corrosion of buried metallic objects.
● As with all electrical systems, safety.
SWER circuits are widely used for utility transmission and distribution of electricity all over the
world. Numerous HVDC interties are SWER circuits, consisting of a single high‐voltage cable and an
earth or sea return to complete the transmission circuit. Many of these are installed in climates and
conditions similar to Alaska, notably in Scandinavia. In many nations, single‐phase AC SWER
circuits are accepted practice and are industry standard for serving rural areas.
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Two single‐phase AC SWER circuits have been successfully built and operated in Alaska. These AC
SWER circuits demonstrate that SWER is a proven, beneficial, and appropriate technology for rural
Alaska transmission applications.
3.2.1.2 Monopolar HVDC Circuit Using SWER
A monopolar HVDC intertie using SWER (see Figure 3‐3) for the return pathway will generally be
the lowest‐cost alternative for HVDC power transmission in rural Alaska applications. This circuit
configuration will consist of the following major components:
● AC/DC converter module in the generating village.
● High‐voltage conductor. This can be an overhead line, buried cable, or submarine cable.
● DC/AC converter in the receiving village.
● Grounding electrodes in both villages to complete the intertie circuit using earth return.
Figure 3-3 Monopolar HVDC Intertie Using SWER
There are numerous examples of monopolar HVDC interties using SWER circuits. The 500‐MW
submarine HVDC link completed between Victoria and Tasmania, Australia, in 2006 is one example
of a recently constructed SWER HVDC system. Bipolar and monopolar HVDC circuits are normally
designed to operate in a monopolar SWER configuration when needed to maximize system
reliability.
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3.2.1.3 Monopolar HVDC Circuit with Return Conductor
A monopolar HVDC intertie with a return conductor (see Figure 3‐4) is similar to a monopolar
SWER HVDC intertie. The primary difference is that the earth return is replaced with a dedicated
return conductor to minimize earth currents induced by the intertie. Often, such interties will still
have the earth electrodes necessary to operate in SWER mode and will operate in SWER mode
during maintenance or emergency situations. This HVDC circuit configuration includes the
following major components:
● AC/DC converter module in the generating village.
● High‐voltage conductor. This can be an overhead line, buried cable, or submarine cable.
● DC/AC converter in the receiving village.
● Return conductor. This can be an under‐built line on the high‐voltage poles, a separate
cable, or incorporated into the same cable as the high‐voltage conductor, such as a
concentric neutral on an AC cable.
● Grounding electrodes in both villages. These will not normally be used to complete the
intertie circuit, but they will be used during maintenance or emergencies.
Monopolar return conductors are warranted in areas where a SWER circuit is not viable or
desirable. Generally, this is due to the risk of inducing corrosion in buried metallic utilities. The lack
of suitable ground conditions for economical earth electrodes would also warrant use of a return
conductor. Using an return conductor with the same electrical resistance as the high‐voltage
conductor will nearly double the conductor losses relative to a SWER transmission circuit.
Figure 3-4 Monopolar HVDC Intertie with Return Conductor (SWER-capable for Backup)
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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MAY 2012 PAGE 14
3.2.1.4 Bipolar HVDC Circuit
A bipolar HVDC intertie (see Figure 3‐5) is generally the most costly and most reliable HVDC circuit
configuration. It employs two parallel high‐voltage conductors, one operated at positive voltage and
the second at negative voltage. The system requires two converters at each end of the intertie (four
total), compared to one converter per end for monopolar circuits (two total). Thus, the bipolar
HVDC configuration includes these major components:
● Two AC/DC converter modules in the generating village. One (+) and one (–).
● Two high‐voltage conductors. These could be overhead lines, buried cables, or submarine
cables.
● A third neutral conductor to carry any current due to minor imbalance between the power
transmission levels on the positive and negative poles. Some bipolar systems do not have a
neutral conductor and instead rely on the grounding electrodes to balance the poles.
● Two DC/AC converters in the receiving village. One (+) and one (–).
● Grounding electrodes in both villages. These will not normally be used to complete the
intertie circuit, but they will be used to balance the system and for SWER operation during
maintenance or emergencies.
The additional costs of a bipolar HVDC intertie are largely due to the additional converters and the
second high‐voltage conductor. A bipolar HVDC intertie will be roughly twice as costly as a
monopolar HVDC intertie, but with twice the capacity and increased reliability.
The principal advantage of a bipolar intertie compared to a monopolar intertie is increased
reliability. If something breaks on one of the two poles, the other pole can be operated as a
monopolar intertie. This will reduce the power transfer capability, but the intertie can continue to
function.
For many rural Alaska applications, the additional cost of bipolar circuits is not justified. Operating
backup diesel generators in villages would be more cost‐effective than constructing a bipolar HVDC
intertie.
Figure 3-5 Bipolar HVDC Intertie (SWER-capable for Backup)
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3.2.2 HVDC Intertie Types
HVDC interties can be built using overhead wires, submarine cables, or underground cables.
Combinations of these can be used for a single intertie. Overhead wire intertie options are
discussed in Section 3.4 and Appendix C. Submarine cable intertie options are discussed in Section
3.5 and Appendix D. Underground cable options are discussed in Appendix G.
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3.3 COMPARISON OF AC TO HVDC TRANSMISSION
The following abbreviated comparison is presented to illustrate when an HVDC intertie is
anticipated to be a good alternative to a comparable AC intertie in rural Alaska applications. A more
detailed comparison is presented in Appendices A and B.
HVDC Advantages:
● Lower per‐mile overhead transmission line cost than AC lines;
● Ability to use underground or submarine cables for long distances;
● Better compatibility with migratory birds due to fewer overhead conductors (1 or 2 wires
instead of 3 or 4 wires);
● Asynchronous connection; and
● Lower per‐mile conductor energy losses.
HVDC Disadvantages:
● An HVDC converter is more expensive, requires more maintenance, and is less reliable than
a comparable AC transformer;
● Converter costs are a barrier to serving loads along the transmission line route;
● Unconventional technology and limited equipment suppliers compared to AC;
● HVDC converters generally have higher energy losses than a comparable AC transformer;
and
● HVDC interties may have fewer funding opportunities than conventional AC lines because
they are uncommon.
Implications:
● If an intertie must employ long‐distance submarine or buried cables, HVDC offers a
technically superior solution to AC. AC cable interties are not technically feasible for long‐
distance transmission systems.
● Where both systems are technically feasible, the decision is largely economic. An HVDC
intertie will have higher terminal costs and lower per‐mile costs. Accordingly, an AC intertie
is more cost‐effective for short interties, and HVDC is more cost‐effective for long interties.
The longer the intertie, the greater the cost savings of an HVDC versus AC system. The
economic crossover point is project specific but for the scale of interties under
consideration in this report, it will generally occur at a distance of 6 and 31 miles.
● Since the HVDC converters developed under this program use new technology, and because
it represents a departure from conventional AC transmission systems, substantial savings
will be a factor in encouraging utilities to adopt this technology in lieu of proven but more
costly intertie solutions.
● Most AC interties are overhead and may not be environmentally acceptable in many parts of
Alaska. HVDC interties are either buried or have fewer wires and structures and may be
more acceptable within refuges and other sensitive areas.
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3.4 OVERHEAD INTERTIE ALTERNATIVES
3.4.1 Conventional AC Interties
The typical cost for constructing a conventional overhead distribution‐class AC intertie in rural
Alaska can range from as little as $100,000 per mile in areas with good logistic support and
transportation infrastructure (road system, southeast) to over $600,000 per mile3 in rural parts of
the state with challenging logistics and little or no transportation infrastructure (remote interior,
northwest, or Yukon‐Kuskokwim delta regions). Because of this prohibitive expense, relatively few
rural interties have been built.
The high cost of rural overhead AC interties is the result of several factors. Two significant cost
contributors common to many Alaskan intertie projects are logistics and foundations. AC systems
rely on multi‐wire transmission lines; this leads to high materials costs and high loads placed on
structures and foundations. The structures needed to support the multiple aerial wires of an AC
system are costly. The resulting AC intertie usually has short spans, 250 to 400 feet being typical,
thus resulting in many transmission components such as poles, hardware, wire, and foundations
that must be purchased, shipped, installed, and maintained.
When the costs of shipping, geotechnical conditions, construction factors, logistics and
environmental requirements are all factored in, conventional AC construction often results in a
prohibitively expensive intertie. As a result, many rural communities are denied the opportunity to
benefit from interconnection to each other or local energy resources.
3.4.2 HVDC Transmission Interties
Polarconsult has investigated alternatives to AC interties and found that in many applications,
HVDC transmission systems offer the most economical solution.
Replacing a conventional overhead AC three‐ or four‐wire transmission line with a one‐ or two‐wire
HVDC transmission line has significant cost advantages. The change in overhead infrastructure
results in reduced structural loads thus allowing fewer support structures per mile of transmission
line. The decrease in materials and construction time is the primary reason overhead HVDC
interties are more economically viable than AC interties.
A monopolar HVDC intertie designed as a SWER circuit needs only a single wire aloft, which
significantly reduces the loads compared with a three‐ or four‐wire AC intertie. Using a single wire
profoundly simplifies the transmission line design, which translates to significant cost savings
compared with an AC line.
Because SWER circuits induce a return current in the earth, they require special attention in the
design and planning phase to avoid adverse effects from this earth current. The primary concerns
are (1) the step potential4 in the immediate vicinity of the grounding stations and (2) accelerated
corrosion of buried metallic objects in the vicinity of the return current pathways through the earth.
3 See Section B.6.1 in Appendix B for cost basis information.
4 A voltage gradient that occurs at the ground surface due to earth return currents. If the voltage gradient is high enough,
it can pose a hazard to people or wildlife stepping in the vicinity.
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In most rural Alaska localities, these concerns can be readily addressed through proper planning
and system design.
Because of these special factors, SWER circuits are not allowed by the National Electrical Safety
Code (NESC), which is the applicable code for electric utility transmission and distribution systems.
Polarconsult has discussed this HVDC system and concept in detail with the state code authority
and finds that SWER circuits can be approved on a project‐specific basis by issuance of a code
waiver. There is precedent for code waivers being issued for SWER systems in Alaska. The use of
SWER circuits is discussed further in Appendix E of this report.
As an alternative to using an earth return circuit, two‐wire monopolar HVDC lines (using an
overhead wire as the return circuit) also achieve a cost savings relative to AC interties although the
savings will typically be less than for an HVDC SWER transmission line.
Bipolar HVDC interties require the use of two additional converters but can transfer twice the
energy of a comparable monopolar system. In the event of a converter failure or loss of a conductor,
a bipolar system can be configured to operate as a monopolar SWER or monopolar two‐wire
system. This offers significant reliability advantages; however, it also incurs the cost of the
additional converters and second high‐voltage conductor. The advantages of the increase in
capacity and reliability are the primary reasons for use of bipolar systems.
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3.5 SUBMARINE CABLE INTERTIE ALTERNATIVES
Another advantage of HVDC transmission over AC is its intrinsic ability to carry energy by buried or
submarine cable over long distances without the technical limitations and additional equipment
required for similar transmission by AC. Monopolar HVDC using a single cable can connect villages
separated by lakes, bays, fjords, or lands where overhead transmission is not practical, cost‐
effective, or desirable. For this reason, low‐power HVDC technology has significant implications for
interconnecting communities in Alaska separated by water bodies, particularly in the southeast.
Cabletricity was retained by Polarconsult as a subconsultant to investigate submarine cables
optimized for use with this HVDC system. Appendix D includes the Cabletricity report detailing
results of their investigations.
The report begins with a description of the electrical system to which the cables will be connected,
and then advances to the regional environment they must withstand and on to descriptions of
submarine cable standards, cable designs, typical installation methods, and cost estimates for a case
study.
Cabletricity evaluated submarine cables suitable for 1‐MW monopolar HVDC interties at 50
kilovolts (kV), with potential upgrade of the converter stations to 5‐MW service in a monopolar
circuit. Cabletricity also evaluated the feasibility and cost of integrating optical fibers into the
power transmission system to serve the communications needs of rural communities. To make this
system practical, simplicity and reliability are critical design considerations.
Cabletricity’s investigations focused on single core insulated conductor submarine cables with
earth or sea return that would be generally suitable for the rugged and deep inter‐island and fjord
crossings typical of southeast Alaska. The objective is to identify suitable conventional or
innovative submarine cable designs to meet the overall project objectives where water crossings
are required.
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4.0 HVDC CONVERTER STATIONS
4.1 OVERVIEW
The HVDC converter stations will include the major components listed below:
● HVDC power converters such as those being developed by PPS;
● Converter enclosures, which may consist of dedicated enclosures or use of an existing
building, such as an existing power plant;
● Protection, control, and switching equipment on the AC and HVDC sides of the converters;
● AC transformers, depending on the AC interface voltage and wiring; and
● Grounding stations, including the ground conductor from the converter station to the
grounding station.
4.2 CONVERTER DEVELOPMENT OVERVIEW
Polarconsult subcontracted with PPS for the development of the HVDC power converters. PPS was
tasked with the development of one full‐scale and full‐functionality 1‐MW power converter,
consisting of two 500‐kilowatt (kW) modules. Development work included preparation of
specifications, design, construction, and testing of the prototype converter.
The HVDC converter is a 1‐MW power converter capable of bidirectional power conversion
between three‐phase 480 volts alternating current (VAC) and 50 kV HVDC. The converter capacity
is appropriate to supply the electrical needs of most Alaska villages economically. In contrast,
existing HVDC power converter systems are only available at much larger transmission capacities,
starting at approximately 50 MW and extending up to 1,000s of MWs of capacity.
Each 500‐kW PPS converter consists of two modules: an air‐cooled low‐voltage cabinet (Figure 4‐
1), and an oil cooled high‐voltage tank (Figure 4‐2). AC power cables connect to the low‐voltage
cabinet, which conditions the power and transforms it to a special high‐frequency AC, which is
transmitted to the high‐voltage tank via power cable. The high‐voltage tank transforms the high‐
frequency AC to 50 kV DC. The high‐voltage tank has two bushings that output up to 500 kW at 50
kV DC. Either bushing can be grounded to produce a positive 50‐kV HVDC output or a negative 50‐
kV HVDC output.
Multiple PPS HVDC converters can be “paralleled” to achieve higher power transmission capacities
where needed. Based on Phase II development work, the price of a commercially produced 1‐MW
HVDC power converter is estimated to be $250,000. At least two 1‐MW converters are needed for a
complete 1‐MW HVDC transmission system.
PPS has successfully demonstrated operation and power flow at the full 50 kV DC in both inverter
(HVDC to AC) mode and rectifier (AC to HVDC) mode in a controlled test facility setting. These
testing efforts validate the design and basic functionality of the converter.
In the course of testing, PPS identified two hardware problems that prevented full‐power testing of
the prototype converters. PPS has investigated these problems and identified the actions necessary
to correct both problems. The problems and solutions are discussed in Appendix F.
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The following figures illustrate the converter features:
o Figures 4‐1 and 4‐2 show the two basic modules that make up a complete 500‐kW
converter system. These are further discussed in Appendix F.
o Figure 4‐3 shows the test setup for testing of the central resonant link circuit in the
high‐voltage DC transformer.
o Figure 4‐4 shows the in‐air high potential (hi‐pot) test setup of the high‐voltage DC
transformer assembly. This test identified some insulation defects that were
corrected. The test demonstrated that the DC transformer assembly will withstand
the voltages experienced at full operating voltage of 50 kV DC.
o Figure 4‐5 shows the dry system test setup and schematic. Before the DC
transformer was immersed in oil, it was tested at low voltage in air to validate
function and facilitate troubleshooting. This was primarily done for convenience, to
avoid the delays and mess associated with repeatedly immersing the DC
transformer in oil and removing it.
o Figure 4‐6 shows a complete 500‐kW converter module, consisting of the HVDC
tank and the low‐voltage alternating current (LVAC) cabinet.
o Figure 4‐7 shows four high‐voltage measurement probes used to monitor the
voltages at different points in the DC transformer. The test showed excellent voltage
sharing between the DC transformer stages, indicating that the system is performing
in accordance with design. Uniform voltage sharing is a key success, as it means the
power electronics components will not be subjected to uneven voltages stresses.
Excessive voltage stresses could severely shorten the life of the components,
reducing the reliability of the converter.
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Figure 4-1 Low Voltage Alternating Current (LVAC) Enclosure: Mechanical Layout
Notes:
Cabinet size: 66”W x 42”D x 66”H;
Cabinet weight: Approximately 2,200 pounds.
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Figure 4-2 HVDC Transformer Tank: Mechanical Layout
Notes:
Tank size: 88”W x 39”D x 59.25”H;
Tank weight with oil: 4,200 pounds.
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Figure 4-3 Central Resonant Link Test Setup
Figure 4-4 Hi–Pot Test Setup for HVDC Transformer
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Figure 4-5 Dry System Inverter Mode Test Schematic and Setup
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Figure 4-6 System #1 HV Tank and LV Enclosure
Figure 4-7 System #1 Showing HV Measurement Probes
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4.3 ADDITIONAL EQUIPMENT
4.3.1 Converter Enclosure
While the converter specifications permit the converters to be installed outdoors in most Alaska
environments, it is assumed that the converters will be installed inside an enclosure. This will
provide for a controlled operating environment and greater security for the converters, extending
their useful service life.
The conceptual design assumes that a modular, prefabricated enclosure will be sent to the
community with the two 500‐kW power converter units already installed. This converter module
will then be set in place on a suitable foundation.
In communities that will be primarily served by an HVDC intertie, it may be appropriate to locate
the converters inside the existing powerhouse or other suitable existing structure. This would have
the following advantages:
● The existing powerhouse may already have a suitable step‐down transformer sized for the
full community load;
● Waste heat from the converters would provide all or part of the heat for the power plant
building; and
● Achieves project cost reduction by eliminating the need for a dedicated converter enclosure
and purchasing or leasing land to site the converter.
4.3.2 Protection and Switchyard Equipment
Switchgear will be needed on the AC side of the converters to isolate and protect the converter from
the AC grid and to monitor power flow between the converter and the grid.
Similar isolation, protection, and monitoring equipment is needed on the HVDC side of the
converter. At a minimum, manual disconnect switches (nonload break), surge arrestors, and
protective fuses are needed on the HVDC side. More automated control apparatus can also be used,
but at increased cost.
4.3.3 AC Transformers
The grid interface on the power converters is three‐phase 480‐volt AC. In communities where the
converter is connected directly to the 480‐volt power plant bus, no transformer is required. In
communities where the converter connects to the local distribution grid, a step‐up transformer is
required. The transformer will typically be a three‐phase 480/12.47‐kV transformer.
4.3.4 Grounding Stations
A grounding station will need to be provided at each HVDC converter station, regardless of the
HVDC circuit configuration. The conceptual design of a 1‐MW, 50‐kV DC grounding station is
presented in Appendix E (Figure E‐1).
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5.0 DESIGN CONCEPTS FOR OVERHEAD INTERTIES
The following summarizes design criteria developed for the conceptual design of the HVDC
overhead intertie lines. Design criteria and conceptual designs are presented in detail in Appendix
C.
5.1 OVERHEAD DESIGN APPROACH
The overhead intertie design concepts presented required consideration of typical site conditions,
codes, utility and lender requirements, construction methodologies, standard design practices, and
project economics. The following two design approaches for overhead HVDC interties have been
evaluated, each with a capacity to supply 1 MW through a monopolar 50‐kV DC system:
5.1.1 RUS Design Approach, Modified for HVDC Interties
The first conceptual design approach is based on the use of structures that are constructed in
accordance with USDA RUS‐type construction (RUS standard practice) for conventional 12.4/24.9‐
kV AC distribution lines. 5 These RUS standard practices are currently used to develop AC interties
throughout Alaska and are widely accepted by the utility industry. HVDC transmission requires
fewer conductors than AC, resulting in reduced loads on the supporting structures. As a result, the
conceptual designs developed using the RUS approach have longer ruling spans than typical AC
lines. This results in fewer transmission structures for the HVDC intertie and an associated
comparative reduction in construction cost.
5.1.2 Alaska‐Specific Design Approach for HVDC Interties
The second conceptual design approach takes the logistic and technical challenges of construction
in rural Alaska into consideration and focuses on methods to reduce construction costs without
compromising performance or long‐term maintainability. This design approach incorporates cost‐
saving features made possible through HVDC‐specific design alternatives, materials, and
construction methods. Design features of this concept include the use of guyed composite
structures to allow significantly longer ruling spans than is possible with RUS standard practice.
The reduced number of structures, less costly foundations, and reduced number of conductors all
result in additional savings compared with interties built in accordance with RUS standard
practices.
The following three HVDC transmission circuit configurations are considered for each of the HVDC
conceptual design approaches:
● Monopolar single‐wire transmission with earth‐return path (SWER);
● Monopolar two‐wire transmission with metallic conductor‐return path (TWMR);
● Bipolar two‐wire transmission (2‐MW capacity).
5 In this report, the term “RUS standard practice” refers to overhead intertie line designs based on the methods and
materials presented in RUS design manuals for transmission and distribution line construction, including but not
limited to: REA, 1982, RUS, 1998, 2002, 2003a, 2003b, 2003c, and 2009.
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Schematic figures are provided for each of these conceptual designs in Appendix C. Detailed reports
that address various technical aspects of the assumed conditions and loadings used to develop
these conceptual designs are provided as attachments to Appendix C.
5.2 GEOTECHNICAL CONDITIONS
Based on the analysis described below, conceptual foundation design alternatives for a guyed pole
utilize three thermoprobe micropiles for the pole base and helical anchors for the guys. The
overhead system test site in Fairbanks, Alaska, features installations of both of these prototype
foundations.
5.3 ENVIRONMENTAL LOADS
Five standard NESC loading cases were analyzed for each conceptual design. These load cases are
considered sufficient for most rural Alaska overhead intertie applications. Specific locations may be
subject to higher and/or lower wind and/or ice loadings. 6 Except where specifically stated
otherwise, each of the conceptual designs presented in this section comply with the most stringent
of these load conditions.
5.4 CONSTRUCTION, RUS STANDARD PRACTICE
The conceptual designs of overhead intertie lines presented in this section have been developed to
take advantage of the following factors:
● Alaska contractors, line crews, and utility line personnel are familiar with RUS standard
practice materials, designs, and construction practices, thus they will be more familiar with
the techniques and procedures for building, maintaining, and repairing these lines.
● Alaska already has many miles of RUS standard‐practice distribution and transmission lines
built and in service throughout the state. Utilities understand the performance record and
issues with this type of line construction.
● Utility lenders, which includes RUS, understand and accept RUS standard construction
practice, which can simplify obtaining funds for constructing new interties.
To take advantage of these factors, conceptual design for HVDC preserved RUS standard practice
construction to the extent possible, modifying the pole top assembly to accommodate the
conductor(s), insulator(s), and clearances for HVDC operation. The ruling span is also increased to
take advantage of the fewer wires and reduced structure loads associated with the HVDC circuit
configurations.
Structural analysis of conventional overhead HVDC transmission structures (adapted from RUS
standard practice) was performed by Polarconsult. A conceptual design summary is presented in
Appendix C for each of the line configurations proposed.
6 Section 4.6 of the Phase I Final Report provides a summary of environmental loadings around Alaska (Polarconsult,
2009)
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5.5 CONSTRUCTION, ALASKA‐SPECIFIC CONCEPT
The conceptual designs of overhead intertie lines presented in this section have been developed to
reduce construction costs on rural Alaska interties. Cost reduction is achieved through special
attention to the factors listed below.
● Minimizing the reliance on heavy equipment that must be mobilized to a construction site. If
lighter equipment or local equipment can be used for construction, mobilization costs will
be less, reducing project costs.
● Maximizing the flexibility in construction methods and seasons. By designing for the use of
smaller equipment, greater use of helicopters for construction support, and similar
techniques, all‐season construction becomes possible, providing increased flexibility for
construction techniques and methods. This increased flexibility creates new opportunities
to increase utilization of equipment, increase competition for line construction projects, and
reduce project costs.
These factors have been incorporated into the conceptual design elements listed below.
● Use of taller structures and longer spans. Because HVDC circuits require only one or two
wires, they can utilize longer spans than a comparable three‐ or four‐wire AC circuit.
Increasing spans reduces the number of structures and foundations for a given length of
overhead line, which reduces costs. With this approach, taller structures are needed to
maintain required clearances between the conductor and the ground.
● Use of glass‐fiber‐reinforced polymer (GFRP) poles instead of wood or steel poles. GFRP
poles have been used for over 50 years in electric utility applications 7 but have little to no
history in Alaska’s electric utility industry. GFRP poles are lighter than wood or steel poles
so they can be transported by a small helicopter such as a Hughes 500 or Bell UH‐1 “Huey.”
They are also rot‐resistant and do not leach toxic preservatives into the soils around the
pole. The Phase II project included demonstration of a field‐friendly splice for GFRP poles,
which permits tall poles to be shipped in parts and assembled in the field. This splice can
also be used for field repair of damaged GFRP poles.
● Use of guyed structures in areas where geotechnical conditions prevent cantilevered poles
from being directly buried in the soil. Accepted practice for such conditions is to drive a
steel pile up to 40 feet deep and then fasten a wood pole to the steel pile. Installing the steel
pile requires mobilizing a crane or other heavy equipment to the project site. A guyed
structure can be installed in such conditions with a much smaller base foundation, as the
guys carry most of the moment, and the structure base mostly carries compressive loads.
7 Ibrahim, 2000.
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5.6 TESTING OF OVERHEAD DESIGN CONCEPTS
The conceptual overhead designs described in Appendix C use commercially available and accepted
materials, designs, and construction methods. Certain aspects of the conceptual designs presented
represent innovations in overhead line design that do not have a proven record within the utility
industry in Alaska conditions. In order to evaluate the performance of these components, they were
installed at a test site in Fairbanks, Alaska. This section summarizes the objectives and installation
of the Fairbanks Test Site. Details of the test program are presented in Appendix C.
5.6.1 Test Objectives
The primary test objectives of the Fairbanks Test Site are listed below.
● Demonstrate performance and assembly time of a splice for a constant‐section GFRP utility
pole.
● Demonstrate installation and performance of micro‐thermopile pole foundations.
● Demonstrate installation and performance of micro‐thermopile guy anchors.
● Demonstrate installation and performance of screw guy anchors.
● Demonstrate the installation and performance of the overall guyed GFRP pole structure.
● Demonstrate maintenance and operational characteristics.
5.6.2 Test Site
The test site is located on private property south of Farmer’s Loop Road and north of Creamers’
Field in Fairbanks. The site consists of warm ice‐rich silty permafrost soils. The site has an organic
layer consisting of deciduous shrubs and black spruce. Peat was present at depths of 1 to 5 feet
below ground surface. The active layer in September 2011 extended to a depth of 3 feet, with
standing water encountered within the vegetative mat near the surface. Geotechnical conditions at
the site are characteristic of marginal warm permafrost conditions, as further described in
Appendix C.
Figures 5‐1 through 5‐4 show the installation of innovative materials and systems at the test site in
Fairbanks.
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Figure 5-1 Installing Micro-Thermopile for Guy Anchor
Contractor GeoTek Alaska, Inc. drilling a hole for installation of a micro‐thermopile at a 45‐degree batter angle
using a GeoProbe 8040 series drill rig. The micro‐thermopile will serve as a guy anchor for the prototype guyed
GFRP pole installation at the Fairbanks Test Site. (Polarconsult, 2011).
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Figure 5-2 Assembling the Prototype GFRP Pole Splice
Contractor City Electric, Inc. installing the field splice for the prototype GFRP pole. 40‐foot and 20‐foot GFRP pole
segments were spliced to create the 60‐foot pole erected at the site. The splice slides over the pole segments and
carries moment through contact between the pole and splice walls. Vertical loads are carried through the butt
ends of the pole segments. No glue or adhesive is necessary for the splice to develop the full mechanical strength
of the pole. The screws serve to prevent differential movement between the pole and splice. (Polarconsult, 2011)
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Figure 5-3 Prototype GFRP Pole Foundation During Installation
Detail of prototype GFRP pole base at the Fairbanks Test Site. The adapter plate was adjusted during installation
so the hinge is oriented in line with the guy anchor in the distance (orange flagging). This will allow use of the
guy anchor to lower the pole with a winch if needed. (Polarconsult, 2011)
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Figure 5-4 Prototype Pole at the Fairbanks Test Site
View of the prototype guyed GFRP pole installed at the Fairbanks Test Site. This photograph is taken at a
distance of approximately 25 yards from the 60‐foot‐tall pole. The four guys and the pole splice are visible in this
photograph. (Polarconsult, 2011)
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6.0 SYSTEM ECONOMICS
The extreme variety of environmental and technical conditions found across rural Alaska results in
a significant variation in intertie costs. The typical cost for constructing a conventional overhead
distribution‐class AC intertie in rural Alaska can vary from as little as $100,000 per mile to over
$600,000 per mile8 in parts of the state with challenging logistics and little or no transportation.
Intertie cost variations also affect submarine cables, underground cables, and other overhead
intertie configurations. The details of system economics are presented in Appendix B.
6.1 COST COMPARISON OF AC AND HVDC OVERHEAD INTERTIES
Two distinct overhead HVDC intertie configurations have been compared to a conventional AC
intertie to illustrate a range of HVDC intertie economics with different overhead designs. The two
HVDC intertie configurations are:
● A two‐wire monopolar HVDC intertie using RUS standard practice construction methods.
This intertie configuration represents the upper range of estimated cost for an HVDC
overhead intertie in rural Alaska applications.
● A monopolar SWER HVDC intertie using Alaska‐specific construction methods. This intertie
configuration represents the lower range of estimated cost for an HVDC overhead intertie in
rural Alaska applications.
The estimated cost for HVDC interties in most rural Alaska applications is expected to fall between
the costs cited for these two configurations.
6.1.1 Installation Cost Comparison
Figure 6‐1 presents the estimated installed cost relative to the intertie length for three different
kinds of interties built in rural Alaska conditions:
● A conventional rural Alaska intertie,
● A two‐wire monopolar HVDC intertie using RUS‐type construction methods, and
● A monopolar SWER HVDC intertie using Alaska‐specific construction methods.
Additionally, Figure 6‐1 illustrates the economic break‐even length and relative increase in savings
for longer HVDC interties. The points at which the AC “cost line” crosses either of the HVDC “cost
lines” represents the economic break‐even length. The estimated HVDC costs show a hypothetical
range of installed costs anticipated for low‐power (under 1 MW) rural Alaska HVDC systems.
8 See Section B.6.1 in Appendix B for cost basis information.
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Figure 6-1 Comparative Installed Cost: Overhead 1-MW HVDC and AC Interties
$0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
$35,000,000
$40,000,000
$45,000,000
0 102030405060708090100
Intertie Length (miles)Probable Installed Cost of Overhead HVDC vs. AC IntertiesAC Intertie (Standard RUS Construction)
HVDC Intertie (Monopolar, TWMR, Standard RUS Construction)
HVDC Intertie (Monopolar, SWER, Alaska‐Specific Construction)
BREAK‐EVEN COST FOR HVDC INTERTIES: 6 to 22 MILES
(INSTALLED‐COST BASIS)
Note: This chart is based on the assumptions and comparative system costs
presented in Appendix B. The break‐even point will vary for every intertie project.
COST SAVINGS
RANGE
AC
HVDC
HVDC
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6.1.2 Life‐Cycle Cost Comparison
Operating costs, maintenance costs, and electrical efficiency affect the long‐term economic value of
an intertie. Table 6‐1 presents comparative life‐cycle costs for hypothetical 25‐mile‐long overhead
AC and HVDC interties in rural Alaska. A length of 25 miles was selected as it conservatively
represents the savings anticipated for short HVDC interties. The estimated life‐cycle cost for a 25‐
mile‐long HVDC intertie ranges from 79% to 107% of the life‐cycle cost of an AC intertie.
Table 6-1 Estimated Life-Cycle Costs for 25-mile Overhead AC and HVDC Interties
Parameter Standard RUS
AC Intertie
Monopolar Two‐
Wire HVDC
Intertie (RUS
Construction2)
Monopolar
SWER HVDC
Intertie
(Alaska‐Specific
Design1)
Cost of Diesel ($/gallon [gal]) $7.00 per gallon
Generation Efficiency (kWh/gal) 13 kWh per gallon
Intertie Efficiency 4 97.7% 93.4% 94.5%
Net Annual Energy Transmission (kWh) 1,664,400
Annual Transmission Losses 4 (kWh) 38,300 133,000 114,000
Annualized Value of Transmission Losses ($) $21,000 $71,000 $61,000
Intertie Design Life (years) 20 years
Intertie Annual Operations and Maintenance
(O&M) Costs
$40,000 $58,000 $54,000
Effective Discount Rate 3%
Present Worth of Transmission Losses $307,000 $1,063,000 $912,000
Present Worth of O&M Costs $595,000 $867,000 $796,000
Converter Stations Installed Cost $20,000 $2,080,000 $1,160,000
Intertie Installed Cost $9,480,000 $7,120,000 $5,340,000
Estimated Life‐Cycle Cost $10,402,000 $11,130,000 $8,208,000
HVDC Life‐Cycle Cost as Percent of AC Life‐Cycle Cost 107% 79%
Present Worth Savings (Cost) of HVDC vs. AC ($728,000) $2,194,000
Notes:
1. “Alaska‐Specific Design” refers to the design concepts presented in Appendix C of this report.
2. “RUS Construction” refers to standard RUS design and construction methods for AC interties, adapted to HVDC
applications as described in Appendix C of this report.
3. All monetary values are in 2012 dollars.
4. Efficiency and loss information includes all transmission system components.
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Figure 6‐2 illustrates the economic break‐even length and relative increase in savings for longer
HVDC interties. The points at which the AC “cost line” crosses either of the HVDC “cost lines”
represents the economic break‐even length. The estimated HVDC costs represent a hypothetical
range of life‐cycle costs anticipated for low‐power (under 1 MW) rural Alaska HVDC systems.
Figure 6-2 Comparative Life-Cycle Cost: Overhead 1-MW HVDC and AC Interties
$0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
$35,000,000
$40,000,000
$45,000,000
0 102030405060708090100
Intertie Length (miles)Probable Life‐Cycle Cost of Overhead HVDC vs. AC IntertiesAC Intertie (Standard RUS Construction)
HVDC Intertie (Monopolar, TWMR, Standard RUS Construction)
HVDC Intertie (Monopolar, SWER, Alaska‐Specific Construction)
BREAK‐EVEN COST FOR HVDC INTERTIES: 12 to 31 MILES
(LIFE CYCLE COST BASIS)
Note: This chart is based on the assumptions and comparative system costs
presented in Appendix B. The break‐even point will vary for every intertie project.
AC
HVDC
HVDC
COST SAVINGS
RANGE
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6.2 CASE STUDIES
The case studies in this section provide project‐specific examples of the expected costs and
resulting benefits of using HVDC systems to interconnect communities and resources. These case
studies rely on existing information regarding the proposed intertie routes, loads, and related
project information. Figure 6‐3 presents a few of the many potential low‐power HVDC project sites
throughout Alaska.
Figure 6-3 Location Map for Potential HVDC Project Sites
For the purposes of this report, two specific HVDC project sites were selected for evaluation. The
“Greens Creek –Hoonah” and the “Nome – Pilgrim Hot Springs” intertie projects are typical of the
design approach and economics common to other HVDC Alaskan interties. Table 6‐2 summarizes
the case studies considered in this section.
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Table 6-2 Summary of Case Studies
HVDC Intertie Case
Study
Transmission
Circuit
Intertie
Type
HVDC
Intertie
Cost
Estimate1
AC
Intertie
Cost
Estimate1
Estimated
HVDC
Savings1
Percent
Capital
Cost
Savings
Greens Creek – Hoonah
5‐MW
monopolar
HVDC circuit
with sea
return2
Submarine
Cable
$22.2
million
$49
million
$26.8
million 55%
Nome – Pilgrim Hot
Springs
5 MW bipolar
HVDC circuit
Overhead
Line
$25.7
million
$36.3
million
$10.6
million 29%
Notes:
1. All cost estimates are presented in 2012 dollars.
2. The case study provides a submarine and overhead intertie capacity of 5 MW and converter station capacity of 2
MW. This provides an ample margin for load growth in Hoonah. The converter station capacity can be upgraded as
needed in 500‐kW increments up to 5 MW.
6.2.1 Green’s Creek – Hoonah Case Study
An intertie between Greens Creek, on the Alaska Electric Light and Power Company (AEL&P) grid
that serves Juneau, and the village of Hoonah, an isolated micro‐grid operated by the IPEC, has been
under consideration for over a decade. AEL&P and the IPEC have completed extensive studies and
design work on this intertie. Studies identified a 25‐mile‐long AC submarine cable and
approximately 4 miles of overhead line near Hoonah as the most economical means to complete
this interconnection. 9 The proposed intertie route is shown on Figure 6‐4.
As the development of this project continued, the costs of the AC submarine cable have escalated,
until the project was finally put on hold due to its excessive cost. Hoonah is currently exploring
local hydropower resources to reduce its energy costs but continues to view an intertie as the best
long‐term solution for its energy needs.
This HVDC system represents a technological advance that can reduce the cost of the Greens
Creek – Hoonah intertie and increase its economic feasibility as compared with Hoonah’s other
energy options. The following subsections of this case study provide a high‐level analysis of the
merits of an HVDC intertie for Hoonah.
For the purposes of this case study, a 5‐MW monopolar HVDC transmission circuit with sea return
was selected to connect Hoonah with Green’s Creek. This circuit consists of 25 miles of submarine
cable and 4 miles of overhead line. A monopolar circuit was selected because it is expected to be the
least‐cost intertie solution between Hoonah and Green’s Creek. Other potential configurations, such
as a bipolar HVDC circuit utilizing two single‐conductor cables, would be more expensive than the
monopolar design selected.
9 (Power Engineers, 2004)
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The estimated capital costs include a 5‐MW transmission circuit (submarine cable and overhead
line), and 2‐MW converter stations at Hoonah and Green’s Creek. The converter stations can be
upgraded to 5 MW by adding 500‐kW converter modules as Hoonah’s load increases. If Hoonah’s
load grows beyond 5 MW, a second submarine cable can be installed to provide a 10‐MW bipolar
transmission system.
Figure 6-4 Greens Creek – Hoonah Intertie Route
6.2.1.1 Economic Analysis
Table 6‐3 presents the economic analysis for the Greens Creek – Hoonah intertie alternatives. The
estimated installed cost for the HVDC intertie is $22.2 million, as compared to the cost of $49
million for a conventional AC intertie. The AC intertie cost estimate is based on the 2009 estimated
cost of $37.5 million10 adjusted to 2012 dollars.
10 IPEC, 2009.
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Table 6-3 Estimated Cost for a Greens Creek – Hoonah HVDC Intertie
Cost Item Estimated Cost
Preconstruction
Right‐of‐way acquisition, engineering, survey, permitting $1,600,000
Administration/Management $900,000
HVDC Converter Stations (power converters, sea electrodes, enclosures, AC and DC side
station equipment) $2,700,000
Submarine Cable Supply and Installation $12,400,000
Overhead HVDC Line: Spaaski Bay to Hoonah $900,000
Contingency (on entire project, 25%) 1 $3,700,000
Total Estimated Cost $22,200,000
Notes: 1. A contingency of 25% is applied to the costs developed for this project based on the uncertainties associated
with the project. A significant amount of work has already been done to characterize the bathymetry and sea
floor conditions along the proposed cable route.
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Table 6‐4 presents estimated benefit‐cost ratios for the Greens Creek – Hoonah intertie under
several load growth scenarios. This analysis indicates a clear economic advantage to an HVDC
intertie based on reasonable load growth forecasts for Hoonah.
Table 6-4 Estimated Benefit-Cost Ratio of Greens Creek – Hoonah HVDC Intertie
Item Load Growth Scenario
Existing Load 165% Growth 200% Growth 6
Annual Hoonah Energy Generation (kWh/yr) 1 5,150,000 8,500,000 9,780,000
AEL&P Avoided Cost of Energy (Juneau) 2 $0.06 per kWh
IPEC Avoided Cost of Energy (Hoonah) 1 $0.20 per kWh
Intertie Outage Rate 3 2%
Annual Hoonah Savings 4 $707,000 $1,170,000 $1,340,000
IPEC Operation, Maintenance, Repair, Replacement
and Rehabilitation (OMR&R) Annual Costs 5 $90,000 $90,000 $100,000
Net Annual Savings (Cost)$617,000 $1,150,000 $1,340,000
Intertie Life and Discount Rate 30 years, 3%
Present Worth of Annual Savings (Costs) $12,070,000 $21,090,000 $24,500,000
Estimated Installed Cost $22,200,000 $22,200,000 $22.200,000
Estimated Benefit‐Cost Ratio 0.54 0.95 1.10
Notes:
1. Based on Power Cost Equalization (PCE) reports for 2007 through 2009 (AEA, 2010a).
2. Approximate AEL&P energy cost. IPEC has capacity, so no demand or capacity charges are included.
3. Assumed value.
4. Annual savings are based on the differential cost of energy and do not consider economic benefits in Hoonah
from lower cost energy, or effects to AEL&P of increased energy sales.
5. IPEC’s estimated operations, maintenance, repair, and routine replacement costs include costs for the converter
stations, savings from decreased operation and overhaul of the diesel power plant in Hoonah, and a one‐time
cable repair event over the 30‐year analysis period.
6. Hoonah’s peak loads under a 200% load growth scenario would exceed the 2‐MW capacity of the intertie
converter stations. Intertie throughput is reduced by 5% to reflect diesel generation in Hoonah.
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6.2.2 Pilgrim Hot Springs – Nome
Pilgrim Hot Springs is a geothermal resource located approximately 60 miles north of Nome. It has
been proposed as a power source to reduce Nome’s reliance on diesel fuel for electrical generation.
ACEP is currently studying the Pilgrim Hot Springs geothermal resource to better characterize the
resource’s potential for power generation and other applications. For purposes of sizing the
transmission line from Pilgrim Hot Springs, an electrical generating capacity and transmission
capacity of 5 MW is assumed, based on conversations with ACEP’s manager for the Pilgrim Hot
Springs assessment project.11 The proposed transmission route is shown on Figure 6‐5.
A bipolar HVDC circuit using overhead lines was selected for the HVDC intertie. The bipolar
configuration was selected because it provides increased reliability compared to a monopolar line
at a reasonable additional cost.
Conceptual power line costs for overhead AC and HVDC interties were estimated to evaluate the
benefits of connecting Pilgrim Hot Springs to Nome using an HVDC intertie. The cost estimates
indicate that an HVDC transmission line would cost 29% less than an AC transmission line.
A routing study was not performed as part of this case study. Power lines were routed along the
existing road corridor. This is assumed to be the least‐cost route for the power lines, as the road can
be used to support the construction and long‐term maintenance of the line. A routing study may
identify other routes that are more favorable due to geotechnical, land status, environmental, or
other factors.
11 Personal communication with Marcus Mager, 2012.
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Figure 6-5 Prospective Transmission Route from Pilgrim Hot Springs to Nome
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6.2.2.1 Economic Analysis
Table 6‐5 presents the economic analysis for the Pilgrim Hot Springs – Nome intertie alternatives.
The estimated installed cost for the HVDC intertie alternative is $25.7 million, as compared to the
cost of $36.3 million for a conventional AC intertie.
No information is available for the installed cost of a geothermal power plant at Pilgrim Hot Springs
or the cost of the energy it would generate, so a benefit‐cost ratio of the intertie alternatives was
not evaluated.
Table 6-5 Estimated Installed Cost for a 5-MW Pilgrim Hot Springs – Nome Intertie
Cost Item
Estimated
Installed Cost for
Bipolar HVDC
Intertie
Estimated
Installed Cost
for AC Intertie
Estimated
HVDC Savings
Percent Cost
Savings
Preconstruction Activities
(right‐of‐way acquisition, design,
survey, permitting)
$3,400,000 $3,400,000 ‐ ‐
Administration/Management $1,000,000 $1,300,000 ‐ ‐
Converter Station Construction $4,600,000 $3,000,000 ‐ ‐
Overhead Intertie Construction $10,800,000 $20,200,000 ‐ ‐
Contingency (30%) 1 $5,900,000 $8,400,000 ‐ ‐
Total Estimated Cost $25,700,000 $36,300,000 $10,600,000 29%
Note:
1. A 30% contingency was applied to the costs for this project because no information was available for the
transmission route. This lack of data creates risks due to factors such as land availability, geotechnical
conditions, structural (wind and ice) loadings, and environmental (bird, wildlife, and aesthetics) factors.
Some of these risks are mitigated by the use of cost data for the robust conceptual designs (i.e., Alaska‐specific
construction) used for the HVDC system. The Alaska‐specific conceptual design is assumed to be adequate for
the expected geotechnical and structural conditions along the route. Environmental and land availability issues,
which could require a longer route or departure from the road corridor, pose relatively greater risks than line
design considerations. The net result of these factors results in the 30% contingency used for the case study
economics.
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7.0 CONCLUSIONS AND RECOMMENDATIONS
7.1 CONCLUSIONS
Phase II has demonstrated that the converter technology is technically viable and the transmission
system is economically feasible. Key Phase II findings are:
● Low‐power HVDC converter technology is expected to be commercially available at $250
per kilowatt per converter.
● Estimates of construction costs for a conceptual 25‐mile overhead HVDC intertie indicate
capital cost savings of approximately 30% compared with a conventional overhead AC
intertie. Estimated life‐cycle costs range from 79% to 107% of the life‐cycle cost of an AC
intertie.
● Longer overhead HVDC interties can expect capital cost savings of up to 40%.
● Significant savings are possible for submarine cable and underground cable applications
using HVDC systems. Estimated capital cost savings on a 25‐mile low‐power HVDC
submarine cable intertie are over 50% compared to AC alternatives.
Based on Phase II findings, the benefits of low‐power HVDC systems for Alaska are substantial, and
continued development of this system is recommended.
7.2 OPPORTUNITIES AND BARRIERS
Based on analysis and study conducted during this Phase II project, Polarconsult has concluded that
this HVDC technology presents the following opportunities for Alaska’s utility industry and rural
communities:
● Less expensive rural electric interties, leading to lower‐cost energy and increased energy
independence for rural communities.
● Interconnection to currently stranded energy resources.
● Interconnection cost savings by combining rural electric and telecommunications interties.
The successful commercialization and adoption of low‐power HVDC technology in Alaska requires
overcoming the following barriers:
● Completion of the commercial development and demonstration of the converter technology.
Continued development of the prototype converters, culminating in independent testing of
the converters and deployment on an Alaska utility system, is needed to prove that the
converters are a commercially viable technology.
● Acceptance and use of low‐power HVDC technology by Alaska’s utility industry. Continued
involvement of in‐state and international stakeholders with the on‐going development of
this technology is considered necessary to surmounting this barrier.
● Development and demonstration of standards and control protocols for MTDC transmission
networks, which are needed to build cost‐effective regional HVDC power networks in rural
Alaska.
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7.3 RECOMMENDATIONS
Based on the conclusions and findings of this project, the following actions are recommended.
Phase III program activities:
● Continued development of the power converter technology to commercialize the existing
prototype converter design. Solicitation of additional HVDC converter manufacturers is
warranted to encourage diversity of suppliers and competition;
● Independent testing of the converters to validate efficiency and performance, followed by
deployment on an Alaskan utility system to validate functionality and reliability in a
commercial setting;
● Further development of MTDC transmission systems interconnection and control
technologies; and
● Continued involvement of in‐state stakeholders in the development of this technology.
Stakeholder actions:
● Incorporate low‐power HVDC technology into Alaska’s regional and statewide energy plans
and policies;
● Continue coordination with the State of Alaska to allow a project‐specific waiver of the
NESC to allow the use of SWER circuits;
● Encourage planned rural power and telecommunications interties to incorporate HVDC
technology in their economic and technical analysis, as well as their environmental and
permitting review processes;
● Engage the telecommunications industry to raise awareness of the synergies possible
between low‐power HVDC transmission and fiber networks in rural Alaska; and
● Collaborate with international stakeholders to identify synergies and lessons learned from
parallel technology development efforts. Coordinate on development of applicable
policies/standards and identification of markets to help expedite the commercialization and
reduce the costs of low‐power HVDC systems.
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APPENDIX A
HVDC OVERVIEW
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TABLE OF CONTENTS
A.1 HIGH‐VOLTAGE DIRECT CURRENT (HVDC) TECHNOLOGY .................................................................. 5
A.2 SINGLE‐WIRE EARTH RETURN (SWER) CIRCUITS ................................................................................... 7
A.2.1 WHY USE SWER? ............................................................................................................................................................. 7
A.3 SWER IN ALASKA ..................................................................................................................................................... 8
A.3.1 BETHEL – NAPAKIAK AC SWER LINE .......................................................................................................................... 8
A.3.2 KOBUK – SHUNGNAK AC SWER LINE .......................................................................................................................... 8
A.3.3 FUTURE OF SWER IN ALASKA ........................................................................................................................................ 8
A.4 HVDC FOR ALASKA ................................................................................................................................................. 9
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A.1 HIGH‐VOLTAGE DIRECT CURRENT (HVDC) TECHNOLOGY
High‐voltage direct current (HVDC) converter technology has advanced to use high‐efficiency solid‐state
hardware, and HVDC links are utilized for electrical transmission throughout the world. While the
technology has advanced considerably since the 1950s, utility application of HVDC remains limited to
transmission functions. The smallest utility‐grade HVDC systems are designed to transmit approximately
50 megawatts (MW) 12. Some notable HVDC installations include:
● Swedish Mainland to Gotland Island: 20 MW, 100 kilovolt (kV), monopolar submarine cable with
sea return. Commissioned in 1956, this was one of the first HVDC interties installed in the world.
This original system was decommissioned in 1987 13.
● Pacific Intertie – Celilo, Oregon, to Sylmar, California: 846‐mile, 3,100 MW, 500 kV, bipolar
overhead line. Commissioned in 1970.
● British Columbia Mainland to Vancouver Island, Canada: 45‐mile, 682 MW, 260‐280 kV, bipolar
submarine and overhead system. The first pole was commissioned in 1968, and a second pole was
commissioned in 1977 14.
● Nelson River Bipolar System, Nelson River Hydro Complex to Southern Manitoba, Canada: Two
bipolar transmission systems operate between the hydropower projects along the Nelson River in
northern Manitoba and Winnipeg in the southern part of the province. The first system is a 540‐
mile, 1,620 MW, 450 kV overhead bipolar circuit commissioned in 1977. The second is a 560‐mile,
1,800 MW, 500 kV overhead bipolar circuit commissioned in stages between 1978 and 1985.
Notably, both systems traverse permafrost terrain similar to that found in Alaska and can operate
in SWER mode, moving 1,000s of amperes of current through earth‐return 15.
● Cross‐Sound Cable, New Haven, Connecticut, to Long Island, New York: 24‐mile, 330 MW, 150 kV
bipolar submarine cable. Commissioned in 2002, this cable uses ABB's HVDC Lite technology.
Both HVDC conductors and a fiber‐optic telecommunications cable are bundled into a single cable
to simplify installation 16.
● England – France Cross Channel Intertie: 38‐mile, 160 MW, 100 kV bipolar submarine cable. The
original system was commissioned in 1961 and replaced in 1986 by a larger system operating at
270 kV and 2,000 MW. A bipolar system was originally installed to reduce magnetic anomalies
that could interfere with shipping.
● Sardinia – Corsica – Italian Mainland, Italy: 500 MW, 200 kV both earth and sea returns. The first
200 MW pole of this system was commissioned in 1965. A second 300 MW pole was installed in
1992. This system is unusual because it is a multipoint system (serving three load centers), unlike
most HVDC interties, which transmit power between only two points.
12 “HVDC Lite,” distributed by ABB, is one example of the smaller utility‐grade HVDC systems.
13 The original system used on‐shore grounding grids to complete the transmission circuit via sea and/or seabed pathways. This
first HVDC link was augmented by a second 150 MW monopolar HVDC link to the island in 1983, and a third 150 MW
monopolar link in 1987. Today, these two newer circuits are operated together as a bipolar transmission link.
14 The first monopolar line is rated for 312 MW at 260 kV, and the second monopolar line is rated at 370 MW at 280 kV.
15 http://www.hydro.mb.ca/corporate/facilities/ts_nelson.shtml
16 Cross Sound Cable Connector Project Literature, www.abb.com
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● Five back‐to‐back HVDC converter stations17 interconnect the Texas grid and U.S. electric grid in
neighboring states. Most of these stations were commissioned in the 1980s. Because of these
stations, Texas has an asynchronous grid connection to the remainder of the Lower 48.
● Three Gorges Dam to Shanghai, China: 530‐mile, 3,000 MW, 500 kV, bipolar overhead line. Four
HVDC lines are planned between Three Gorges and China's eastern coastal regions. The first
bipolar circuit was commissioned in 2003 and the second in 2006.
● Victoria to Tasmania, Australia: 500 MW, 400 kV, monopolar submarine cable with sea return.
Commissioned in 2005.
● Sweden to Germany, Baltic Cable: 600 MW, 450 kV, with earth return via deep hole electrodes.
Commissioned in 1993.
HVDC links can be superior to high‐voltage alternating current (AC) links for several key reasons:
● HVDC links are less costly and/or more efficient than AC links under certain circumstances.
● Long interties utilizing insulated cables (as for submarine applications) are possible with HVDC
electricity, but prohibitively difficult with AC electricity due to cable capacitance and reactive
power losses.
● HVDC links provide an asynchronous connection between AC electrical grids. Analogous to a
clutch on a mechanical system, an HVDC intertie allows each AC system to operate at its own
phase and frequency and still allow power transfer between the systems. This can increase the
stability of both AC grids.
● For a given power transfer requirement, HVDC interties can require less right‐of‐way than
comparable AC interties. They can also have a variety of other regulatory, permitting, or
environmental advantages compared to AC interties.
Because of the high cost of the converter systems necessary to convert HVDC to a more readily used AC
waveform, HVDC is generally limited to transmission applications. Accordingly, most or all utility HVDC
systems in use today are point‐to‐point transmission lines, with no intermediate take‐off points or
substations for communities en route.
For the small‐scale rural Alaska HVDC applications considered in this study, there is still an economic
barrier due to the cost of the HVDC converters (estimated at $250,000 per MW in 2012 dollars). For
example, a remote lodge or fish camp likely cannot justify the cost to tap the HVDC line, but most villages
can.
As HVDC interties are considered for rural Alaska applications, utilities may desire to extend AC
distribution as an underbuild or overbuild on an overhead HVDC line. Similarly, other utilities may desire
to utilize the overhead structures to co‐locate their cables. This practice is possible so long as applicable
code requirements and safety provisions are followed. It may be desirable to use conventional
construction in the immediate vicinity of villages to facilitate colocation of multiple utility cables,
transitioning to a different, optimized overhead structure for HVDC once away from the village.
17 The five HVDC systems are the 220‐MW back‐to‐back North DC Tie, 600‐MW back‐to‐back East DC Tie, 36 MVA back‐to‐back
EGPS DC Tie, 150 MVA back‐to‐back RAIL DC Tie, and 80 MVA Laredo variable frequency transformer (VFT) Tie.
(www.ercot.com).
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A.2 SINGLE‐WIRE EARTH RETURN (SWER) CIRCUITS
In its simplest form, an electrical circuit requires two current pathways, typically wires. One wire goes
from the power supply to the load, and a second wire goes from the load back to the power supply. Both
single‐phase AC and DC circuits rely on this basic configuration. The wire from the power supply to the
load is usually at an increased voltage relative to ground, and so it is insulated for safety and to prevent
short circuits. The wire from the load back to the power supply is usually at a much lower voltage relative
to ground and thus is usually but not always insulated.
In single‐wire earth return (SWER) circuits, the wire that serves as the second current pathway from the
load back to the power supply is replaced with a suitable, convenient, and safe current pathway. In the
most general case, this “non‐wire” pathway can be a car or truck chassis, the metal handle of a flashlight,
the earth, natural water bodies, or other objects that can safely complete the electrical circuit.
Sea return circuits are similar to earth return circuits. The only difference is that the sea, or any water
body, is used as the predominant return circuit pathway. Parallel pathways, such as the seabed, are also
available for current flow.
A.2.1 Why Use SWER?
The primary advantages offered by SWER circuits include:
● Lower costs (eliminate the second conductor).
● Higher efficiency (lower electrical losses).
The primary concerns associated with SWER circuits include:
● Avoiding corrosion of buried or submarine metallic objects in the vicinity of the SWER circuit.
● As with all electrical systems, safety.
SWER circuits are widely used for utility transmission and distribution of electricity all over the world.
Numerous HVDC interties are SWER circuits, consisting of a single high‐voltage cable and an earth or sea
return to complete the transmission circuit. Many of these are installed in climates and conditions similar
to Alaska, notably in Scandinavia. In many nations, single‐phase AC SWER circuits are accepted practice
and are industry standard for serving rural areas.
Nations and jurisdictions that use SWER AC circuits to serve their rural areas economically include the
following 18, 19.
● Australia (over 100,000 miles in service)
● Cambodia (Electricite’ du Cambodge)
● New Zealand
● Vietnam
● Laos (Electricite’ du Laos)
● South Africa (Eskon Distribution)
18 “Single Wire Earth Return for Remote Rural Distribution, Reducing Cost and Improving Reliability.” Conrad W. Holland.
Maunsell Ltd., An AECOM Company.
19 “Single Wire Power in Alaska.” State of Alaska, Division of Energy and Power Development. R.W. Rutherford Associates. 1982.
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● Saskatchewan
● India
● Brazil
A.3 SWER IN ALASKA
At least two single‐phase AC SWER circuits have been successfully built and operated in Alaska. These AC
SWER circuits demonstrate that SWER is a proven, beneficial, and appropriate technology for rural Alaska
transmission applications.
A.3.1 Bethel – Napakiak AC SWER Line
In 1981, a 10.5‐mile 14.4 kV single‐phase AC SWER line was constructed to connect the small village of
Napakiak to the City of Bethel. This line used bipod structures to suspend a 7#8 Alumoweld conductor.
This line was constructed at a cost of $23,000 per mile (1980 $) and operated successfully for many years.
Arguably, the line had two shortcomings, neither related to its SWER operation: (1) the structural design
of the line relied upon the conductor to provide longitudinal support to the bipod poles between dead
ends, and on at least one occasion a conductor break caused a series of structures to fall down; and (2)
over time, the load in Napakiak exceeded the line's capacity. However, the line was an unqualified success
at demonstrating that SWER can reduce the costs of power transmission in rural Alaska.
Common misperceptions about this line have given it a negative reputation, which is often incorrectly
attributed to its “innovative” SWER design. The line did suffer high losses, but these can be attributed to
unmetered loads in Napakiak and the poor condition of the distribution system in Napakiak.
The Alaska Energy Authority replaced the Bethel‐Napakiak line with a conventional three‐phase line in
2010. The installed cost of this replacement was approximately $344,000 per mile in 2012 dollars,
approximately three times greater than the inflation‐adjusted cost of the original line 20.
A.3.2 Kobuk – Shungnak AC SWER Line
A 10‐mile single‐phase AC SWER line was constructed to connect the village of Shungnak to Kobuk in
northwestern Alaska. The line and the SWER system worked successfully; however, the support
structures were constructed of local spruce trees, and eventually the bases rotted. Like the Bethel –
Napakiak SWER line, this line also successfully demonstrated SWER viability in permafrost regions. In
1991, this 10‐mile line was replaced with a conventional three‐phase 7.2/12.4 kV AC line with poles
attached to driven steel H‐piles at a cost of $1.1 million, or about $110,000 per mile in 1991 dollars 21.
A.3.3 Future of SWER in Alaska
The transition of most Alaska villages to three‐phase distribution systems has diminished the value of
single‐phase AC SWER interties. AC phase converters would be necessary to interface the intertie with
one or both village grids. In addition, the national electrical codes adopted by the State of Alaska do not
allow the use of SWER circuits for routine power transmission or distribution. Perhaps because of these
factors, there is currently a general lack of interest in SWER technology in Alaska.
20 (AEA, 2007); (DC ,2010).
21 Petrie, Brent. Alaska Village Electric Cooperative, Inc. Personal Communication. February 2008.
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Despite such factors, SWER circuits remain a proven and cost‐effective option for rural Alaska
applications, and they warrant serious consideration. Coupled with HVDC, SWER offers cost and technical
advantages that have the potential to revolutionize rural power transmission in Alaska.
Affordable energy is a vital underpinning of creating a sustainable economic base for Alaska's rural areas.
Affordable transmission is key to achieving affordable energy, and the coupling of SWER and HVDC
presents the brightest opportunity for achieving affordable transmission in Alaska. Accordingly, the
future of SWER in Alaska is very promising.
A.4 HVDC FOR ALASKA
The list of existing HVDC projects in Section A.2 illustrates the fact that today's commercial HVDC
technology remains limited to large‐scale transfer of electricity, normally measured in the 100s or 1,000s
of megawatts. Such technology has very limited application in Alaska, as our largest utility grid, along the
rail belt, has a peak load of well under 1,000 MW. Most rural loads are measured in the 100s of kW.
The lack of commercial HVDC technology in the kilowatt class necessary for rural Alaska applications
means that the numerous benefits offered by HVDC transmission are not presently available to Alaska's
rural communities. The key objective and impetus for this project is to lower the cost of rural Alaska
interties by extending the reach of commercially available HVDC technology down to the kilowatt class
needed to serve Alaska's rural energy transmission needs.
The applications for this technology in Alaska are numerous and include:
● Connecting Bethel and nearby villages with a wind farm along the Bering Sea coast.
● Connecting villages along the Yukon River such as Koyukuk, Nulato, Ruby, and Kaltag with the
proposed Toshiba nuclear battery in Galena.
● Connecting 25 southwestern communities to a proposed 25‐MW geothermal plant near King
Salmon.
● Connecting North Slope communities such as Atqusuk with Barrow to share in the low‐cost
electricity derived from Barrow’s gas fields.
● Developing the geothermal resource at Pilgrim Hot Springs and transmit the power to Nome via
HVDC intertie.
● Completing connections in the Southeast Intertie via an affordable HVDC submarine cable.
A.3.9 Design Considerations for Small Alaska HVDC Interties
Many of the technical aspects of designing and building small HVDC interties in Alaska are much the same
as for building interties anywhere. The single dominating factor that sets construction in rural Alaska
apart is logistics. Most projects have little or no support infrastructure, ranging from the basics such as
modern lodging for workers to availability of transportation infrastructure, heavy equipment, skilled
labor, and so on.
Many major construction projects address the logistical challenges of rural Alaska by importing
everything necessary to get the job done by conventional means. This works, but is very costly.
A different solution to the logistics challenge is to tailor the design to use available local resources to the
extent possible. This is a very challenging proposition, but the rewards – lower construction costs – are
substantial. In general terms, designing for Alaska logistics means:
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● Use materials and equipment that are readily shipped by common transportation methods, such
as small cargo aircraft 22. Use materials and construction methods that can utilize small, low
ground pressure equipment to enable construction during summer or autumn thawed conditions.
● Use materials and construction methods that employ locally available equipment for transport
and construction as much as possible.
● Reduce the amount of construction and fabrication required in the field and on the line. Pre‐
manufacture and preassemble before shipping to the villages or in the villages before shipping to
the field to reduce costs and increase quality.
● Optimize the construction and assembly methods to employ locally available labor.
22 The largest cargo aircraft suitable for Alaska logistic planning is a Hercules C‐130, but many village airstrips cannot
accommodate a Hercules. A more universal cargo aircraft for remote Alaska projects is a Sherpa SD‐330 or similar small
cargo aircraft.
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APPENDIX B
ECONOMIC ANALYSIS
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TABLE OF CONTENTS
B.1 INTRODUCTION ........................................................................................................................................................ 7
B.2 ECONOMIC ANALYSIS ............................................................................................................................................ 8
B.2.1 COMPARATIVE COST: AC VERSUS HVDC OVERHEAD INTERTIES ............................................................................. 8
B.2.2 INSTALLATION COST COMPARISON ................................................................................................................................ 8
B.2.3 LIFE‐CYCLE COST COMPARISON ................................................................................................................................... 10
B.3 COST ANALYSIS BASIS ......................................................................................................................................... 12
B.3.1 GENERATION AND LOAD ASSUMPTIONS ...................................................................................................................... 12
B.3.2 SYSTEM EFFICIENCY ASSUMPTIONS ............................................................................................................................. 12
B.3.3 OPERATION, MAINTENANCE, AND REPAIR ASSUMPTIONS ....................................................................................... 12
B.3.4 ECONOMIC ASSUMPTIONS .............................................................................................................................................. 13
B.3.5 INSTALLED COST ASSUMPTIONS ................................................................................................................................... 13
B.4 CASE STUDIES ......................................................................................................................................................... 14
B.4.1 GREEN’S CREEK – HOONAH CASE STUDY .................................................................................................................... 14
B.4.2 PILGRIM HOT SPRINGS – NOME .................................................................................................................................... 19
B.5 DETAILED HVDC INTERTIE COST INFORMATION .................................................................................. 23
B.5.1 OVERHEAD INTERTIE COST DETAIL ............................................................................................................................. 23
B.5.2 SUBMARINE CABLE INTERTIE COST DETAIL ............................................................................................................... 25
B.5.3 UNDERGROUND CABLE INTERTIE COST DETAIL ........................................................................................................ 25
B.5.4 CONVERTER STATION COST DETAIL ............................................................................................................................ 26
B.6 DETAILED AC INTERTIE COST INFORMATION ........................................................................................ 30
B.6.1 COST BASELINES FOR OVERHEAD AC INTERTIES ...................................................................................................... 31
B.6.2 COST BASELINE FOR SUBMARINE CABLE AC INTERTIES .......................................................................................... 33
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LIST OF TABLES
Table B‐1 Estimated Life‐Cycle Costs for 25‐mile Overhead AC and HVDC Interties ....................... 10
Table B‐2 Summary of Case Studies ...................................................................................................................... 14
Table B‐3 Estimated Cost for an Greens Creek – Hoonah HVDC Intertie ............................................... 17
Table B‐4 Estimated Benefit‐Cost Ratio of Greens Creek – Hoonah HVDC Intertie .......................... 18
Table B‐5 Estimated Installed Cost for a 5‐MW Pilgrim Hot Springs – Nome Intertie ..................... 22
Table B‐6 Estimated Cost for a 25‐mile Overhead HVDC Intertie ............................................................ 24
Table B‐7 Estimated Costs for a 25‐mile Underground HVDC Intertie .................................................. 26
Table B‐8 1‐MW HVDC Converter Station Cost Estimate ............................................................................. 27
Table B‐9 HVDC Converter Enclosure Cost Detail ........................................................................................... 27
Table B‐10 Switchgear and Switchyard Cost Detail .......................................................................................... 28
Table B‐11 HVDC Grounding Station Cost Detail ................................................................................................ 29
Table B‐12 Cost Baselines for Remote Alaska AC Intertie Construction .................................................. 30
Table B‐13 Estimated Costs for Overhead AC Interties ................................................................................... 31
Table B‐14 Installed Costs of Recent Remote Alaska Overhead AC Interties ......................................... 32
Table B‐15 Installed Costs of Recent Remote Alaska Submarine Cable Interties ................................. 33
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LIST OF FIGURES
Figure B‐1 Comparative Installed Cost: Overhead 1‐MW HVDC and AC Interties ................................. 9
Figure B‐2 Comparative Life‐Cycle Cost: Overhead 1‐MW HVDC and AC Interties ............................ 11
Figure B‐3 Greens Creek – Hoonah Intertie Route ............................................................................................ 15
Figure B‐4 Prospective Transmission Route from Pilgrim Hot Springs to Nome ................................ 20
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B.1 INTRODUCTION
The extreme variety of environmental and technical conditions found across rural Alaska results in a
significant variation in intertie costs. The typical cost for constructing a conventional overhead
distribution‐class alternating current (AC) intertie in rural Alaska can vary from as little as $100,000 per
mile in areas with good logistic support geotechnical conditions and transportation infrastructure (road
system, southeast) to over $600,000 per mile23 in parts of the state with challenging logistics and little or
no transportation infrastructure (remote interior, northwest, or Yukon‐Kuskokwim delta regions).
Intertie cost variations also affect submarine cables, underground cables, and other overhead intertie
configurations.
This appendix provides the following economic analyses:
● Comparative present worth analysis of conceptual AC and high‐voltage direct current (HVDC)
interties;
● Case studies of Alaska HVDC interties;
● Estimated costs for conceptual HVDC interties; and
● Baseline costs for rural Alaska AC interties.
23 See Section B.6.1 for information on the cost basis of rural Alaska AC interties.
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B.2 ECONOMIC ANALYSIS
This section evaluates comparative costs for conceptual AC and HVDC interties. Because HVDC interties
incur the added expense of converter stations, short HVDC interties (under approximately 6 to 31 miles)
will generally not be cost‐effective compared with AC interties, depending on project‐specific conditions.
As the intertie length increases, the lower per‐mile cost of the transmission line offsets the additional cost
of the power converters. HVDC interties shorter than a certain economic “break‐even” length will be more
costly than a comparable AC intertie. The relative savings possible with an HVDC transmission system
increases for intertie lengths above this break‐even length.
Based on specific project conditions, and on the assumptions and analysis described herein, the
conceptual break‐even length for overhead interties is approximately 6 to 22 miles on an installed‐cost
basis, and 12 to 31 miles on a life‐cycle cost basis. The conditions and assumptions used to develop these
economic break‐even length estimates are provided in this appendix.
B.2.1 Comparative Cost: AC versus HVDC Overhead Interties
Two distinct HVDC intertie configurations have been compared to a conventional AC intertie to illustrate
the difference in project economics. The two HVDC intertie configurations are:
● A two‐wire monopolar HVDC intertie using U.S. Department of Agriculture (USDA) Rural Utilities
Service (RUS)‐type construction methods. This intertie configuration represents the upper range
of estimated cost for an HVDC overhead intertie in rural Alaska applications.
● A monopolar single‐wire earth return (SWER) HVDC intertie using Alaska‐specific construction
methods. This intertie configuration represents the lower range of estimated cost for an HVDC
overhead intertie in rural Alaska applications.
The cost for HVDC interties in most rural Alaska applications are expected to fall between the cost
estimates cited for these two configurations.
B.2.2 Installation Cost Comparison
Figure B‐1 presents the estimated installed cost relative to the intertie length for three different kinds of
overhead interties built in rural Alaska conditions:
● A conventional rural Alaska intertie,
● A two‐wire monopolar HVDC intertie using RUS‐type construction methods, and
● A monopolar SWER HVDC intertie using Alaska‐specific construction methods.
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In addition, Figure B‐1 illustrates the economic break‐even length, and relative increase in savings for
longer HVDC interties. The points at which the AC “cost line” crosses either of the HVDC “cost lines”
represents the economic break‐even length. The estimated HVDC costs represent a hypothetical range of
installed costs anticipated for low‐power (under 1 megawatt [MW]) rural Alaska HVDC systems.
Figure B-1 Comparative Installed Cost: Overhead 1-MW HVDC and AC Interties
$0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
$35,000,000
$40,000,000
$45,000,000
0 102030405060708090100
Intertie Length (miles)Probable Installed Cost of Overhead HVDC vs. AC IntertiesAC Intertie (Standard RUS Construction)
HVDC Intertie (Monopolar, TWMR, Standard RUS Construction)
HVDC Intertie (Monopolar, SWER, Alaska‐Specific Construction)
BREAK‐EVEN COST FOR HVDC INTERTIES: 6 to 22 MILES
(INSTALLED‐COST BASIS)
Note: This chart is based on the assumptions and comparative system costs
presented in Appendix B. The break‐even point will vary for every intertie project.
COST SAVINGS
RANGE
AC
HVDC
HVDC
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B.2.3 Life‐Cycle Cost Comparison
Operating costs, maintenance costs, and efficiency affect the long‐term economic value of an intertie.
Table B‐1 presents comparative life‐cycle costs for hypothetical 25‐mile‐long overhead AC and HVDC
interties in rural Alaska. A length of 25 miles was selected as it represents the savings possible using a
relatively short HVDC intertie. The estimated life‐cycle cost for a 25‐mile‐long HVDC intertie ranges from
79% to 107% of the life‐cycle cost of an AC intertie.
Table B-1 Estimated Life-Cycle Costs for 25-mile Overhead AC and HVDC Interties
Parameter Standard RUS AC
Intertie
Monopolar Two‐
Wire HVDC
Intertie (RUS
Construction2)
Monopolar SWER
HVDC Intertie
(Alaska Specific
Design1)
Cost of Diesel ($/gal) $7.00 per gallon
Generation Efficiency (kWh/gal) 13 kWh per gallon
Intertie Efficiency4 97.7% 93.4% 94.5%
Net Annual Energy Transmission (kWh) 1,664,400
Annual Transmission Losses4 (kWh) 38,300 133,000 114,000
Annualized Value of Transmission Losses ($) $21,000 $71,000 $61,000
Intertie Design Life (years) 20 years
Intertie Annual O&M Costs $40,000 $58,000 $54,000
Effective Discount Rate 3%
Present Worth of Transmission Losses $307,000 $1,063,000 $912,000
Present Worth of O&M Costs $595,000 $867,000 $796,000
Converter Stations Installed Cost $20,000 $2,080,000 $1,160,000
Intertie Installed Cost $9,480,000 $7,120,000 $5,340,000
ESTIMATED LIFE‐CYCLE COST $10,402,000 $11,130,000 $8,208,000
HVDC LIFE‐CYCLE COST AS PERCENT OF AC LIFE‐CYCLE COST 107% 79%
PRESENT WORTH SAVINGS (COST) OF HVDC VS. AC ($728,000) $2,194,000
Notes:
1. “Alaska‐Specific Design” refers to the design concepts presented in Appendix C of this report.
2. “RUS Construction” refers to standard RUS design and construction methods for AC interties, adapted to HVDC applications
as described in Appendix C of this report.
3. All monetary values are in 2012 dollars.
4. Efficiency and loss information includes all transmission system components.
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Figure B‐2 illustrates the economic break‐even length, and relative increase in savings for longer HVDC
interties. The points at which the AC “cost line” crosses either of the HVDC “cost lines” represents the
economic break‐even length. The estimated HVDC costs represent a hypothetical range of life‐cycle costs
anticipated for low‐power (under 1 MW) rural Alaska HVDC systems.
Figure B-2 Comparative Life-Cycle Cost: Overhead 1-MW HVDC and AC Interties
$0
$5,000,000
$10,000,000
$15,000,000
$20,000,000
$25,000,000
$30,000,000
$35,000,000
$40,000,000
$45,000,000
0 102030405060708090100
Intertie Length (miles)Probable Life‐Cycle Cost of Overhead HVDC vs. AC IntertiesAC Intertie (Standard RUS Construction)
HVDC Intertie (Monopolar, TWMR, Standard RUS Construction)
HVDC Intertie (Monopolar, SWER, Alaska‐Specific Construction)
BREAK‐EVEN COST FOR HVDC INTERTIES: 12 to 31 MILES
(LIFE CYCLE COST BASIS)
Note: This chart is based on the assumptions and comparative system costs
presented in Appendix B. The break‐even point will vary for every intertie project.
AC
HVDC
HVDC
COST SAVINGS
RANGE
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B.3 COST ANALYSIS BASIS
B.3.1 Generation and Load Assumptions
The following generation and load assumptions are used as the basis of the cost analysis:
● Energy transmitted over all intertie configurations is assumed to be generated by a diesel‐electric
plant operating at a constant efficiency of 13 kilowatt‐hours (kWh) per gallon;
● The price of diesel is assumed to be $7.00 per gallon; and
● No escalator is applied to the price of fuel over time.
B.3.2 System Efficiency Assumptions
The following circuit path is assumed for the AC intertie case:
● Generation at 480 volts alternating current (VAC) in community “A”;
● Step up to 7.2/12.47 kilovolts (kV) AC at the power plant in community “A”; and
● Transmission at 7.2/12.47 kV AC to the receiving community “B.”
The following circuit path is assumed for the HVDC intertie cases:
● Generation at 480 VAC in community “A,”
● Conversion from 480 V AC to 50 kV direct current (DC) at the community “A” power plant,
● Transmission at 50 kV DC to the receiving community “B,”
● Conversion from 50 kV DC to 480 VAC at the power plant in community “B,” and
● Step‐up from 480 VAC to 7.2/12.47 kV AC in community “B.”
The following additional assumptions have been made:
● Both load paths include a single 480 V to 7.2/12.47 kV AC transformer; the comparative analysis
does not need to consider losses in this transformer.
● Intertie line losses are based on the operating voltages and conductors described in Appendix C
for each intertie configuration.
● Two different HVDC converter efficiencies were used to characterize the range of comparative
economics for HVDC interties:
● The RUS‐based HVDC intertie case uses a converter efficiency of 96.2%, which is the efficiency
published by Princeton Power Systems, Inc.(PPS) for the prototype converter at 50% load (see
Appendix F).
● The Alaska‐specific HVDC intertie case uses a higher converter efficiency of 97.2%. This
hypothetical efficiency results in improved comparative economic performance.
● Transmission system losses are valued based on the avoided cost of fuel. All other utility costs are
assumed to be fixed and not affected by transmission system losses.
B.3.3 Operation, Maintenance, and Repair Assumptions
An annual budget of $7,500 to $12,300 per converter is provided for maintenance, repair, and scheduled
components replacement. For HVDC interties, the $12,300 figure is used for the RUS‐based HVDC intertie
case, and $7,500 is used for the Alaska‐specific HVDC intertie case. The $7,500 per converter
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maintenance, repair, and replacement budget is based on the expected life and replacement cost of major
components. These components include the power electronics boards, controller, and other major items
that are expected to require replacement during the 20‐year life of the system. See Appendix F for details
on converter component life and replacement costs.
An annual maintenance and repair budget of $1,500 per mile is assumed for all three overhead intertie
configurations.
B.3.4 Economic Assumptions
A discount rate of 3% has been applied to bring future cash flows (line losses; Operation and
Maintenance, Repair, Replacement, and Rehabilitation [OMR&R] costs) to present values. For purposes of
this comparative analysis, a project life of 20 years is used for all interties, and no salvage value, disposal,
or replacement cost are considered at the end of the 20‐year life.
B.3.5 Installed Cost Assumptions
The range of installed costs developed for the converter stations in Section B.5 was used for the
comparative economic analysis. For HVDC interties, an installed cost of $1,040,000 per station is used for
the RUS‐based HVDC intertie case, and $580,000 is used for the Alaska‐specific HVDC intertie case
The range of installed costs for the three intertie configurations are based on the estimated intertie costs
presented in the following sections of this appendix.
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B.4 CASE STUDIES
The case studies in this section provide project‐specific examples of the expected costs and resulting
benefits of using HVDC systems to interconnect communities and resources. These case studies rely on
existing information regarding the proposed intertie routes, loads, and related project information.
Table B‐2 summarizes the case studies considered in this section.
Table B-2 Summary of Case Studies
HVDC Intertie Case
Study
Transmission
Circuit
Intertie
Type
HVDC
Intertie
Cost
Estimate1
AC
Intertie
Cost
Estimate1
Estimated
HVDC
Savings1
Percent
Capital
Cost
Savings
Greens Creek – Hoonah
5‐MW
monopolar
HVDC circuit
with sea
return2
Submarine
Cable
$22.2
million $49 million $26.8
million 55%
Nome – Pilgrim Hot
Springs
5 MW bipolar
HVDC circuit
Overhead
Line
$25.7
million
$36.3
million
$10.6
million 29%
Notes:
1. All cost estimates are presented in 2012 dollars.
2. The case study provides a submarine and overhead intertie capacity of 5 MW, and converter station capacity of 2 MW.
This provides ample margin for load growth in Hoonah. The converter station capacity can be upgraded as‐needed in 500
kW increments up to 5 MW.
B.4.1 Green’s Creek – Hoonah Case Study
An intertie between Greens Creek, on the Alaska Electric Light and Power, Inc. (AEL&P) grid that serves
Juneau, and the village of Hoonah, an isolated micro‐grid operated by the Inside Passage Electric
Cooperative, Inc. (IPEC) has been under consideration for over a decade. AEL&P and IPEC have completed
extensive study and design work on this intertie. Studies identified a 25‐mile‐long AC submarine cable
and approximately 4 miles of overhead line near Hoonah as the most economical means to complete this
interconnection. 24 The proposed intertie route is shown on Figure B‐3.
As the development of this project continued, the costs of the AC submarine cable have escalated, until the
project was finally put on hold due to its excessive cost. Hoonah is currently exploring local hydropower
resources to reduce its energy costs but continues to view an intertie as the best long‐term solution for its
energy needs.
This HVDC system represents a technological advance that can reduce the cost of the Greens
Creek – Hoonah intertie and increase its economic feasibility as compared with Hoonah’s other energy
options. The following subsections of this case study provide a high‐level analysis of the merits of an
HVDC intertie for Hoonah.
24 (Power Engineers, 2004)
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE B-15
For purposes of this case study, a 5‐MW monopolar HVDC transmission circuit with sea return was
selected to connect Hoonah with Green’s Creek. This circuit consists of 25 miles of submarine cable and 4
miles of overhead line. A monopolar circuit was selected because it is expected to be the least‐cost intertie
solution between Hoonah and Green’s Creek. Other potential configurations, such as a bipolar HVDC
circuit utilizing two single‐conductor cables, would be more expensive than the monopolar design
selected.
The estimated capital costs include a 5 MW transmission circuit (submarine cable and overhead line), and
2 MW converter stations at Hoonah and Green’s Creek. The converter stations can be upgraded to 5 MW
by adding 500 kW converter modules as Hoonah’s load increases. If Hoonah’s load grows beyond 5 MW, a
second submarine cable can be installed to provide a 10 MW bipolar transmission system.
Figure B-3 Greens Creek – Hoonah Intertie Route
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B.4.1.1 Conceptual Design Basis
B.4.1.1.1 Load
Hoonah’s annual kWh generation is approximately 5,000 to 5,500 megawatt‐hours (MWh). The peak load
in Hoonah is estimated at 1,200 kW.25 An initial intertie power capacity of 2,000 kW would serve 100% of
the community’s existing needs and provide a 67% margin for future load growth (for handling peak
load).
B.4.1.1.2 Conceptual Intertie Design
A monopolar HVDC intertie circuit with sea‐return is considered for the conceptual design of the Greens
Creek – Hoonah intertie. The intertie has an initial capacity of 2,000 kW, but the proposed submarine
cable can be operated at 5,000 kW by installing additional modular power converters and related
upgrades at either end of the HVDC system. A higher‐capacity upgrade to 10 MW is possible through
further converter station expansion and installation of a second cable to form a bipolar HVDC system. The
initial HVDC system would consist of the following major components:
● An HVDC converter station at Hawk Inlet on the Greens Creek end of the intertie with a rated
capacity of 2,000 kW. This station would require a 69‐kV to 480‐volt (V) step‐down transformer,
four 500‐kW HVDC converter modules, a sea return electrode rated for 40 amperes of current,
and associated controls and protective equipment.
● 25 miles of monopolar HVDC submarine cable. This cable would have a rated capacity of 5 MW at
50 kV DC (100 amperes). This cable would include a 35 square millimeter (mm2) copper
conductor, a cross‐linked polyethylene dielectric, an extruded lead alloy sheath, and two layers of
counter‐laid galvanized steel armor wire.26 A fiber‐optic bundle is assumed to be included either
in the cable construction or within one of the armor wire positions to facilitate broadband
communications.
● A submarine cable landing station at Spasski Bay near Hoonah. This station would house the shore
end of the submarine cable and transition to an overhead HVDC conductor. The station would also
include a second sea‐return electrode to complete the sea‐return circuit.
● A 3.5‐mile overhead monopolar HVDC transmission line with metallic return from Spasski Bay to
the existing Hoonah powerhouse. This two‐wire overhead line would have one wire at +50 kV DC
and the second wire close to earth potential.
● A second 2,000‐kW HVDC converter station adjacent to the existing Hoonah powerhouse. This
station would house the four 500‐kW HVDC power converters and an AC transformer to converter
the 480 VAC output to 4,160 VAC to interface with the power plant bus voltage.
25 AEA, 2010a; AEA, 2010b
26 See Figure 2 in Attachment D‐1 to Appendix D of this report.
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B.4.1.2 Economic Analysis
Table B‐3 presents the economic analysis for the Greens Creek – Hoonah intertie alternatives. The
estimated installed cost for the HVDC intertie is $22.2 million, as compared to the cost of $49 million for a
conventional AC intertie. The AC intertie cost estimate is based on the 2009 estimated cost of $37.5
million27 adjusted to 2012 dollars.
Table B-3 Estimated Cost for an Greens Creek – Hoonah HVDC Intertie
Cost Item Estimated Cost
Preconstruction
Right‐of‐way acquisition, engineering, survey, permitting $1,600,000
Administration/Management $900,000
HVDC Converter Stations (power converters, sea electrodes, enclosures, AC and DC side
station equipment) $2,700,000
Submarine Cable Supply and Installation $12,400,000
Overhead HVDC Line: Spaaski Bay to Hoonah $900,000
Contingency (on entire project, 25%) 1 $3,700,000
Total Estimated Cost $22,200,000
Notes: 1. A contingency of 25% is applied to the costs developed for this project based on the uncertainties associated with the
project. A significant amount of work has already been done to characterize the bathymetry and sea floor conditions
along the proposed cable route.
27 IPEC, 2009.
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
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Table B‐4 presents estimated benefit‐cost ratios for the Greens Creek – Hoonah intertie under several
load growth scenarios. This analysis indicates a clear economic advantage to an HVDC intertie based on
reasonable load growth forecasts for Hoonah.
Table B-4 Estimated Benefit-Cost Ratio of Greens Creek – Hoonah HVDC Intertie
Item Load Growth Scenario
Existing Load 165% Growth 200% Growth 6
Annual Hoonah Energy Generation (kWh/yr) 1 5,150,000 8,500,000 9,780,000
AEL&P Avoided Cost of Energy (Juneau) 2 $0.06 per kWh
IPEC Avoided Cost of Energy (Hoonah) 1 $0.20 per kWh
Intertie Outage Rate 3 2%
Annual Hoonah Savings 4 $707,000 $1,170,000 $1,340,000
IPEC Operation, Maintenance, Repair, Replacement and
Rehabilitation (OMR&R) Annual Costs 5 $90,000 $90,000 $100,000
Net Annual Savings (Cost)$617,000 $1,150,000 $1,340,000
Intertie Life and Discount Rate 30 years, 3%
Present Worth of Annual Savings (Costs) $12,070,000 $21,090,000 $24,500,000
Estimated Installed Cost $22,200,000 $22,200,000 $22.200,000
Estimated Benefit‐Cost Ratio 0.54 0.95 1.10
Notes:
1. Based on Power Cost Equalization (PCE) reports for 2007 through 2009 (AEA, 2010a).
2. Approximate AEL&P energy cost. IPEC has capacity, so no demand or capacity charges are included.
3. Assumed value.
4. Annual savings are based on the differential cost of energy and do not consider economic benefits in Hoonah from lower
cost energy, or effects to AEL&P of increased energy sales.
5. IPEC’s estimated operations, maintenance, repair, and routine replacement costs include costs for the converter
stations, savings from decreased operation and overhaul of the diesel power plant in Hoonah, and a one‐time cable
repair event over the 30‐year analysis period.
6. Hoonah’s peak loads under a 200% load growth scenario would exceed the 2‐MW capacity of the intertie converter
stations. Intertie throughput is reduced by 5% to reflect diesel generation in Hoonah.
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE B-19
B.4.2 Pilgrim Hot Springs – Nome
Pilgrim Hot Springs is a geothermal resource located approximately 60 miles north of Nome. It has been
proposed as a power source to reduce Nome’s reliance on diesel fuel for electrical generation. ACEP is
currently studying the Pilgrim Hot Springs geothermal resource to better characterize the resource’s
potential for power generation and other applications. For purposes of sizing the transmission line from
Pilgrim Hot Springs, an electrical generating capacity and transmission capacity of 5 MW is assumed,
based on conversations with ACEP’s manager for the Pilgrim Hot Springs assessment project.28 The
proposed transmission route is shown on Figure B‐4.
A bipolar HVDC circuit using overhead lines was selected for the HVDC intertie. The bipolar configuration
was selected because it provides increased reliability compared to a monopolar line at a reasonable
additional cost.
Conceptual power line costs for overhead AC and HVDC interties were estimated to evaluate the benefits
of connecting Pilgrim Hot Springs to Nome using an HVDC intertie. The cost estimates indicate that an
HVDC transmission line would cost 29% less than an AC transmission line.
28 Personal communication with Marcus Mager, 2012.
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Figure B-4 Prospective Transmission Route from Pilgrim Hot Springs to Nome
B.4.2.1 Conceptual Design Basis
A routing study was not performed as part of this case study. The intertie route is assumed to follow the
approximately 70‐mile road corridor from Nome to Pilgrim Hot Springs. This is assumed to be the least‐
cost route for the power lines, as the road can be used to support the construction and long‐term
maintenance of the line. A routing study may identify other routes that are more favorable due to
geotechnical, land status, environmental, or other factors.
For this analysis, the transmission route distance is assumed to be 60 miles.
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B.4.2.1.1 Load
Nome’s average annual electricity usage is approximately 3,500 kW, and monthly peak demand is
between 4 and 10 MW. The assumed size of the Pilgrim Hot Springs geothermal power plant is assumed
to be 5 MW. The intertie is therefore assumed to have a capacity of 5 MW and operate at between 2 and 5
MW, depending on instantaneous demand in Nome.
B.4.2.1.2 Conceptual AC Intertie Design
The conceptual design for the AC intertie is a three‐wire 69‐kV AC overhead line set on 45‐foot wood
poles with a ruling span of 400 feet. All poles are assumed to be fastened to steel pile foundations for
moment support and to resist frost jacking forces.
The AC transmission system would consist of the following major components:
● A 5‐MW geothermal power plant at Pilgrim Hot Springs generating at 4,160 V.
● A substation and switch yard to increase voltage from 4,160 V to 69 kV.
● An approximately 60‐mile‐long overhead intertie from Pilgrim Hot Springs to Nome.
● A substation and switchyard in Nome to isolate Nome from the transmission line and step down
the voltage from 69 kV to 12.47 kV for distribution in Nome.
B.4.2.1.3 Conceptual HVDC Intertie Design
The conceptual design for the HVDC intertie is a bipolar circuit operating at +50 and –50 kV DC. The two
circuits would be supported on a guyed glass‐fiber‐reinforced polymer (GFRP) pole fitted with a cross
arm and suspension insulators. A ruling span of 1,000 feet is assumed. The design is similar to that shown
on Figure C‐9.
The HVDC transmission system would consist of the following major components:
● A 5‐MW geothermal power plant at Pilgrim Hot Springs generating at 480 V. It may be preferable
to instead generate at 4,160 V and have a step‐down transformer to the 480 V interface voltage to
the power converters.
● A bipolar HVDC converter station consisting of two banks of five 500‐kW power converters. Each
bank would form a 2.5‐MW pole on the bipolar transmission system.
● An approximately 60‐mile‐long bipolar HVDC transmission line from Pilgrim Hot Springs to
Nome.
● A second bipolar HVDC converter station in Nome.
● An AC transformer to step up the AC output from the converters from 480 V up to 7.2/12.47 kV
for distribution in Nome.
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PHASE II – PROTOTYPING AND TESTING
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B.4.2.2 Economic Analysis
Table B‐5 presents the economic analysis for the Pilgrim Hot Springs – Nome intertie alternatives. The
estimated installed cost for the HVDC intertie alternative is $25.7 million, as compared to the cost of $36.3
million for a conventional AC intertie.
No information is available for the installed cost of a geothermal power plant at Pilgrim Hot Springs or the
cost of the energy it would generate, so a benefit‐cost ratio of the intertie alternatives was not evaluated.
Table B-5 Estimated Installed Cost for a 5-MW Pilgrim Hot Springs – Nome Intertie
Cost Item
Estimated Installed
Cost for Bipolar
HVDC Intertie
Estimated
Installed Cost
for AC Intertie
Estimated
HVDC Savings
Percent Cost
Savings
Preconstruction Activities
(right‐of way acquisition, design,
survey, permitting)
$3,400,000 $3,400,000 ‐ ‐
Administration/Management $1,000,000 $1,300,000 ‐ ‐
Converter Station Construction $4,600,000 $3,000,000 ‐ ‐
Overhead Intertie Construction $10,800,000 $20,200,000 ‐ ‐
Contingency (30%) 1 $5,900,000 $8,400,000 ‐ ‐
Total Estimated Cost $25,700,000 $36,300,000 $10,600,000 29%
Note:
1. A 30% contingency was applied to the costs for this project because no information was available for the transmission route.
This lack of data creates risks due to factors such as land availability, geotechnical conditions, structural (wind and ice)
loadings, and environmental (bird, wildlife, and aesthetics) factors.
Some of these risks are mitigated by the use of cost data for the robust conceptual designs (i.e., Alaska‐specific construction)
used for the HVDC system. The Alaska‐specific conceptual design is assumed to be adequate for the expected geotechnical
and structural conditions along the route. Environmental and land availability issues, which could require a longer route or
departure from the road corridor, pose relatively greater risks than line design considerations. The net result of these factors
results in the 30% contingency used for the case study economics.
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B.5 DETAILED HVDC INTERTIE COST INFORMATION
B.5.1 Overhead Intertie Cost Detail
This report considers different overhead design concepts for HVDC interties. This section presents a
range of estimated costs for these concepts.
The two‐wire monopolar intertie adapted from standard RUS practice is estimated to have the highest
installed cost. In contrast, the monopolar SWER intertie based on Alaska‐specific design concepts is
estimated to have the lowest installed cost.
Table B‐6 presents a breakdown of the estimated installed costs for 25‐mile overhead interties in rural
Alaska using the design cases and concepts presented in Appendix C.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC. HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS PHASE II – PROTOTYPING AND TESTING MAY 2012 PAGE B-24 Table B-6 Estimated Cost for a 25-mile Overhead HVDC Intertie Cost Item Monopolar SWER, Alaska Specific Construction Two‐Wire Monopolar HVDC, RUS –Based Construction Per‐Mile Cost Project Cost Per‐Mile Cost Project Cost Preconstruction Right‐of‐way acquisition, design, survey, permitting $58,000 $1,450,000 $56,000 $1,400,000 Administration/Management $13,000 $325,000 $17,000 $425,000 Materials (intertie only) $48,000 $1,200,000 $47,000 $1,175,000 Converter Stations (on per‐mile basis) $62,000 $1,550,000 $62,000 $1,550,000 Shipping $15,000 $375,000 $25,000 $625,000 Mobilization/Demobilization $37,000 $925,000 $94,000 $2,350,000 Labor $67,000 $1,675,000 $71,000 $1,775,000 Total Cost$300,000 $7,500,000 $372,000 $9,300,000 Note: Line item costs include an embedded 25% contingency.
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B.5.2 Submarine Cable Intertie Cost Detail
A number of site‐specific factors influence the cost of submarine cable applications for HVDC applications
in Alaska. These are the following:
● Cable laying vessels are specialized equipment that must be mobilized to Alaska. Mobilizing these
vessels to Alaska is costly and project dependant. Mobilization costs result in short submarine
interties being significantly more expensive on a per‐mile basis than long submarine interties.
● Marine traffic influences submarine intertie costs. Shallower cable routes must consider
commercial fishing activity, anchoring, and related marine traffic that may pose a hazard to the
cable.
● The seafloor conditions along the cable route also influence costs. Steep slopes, rugged exposed
rock, or unstable slopes will tend to increase costs or project risk.
● The depth of the cable route will influence costs. Deeper routes require stronger, heavier, and
more costly cables, which in turn can require larger, more expensive cable laying vessels.
As a result, a generic per‐mile cost of low‐power submarine cables is not meaningful without
consideration of the project‐specific factors.
B.5.3 Underground Cable Intertie Cost Detail
A number of site‐specific factors will strongly influence the technical feasibility and cost of underground
cable applications for low‐power HVDC applications in Alaska. These are the following:
● Presence of ground susceptible to frost cracking or polygonal cracking. These ground cracks can
impose large tension forces on cables and cause mechanical failure of the cable, resulting in
electrical faults.
● Geotechnical conditions along the cable route will influence the cost of cable installation.
● Steep terrain or other local conditions may prevent use of underground cable.
Estimated costs for HVDC interties using underground cables are presented in Table B‐7.
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Table B-7 Estimated Costs for a 25-mile Underground HVDC Intertie
Cost Item Estimated Per‐Mile Cost
Preconstruction
Right‐of‐way acquisition, design, survey, permitting $45,000
Administration/Management $13,000
Materials (intertie only) $80,000
Converter stations (on per mile basis) $62,000
Shipping $20,000
Mobilization/Demobilization $10,000
Labor $20,000
Total Cost $250,000
Note:
Line item costs include an embedded 25% contingency.
The estimated costs in Table B‐7 are based on the following assumptions:
● Terrain and conditions are suitable for use of a track‐mounted trencher such as a Ditch Witch
RT115 Quad, which can cut a trench through frozen ground during the winter months over most
terrain;
● 1/0 full concentric neutral jacketed 35‐kV AC cable with ethylene propylene rubber (EPR)
dielectric in a 2‐inch duct;
● A water blocking antifreeze gel compound is used;
● A fiber‐optic cable in duct is installed in the same trench;
● Limited brushing is necessary to clear the route;
● Cable reels are spotted along the line with a helicopter; and
● The cable installation depth is a minimum of 18 inches.
B.5.4 Converter Station Cost Detail
The HVDC converter stations will include the major components:
● HVDC power converters;
● Converter enclosures, which may consist of dedicated enclosures or use of an existing building,
such as an existing power plant;
● Protection and switching equipment on the AC and HVDC sides of the converters;
● AC transformers, depending on the AC interface voltage and wiring; and
● Grounding stations, including the ground conductor from the converter station to the grounding
station.
The estimated installed component costs for a 1‐MW monopolar HVDC converter station is presented in
Table B‐8. The range of costs is based on the presence of existing infrastructure and project‐specific
conditions.
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Table B-8 1-MW HVDC Converter Station Cost Estimate
Cost Item Estimated Cost
1‐MW HVDC Power Converter $220,000 to $280,000
Converter Enclosure $40,000 to $160,000
AC‐Side and HVDC‐Side Protective and Switching Equipment $100,000 to $190,000
1‐megavolt amperes (MVA) AC Transformer (7.2/12.4 kV – 480 V) $0 to $30,000
Grounding Station $100,000 to $170,000
Contingency (25%) $120,000 to $210,000
Total, 1‐MW HVDC Converter Station $580,000 to $1,040,000
B.5.4.1 Converter Cost Detail
Based on Phase II development efforts, PPS estimates that the commercial cost of the HVDC power
converters will be $250,000 +/‐ 10% per 1‐MW power converter. PPS states that as manufacturing
volumes increase, the per‐converter cost should decrease. PPS forecasts a 5% to 10% discount at 10 units
and a 20% to 30% discount at 100 units. See Appendix F for a more detailed discussion of converter costs.
B.5.4.2 Converter Enclosure Cost Detail
Estimated costs assume that a modular, prefabricated enclosure will be sent to the community with the
two 500‐kW power converter units already installed. This converter module will then be set in place on a
suitable foundation. Estimated costs are listed in Table B‐9.
Table B-9 HVDC Converter Enclosure Cost Detail
Cost Item Estimated Cost
Power Converter Enclosure $68,000
Foundation $30,000
Labor $27,000
Shipping $35,000
Total, 1‐MW HVDC Converter Enclosure $160,000
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PHASE II – PROTOTYPING AND TESTING
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In communities that will be primarily served by an HVDC intertie, it may be appropriate to locate the
converters inside the existing powerhouse or other suitable existing structure. This would have the
following advantages:
● The existing powerhouse would already have a step‐down transformer sized for the full
community load,
● Waste heat from the converters would provide all or part of the heat for the power plant building,
and
● This would achieve project cost reduction by eliminating the need for a dedicated converter
enclosure and the need to purchase or lease land to site the converter.
B.5.4.3 Switchgear and Switchyard Equipment Cost Detail
Switchgear is required on the AC side of the converters for isolation and protection purposes. Depending
on the desired degree of system automation, the switchgear may also interface between the converter
controls and the power plant controls to allow remote dispatch of generators and the HVDC power
converter.
Similar isolation, protection, and monitoring equipment is needed in the HVDC switchyard on the HVDC
side of the converter. At a minimum, manual disconnect switches (nonload break), surge arrestors, and
fuses are required. Current and voltage sensors are needed on the HVDC line as well.
Estimated switchgear and switchyard costs are presented in Table B‐10.
Table B-10 Switchgear and Switchyard Cost Detail
Cost Item Estimated Cost
AC Switchgear Section (Fuses, Disconnect Switches [load break]) $25,000 to $35,000
HVDC Manual Disconnect Switch (nonload break) $2,000 to $20,000
HVDC Surge Arrestor $10,000 to $15,000
HVDC Fuse $2,000 to $8,000
AC and DC Sensors $30,000 to $48,000
Other Materials $12,000 to $16,000
Shipping $5,000 to $18,000
Labor $14,000 to $20,000
Total, 1‐MW HVDC Converter Station Switchgear and Switchyard $100,000 to $190,000
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B.5.4.4 AC Transformer Cost Detail
The grid interface on the power converters is three‐phase 480‐V AC. In communities where the converter
is connected directly to the 480‐V power plant buss, no additional transformer is required. In
communities where the converter connects to the local distribution grid, a step‐up transformer is
required. The transformer is assumed to be a three‐phase 480/12.47 kV transformer.
B.5.4.5 Grounding Station Cost Detail
A grounding station will need to be provided at each HVDC converter station, regardless of the HVDC
circuit configuration. The conceptual design of a 1‐MW 50 kV DC grounding station is presented in
Appendix E. Estimated costs for this station are presented in Table B‐11, and include 1 mile of overhead
line between the converter station and the grounding station.
Costs for grounding stations will depend on the local geotechnical conditions, the distance between the
converter and grounding stations, and other factors.
Table B-11 HVDC Grounding Station Cost Detail
Cost Item Conceptual Cost
Site Investigations $26,000 to $33,000
Materials $25,000 to $45,000
Labor $34,000 to $46,000
Equipment $7,000 to $12,000
Shipping $8,000 to $34,000
Total, 1‐MW HVDC Grounding Station $100,000 to $170,000
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B.6 DETAILED AC INTERTIE COST INFORMATION
This section presents cost baselines for remote Alaska AC interties to allow comparison to the HVDC
alternatives presented in this report. Cost baselines for AC intertie projects were developed using two
methods. The first method was to develop conceptual cost estimates considering unit costs for labor,
materials, mobilization, etc. The second method was to review, where available, the actual costs of recent
relevant AC intertie projects in Alaska. For both methods, two types of interties were analyzed:
1. Overhead intertie lines in arctic and subarctic regions of western Alaska. These regions
present some of the greatest geotechnical and logistical challenges; therefore, they tend to have
the highest installed costs for overhead interties.
2. Submarine cable interties in rural Alaska. For many parts of Alaska, and in particular the
southeast, submarine cables are the only viable means of building a power intertie.
The cost baselines are summarized in Table B‐12.
Table B-12 Cost Baselines for Remote Alaska AC Intertie Construction
Type of AC Electric Intertie 1 Cost Baseline by
Unit Cost/Quantity Method
Cost Baseline from Recent
Project Experience
Overhead Interties 2 $440,000 per mile $450,000 per mile +/‐ 50%
Submarine Cable Interties 3 N/A $1,300,000 per mile +/‐ 35%
Notes:
1. Intertie power capacity will affect cost. See subsequent notes for the specific types of interties considered to develop
these conceptual costs.
2. Interties are standard RUS three‐phase 14.4/24.9 kV construction, using steel pile foundations.
3. Interties are single‐bundled three‐conductor armored cable.
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B.6.1 Cost Baselines for Overhead AC Interties
B.6.1.1 Cost Baseline for Overhead AC Interties Using Unit Costs and Quantities
A cost baseline for typical AC transmission systems has been estimated for 10‐mile and 25‐mile intertie
concepts. These concepts are based on a standard four‐wire three‐phase 14.4/24.9 kV RUS power line
using driven steel pile foundations. The estimated installed costs are presented in Table B‐13.
Table B-13 Estimated Costs for Overhead AC Interties
Cost Item
10‐Mile Intertie 25‐Mile intertie
Per‐Mile
Cost
Project Cost Per‐Mile Cost Project Cost
Preconstruction
Right‐of‐way acquisition, design, survey,
permitting
$61,000 $610,000 $39,000 $975,000
Administration/Management $18,000 $180,000 $18,000 $425,000
Materials $71,000 $710,000 $71,000 $1,775,000
Shipping $36,000 $360,000 $33,000 $825,000
Mobilization/Demobilization $136,000 $1,360,000 $125,000 $3,125,000
Labor $111,000 $1,110,000 $111,000 $2,675,000
Total Cost $440,000 $4,400,000 $397,000 $9,875,000
The per‐mile cost of overhead AC interties decreases as the intertie gets longer. This is influenced by the
following factors:
● The scope and complexity of environmental, right‐of‐way, design, and permitting issues for the
project.
● The quality of access corridors along the intertie route. The estimated costs assume that per‐mile
labor costs are independent of intertie length.
● The construction plan and schedule. The estimated costs assume that per‐mile
mobilization/demobilization costs decrease slightly with increasing intertie length.
This report finds that per‐mile costs for typical overhead AC interties decrease approximately 10% as the
intertie length increases from 10 to 25 miles. Further, an additional decrease of 5% occurs from 25 to 50
miles. Costs are constant on a per‐mile basis from 50 to 100 miles.
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B.6.1.2 Cost Baseline for Overhead AC Interties Using Comparable Project Costs
Construction cost data compiled for seven remote overhead intertie lines built in western Alaska over the
past 20 years are presented in Table B‐14. The lines selected are considered representative of the most
difficult logistical and geotechnical conditions common in Alaska. Based on Table B‐14, the conceptual
per‐mile cost for a remote Alaska overhead AC intertie is $450,000 per mile, +/‐50% (2012 $).
The cost data are presented as a general cost baseline for remote Alaska overhead interties.
Table B-14 Installed Costs of Recent Remote Alaska Overhead AC Interties
Intertie Project Installed
Cost 1
Year
Built
Length
(miles)
Per‐Mile Cost
(2012 $) 2
Kobuk – Shungnak 3 $1.1M 1991 11 $276,500
Toksook Bay – Tununak 4, 5 $2.0M 2005 6.6 $440,200
Nunapitchuk – Old Kasigluk – Akula Hts. 5, 6 $1.9M 2006 4.2 $594,400
Toksook Bay – Nightmute 7, 8 $6.9M 2009 18 $495,800
Bethel – Napakiak 5, 9 $3.1M 2010 10.5 $344,400
Brevig Mission – Teller 10 $4.7M 2011 6.8 $730,200
Emmonak – Alakanuk 11 $2.9M 2011 11 $267,300
Average Cost per Mile, 2012 Dollars: $449,800
Average Cost per Mile, (Excluding Highest and Lowest‐Cost Projects): $430,300
Notes:
1. Installed costs are in nominal dollars at the time of construction. Due to the limited detail and variety of sources for cost
data, it is not always possible to discern if costs for a given project include preconstruction, construction, shared
mobilization with separate but concurrent projects, and similar complicating factors. Adjusting for these unknown
factors may increase or decrease the project cost that is presented in the table.
2. Project costs are adjusted to 2012 dollars using a custom escalator based on Alaska labor costs and commodity prices
relevant to overhead intertie construction.
3. Estimated cost for the project. The project consisted of replacing an AC SWER intertie with a conventional RUS AC
intertie (Petrie, personal communication, 2012).
4. The project consisted of a new overhead AC intertie (Denali Commission, 2008b).
5. Entire intertie was set on H‐pile or round pile foundations (Denali Commission, 2008a, 2008b, and 2010).
6. The project consisted of replacing an existing overhead AC intertie with a new overhead AC intertie. The cost was
reduced by $300,000 for step‐down transformers for services along the intertie route that are not part of the “intertie”
cost (Denali Commission, 2008a)
7. The project consisted of a new overhead AC intertie (Denali Commission, 2009).
8. Approximately 30% of intertie is set on steel pile foundations (Denali Commission, 2009).
9. The project consisted of replacing an AC SWER intertie with a conventional RUS AC intertie (Denali Commission, 2010).
10. The project consisted of a new AC intertie including overhead, underground, and submarine cable segments. Cost
includes preconstruction and budgeted construction (Denali Commission, 2011).
11. This is the estimated cost for a proposed intertie built in 2011. The intertie project shared mobilization costs with
concurrent installation of wind turbines in Emmonak (AVEC, 2008).
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B.6.2 Cost Baseline for Submarine Cable AC Interties
Construction cost data were compiled for three AC submarine power cables installed or proposed in
Alaska over the past 15 years; these data are presented in Table B‐15. Very few “low‐power” AC
submarine cables have been built in Alaska – the cables in Table B‐15 each have a capacity of 10 to 15
MW. These lines were reviewed because they are the smallest submarine cables with available cost data.
The indicated conceptual per‐mile cost for a AC submarine intertie in Alaska is $1,300,000 per mile, +/‐
35% (2012 $).
Submarine cable costs are project dependent and have a significant cost variability. Short cable projects in
particular can be expected to have significantly higher per‐mile cost due to the fixed mobilization cost of
specialized cable‐laying vessels.
The cost data provide a general cost baseline for remote Alaska submarine power cables.
Table B-15 Installed Costs of Recent Remote Alaska Submarine Cable Interties
Intertie Project Installed
Cost 1
Year Built/
Proposed
Length
(miles)
Per‐Mile Cost
(2012 $) 2
Haines – Skagway 3 $5.86M 1998 15 $880,000
Homer – South Katchemak Bay 5 $2.5M 2001 4.5 $1,200,000
Green’s Creek – Hoonah 4 $37.5M 2009 29 $1,700,000
Average Cost per Mile, 2012 Dollars: $1,300,000
Notes:
1. Installed costs are in nominal dollars at the time of construction. Due to the limited detail and variety of sources for cost
data, it is not always possible to discern if costs for a given project include preconstruction, construction, shared
mobilization with separate but concurrent projects, and similar complicating factors. Adjusting for these unknown
factors may increase or decrease the project cost that is presented in the table.
2. Project costs are adjusted to 2012 dollars using a custom escalator based on Alaska labor costs and commodity prices
relevant to power line construction.
3. The Haines‐Skagway cable has a maximum depth of 1,500 feet and a rated capacity of 15 MW (INEEL, 1998).
4. The Green’s Creek – Hoonah cable has not been built due to its cost. Installed costs are the most recent estimates
available. This cable route includes depths to 2,600 feet. Costs include approximately 4 miles of overhead line (IPEC,
2009).
5. The Homer – South Katchemak Bay cable has a maximum depth of 600 feet and a rated capacity of approximately 12
MW (AJOC, 2001).
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APPENDIX C
CONCEPTUAL DESIGN OF
OVERHEAD HVDC INTERTIE LINES
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TABLE OF CONTENTS
C.1 INTRODUCTION ........................................................................................................................................................ 7
C.1.1 RURAL UTILITIES SERVICE (RUS) DESIGN APPROACH, MODIFIED FOR HVDC INTERTIES ................................ 7
C.1.2 ALASKA‐SPECIFIC DESIGN APPROACH FOR HVDC INTERTIES .................................................................................. 7
C.2 DESIGN CRITERIA FOR OVERHEAD INTERTIE LINES ............................................................................. 8
C.2.1 GEOTECHNICAL CONDITIONS........................................................................................................................................... 8
C.2.2 ENVIRONMENTAL LOADS ................................................................................................................................................. 8
C.3 CONCEPTUAL DESIGN OF OVERHEAD HVDC TRANSMISSION, RUS STANDARD PRACTICE 10
C.3.1 CONVENTIONAL AC INTERTIE DESIGN ........................................................................................................................ 10
C.3.2 MONOPOLAR SINGLE‐WIRE TRANSMISSION WITH EARTH‐RETURN PATH (SWER), CONVENTIONALLY BUILT
............................................................................................................................................................................................ 13
C.3.3 MONOPOLAR TWO‐WIRE TRANSMISSION WITH METALLIC CONDUCTOR‐RETURN PATH (TWMR),
CONVENTIONALLY BUILT ............................................................................................................................................... 16
C.3.4 BIPOLAR TWO‐WIRE TRANSMISSION, CONVENTIONALLY BUILT ........................................................................... 19
C.4 CONCEPTUAL DESIGN OF OVERHEAD HVDC TRANSMISSION, ALASKA‐SPECIFIC METHODS22
C.4.1 MONOPOLAR SINGLE‐WIRE TRANSMISSION WITH EARTH‐RETURN PATH (SWER, ALASKA‐SPECIFIC DESIGN
............................................................................................................................................................................................ 23
C.4.2 MONOPOLAR TWO‐WIRE TRANSMISSION WITH METALLIC CONDUCTOR‐RETURN PATH (TWMR), ALASKA‐
SPECIFIC DESIGN ............................................................................................................................................................. 26
C.4.3 BIPOLAR HVDC INTERTIE LINE, ALASKA SPECIFIC DESIGN ................................................................................... 29
C.4.4 CONCEPTUAL DESIGN ANALYSIS ................................................................................................................................... 32
C.4.5 MAINTENANCE METHODS .............................................................................................................................................. 33
C.5 CONCEPTUAL DESIGN ANALYSIS ................................................................................................................... 35
C.5.1 STRUCTURAL DESIGN ...................................................................................................................................................... 35
C.5.2 FOUNDATION DESIGN ..................................................................................................................................................... 35
C.5.3 ANALYSIS OF THERMOPROBE PERFORMANCE ............................................................................................................ 35
C.5.4 ELECTRICAL DESIGN ....................................................................................................................................................... 44
C.6 TESTING OF OVERHEAD DESIGN CONCEPTS ............................................................................................ 49
C.6.1 TEST OBJECTIVES ............................................................................................................................................................ 49
C.6.2 TEST SITE ......................................................................................................................................................................... 49
C.6.3 INSTALLATION .................................................................................................................................................................. 49
C.6.4 MONITORING .................................................................................................................................................................... 50
APPENDIX C ATTACHMENTS ........................................................................................................................................... 63
ATTACHMENT C‐1: ZARLING AERO CONSULTING (ZAE) THERMAL ANALYSIS OF THERMOPILE ..................................... 63
ATTACHMENT C‐2: ARCTIC FOUNDATIONS, INC. (AFI) SHOP DRAWINGS ............................................................................ 91
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LIST OF TABLES
Table C‐1 Conceptual Design Data for Conventional AC Intertie Line .................................................... 12
Table C‐2 Conceptual Design Data for Conventionally Built Monopolar SWER HVDC Intertie Line
.......................................................................................................................................................................... 15
Table C‐3 Conceptual Design Data for Conventionally Built Monopolar HVDC with Metallic Return
.......................................................................................................................................................................... 18
Table C‐4 Conceptual Design Data for Conventionally Built Bipolar HVDC Intertie Line ............... 21
Table C‐5 Conceptual Design Data for Alaska‐Specific Monopolar SWER HVDC Intertie Line .... 25
Table C‐6 Conceptual Design Data for Alaska‐Specific Monopolar Metallic‐Return Intertie Line28
Table C‐7 Conceptual Design Data for Alaska‐Specific Bipolar HVDC Intertie Line .......................... 31
Table C‐8 Summary of Results from Thermoprobe Modeling by ZAE .................................................... 37
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LIST OF FIGURES
Figure C‐1 Tangent Pole for Conventional AC Intertie Line .......................................................................... 11
Figure C‐2 Conventional Tangent Pole for Monopolar SWER HVDC Intertie Line .............................. 14
Figure C‐3 Conventional Tangent Pole for Monopolar HVDC with Metallic Return ........................... 17
Figure C‐4 Conventional Tangent Pole for Bipolar HVDC Intertie Line ................................................... 20
Figure C‐5 Alaska‐Specific Tangent Pole for Monopolar SWER HVDC Intertie Line .......................... 24
Figure C‐6 Alaska‐Specific Tangent Pole for Monopolar Metallic‐Return Intertie Line .................... 27
Figure C‐7 Alaska‐Specific Tangent Pole for Bipolar HVDC Intertie Line ............................................... 30
Figure C‐8 Prototype Micro‐Thermopile Tripod Pole Foundation ............................................................ 38
Figure C‐9 Shop Drawing of Prototype GFRP Pole Base Adapter for Micro‐Thermopile Foundation
(Sheet 1 of 3) .............................................................................................................................................. 39
Figure C‐10 Shop Drawing of Prototype GFRP Pole Base Adapter for Micro‐Thermopile Foundation
(Sheet 2 of 3) .............................................................................................................................................. 40
Figure C‐11 Shop Drawing of Prototype GFRP Pole Base Adapter for Micro‐Thermopile Foundation
(Sheet 3 of 3) .............................................................................................................................................. 41
Figure C‐12 Galvanized Screw Anchors with 8‐Inch Flights ........................................................................... 43
Figure C‐13 Typical Bipolar HVDC Transmission Line Using Suspension Insulators ........................... 45
Figure C‐14 Typical Tangent Structure Using Post Insulators ....................................................................... 46
Figure C‐15 Typical Angle Structure Using Suspension and Post Insulators ........................................... 47
Figure C‐16 Typical Tangent Structure Using Suspension and Post Insulators ...................................... 48
Figure C‐17 Installing Micro‐Thermopile for Guy Anchor ............................................................................... 51
Figure C‐18 Setting Micro‐Thermopile Guy Anchor with Sand Slurry Backfill ....................................... 52
Figure C‐19 Installing Micro‐Thermopile for Guy Anchor ............................................................................... 53
Figure C‐20 Micro‐Thermopiles Staged at Fairbanks Test Site for Installation of Prototype Foundations
.......................................................................................................................................................................... 54
Figure C‐21 Micro‐Thermopile Tripod for Prototype Pole Foundation ..................................................... 55
Figure C‐22 Installing Helical Screw Anchor for Guy Anchor ......................................................................... 56
Figure C‐23 Guy Attached to Micro‐Thermopile Foundation ......................................................................... 57
Figure C‐24 Assembling the Prototype GFRP Pole Splice ................................................................................. 58
Figure C‐25 Installed GFRP Pole, Micro‐Thermopiles, and Adapter Plate ................................................. 59
Figure C‐26 Prototype GFRP Pole Foundation During Installation .............................................................. 60
Figure C‐27 Prototype Pole at the Fairbanks Test Site ...................................................................................... 61
Figure C‐28 Prototype Pole at the Fairbanks Test Site ...................................................................................... 62
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C.1 INTRODUCTION
The conceptual overhead transmission line design alternatives presented in this appendix required
consideration of site‐specific conditions, codes, utility and lender requirements, construction
methodologies, standard design practices, and project economics.
Two conceptual design approaches for overhead high‐voltage direct current (HVDC) interties have been
evaluated, each with a capacity to supply 1 megawatt (MW) at 50 kilovolts (kV) DC: (1) U.S. Department
of Agriculture (USDA) Rural Utilities Service (RUS) design approach, modified for HVDC interties; and (2)
Alaska‐specific design approach for HVDC interties. Each is described below.
C.1.1 Rural Utilities Service (RUS) Design Approach, Modified for HVDC Interties
The first conceptual design approach is based on the use of structures that are constructed in accordance
with the RUS standard practices for conventional 12.4/24.9 kilovolt (kV) alternating current (AC)
distribution lines. 29 These RUS standard practices are currently used to develop AC interties throughout
Alaska and are widely accepted by the utility industry. HVDC transmission requires fewer conductors
than AC, resulting in reduced loads on the supporting structures. As a result, the conceptual designs
developed with the RUS approach have longer ruling spans than typical AC lines. This results in fewer
transmission structures for the HVDC intertie and an associated comparative reduction in construction
cost.
C.1.2 Alaska‐specific Design Approach for HVDC Interties
The second conceptual design approach takes the logistic and technical challenges of construction in rural
Alaska into consideration and focuses on methods to reduce construction costs without compromising
performance or long‐term maintainability. This design approach incorporates cost‐saving features made
possible through HVDC‐specific design alternatives, materials, and construction methods. Design features
of this concept include the use of guyed composite structures to allow significantly longer ruling spans
than is possible with RUS standard practice. The reduced number of structures, less costly foundations,
and reduced number of conductors all result in additional savings compared with interties built to RUS
standard practices.
The following three HVDC transmission circuit configurations are considered for each of the HVDC
conceptual design approaches:
● Monopolar single‐wire transmission with earth‐return path (SWER);
● Monopolar two‐wire transmission with metallic conductor‐return path (TWMR);
● Bipolar two‐wire transmission.
Schematic figures are provided in this appendix for each of these conceptual designs. Detailed reports
that address various technical aspects of the assumed conditions and loadings used to develop these
conceptual designs are provided as attachments to this appendix.
29 In this report, the term “RUS standard practice” refers to overhead intertie line designs based on the methods and materials
presented in RUS design manuals for transmission and distribution line construction, including but not limited to: REA,
1982, RUS, 1998, 2002, 2003a, 2003b, 2003c, and 2009.
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C.2 DESIGN CRITERIA FOR OVERHEAD INTERTIE LINES
The following design criteria has been developed as a basis for the conceptual design of the HVDC
overhead intertie lines.
C.2.1 Geotechnical Conditions
Based on the analysis described below, conceptual foundation design alternatives for a guyed pole utilize
three thermoprobe micropiles for the pole base and helical anchors for the guys. The conceptual
foundation design alternatives are presented on Figures C‐9 through C‐11. The overhead system test site
includes installation of both of these prototype foundations, as well as thermoprobe micropiles and screw
anchors to restrain the guy wires.
Polarconsult contracted with Golder Associates, Inc. (Golder) to identify and characterize the most
common geotechnical conditions that pose the greatest technical and economic challenges for rural
Alaska overhead intertie lines as currently designed.
In summary, Golder identified three conceptual geotechnical conditions representing the greatest
economic challenge for rural Alaska overhead interties. These are summarized below.
Profile “A”: Icy, “warm” permafrost comprised primarily of low‐plasticity mineral silt below an active
layer with higher organic content. The permafrost temperature in the upper 15 feet beneath the
active layer would have a maximum temperature (occurring in late autumn) of 31.0 to 31.5 °F. The
active layer is assumed to be approximately 3.5 feet thick, consisting of organic soils and surface peat.
Surface vegetation in the project footprint is assumed to remain undisturbed by line construction.
This profile is intended to represent a generic geotechnical profile in the lower Yukon and Kuskokwim
areas.
Profile “B”: Warm and degrading permafrost, primarily low‐ to moderate‐plasticity mineral silt with
elevated pore water salinity. Taliks or thin unbonded soil layers may be present in the frozen soil
matrix within 15 to 20 feet below grade. Temperatures are expected to average 31.5 to 31.8 °F in the
uppermost 15 feet below the active layer. Degrading permafrost conditions are expected below the
active layer in some areas along the intertie alignment. Surface vegetation in the project footprint is
assumed to remain undisturbed by line construction. This profile is intended to represent a generic
geotechnical profile along coastal areas of western Alaska.
Profile “C”: Thawed or unfrozen mineral soil, generally sandy with silt contents of 20% to 40% total
dry weight. Highly degraded permafrost with significant thawed zones is present below the active
layer. Soil moisture contents represent saturated conditions and no significant pore water salinity is
present. A higher organic content active layer is present, with grasses, brush, and trees for vegetation.
The active layer is approximately 5 feet. This profile is intended to represent a generic geotechnical
profile along the permafrost margin in interior Alaska or inland areas with significant permafrost
degradation.
C.2.2 Environmental Loads
The following loadings were analyzed for each conceptual design:
Case 1: National Electrical Safety Code (NESC) 250B = ½ inch of ice, 4 pounds per square foot (psf)
wind.
Case 2: NESC 250C = no ice, 120 mph wind.
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Case 3: NESC 250D = ¼ inch of ice, 80 mph wind.
Case 4: High ice = 1 inch ice, no wind, 30 degrees Fahrenheit (°F).
Case 5: No ice or wind.
These load cases are considered sufficient for many rural Alaska overhead intertie applications. Specific
locations may be subject to higher and/or lower wind and/or ice loadings. 30 Except where specifically
stated otherwise, each of the conceptual designs presented in this section comply with the most stringent
of these load conditions.
30 Section 4.6 of the Phase I Final Report provides a summary of environmental loadings around Alaska (Polarconsult, 2009)
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C.3 CONCEPTUAL DESIGN OF OVERHEAD HVDC TRANSMISSION, RUS
STANDARD PRACTICE
The conceptual designs of overhead intertie lines presented in this section have been developed to take
advantage of the following factors:
● Alaska contractors, line crews, and utility line personnel are familiar with RUS standard practice
materials, designs, and construction practices, thus they will be more familiar with the techniques
and procedures for building, maintaining, and repairing these lines.
● Alaska already has many miles of RUS standard‐practice distribution and transmission lines built
and in service throughout the state. Utilities understand the performance record and issues with
this type of line construction.
● Utility lenders, which includes RUS, understand and accept RUS standard construction practice,
which can simplify obtaining funds for constructing new interties.
To take advantage of these factors, conceptual design for HVDC preserved RUS standard practice
construction to the extent possible, modifying the pole top assembly to accommodate the conductor(s),
insulator(s), and clearances for HVDC operation. The ruling span is also increased to take advantage of the
fewer wires and reduced structure loads associated with the HVDC circuit configurations.
Structural analysis of conventional overhead HVDC transmission structures (adapted from RUS standard
practice) was performed by Polarconsult. A conceptual design summary is presented in the following
sections for each line configuration.
C.3.1 Conventional AC Intertie Design
Conventional AC intertie designs for low‐power (under 1 MW) rural Alaska AC intertie lines are
considered in this study for the following reasons:
1. The majority of existing rural Alaska interties are built per RUS standard practice. Thus, this
conventional AC overhead line configuration is the baseline for comparisons of capital cost,
electrical efficiency, and other metrics by which the HVDC intertie systems are evaluated in this
report.
2. The RUS standard practice construction that is used for most AC intertie lines in rural Alaska has
been used in this report as the basis for conceptual design of conventionally built HVDC intertie
lines.
Most rural Alaska AC intertie lines are designed and constructed per RUS standard practice, which
typically uses direct‐burial cantilevered wood poles.31 Many intertie lines, such as those in the Yukon‐
Kuskokwim region, cannot use direct‐burial cantilevered wood pole designs due to the adverse
geotechnical conditions. In these problem areas, the wood pole is commonly attached to a steel pile
driven to a depth of as much as 40 feet to provide an adequate foundation for the cantilevered pole. The
wood poles are typically 35 to 45 feet in length, depending on the site conditions and line design.
The poles support a standard RUS tangent pole‐top assembly as presented on Figure C‐1. The conceptual
design data for this type of line construction is provided in Table C‐1.
31 See RUS, 1998; RUS, 2005.
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Figure C-1 Tangent Pole for Conventional AC Intertie Line
Image Credit: RUS, 1998
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Table C-1 Conceptual Design Data for Conventional AC Intertie Line
I. GENERAL INFORMATION
PROJECT: CONCEPTUAL 1 MW HVDC LINE
SUMMARY OF CONCEPTUAL DESIGN DATA LINE IDENTIFICATION: VOLTAGE:
RUS STD. AC CONSTRUCTION 14.4 / 24.9 KV AC
THREE‐PHASE 14.4 / 24.9 Kv AC INTERTIE TYPE
STANDARD RUS CONSTRUCTION THREE PHASE AC DIST LINE < 1 MW
TYPE OF TANGENT STRUCTURE: BASE POLE:
WOOD POLE 35 FT CLASS 1
DESIGNED BY: POLARCONSULT ALASKA (CONCEPT DESIGN)
II. CONDUCTOR DATA TRANSMISSION COMMON NEUTRAL
SIZE: 1/0 (raven) 1/0 (raven)
STRANDING: 6/1 6/1
MATERIAL: ACSR ACSR
DIAMETER (IN): 0.398 0.398
WEIGHT (LBS/FT): 0.145 0.145
RATED STRENGTH (LBS): 4,380 4,380
III. DESIGN LOADS
NESC LOADING DISTRICT: HEAVY TRANSMISSION (LBS/FT) COMMON NEUTRAL (LBS/FT)
a. ICE (IN.): (vertical) 0.5 in. radial 0.5 in. radial
b. WIND ON ICED COND (PSF): (transverse) 4.0 psf 4.0 psf
c. CONSTANT K: (resultant + K) 0.3 psf 0.3 psf
EXTREME ICE (NO WIND): (vertical) 1.0 in. radial 1.0 in. radial
EXTREME WIND (NO ICE): (transverse) 120 mph 30.6 psf 120 mph 30.6 psf
EXTREME ICE + WIND:
ICE: (vertical) 0.25 in. radial 0.25 in. radial
WIND: (transverse) 80 mph 13.6 psf 80 mph 13.6 psf
IV. SAG & TENSION DATA
RULING SPAN: 250 ft.
SOURCE OF SAG/TENSION DATA: SOUTHWIRE SAG10 TRANSMISSION COMMON NEUTRAL
TENSIONS (% RATED STRENGTH)INITIAL FINAL INITIAL FINAL
NESC a. UNLOADED TEMP: 60 F lbs: 1,333 642 1,333 642
30% 15% 30% 15%
NESC b. LOADED TEMP: 0 F lbs: 2,190 2,190
50% 50%
MAXIMUM ICE TEMP: 30 F lbs: 2,488 2,488
HIGH WIND (NO ICE) TEMP: 60 F lbs: 1,875 1,875
UNLOADED LOW TEMPERATUR TEMP:‐20 F lbs: 1,868 1,868
SAGS (FT)
NESC DISTRICT LOADED TEMP: 0 F 3.61 3.61
UNLOADED HIGH TEMP TEMP: 212 F 3.56 3.56
MAXIMUM ICE TEMP: 30 F 5.93 5.93
LOADED 1/2" ICE, NO WIND TEMP: 32 F 3.73 3.73
V. CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT: EXTREME ICE LOADING
CLEARANCES IN FEET RAILROADS ROADS CULTIVATED AREAS (REMOTE AREAS) ADD'L ALLOWANCE
TRANSMISSION CLR. TO GROUND NA 21.2 21.2 5.0
VI. RIGHT OF WAY
WIDTH: 30 FT. AT EXTREME WIND, FINAL SAG, AREAS WITH TYP. STRUCTURES ADJ. TO ROW
WIDTH: 35 FT. AT EXTREME WIND, FINAL SAG, CLEARANCE TO VEGETATION AT LINE ELEV.
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C.3.2 Monopolar Single‐Wire Transmission with Earth‐Return Path (SWER),
Conventionally Built
The RUS standard practice for an AC line construction (Figure C‐2) can be adapted for a monopolar SWER
HVDC line. The necessary changes are listed below:
● Elimination of the four (or three) conductors, insulators, and the cross‐arm assembly.
● Addition of a single conductor rated for the structural loads and electrical requirements of the
line. Aluminum conductor steel reinforced (ACSR) 4/0 Penguin was selected for the conceptual
design.
● Add a single line post insulator rated for nominal 50 kV DC and the structural loads from the
conductors. A 115 kV AC NGK polymer line post insulator (#L4‐SN321‐15U) was selected for the
conceptual design.32
● Increase the ruling span between the poles from 250 feet (typical for AC lines) to 500 feet.
A tangent pole‐top assembly for a conventionally built monopolar HVDC SWER intertie is shown on
Figure C‐2. The conceptual design data for this type of line construction is provided in Table C‐2.
32 The insulator design is considered conservative and is anticipated to be adequate for most regions of Alaska. Insulators rated
at a lower voltage may be appropriate for some intertie lines.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-14
Figure C-2 Conventional Tangent Pole for Monopolar SWER HVDC Intertie Line
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-15
Table C-2 Conceptual Design Data for Conventionally Built Monopolar SWER HVDC Intertie Line
I. GENERAL INFORMATION
PROJECT: CONCEPTUAL 1 MW HVDC LINE
SUMMARY OF CONCEPTUAL DESIGN DATA LINE IDENTIFICATION: VOLTAGE:
RUS STD. AS HVDC SWER 50 KV HVDC
MONOPOLAR HVDC OVERHEAD INTERTIE, SWER CIRCUIT TYPE
STANDARD RUS CONSTRUCTION MONOPOLAR HVDC SWER
TYPE OF TANGENT STRUCTURE: BASE POLE:
WOOD POLE 35 FT CLASS 1
DESIGNED BY: POLARCONSULT ALASKA (CONCEPT DESIGN)
II. CONDUCTOR DATA TRANSMISSION COMMON NEUTRAL
SIZE: 4/0 'PENGUIN' (NONE)
STRANDING: 6/1
MATERIAL: ACSR
DIAMETER (IN): 0.563
WEIGHT (LBS/FT): 0.291
RATED STRENGTH (LBS): 8,350
III. DESIGN LOADS
NESC LOADING DISTRICT: HEAVY TRANSMISSION (LBS/FT) COMMON NEUTRAL (LBS/FT)
a. ICE (IN.): (vertical) 0.5 in. radial (NONE)
b. WIND ON ICED COND (PSF): (transverse) 4.0 psf
c. CONSTANT K: (resultant + K) 0.3 psf
EXTREME ICE (NO WIND): (vertical) 1.0 in. radial
EXTREME WIND (NO ICE): (transverse) 120 mph 31.1 psf
EXTREME ICE + WIND:
ICE: (vertical) 0.25 in. radial
WIND: (transverse) 80 mph 13.8 psf
IV. SAG & TENSION DATA
RULING SPAN: 500 ft.
SOURCE OF SAG/TENSION DATA: SOUTHWIRE SAG10 TRANSMISSION COMMON NEUTRAL
TENSIONS (% RATED STRENGTH)INITIAL FINAL INITIAL FINAL
NESC a. UNLOADED TEMP: 60 F lbs: 1,999 1,142 (NONE)
24% 14%
NESC b. LOADED TEMP: 0 F lbs: 4,175
50%
MAXIMUM ICE TEMP: 30 F lbs: 4,982
HIGH WIND (NO ICE) TEMP: 60 F lbs: 3,915
UNLOADED LOW TEMPERATUR TEMP:‐20 F lbs: 3,013
SAGS (FT)
NESC DISTRICT LOADED TEMP: 0 F9.71
UNLOADED HIGH TEMP TEMP: 212 F11.32
MAXIMUM ICE TEMP: 30 F14.06
LOADED 1/2" ICE, NO WIND TEMP: 32 F10.44
V. CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT: EXTREME ICE LOADING
CLEARANCES IN FEET RAILROADS ROADS CULTIVATED AREAS (REMOTE AREAS) ADD'L ALLOWANCE
TRANSMISSION CLR. TO GROUND NA 21.7 21.7 5.0
VI. RIGHT OF WAY
WIDTH: 40 FT. AT EXTREME WIND, FINAL SAG, AREAS WITH TYP. STRUCTURES ADJ. TO ROW
WIDTH: 45 FT. AT EXTREME WIND, FINAL SAG, CLEARANCE TO VEGETATION AT LINE ELEV.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-16
C.3.3 Monopolar Two‐Wire Transmission with Metallic Conductor‐Return Path
(TWMR), Conventionally Built
The standard RUS design for an AC line can be adapted for a monopolar HVDC line with metallic return.
Necessary adaptations are listed below:
● Eliminate the four (or three) conductors, insulators, and the cross‐arm assembly.
● Increase the ruling span for the intertie line from a typical 250 feet up to 500 feet.
● Add one cantilevered line post insulator rated for nominal 50 kV DC and the structural loads from
the conductors. 115 kV AC NGK polymer line post insulators (#L4‐SN321‐23) were selected for
the conceptual design.
● Add one offset neutral bracket for the metallic return conductor.
● Add two conductors rated for the structural loads and electrical requirements of the line. ACSR
4/0 Penguin was selected for the conceptual design for both high‐voltage conductors.
A tangent pole‐top assembly for this conceptual design is shown on Figure C‐3. The conceptual design
data for this type of line construction is provided in Table C‐3.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-17
Figure C-3 Conventional Tangent Pole for Monopolar HVDC with Metallic Return
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-18
Table C-3 Conceptual Design Data for Conventionally Built Monopolar HVDC with Metallic Return
I. GENERAL INFORMATION
PROJECT: CONCEPTUAL 1 MW HVDC LINE
SUMMARY OF CONCEPTUAL DESIGN DATA LINE IDENTIFICATION: VOLTAGE:
RUS STD. AS HVDC TWMR 50 KV HVDC
MONOPOLAR HVDC INTERTIE ‐ TWMR CIRCUIT TYPE
(METALLIC RETURN)MONOPOLAR HVDC ‐ METALLIC RETURN
STANDARD RUS CONSTRUCTION TYPE OF TANGENT STRUCTURE: BASE POLE:
WOOD POLE 45 FT CLASS 1
DESIGNED BY: POLARCONSULT ALASKA (CONCEPT DESIGN)
II. CONDUCTOR DATA TRANSMISSION COMMON NEUTRAL
SIZE: 4/0 'PENGUIN' 4/0 'PENGUIN'
STRANDING: 6/1 6/1
MATERIAL: ACSR ACSR
DIAMETER (IN): 0.563 0.563
WEIGHT (LBS/FT): 0.291 0.291
RATED STRENGTH (LBS): 8,350 8,350
III. DESIGN LOADS
NESC LOADING DISTRICT: HEAVY TRANSMISSION (LBS/FT) COMMON NEUTRAL (LBS/FT)
a. ICE (IN.): (vertical) 0.5 in. radial 0.5 in. radial
b. WIND ON ICED COND (PSF): (transverse) 4.0 psf 4.0 psf
c. CONSTANT K: (resultant + K) 0.3psf 0.3psf
EXTREME ICE (NO WIND): (vertical) 1.0 in. radial 1.0 in. radial
EXTREME WIND (NO ICE): (transverse) 120 mph 32.2 psf 120 mph 32.2 psf
EXTREME ICE + WIND:
ICE: (vertical) 0.25 in. radial 0.25 in. radial
WIND: (transverse) 80 mph 14.3 psf 80 mph 14.3 psf
IV. SAG & TENSION DATA
RULING SPAN: 500 ft.
SOURCE OF SAG/TENSION DATA: SOUTHWIRE SAG10 TRANSMISSION COMMON NEUTRAL
TENSIONS (% RATED STRENGTH)INITIAL FINAL INITIAL FINAL
NESC a. UNLOADED TEMP: 60 F lbs: 1,999 1,142 1,999 1,142
24% 14% 24% 14%
NESC b. LOADED TEMP: 0 F lbs: 4,175 4,175
50% 50%
MAXIMUM ICE TEMP: 30 F lbs: 4,982 4,982
HIGH WIND (NO ICE) TEMP: 60 F lbs: 3,983 3,983
UNLOADED LOW TEMPERATUR TEMP:‐20 F lbs: 3,013 3,013
SAGS (FT)
NESC DISTRICT LOADED TEMP: 0 F9.71 9.71
UNLOADED HIGH TEMP TEMP: 212 F 11.32 11.32
MAXIMUM ICE TEMP: 30 F 14.06 14.06
LOADED 1/2" ICE, NO WIND TEMP: 32 F 10.44 10.44
V. CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT: EXTREME ICE LOADING
CLEARANCES IN FEET RAILROADS ROADS CULTIVATED AREAS (REMOTE AREAS) ADD'L ALLOWANCE
TRANSMISSION CLR. TO GROUND NA 21.7 21.7 5.0
VI. RIGHT OF WAY
WIDTH: 50 FT. AT EXTREME WIND, FINAL SAG, AREAS WITH TYP. STRUCTURES ADJ. TO ROW
WIDTH: 45 FT. AT EXTREME WIND, FINAL SAG, CLEARANCE TO VEGETATION AT LINE ELEV.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-19
C.3.4 Bipolar Two‐Wire Transmission, Conventionally Built
The standard RUS design for an AC line can be adapted for a bipolar HVDC line. Necessary adaptations are
listed below:
● Eliminate the four (or three) conductors, insulators, and the cross‐arm assembly.
● Increase the ruling span for the intertie line from a typical 250 feet up to 500 feet.
● Add two cantilevered post insulators rated for nominal 50 kV DC and the structural loads from the
conductors. A 115 kV AC NGK polymer line post insulator (#L4‐SN321‐15U) was selected for the
conceptual design.
● Add two conductors rated for the structural loads and electrical requirements of the line. ACSR
4/0 Penguin was selected for the conceptual design for both the high‐voltage and metallic‐return
conductors.
A tangent pole‐top assembly for this conceptual design is shown on Figure C‐4. The conceptual design
data for this type of line construction is provided in Table C‐4.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-20
Figure C-4 Conventional Tangent Pole for Bipolar HVDC Intertie Line
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-21
Table C-4 Conceptual Design Data for Conventionally Built Bipolar HVDC Intertie Line
I. GENERAL INFORMATION
PROJECT: CONCEPTUAL 2 MW HVDC LINE
SUMMARY OF CONCEPTUAL DESIGN DATA LINE IDENTIFICATION: VOLTAGE:
RUS STD. AS BIPOLAR HVDC +/‐ 50 KV HVDC
BIPOLAR HVDC INTERTIE TYPE
STANDARD RUS CONSTRUCTION BIPOLAR HVDC
TYPE OF TANGENT STRUCTURE: BASE POLE:
WOOD POLE 40 FT CLASS 1
DESIGNED BY: POLARCONSULT ALASKA (CONCEPT DESIGN)
II. CONDUCTOR DATA TRANSMISSION + 50 kVDC TRANSMISSION ‐ 50 kVDC
SIZE: 4/0 'PENGUIN' 4/0 'PENGUIN'
STRANDING: 6/1 6/1
MATERIAL: ACSR ACSR
DIAMETER (IN): 0.563 0.563
WEIGHT (LBS/FT): 0.291 0.291
RATED STRENGTH (LBS): 8,350 8,350
III. DESIGN LOADS
NESC LOADING DISTRICT: HEAVY TRANSMISSION (LBS/FT) TRANSMISSION (LBS/FT)
a. ICE (IN.): (vertical) 0.5 in. radial 0.5 in. radial
b. WIND ON ICED COND (PSF): (transverse) 4.0 psf 4.0 psf
c. CONSTANT K: (resultant + K) 0.3 psf 0.3 psf
EXTREME ICE (NO WIND): (vertical) 1.0 in. radial 1.0 in. radial
EXTREME WIND (NO ICE): (transverse) 120 mph 31.2 psf 120 mph 31.2 psf
EXTREME ICE + WIND:
ICE: (vertical) 0.25 in. radial 0.25 in. radial
WIND: (transverse) 80 mph 13.9 psf 80 mph 13.9 psf
IV. SAG & TENSION DATA
RULING SPAN: 500 ft.
SOURCE OF SAG/TENSION DATA: SOUTHWIRE SAG10 TRANSMISSION TRANSMISSION
TENSIONS (% RATED STRENGTH)INITIAL FINAL INITIAL FINAL
NESC a. UNLOADED TEMP: 60 F lbs: 1,999 1,142 1,999 1,142
24% 14% 24% 14%
NESC b. LOADED TEMP: 0 F lbs: 4,175 4,175
50% 50%
MAXIMUM ICE TEMP: 30 F lbs: 4,982 4,982
HIGH WIND (NO ICE) TEMP: 60 F lbs: 3,922 3,922
UNLOADED LOW TEMPERATUR TEMP:‐20 F lbs: 3,013 3,013
SAGS (FT)
NESC DISTRICT LOADED TEMP: 0 F9.71 9.71
UNLOADED HIGH TEMP TEMP: 212 F 11.32 11.32
MAXIMUM ICE TEMP: 30 F 14.06 14.06
LOADED 1/2" ICE, NO WIND TEMP: 32 F 10.44 10.44
V. CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT: EXTREME ICE LOADING
CLEARANCES IN FEET RAILROADS ROADS CULTIVATED AREAS (REMOTE AREAS) ADD'L ALLOWANCE
TRANSMISSION CLR. TO GROUND NA 21.7 21.7 5.0
VI. RIGHT OF WAY
WIDTH: 50 FT. AT EXTREME WIND, FINAL SAG, AREAS WITH TYP. STRUCTURES ADJ. TO ROW
WIDTH: 45 FT. AT EXTREME WIND, FINAL SAG, CLEARANCE TO VEGETATION AT LINE ELEV.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-22
C.4 CONCEPTUAL DESIGN OF OVERHEAD HVDC TRANSMISSION, ALASKA‐
SPECIFIC METHODS
The conceptual designs of overhead intertie lines presented in this section have been developed to reduce
construction costs on rural Alaska interties. Cost reduction is achieved through special attention to the
factors listed below.
● Minimizing the reliance on heavy equipment that must be mobilized to a construction site. If
lighter equipment or local equipment can be used for construction, mobilization costs will be less,
reducing project costs.
● Maximizing the flexibility in construction methods and seasons. By designing for the use of
smaller equipment, greater use of helicopters for construction support, and similar techniques,
all‐season construction becomes possible, creating new opportunities to increase utilization of
equipment, increase competition for line construction projects, and reduce project costs.
These factors have been incorporated into the conceptual design elements listed below.
● Use of taller structures and longer spans. Because HVDC circuits require only one or two wires,
they can utilize longer spans than a comparable three‐ or four‐wire AC circuit. Increasing spans
reduces the number of structures and foundations for a given length of overhead line, which
reduces costs. With this approach, taller structures are needed to maintain required clearances
between the conductor and the ground.
● Use of glass‐fiber‐reinforced polymer (GFRP) poles instead of wood or steel poles. GFRP poles
have been used for over 50 years in electric utility applications33 but have little to no history in
Alaska’s electric utility industry. GFRP poles are lighter than wood or steel poles so they can be
transported by a small helicopter such as a Hughes 500 or Bell UH‐1 “Huey.” They are also rot‐
resistant and do not leach toxic preservatives into the soils around the pole. The Phase II project
included demonstration of a field‐friendly splice for GFRP poles, which permits tall poles to be
shipped in parts and assembled in the field. This splice can also be used for field repair of
damaged GFRP poles.
● Use of guyed structures in areas where geotechnical conditions prevent cantilevered poles from
being directly buried in the soil. Accepted practice for such conditions is to drive a steel pile up to
40 feet deep and then fasten a wood pole to the steel pile. Installing the steel pile requires
mobilizing a crane or other heavy equipment to the project site. A guyed structure can be installed
in such conditions with a much smaller base foundation, as the guys carry most of the moment,
and the structure base mostly carries compressive loads.
The following sections describe conceptual designs using these Alaska‐specific methods for the following
types of HVDC circuits:
● Monopolar SWER;
● Monopolar TWMR;
● Bipolar two‐wire transmission.
In all cases, the conceptual designs presented in the following sections comply with the design criteria,
load factors, and strength factors set forth in Section C.2 of this appendix and by RUS.34
33 Ibrahim, 2000.
34 RUS, 2009
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-23
C.4.1 Monopolar Single‐Wire Transmission with Earth‐Return Path (SWER, Alaska‐
Specific Design
The Alaska‐specific conceptual design for a monopolar HVDC line consists of the following elements:
● Single 19#10 Alumoweld conductor installed at a ruling span of 1,000 feet.
● A single line post insulator rated for nominal 50 kV DC and the structural loads from the
conductors. A 115 kV AC NGK polymer line post insulator (#L4‐SN321‐15U) was selected for the
conceptual design.35
● A 14‐inch‐diameter, 0.375‐inch wall, 50‐foot‐tall GFRP pole. This pole can be increased to 70 feet
if needed without modification for spans up to 1,500 feet or for increased ground or terrain
clearances.
● Four guys attached to the pole top installed at a 45‐degree angle to the conductor and a 45‐degree
angle to ground.
● Guy anchors consisting of two flights of 8‐inch screw anchors driven 10 to 15 feet into the ground.
● A pole base foundation consisting of three 1½‐inch by 25‐foot thermoprobe micropiles installed
to a depth of 20 feet. The remaining 5 feet serve as the thermoprobe radiator.
A tangent pole‐top assembly for this monopolar HVDC SWER intertie conceptual design is shown on
Figure C‐5. The conceptual design data for this type of line construction is provided in Table C‐5.
35 The insulator design is considered conservative and is anticipated to be adequate for most regions of Alaska. Insulators rated
at a lower voltage may be appropriate for some intertie lines.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-24
Figure C-5 Alaska-Specific Tangent Pole for Monopolar SWER HVDC Intertie Line
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-25
Table C-5 Conceptual Design Data for Alaska-Specific Monopolar SWER HVDC Intertie Line
I. GENERAL INFORMATION
PROJECT: CONCEPTUAL 1 MW HVDC LINE
SUMMARY OF CONCEPTUAL DESIGN DATA LINE IDENTIFICATION: VOLTAGE:
AK SPECIFIC HVDC SWER DES. 50 KV HVDC
MONOPOLAR HVDC OVERHEAD INTERTIE, SWER CIRCUIT TYPE
ALASKA‐SPECIFIC CONSTRUCTION MONOPOLAR HVDC SWER
TYPE OF TANGENT STRUCTURE: BASE POLE:
GUYED FRP POLE 45 FT FRP POLE
DESIGNED BY: POLARCONSULT ALASKA (CONCEPT DESIGN)
II. CONDUCTOR DATA TRANSMISSION COMMON NEUTRAL
SIZE: 19#10 ALUMOWELD (NONE)
STRANDING: 19#10
MATERIAL: ALUMOWELD
DIAMETER (IN): 0.509
WEIGHT (LBS/FT): 0.449
RATED STRENGTH (LBS): 27,190
III. DESIGN LOADS
NESC LOADING DISTRICT: HEAVY TRANSMISSION (LBS/FT) COMMON NEUTRAL (LBS/FT)
a. ICE (IN.): (vertical) 0.5 in. radial (NONE)
b. WIND ON ICED COND (PSF): (transverse) 4.0 psf
c. CONSTANT K: (resultant + K) 0.3 psf
EXTREME ICE (NO WIND): (vertical) 1.0 in. radial
EXTREME WIND (NO ICE): (transverse) 120 mph 32.2 psf
EXTREME ICE + WIND:
ICE: (vertical) 0.25 in. radial
WIND: (transverse) 80 mph 14.3 psf
IV. SAG & TENSION DATA
RULING SPAN: 1,000 ft.
SOURCE OF SAG/TENSION DATA: SOUTHWIRE SAG10 TRANSMISSION COMMON NEUTRAL
TENSIONS (% RATED STRENGTH)INITIAL FINAL INITIAL FINAL
NESC a. UNLOADED TEMP: 60 F lbs: 8,071 6,798 (NONE)
30% 25%
NESC b. LOADED TEMP: 0 F lbs: 11,246
41%
MAXIMUM ICE TEMP: 30 F lbs: 12,637
HIGH WIND (NO ICE) TEMP: 60 F lbs: 10,075
UNLOADED LOW TEMPERATUR TEMP:‐20 F lbs: 9,736
SAGS (FT)
NESC DISTRICT LOADED TEMP: 0 F 15.97
UNLOADED HIGH TEMP TEMP: 212 F 13.73
MAXIMUM ICE TEMP: 30 F 23.85
LOADED 1/2" ICE, NO WIND TEMP: 32 F 15.02
V. CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT: EXTREME ICE LOADING
CLEARANCES IN FEET RAILROADS ROADS CULTIVATED AREAS (REMOTE AREAS) ADD'L ALLOWANCE
TRANSMISSION CLR. TO GROUND NA 21.7 21.7 5.0
VI. RIGHT OF WAY
WIDTH: 60 FT. AT EXTREME WIND, FINAL SAG, AREAS WITH TYP. STRUCTURES ADJ. TO ROW
WIDTH: 70 FT. FOOTPRINT OF 4‐GUYED STRUCTURE, GUYS AT 45 DEGREES TO LINE
WIDTH: 95 FT. FOOTPRINT OF 4‐GUYED STRUCTURE, GUYS IN LINE AND NORMAL TO CONDUCTOR.
WIDTH: 55 FT. AT EXTREME WIND, FINAL SAG, CLEARANCE TO VEGETATION AT LINE ELEV.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-26
C.4.2 Monopolar Two‐Wire Transmission with Metallic Conductor‐Return Path
(TWMR), Alaska‐Specific Design
The Alaska‐specific conceptual design for a monopolar HVDC line (Figure C‐6) can be adapted for a two‐
wire monopolar HVDC line with metallic return. The necessary changes are listed below:
● Increase the GFRP pole height from 50 feet to 65 feet. No change is needed in the pole section or
material under the load cases listed in Section C.2.
● Addition of a second 19#10 Alumoweld conductor supported by an offset bracket 15 feet below
the top of the pole. At this attachment point, this second conductor will have adequate clearance
from the guys, ground, and the high‐voltage conductor under all load conditions listed in Section
C.2 of this appendix.
● Maintain the ruling span at 1,000 feet.
A tangent pole‐top assembly for a conventionally built two‐wire monopolar HVDC intertie is shown on
Figure C‐6. The conceptual design data for this type of line construction is provided in Table C‐6.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-27
Figure C-6 Alaska-Specific Tangent Pole for Monopolar Metallic-Return Intertie Line
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-28
Table C-6 Conceptual Design Data for Alaska-Specific Monopolar Metallic-Return Intertie Line
I. GENERAL INFORMATION
PROJECT: CONCEPTUAL 1 MW HVDC LINE
SUMMARY OF CONCEPTUAL DESIGN DATA LINE IDENTIFICATION: VOLTAGE:
AK SPECIFIC HVDC SWER DES. 50 KV HVDC
MONOPOLAR HVDC OVERHEAD INTERTIE TMWR CIRCUIT TYPE
(METALLIC RETURN)MONOPOLAR HVDC WITH METALLIC RETURN
ALASKA‐SPECIFIC CONSTRUCTION TYPE OF TANGENT STRUCTURE: BASE POLE:
GUYED FRP POLE 65 FT FRP POLE
DESIGNED BY: POLARCONSULT ALASKA (CONCEPT DESIGN)
II. CONDUCTOR DATA TRANSMISSION COMMON NEUTRAL
SIZE: 19#10 ALUMOWELD 19#10 ALUMOWELD
STRANDING: 19#10 19#10
MATERIAL: ALUMOWELD ALUMOWELD
DIAMETER (IN): 0.509 0.509
WEIGHT (LBS/FT): 0.449 0.449
RATED STRENGTH (LBS): 27,190 27,190
III. DESIGN LOADS
NESC LOADING DISTRICT: HEAVY TRANSMISSION (LBS/FT) COMMON NEUTRAL (LBS/FT)
a. ICE (IN.): (vertical) 0.5 in. radial 0.5 in. radial
b. WIND ON ICED COND (PSF): (transverse) 4.0 psf 4.0 psf
c. CONSTANT K: (resultant + K) 0.3 psf 0.3 psf
EXTREME ICE (NO WIND): (vertical) 1.0 in. radial 1.0 in. radial
EXTREME WIND (NO ICE): (transverse) 120 mph 34.0 psf 120 mph 34.0 psf
EXTREME ICE + WIND:
ICE: (vertical) 0.25 in. radial 0.3 in. radial
WIND: (transverse) 80mph 15.1psf 80 mph 15.1 psf
IV. SAG & TENSION DATA
RULING SPAN: 1,000 ft.
SOURCE OF SAG/TENSION DATA: SOUTHWIRE SAG10 TRANSMISSION COMMON NEUTRAL
TENSIONS (% RATED STRENGTH)INITIAL FINAL INITIAL FINAL
NESC a. UNLOADED TEMP: 60 F lbs: 8,071 6,798 8,071 6,798
30% 25% 30% 25%
NESC b. LOADED TEMP: 0 F lbs: 11,246 11,246
41% 41%
MAXIMUM ICE TEMP: 30 F lbs: 12,637 12,637
HIGH WIND (NO ICE) TEMP: 60 F lbs: 10,075 10,075
UNLOADED LOW TEMPERATUR TEMP:‐20 F lbs: 9,736 9,736
SAGS (FT)
NESC DISTRICT LOADED TEMP: 0 F 15.97 15.97
UNLOADED HIGH TEMP TEMP: 212 F 13.73 13.73
MAXIMUM ICE TEMP: 30 F 23.85 23.85
LOADED 1/2" ICE, NO WIND TEMP: 32 F 15.02 15.02
V. CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT: EXTREME ICE LOADING
CLEARANCES IN FEET RAILROADS ROADS CULTIVATED AREAS (REMOTE AREAS) ADD'L ALLOWANCE
TRANSMISSION CLR. TO GROUND NA 21.7 21.7 5.0
VI. RIGHT OF WAY
WIDTH: 60 FT. FOR EXTREME WIND, FINAL SAG, AREAS WITH TYP. STRUCTURES ADJ. TO ROW
WIDTH: 100 FT. FOOTPRINT OF 4‐GUYED STRUCTURE, GUYS AT 45 DEGREES TO LINE
WIDTH: 135 FT. FOOTPRINT OF 4‐GUYED STRUCTURE, GUYS IN LINE AND NORMAL TO CONDUCTOR.
WIDTH: 60 FT. FOR EXTREME WIND, FINAL SAG, CLEARANCE TO VEGETATION AT LINE ELEV.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-29
C.4.3 Bipolar HVDC Intertie Line, Alaska Specific Design
The Alaska‐specific conceptual design for a monopolar HVDC line (Figure C‐7) can be adapted for a two‐
wire bipolar HVDC line. The necessary changes are listed below:
● Increase the GFRP pole height from 50 feet to 55 feet. No change is needed in the pole section or
material.
● Eliminate the post‐top insulator and add two 8‐foot‐long cross‐arms. A Powertrusion
#SH2096100N or equal was selected for the conceptual design.
● Install two suspension insulators off each end of the cross‐arm. A 115‐kV AC NGK suspension
insulator #251‐SE510‐EE or equal was selected for the conceptual design.
● Use 19#10 Alumoweld as the conductor for both the positive and negative poles of the circuit.
● Maintain the same span length of 1,000 feet.
A tangent pole‐top assembly for an Alaska‐specific bipolar two‐wire HVDC intertie is shown on Figure C‐
7. The conceptual design data for this type of line construction is provided in Table C‐7.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-30
Figure C-7 Alaska-Specific Tangent Pole for Bipolar HVDC Intertie Line
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-31
Table C-7 Conceptual Design Data for Alaska-Specific Bipolar HVDC Intertie Line
I. GENERAL INFORMATION
PROJECT: CONCEPTUAL 1 MW HVDC LINE
SUMMARY OF CONCEPTUAL DESIGN DATA LINE IDENTIFICATION: VOLTAGE:
AK SPECIFIC HVDC SWER DES. 50 KV HVDC
BIPOLAR HVDC INTERTIE TYPE
ALASKA‐SPECIFIC CONSTRUCTION BIPOLAR HVDC
TYPE OF TANGENT STRUCTURE: BASE POLE:
GUYED FRP POLE 55 FT FRP POLE
DESIGNED BY: POLARCONSULT ALASKA (CONCEPT DESIGN)
II. CONDUCTOR DATA TRANSMISSION COMMON NEUTRAL
SIZE: 19#10 ALUMOWELD 19#10 ALUMOWELD
STRANDING: 19#10 19#10
MATERIAL: ALUMOWELD ALUMOWELD
DIAMETER (IN): 0.509 0.509
WEIGHT (LBS/FT): 0.449 0.449
RATED STRENGTH (LBS): 27,190 27,190
III. DESIGN LOADS
NESC LOADING DISTRICT: HEAVY TRANSMISSION (LBS/FT) COMMON NEUTRAL (LBS/FT)
a. ICE (IN.): (vertical) 0.5 in. radial 0.5 in. radial
b. WIND ON ICED COND (PSF): (transverse) 4.0 psf 4.0 psf
c. CONSTANT K: (resultant + K) 0.3 psf 0.3 psf
EXTREME ICE (NO WIND): (vertical) 1.0 in. radial 1.0 in. radial
EXTREME WIND (NO ICE): (transverse) 120 mph 32.3 psf 120 mph 32.3 psf
EXTREME ICE + WIND:
ICE: (vertical) 0.25 in. radial 0.3 in. radial
WIND: (transverse) 80 mph 14.3 psf 80 mph 14.3 psf
IV. SAG & TENSION DATA
RULING SPAN: 1,000 ft.
SOURCE OF SAG/TENSION DATA: SOUTHWIRE SAG10 TRANSMISSION COMMON NEUTRAL
TENSIONS (% RATED STRENGTH)INITIAL FINAL INITIAL FINAL
NESC a. UNLOADED TEMP: 60 F lbs: 8,071 6,798 8,071 6,798
30% 25% 30% 25%
NESC b. LOADED TEMP: 0 F lbs: 11,246 11,246
41% 41%
MAXIMUM ICE TEMP: 30 F lbs: 12,637 12,637
HIGH WIND (NO ICE) TEMP: 60 F lbs: 10,075 10,075
UNLOADED LOW TEMPERATUR TEMP:‐20 F lbs: 9,736 9,736
SAGS (FT)
NESC DISTRICT LOADED TEMP: 0 F 15.97 15.97
UNLOADED HIGH TEMP TEMP: 212 F 13.73 13.73
MAXIMUM ICE TEMP: 30 F 23.85 23.85
LOADED 1/2" ICE, NO WIND TEMP: 32 F 15.02 15.02
V. CLEARANCES
MINIMUM CLEARANCES TO BE MAINTAINED AT: EXTREME ICE LOADING
CLEARANCES IN FEET RAILROADS ROADS CULTIVATED AREAS (REMOTE AREAS) ADD'L ALLOWANCE
TRANSMISSION CLR. TO GROUND NA 21.7 21.7 5.0
VI. RIGHT OF WAY
WIDTH: 60 FT. FOR EXTREME WIND, FINAL SAG, AREAS WITH TYP. STRUCTURES ADJ. TO ROW
WIDTH: 95 FT. FOOTPRINT OF 4‐GUYED STRUCTURE, GUYS AT 45 DEGREES TO LINE
WIDTH: 125 FT. FOOTPRINT OF 4‐GUYED STRUCTURE, GUYS IN LINE AND NORMAL TO CONDUCTOR.
WIDTH: 55 FT. FOR EXTREME WIND, FINAL SAG, CLEARANCE TO VEGETATION AT LINE ELEV.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-32
C.4.4 Conceptual Design Analysis
The conceptual design of overhead transmission structures and foundations considered methods for
construction, long‐term operation, maintenance, repair, and replacement of the HVDC transmission
infrastructure.
C.4.4.1 Construction Methods
The cost‐reduction potential of HVDC on rural Alaska projects may be realized using optimized
construction methods.
The use of lightweight overhead structures and foundations allows significant latitude for the
construction and maintenance of the lines. The use of helicopters to stage the materials and construction
equipment becomes possible.
Conventional AC transmission line construction is typically performed in the winter to support the heavy
equipment required for construction. This equipment often includes large pile‐driving or drilling
machines that can only be operated on frozen ground. The resulting winter construction schedule,
combined with summer mobilization of the equipment, contributes significantly to the high cost of AC
interties.
AC transmission structures and foundations are usually based on a cantilever pole design. For the low‐
strength geotechnical conditions found in much of rural Alaska, this design approach is inefficient
compared to the use of axially loaded guyed structures proposed in the HVDC conceptual design.
The HVDC construction approach can utilize Hughes 500 or Bell UH‐1 type helicopters, which are
commonly available in Alaska. These helicopters have a sling capacity of approximately 1,000 and 3,000
pounds, respectively. The HVDC composite pole structures, guy wires, screw foundations, thermoprobe
foundations, and other transmission components can be readily staged by these helicopters. Installation
equipment and other construction tools are available in sizes that can be lifted by helicopter.
In addition, this construction approach involves the use of tracked, low‐ground‐pressure vehicles with
attachments optimized for the installation of the HVDC foundations and erection of the composite pole
structures. The ideal vehicle would be similar to a hydraulically driven BB Carrier. The BB Carrier was a
predecessor of Nodwell tracked vehicles, but much smaller 36. The hydraulic drive system can be used to
power drills, winches, spades, impact drivers, and other onboard equipment used for line construction 37.
C.4.4.2 Recommended Construction Approach
The following narrative sets forth the general construction approach recommended for the conceptual
overhead HVDC intertie design presented herein. Preferred construction methods for any specific intertie
will differ from this approach and will affect construction costs.
1. Identify and procure property rights to the intertie alignment. Standard practices for this effort
are appropriate and are not duplicated here.
36 The BB Carrier was manufactured in the late 1950s and early 1960s by Bombardier. It is no longer in production and is quite
rare today. It featured a gross vehicle weight of about 2,000 pounds, a payload capacity of about 1,000 pounds, and a ground
pressure of less than one psi. Its drive train used a planetary transmission, maintaining power to both tracks during turns,
which reduced the tendency of these vehicles to damage fragile tundra vegetation.
37 A 20,000 to 30,000‐ft‐lb hydraulic impact driver head on a small boom would be useful for driving foundation screw anchors.
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2. Send an engineering crew and survey party to survey the line and determine pole locations in the
field. Surveying and preliminary line design may be completed beforehand by remote methods
(e.g., light detection and ranging [LIDAR] survey). The engineering crew will conduct geotechnical
testing at each pole site to determine the type of foundation required. As appropriate, the
engineering crew may adjust pole locations based on encountered conditions.
3. Order and ship materials to the project site. Depending on the project, one or both villages will be
used as the base of operations. It may be cost‐effective to preassemble pole or foundation units
prior to shipping to the site.
4. Prepare and install pole foundations. Depending on the project, pole foundations may be shipped
ready to install or may require some assembly in the village. Once ready to deploy to the field, the
foundations for each pole (pole base and three guy foundations) will be airlifted to the pole site by
helicopter. A small low‐ground‐pressure vehicle will be used to install the foundations. Depending
on the terrain, this stage may occur during the late winter or summer months. The ground vehicle
will remain in the field, and personnel and consumables will be transported to the vehicle daily by
air. This will reduce transit times.
5. Prepare and assemble poles. This will occur in one or both villages and may include splicing the
poles, attaching the pole top and base hardware, attaching the post insulator and stringing blocks,
and attaching the guy wires and hardware. An assembled pole will be packaged in a manner
suitable for airlift and clearly labeled so it is deployed to the proper foundation.
6. Pole installation. Each assembled pole will be airlifted by helicopter to the pole's foundation. The
pole will be spotted on the ground by the helicopter and a ground crew. The ground crew will use
an A‐frame and their small, low‐ground‐pressure vehicle to erect the pole using two of the guy
anchors as hoist points. Alternatively, the helicopter could be used for faster erecting and securing
of the pole. Once the pole is erected, plumbed, and guys tensioned, the crew will drive to the next
foundation site. Depending on helicopter logistics, it may be cost‐effective to employ two ground
crews for this activity. Ground crews and consumables will be mobilized to the line daily by
helicopter.
7. Stringing and setting the conductor. The stringing line will be deployed by helicopter. Once in
place, the conductor will be staged by helicopter and deployed by ground crews. A Hughes‐500
can lift approximately 2,000 feet of conductor at a time. Once the conductor is strung, ground
crews will ascend each pole to set, tension, and fix the conductor. Armor wrap and vibration
dampers will be installed at this time.
C.4.5 Maintenance Methods
This section discusses the conceptual maintenance and repair methods that are appropriate for the long‐
span, tall‐pole HVDC SWER overhead intertie. While some topics may be generally applicable to the
maintenance and repair of overhead interties, this discussion focuses on and is specific to this particular
intertie design concept.
Fiberglass poles cannot be climbed using the spur‐and‐belt method commonly employed to climb wood
poles. Instead, a pulley and cable or rope system would be an integral part of the fiberglass pole. The
pulley would be installed in the pole top, and the cable would travel down the pole interior. The line crew
is envisioned to use a harness and winch apparatus to attach to the pole apparatus and use this system to
lift a lineman to the pole top for maintenance.
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
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This approach offers several advantages compared with conventional pole climbing methods.
● The equipment and inherent safety of the approach enables less experienced crews to ascend the
poles.
● Pole‐top maintenance is easier or possible during colder weather or adverse conditions.
● Ascent, descent, and top‐site work is faster because the crew is not as fatigued.
● Work is less physically demanding, reducing the likelihood of fatigue‐related accidents.
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C.5 CONCEPTUAL DESIGN ANALYSIS
The majority of the design analysis for the overhead transmission concepts presented in this study
follows established design practices that are found in industry literature.38 This section discusses specific
aspects of the conceptual design of HVDC systems that are unique to Alaska and warrant more detailed
discussion.
C.5.1 Structural Design
Polarconsult contracted with Line Design Engineering, Inc. (LDE) for assistance in the structural and code
analysis of Alaska‐specific overhead HVDC transmission structure design concepts.
C.5.2 Foundation Design
Polarconsult tasked Golder with developing conceptual foundation designs for the representative soils
and geotechnical conditions discussed in this report. Golder proposed three foundation design concepts
that provide economical foundation options for supporting guyed power poles in the representative
geotechnical conditions. These are summarized below.
● Passively cooled thermoprobe micropiles, installed under the pole to receive compressive
loads. Arctic Foundations, Inc. (AFI) was identified as an experienced manufacturer of such
foundation systems.
● Small‐diameter helical anchors, installed under the pole to receive compressive loads or
installed at the guys to receive tension loads. Thermopiles could be installed adjacent to these
anchors to decrease temperatures in the bearing soils, which will increase the anchor strength.
● Smaller‐diameter (4‐ to 6‐inch) vertical piles for both poles and guys, installed with impact
hammers using smaller tracked rigs. Thermopiles could be installed adjacent to these anchors to
decrease temperatures in the bearing soils and increase pile strength.
Existing conventional foundation methods were maintained for conventional intertie line construction.
This consists of either direct burial of a wood pole in suitable soils or fastening a wood pole to a driven
steel pile in the more difficult geotechnical conditions.
For guyed power poles, a set of three 1½‐inch‐diameter thermoprobe micropiles installed to a depth of
20 feet with a 5‐foot radiator section above ground are used as the conceptual design for the pole base,
and helical anchors are used as the conceptual design for the pole guys.
C.5.3 Analysis of Thermoprobe Performance
Polarconsult contracted with Zarling Aero Engineers (ZAE) to model the seasonal thermal performance of
a passive cooling element such as a thermoprobe micropile. ZAE modeled a warm permafrost condition
analogous to Golder’s geotechnical Profile “C” using thick and thin organic layers and current climate data
for marginal permafrost in the Fairbanks area. Thermoprobes with thermal conductances of 1.0 British
thermal unit (Btu)/hr‐ft‐°F and 2.0 Btu/hr‐ft‐°F were considered.39 ZAE also evaluated the effect of
placing a 4‐inch‐thick layer of rigid insulation on the ground surface within 4 feet of the thermoprobe.
38 Representative publications include RUS, 2001; RUS, 2003a; RUS, 2009; Naidu, 1996; KZK, 2006; Skrotzki, 1980; Southwire,
2008; and Thrash, 2007.
39 The 1.5‐inch‐diameter, 25‐foot‐long thermoprobes installed at the Fairbanks Test Site (see Section C.6 of this appendix) have
an estimated thermal conductance of 0.3 Btu/hr‐ft‐°F (AFI, 2011).
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ZAE repeated this analysis with warmer climate conditions to forecast the performance of the
thermoprobes under a warming climate in the 2060 to 2069 decade. The results of these analyses are
summarized in Table C‐8. ZAE’s technical analysis and report is included as Attachment C‐1 to this
appendix.
Table C‐8 presents the following model results that directly pertain to the structural performance of the
thermoprobes:
1. Maximum depth of the active layer (occurs in late fall). This defines how much of the upper
portion of the thermoprobe is in thawed, structurally weak soils that provided limited lateral
support to the thermopile. For structural analysis, this portion of the thermoprobe is assumed to
be an unsupported column that must be stiff enough to transfer compressive loads from the top of
the thermoprobe down to the permafrost region without buckling.
2. Average maximum temperature of the permafrost 1 foot from the thermopile in early fall
(maximum annual temperature). This defines the minimum strength of the soil around the
thermoprobe and the bearing strength of the thermopile to resist both compressive and tension
loads.
The results of ZAE’s analysis (Table C‐8) are explained below. It is important to emphasize that these
results are specific to the soil parameters, thermoprobe performance, and climate conditions modeled.
Other model inputs may produce significantly different results.
1. Under the geotechnical conditions modeled, a 4‐inch layer of rigid foam insulation installed at the
surface and extending radially out from the thermoprobe for 4 feet can reduce the maximum
depth of the active layer by 1 to 2 feet. Due to the modest structural benefit, expected cost, and
difficulty of installing and maintaining such an insulation assembly, this insulation element is not
included in the conceptual foundation designs.
2. Under all geotechnical conditions modeled, the thermoprobe lowers the soil temperature
immediately surrounding the thermoprobe throughout the year. This effect is most pronounced
during the winter months when the thermoprobe is extracting heat from the soil and cools the soil
by up to 5 °F surrounding the thermoprobe. This cold bulb persists through the summer, resulting
in an end‐of‐summer residual thermal anomaly of a few 1/10ths °F in the soil surrounding the
thermoprobe. This result significantly enhances the compressive and tension capacity of the
thermoprobe during the winter and spring months and produces a lesser (and decreasing)
enhancement through the summer and into fall. The thermoprobe immediately starts cooling the
surrounding soils upon the return of freezing nighttime conditions in the late fall.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC. HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS PHASE II – PROTOTYPING AND TESTING MAY 2012 PAGE C-37 Table C-8 Summary of Results from Thermoprobe Modeling by ZAE Thermoprobe conductance = 1.0 Btu/hr‐ft‐°F Thermoprobe conductance = 2.0 Btu/hr‐ft‐°F Thin Organic LayerThick Organic Layer Thin Organic LayerThick Organic LayerExisting Climate Conditions (Fairbanks, 1971 – 2000) 4” Surface InsulationNo Surface Insulation4” Surface InsulationNo Surface Insulation 4” Surface InsulationNo Surface Insulation4” Surface InsulationNo Surface InsulationMaximum depth of active layer without thermoprobe (at thermoprobe) 1 6.5 feet 3 feet 6.5 feet 3 feet Maximum depth of active layer with thermoprobe (at thermoprobe) 5.1 feet 6.5 feet < 1 foot 3 feet 5 feet 6.0 feet < 1 foot 3 feet Average early winter soil temperature one foot from thermoprobe 30°F 30°F 30°F 30°F 28°F 28°F 28°F 28°F End of summer/early fall temperatures one foot from thermoprobe 30‐35°F 30‐35°F 30‐32°F 30‐34°F 30‐35°F 30‐35°F 29‐33°F 29‐34°F Projected 2060‐2069 Climate Conditions for Fairbanks (+2.7°F increase in annual mean temperature) Maximum depth of active layer without thermoprobe (at thermoprobe) 1 8 feet 8 feet 3.5 feet 3.5 feet NA NA NA NA Maximum depth of active layer with thermoprobe (at thermoprobe) 6.5 feet 7.5 feet 1 foot 3.5 feet NA NA NA NA Average early winter soil temperature one foot from thermoprobe 31°F 31°F 31.5°F 31.5°F NA NA NA NA End of summer/early fall temperatures one foot from thermoprobe 31‐37°F 31‐37°F 31‐34°F 31‐35°F NA NA NA NA See the full ZAE report, Attachment C‐1 to this appendix, for more detailed information. 1 Temperature at 11 feet from thermoprobe, which is the limit of the model graphics in the report. NA: Not analyzed.
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C.5.3.1 Thermoprobe Conceptual Design
AFI developed conceptual thermopile designs based on the structural loads given for the Alaska‐specific
intertie structures. The design and fabrication sheets for the AFI thermopile are included as Attachment
C‐2.
Pole foundations using either a single 3‐inch thermopile or a set of three 1½‐inch thermopiles are both
practical. 1½‐inch thermopiles can be installed by smaller equipment than a 3‐inch pile, although the
material cost and installation time will both be somewhat higher than for a single 3‐inch thermopile. On
some projects, the use of smaller equipment is expected to result in sufficient savings in spite of the
increased material and labor costs.
Figures C‐9 through C‐11 present the adapter plate developed to mate a GFRP pole to three 1½‐inch
thermopiles. Figure C‐8 below shows the prototype installation of this pole foundation design installed at
the foundation test site in Fairbanks. The Fairbanks testing is described in greater detail in Section C.6 of
this appendix.
Figure C-8 Prototype Micro-Thermopile Tripod Pole Foundation
Fairbanks, Alaska. Polarconsult, 2011
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC. HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS PHASE II – PROTOTYPING AND TESTING MAY 2012 PAGE C-39 Figure C-9 Shop Drawing of Prototype GFRP Pole Base Adapter for Micro-Thermopile Foundation (Sheet 1 of 3)
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC. HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS PHASE II – PROTOTYPING AND TESTING MAY 2012 PAGE C-40 Figure C-10 Shop Drawing of Prototype GFRP Pole Base Adapter for Micro-Thermopile Foundation (Sheet 2 of 3)
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC. HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS PHASE II – PROTOTYPING AND TESTING MAY 2012 PAGE C-41 Figure C-11 Shop Drawing of Prototype GFRP Pole Base Adapter for Micro-Thermopile Foundation (Sheet 3 of 3)
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C.5.3.2 Screw Anchor Conceptual Design
Based on the conceptual design analysis prepared by Golder, screw anchors fitted with two flights of 8‐
inch helices and driven to a depth of 10 to 15 feet below the ground surface will be suitable for anchoring
most guys. In the conceptual soils presented by Golder, these anchors can be installed with a torque of
10,000 to 15,000 foot‐pounds. Guys at angle structures or dead ends may require two or more anchors.
Representative screw anchors are shown on Figure C‐12.
Figure C-12 Galvanized Screw Anchors with 8-Inch Flights
Pallet of galvanized screw anchors with 8‐inch flights. Similar anchors are suitable for restraining guys for Alaska‐
specific transmission structures in many challenging soils. (Polarconsult, 2011; Photograph courtesy of Alaska
Foundation Technology, Inc.)
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C.5.4 Electrical Design
C.5.4.1 Conductor
A 1‐MW transmission capacity at 50 kV DC equates to a nominal peak ampacity of 20 amperes. Overload
or fault conditions are higher. The economically allowable conductor losses on the HVDC line were set at
3% losses at 100% nominal capacity. For a 25‐mile, 1‐MW, two‐wire monopolar intertie, this is
approximately equivalent to 1.5 ohms per conductor‐mile. The required conductor resistance is the same
for a monopolar SWER transmission circuit, provided that the grounding grids and earth return pathway
have a total resistance equal to or less than 37.5 ohms.
The structural requirements of the conductor are part of a larger technical and economic analysis of the
overhead system design. For rural Alaska intertie lines, longer spans and fewer foundations will generally
result in lower overall capital costs. This design decision calls for stronger conductors to withstand the
higher stresses from environmental loads and taller poles to maintain ground clearances under maximum
sag conditions.
For conventionally built HVDC intertie design concepts, these design considerations resulted in the
selection of a 4/0 ACSR Penguin conductor for all HVDC circuit configurations.
For Alaska‐specific HVDC intertie design concepts, these design considerations resulted in the selection of
a 19#10 Alumoweld conductor for all HVDC circuit configurations.
C.5.4.2 Insulators
Insulators in DC applications are more susceptible than AC insulators to the accumulation of
contamination on the insulator sheds. This is due to the presence of a static electric field around the high‐
voltage conductor, which attracts charged particles toward the conductor. This attraction of charged
particles results in more particles landing on and contaminating the insulator than occurs on comparable
AC systems. This is because the alternating electric field around an AC conductor does not impart a net
attraction to charged particles.
Periodic rains and other weather events can dislodge these particles from the insulator sheds. Various
special coatings can also help to repel particles. If the insulator provides a sufficiently long leakage path to
accommodate the accumulated contamination, then no action is required. In some climates, it is necessary
to wash the insulators periodically. This can be done from suitably equipped helicopters or line trucks.
On most rural Alaska intertie lines, washing insulators would be cost prohibitive, and when possible, the
insulators should be designed to withstand long‐term accumulation of contamination. Design guidance
for HVDC insulators indicate that insulators rated for 34.5 to 42 kV AC service are adequate for 50 kV DC,
depending on the degree of environmental contamination and self‐cleaning conditions that exist along the
intertie route.40
Due to the wide range of environmental conditions present in Alaska, a very conservative conceptual
insulator design has been adopted to provide a substantial allowance for insulator contamination. In
discussions with insulator manufacturers, insulators rated for 115 kV AC have been selected for the
conceptual design. This provides a leakage path length that is more than 2.7 times the published guidance
for HVDC transmission insulators. Specific projects may be able to realize some cost savings by using
40 Arrillaga, 1998. Page 256‐257.
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lower‐voltage insulators if they are distant from coastal regions (salt spray), active rivers (blowing dust),
glaciers (blowing dust), arid regions (lack of cleansing rains), and similar geographic or climatic
characteristics.
Most HVDC lines are bipolar systems with two high‐voltage conductors (Figure C‐13). A typical economic
design solution for a two‐conductor overhead intertie line uses suspension insulators. In a monopolar
SWER overhead system, the most economical design calls for a line post insulator atop a single structure.
Figure C-13 Typical Bipolar HVDC Transmission Line Using Suspension Insulators
HVDC crossover, North Dakota. Source:
http://upload.wikimedia.org/wikipedia/commons/b/ba/HVDC_Crossover_North‐Dakota.jpg.
At the spans, voltages, and environmental loads considered for this application, a composite line post with
a 3.5‐inch‐diameter pultruded fiberglass core and silicone sheds are necessary to withstand the vertical,
lateral, and longitudinal mechanical loads placed on the insulator. An insulator such as part no. L4‐SN321‐
15U manufactured by NGK, Inc. or similar products are suitable for this application. Certain load
conditions, such as unbalanced shedding of 1‐inch radial ice on a 1,000‐foot span, exceed the rated
structural capacity of this insulator.
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For specific projects, this limitation can be addressed in several ways (e.g., less stringent design loads,
reduced insulator margin, shorter spans, etc.). Manufacturers are developing stronger line post insulators
(4.0‐ and 4.5‐inch cores) that will be adequate for all load combinations considered in this study. It is
estimated that these will be commercially available by 2014 or thereafter.
Alternate insulator configurations can also be used to circumvent the structural limitations of existing line
post insulators. Figures C‐14 through C‐16 present two potential insulator configurations that use
suspension insulators to reduce the loadings on a line post insulator. These configurations can be adapted
for use on any of the conceptual overhead designs presented in this appendix. Suspension insulators are
less costly than the line post insulators; however, these more complicated assemblies will require more
labor to install.
Figure C-14 Typical Tangent Structure Using Post Insulators
Cantilevered wood pole tangent structure for an AC transmission line. Post insulators are used to carry all three‐phase
conductors. The post‐top insulator carries longitudinal and lateral forces in bending, and the two side insulators carry
vertical and longitudinal forces in bending. These applications are similar to those shown on Figure C‐3 and Figure C‐4.
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Figure C-15 Typical Angle Structure Using Suspension and Post Insulators
Guyed steel pole angle structure for an AC transmission line. Suspension insulators are used to carry the conductor
tension, and a post insulator is used to hold the conductor off of the support structure. Available post insulators are not
strong enough to be used as a post‐top insulator (as on Figure C‐4 or C‐14) in this type of application. (Polarconsult,
2012)
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Figure C-16 Typical Tangent Structure Using Suspension and Post Insulators
Cantilevered wood pole tangent structure for a 115 kV AC transmission line. Note the use of a suspension insulator in
tension and post insulator in compression to carry the weight of the conductor. The base of the post insulator is hinged
to allow some longitudinal movement of the conductor. The post insulator also carries most of the lateral wind loads on
the conductor. This insulator configuration can be used for single‐ or double‐wire HVDC circuit configurations. A back
guy could be used to reduce the net moment on the pole and foundation. (Polarconsult, 2012)
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
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PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE C-49
C.6 TESTING OF OVERHEAD DESIGN CONCEPTS
Most elements of the conceptual overhead designs described in this appendix utilize commercially
available and accepted materials, designs, and construction methods. Certain components of the
conceptual designs presented in Section C.5 represent innovations in overhead line design that do not
have a proven record within the utility industry. In order to evaluate the performance of these
components, they were installed at a test site in Fairbanks, Alaska. This section describes the objectives
and installation of the Fairbanks Test Site.
C.6.1 Test Objectives
The primary test objectives of the Fairbanks Test Site are listed below.
1. Demonstrate performance and assembly time of a splice for a constant‐section GFRP utility pole.
2. Demonstrate installation and performance of micro‐thermopile pole foundations.
3. Demonstrate installation and performance of micro‐thermopile guy anchors.
4. Demonstrate installation and performance of screw guy anchors.
5. Demonstrate the installation and performance of the overall guyed GFRP pole structure.
C.6.2 Test Site
The test site is located on private property off Farmer’s Loop Road north of Creamers’ Field in Fairbanks.
The site consists of warm ice‐rich silty permafrost soils. The site has an organic layer consisting of
deciduous shrubs and black spruce. Peat was present at depths of 1 to 5 feet below ground surface. The
active layer in September extended to a depth of 3 feet, with standing water encountered within the
vegetative mat near the surface.
Geotechnical conditions at the site are characteristic of marginal warm permafrost conditions, generally
consistent with conceptual geotechnical profile “C” developed by Golder and described in Section C of this
appendix.
C.6.3 Installation
Key items installed at the test site are described in this section.
C.6.3.1 Soil Temperature Probes
The site has two soil temperature monitoring probes. Each probe is a ¾‐inch PVC pipe inserted into a drill
hole that extends to 25 feet below grade. One hole is located adjacent (1.0 foot away) to the micro‐
thermopile tripod pole foundation and will be used to monitor the thermal effects of the thermopiles and
vegetation clearing. The second hole is located approximately 50 feet away in an undisturbed black
spruce stand and will be used to collect baseline soil temperature data.
C.6.3.2 Glass‐Fiber‐Reinforced Polymer (GFRP) Pole
The site has one 60‐foot‐tall guyed glass‐fiber‐reinforced polymer (GFRP) pole. The GFRP pole has a
round section, is 12 inches in diameter, and has a 0.5‐inch wall. The GFRP pole is manufactured by
Powertrusions, Inc. The GFRP pole consists of a 40‐foot and 20‐foot section connected by a full moment‐
carrying slip‐on external splice. The splice does not require any glue or solvent to develop bearing or
moment capacity. Bearing is carried by physical contact of the butt‐ends of the pole segments. Moment is
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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carried through mechanical contact between the pole and splice walls. The splice is held in place by #14
¼‐inch‐diameter x 1½‐inch‐long zinc plated Teks hex washer head screws driven around the perimeter
of the splice into each pole segment. The pole at the Fairbanks site is in compression. Power line poles
subject to uplift would need to design the splice connection for tension loads.
C.6.3.3 GFRP Pole Foundation
The GFRP pole foundation is a micro‐thermopile tripod with an adapter piece to fit the pole onto the
micro‐thermopiles. Shop drawings of the adapter piece are presented on Figure C‐9 through C‐11. The
adapter piece:
● Features an integral hinge assembly to raise or lower poles in the field,
● Provides generous tolerances for batter angles and placement of the micro‐thermopiles, and
● Provides full flexibility in orientation of the hinge angle relative to the tripod angle (so the pole
can be raised or lowered in line with a guy anchor regardless of how the pole foundation micro‐
thermopiles are oriented.
C.6.3.4 Guys
The GFRP pole is secured by four 3/8‐inch extra‐high‐strength (EHS) guy lines set at 90 degrees to each
other and 45 degrees to ground. The guys and guy hardware is conventional. A FUTEK model LSB4000
load cell is rigged into one guy wire on each axis to measure guy wire tension.
C.6.3.5 Guy Anchors
Four different guy anchors are installed at the Fairbanks site.
1. A 25‐foot‐long by 1½‐inch‐diameter micro‐thermopile, installed at a 45‐degree angle to the
ground surface (directly in‐line with the guy). This anchor resists guy tension solely with skin
friction. The anchor is installed with the top 5 feet above ground as the radiator section.
2. A 25‐foot‐long by 1½‐inch‐diameter micro‐thermopile, installed at a 70‐degree angle to the
ground surface. This reduced angle from vertical is easier to install but places a moment on the
micro‐thermopile.
3. A standard 8‐inch double‐flight screw anchor. The screw anchor was driven 15 feet below ground
surface at a 45‐degree angle, placing the anchor flights approximately 10 feet below grade.
4. A standard 6‐inch swamp anchor. The swamp anchor is screwed into the soil by a drive rod that is
then withdrawn. The anchor attaches to the guy wire via a ground cable. This type of anchor is
less susceptible to frost heave than the three other anchors described above.
C.6.4 Monitoring
Polarconsult will continue to monitor the installation at the test site for performance.
1. Monitor seasonal fluctuations in soil thermal profiles to establish baseline thermal profiles and
the performance of the micro‐thermopiles.
2. Monitor guy wire tensions and differential elevations of guy wires and pole foundation to identify
creep in the foundations.
3. Monitor performance of the GFRP pole and splice.
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Figure C-17 Installing Micro-Thermopile for Guy Anchor
Contractor GeoTek Alaska, Inc. drilling a hole for installation of a micro‐thermopile at a 45‐degree batter angle using a
GeoProbe 8040 series drill rig. The micro‐thermopile will serve as a guy anchor for the prototype guyed GFRP pole
installation at the Fairbanks Test Site. (Polarconsult, 2011).
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Figure C-18 Setting Micro-Thermopile Guy Anchor with Sand Slurry Backfill
Setting micro‐thermopile guy anchor with a sand slurry. (Polarconsult, 2011)
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Figure C-19 Installing Micro-Thermopile for Guy Anchor
Contractor GeoTek Alaska, Inc. drilling a hole for installation of a micro‐thermopile at a 45‐degree batter angle using a
GeoProbe 8040 series drill rig. The micro‐thermopile will serve as a guy anchor for the prototype guyed GFRP pole
installation at the Fairbanks Test Site. (Polarconsult, 2011).
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Figure C-20 Micro-Thermopiles Staged at Fairbanks Test Site for Installation of Prototype
Foundations
1½‐inch‐diameter by 25‐foot‐long micro‐thermopiles used for pole base and guy anchor systems for a prototype guyed
GFRP pole installed at the Fairbanks Test Site. Three micro‐thermopiles are used at the pole base, and one each for two
of the four guy anchors. (Polarconsult, 2011)
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Figure C-21 Micro-Thermopile Tripod for Prototype Pole Foundation
Micro‐thermopile tripod for prototype pole foundation. The fourth pipe at left is a soil temperature monitoring well that
is used to monitor the thermal‐affected zone around the thermopiles. There is a second soil temperature monitoring
probe located approximately 40 feet from the pole base (not shown in photo) that is used to establish the baseline
thermal profile of the site. (Polarconsult, 2011)
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Figure C-22 Installing Helical Screw Anchor for Guy Anchor
Contractor City Electric, Inc. installing a helical screw anchor with two 8‐inch flights. The anchor was driven 15 feet
into the ground at a 45‐degree batter angle. The anchor will be used to secure one of the four guys on the prototype
GFRP pole installed at the Fairbanks Test Site. (Polaconsult, 2011)
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Figure C-23 Guy Attached to Micro-Thermopile Foundation
Guy wire supporting the installed prototype GFRP pole at the Fairbanks Test Site. The guy anchor is a micro‐thermopile
installed at a 20‐degree batter angle. This guy wire includes a load cell to monitor guy wire tension. The load cell reader
is attached to the cell and is visible in the photo (black and yellow device below the guy wire). Polarconsult, 2011.)
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Figure C-24 Assembling the Prototype GFRP Pole Splice
Contractor City Electric, Inc. installing the field splice for the prototype GFRP pole. 40‐foot and 20‐foot GFRP pole
segments were spliced to create the 60‐foot pole erected at the site. The splice slides over the pole segments and carries
moment through contact between the pole and splice walls. Vertical loads are carried through the butt ends of the pole
segments. No glue or adhesive is necessary for the splice to develop the full mechanical strength of the pole. The screws
serve to prevent differential movement between the pole and splice. (Polarconsult, 2011)
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Figure C-25 Installed GFRP Pole, Micro-Thermopiles, and Adapter Plate
Detail of prototype GFRP pole base at the Fairbanks Test Site. The custom‐designed base plate accommodates the
variable angle and location of the three micro‐thermopiles and includes a hinge so the pole can be lowered if needed.
The base plate allows for adjustment of the hinge orientation during installation so a guy anchor can be used to winch
the pole down. (Polarconsult, 2011)
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Figure C-26 Prototype GFRP Pole Foundation During Installation
Detail of prototype GFRP pole base at the Fairbanks Test Site. The adapter plate was adjusted during installation so the
hinge is oriented in line with the guy anchor in the distance (orange flagging). This allows use of the guy anchor to
lower the pole with a winch if needed. (Polarconsult, 2011)
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Figure C-27 Prototype Pole at the Fairbanks Test Site
View of the prototype guyed GFRP pole installed at the Fairbanks Test Site. This photograph is taken at a distance of
approximately 200 yards from the 60‐foot tall pole. (Polarconsult, 2011)
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Figure C-28 Prototype Pole at the Fairbanks Test Site
View of the prototype guyed GFRP pole installed at the Fairbanks Test Site. This photograph is taken at a distance of
approximately 25 yards from the 60‐foot tall pole. The four guys and the pole splice are visible in this photograph
(Polarconsult, 2011)
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APPENDIX C ATTACHMENTS
Attachment C‐1:
Zarling Aero Consulting (ZAE) Thermal Analysis of Thermopile
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Attachment C‐2:
Arctic Foundations, Inc. (AFI) Shop Drawings
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FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC. HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS PHASE II – PROTOTYPING AND TESTING MAY 2012 PAGE C-93 Attachment C.2.1 Arctic Foundations, Inc. (AFI) Shop Drawing for Pile
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC. HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS PHASE II – PROTOTYPING AND TESTING MAY 2012 PAGE C-94 Attachment C.2.2 Arctic Foundations, Inc. (AFI) Shop Drawing for Guy Anchor
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APPENDIX D
CONCEPTUAL DESIGN FOR SUBMARINE CABLES
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TABLE OF CONTENTS
APPENDIX D ATTACHMENT ............................................................................................................................................... 5
ATTACHMENT D‐1: CABLETRICITY HVDC TRANSMISSION SYSTEMS FOR RURAL ALASKA APPLICATIONS DC POWER CABLES
FOR 1–5 MW CONVERTERS ............................................................................................................................................ 5
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APPENDIX D ATTACHMENT
Attachment D‐1:
Cabletricity HVDC Transmission Systems for Rural Alaska Applications DC
Power Cables for 1–5 MW Converters
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE E-1
APPENDIX E
SWER CIRCUITS AND HVDC SYSTEM GROUNDING
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TABLE OF CONTENTS
E.1 SINGLE‐WIRE EARTH RETURN (SWER) CIRCUITS ................................................................................... 7
E.2 SYSTEM GROUNDING ............................................................................................................................................. 7
APPENDIX E ATTACHMENTS ............................................................................................................................................. 9
ATTACHMENT E‐1: HVDC GROUND ELECTRODE OVERVIEW ................................................................................................... 9
ATTACHMENT E‐2: GROUNDING STATION FIGURE ................................................................................................................... 25
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PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE E-5
LIST OF FIGURES
Figure E‐1 Grounding Station .................................................................................................................................... 27
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PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE E-7
E.1 SINGLE‐WIRE EARTH RETURN (SWER) CIRCUITS
The most economical applications of low‐power high‐voltage direct current (HVDC) systems in Alaska
will use monopolar circuits with single‐wire earth return (SWER). Alaska has adopted the National
Electric Safety Code (NESC) to regulate the design and installation of utility grade electric systems. The
NESC does not allow the use of SWER circuits. This rule is based on considerations of life safety
(avoidance of step potential hazards) and economics, as DC SWER circuits can cause accelerated
corrosion of nearby buried metal infrastructure such as pipelines.
SWER circuits are successfully used on AC and DC circuits in many international jurisdictions. In many
rural Alaska applications, the use of HVDC SWER circuits is a safe and appropriate technology that can
save significant costs. There is a process to obtain waivers to the NESC rules that will permit the
installation of SWER circuits. Two AC SWER systems built in the 1980s successfully obtained such
waivers.
Polarconsult subcontracted with the Manitoba HVDC Research Centre (MHRC) to prepare a letter report
summarizing the technical and code issues associated with the appropriate use of SWER circuits. That
report is included as Attachment E‐1 to this appendix.
E.2 SYSTEM GROUNDING
A conceptual design for a low‐power HVDC grounding station suitable for use with the proposed HVDC
transmission system is included in the attachment to this appendix.
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APPENDIX E ATTACHMENTS
Attachment E‐1:
HVDC Ground Electrode Overview
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MAY 2012 PAGE E-24
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MAY 2012 PAGE E-25
Attachment E‐2:
Grounding Station Figure
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PHASE II – PROTOTYPING AND TESTING
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Figure E-1 Grounding Station
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PHASE II – PROTOTYPING AND TESTING
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MAY 2012 PAGE F-1
APPENDIX F
HVDC POWER CONVERTER DEVELOPMENT
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TABLE OF CONTENTS
F.1 CONVERTER DEVELOPMENT ............................................................................................................................. 7
F.1.1 INTRODUCTION .................................................................................................................................................................. 7
F.1.2 CONVERTER SIZING ANALYSIS ........................................................................................................................................ 7
F.1.3 CONVERTER TEST RESULTS ........................................................................................................................................... 10
F.1.3.1 Fiber Optic Triggering System in High‐Voltage Tank .............................................................. 10
F.1.3.2 IGBT Switches in High‐Voltage Tank ............................................................................................... 10
APPENDIX F ATTACHMENTS ........................................................................................................................................... 13
ATTACHMENT F‐1: PPS HVDC POWER CONVERTER REPORT ............................................................................................... 13
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MAY 2012 PAGE F-5
LIST OF FIGURES
Figure F‐1 Typical Load Duration Profile for an Alaska Village .................................................................... 8
Figure F‐2 Peak Loads in Alaska Villages (2007 – 2009) ................................................................................. 9
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MAY 2012 PAGE F-7
F.1 CONVERTER DEVELOPMENT
F.1.1 Introduction
The high‐voltage direct current (HVDC) converter developed under this project is a 1‐megawatt (MW)
power converter capable of bidirectional power conversion between three‐phase 480 volts alternating
current (VAC) and 50 kilovolts (kV) HVDC. The converter capacity is appropriate to supply the electrical
needs of most Alaska villages. In contrast, existing HVDC power converter systems are only cost effective
at much larger transmission capacities, starting at approximately 50 MW and extending up to 1,000s of
MWs of capacity.
Multiple HVDC converters can be “paralleled” to achieve higher power transmission capacities where
needed. Based on Phase II development work, the price of a commercially produced 1‐MW HVDC power
converter is estimated to be $250,000. At least two 1‐MW converters are needed for a complete 1‐MW
HVDC transmission system.
This appendix presents Princeton Power Systems, Inc.’s (PPS’s) final deliverables for converter
specification, design, and test plan under Phase II of the HVDC technology development program
(Attachment F‐1).
PPS has successfully demonstrated operation of the prototype converters at the full 50 kV DC and power
flow in both inverter (HVDC to AC) mode and rectifier (AC to HVDC) mode in a controlled test facility
setting. These testing efforts validate the design and basic functionality of the converter.
In the course of testing, PPS identified two hardware problems that prevented full‐power testing of the
prototype converters. PPS has investigated these problems and identified the actions necessary to correct
both problems. The problems and solutions are discussed in Attachment F‐1 to this appendix.
PPS is continuing to work on the hardware modifications needed to correct the prior technical problems.
Due to the long lead‐time to obtain suitable replacement insulated gate bipolar transistor (IGBT)
switches, the converter modifications and testing are not expected to be completed until late 2012. PPS
will issue a supplemental report detailing the results of final Phase II testing when testing is completed.
This supplemental report and the fully operational converters will be PPS’s final deliverable under Phase
II of this research and development (R&D) project.
F.1.2 Converter Sizing Analysis
The electrical load characteristics of rural Alaskan communities that are the target of this project were
evaluated. The capacity of the HVDC intertie system was based on the likely peak loads and load duration
profiles of the selected communities.
The duration of peak loads provides an economic basis for design capacity of the intertie. In general, the
intertie is designed to minimize the line losses at peak loads. The load duration profile for Hooper Bay is
presented on Figure F‐1. This profile is representative of rural Alaskan communities with a peak load of
760 kW, and will generally apply to other communities. Some communities, such as those with fish
processors, will have load profiles different than that shown on Figure F‐1.
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MAY 2012 PAGE F-8
Figure F-1 Typical Load Duration Profile for an Alaska Village
0
100
200
300
400
500
600
700
800
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Percent of Time Load is Equaled or ExceededSystem Load in kW
Polarconsult, 2012 41
The peak loads of rural Alaska communities participating in the Power Cost Equalization (PCE) program
were reviewed to determine the appropriate power capacity for the HVDC interties considered for this
study. The distribution of peak loads is presented on Figure F‐2.
Based on this analysis, a 1‐MW power intertie is an appropriate conceptual capacity for the majority of
rural Alaska interties. For maximum reliability and flexibility, the power converter specifications call for a
1‐MW unit comprised of two 500‐kW modules operating in parallel. The converter modules can be
connected to operate in parallel, thus providing additional capacity up to a few MWs where necessary.
Interties designed for more than a few MWs may warrant reevaluation of the AC interface voltage (480
volts [V] for the 500‐kW power converter module).
41 Data generated for Hooper Bay using the Alaska Village Electric Load Calculator (NREL, 2005)
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC. HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS PHASE II – PROTOTYPING AND TESTING MAY 2012 PAGE F-9 Figure F-2 Peak Loads in Alaska Villages (2007 – 2009) 010002000300040005000Point LayNaknekBethel / OscarvilleCraigKotzebueDillinghamHainesAlakanukTok / TanacrossAmblerGalenaDeeringPoint HopeSt. PaulNuiqsutWalesKaktovikSelawikAtmautluakFort YukonKasiglukHooper BayToksook BayAniakTogiakMountain VillageChevakGambellKipnukNapaskiakKotlikPilot StationBucklandOuzinkieNew StuyahokShishmarefGustavusKwigillingokMarshallHealy LakeKongiganakStebbinsNorthwayManokotakMekoryukTellerHusliaElfin CoveNunapitchukKokhanok BayTukuksakShaktoolikBeaverHughesTenakee SpringsMintoNunam IquaGoodnews BayPort AlsworthLevelockPilot PointEagle / Eagle VillageGraylingAtkaRubySleetmuteManley Hot SpringsCrooked CreekChuathbalukChignik LakeLime VillageTetlinTakotnaVenetieMentastaCirclePedro BayIgiugigKarlukRed DevilAdakCentralDot LakeEkwokKakeKobukNapakiakTununakCommunityPeak Power Demand (kW)(2) 1 MW HVDC CONVERTERS USED FOR BIPOLAR INTERTIE, ADEQUATE FOR 82% OF COMMUNITIES.1 MW HVDC CONVERTER, ADEQUATE FOR 76% OF COMMUNITIES.1 MW HVDC CONVERTER WITH 500KW MODULE FAILURE, ADEQUATE FOR 60% OF COMMUNITIES.Source: 2009 Power Cost Equalization Data, Alaska Energy Authority
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE F-10
F.1.3 Converter Test Results
In the course of testing the prototype converters, PPS has successfully demonstrated operation at the full
50 kV DC and power flow in both inverter (HVDC to AC) mode and rectifier (AC to HVDC) mode. In the
course of testing, PPS identified two hardware problems that prevented completion of Phase II testing of
the prototype converters, including demonstration of full power operation. PPS has investigated these
problems and identified the actions necessary to correct both problems. The problems and solutions are
summarized below.
F.1.3.1 Fiber Optic Triggering System in High‐Voltage Tank
A fiber optic network is used to trigger the solid‐state IGBT switches inside the high‐voltage tank. Testing
revealed problems with the triggering timing and reliability of this triggering system. Investigation
determined that the lenses used in the fiber optic system exhibit excessively high signal loss, causing the
observed timing and reliability issues. PPS has identified and tested different lenses and is proceeding to
replace the lenses in both prototype converter modules to solve this problem.
F.1.3.2 IGBT Switches in High‐Voltage Tank
The IGBT switches in the high‐voltage tank were found to enter thermal runaway when the prototype
converter is operated at low‐power levels in inverter (HVDC to AC) mode. Investigation has determined
that these switches do not perform in accordance with the manufacturer’s specifications. Consultations
with the manufacturer has not produced an acceptable remedy, and PPS has concluded that these IGBTs
cannot be used for this application. PPS has identified alternate IGBTs that meet the technical and
economic criteria of this project, and is proceeding to upgrade the converters with these switches.
Because the switches operate at a different voltage than the original switches and have a different form
factor, redesign of the high‐voltage stage boards is necessary.
Because of the hardware problems identified, PPS has not yet completed converter testing. Final testing is
pending receipt of new IGBTs.
Figure F‐3 shows a simplified schematic illustrating the current development status of the converter’s
basic functional modes.
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Figure F-3 Simplified Schematic Illustrating Technical Progress
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APPENDIX F ATTACHMENTS
Attachment F‐1:
PPS HVDC Power Converter Report
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APPENDIX G
HVDC SYSTEM PROTECTION, CONTROLS, AND COMMUNICATIONS
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TABLE OF CONTENTS
G.1 INTRODUCTION ........................................................................................................................................................ 7
G.1.1 POINT‐TO‐POINT SYSTEMS ............................................................................................................................................. 7
G.1.2 MULTITERMINAL HVDC (MTDC) SYSTEMS ............................................................................................................... 7
G.2 PROTECTIVE HARDWARE ................................................................................................................................... 7
G.3 COMMUNICATIONS ................................................................................................................................................. 7
G.3.1 FAULT DETECTION ............................................................................................................................................................ 8
G.3.2 INFRASTRUCTURE .............................................................................................................................................................. 8
G.4 OVERHEAD INTERTIE COMMUNICATION OPTIONS ................................................................................ 9
G.4.1 OPTICAL GROUND WIRE .................................................................................................................................................. 9
G.4.2 POWER LINE CARRIER ...................................................................................................................................................... 9
G.4.3 WRAPPED FIBER‐OPTIC CABLE ...................................................................................................................................... 9
G.4.4 SEPARATE TELECOM UNDERBUILD ................................................................................................................................ 9
G.5 UNDERGROUND CABLE INTERTIE OPTIONS .............................................................................................. 9
G.6 SUBMARINE CABLE INTERTIE OPTIONS .................................................................................................... 10
G.7 BROADBAND INTEGRATION ............................................................................................................................ 10
APPENDIX G ATTACHMENTS ........................................................................................................................................... 11
ATTACHMENT G‐1: MHRC TASK 3, HVDC STATION HARDWARE RECOMMENDATIONS .................................................. 11
ATTACHMENT G‐2: MHRC TASK 2, MULTI‐TERMINAL HVDC TECHNICAL REVIEW ........................................................ 25
ATTACHMENT G‐3: MHRC TASK 5, CARRIER COMMUNICATIONS ........................................................................................ 45
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LIST OF TABLES
Table G‐1 Communications Options with HVDC Interties ......................................................................... G‐8
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G.1 INTRODUCTION
This appendix discusses electrical protection, controls, and communications requirements needed to
operate the high‐voltage direct current (HVDC) systems discussed in this report. There are certain
minimum protection, control, and communication provisions required of any HVDC system.
In its simplest form, the protection, controls, and communications provisions may be manually operated.
This approach is simpler to manage and less costly to install and maintain than fully automated systems,
but is generally limited to point‐to‐point interties.
The protection, controls, and communications needs of more complex multiterminal HVDC (MTDC)
systems requires the use of automated controls for operation. The requirement for automated capabilities
are more costly and complicated to operate.
G.1.1 Point‐to‐Point Systems
Many rural HVDC interties may benefit from a point‐to‐point HVDC system. Low‐power (<1 MW) point‐
to‐point monopolar HVDC systems can automatically regulate power flow over the HVDC system by
monitoring the HVDC voltage. No communications between the converters are needed to achieve this
basic power transfer function. Existing commercial telecommunications networks in the communities can
be used to provide some degree of monitoring and control function.
G.1.2 Multiterminal HVDC (MTDC) Systems
MTDC networks by definition have more than two HVDC converter stations connected to a given HVDC
line. Each of the converter stations is capable of adding or subtracting power from the HVDC line.
MTDC networks are projected to be the lowest cost intertie solution for many of the rural energy
networks under consideration. These regions include interconnection of several southeast communities,
the adjacent communities in the Yukon‐Kuskokwim Delta, and others in the Bristol Bay area. Accordingly,
the technical feasibility of MTDC networks is of particular interest for Alaska’s utility industry.
G.2 PROTECTIVE HARDWARE
Recommendations prepared by the Manitoba HVDC Research Centre (MHRC) discuss the general DC‐side
HVDC converter station hardware necessary for basic operation and protection of the HVDC system. This
information is presented in Attachment G‐1 to this appendix and is titled “Technical Note on HVDC Station
Hardware.”
Protective AC‐side hardware will include fuses or breakers, disconnects, and controls as needed to
integrate with the local generating plant. Project‐specific design is necessary as these interfaces can range
from basic and manually operated to highly integrated and automated, depending on the needs of the
particular application. The power converters developed by PPS support standard communication
protocols to allow integration with overall control systems.
G.3 COMMUNICATIONS
Communications are used for monitoring of converter station status, economic dispatch of distributed
generation assets, fault detection on the HVDC network, and related utility functions. Systems often
include dedicated voice and data circuits to facilitate communications between different parts of the
utility transmission network.
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G.3.1 Fault Detection
Without differential current monitoring between the HVDC converter stations, if the total current into the
HVDC system (fault current + load current) is less than the rated system current (20 amperes for a 1‐MW
intertie), the rectifying converter will not be able to distinguish the fault load from a normal load and will
continue to input power into the HVDC line to maintain the HVDC voltage. If the fault current is high
enough to exceed the capacity of the rectifying converter, then the converter will trip and announce a
fault.
The result is that a low impedance fault can generally be detected by the anomalously high power draw,
whereas a high impedance fault can remain undetected indefinitely with this scheme. Timely detection
and correction is therefore desirable where practical.
AC systems experience similar problems detecting high impedance faults, so this type of risk is not
without precedent on utility systems. The remoteness and lack of people in the vicinity of these
transmission lines is a factor that should be considered when utilities evaluate this risk. A project‐specific
analysis should be conducted for every intertie to evaluate the cost of fault detection capabilities against
the risks associated with undetected faults.
Detection of persistent high impedance faults requires, at a minimum, slow‐speed communication
between the converter stations and differential current monitoring. If the fault impedance is so high that
the fault current is below the error of the differential current detection method (as could be the case for a
downed conductor lying on ice, for example), the fault may remain unnoticed even with this detection
regime in place. The only practical way to identify such faults is by physical inspection of the intertie line.
Fault detection is discussed in the MHRC Technical Note on HVDC Station Hardware Recommendations
included as Attachment G‐1 to this appendix.
G.3.2 Infrastructure
All remote Alaska communities have access to basic telephone service and broadband internet service. At
a minimum, these services are provided through geosynchronous satellite platforms. Depending on the
project location, communities may be served by existing microwave relay systems, copper wire networks,
fiber‐optic networks, or a combination of these.
The slowest communication option available statewide is geosynchronous satellite‐based
communications with an inherent latency of at least 250 milliseconds for one‐way communications. This
latency arises from the travel time for a signal to reach the orbiting satellite and return to earth. Signal
processing at the Earth stations or aboard the satellite add to this latency.
This communications method would be sufficient for a basic differential current monitoring protocol and
for certain supervisory control and data acquisition (SCADA) functions for an HVDC intertie.
Options for integrated dedicated communications circuits are discussed in ‘Technical Note on Carrier
Communications,” prepared by MHRC, included as Attachment G‐3 to this appendix.
The cost‐effectiveness of such options will depend on the type of HVDC intertie, and on the specific
configuration of the HVDC line. Table G‐1 summarizes the three basic HVDC intertie configurations and
potentially suitable communications technologies for each.
Table G-1 Communications Options with HVDC Interties
Intertie Type Communications Option
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Overhead Conductor Optical Ground Wire (OPGW)
Carrier
Wrapped fiber-optic cable
Separate telecom underbuild
Underground Cable Separate fiber-optic cable in same trench
Fiber-optic circuit bundled into power cable
Submarine Cable Fiber-optic cable in conductor tube
Fiber-optic cable in armor strand
G.4 OVERHEAD INTERTIE COMMUNICATION OPTIONS
G.4.1 Optical Ground Wire
Optical ground wire (OPGW) is a type of electrical conductor that has aluminum conductor strands
surrounding a stainless‐steel tube at the conductor’s core. Optical fibers are routed through the stainless‐
steel tube. OPGW is commonly used as an overhead grounding wire on AC transmission towers for
lightning protection.
Depending on the application, OPGW may be suitable for use as the current‐carrying conductor on an
HVDC transmission line. One potentially significant drawback would be the increased complexity of
repairing conductor breaks due to the stainless‐steel tube and optical fibers. The need for specially
trained personnel and equipment to repair this type of conductor could significantly delay the repair of a
conductor break, reducing the reliability of the transmission line.
The MHRC Technical Note included as Attachment G‐3 to this appendix discusses OPGW applications in
more detail.
G.4.2 Power Line Carrier
Power line carrier (PLC) is a means of using a current‐carrying conductor in an intertie circuit to carry a
data signal as well. A coil is used to magnetically induce a data waveform onto the conductor, and a
second coil is used to receive the waveform. PLC systems have been implemented on HVDC circuits and
are discussed in the MHRC Technical Note in Attachment G‐3.
G.4.3 Wrapped Fiber‐Optic Cable
Optical fiber packages are available that can be wrapped over a messenger wire, such as the power
conductor. There are two potential drawbacks with this option. The first is that the optical fiber cable
would increase the wind exposure and icing surface of the conductor, increasing environmental loadings
on the overhead system. The second is that the presence of the optical fiber cable would complicate the
repair of broken conductors.
G.4.4 Separate Telecom Underbuild
Depending on the type of overhead line construction used for the HVDC intertie line, a conventional
telecommunications underbuild may be appropriate. This could use fiber or copper depending on the
specific circumstances.
G.5 UNDERGROUND CABLE INTERTIE OPTIONS
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The most straightforward means of adding communications to an underground cable HVDC intertie is to
include a separate fiber‐optic or copper cable. Fiber optics would be preferred if a single‐wire earth
return (SWER) circuit is used, as it would not pick up the return current. Conventional design and
construction practices are suitable for installation of co‐located underground communication and power
cables.
G.6 SUBMARINE CABLE INTERTIE OPTIONS
There are three general options for bundling telecommunications with submarine power cables. All three
utilize fiber optics, and are accepted practice for submarine power and/or telecommunication cables.
These methods are:
● Replacing one or more of the armor wires on the submarine cable with a hollow stainless‐steel tube
and routing optical fibers through the tube(s).
● Utilizing a hollow copper tube as the current‐carrying conductor and routing optical fibers within the
copper tube. This is a common cable construction on transoceanic fiber‐optic cables.
● Inserting a stainless‐steel tube between two layers of the submarine cable, typically between the lead
sheath (if so equipped) and the polyethylene outer cable jacket. Optical fibers are routed through this
tube.
G.7 BROADBAND INTEGRATION
There is an opportunity to integrate broadband communications with certain HVDC intertie projects.
Where feasible, combining power and telecommunications connectivity into a single project can
significantly increase the benefits of an intertie project and deliver both capabilities at a lower cost than
possible through individual projects.
This opportunity is particularly promising for underground and submarine cable applications. In many
applications, the incremental cost of including a fiber optic bundle with either power cable is expected to
be modest compared to the resulting benefits. Attachment D‐1 discusses this opportunity in the context of
submarine cables.
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APPENDIX G ATTACHMENTS
Attachment G‐1:
MHRC Task 3, HVDC Station Hardware Recommendations
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Attachment G‐2:
MHRC Task 2, Multi‐Terminal HVDC Technical Review
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Attachment G‐3:
MHRC Task 5, Carrier Communications
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APPENDIX H
CANDIDATE HVDC SYSTEM DEMONSTRATION PROJECTS
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TABLE OF CONTENTS
H.1 INTRODUCTION ........................................................................................................................................................ 7
H.2 DEMONSTRATION PROJECT OBJECTIVES ..................................................................................................... 7
H.3 CRITERIA FOR DEMONSTRATION PROJECT SITES ................................................................................... 8
H.4 POTENTIAL DEMONSTRATION PROJECTS ................................................................................................. 10
H.4.1 SUMMARY OF PROJECTS CONSIDERED ......................................................................................................................... 10
H.4.2 HVDC DEMONSTRATION PROJECTS ON EXISTING AC DISTRIBUTION LINES ....................................................... 12
H.4.2.1 Dillingham to Aleknagik AC Line Conversion (Demonstration Only) ............................... 12
H.4.2.2 Eureka AC Line Conversion (Demonstration Only) .................................................................. 12
H.4.2.3 Hope Substation to Hope AC Line Conversion (Demonstration Only) ............................. 12
H.4.2.4 Homer – Seldovia AC Line Conversion (Demonstration Only) ............................................ 13
H.4.3 HVDC DEMONSTRATION PROJECTS ON NEW AC DISTRIBUTION LINE EXTENSIONS ......................................... 13
H.4.3.1 GVEA Phillips Road Line Extension .................................................................................................. 14
H.4.3.2 GVEA Cummings Road Line Extension ........................................................................................... 14
H.4.3.3 MEA to Independence Mine Line Extension ................................................................................. 14
H.4.4 HVDC INTERTIE PROJECTS ........................................................................................................................................... 15
H.4.4.1 Barrow to Atqasuk HVDC Intertie ..................................................................................................... 15
H.4.4.2 Nome to Teller and Brevig Mission HVDC Intertie .................................................................... 15
H.4.4.3 Pilgrim Hot Springs to Nome HVDC Intertie ................................................................................ 15
H.4.4.4 St. Michaels – Stebbins HVDC Intertie ............................................................................................. 16
H.4.4.5 St. Mary’s to Mountain Village HVDC Intertie .............................................................................. 16
H.4.4.6 Dillingham to Manokotak HVDC Intertie ....................................................................................... 16
H.4.4.7 New Stuyahok – Ekwok HVDC Intertie ........................................................................................... 16
H.4.4.8 Kodiak – Ouzinkie HVDC Intertie ...................................................................................................... 16
H.4.4.9 Green’s Creek to Hoonah HVDC Intertie ........................................................................................ 17
H.4.4.10 Petersburg to Kake HVDC Intertie .................................................................................................... 17
H.4.4.11 Gustavus to Glacier Bay National Park Intertie (HVDC Demonstration Only) .............. 17
H.4.5 PROJECT MAPS ................................................................................................................................................................. 18
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LIST OF TABLES
Table H‐1 Types of HVDC Demonstration Projects and Factors for Each ................................................ 9
Table H‐2 Potential HVDC Demonstration Projects ........................................................................................ 10
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LIST OF FIGURES
Figure H‐1 Location Map for Potential Demonstration Project Sites ........................................................ 11
Figure H‐2 Vicinity Map for Demonstration Projects near Dillingham ..................................................... 18
Figure H‐3 Vicinity Map for Eureka AC Line Conversion ................................................................................ 19
Figure H‐4 Vicinity Map for Hope AC Line Conversion ................................................................................... 20
Figure H‐5 Vicinity Map for Seldovia AC Line Conversion ............................................................................. 21
Figure H‐6 Vicinity Map for Delta Junction AC Line Extension .................................................................... 22
Figure H‐7 Vicinity Map for Deltana AC Line Extension ................................................................................. 23
Figure H‐8 Vicinity Map for Independence Mine AC Line Extension ......................................................... 24
Figure H‐9 Vicinity Map for Barrow – Atqasuk HVDC Intertie ..................................................................... 25
Figure H‐10 Vicinity Map for Demonstration Projects near Nome ............................................................... 26
Figure H‐11 Vicinity Map for St. Michaels – Stebbins HVDC Intertie ........................................................... 27
Figure H‐12 Vicinity Map for St. Mary’s – Mountain Village HVDC Intertie .............................................. 28
Figure H‐13 Vicinity Map for New Stuyahok – Ekwok HVDC Intertie .......................................................... 29
Figure H‐14 Vicinity Map for Kodiak – Ouzinkie HVDC Intertie ..................................................................... 30
Figure H‐15 Vicinity Map for Gustavus and Hoonah HVDC Interties ........................................................... 31
Figure H‐16 Vicinity Map for Kake – Petersburg HVDC Intertie .................................................................... 31
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H.1 INTRODUCTION
This report includes the evaluation of potential projects for demonstration of the high‐voltage direct
current (HVDC) technology in Phase III. This effort consisted of the following major activities:
● Defining the primary objectives of a demonstration project;
● Defining the key criteria for candidate projects;
● Identifying potential intertie projects;
● Contacting local stakeholders to gather information about those projects; and
● Evaluating the projects for suitability as a demonstration of this HVDC technology.
This appendix summarizes and presents the findings from these activities. A specific site has not been
selected for a demonstration project at this time. Polarconsult will continue to work with the various
project stakeholders to identify a specific demonstration project in the future.
H.2 DEMONSTRATION PROJECT OBJECTIVES
Polarconsult worked with the Stakeholder’s Advisory Group (SAG), individual stakeholders, Polarconsult
subcontractors, and other interested entities over the course of Phase II to refine the objectives of the
Phase III demonstration project for the proposed HVDC system.
Defining these objectives was a major topic of discussion at the 2nd SAG Meeting, held in Anchorage on
January 14, 2011. A series of conference calls were held with members of the SAG in January and
February 2011 to refine the objectives of the demonstration project and the candidate sites identified by
Polarconsult.
These efforts established the following as key objectives of the demonstration project:
● Facilitate expeditious advancement of the proposed HVDC system. A demonstration project that
cannot be implemented for years due to prohibitive cost, regulatory impediments, or similar
factors could unduly delay commercial acceptance of the system and widespread deployment in
Alaska.
● Demonstrate to stakeholders (Alaska utilities, policy makers, regulators, etc.) that the HVDC
converter is functional, robust, and practical under the logistical, electrical, and environmental
operating conditions typical of rural Alaska applications.
● Demonstrate that innovative aspects of the transmission line construction, such as use of single‐
wire earth return (SWER) circuits in permafrost regions, new overhead line designs or materials,
and similar system elements are reliable, cost‐effective, and appropriate for rural Alaska intertie
applications.
One of the key insights provided by the SAG was that the commercialization plan for the proposed system,
including the demonstration phase, should be designed in a measured manner that incrementally
demonstrates and proves up the various technical aspects of the system. It was suggested that a single
overly ambitious demonstration project that features several innovative technologies increases the risk
that any one noncritical technical failure may become interpreted as a failure of the overall system.
The goal of Phase III will include full testing of the converter system, including the manufacturer and
third‐party functional, compliance, and performance testing needed to move the converter technology
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from advanced prototypes to a commercial product. Phase III will also include a full scale field
demonstration of the HVDC technology on a utility system in Alaska. The specific project details are
dependant on the candidate location selected for the intertie. Phase III is intended to be the final proof‐of‐
concept project, to be followed by commercial deployment of the system.
H.3 CRITERIA FOR DEMONSTRATION PROJECT SITES
Phase III demonstrations will present a fully functional real‐world HVDC transmission line using the
converter technology developed in this project. Available inventories of Alaska intertie candidates are
presented in Distributing Alaska’s Power (WH Pacific, 2008) and Rural Alaska Electric Utility Interties
Survey (Neubauer, 1997).
Polarconsult conducted an extensive review of potential candidate demonstration projects, starting from
these resources and other current information. The resulting list of potential demonstration projects is
not comprehensive, as there are numerous opportunities for rural Alaska power interties, but it does
provide a representative selection of geographic and technical criteria for demonstration sites. Three
types of demonstration projects were considered, listed below. Key factors about the suitability of these
types of projects are summarized in Table H‐1.
1. New Rural Alaska HVDC Intertie. This option would be a fully functional HVDC intertie
demonstration. It would consist of building a new intertie between two Alaska villages, or
possibly between a larger grid and a village.
2. New AC Distribution Line Extension Operated as HVDC for Trial Period. This option would be
a new alternating current (AC) distribution line extension from an existing system to a new area.
The line extension would be operated as an HVDC line for the demonstration period, and then
converted to AC after the demonstration project concluded.
3. Existing AC Distribution Line Extension, Converted to HVDC for Demonstration Then
Switched Back to AC. This option would convert an existing AC distribution line to HVDC for the
demonstration project. The line would be converted back to AC after the demonstration project
concluded.
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Table H-1 Types of HVDC Demonstration Projects and Factors for Each
Projects
Factors
Permanent HVDC Intertie
Between Two Alaska
Villages
(Operate as HVDC)
AC Distribution System
Extension
(Operate as HVDC, then
convert to AC)
Existing AC Distribution
Line
(Convert to HVDC, then
revert to AC)
Function Intertie limited to power transmission (no services along intertie route)
Power
Capacity Peak load limited to 500 kW (to utilize existing prototype converters)
Cost & Length
Intertie length of 10+ miles
to achieve cost savings
over an AC intertie
Minimize intertie length (to maintain affordable budget and
help avoid funding delays)
Schedule
3 to 5+ years
Requires (design,
permitting, right-of-way,
funding, etc.)
1-3+ years
(May require right-of-way
acquisition, design, permitting,
funding, etc.)
+/- 1 year
(Existing right-of-way,
should require fewer
permits and design,
funding, etc.)
Benefits
1. HVDC demonstration.
2. New intertie lowers utility
costs to both communities.
1. HVDC demonstration.
2. Utility/public receive an AC
line extension.
1. HVDC demonstration
only. Hosting utility incurs
costs and customers incur
service interruptions.
Organizational
Complexity
Two utilities involved, may
require RCA involvement
and regulatory oversight.
Single utility involvement (to
reduce interconnection or
regulatory issues).
Single utility involvement (to
reduce interconnection or
regulatory issues).
Technical
Intertie connections at
480-V bus of existing
power plants.
Intertie connections at
distribution voltage. Step
up/down transformers required.
Intertie connections at
distribution voltage. Step
up/down transformers
required.
kW: kilowatt
RCA: Regulatory Commission of Alaska
V: volt
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MAY 2012 PAGE H-10
H.4 POTENTIAL DEMONSTRATION PROJECTS
H.4.1 Summary of Projects Considered
The interties projects reviewed by Polarconsult are listed by category in Table H‐2 and shown on Figure
H‐1. More detailed information and preliminary maps of potential intertie routes are provided on the
following pages.
Table H-2 Potential HVDC Demonstration Projects
Rural Alaska Microgrids Major Alaska Grids
New HVDC Intertie
Build as HVDC; keep as HVDC
after demonstration.
Barrow – Atqasuk (NSB)
Pilgrim Hot Springs – Nome (NJUS)
St. Mary’s – Mountain Village – Pilot
Station (AVEC)
Dillingham – Manokotak (NEC)
New Stukahok – Ekwok (AVEC)
Kodiak – Ouzinkie (KEA - OED)
Kake – Petersburg (IPEC/SEAPA)
Hoonah – Green’s Creek (IPEC/
AEL&P)
AC Line Extension
Build as HVDC; convert to AC
after demonstration.
Gustavus – Glacier Bay Nat’l Park
(GEC) Delta Junction (GVEA)
Deltana (GVEA)
Independence Mine (MEA)
Existing AC Line
Demonstration
Convert to HVDC; revert to AC
after demonstration.
Dillingham – Aleknagik (NEC)
Glennallen – Eureka (CVEA)
Canyon Creek – Hope (CEA)
Homer – Seldovia (HEA)
Acronyms and Abbreviations:
NEC Nushagak Electric Cooperative, Inc.
NSB North Slope Borough
NJUS Nome Joint Utility Service
IPEC Inside Passage Electric Cooperative, Inc.
SEAPA Southeast Alaska Power Agency
GEC Gustavus Electric Company
AVEC Alaska Village electric Cooperative, Inc.
CEA Chugach Electric Association, Inc.
HEA Homer Electric Association, Inc.
CVEA Copper Valley Electric Association, Inc.
KEA Kodiak Electric Association, Inc.
OED City of Ouzinkie Electric Department
MEA Matanuska Electric Association, Inc.
GVEA Golden Valley Electric Association, Inc.
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Figure H-1 Location Map for Potential Demonstration Project Sites
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PHASE II – PROTOTYPING AND TESTING
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H.4.2 HVDC Demonstration Projects on Existing AC Distribution Lines
This section provides overviews of potential HVDC demonstration projects that would be implemented on
existing AC distribution lines. The AC line would be converted to HVDC service for the demonstration
project, and after the HVDC demonstration is completed, the line would be reverted to AC service. The
candidate interties are organized geographically, moving from northwest to southeast.
H.4.2.1 Dillingham to Aleknagik AC Line Conversion (Demonstration Only)
This is an existing, approximately 25‐mile‐long, three‐phase AC intertie that provides electric service to
Aleknagik from Nushagak Electric Cooperative’s diesel generators in Dillingham (Figure H‐2). The line is
understood to be of standard Rural Utilities Service (RUS) construction, insulated to 34.5 kilovolts (kV)
but operated as a 7.2/12.4‐kV intertie. This existing line would be converted to HVDC operation for a
demonstration period, and then reverted to normal AC operation after the demonstration is completed.
The load in Aleknagik is not known. If it exceeds 500 kilovolt‐amperes (kVA), then either additional
intertie capacity or diesel generators in Aleknagik would be required.
The existing insulators on the intertie should be sufficient for service at 50 kV DC. Because the line is
insulated at 34.5 kV (approximately equal to 60 kV DC), there may be issues with buildup of
contamination under a static DC electric field leading to arcing over the insulators. If this became an issue,
the insulators would need to be cleaned. Analysis is warranted to see if the HVDC intertie voltage should
be reduced to avoid this problem. Voltage reduction would also decrease the power throughput capability
of the HVDC converters.
H.4.2.2 Eureka AC Line Conversion (Demonstration Only)
This is an existing, approximately 50‐mile‐long, single‐phase, 14.4‐kV distribution line owned and
operated by Copper Valley Electric Association, Inc. (CVEA) serving the communities and residents west
of Glennallen, Alaska (Figure H‐3). The demonstration project would consist of converting a segment of
this line to HVDC operation for the demonstration period, then converting it back to AC operation.
The geotechnical conditions along this line are believed to be favorable for testing a SWER configuration
in permafrost soils although an appropriate line segment would need to be identified for SWER operation.
The peak load on the HVDC segment of the line would depend on where the demonstration would take
place along the line. A peak load of 167 kVA or less would be preferred to allow use of the 500‐kVA
prototype converters.
Preliminary discussions were held with CVEA in February 2011 regarding this demonstration project. A
specific site was not identified, but CVEA was generally supportive of hosting the HVDC demonstration
project, provided that it did not damage utility assets or negatively impact customers and was revenue‐
neutral to the utility (Botulinski, private conversation, 2011).
H.4.2.3 Hope Substation to Hope AC Line Conversion (Demonstration Only)
This is an existing, approximately 20‐mile‐long, single phase, 14.4‐kV distribution line owned and
operated by Chugach Electric Association, Inc. (CEA) serving the community of Hope on Turnagain Arm
near Anchorage (Figure H‐4). Hope has a peak load of approximately 300 kilowatts (kW). CEA is planning
a multipart upgrade of this line to address reliability issues. The first part of this upgrade project would
rebuild and relocate approximately 4 miles of the intertie starting at the Hope Substation near the Hope
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
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Junction on the Seward Highway. CEA estimates that this project would be ready for construction in 2013
(Jenkins, private conversation, 2011). The demonstration project would coordinate with the line upgrade.
The demonstration project would require transformers on either end of the demonstration segment to
convert between 14.4 kV and the 480‐V AC interface of the power converters. In addition, because the
14.4‐kV line is single phase, the converter capacity would be reduced by approximately 1/3 to 167 kVA.
This could be addressed either with increased converter capacity or occasional operation of the existing
diesel generator in Hope to meet peak loads.
CEA is supportive of hosting the HVDC demonstration project, provided that it did not damage utility
assets or negatively impact customers and was revenue‐neutral to the utility. While this intertie appears
technically feasible, less complicated HVDC demonstration projects likely exist within the state.
H.4.2.4 Homer – Seldovia AC Line Conversion (Demonstration Only)
This is an existing distribution line owned and operated by Homer Electric Association, Inc. (HEA),
serving the communities on the south side of Katchemak Bay from Halibut Cove to Seldovia. The line is
three‐phase, 24.9‐kV AC starting in Homer. It crosses Katchemak Bay with a 4.5‐mile‐long cable installed
in 2001, and then continues as an overhead line to the south bay communities (Figure H‐5). The overhead
line is a combination of conventional RUS construction and tree cable. Load on this distribution circuit is
approximately 1,100 kVA (McDonough, private conversation, 2011).
The concept for this demonstration project would be to operate the existing submarine cable as an HVDC
cable for the demonstration project. There are two challenges with this concept:
1. The peak load on the circuit is approximately twice the capacity of the prototype converters. This will
require load sharing between HEA through the HVDC link and diesels on the south side of the cable.
This is not a technical challenge; however, it will result in significant costs that the demonstration
project budget would need to absorb. 500 kW of continuous diesel generation for a 6‐month
demonstration period would cost approximately $700,000. A better alternative at this price may be to
build two more 500 kW converter modules, increasing the HVDC intertie capacity to 1,000 kW.
2. The existing submarine cable is only rated for 24.9 kV AC. This is approximately equal to 43 kV DC,
less than the nominal HVDC system voltage of 50 kV. Two possible remedies exist for this. If HEA can
be assured that the cable will operate at 50 kV DC without ill effect, then the demonstration project
could proceed. Given that cables are typically subjected to DC voltages on the order of 50 to 100 kV
during acceptance tests, it seems likely that this would be possible. The nature of these assurances has
not been defined. The second remedy is to decrease the operating voltage of the HVDC intertie. PPS
has indicated that the converter software can be programmed to reduce the DC voltage; however, this
will decrease the power rating of the converters. Lowering the voltage from 50 to 40 kV would lower
the power rating of a converter module from approximately 500 to 400 kVA.
HEA is supportive of hosting the HVDC demonstration project, provided that it did not damage utility
assets or negatively impact customers and was revenue‐neutral to the utility. While this intertie appears
technically feasible, less complicated HVDC demonstration projects likely exist within the state.
H.4.3 HVDC Demonstration Projects on New AC Distribution Line Extensions
This section provides overviews of potential HVDC demonstration projects that would be implemented on
purpose‐built AC distribution line extensions. After the HVDC demonstration is completed, the line would
be converted to AC service and would be a lasting benefit to the utility and newly served customers. The
candidate interties are organized geographically, moving northwest to southeast.
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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H.4.3.1 GVEA Phillips Road Line Extension
This project would be an approximately 1.75‐mile single‐phase overhead distribution extension to serve
several residences at the end of Phillips Road in Delta Junction, within the Golden Valley Electric
Association, Inc. (GVEA) service area (Figure H‐6). The line extension would be built as a standard AC
distribution line, operated as an HVDC intertie for demonstration purposes, and then turned over to GVEA
for subsequent operation as an AC distribution line.
GVEA and the residences at the end of the line would both likely contribute funds or in‐kind services to
the line extension. Total contribution is estimated at $50,000, and the line build, excluding any costs
associated with the HVDC demonstration, is budgeted at $140,000. A right‐of‐way would need to be
obtained for the project, which would take an estimated 6 to 12 months.
The project is located in close proximity to the Trans‐Alaska Pipeline System, and as such would likely not
be suitable for demonstration of SWER operation. The peak load of the residences at the end of the line is
likely less than the approximately 167‐kVA capacity of the 500‐kW prototype converters in single‐phase
operation.
GVEA is very supportive of hosting the HVDC demonstration project, provided that it did not damage
utility assets or negatively impact customers and was revenue‐neutral to the utility, beyond the in‐kind
construction contributions that GVEA offered for the line extension (Wright, private conversation, 2011).
H.4.3.2 GVEA Cummings Road Line Extension
This project would be an approximately 4‐ to 6‐mile single‐phase overhead distribution extension to
serve several residences at the end of Cummings Road in Deltana, within the GVEA service area (Figure H‐
7). The line extension would be built as a standard AC distribution line, operated as an HVDC intertie for
demonstration purposes, and then turned over to GVEA for subsequent operation as an AC distribution
line.
GVEA and the residences at the end of the line would both likely contribute funds or in‐kind services to
the line extension. Total contribution is estimated at $60,000, and the line build, excluding any costs
associated with the HVDC demonstration, is budgeted at $560,000. A right‐of‐way would need to be
obtained for the project, which would take an estimated 6 to 12 months.
The peak load of the residences at the end of the line is likely less than the approximately 167‐kVA
capacity of the 500‐kW prototype converters in single‐phase operation.
GVEA is very supportive of hosting the HVDC demonstration project, provided that it did not damage
utility assets or negatively impact customers and was revenue‐neutral to the utility, beyond the in‐kind
construction contributions that GVEA offered for the line extension (Wright, 2011).
H.4.3.3 MEA to Independence Mine Line Extension
This project would be an approximately 5.5‐mile underground AC distribution line from the end of
Matanuska Electric Association, Inc. (MEA)’s existing Hatcher Pass distribution line up to the
Independence Mine State Historical Park (State Park) (Figure H‐8). The line would be built as an AC
distribution feeder, operated as an HVDC line for the demonstration project, and then reverted to AC
operation.
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Easements for the first approximately 2 miles of the line extension are pending from the Alaska
Department of Natural Resources (ADNR) and Matanuska‐Susitna Borough (MSB) for a proposed
hydroelectric project located along the route. 42 New easements would be required for the remaining
approximately 3.5 miles to the State Park. The intertie would eliminate the need for diesel generation at
the State Park during the summer months. The hydroelectric project developer and ADNR Division of
Parks and Recreation both may support this project with matching funds.
When contacted regarding this project, the State Park was supportive (Biessel, private conversation,
2011). Three private entities located near the park expressed no interest in connecting to the line. When
contacted regarding this project, MEA expressed concerns about its staff availability to support this
project (Kuhn, private conversation, 2011).
H.4.4 HVDC Intertie Projects
This section provides overviews of potential HVDC interties between rural Alaska communities. The
interties are organized geographically, starting in the northwest and moving to the southeast.
H.4.4.1 Barrow to Atqasuk HVDC Intertie
This 75‐mile‐long overland intertie would connect Atqasuk, which uses high‐cost diesel for electricity, to
Barrow, which generates electricity from low‐cost natural gas (Figure H‐9). This project could include
conversion of Atqasuk to electric heating to achieve greater benefits. The North Slope Borough is
currently studying this intertie. If the HVDC technology is commercially available in a timely manner, it
could be used on this intertie. If it is not, the intertie would be built as a three‐phase AC line.
H.4.4.2 Nome to Teller and Brevig Mission HVDC Intertie
This approximately 75‐mile‐long overland intertie would connect Teller and Brevig Mission—which both
generate electricity with diesel fuel—to Nome, which generates electricity from diesel and some wind
(Figure H‐10). The Alaska Village Electric Cooperative, Inc. (AVEC) recently built an intertie between
Teller and Brevig Mission. If the Pilgrim Hot Springs geothermal resource is developed and is large
enough to supply Nome as well as Teller and Brevig Mission, it could significantly reduce electric costs in
these villages.
H.4.4.3 Pilgrim Hot Springs to Nome HVDC Intertie
The geothermal resource at Pilgrim Hot Springs could provide electricity for Nome. One of the challenges
with this renewable energy concept is the cost of the approximately 60‐mile transmission line between
Pilgrim Hot Springs and Nome (Figure H‐10). Using this HVDC technology could reduce the costs of this
intertie, improving project economics. One potential hurdle for this demonstration project candidate is
that the Pilgrim Hot Springs resource has been tentatively estimated at 5 megawatts (MW). This is larger
than the capacity of the prototype converters, and approximately ten 500‐kW converters would be
needed at each end of the intertie. PPS has indicated that paralleling this many converters together is
technically feasible but this function has not been verified at this time. ACEP is assessing the geothermal
resource at Pilgrim Hot Springs, which will help determine how much power can be derived from the
resource (Mager, private conversation, 2011).
42 The developer of this hydroelectric project is an affiliated interest of Polarconsult Alaska, Inc.
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H.4.4.4 St. Michaels – Stebbins HVDC Intertie
This approximately 10‐mile‐long overland intertie would connect St. Michaels and Stebbins, two villages
served by the AVEC, allowing AVEC to economize by consolidating bulk fuel and generation assets and
operations at one village (Figure H‐11). There is good marine access to both villages. The relatively short
distance of this intertie reduces the savings of an HVDC intertie compared with an AC intertie.
H.4.4.5 St. Mary’s to Mountain Village HVDC Intertie
This approximately 26‐mile‐long overland intertie would connect St. Mary’s and Mountain Village on the
Yukon River, allowing AVEC to economize by consolidating bulk fuel and generation assets and
operations at one village (Figure H‐12). There is good access to both villages, and an existing road
between them would facilitate construction of the overhead intertie.
H.4.4.6 Dillingham to Manokotak HVDC Intertie
This approximately 20‐mile‐long intertie would connect Manokotak to Dillingham (Figure H‐2). This
intertie would allow the Dillingham and Manokotak electric utilities to consolidate operations, lowering
costs in Manokotak, and improving the economies of scale for both utilities. In addition, Dillingham is
currently studying two hydroelectric resources, Lake Grant and Lake Elva, which would provide stable,
low‐cost electricity. If these projects are built, rates in Manokotak would be significantly reduced with
this intertie. An intertie between Manokotak and Dillingham has been studied in the past (Polarconsult,
1986) but has not been constructed. The proposed HVDC technology could reduce costs for the intertie,
improving project economics.
H.4.4.7 New Stuyahok – Ekwok HVDC Intertie
This approximately 8‐mile overland intertie would connect these two AVEC villages, allowing AVEC to
economize by consolidating bulk fuel and generation assets and operations at one village (Figure H‐13).
The relatively short distance of this intertie reduces the savings of an HVDC intertie compared with a
conventional AC intertie.
H.4.4.8 Kodiak – Ouzinkie HVDC Intertie
This approximately 8‐mile‐long submarine cable intertie would connect Ouzinkie with the Kodiak Electric
Association, Inc. (KEA) grid (Figure H‐14). Ouzinkie generates electricity with a combination of hydro and
diesel. KEA generates electricity from a combination of hydro, wind, and diesel. Due to the different
generation sources and economy of scale on the KEA system, KEA’s electric rates are significantly lower
than Ouzinkie’s. The intertie would benefit KEA by increasing load and would benefit Ouzinkie by
reducing rates. KEA and Ouzinkie have already studied an overland intertie with a short AC cable crossing
of Narrow Strait (Dryden & Larue, 2011). The estimated costs of the short cable crossing are a significant
portion of the total project cost, in part due to the mobilization costs of specialized equipment for cable
installation. It may be more cost‐effective to install a submarine HVDC cable for the entire route.
This intertie appears to be a suitable candidate for an HVDC demonstration project. The economic
benefits to Ouzinkie appear to be significant (Totemoff, private conversation, 2011). A submarine HVDC
cable using the technology developed in this project appears to be a less expensive option than the
overhead/cable crossing option. Ouzinkie’s peak load is approximately 400 kW, within the capacity of the
prototype converters. Further conversations with the project stakeholders are warranted.
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H.4.4.9 Green’s Creek to Hoonah HVDC Intertie
This 26‐mile‐long submarine intertie would connect Hoonah to Alaska Electric Light and Power Company
(AEL&P)’s Juneau power grid, providing lower‐cost power to Hoonah (Figure H‐15). The intertie is a good
length for HVDC and would provide a clear benefit to Hoonah. The intertie has been under consideration
for several years, and significant engineering studies have already been completed. The intertie is
uneconomic using AC transmission or existing HVDC technology. The proposed HVDC technology could
reduce costs for the intertie, improving project economics.
H.4.4.10 Petersburg to Kake HVDC Intertie
This approximately 60‐mile‐long submarine and overland intertie would connect Kake with the
Petersburg‐Ketchikan grid (Figure H‐16). The intertie would allow Kake to convert from high‐cost diesel
electricity to low‐cost hydro electricity, and would be part of the proposed southeast intertie grid. Using
HVDC could reduce costs by allowing longer spans, buried cable, or increased use of submarine cable.
While a 1‐MW monopolar HVDC intertie would be sufficient to serve Kake, future extension of the
southeast intertie to Sitka or development of nearby hydropower resources could increase the load on
this intertie to tens of megawatts.
H.4.4.11 Gustavus to Glacier Bay National Park Intertie (HVDC Demonstration Only)
With the completion of the 800‐kW Falls Creek Hydroelectric Project in 2009, Gustavus now has excess
hydropower. The headquarters of Glacier Bay National Park, located approximately 5 to 10 miles from
Gustavus, continues to rely on diesel generation for electricity (Figure H‐15). Connecting the park
headquarters with Gustavus would allow the Park to reduce fuel consumption and operating costs and
would allow Gustavus to increase its rate base and power sales, lowering overall rates. A buried HVDC
cable would be preferable to overhead AC lines in the park, where aesthetics are a major factor. Due to the
relatively short length, an HVDC intertie may not be cost‐effective compared to an AC intertie.
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H.4.5 Project Maps
Figure H-2 Vicinity Map for Demonstration Projects near Dillingham
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Figure H-3 Vicinity Map for Eureka AC Line Conversion
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Figure H-4 Vicinity Map for Hope AC Line Conversion
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Figure H-5 Vicinity Map for Seldovia AC Line Conversion
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Figure H-6 Vicinity Map for Delta Junction AC Line Extension
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Figure H-7 Vicinity Map for Deltana AC Line Extension
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Figure H-8 Vicinity Map for Independence Mine AC Line Extension
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Figure H-9 Vicinity Map for Barrow – Atqasuk HVDC Intertie
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Figure H-10 Vicinity Map for Demonstration Projects near Nome
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Figure H-11 Vicinity Map for St. Michaels – Stebbins HVDC Intertie
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Figure H-12 Vicinity Map for St. Mary’s – Mountain Village HVDC Intertie
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Figure H-13 Vicinity Map for New Stuyahok – Ekwok HVDC Intertie
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Figure H-14 Vicinity Map for Kodiak – Ouzinkie HVDC Intertie
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Figure H-15 Vicinity Map for Gustavus and Hoonah HVDC Interties
Figure H-16 Vicinity Map for Kake – Petersburg HVDC Intertie
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APPENDIX I
STAKEHOLDER ADVISORY GROUP INVOLVEMENT AND MEETINGS
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TABLE OF CONTENTS
I.1 INTRODUCTION ........................................................................................................................................................ 7
I.2 LIST OF SAG MEMBERS ......................................................................................................................................... 8
I.3 SUMMARY OF SAG ROLE AND POLICIES ....................................................................................................... 9
I.3.1 POLICIES AND PROCEDURES ............................................................................................................................................ 9
I.3.1.1 Formation ...................................................................................................................................................... 9
I.3.1.2 Scheduled Meetings ................................................................................................................................... 9
I.3.1.3 Organization ................................................................................................................................................. 9
I.3.1.4 Communication ........................................................................................................................................... 9
I.3.1.5 Termination ................................................................................................................................................ 11
I.4 STAKEHOLDER ADVISORY GROUP (SAG) MEETING PRESENTATION MATERIALS ................. 12
I.4.1 SAG MEETING #1 – FAIRBANKS, ALASKA (APRIL 27, 2010) ................................................................................ 12
I.4.2 SAG MEETING #2 – ANCHORAGE, ALASKA (JANUARY 14, 2011) ........................................................................ 32
I.4.3 SAG MEETING #3 – ANCHORAGE, ALASKA (OCTOBER 25, 2011) ....................................................................... 53
I.5 HANDOUTS FROM OTHER MEETINGS CONDUCTED DURING THE PROJECT ........................... 105
I.5.1 SOUTHEAST CONFERENCE MID‐SESSION SUMMIT – JUNEAU, ALASKA (MARCH 2, 2010) ............................ 107
I.5.2 EMERGING ENERGY TECHNOLOGY FORUM – JUNEAU, ALASKA (FEBRUARY 14, 2011) ................................. 113
I.5.3 BROWN‐BAG WORK SESSION – ANCHORAGE, ALASKA (AUGUST 29, 2011) ................................................... 125
I.5.4 HVDC CONVERTER DEMONSTRATION – LAWRENCEVILLE, NEW JERSEY (NOVEMBER 14, 2011) ............. 145
I.6 ADDITIONAL MEETINGS ................................................................................................................................. 151
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MARCH 2012 PAGE I-4
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MARCH 2012 PAGE I-5
LIST OF TABLES
Table I‐1 List of SAG Members ................................................................................................................................. 8
Table I‐2 Summary of Correspondence with SAG Members ...................................................................... 10
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MARCH 2012 PAGE I-6
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MARCH 2012 PAGE I-7
I.1 INTRODUCTION
This appendix provides the following detailed information regarding the Stakeholders Advisory Group
(SAG) formed for Phase II of the High‐Voltage Direct Current (HVDC) Development Program:
● List of SAG members;
● Summary of SAG role and policies;
● Summary of key informal correspondence between SAG members and Polarconsult over the course of
the project;
● Handouts and transcripts from the three SAG meetings; and
● Handouts from other meetings and outreach activities conducted over the course of the project.
Meeting transcripts are available separately.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MARCH 2012 PAGE I-8
I.2 LIST OF SAG MEMBERS
Table I-1 List of SAG Members
Company First Name Last Name Position
Denali Commission Denali Daniels SAG Chair
Alaska Center for Energy and Power (ACEP) Gwen Holdmann ACEP Director
Alaska Center for Energy and Power (ACEP) Jason Meyer ACEP Project Manager
Alaska Center for Energy and Power (ACEP) Brent Sheets SAG Member
Polarconsult Alaska, Inc. Joel Groves Project Manager
Polarconsult Alaska, Inc. Earle Ausman President
Polarconsult Alaska, Inc. David Ausman Vice President
Princeton Power Systems, Inc. (PPS) Darren Hammell Executive Vice President
Alaska Department of Labor (AKDOL) Daniel Greiner Alt. SAG Member
Alaska Department of Labor (AKDOL) Alvin Nagel SAG Member
Alaska Division of Community and Regional Affairs (DCRA) Percy Frisby SAG Member
Alaska Energy Authority (AEA) David Lockhard SAG Member
Alaska Power & Telephone Company (APT) Bob Grimm SAG Member
Alaska Power Association (APA) Marilyn Leland SAG Member
Alaska Village Electric Cooperative, Inc. (AVEC) Meera Kohler SAG Member
Alaska Village Electric Cooperative, Inc. (AVEC) Brent Petrie Alt. SAG Member
Bering Straits Native Corporation (BSNC) Jerald Brown SAG Member
Bethel Electric Utility (BEC) Bob Charles SAG Member
Copper Valley Electric Association (CVEA) Robert Wilkinson SAG Member
Dillingham Nels Andersen SAG Member
Golden Valley Electric Association, Inc. (GVEA) Brian Newton SAG Member
Homer Electric Association, Inc. (HEA) Brad Janorschke SAG Member
Inside Passage Electric Cooperative (IPEC) Jodi Mitchell SAG Member
Institute of Northern Engineering (INE, UAF) Ron Johnson SAG Member
Kodiak Electric Association, Inc. (KEA) Darron Scott SAG Member
Kotzebue Electric Association, Inc. (KoEA) Brad Reeve SAG Member
Matanuska Electric Association (MEA) Joe Griffith SAG Member
Matanuska Electric Association (MEA) Trivia Singaraju Alt. SAG Member
Naknek Electric Association, Inc. (NEA) Donna Vukich SAG Member
Nat’l. Rural Electric Cooperative Association (NRECA) Tom Lovas SAG Member
Nome Chamber of Commerce (NCC) Mitch Erickson SAG Member
Nome Joint Utilities (NJUS) John Handeland SAG Member
North Slope Borough (NSB) Kent Grinage SAG Member
Northwest Arctic Borough (NWAB) Ingemar Mathiasson SAG Member
Nushagak Electric Association Mike Favors SAG Member
Nuvista Light and Power, Inc. (NLP) Bob Charles SAG Member
Southeast Conference (SEC) Robert Venables Alt. SAG Member
Southeast Conference (SEC) Shelly Wright SAG Member
Southwest Alaska Municipal Conference (SWAMC) Andy Varner SAG Member
U.S. Department of Agriculture (USDA) Rural Utilities Service (RUS) Eric Marchegiani SAG Member
University of Alaska Fairbanks (UAF) Richard Wies SAG Member
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MARCH 2012 PAGE I-9
I.3 SUMMARY OF SAG ROLE AND POLICIES
I.3.1 Policies and Procedures
The SAG is an advisory body comprised of representatives of Alaska’s rural electric utility industry and
related professionals. The purpose of the SAG is to provide comments, feedback, review, and
recommendations to the HVDC Development Program, awarded by the Denali Commission (Commission),
managed by the Alaska Center for Energy and Power (ACEP), and contracted to Polarconsult Alaska, Inc.
(Polarconsult).
I.3.1.1 Formation
To maintain independence of the SAG, ACEP identified members for participation, with consideration of
recommendations from Polarconsult and the Denali Commission. A final candidate list was sent out for
comment to Polarconsult and forwarded for approval to the Denali Commission.
I.3.1.2 Scheduled Meetings
Per the scope of work under UAF – Polarconsult Contract #10‐0055, the SAG formally convened three
times over the course of the HVDC Project. Per the scope of work and budget, the cost of convening these
meetings was the responsibility of Polarconsult. Funding for member travel and participation costs was
not provided. The meetings were convened in a manner conducive to remote participation of members.
The meeting dates were April 28, 2010; December 1, 2010; and July 15, 2011.
The agenda for these meetings was set by ACEP, with input from Polarconsult and the Denali Commission
and final approval by the Denali Commission.
I.3.1.3 Organization
The SAG shall consist of the Chair (the Denali Commission) and members. To maintain equality on the
SAG, individual organizations may hold only one member position. Up to 30 SAG members will be
allowed, the final number determined based on the level of interest. If at any time over the course of the
project one of the members resigns or is no longer active, ACEP will invite another individual to fill this
position, with the approval of the Denali Commission. Members may designate proxies from within their
organization to attend meetings.
ACEP encourages organizations and individuals not selected for the SAG to participate informally in this
project. Public comment is always welcome and an e‐mail list and forum will be made available on the
ACEP project website.
I.3.1.4 Communication
At certain project milestones, or upon recommendation from ACEP, Polarconsult shall solicit comments,
review, and recommendations to the HVDC program. All formal communication between Polarconsult
and the SAG shall be through the Chair, with inclusion of ACEP. Polarconsult is free to contact the whole
SAG formally or contact individual SAG members informally, as the need arises. All informal
communication will not represent the advice or recommendations of the SAG. In the interests of
promoting maximum feedback from the industry, confidential communications will be accepted where
there is a demonstrated need to maintain confidentiality.
Table I‐2 provides a summary of correspondence with SAG members related to this project.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MARCH 2012 PAGE I-10
Table I-2 Summary of Correspondence with SAG Members
Date SAG Member Participants Subject Summary
Jan.–Feb.
2010 MEA
Trivi Singaraju (MEA)
Gary Kuhn (MEA)
Joel Groves (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
Jan.–Feb.
2010 CVEA Chris Botulinski (CVEA)
Earle Ausman (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
Jan.–March
2010
At Large
Citizen
Nels Anderson
Earle Ausman (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
Jan.–March
2010 CEA
Ed Jenkin (CEA)
Dave Ausman (Polarconsult)
Joel Groves (Polarconsult)
Earle Ausman (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
Jan.–March
2010 HEA
Brad Zubeck (HEA)
Kathy McDonough (HEA)
Joel Groves (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
May–June
2010 NWAB Ingemar Mathiasson (NWAB)
Earle Ausman (Polarconsult)
International
examples of
electric codes
Mr. Mathiasson used his contacts in
Sweden to request examples of
international electric codes with
regard to SWER circuits, HVDC, and
related rural electric issues.
July–
October
2010
AVEC
Brent Petrie (AVEC)
Bill Thomson (AVEC)
Mark Tietzel (AVEC)
Joel Groves (Polarconsult)
Earle Ausman (Polarconsult)
HVDC Converter
Specification
Discussions and comments from
AVEC on draft specification for
HVDC power converter.
July–
October
2010
UAF/ACEP
Richard Wies (UAF)
Jason Meyer (ACEP)
Joel Groves (Polarconsult)
Earle Ausman (Polarconsult)
HVDC Converter
Specification
Discussions and comments from
AVEC on draft specification for
HVDC power converter.
August 2010 AVEC Mark Teitzel (AVEC)
Joel Groves (Polarconsult)
Conceptual
Design of
Overhead Line
Request for examples of
environmental loadings used on
previous AVEC interties,
performance of these projects.
September
2010 IPEC Peter Bibb (IPEC)
Joel Groves (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
October–
November
2010
GVEA
Mike Wright (GVEA)
Searl Burnett (GVEA)
Earle Ausman (Polarconsult)
Conceptual
Design of
Overhead Line
Site visit to review design,
performance, and failure modes of
guyed Y and X towers on
transmission lines between
Fairbanks and Healy.
November
2010 AVEC
Brent Petrie (AVEC)
Joel Groves (Polarconsult)
Earle Ausman (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
December
2010 SEC
Shelly Wright (SEC)
Robert Venables (SEC)
Joel Groves (Polarconsult)
Earle Ausman (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
January
2011 APT
Bob Grimm (APT)
Earle Ausman (Polarconsult)
Joel Groves (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MARCH 2012 PAGE I-11
Date SAG Member Participants Subject Summary
January
2011 NWAB
Ingemar Mathiasson (NWAB)
Brent Petrie (AVEC)
Joel Groves (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
January
2011 RUS Eric Marchegiani (RUS)
Joel Groves (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
January
2011 Multiple Multiple SAG Members Demonstration
Project Sites
Teleconference with SAG members
on HVDC demonstration project
sites.
January–
March 2011 GVEA
Mike Wright (GVEA)
Joel Groves (Polarconsult)
Earle Ausman (Polarconsult)
Demonstration
Project Sites
Discussing potential HVDC
demonstration project sites.
March 2011 AVEC
Bill Thomson (AVEC)
Joel Groves (Polarconsult)
Earle Ausman (Polarconsult)
Randy Wachal (MHRC)
HVDC Controls
and integration
Discussions among Polarconsult,
Manitoba, and AVEC on system
controls and integration needs.
May–June
2011 CVEA
Chris Botulinski (CVEA)
Earle Ausman (Polarconsult)
Joel Groves (Polarconsult)
HVDC Test Site Discussions looking for a test site for
HVDC pole and foundations.
June 2011 UAF
Richard Wies (UAF)
Jason Meyer (ACEP)
Joel Groves (Polarconsult)
Earle Ausman (Polarconsult)
Examples of cold
regions design for
overhead HVDC
Visit of Chinese delegation regarding
design of HVDC line across the
Tibetan Plateau.
June–July
2011 GVEA
Mike Wright (GVEA)
Joel Groves (Polarconsult)
Earle Ausman (Polarconsult)
HVDC Test Site Discussions looking for a test site for
HVDC pole and foundations
July 2011 AKDOL
Al Nagel (AKDOL)
Dave Greiner (AKDOL)
Randy Wachal (MHRC)
Joel Groves (Polarconsult)
SWER circuit
safety.
Discussions with Alaska Department
of Labor regarding HVDC SWER
circuits and soliciting comments on
the SWER analysis prepared by
Manitoba.
November
2011 AVEC Pam Lyons (AVEC)
Joel Groves (Polarconsult)
Converter
Shipping Cost
AVEC assistance on obtaining
shipping costs to move prototype
converters to Alaska.
Nov, 2011 –
Jan 2012 AVEC
Meera Kohler (AVEC)
Mark Tietzel (AVEC)
Brent Petrie (AVEC)
Joel Groves (Polarconsult)
Cost data for past
AC projects
Discussions from November 2011
through January 2012 regarding
details of cost data for remote
Alaska AC intertie projects built over
the past decade.
December
2011 AKDOL
Al Nagel (AKDOL), Dave
Greiner (AKDOL), Jason
Meyer (ACEP), Joel Groves
(Polarconsult)
SWER circuit
safety.
Discussions with Alaska Department
of Labor regarding HVDC SWER
circuits and NESC code.
I.3.1.5 Termination
The SAG shall be formally terminated upon the end of the project issued from the Denali Commission.
FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
MARCH 2012 PAGE I-12
I.4 STAKEHOLDER ADVISORY GROUP (SAG) MEETING PRESENTATION
MATERIALS
I.4.1 Sag Meeting #1 – Fairbanks, Alaska (April 27, 2010)
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
PHASE II – PROTOTYPING AND TESTING
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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HVDC TRANSMISSION SYSTEM FOR RURAL ALASKAN APPLICATIONS
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I.4.2 SAG Meeting #2 – Anchorage, Alaska (January 14, 2011)
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I.4.3 SAG Meeting #3 – Anchorage, Alaska (October 25, 2011)
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I.5 HANDOUTS FROM OTHER MEETINGS CONDUCTED DURING THE
PROJECT
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I.5.1 Southeast Conference Mid‐Session Summit – Juneau, Alaska (March 2, 2010)
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I.5.2 Emerging Energy Technology Forum – Juneau, Alaska (February 14, 2011)
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I.5.3 Brown‐Bag Work Session – Anchorage, Alaska (August 29, 2011)
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I.5.4 HVDC Converter Demonstration – Lawrenceville, New Jersey (November 14,
2011)
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I.6 ADDITIONAL MEETINGS
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The following additional meetings were held during the course of this project regarding a HVDC
transmission system in rural Alaska.
● Southeast Conference Mid‐Session Summit – Juneau, Alaska (MARCH 2, 2010)
● Emerging Energy Technology Forum – Juneau, Alaska (February 14, 2011)
● Brown‐Bag Work Session – Anchorage, Alaska (August 29, 2011)
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APPENDIX J
BIBLIOGRAPHY
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Alaska Center for Energy and Power (ACEP, 2012). Alaska Stranded Renewables. A Preliminary
Framework for Assessment. December 2011.
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Alaska Village Electric Cooperative, Inc. (AVEC, 2008). Application for Renewable Energy Fund Grant,
Emmonak, Alaska, Wind Design and Construction Project. November 11, 2008.
Arrillaga, Josu (Arrillaga, 1998). High Voltage Direct Current Transmission. 2nd Edition, 1998.
Commonwealth North (CWN, 2012). Energy for a Sustainable Alaska: The Rural Conundrum. February
2012.
Department of Community and Regional Affaris (DCRA, 2011). Current Community Conditions: Fuel Prices
Across Alaska, Report to the Director. June 2010 Update.
Denali Commission (Denali Commission, 2008a). 49C Intertie Upgrade Nunapitchuk to Kasigluk, Closeout
Summary Report. June 2008.
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and Closeout Summary Report. 2009.
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Number 01117 220607 Bethel–Napakiak Intertie. June 30, 2010.
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Monashka Feeder High Sub Station. 2011.
Ibrahim, Sherif (Ibrahim, 2000). Performance Evaluation of Fiber‐Reinforced Polymer Poles for
Transmission Lines. Doctoral Thesis, University of Manitoba, Department of Civil and Geological
Engineering. 2000.
Idaho National Engineering and Environmental Laboratory (INEEL, 1998). Haines‐Skagway Submarine
Cable Intertie Project, Haines to Skagway, Alaska. Final Technical and Construction Report.
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FINAL REPORT, VERSION 1.1 POLARCONSULT ALASKA, INC.
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PHASE II – PROTOTYPING AND TESTING
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Inside Passage Electric Cooperative, Inc. (IPEC, 2009). Electric Transmission Intertie, Juneau ‐ Green's
Creek Mine ‐ Hoonah. Presentation to Southeast Conference by Jodi Mitchell. 2009.
Kuffel, E., Zaengl, W. S., & Kuffel, J. (KZK, 2006). High Voltage Engineering Fundamentals. 2nd Edition,
2006.
Naidu, M. S. & Kamaraju, V. (Naidu, 1996). High Voltage Engineering. 2nd Edition, 1996.
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Computer Program. 2005.
Neubauer Engineering & Tech Svc., Foster Wheeler Env. Corp. (Neubauer, 1997). Rural Alaska Electric
Utility Interties.
Penton Media Publications (TDW, 2012). Transmission & Distribution World: HVDC Transforming an
Industry. April 2012 Issue.
Polarconsult Alaska, Inc. (Polarconsult, 1986). Manokotak Transmission Line Study. June 1986.
Polarconsult Alaska, Inc. (Polarconsult, 2009). Phase I – Preliminary Design and Feasibility Analysis Final
Report.
Power Engineers (Power Engineers, 2004). Juneau ‐ Greens Creek / Hoonah Intertie Study, Load Flow and
Short Circuit Analysis Final Report, Rev 1. December 30, 2004.
Skrotzki, Bernhardt G. A. (Skrotzki, 1980). Electric Transmission & Distribution. 1980.
Southwire (Southwire, 2008). Southwire SAG 10, Version 3.10.7. 2008.
Thrash, Ridley, Murah, Amy, Lancaster, Mark, & Nuckles, Kim (Thrash, 2007). Overhead Conductor. 2nd
Edition, 2007.
U.S. Department of Agriculture ‐ Rural Utility Service (RUS, 1998). Specifications and Drawings for
24.9/14.4 kV Line Construction. Bulletin 1728F‐803 (D‐803), December 1998.
U.S. Department of Agriculture ‐ Rural Utility Service (RUS, 2001). Electric Distribution Line Guys and
Anchors. Bulletin 1724E‐153, April 2001.
U.S. Department of Agriculture ‐ Rural Utility Service (RUS, 2002). Mechanical Loading on Distribution
Cross Arms. Bulletin 1724E‐151, November 2002.
U.S. Department of Agriculture ‐ Rural Utility Service (RUS, 2003a). Unguyed Distribution Poles ‐ Strength
Requirements. Bulletin 1724E‐150, July 2003.
U.S. Department of Agriculture ‐ Rural Utility Service (RUS, 2003b). The Mechanics of Distribution Line
Connectors. Bulletin 1724E‐152, July 2003.
U.S. Department of Agriculture ‐ Rural Utility Service (RUS, 2003c). Distribution Conductor Clearances and
Span Limitations. Bulletin 1724E‐154, July 2003.
U.S. Department of Agriculture ‐ Rural Utility Service (RUS, 2005). Specifications and Drawings for 12.47/
7.2 kV Line Construction. Bulletin 1728F‐804, Oct 2005.
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PHASE II – PROTOTYPING AND TESTING
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