HomeMy WebLinkAboutAEA Railbelt Transmission Plan Project15-0481 EPS DavidMeyer 03-06-2017-RB
Alaska Energy Authority
Railbelt Transmission Plan
Project #15-0481
March 6, 2017
David A. Meyer. P.E.
Randy Miller, P.E.
Dr. James W. Cote, Jr., P.E.
David W. Burlingame, P.E.
Alaska Energy Authority
Railbelt Transmission Plan
March 6, 2017
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Table of Contents
1 INTRODUCTION ............................................................................................................... 1
2 EXECUTIVE SUMMARY ................................................................................................... 1
3 DETAILED SUMMARY ..................................................................................................... 3
3.1 Kenai- Anchorage Transmission ................................................................................. 3
3.2 Southcentral Alaska Reliability................................................................................... 5
3.3 Anchorage-Fairbanks Intertie Reliability ................................................................... 5
3.4 Proposed System Transmission Maps ....................................................................... 7
4 POWER FLOW & TRANSIENT STABILITY ANALYSIS .................................................10
4.1 Introduction ............................................................................................................. 10
4.2 Methodology ............................................................................................................ 10
4.3 System Analysis and Base Cases .............................................................................. 11
4.4 Unit Commitment, Dispatch, and Spinning Reserves .............................................. 11
4.5 Intertie Export Limits ............................................................................................... 12
4.6 Assumptions ............................................................................................................. 13
4.6.1 BESS Spinning Reserves ................................................................................ 13
4.6.2 HVDC Tie Modeling ...................................................................................... 13
4.6.3 Nikiski Overfrequency Relaying ................................................................... 13
4.6.4 Fairbanks Area Generation .......................................................................... 13
4.7 PSS/E Modeling Changes ......................................................................................... 14
4.7.1 Dynamics ...................................................................................................... 14
4.7.2 Power Flow ................................................................................................... 14
4.8 Performance Standards & Criteria ........................................................................... 14
4.8.1 Stability Criteria ........................................................................................... 15
4.8.2 Voltage Criteria ............................................................................................ 15
4.9 Contingencies ........................................................................................................... 15
4.10 Existing Kenai Intertie .............................................................................................. 18
4.10.1 Generation Scenarios ................................................................................... 19
4.10.2 Results .......................................................................................................... 22
4.10.3 Explanation of Limits.................................................................................... 23
4.10.4 Winter Peak ................................................................................................. 23
4.10.5 Summer Peak & Summer Valley .................................................................. 24
4.10.6 Spinning Reserve Sensitivities ...................................................................... 24
4.10.7 UFLS.............................................................................................................. 25
4.10.8 Bradley Lake Limits ...................................................................................... 26
4.11 Anchorage-Fairbanks - Alaska Intertie ..................................................................... 26
4.11.1 Generation Scenarios ................................................................................... 26
4.11.2 Results .......................................................................................................... 30
4.11.3 Winter Peak ................................................................................................. 31
4.11.4 Summer Peak ............................................................................................... 31
4.11.5 Summer Valley ............................................................................................. 31
4.11.6 Sensitivity to Fairbanks Area Generation .................................................... 32
4.11.7 UFLS.............................................................................................................. 33
4.12 Kenai Area System Improvements ........................................................................... 34
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March 6, 2017
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4.12.1 System Improvement Projects ..................................................................... 34
4.12.2 Alternatives .................................................................................................. 39
4.12.3 Generation Scenarios ................................................................................... 40
4.12.4 Results .......................................................................................................... 42
4.13 Southcentral and Northern Area System Improvements ........................................ 43
4.13.1 Southcentral System Improvement Projects ................................................ 43
4.13.2 Northern System Improvement Projects ...................................................... 44
4.13.3 Generation Scenarios ................................................................................... 46
4.13.4 Results .......................................................................................................... 49
4.13.5 Sensitivity to Fairbanks Area Generation .................................................... 51
4.13.6 UFLS.............................................................................................................. 51
4.14 Conclusions .............................................................................................................. 51
5 PROJECT PRIORITIZATION ...........................................................................................52
6 PRIORITIZATION: PROCESS .........................................................................................54
7 PRIORITIZATION: CONCLUSIONS ................................................................................57
APPENDIX: DETAILED COST ESTIMATES ............................................................................58
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March 6, 2017
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List of Tables
Table 2-1: Economic/Reliability Projects .................................................................................... 2
Table 2-2: Reliability Projects ..................................................................................................... 2
Table 3-1: Kenai Project Costs ................................................................................................... 5
Table 3-2: Southcentral Project Costs ........................................................................................ 5
Table 3-3: Northcentral Project Costs ........................................................................................ 6
Table 3-4: Northcentral Project Costs –230 kV Line Upgrades ................................................... 7
Table 4-1: Seasonal and Utility Loads (MW) .............................................................................11
Table 4-2: Railbelt UFLS Scheme Load Distribution .................................................................11
Table 4-3: Kenai Area Line/Transformer Contingencies ............................................................16
Table 4-4: Southcentral Area Line/Transformer Contingencies .................................................17
Table 4-5: Northern Area Line/Transformer Contingencies .......................................................18
Table 4-6: Generation Contingencies ........................................................................................18
Table 4-7: Existing Winter Peak Base Case Dispatches ...........................................................20
Table 4-8: Existing Summer Peak Base Case Dispatches ........................................................21
Table 4-9: Existing Sumer Valley Base Case Dispatches ..........................................................22
Table 4-10: Seasonal Results – Final Export Limits ..................................................................23
Table 4-11: Seasonal Results – Spin Comparison ....................................................................25
Table 4-12: Bradley Lake Plant Limits with No RAS ..................................................................26
Table 4-13: Healy Area Generation Scenarios .........................................................................27
Table 4-14: Existing Winter Peak Base Case Dispatches .........................................................28
Table 4-15: Existing Summer Peak Base Case Dispatches ......................................................29
Table 4-16: Existing Summer Valley Base Case Dispatches .....................................................30
Table 4-17: Winter Peak Export Stability Limits .........................................................................31
Table 4-18: Summer Peak Export Stability Limits ......................................................................31
Table 4-19: Summer Valley Export Stability Limits ....................................................................32
Table 4-20: Sensitivity to Fairbanks Generation ........................................................................33
Table 4-21: BESS Sizing Requirements ....................................................................................38
Table 4-22: Winter Peak Generation Scenarios ........................................................................41
Table 4-23: Summer Peak Generation Scenarios .....................................................................42
Table 4-24: Existing/Future Kenai Area Export Limits ...............................................................43
Table 4-25: Winter Peak Generation Scenarios ........................................................................47
Table 4-26: Summer Peak Generation Scenarios .....................................................................48
Table 4-27: Summer Valley Generation Scenarios ....................................................................49
Table 4-28: Winter Peak Existing/Future Southcentral Export Limits .........................................50
Table 4-29: Summer Peak Existing/Future Southcentral Export Limits ......................................50
Table 4-30: Summer Valley Existing/Future Southcentral Export Limits ....................................51
Table 5-1: Project Summary Cost .............................................................................................52
Table 5-2: Recommended Project Sequence ............................................................................53
Table 6-1: Project Sections and Subcomponents used for Analysis ..........................................55
Table A-1: Bernice Lake-Beluga HVDC ....................................................................................58
Table A-2: 35 MW/20 MWh BESS.............................................................................................59
Table A-3: Bradley-Soldotna 115 kV – Line Sections ................................................................59
Table A-4: Bradley Substation ...................................................................................................60
Table A-5: Soldotna Substation .................................................................................................62
Table A-6: Dave’s Creek - Hope 230kV Line .............................................................................64
Table A-7: Hope – Portage 230kV Line .....................................................................................65
Table A-8: Portage - Girdwood 230kV Line ...............................................................................66
Table A-9: Girdwood - Indian 230kV Line ..................................................................................67
Table A-10: Indian - University 230kV Line ...............................................................................68
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Table A-11: Dave’s Creek Substation .......................................................................................69
Table A-12: Summit & Hope Substations ..................................................................................71
Table A-13: Portage Substation ................................................................................................73
Table A-14: Girdwood Substation..............................................................................................75
Table A-15: Indian Substation ...................................................................................................77
Table A-16: University Substation .............................................................................................79
Table A-17: Quartz Creek Substation ........................................................................................80
Table A-18: Dave's Creek - Quartz Creek Upgrade ...................................................................82
Table A-19: Fossil Creek Substation .........................................................................................83
Table A-20: Eklutna Hydro Substation ......................................................................................85
Table A-21: Lorraine Substation ................................................................................................87
Table A-22: Douglas Substation ................................................................................................89
Table A-23: Healy Substation ....................................................................................................93
Table A-24: Gold Creek Substation ...........................................................................................97
Table A-25: Lorraine-Douglas 230 kV Line ................................................................................99
Table A-26: Douglas – Healy 230 kV line ................................................................................ 100
Table A-27: Healy – Gold Hill 230 kV Line .............................................................................. 101
Table A-28: Clear and Eva Creek Substations ........................................................................ 102
Table A-29: Nenana Substation .............................................................................................. 103
Table A-30: Ester Substation .................................................................................................. 105
Table A-31: Gold Hill and Wilson Substations ......................................................................... 107
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Table of Figures
Figure 3-1: Northern Proposed Transmission System ................................................................ 8
Figure 3-2: Kenai and Southcentral Proposed Transmission System ......................................... 9
Figure 4-1: Kenai Export Loss Analysis .....................................................................................35
Figure 4-2: Anchorage – Healy Loss Analysis: Base vs. Proposed ...........................................46
Figure 5-1: Estimated Yearly and Cumulative Expenditures (USD) ...........................................54
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March 6, 2017
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1 Introduction
This report includes the findings of the transmission system analysis and economic studies
completed to determine the future composition of the Railbelt transmission system.
Since the last draft report was issued in March 2014, new reliability and operating standards have
been adopted by the Railbelt utilities, and new generation plants for all utilities have been
commissioned. Additionally, the Railbelt utilities have spent considerable effort reviewing and
updating the economic models used to simulate the Railbelt’s cost of power production. As a
result of the new standards, new power plants, and the utilities’ work on the economic model; the
transmission studies have been updated to reflect 2016 conditions, and the economic studies
have been updated to use the latest economic models available from the utilities. Since the
economic studies do not include the total economic evaluation of the projects, but only evaluate
possible fuel savings, they are presented as a separate report, apart from the technical system
studies.
The purpose of this plan is to outline a transmission system and improvement projects necessary
to meets the requirements of the Railbelt Transmission System Planning Standard, AKTPL-001-
4. Per the standard, once a proposed project is identified, each project must undergo a process
that includes economic and reliability evaluations to justify its construction. This plan outlines the
transmission system improvements required to meet the standard, but does not attempt to
complete each projects’ analysis required in the standard to determine if and when it should be
constructed.
The transmission system improvements needed to support the Watana project, or any other major
generation project not currently under construction or completed are not included in the report.
2 Executive Summary
Electric Power Systems (EPS) has completed an analysis to determine the future transmission
system in the Railbelt. The need for the transmission plan was driven by the changes in the
Railbelt generation and transmission system since the completion of the 2010 Regional Integrated
Resource Plan (RIRP) administered by the Alaska Energy Authority (AEA).
The recommended transmission system improves reliability and has the potential to mitigate
future cost increases to Railbelt ratepayers and allow significant energy transfers between
different areas of the Railbelt system. Constraints for the use of Bradley Lake hydroelectric project
energy are removed and the coordination of hydro and thermal generation resources throughout
the Railbelt can be optimized. While the proposed reliability improvements are far from what
would be required for a transmission system in the Lower 48, they do significantly improve the
reliability and economics of the Railbelt and allow the utilities to pursue additional load and
resource pooling options not possible with the existing transmission system. The proposed
improvements allow increased use of variable renewable generation, such as wind and
photovoltaic (PV) in the Railbelt system, which is currently near its limit of renewable resource
penetration.
Most transmission improvements are typically justified by the cost of unserved energy, or the
value of system reliability, and are rarely justified purely on hard economic benefits. However,
there is currently no uniform estimate of unserved energy throughout the Railbelt, nor are there
adequate records or criteria to allow it to be equitably evaluated. Typically, in the Lower 48, the
types of reliability improvements included within this plan are required as part of the power
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systems’ mandate to meet NERC’s and/or the transmission areas’ reliability criteria. Projects are
not evaluated solely in terms of the pure economic benefit of the project for fuel savings or reduced
losses. For this reason, the economic evaluation of these projects is not included in this portion
of the study. The economic model developed for the production cost simulations has been made
available to the utilities, along with the results of the analysis in a separate document for the
utilities to complete the evaluation in accordance with AKTPL-001-4.
This report is not a mandate to construct these projects, but rather should be considered the first
step in the transmission planning process outlined in the recently completed transmission
planning standard, specifically AKTPL-001-4. Each of the projects must undergo further cost and
benefit analysis prior to making the decision to construct each project. Some projects may be
deemed feasible and constructed following the assessment and others may be put on hold until
economic or other conditions warrant their construction.
All of the projects identified in the study are driven by the reliability improvements, with most
having the added benefit of positive economic value. As the projects are evaluated going forward,
the value of unserved energy, the value of renewable energy, the value of future load-serving
capability, the value of capacity sharing or deferral and the value of a significant reduction in
greenhouse gasses should be computed and utilized in each projects’ analysis. However, some
of the projects are strictly reliability driven projects with little or very small economic benefits and
can only be justified by more traditional transmission evaluation methods.
A summary of the projects that have both economic and reliability benefits are included in Table
2.1.
Table 2-1: Economic/Reliability Projects
Projects that do not include definitive economic benefits are shown in Table 2.2.
Table 2-2: Reliability Projects
The recommended transmission plan meets the requirements of AKTPL-001-4 for system
reliability and contingency evaluation. However, AKTPL-001-4 also requires each project be
evaluated in terms of reliability and costs to determine whether the project should be constructed.
The evaluation required by the standard includes the costs identified in this report, but also
requires the identification of all benefits, including the benefits not included in the scope of this
Priority Project Description Cost (Millions)
1 Bernice Lake-Beluga HVDC 100 MW HVDC Intertie 185.3$
2 35 MW/20 MWh BESS Anchorage area battery 41.1$
3 Bradley-Soldotna 115 kV Line New line & Bradley/Soldotna sub 66.6$
4 University-Dave’s Creek 230kV Reconstruct existing line 57.5$
5 University-Dave’s Substations Convert line for 230 kV operation 36.3$
6 Dave's Creek - Quartz Creek Upgrade line to Rail conductor, Quartz sub 16.2$
1 Lorraine-Douglas Lorraine - Douglas 230 kV line/stations 128.5$
2 Douglas – Healy line New 230 kV line operated at 138 kV 245.7$
1 Healy-Fairbanks 230 kV Convert 138 kV to 230 kV 107.9$
885.0$ Total Reliability & Economic Projects
Priority Project Description Cost (Millions)
1 Fossil Creek New 115 kV substation 11.9$
3 Eklutna Hydro New 115 kV substation 10.1$
1 115 kV line Plt 1-Raptor-Fssl Ck 17.3$
1 Communications Upgrade Communications between Anch-Fairbanks 15.0$
54.3$ Total Reliability Only Projects
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project, such as generation capacity deferral, value of unserved energy, water management,
additional green energy, firm fuel and energy deliveries for all utilities, and Bradley excess energy
delivery.
It is recognized that the costs included in this report are estimates and that changes in
assumptions can alter the conclusions and recommendations.
3 Detailed Summary
A detailed description of the projects and benefits for each of the Railbelt areas is presented
below. The appendix includes detailed, itemized cost estimates for the projects recommended in
this plan.
3.1 Kenai- Anchorage Transmission
Transmission between the Kenai Peninsula and the rest of the Railbelt system consists of a single
115 kV transmission line to deliver power to, or receive power from, Southcentral Alaska. This
line was completed in 1961 to transfer a relatively small amount of Cooper Lake Hydro power (16
MW) into the Anchorage area. The Bradley Lake Hydroelectric Project, commissioned in 1991,
has been constrained in its operation since its completion due to the inadequate transmission
system between the Kenai and the northern and southcentral Railbelt systems. In the past, the
Bradley Lake project participants successfully mitigated the constraints of the transmission
system to the greatest extent possible by cooperative agreements and actions among the utilities.
The changing atmosphere of the Cook Inlet gas situation and the evolving landscape of
generation in the Railbelt has foreclosed many of the mechanisms historically available to the
Railbelt utilities to mitigate the constraints on the Bradley Lake project. As a result of the loss of
the mitigation options and the changing aspects of the generation and gas systems, without
improvements to the transmission system between Anchorage and Kenai, the utilities will
experience substantial increases in both electrical line losses, lost generation capacity, and
operating costs due to the transmission constraints placed on transfers from the Kenai.
In addition to the near-term constraints identified above, the Anchorage-Kenai constraints
severely inhibit the integration of additional variable resources such as wind energy. These
constraints prevent Kenai hydro energy from being used as part of an overall hydro management
or coordination strategy to promote the integration of renewable energy. The lack of transmission
capacity also limits the amount of other Kenai resources that could be used to mitigate the impacts
of variable generation such as wind energy and will significant ly increase the cost of integrating
renewables into the Railbelt system. The Eklutna hydro facility is the only hydro resource not
constrained by the Railbelt transmission system.
The basic constraint of the Bradley Lake project is the lack of an adequate transmission system
to deliver the project’s energy from Kachemak Bay to Anchorage and Fairbanks. Besides only a
single transmission line between the Cooper Lake area and Anchorage, a single 115 kV
transmission line from Soldotna to the Cooper Lake area makes up the connection between the
majority of the Railbelt and Bradley Lake. These two single lines have a combined length of 146
miles. Although the lines have been well maintained and improved by the utility owners, they
were not originally designed to carry large amounts of power over long distances. For
comparison, the line between Anchorage and Fairbanks carries slightly less power than the
University to Dave’s Creek Line, but is constructed to a much higher voltage and uses two large
conductors per phase instead of the one small conductor per phase, as used on the Kenai line.
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The solution to eliminating the Bradley Lake constraints is an improved transmission system
between Anchorage and the Kenai. This can be accomplished by either an additional
transmission path between the two regions, upgrading the existing transmission line to a larger
capacity line, or a combination of both building a new line and improving the existing line.
The study evaluated all three options. Adding a new transmission line between the regions greatly
increases the reliability and relieves some constraints on Bradley Lake, but a new line by itself
does not remove constraints on Bradley Lakes’ energy, since Bradley Lake must be operated in
a manner to continue operation following the loss of either the new or the existing transmission
line. Upgrading the existing transmission line from Soldotna to Anchorage in lieu of a new line
was also studied, however it was not recommended due to higher costs, construction timing, and
constraints associated with continued operation of a transmission system with a single
transmission line between Kenai and Anchorage.
The recommended transmission system is composed of improvements to portions of the existing
Anchorage – Kenai transmission system, combined with a new transmission line connecting the
Southcentral area’s 230 kV transmission system at Beluga to the 115 kV transmission system at
Bernice Lake or Soldotna. The combination of these two projects results in the lowest overall
cost as well as the most benefits and fewest constraints on the Bradley project.
The routing of a new submarine cable and overhead transmission line were based on a paper
study of possible routes using our past experience with the previously dismissed Southern Intertie.
Other routing options that could reduce the cost of the line may be possible with further evaluation
of the project.
In addition to the Bradley Lake constraints, the single contingency line between Anchorage and
Kenai requires certain generators to operate on the Kenai. In order to ensure there is not
excessive loss of load following the opening of the single transmission line, the Kenai is required
to maintain certain levels of generation on-line as opposed to importing generation from other
areas. As the generation fleet ages, this may require replacement of thermal units on the Kenai
in a Railbelt system that is capacity rich in order to provide a base-loaded, more efficient unit to
meet this generation constraint.
A 35 MW/20 MWHr BESS is recommended in conjunction with the transmission improvements.
The project’s primary purpose is to provide contingency reserves for the loss of the Kenai Intertie
or HVDC line. However, it also provides benefits to the entire Railbelt area by supplying
contingency reserves and some regulating reserves to the system. The size of the BESS, in
conjunction with Hydro and other BESS resources can provide all the contingency reserves
required in the Railbelt without thermal generation. The project could be located in any area north
of the Kenai to provide these benefits.
A summary of the costs of the proposed projects to relieve the constraints on the Bradley Lake
hydroelectric project and the Kenai generation constraints is presented in Table 3-1. The costs
are estimated, budgetary figures within +/- 20%.
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Table 3-1: Kenai Project Costs
3.2 Southcentral Alaska Reliability
A single 115 kV transmission line between the Anchorage and the Palmer areas connects
AML&P’s Plant 2 to the Eklutna Hydro Plant. A recent upgrade of this line has added a second
circuit, which is not energized due to the lack of a substation at Fossil Creek and inadequate
substation space at Eklutna. A portion of this new circuit is energized as a radial line from the
EGS power plant. Improvements to the reliability of the Southcentral Railbelt system serving
Anchorage and the Mat-Su area consist of two substation projects required to place this additional
circuit into service. The substation projects are driven by reliability requirements. In the case of
the Eklutna substation project, the existing substation equipment has exceeded its useful life and
the station cannot be replaced in its current configuration.
The Fossil Creek Substation allows the interconnection of the second 115 kV transmission line
into the Railbelt system and also allows for a second interconnection between the ML&P system
and Fossil Creek through Raptor substation. This second path into the AML&P system eliminates
generation constraints for the new Eklutna Generation Station and increases the critical clearing
time for 115 kV faults to more manageable levels.
A second transmission line into the AML&P system via Raptor Substation increases reliability to
the AML&P/JBER area and completes the path between the AML&P 115 kV and the 230 kV
systems. This line segment is comprised of a Plant 1 – Raptor (7.0 Mi) section and a Raptor –
Fossil Creel (4.1 Mi) section.
A summary of the costs of the proposed projects for the Southcentral Railbelt are presented in
Table 3-2.
Table 3-2: Southcentral Project Costs
3.3 Anchorage-Fairbanks Intertie Reliability
Transfers between the Fairbanks area and the Anchorage/Kenai systems are currently limited to
a single line between the areas. Due to the single line, all power transfers are “economic” or
transfers that occur only when energy is available in the south through available generation and
1 Bernice Lake-Beluga HVDC 100 MW HVDC Intertie $ 185.3
2 35 MW/20 MWh BESS Anchorage area battery $ 41.1
3 Bradley-Soldotna 115 kV Line New line & Bradley/Soldotna sub $ 66.6
4 University-Dave’s Creek 230kV Reconstruct existing line $ 57.5
5 University-Dave’s Substations Convert line for 230 kV operation $ 36.3
6 Dave's Creek - Quartz Creek Upgrade line to Rail conductor $ 16.2
Electrical Projects Total $ 403.0
ProjectPriority Description Cost
(Millions)
1 Fossil Creek New 115 kV substation 11.9$
1 Eklutna Hydro New 115 kV substation 10.1$
1 115 kV line Plt 1-Raptor-Fssl Ck 17.3$
39.3$
Priority Station Description Costs
(Millions)
Total
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when the single line is in service. GVEA currently maximizes the use of the existing intertie, but
must maintain sufficient generation and fuel resources in its area in case the single intertie
between is out of service. The absence of a second transmission line between the areas
precludes the contracting for firm power between the Northern and Southern systems and
precludes GVEA from contracting for known quantities of fuel or energy from the southern utilities
including the sharing of capacity reserves across the Railbelt system.
The addition of a second line between Anchorage and Fairbanks increases the amount of energy
capable of being transferred between the areas from 69 MW of non-firm in the existing system to
over 189 MW of firm power sales with Healy 2 on-line (all of Fairbanks area load). It is important
to note the difference in service between the existing system and the proposed system when
comparing the improvements in transfer. Under the existing system, any transfer from Anchorage
above 30-40 MW will result in load shedding in the Fairbanks area following the loss of the single
line. This is considerably different than the 189 MW limit of the proposed system which would not
result in any customer outages for the loss of a single line.
The second transmission line spanning the 171 miles between Healy and Anchorage will prevent
loss of load in Fairbanks for single line outages and will allow GVEA to access electrical and gas
markets in the Southcentral system. It will also allow GVEA to evaluate the most economic
solution for replacement generation capacity as its power production fleet continues to age or if
coal resources are retired.
A new substation approximately mid-way between Healy and Douglas substations is proposed to
serve as a sectionalizing point between the line sections. The substation would lessen the impact
of the loss of one of the two line section between Healy and Douglas, lessoning the power swing
due to the loss of the line . The substation also improves the voltage control characteristics and
decreases the amount of required equipment needed for voltage control along the Douglas –
Healy corridor.
A summary of the costs of the proposed projects to provide reliability and economic energy
transfers between the northern and southern systems is presented in Table 3-3.
Table 3-3: Northcentral Project Costs
The analysis determined that upgrading the 138 kV lines into the Fairbanks area to 230 kV
essentially eliminated transfer constraints between southern generation resources and the
Fairbanks area. An upgrade of the existing lines to 230 kV operation would satisfy the
requirements of AKTPL-001-4 and increase the transfer capacity between the Anchorage and
Fairbanks areas. The costs of the 230 kV transmission line upgrades are presented in Table 3-
4.
Group Item Description Costs
(Millions)
1 Lorraine-Douglas Lorraine - Douglas 230 kV line/stations $ 128.5
2 Douglas – Healy line New 230 kV line operated at 138 kV $ 245.7
Communications Upgrade $ 15.0
Total $ 389.1
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Table 3-4: Northcentral Project Costs –230 kV Line Upgrades
3.4 Proposed System Transmission Maps
Transmission maps were created for the proposed transmission system and are shown below in
Figure 3-1: Northern Proposed Transmission System and Figure 3-2: Kenai and Southcentral
Proposed Transmission System.
Group Item Description Cost
(Millions)
1 Healy-Fairbanks 230 kV Convert 138 kV to 230
kV $ 107.9
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Figure 3-1: Northern Proposed Transmission System
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Figure 3-2: Kenai and Southcentral Proposed Transmission System
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4 Power Flow & Transient Stability Analysis
4.1 Introduction
The goal of the Railbelt Transmission Plan (“Plan”) system study is to determine the future
transmission system for the Railbelt. This portion of the study focuses on the technical
requirements of the system. The objectives of the Plan include improving reliability, mitigating
future cost increases to Railbelt ratepayers, relieving energy transfer constraints, allowing the use
of peaking capacity from the Bradley Lake hydroelectric project, and increasing energy transfers
between all areas of the Railbelt.
This technical portion of the study built from the Draft Plan dated March 17, 2014 (“Pre/Post –
Watana Transmission Study”) and other supporting studies. Portions of the technical results and
conclusions from the 2014 Draft Plan remain unchanged and are used to support the final
recommended system improvements. Some of the conclusions from the previous 2014 Draft
report, including various transmission configuration alternatives, steady state contingency
analysis, and loss analyses, remain unchanged. This system technical study assumed that the
economic justifications for the various system improvement projects recommended in the 2014
Draft Plan will be updated by the utilities as part of the AKTPL-001-4 compliance process.
A listing of the most important past system studies leading up to this Final Plan follows.
Pre/Post – Watana Transmission Study, March 17, 2014 (Draft Plan)
Kenai Transmission Study, March 7, 2014
Regulation Resource Study, March 7, 2014
Post Watana Transmission Study, January 27, 2014
Northcentral Analysis, May 3, 2013
The updated system study for the Final Plan includes the use of the recently adopted set of
Railbelt Utility Reliability Standards as well as the most current Railbelt system models. The
current Railbelt models incorporate various changes to the system including refinements to the
dynamic response of the system models based on benchmarking of the models.
4.2 Methodology
The methodology of the system study focused on two stages of analysis in order to meet the
objectives of the Plan. The first stage consisted of analyzing the existing system to identify the
limitations of the 2015 system. This primarily included the determination of the transfer limits
between the Kenai and Anchorage areas (Kenai Intertie) and the Anchorage and Fairbanks areas
(Alaska Intertie). W eak points or areas where system improvements may be necessary or
required based on the recently adopted transmission planning criteria were identified by system
studies utilizing dispatch and unit commitment scenarios designed to identify system limits. The
results of the first stage of the analysis were used as transmission constraints for the economic
analysis.
The second stage of analysis involved the determination of system improvements required to
meet the transmission planning criteria. The final recommended system improvements were
screened using production cost simulations that are included in a separate document. The costs
of the improvements are included within this report. Since the benefit analysis only included
production cost simulations and was not a complete benefit analysis, its outcome and results were
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provided for completion by the utilities as part of the due diligence required in AKTPL-00104. The
2014 Draft Plan report included an extensive assessment of various system improvement options.
These improvements have not changed enough from the results in the Draft Plan to change the
final recommendations. As a result, the focus of this updated system study was to re -evaluate
the limitations of the existing system and the technical benefits of the recommended options found
in the 2014 Draft Plan. No changes in the recommended system improvements, when compared
to those in the 2014 Draft Plan, are proposed, with the exception that further studies indicate a
need for a larger BESS in the Anchorage area.
4.3 System Analysis and Base Cases
The system study was performed using the Power Systems Simulator Engineer (“PSS/E”)
software. Power flow and transient stability analysis used seasonal load and generation
variations and several types of contingencies. The contingencies included generation trips,
transformer faults, and line fault conditions.
The starting base cases used for the study consisted of the most current 2016 Railbelt System
Studies Subcommittee (SSS) cases dated approximately 12/11/2015. The cases include
changes to the models determined during the recent benchmarking analysis completed in the fall
of 2015. One base case from each of the three seasons was used as a starting point. Table 4-1
includes the loads found in the bases cases. Table 4-2 describes the under-frequency load
shedding (UFLS) scheme found for each season. The Railbelt utilities indicated that insignificant
load growth is expected in the near future and that the loads in the SSS cases represent
reasonable seasonal load for the purposes of the transmission planning study. Due to the volume
of cases used in this study, detailed summaries of each power flow and transient stability case
are not included in this report. Rather, the power flow and stability cases are available
electronically to the Railbelt utilities for their review. The most limiting cases are described in
detail in the sections below.
Table 4-1: Seasonal and Utility Loads (MW)
Table 4-2: Railbelt UFLS Scheme Load Distribution
4.4 Unit Commitment, Dispatch, and Spinning Reserves
The setup for the various generation scenarios used for the study was based on the commitments
and dispatches found in the SSS cases. Modifications to generation commitments and dispatches
were necessary for the study cases to determine the intertie limit s, and other generation
sensitivities found during existing and future system conditions. The resulting commitments,
HEA AMLP GVEA CEA SES MEA Load Losses
Winter Peak Base 91.7 182.0 226.5 229.0 9.0 138.0 876.2 33.6
Summer Peak Base 90.6 167.8 190.8 161.0 8.0 86.0 704.2 28.7
Summer Valley Base 48.3 89.0 118.8 94.0 6.0 50.0 406.0 24.9
Total SystemSeasonCase
Description
Utility
Load 393 Load 670 Load 840
MW %MW %MW %
59.0 0.083-0.15 0.05-0.0833 39.0 9.9%69.0 10.3%85.1 10.1%
58.7 0.083-0.15 0.05-0.0833 43.3 11.0%75.5 11.3%92.8 11.1%
58.5 0.083-0.15 0.05-0.0833 41.5 10.6%70.8 10.6%91.4 10.9%
Frequency
Set Point
(Hz)
Pickup Timer
(sec)
Breaker
Timer (sec)
Load by Stage & Season (MW/% Load)
Summer Valley Summer Peak Winter Peak
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dispatches, and spinning reserves reflect the generation scenarios needed in a planning study
and do not necessarily reflect the scenarios used in an operations study. The cases represent a
reasonable spectrum of conditions, especially at high transfer levels, that can be expected to
normally occur. This includes cases with no extra spinning reserves and no regulating reserves,
beyond the minimum requirements. This ensures that the results produce a long range plan that
can work in a wide range of operating conditions, without putting the system at undue risk for
severe outages or possible system collapse.
The amount of spinning reserves used in the cases varied depending on the particular area of
analysis. For studying the existing Kenai Intertie, the amount of spin found North of Dave’s Creek
Substation was kept to levels exceeding the amount of transfer on the Kenai Intertie. In most
cases, this level was larger than the largest conventional generation contingency.
Both hydro based and combustion turbine / steam turbine (CT/ST) based spinning reserves were
studied. The two different reserve cases determined the sensitivity of the system response to the
type of units carrying the reserves, and to help define any limits for the economic analysis. The
hydro-based cases maximized the spin available on the Bradley Lake, Cooper Lake, and Eklutna
Hydro generation units (Bradley Lake spin was limited to a maximum of 27 MW per existing
Railbelt operating practices). The CT/ST based spin cases had limited or no spin available from
the hydro units. The GVEA Battery Energy Storage System (BESS) at Wilson substation provided
26 MW of spin in the PSS/E models for all cases analyzed. The CT/ST spin was usually located
at Plant 2A, although some cases required spin on the Nikiski CT/ST and / or the Soldotna CT.
Other Kenai Intertie and Alaska Intertie export limits were also studied as sensitivities.. Some of
the Kenai Intertie alternatives included Cooper Lake on/offline and variations in output and
commitment of the Nikiski and Soldotna units. The Healy area generation (Healy #1, #2, Eva
Creek) commitment was also varied to determine the Alaska Intertie and Healy export limits during
varying generation conditions in the Northern area.
4.5 Intertie Export Limits
The intertie flows were varied to determine the stability based flow limits. The change in flow was
facilitated by changing the generation in one area, either Kenai or Fairbanks, and allowing the
generation in the Anchorage area to provide the corresponding opposite change in generation
and to adjust for changes in system losses. Typically, Plant 2A was used for the generation
adjustments in Anchorage, although using either SPP or EGS plants would produce similar
results.
The change in generation produced a range of flows through each intertie, with each case then
checked to determine the system stability. The step size for the change in generation varied
throughout the study was roughly 3-5 MW. Throughout each range of flows, no changes in unit
commitment were made. The total system spin was therefore relatively constant and only
changed due to changes in system losses.
The export limits were determined by the detection of an out-of-step condition, a loss of
synchronism condition, and/or a voltage collapse condition. The export limit results stated in this
report represent the level of intertie flow one step lower (3-5 MW) than the case that resulted in
the stability criteria violation. Therefore, the limit is 0-5 MW below the point of instability, unless
explicitly stated.
The transfer limits presented in the study are a combination of stability, voltage, thermal,
generation, or load based limits. In some cases, the stated limit is not based on a criteria violation,
but one based on practical operating considerations. For instance, some of the limits for the Kenai
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and Fairbanks Interties are indeterminable because the limit is higher than the available
load/generation served through the Intertie.
4.6 Assumptions
Several assumptions relating to the modeling and methodology were used to complete the
analysis. A brief description of the major assumptions follows.
4.6.1 BESS Spinning Reserves
The GVEA BESS has been configured to provide 26 MW of spin for almost all PSS/E simulations.
The only exception to this occurs when the BESS needs to be auto-scheduled for a specific
disturbance to a value greater than 26 MW. The BESS model within PSS/E does not provide
parallel control functions for spinning reserves and auto-scheduling. However, the actual
equipment in the field does provide for parallel control functions. To work around this issue for
simulation purposes, the BESS was configured for either 26 MW of spin or was auto-scheduled
from 26-40 MW depending on the disturbance and system conditions. This work around for the
PSS/E model does not negatively impact the simulation results.
4.6.2 HVDC Tie Modeling
The proposed HVDC tie was modeled within PSS/E using constant power loads to simulate the
HVDC interconnection between Bernice Lake Substation and Beluga Substation. The tie flows
along the HVDC line were scheduled at the 75 MW nominal rating of the tie under normal
conditions. The continuous overload capacity of the tie was assumed to be 100 MW. Four
percent losses were assumed for the tie. The PSS/E modeling consists of a positive valued load
placed at Bernice and a negative value load placed at Beluga for flow from Bernice to Beluga.
4.6.3 Nikiski Overfrequency Relaying
The Nikiski CT modeling within PSS/E includes an overfrequency protective relay. The relay trips
the unit when the unit frequency exceeds 60.6 Hz for 3 seconds. The relay was modeled properly
within PSS/E to reflect actual settings confirmed in the field, but has been disabled for this study,
due to the negative impact of the unit trip on the Kenai frequency for Kenai islanding events. In
simulations, the Nikiski unit frequently trips offline when the Kenai is separated from the
Anchorage area, and can negatively impact the Kenai system, frequently contributing to load
shedding. EPS recommends that this overfrequency relay setting be re-evaluated in order to
avoid tripping Nikiski when possible.
4.6.4 Fairbanks Area Generation
The minimum amount of Fairbanks area generation required for stability and voltage purposes
impacted the results of the study. This is especially true as Douglas export limits to the north
were increased with system improvements and the stability limits to the north exceed the load
demand in Fairbanks. The generation or unit commitment found in the 2016 SSS power flow
cases was used as the starting point for our cases. Sensitivity cases were run with some or all
GVEA generation in Fairbanks taken offline. However, DOD generation remained on-line for all
cases.
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4.7 PSS/E Modeling Changes
Various changes to the Railbelt PSS/E model were made since the Draft Plan was produced.
Many of the changes were subtle and considered normal maintenance items necessary as the
utility systems are upgraded and more PSS/E benchmarking is performed. The Railbelt SSS has
been very active in identifying and administering the required changes to the PSS/E models. The
changes include modifications to the power flow and dynamic models. The following is a summary
of the changes made to the models that may contribute to differences between the Draft and Final
Plan system study results.
4.7.1 Dynamics
Teeland/Healy/Gold Hill SVC’s – New custom Alstom models (power flow/dynamics)
EGS Units – Changes to generator, exciter, governor, and under-excitation limiter models,
from benchmarking study (power flow/dynamics)
SPP Units – Governor response, inertia, from benchmarking study
Beluga 3 Unit – Governor response, droop, from benchmarking study
North Pole CT Unit - Governor droop, from benchmarking study
Chena 5 Unit – Turn off governor due to lack of response
UFLS Settings – Various modifications to the UFLS scheme from the SSS
UF/OF Settings – Various islanding and generation unit under and over frequency relay
settings additions and modifications, from the SSS
GVEA BESS – Auto-scheduling for specific system conditions
4.7.2 Power Flow
2016 Loads
Healy #1, #2 – MVAr control limits
SPP Unit Transformers – Impedance and other changes
University-Indian Line – Impedance change due to reconductoring
Plant 2A – Generator source impedance change
4.8 Performance Standards & Criteria
The performance standard used to perform the system analysis and assess the system was
Standard AKTPL-001-4. The final revision, submitted for IMC approval, of this document is dated
February 11, 2016. The development of this standard included eight revisions starting November
5, 2015. The development of the Planning and Operating standards coincided with the Final Plan
and resulted in different criteria than was used in the Draft Plan.
Of particular importance in the standards is the requirement that unit commitment and dispatch
scenarios be selected to maximize transfers between load and generation areas. Additionally,
the standard requires that no single contingency shall result in non-consequential loss of load
(load not directly served from the outaged line) and no single contingency shall result in the loss
of a firm transmission path.
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4.8.1 Stability Criteria
The transient stability criteria include limits on the system frequency, voltage levels, system
response, and unit response. The transient criteria listed below were used for N-1 contingency
analysis.
Sustained voltages on the transmission system buses must not be below 0.8 per unit (pu)
Transient frequency must stay between 57 Hz and 62 Hz
System response must not exhibit large or increasing amplitude oscillations in frequency
or voltage
Units must not exhibit out of step or loss of synchronism response
Single contingency events cannot cause uncontrolled load shedding
It is not acceptable to operate the system in a configuration that would result in unstable system
response for single contingencies. Therefore, infrastructure improvements or operational
constraints must be completed to eliminate the possibility of an unstable condition occurring.
4.8.2 Voltage Criteria
The criteria included limits on the maximum and minimum voltages allowed on the Railbelt system
as well as operational limits of the generators and the SVC’s. The criteria are listed below.
Voltages at 230 kV, 138 kV undersea cables must be below 1.02 pu
Voltages at 230 kV, 138 kV, and 115 kV substations serving load must be below 1.05 pu
Voltages at 230 kV, 138 kV, and 115 kV substations NOT serving load must be below 1.10
pu
Voltages at 230 kV, 138 kV, and 115 kV substations must be above 0.95 pu
As with the stability criteria, it is not acceptable to operate the system in a configuration that would
result in the system violating the voltage criteria. Therefore, infrastructure improvements or
operational constraints must be completed to eliminate the possibility of a voltage violation
occurring.
4.9 Contingencies
As previously discussed, the contingencies performed for the study included gener ation,
transformer, and transmission line outages. In accordance with Standard AKTPL-001-4, a list of
the contingencies anticipated to have the most severe impact was created. The most limiting
contingencies, those that ultimately determined the final recommended system improvements,
varied from case to case based on system conditions and generation scenarios.
The following list describes the disturbances simulated for this analysis. Table 4-3 through Table
4-6 list the contingencies used for the analysis. The list includes all disturbances considered in
the existing and future analysis. General comments about the contingencies follow.
All fault contingencies were simulated with a three-phase fault.
Almost all clearing times associated with generator, line, and transformer disturbances
used five cycle clearing times. The only exception to this is for the far end clearing times
for a fault on the Douglas to Healy line (30 cycles) in the existing system.
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Generator contingencies included the trip of the generator. For some contingencies, a
three-phase generator bus fault preceded the generator trip, cleared by the generator
breaker.
EGS and North Pole CC generation contingencies were simulated by the loss of a GSU
transformer where multiple units interconnect to the system via a single transformer.
Faults on the Bradley Lake-Soldotna line were simulated with and without the transfer trip
of one of the Bradley Lake units, for sensitivity analysis purposes.
For the existing system simulations, the GVEA BESS was auto-scheduled according to
the type of disturbance and system operating conditions. No auto-scheduling was
required for the future system with the recommended improvements.
For the future transmission system, any fault and subsequent line clearing condition
opening the 115 kV line from Soldotna to Dave’s Creek results in an increase of 25 MW
in scheduled flow on the HVDC tie from Bernice Lake to Beluga.
Table 4-3: Kenai Area Line/Transformer Contingencies
ID Description Comment
a00 Dry Run No disturbance
a01 Bradley-Soldotna_115@Soldotna No Bradley unit transfer trip
a02 Bradley-Soldotna_115@Brad_Lk No Bradley unit transfer trip
a08 Quartz-Daves_115@Daves_Ck
a11 Soldotna_SVC_115@Soldotna
a13 Soldotna-Diamond_115@Soldotna
a14 Soldotna-Diamond_115@Diamond
a15 Bradley-Soldotna_115@Sold-xfer Bradley unit transfer trip
a16 Bradley-Soldotna_115@Brad-xfer Bradley unit transfer trip
a20 Quartz-Daves_115@Daves_Ck-DC Increase DC tie flow
a22 Bernice-Beluga_DC@Bernice
a23 Bernice-Beluga_DC@Beluga
a24 Soldotna-Sterling@Soldotna No increase DC tie flow
a25 Soldotna-Sterling@Sterling No increase DC tie flow
a26 Soldotna-Sterling@Soldotna-DC Increase DC tie flow
a27 Soldotna-Sterling@Sterling-DC Increase DC tie flow
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Table 4-4: Southcentral Area Line/Transformer Contingencies
ID Description Comment
b01 230_Cable_230@Plant_2
b02 230_Cable_230@Pt_Mack
b03 University-Plant_2_230@University
b04 University-Plant_2_230@Plant_2
b05 Pt.Mack-Teeland_230@Pt_Mack_RAS Teeland-Douglas line transfer trip >50 MVA
b06 Pt.Mack-Teeland_230@Teeland_RAS Teeland-Douglas line transfer trip >50 MVA
b09 Anchorage-University_115@University
b10 Plant_2-Anchorage_115@Plant_2
b11 Plant_2-Anchorage_115@Anchorage
b12 Plant_2-EGS_115@Plant_2
b13 Plant_2-EGS_115@EGS
b14 Beluga-Pt.Mack@Beluga
b15 Beluga-Pt.Mack@Pt.Mack
b16 Teeland-Hospital_115@Teeland
b17 Teeland-Hospital_115@Hospital
b18 Teeland-Douglas_138@Teeland
b19 Teeland-Douglas_138@Douglas
b20 ITSS-University_138@ITSS
b21 ITSS-University_138@University
b22 EGS_XFMR-@XFMR Four units maximum lost generation
b23 ITSS-Pt_Mack1_138@ITSS
b30 Plant_2-Fossil_115@Plant_2
b32 230_Cable_230@Plant_2
b33 230_Cable_230@Lorraine
b34 Lorraine-Teeland@Lorraine
b35 Lorraine-Teeland@Teeland
b36 Lorraine-Douglas@Lorraine
b37 Lorraine-Douglas@Douglas
b38 Lorraine-Pt_Mack@Lorraine
b39 Lorraine-Pt_Mack@Pt_Mack
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Table 4-5: Northern Area Line/Transformer Contingencies
Table 4-6: Generation Contingencies
4.10 Existing Kenai Intertie
The key objective for the existing Kenai Intertie portion of this study was to determine the
maximum export limits. The export flow was measured at Dave’s Creek Substation with positive
ID Description Comment
c01 Healy-Douglas@Healy GVEA BESS autoscheduling
c02 Healy-Douglas@Douglas GVEA BESS autoscheduling
c03 Healy-Gold_Hill@Healy GVEA BESS autoscheduling
c04 Healy-Gold_Hill@Gold_Hill GVEA BESS autoscheduling
c05 Healy-Eva_Creek@Healy GVEA BESS autoscheduling
c06 Healy-Eva_Creek@Eva_Creek GVEA BESS autoscheduling
c07 Eva_Creek-Wilson@Eva_Creek GVEA BESS autoscheduling
c08 Eva_Creek-Wilson@Wilson GVEA BESS autoscheduling
c09 North_Pole_Combined_XFMR-@XFMR GVEA BESS autoscheduling
c09 North_Pole_Combined_XFMR-@XFMR GVEA BESS autoscheduling, CT/ST lost generation
c10 Douglas-Gold_Creek@Douglas
c11 Douglas-Gold_Creek@Gold_Creek
c12 Healy-Gold_Creek@Healy
c13 Healy-Gold_Creek@Gold_Creek
c14 Healy-Eva_Creek_230@Healy
c15 Healy-Eva_Creek_230@Eva_Creek
c16 Healy-Clear_230@Healy
c17 Healy-Clear_230@Clear
c18 Wilson_XFMR_230@230_XFMR
c19 Wilson_XFMR_230@138_XFMR
c20 Gold_Hill_XFMR_230@230_XFMR
c21 Gold_Hill_XFMR_230@138_XFMR
ID Description Comment
g00 Bradley 1
g01 Bradley 1/Fault
g02 Nikiski 1
g03 Nikiski 1/Fault
g04 Sold 1
g05 Sold 1/Fault
g06 Plant 2a 10
g07 Plant 2a 10/Fault
g08 SPP 12
g09 SPP 12/Fault
g10 Beluga 5
g11 Beluga 5/Fault
g12 Healy 2 GVEA BESS autoscheduling
g12 Healy 2 No GVEA BESS autoscheduling
g13 Healy 2/Fault
g14 NPCC 3 GVEA BESS autoscheduling
g14 NPCC 3 No GVEA BESS autoscheduling
g15 Chena 5
g16 NP 1 GVEA BESS autoscheduling
g16 NP 1 No GVEA BESS autoscheduling
g18 Healy 1 GVEA BESS autoscheduling
g18 Healy 1 No GVEA BESS autoscheduling
g20 Plant 2a 9
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flow to Hope Substation. The export limits were determined based on the minimum stability,
voltage, or thermal limit determined by applicable studies. Several generation scenarios were
used to determine the export limit’s sensitivity to unit commitment and output.
4.10.1 Generation Scenarios
The generation scenarios shown in Table 4-7 through Table 4-9 were used to determine the
export limits. The amount of generation for each main generation source is shown , in MW . The
amount, type, and location of spin are also provided along with the amount of export for the Kenai
Intertie and the Alaska Intertie. Each case represents the maximum export conditions while
maintaining system stability.
Two base cases for each season are shown in the Tables. The two cases differ in the location of
the spinning reserves. There is either an emphasis on Hydro or on CT/ST spin. The additional
generation sensitivities include changing the status of Cooper Lake, varying the Soldotna CT unit
output, varying the commitment of Nikiski CC and Soldotna CT, and changing the status of the
Nikiski ST unit.
To vary the intertie flow and determine the export limit, Bradley Lake, Nikiski, or Soldotna
generation was adjusted in the Kenai area while Plant 2A was adjusted in the Anchorage area.
The emphasis on the type of spin determined whether or not Bradley Lake, Nikiski, or Soldotna
generation was varied.
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Table 4-7: Existing Winter Peak Base Case Dispatches
Description
Case Name
Generation Spin Generation Spin
Bradley Lake Hydro 115.7 4.3 119.8 0.2
Cooper Lake Hydro 14.0 5.6 19.6 -
Eklutna Hydro 2.0 38.0 40.0 -
Nikiski CC 60.8 0.2 53.9 7.1
Soldotna CT - -
Tesoro 10.0 - 10.0 -
Beluga Plant 78.6 - 78.6 -
SPP 188.5 (0.0) 188.5 (0.0)
Plant 1 - -
Plant 2a 93.3 21.7 51.6 63.4
EGS 136.0 - 136.0 -
Healy 1 28.5 - 28.5 -
Healy 2 61.9 0.0 61.9 0.0
Eva Creek 10.0 - 10.0 -
GVEA BESS - 26.0 - 26.0
North Pole CC 64.7 0.3 64.7 0.3
Chena 5 23.0 - 23.0 -
UAF 11.0 - 11.0 -
Fort Wainwright 15.0 - 17.0 -
Eielson AFB 8.0 - 8.0 -
Fort Knox (11.0) - (11.0) -
Generation/Spin Total 910.0 96.2 911.0 97.1
Dave's North Spin 86.1 89.8
Hydro Spin 47.9 0.2
CT/ST Spin 48.3 96.9
Dave's Creek - Hope Flow 84.9 87.5
Douglas - Stevens Flow 22.2 20.1
Base - Hydro Spin
wp_g010_s085_n022
Base - CT/ST Spin
wp_g110_s087_n020
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Table 4-8: Existing Summer Peak Base Case Dispatches
Description
Case Name
Generation Spin Generation Spin
Bradley Lake Hydro 119.8 0.2 119.8 0.2
Cooper Lake Hydro 19.6 - 19.6 -
Eklutna Hydro 2.0 38.0 40.0 -
Nikiski CC 51.1 - 51.1 -
Soldotna CT - -
Tesoro 8.0 - 8.0 -
Beluga Plant 59.0 - 59.0 -
SPP 141.0 (0.0) 141.0 (0.0)
Plant 1 - -
Plant 2a 71.2 21.6 31.5 61.3
EGS 85.0 - 85.0 -
Healy 1 26.4 - 26.4 -
Healy 2 61.9 - 61.9 -
Eva Creek 6.0 - 6.0 -
GVEA BESS - 26.0 - 26.0
North Pole CC 40.0 - 40.0 -
Chena 5 23.0 - 23.0 -
UAF 5.0 - 7.0 -
Fort Wainwright 15.0 - 15.0 -
Eielson AFB 10.0 - 10.0 -
Fort Knox (11.0) - (11.0) -
Generation/Spin Total 733.1 85.8 733.4 87.5
Dave's North Spin 85.6 87.3
Hydro Spin 38.2 0.2
CT/ST Spin 47.6 87.3
Dave's Creek - Hope Flow 85.5 85.5
Douglas - Stevens Flow 19.5 17.3
sp_g110_s086_n017sp_g010_s086_n020
Base - Hydro Spin Base - CT/ST Spin
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Table 4-9: Existing Sumer Valley Base Case Dispatches
4.10.2 Results
The results of the analysis for the existing system show that the Winter Peak cases were limited
by stability or voltage conditions, while the summer cases were primarily limited by the thermal
ratings of the 115 kV line between Soldotna and Dave’s Creek. Table 4-10 describes the limits
along with the limiting condition and the basic generation configuration differences.
Description
Case Name
Generation Spin Generation Spin
Bradley Lake Hydro 91.6 27.0 119.8 0.2
Cooper Lake Hydro 14.0 5.6 19.6 -
Eklutna Hydro 2.0 38.0 40.0 -
Nikiski CC 55.3 - 22.7 32.6
Soldotna CT - -
Tesoro 2.9 - 2.9 -
Beluga Plant - - - -
SPP 109.1 (0.1) 72.9 36.1
Plant 1 - -
Plant 2a 17.9 37.5 17.2 38.2
EGS 34.0 - 34.0 -
Healy 1 - -
Healy 2 61.9 - 61.9 -
Eva Creek 7.9 - 7.9 -
GVEA BESS - 26.0 - 26.0
North Pole CC - - - -
Chena 5 23.0 - 23.0 -
UAF 1.5 - 1.5 -
Fort Wainwright 5.0 - 5.0 -
Eielson AFB 5.0 - 5.0 -
Fort Knox - - - -
Generation/Spin Total 431.1 134.0 433.5 133.1
Dave's North Spin 101.4 100.3
Hydro Spin 70.6 0.2
CT/ST Spin 63.4 132.9
Dave's Creek - Hope Flow 96.2 95.1
Douglas - Stevens Flow 17.0 17.0
sv_g010_s096_n017 sv_g110_s095_n017
Base - Hydro Spin Base - CT/ST Spin
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Table 4-10: Seasonal Results – Final Export Limits
4.10.3 Explanation of Limits
The limits, as shown in Table 4-10, were derived as follows: The stability limit was determined
by stability simulations where the initial flow equaled the flow limit, a contingency was simulated
and the system responds, and the result was a stable system response. The flow was then
increased in increments of 5 MW until an instability was simulated. The stability limit was the last
stable response prior to the instability and these limits are shown in Table 4-10 with a stability
margin of 5 MW.
In a parallel manner, the amount of power transfer limited by voltage is the initial steady state flow
on the Dave’s Creek – Hope line, such that when the contingency reserves on the Kenai are
required in Anchorage/Fairbanks, the resulting flow on the Kenai tie results in a steady state
voltage along the tie of 0.95 per unit. Power flow cases were run for the different generation
scenarios to determine the flow limit along the tie where a low voltage of 0.95 per unit (pu) is
reached. The voltage limit used in the results is derived by taking the flow value that yields a
voltage of 0.95 pu, subtracting the reserves on the Kenai, and then subtracting 5 MW of margin.
The reserves range from 27 MW for Bradley Lake alone, to 47 MW representing 27 MW at Bradley
Lake, 11 MW from HEA, and another 9 MW from Cooper Lake.
Likewise, the thermal based export limit was derived by taking the seasonal line ratings and
subtracting 27 to 47 MW for reserves, with no extra margin added in. No margin was added
because thermal limits include inherent time delays before damage occurs, allowing time for
generation to be re-dispatched to alleviate the overload.
4.10.4 Winter Peak
For the Winter Peak cases, the thermal rating (173 MW) of the intertie is far greater than the
voltage or stability constraints. Thus, there are no thermal rating concerns related to the Winter
Peak cases.
The voltage limit is a steady state limit based on the minimum voltage found on the 115 kV intertie.
The minimum voltage allowed is 0.95 pu and this typically occurs at actual export levels of 105
MW when Cooper Lake is online and 95 MW when offline. During these higher transfer
conditions, the lowest voltage is typically found at Portage Substation in the existing system.
Reserves of 27 to 47 MW are included in the voltage based flow limits as previously discussed,
plus a margin of 5 MW.
Voltage Thermal Stability
both online on on both online 53-73 126-146 87
both online on on 43-63 126-146 72
both online on both online 53-73 126-146 80
both online on 43-63 126-146 67
both online on both online 53-73 126-146 68
both online on on both online 53-73 49-69 88
both online on on 43-63 49-69 73
both online on both online 55-75 49-69 86
both online on 54-74 49-69 61
both online on both online 53-73 49-69 67
both online on both online 61-81 49-69 90
both online on 50-70 49-69 76
both online on both online 61-81 49-69 84
Limits (MW)
WP
SP
SV
Season Bradley Lake Nikiski CC Soldotna Cooper Lake
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The Winter Peak cases were limited by voltage when Bradley Lake, Nikiski, and Soldotna units
are all online and high reserve levels from the Kenai area are relied upon.
For the other Winter Peak cases with less generation online in the Kenai area, the export limits
were limited by stability constraints. The limiting contingency in all cases is the fault and trip of
the Soldotna SVC transformer resulting in an out-of -step condition on the Kenai Intertie.
4.10.5 Summer Peak & Summer Valley
Unlike the Winter Peak cases, the summer cases were dominated by thermal overload conditions
limiting the export levels. The thermal rating (96 MW) of the intertie is nearly half of the winter
rating. The section of the tie that is the heaviest loaded varies depending on the output of Cooper
Lake. With Cooper Lake online, the heaviest loaded line section is Quartz Creek to Dave’s Creek.
With Cooper offline, all of the exported power flows on the Soldotna to Sterling line, thus making
it the heaviest loaded line section under these generation conditions.
The sole summer case exhibiting a stability limit has a generation scenario with Nikiski generation
offline and the Soldotna unit online. Similar to the Winter Peak case results, the stability limit was
a fault and trip of the Soldotna SVC transformer. Note that the stability limit was only slightly lower
than the thermal limit for this case (75 MW).
4.10.6 Spinning Reserve Sensitivities
Table 4-11 illustrates the differences in the export stability limits comparing cases with an
emphasis in Hydro versus CT/ST spin, for the fault and trip of the Soldotna SVC. The comparison
shows that the difference is negligible for all seasons and generation configurations studied. The
largest difference found is 3 MW. This value is within the tolerance, or incremental steps in flows,
used to determine the limiting export level. The difference in type of spin is more significant for
the contingencies where generation is lost and the inertial and governor response of the
generation units is more of a factor in the results. Note that the results in Table 4-11 do not
include a stability limit margin of 5 MW.
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Table 4-11: Seasonal Results – Spin Comparison
The two most significant outages that resulted in load shedding were the loss of the Kenai tie,
and the trip of Beluga 5. Additionally, the loss of Healy 2 caused load shedding.
In all cases, there were spinning reserves online greater than the size of the outage. This also
includes the Kenai tie outage case where the spin north of the tie outage was equal to or larger
than the flow on the tie. The Kenai tie outage simulations were performed for flow levels at the
stability limit which was greater than the voltage or thermal based limit in most cases.
The under-frequency response of the spinning reserves on the existing system consists of
response from the Wilson BESS, the combustion turbines, and the hydro units. The response is
a complex interaction of all these components.
A detailed analysis of the amount and quality of spin necessary to avoid load shedding per the
performance criteria was not completed for the existing system study and is outside the scope of
this study. Additionally, the issues of spin amounts and spin quality are impacted by all the
generation changes that have recently occurred or are about to occur in the Railbelt. These
changes include the addition of a number of lighter inertia units such as aero-derivative
combustion turbines, combined with the retirement of the larger HRSG units.
4.10.7 UFLS
The existing Railbelt system experiences UFLS activation for many single contingencies under
most operating conditions. UFLS activation increases as the spin levels on hydro units (Bradley
Lake, Cooper Lake, and Eklutna Lake) is increased. UFLS activation for most contingencies
cannot be prevented without substantial increases in thermal generation or other fast-acting
contingency reserves.
The UFLS results between the Hydro spin cases compared to the CT/ST spin cases provide some
insight into the differences in quality of spin. Some sensitivity cases were run that indicated that
the UFLS results were dependent on how much spin is on hydro units versus combustion turbines,
and on how many combustion turbines carry spin. For instance, 20 MW of spin on one CT
provides a measurably poorer response than 20 MW of spin spread equally over 5 units.
Hydro CT/ST Hydro CT/ST Hydro CT/ST
Base 85 87 47.9 48.3 0.2 96.9
Base - Cooper 72 72 41.7 36.9 0.2 79.3
Base + Sold Max 92 93 70.6 61.1 0.2 149.9
Base + Sold Min 95 94 66.6 84.2 0.2 149.9
Base 86*86*38.2 47.6 0.2 87.3
Base + Red. HEA Load 91**91**38.2 53.9 0.2 93.6
Base - Cooper 66*66*38.2 31.0 0.2 70.8
Base - Nikiski + Sold 73 72 41.8 37.0 0.2 80.1
Base + Sold Max 96 93 68.5 62.7 0.2 129.6
Base + Sold - Cooper 80 78 65.0 49.9 0.2 111.9
Base + Sold Min 93 94 58.3 72.8 0.2 129.2
Base 96 95 70.6 63.4 0.2 132.9
Base - Cooper 84 81 64.5 53.2 0.2 115.3
Base - Nikiski + Sold 90 89 65.0 58.3 14.0 107.7
Kenai area Base generation configuration includes 2-Bradley units, Nikiski CC, and 2-Cooper units online
Soldotna Min assumed to be 28 MW
* Limit may be larger, no spin remaining south of Dave's Creek
** Reduced load to increase export capacity
SV
SP
WP
Hydro Emphasis CT/ST EmphasisGeneration Configuration
Spin (MW)
Season Stability Export Limit (MW)
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However, a definitive evaluation of spin amounts and spin quality was outside the scope of the
transmission planning study.
4.10.8 Bradley Lake Limits
The Bradley Lake Plant is limited in total plant output due to instabilities related to the loss of the
Bradley Lake-Soldotna 115 kV line. At high plant output levels, when there is a fault and trip of
the Bradley-Soldotna line, the Bradley Lake units lose synchronism with the remaining system.
Historically, a remedial action scheme has been proposed for this event, but the RAS is not
currently in service. Table 4-12 provides the approximate plant limits for each season, assuming
that the RAS is not in service. Note that the loss of generation for a single line outage such as
the Bradley Lake – Soldotna 115 kV line is not compliant with the transmission planning criteria.
In addition to the stability, voltage, and thermal limits, the Bradley Lake plant limits must meet the
performance criteria.
Table 4-12: Bradley Lake Plant Limits with No RAS
4.11 Anchorage-Fairbanks - Alaska Intertie
The key objective for evaluating the existing Alaska Intertie was to determine the maximum export
limits through the Alaska Intertie. The export flow was measured at Douglas Substation with
positive flow north toward Healy. Three key values were required to fully describe the flow from
Anchorage to Fairbanks and to capture the limiting conditions. These values are (1) the flow north
out of Douglas, (2) the generation at both Healy and Eva Creek, and (3) the total flow north leaving
the Healy / Eva Creek area. Only two of these values can be varied independently. For each
limiting condition, either the limit is reached from the Douglas line looking north, or from the two
lines north out of the Healy / Eva Creek area toward Fairbanks. The limits described below include
each of the three key quantities and identify what line section is the limiting condition.
The export limits were determined based on the minimum stability limit. The Alaska Intertie was
not constrained by the same thermal and voltage sensitivities as seen for the Kenai Intertie. Many
generation scenarios were used to determine the export limit sensitivity to unit commitment and
output in the Fairbanks, Healy, and Anchorage areas.
4.11.1 Generation Scenarios
The generation scenarios chosen to determine the stability limits for the Alaska Intertie were
based on two initial assumptions. First, the Kenai area generation and export level from the Kenai
Intertie remains constant at the seasonal stability limit determined in this study. Second, eight
generation scenarios for the Healy area generation were created to cover the potential generation
configurations and variations in output. These scenarios ranged from all Healy area generation
at its maximum output to no generation online in the Healy area. A description of the eight
scenarios is presented in Table 4-13. The total range in Healy area generation is 0-114 MW.
WP 110
SP 111
SV 96
Plant Limit with
No RAS (MW)Season
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Table 4-13: Healy Area Generation Scenarios
Tables 4-14 through 4-16 describe the generation scenarios used to determine the stability limits.
Each season is shown with four different dispatches. Two of the dispatches represent the
generation with a Hydro based emphasis on spin, while the other two represent the CT/ST spin
emphasis cases. In these Tables, only two of the eight Healy area generation scenarios are
provided. The two shown illustrate the two extreme cases with the Healy area generation at its
maximum and minimum values.
The Fairbanks area generation used in the Winter Peak and Summer Peak cases is similar to the
SSS provided cases. The North Pole CC plant is online with Chena 5 and the other Department
of Defense (DOD) generation. For some of the Summer Valley cases, the Fairbanks area
generation was reduced to only Chena 5 online. This occurred when the amount of Healy area
generation plus the Alaska Intertie flow from Douglas served all of the northern possible loads
without reaching the stability limit.
In addition to the variations in the Alaska Intertie flow (export) directly caused by the changes in
the Healy area generation, the export levels were adjusted by changing the North Pole CC Plant
in the north, while Plant 2A was adjusted in the Anchorage area. In some Summer Valley cases,
the Chena 5 unit was adjusted if the North Pole CC Plant was not online.
Healy #2 Healy #1 Eva Creek WP SP SV
1 on on on 114 112 114
2 on on -90 88 90
3 on -on 86 86 86
4 on --62 62 62
5 -on on 53 50 53
6 -on -29 26 29
7 --on 24 24 24
8 ---- - -
Healy Area Generation Seasonal Generation (MW)Dispatch
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Table 4-14: Existing Winter Peak Base Case Dispatches
Description
Case Name
Generation Spin Generation Spin Generation Spin Generation Spin
Bradley Lake Hydro 115.7 4.3 115.7 4.3 119.8 0.2 119.8 0.2
Cooper Lake Hydro 14.0 5.6 14.0 5.6 19.6 - 19.6 -
Eklutna Hydro 2.0 38.0 2.0 38.0 40.0 - 40.0 -
Nikiski CC 60.8 0.2 60.8 0.2 53.9 7.1 53.9 7.1
Soldotna CT - - - -
Tesoro 10.0 - 10.0 - 10.0 - 10.0 -
Beluga Plant 78.6 - 78.6 - 78.6 - 78.6 -
SPP 188.5 (0.0) 188.5 (0.0) 188.5 (0.0) 188.5 (0.0)
Plant 1 32.0 - 32.0 - 32.0 - 32.0 -
Plant 2a 111.4 3.7 95.6 19.4 72.2 42.8 53.9 61.2
EGS 119.0 - 153.0 - 119.0 - 153.0 -
Healy 1 28.5 - - 28.5 - -
Healy 2 61.9 0.0 - 61.9 0.0 -
Eva Creek 24.0 - - - 24.0 - - -
GVEA BESS - 26.0 - 26.0 - 26.0 - 26.0
North Pole CC 46.4 18.6 51.2 13.8 43.9 21.1 51.2 13.8
Chena 5 - - 23.0 - - - 23.0 -
UAF 11.0 - 11.0 - 11.0 - 11.0 -
Fort Wainwright 15.0 - 15.0 - 17.0 - 17.0 -
Eielson AFB 8.0 - 8.0 - 8.0 - 8.0 -
Fort Knox (11.0) - (11.0) - (11.0) - (11.0) -
Generation/Spin Total 915.8 96.4 847.5 107.2 916.9 97.3 848.5 108.2
Dave's North Spin 86.3 97.2 90.0 100.9
Hydro Spin 47.9 47.9 0.2 0.2
CT/ST Spin 48.6 59.4 97.1 108.0
Dave's Creek - Hope Flow 84.9 84.9 87.5 87.5
Douglas - Stevens Flow 54.4 71.0 55.0 68.8
Healy Export 151.0 53.0 151.0 50.0
CT/ST Spin - 1, 2, Eva CT/ST Spin - None
wp_g320_s087_n055_h151 wp_g390_s087_n069_h050
Hydro Spin - 1, 2, Eva Hydro Spin - None
wp_g220_s085_n054_h151 wp_g290_s085_n071_h053
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Table 4-15: Existing Summer Peak Base Case Dispatches
Description
Case Name
Generation Spin Generation Spin Generation Spin Generation Spin
Bradley Lake Hydro 119.8 0.2 119.8 0.2 119.8 0.2 119.8 0.2
Cooper Lake Hydro 19.6 - 19.6 - 19.6 - 19.6 -
Eklutna Hydro 2.0 38.0 2.0 38.0 40.0 - 40.0 -
Nikiski CC 51.1 - 51.1 - 51.1 - 51.1 -
Soldotna CT - - - -
Tesoro 8.0 - 8.0 - 8.0 - 8.0 -
Beluga Plant 59.0 - 59.0 - 59.0 - 59.0 -
SPP 141.0 (0.0) 141.0 (0.0) 141.0 (0.0) 141.0 (0.0)
Plant 1 28.0 - 28.0 - 28.0 - 28.0
Plant 2a 88.2 4.6 73.8 19.1 51.0 41.9 34.1 58.7
EGS 68.0 - 119.0 - 68.0 - 119.0 -
Healy 1 26.4 - - 26.4 - -
Healy 2 61.9 0.0 - 61.9 0.0 -
Eva Creek 24.0 - - - 24.0 - - -
GVEA BESS - 26.0 - 26.0 - 26.0 - 26.0
North Pole CC 22.0 18.0 34.2 5.8 19.5 20.5 34.2 5.8
Chena 5 - - 23.0 - - - 23.0 -
UAF 5.0 - 5.0 - 7.0 - 7.0 -
Fort Wainwright 15.0 - 15.0 - 15.0 - 15.0 -
Eielson AFB 10.0 - 10.0 - 10.0 - 10.0 -
Fort Knox (11.0) - (11.0) - (11.0) - (11.0) -
Generation/Spin Total 738.0 86.9 697.5 89.1 738.3 88.6 697.8 90.8
Dave's North Spin 86.7 88.9 88.4 90.6
Hydro Spin 38.2 38.2 0.2 0.2
CT/ST Spin 48.7 50.9 88.4 90.6
Dave's Creek - Hope Flow 85.5 85.5 85.5 85.5
Douglas - Stevens Flow 47.0 81.0 47.3 78.6
Healy Export 140.0 60.0 140.0 58.0
CT/ST Spin - 1, 2, Eva
sp_g320_s086_n047_h140
CT/ST Spin - None
sp_g390_s086_n079_h058sp_g220_s086_n047_h140 sp_g290_s086_n081_h060
Hydro Spin - 1, 2, Eva Hydro Spin - None
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Table 4-16: Existing Summer Valley Base Case Dispatches
4.11.2 Results
Tables 4-17 through 4-19, shown in the following subsections, present the stability based export
limits determined for the Alaska Intertie. The Alaska Intertie is not limited by thermal or voltage
based constraints as is the Kenai Intertie. Thus, the export limits are the stability limits unless
limited by load. Note that the limits in 4-17 through 4-19 do not include any margin.
Values are shown in the tables for each Healy area generation scenario, season, and spin
configuration. Export flows are provided for the Douglas – Stevens line and the combined Healy
area export. The combined Healy area export value is the sum of the Eva Creek generation and
the two 138 kV line flows heading north out of Healy. Note that similar to the findings in the Kenai
Intertie results, there is no significant difference between the Hydro and CT/ST spin cases in
terms of the export limit.
The limiting contingencies for the stability-limited cases varied depending on the amount of
generation produced in the Healy area. Typically, for high generation levels in the Healy area
(lower flows out of Douglas), the limiting contingency is located in the Healy area (such as for a
fault near Healy on the Healy-Eva Creek Line). The results also show that the status of Healy 1
impacts this limit. The majority of cases with Healy 1 online were limited by a Healy area fault.
Recent Railbelt studies have also shown instabilities related to the status of Healy 1 and the initial
reactive power output of the Healy 1&2 units. At higher reactive power outputs from these units,
the system is more stable and can maintain slightly higher transfers. These units recently
received upgraded excitation systems, however the new models were not provided for this study.
Description
Case Name
Generation Spin Generation Spin Generation Spin Generation Spin
Bradley Lake Hydro 60.0 27.0 60.0 27.0 90.0 27.0 90.0 27.0
Cooper Lake Hydro 14.0 5.6 14.0 5.6 19.6 - 19.6 -
Eklutna Hydro 2.0 38.0 9.1 30.9 40.0 - 40.0 -
Nikiski CC 55.3 - 55.3 - 22.7 32.6 22.7 32.6
Soldotna CT - - - -
Tesoro 2.9 - 2.9 - 2.9 - 2.9 -
Beluga Plant - - - - - - - -
SPP 109.1 (0.1) 109.1 (0.1) 72.9 36.1 95.5 13.5
Plant 1 - - - -
Plant 2a 26.9 28.5 110.7 0.1 24.3 31.1 95.4 15.4
EGS 17.0 - 17.0 - 17.0 - 17.0 -
Healy 1 28.5 - - 28.5 - -
Healy 2 61.9 0.0 - 61.9 0.0 -
Eva Creek 24.0 - - - 24.0 - - -
GVEA BESS - 26.0 - 26.0 - 26.0 - 26.0
North Pole CC - - 26.8 26.2 - - 24.4 28.6
Chena 5 20.0 - 20.0 - 20.0 - 20.0 -
UAF - - - - - - - -
Fort Wainwright - - - - - - - -
Eielson AFB - - - - - - - -
Fort Knox - - - - - - - -
Generation/Spin Total 421.6 125.0 424.9 115.7 423.8 152.9 427.5 143.2
Dave's North Spin 92.4 83.1 93.3 83.5
Hydro Spin 70.6 63.5 27.0 27.0
CT/ST Spin 54.4 52.2 125.9 116.2
Dave's Creek - Hope Flow 71.0 71.0 72.1 72.1
Douglas - Stevens Flow (12.0) 76.4 (12.0) 79.1
Healy Export 86.0 58.0 86.0 60.0
CT/ST Spin - 1, 2, Eva CT/ST Spin - None
sv_g390_s072_n079_h060sv_g320_s072_n0012_h086
Hydro Spin - 1, 2, Eva Hydro Spin - None
sv_g220_s071_n0012_h086 sv_g290_s071_n076_h058
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For the lower generation levels in the Healy area (higher flows out of Douglas), the limiting
contingencies are typically in the Anchorage area. These contingencies include faults near
generation such as SPP and Plant 2A and in the 230 kV Anchorage system. 138 kV line faults
near ITSS were the most limiting contingencies in many cases.
4.11.3 Winter Peak
The Winter Peak export limits range from 54-72 MW out of Douglas and 50-151 MW out of Healy.
Note that the stated export levels are coincident and were limited by either a Healy area or
Anchorage area fault and associated line outage. Thus, it is possible that the flows out of Douglas
could be increased if the Healy exports are reduced for Dispatches 1 & 2.
Table 4-17: Winter Peak Export Stability Limits
4.11.4 Summer Peak
The Summer Peak export limits range from 47-81 MW out of Douglas and 58-140 MW out of
Healy. These results are similar to the Winter Peak results, although flows out of Douglas are
increased by 12-13 MW for low levels of generation in the Healy area. During high levels of Healy
area generation, the Douglas exports are lower than the Winter Peak cases.
Table 4-18: Summer Peak Export Stability Limits
4.11.5 Summer Valley
The Summer Valley results are very different compared to the peak cases due to the reduced
load levels. For the majority of cases, the stability limit exceeds the export levels required to serve
Dispatch Healy #2 Healy #1 Eva Creek Total (MW)Douglas Healy Douglas Healy
1 on on on 114 54 151 55 151
2 on on -90 67 139 65 137
3 on -on 86 72 139 72 139
4 on --62 72 115 72 116
5 -on on 53 72 106 71 105
6 -on -29 65 75 65 76
7 --on 24 67 73 67 73
8 ---- 68 50 69 50
No shading indicates a Douglas flow or Anchorage based limiting contingency
Shading indicates a Healy export or Northern area limiting contingency
WP - Stability Export Limits (MW)Healy Area Generation Hydro Emphasis CT/ST Emphasis
Dispatch Healy #2 Healy #1 Eva Creek Total (MW)Douglas Healy Douglas Healy
1 on on on 112 47 140 47 140
2 on on -88 61 130 62 130
3 on -on 86 69 135 69 135
4 on --62 79 120 80 120
5 -on on 50 71 101 72 102
6 -on -26 77 83 78 83
7 --on 24 80 83 80 83
8 ---- 81 60 79 58
No shading indicates a Douglas flow or Anchorage based limiting contingency
Shading indicates a Healy export or Northern area limiting contingency
Healy Area Generation SP - Stability Export Limits (MW)
Hydro Emphasis CT/ST Emphasis
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the Fairbanks area load. With the Healy area at its two lowest generation levels, the exports are
stability limited with similar limits to the Summer Peak cases.
Table 4-19: Summer Valley Export Stability Limits
4.11.6 Sensitivity to Fairbanks Area Generation
Sensitivity cases were completed for different levels of GVEA Fairbanks area generation. For the
summer valley cases, the minimum generation in Fairbanks was the UAF and military generation,
plus the Aurora unit (Chena 5). Sensitivity cases were run with the Aurora unit offline, such that
only the UAF and DOD units were online in Fairbanks. In all these cases, the system remained
stable for the contingencies studied and the flows north out of Douglas and Healy were only limited
by the minimum load in the Fairbanks area.
For load levels above the Summer Valley cases, varying levels of GVEA generation are required
in addition to the DOD and UAF generation levels to maintain voltage and stability in the Fairbanks
area as indicated in the Table 4-20 below.
Dispatch Healy #2 Healy #1 Eva Creek Total (MW)Douglas Healy Douglas Healy
1 on on on 114 (12) 86 (12) 86
2 on on -90 12 86 12 86
3 on -on 86 16 86 16 86
4 on --62 41 86 41 86
5 -on on 53 49 84 49 84
6 -on -29 64 75 64 75
7 --on 24 79 84 79 84
8 ---- 76 58 79 60
No shading indicates a Douglas flow or Anchorage based limiting contingency
Shading indicates a Healy export or Northern area limiting contingency
Shading indicates Fairbanks at minimum generation, no stability limit
Healy Area Generation SV - Stability Export Limits (MW)
Hydro Emphasis CT/ST Emphasis
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Table 4-20: Sensitivity to Fairbanks Generation
4.11.7 UFLS
The UFLS results related to the Alaska Intertie export limits fit into two categories; the loss of the
Anchorage-Healy Intertie and the loss of a generation unit. The loss of the Intertie can occur for
any line outage between Teeland and Healy. The tie can also be lost for a fault on the 230 kV Pt.
MacKenzie-Teeland line at higher flow levels because this outage will cause a trip of the 138 kV
Teeland-Douglas line, islanding the system to the north.
The amount of load shedding that occurs following islanding of the northern system depends on
the online generation north of Healy and the level of auto scheduling on the GVEA BESS. Two
stages of load shedding occur in some cases for a Healy area fault on the tie even with auto
scheduling. The use of auto scheduling shows a clear improvement over outages south of
Douglas where the BESS is not auto-scheduled. The cases are not compliant with the
transmission system planning criteria in AKTPL-001-4 which does not allow for loss of a firm
transmission path or non-consequential loss of load for single contingency events.
The results for the Winter Peak and Summer Peak seasons are similar. The Summer Valley
season is more sensitive to load shedding simply because of the lightly loaded system and
minimum amount of generation online.
Doug Fbks Doug Fbks
8 ---76 58 --20 27 79 60 --20 24
7 --24 79 84 24 --22 79 84 24 --22
6 29 --64 75 29 14 17 -64 75 29 14 17 -
5 29 -24 49 84 53 12 10 -49 84 53 12 20 -
4 -62 -41 86 62 -20 -41 86 62 -20 -
3 -62 24 16 86 86 -20 -16 86 86 -20 -
2 29 62 -12 86 90 -20 -12 86 90 -20 -
1 29 62 24 -12 86 114 -20 --12 86 114 -20 -
8 ---81 60 -30 23 74 79 58 -32 23 73
7 --24 80 83 24 30 23 52 80 83 24 32 23 49
6 29 --77 83 26 30 23 52 78 83 26 32 23 49
5 29 -24 71 101 50 30 23 34 72 102 50 32 23 32
4 -62 -79 120 62 30 23 17 80 120 62 32 23 15
3 -62 24 69 135 86 30 -27 69 135 86 32 -24
2 29 62 -61 130 88 30 -32 62 130 88 32 -29
1 29 62 24 47 140 112 30 -22 47 140 112 32 -20
8 ---71 53 -34 23 115 69 50 -36 23 115
7 --24 67 73 24 34 23 96 67 73 24 36 23 93
6 29 --65 75 29 34 23 93 65 76 29 36 23 91
5 29 -24 72 106 53 34 23 65 71 105 53 36 23 63
4 -62 -72 115 62 34 23 56 72 116 62 36 23 54
3 -62 24 72 139 86 34 23 34 72 139 86 36 23 32
2 29 62 -67 139 90 34 23 34 65 137 90 36 23 34
1 29 62 24 54 151 114 34 -46 55 151 114 36 -44
GVEA
FB
Alaska Railbelt Transmission Plan
Stability Limit due to Anchorage Contingencies
Stability Limit due to Golden Valley Contingencies
No Shading indicates Fairbanks at minimum generation, no stability limit
Hydro Emphasis CT/ST Emphasis
Healy /
Eva DOD GVEA
FB
Healy /
Eva DOD
Summer
Valley
Winter
Peak
Summer
Peak
Aurora AuroraTransfersTransfersHealy
#1
Healy
#2
Eva
Creek
Disp
#
Season
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4.12 Kenai Area System Improvements
The recommended system improvements associated with the Kenai area provide increased
reliability and firm energy transfers to the southcentral and northern areas of the Railbelt system
from the Kenai. The projects recommended are the same as those that were recommended in
the 2014 Draft Plan, with the exception of the increase in BESS size. This study establishes
updated system limits and capabilities with the recommended improvements in place.
4.12.1 System Improvement Projects
The proposed transmission upgrades allow for all of the Bradley Lake energy to be exported to
Anchorage and the northern utilities while also significantly reducing losses on the transmission
system. There are three main areas of focus to relieving the generation constraints from the Kenai;
1) Kenai area transmission improvements, 2) Kenai to Anchorage transmission improvements,
and 3) Anchorage area stored energy additions. Kenai area transmission improvements consist
of adding a new transmission line between Bradley Lake and Soldotna. Kenai to Anchorage
transmission improvements include a new HVDC line between Bernice Lake and Beluga and
conversion of the existing Kenai Intertie between University and Dave’s Creek to 230 kV. The
Anchorage area stored energy project includes a 35 MW BESS in the Anchorage area to provide
stability and allow re-dispatching of Kenai and Anchorage area generation if the HVDC or AC line
tie fails during high Kenai exports.
A loss analysis was completed with Kenai export levels ranging from 55 MW to 100 MW for the
recommended transmission configuration, comparing the losses to the year 2015 transmission
system. The results are shown graphically in Figure 4-1Figure . The HVDC Intertie was assumed
to schedule all Kenai exports up to a maximum value of 75 MW. The export value is the flow
measured at the Dave’s Creek – Hope transmission line, from the Dave’s Creek end in addition
to the HVDC flow. The loss value includes the losses of all of the Kenai Transmission lines from
Bradley Lake to University, as well as the transmission lines to the HVDC Intertie. It is assumed
that the HVDC Intertie has losses that are equal to 4% of the energy flowing on the line. The
results show a significant reduction in losses with the addition of the HVDC intertie, the Kenai Tie
upgraded to 230 kV, and addition of a second 115 kV line between Bradley Lake and Soldotna
substations.
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Figure 4-1: Kenai Export Loss Analysis
It should be noted that thermal overloads of the Soldotna – Quartz Creek line section are still
possible with the recommended transmission improvements following the loss of the HVDC
transmission line. The overload only occurs during the summer time frame when the transmission
ratings are decreased from their winter peak ratings. An outage of the HVDC intertie during
maximum Kenai export conditions requires a reduction in Bradley Lake generation of about 20
MW, again only for the summer. The recommended BESS installation is intended to prevent loss
of load following this outage and provide energy during the time required to adjust the Kenai
export to acceptable levels.
4.12.1.1 100 MW HVDC Intertie Beluga - Bernice Lake
Currently, the Anchorage - Kenai systems have only one transmission line available for transfers,
thus eliminating the ability to provide firm energy transfers to/from the Anchorage area. The single
line also presents a reliability challenge to the Kenai, resulting in restricted energy transfers to
and from the Kenai in order to control the transient frequency following separation. The single
line also results in load shedding in the Anchorage/Fairbanks areas following the loss of the line,
even if additional contingency reserves are carried in the northern systems. To allow firm energy
transfers and improve reliability to the Kenai and northern Railbelt areas, a second line is needed
connecting the Kenai and Southcentral Railbelt areas. The second line helps by eliminating load
shedding from occurring for the loss of the Kenai tie and helps by removing generation constraints
both on the Kenai and northern areas, allowing full economic use of available generation. The
second line also eliminates reserve constraints in the Southcentral Railbelt, allowing reserves on
the Kenai to transfer to the Southcentral area without constraint.
A second transmission tie between the Kenai Peninsula and the Anchorage area is needed to
allow reliable export of Bradley Lake’s energy to the northern utilities. Studies in connection with
the abandoned “Southern Intertie” project had identified a 138 kV transmission line between
0
5
10
15
20
25
30
50 55 60 65 70 75 80 85 90 95 100 105Losses (MW)Kenai Export @ Dave's Creek and HVDC (MW)
Kenai Export Losses
Base vs Recommended Upgrades
Base
Kenai Tie Upgraded to 230 kV, Second
Bradley Lake - Soldotna, and HVDC TIE
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Bernice Lake and Pt. Woronzof as the recommended alternative. It included a submarine section
between Pt. Possession and Pt. Woronzof, which required substantial reactive compensation. A
HVDC tie was investigated at the time, but found to be too costly. This study has investigated
both options and concludes that the HVDC tie is now less costly and a technically more
appropriate solution.
The project includes the construction of a 100 MW HVDC intertie between the Beluga power plant
in Southcentral Alaska and the 115 kV Bernice Lake Power Plant on the Kenai Peninsula. The
route of the cables would result in the majority of the cables being parallel to the Cook Inlet current
flow, making them less susceptible to damage caused by high currents than the Pt. Woronzof
and Pt. Possession cables.
The interconnecting HVDC power line would consist of two undersea cables (due to the length of
repair delay for a single submarine cable failure) each rated for 100 MW transfer capacity. A
failure of either cable would result in the loss of the intertie until the faulted cable was removed
from service. The capacity of the intertie would remain at 100 MW following the loss of the first
cable.
The cables are approximately 36 miles in length and are estimated to be rated at 100 kV DC. The
converters are mono-pole HVDC converters with a transfer capacity of 100 MW. The actual
voltage and submarine cable ratings will require optimization to provide the most economic
selection for the project.
Besides allowing for high Kenai export conditions, additional benefits of the HVDC intertie are the
large decrease in Kenai export losses and the provision for damping of inter area oscillations
between the Kenai and the rest of the Railbelt via the HVDC controls. The HVDC line will also
mitigate the minimum generation constraint on the Kenai and allow for capacity sharing between
the Kenai and Anchorage systems.
The 100 MW size of the HVDC was determined by transient analysis. The HVDC tie was
scheduled with an initial flow of 75 MW, and then the upgraded Kenai AC tie was outaged. The
HVDC line flow was then increased (assumed as a step change) until the Anchorage area did not
load shed and the system was stable. The Kenai tie was opened between the Dave’s Creek and
Quartz Creek substations, which was deemed the worst case outage due to the load at Seward
remaining connected to the Anchorage system and the generation at Cooper Lake remaining
connected to the Kenai system. The results show that the HVDC line should have the capability
of increasing transfers quickly to 100 MW to eliminate load shedding in Anchorage with total Kenai
exports at a maximum of around 127 MW.
4.12.1.2 2nd Bradley Lake – Soldotna Line
In addition to providing firm transfers by adding a second tie to the Kenai, relieving the constraints
associated with the Bradley Lake output is beneficial. A second line from Bradley Lake to
Soldotna Substation is recommended and is necessary to remove the constraints on the output
of Bradley Lake. Without a second line, high transfer levels out of Bradley Lake are not possible
without violating the planning criteria. Adding the second line eliminates this restriction, reduces
losses, and also eliminates the existing thermal constraints when a Bradley Lake line is out of
service.
This project includes the construction of a new 68 mile long, 115 kV transmission line from the
Bradley Lake Power plant to a new substation near HEA’s existing Soldotna substation. The
transmission line includes modifications to the existing GIS switchgear and 0.5 miles of 115 kV
solid-dielectric cable at the Bradley Lake power plant. The northern end of the line would
terminate in a new 115 kV substation connected to the existing HEA substation through the
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existing AEA SVC bay. The line would utilize the same construction configuration and conductor
size as the existing Bradley – Soldotna transmission line.
Reconductoring the existing Diamond Ridge – Soldotna line was evaluated, but not selected as
the preferred alternative for increased power transfers out of Bradley Lake. A new line is slightly
less cost than rebuilding the existing line and provides increased power transfers and stability
margin than the reconstructed line.
4.12.1.3 230 kV Conversion University – Dave’s Creek
This project includes the conversion of 55 miles of the existing 115 kV Kenai Tie (from Chugach’s
Dave’s Creek Substation on the Kenai Peninsula to Chugach’s University Substation in
Anchorage) to 230 kV. The project requires two separate phases, the conversion of the
transmission line to 230 kV, followed by the conversion of the substations along the line to 230
kV. The line conversion would include rebuilding the line across the avalanche areas along the
existing route, to include the installation of avalanche deflection structures and the installation of
more avalanche resistant structures. The line would be placed along the existing line’s route and
would utilize wooden H-Frames utilizing the current 795 ACSR “Drake” conductor. Chugach
Electric has been upgrading the line in sections as part of its system maintenance and
improvement and certain sections of the line have already been reconstructed to 230 kV
standards.
4.12.1.4 University - Dave’s Creek 230 kV Substations and Compensation
This project includes the installation of reactive compensation at Dave’s Creek station and the
conversion of substations at Dave’s Creek, Hope, Summit Lake, Portage, Girdwood, and Indian
stations to 230 kV. The project also includes the completion of the 230 kV bus at Chugach’s
University substation. The project includes the installation of sectionalizing switches at each of
the stations to allow remote sectionalizing of the transmission line. On the southern end, the line
would terminate at Dave’s Creek and would include a single 230 kV to 115 kV, 150 MVA
transformer to interconnect into the 115 kV bus sections.
A 10 MVAR fixed reactor would be required at the Dave’s Creek substation. The reactor allows
load to be served from the Kenai with the University substation end of the line opened without
units on the Kenai being operated in the “buck” condition. Further switching studies will be
required to confirm if a switched reactor can be utilized in conjunctio n with the existing SVC or if
the existing SVC will require upgrading.
4.12.1.5 Reconductor Dave’s Creek – Quartz Creek
The 115kV line between Dave’s Creek and Quartz Creek utilizes a “Dove" equivalent conductor,
which will make it necessary to reduce Bradley Lake and / or Cooper Lake generation by 38
MW when the HVDC line is outaged during summer peak and maximum Kenai export
conditions. The winter peak season does not require a reduction in Kenai exports due to the
higher thermal ratings of the conductors. To increase the transfer capacity to 133 MVA between
the two substations, the 10-mile long line should be reconductored to 954 ACSR “Rail”
conductor.
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4.12.1.6 35 MW BESS – Anchorage Area
The existing Railbelt system experiences UFLS activation for many single contingencies under
most operating conditions. UFLS activation increases as the spin levels on hydro units (Bradley
Lake, Cooper Lake, and Eklutna Lake) is increased. UFLS activation for most contingencies
cannot be prevented without substantial increases in thermal generation or other fast-acting
contingency reserves.
The addition of the 35 MW ESS in Anchorage will mitigate all UFLS activation for single unit /
equipment outages for the future system. The ESS will also eliminate thermal overloads that can
occur due to a loss of the HVDC line during periods of high Kenai exports.
An Anchorage area BESS rated at 35 MW is recommended for dynamic and longer-term system
requirements. A 35 MW BESS is required to alleviate short-term overloads on the remaining
Intertie when either the HVDC or Kenai AC tie are lost until northern area generation can be re-
dispatched to alleviate the overload. The capacity of the BESS provides time for the Anchorage
area generation to be re-dispatched following the loss of the line.
The BESS also provides dynamic response for unit and transmission outages and can assist the
system response for the loss of the either of the two recommended Kenai Intertie lines (AC or
DC), especially during heavy export conditions. Load shedding for single contingencies, such as
generator unit trips in the Railbelt will be eliminated following the installation of the BESS.
The BESS provides some reserve support for regulation as well as contingency reserves. By
supplying contingency reserves for the loss of the Anchorage-Kenai 115 kV Intertie, the system
will also provide reserves for generation contingencies, eliminating up to 35 MW of fast-acting
contingency reserves from being carried on fossil fuel generation.
4.12.1.7 BESS Sizing
Table 4-21 shows the minimum required BESS size for all seasons and generation scenarios.
The sizing is based on adding energy support in the Anchorage area to provide contingency
reserves and alleviate the overloaded 115 kV line sections on the AC Kenai Intertie following the
loss of the HVDC Kenai tie. The recommended size of 35 MW is sufficient to provide contingency
reserves for all seasons, and also provides the benefit of eliminating equivalent contingency
reserves in the Anchorage/Fairbanks areas for line outage contingencies. The response of the
BESS to unit contingencies eliminates load shedding for all unit contingencies in the Railbelt.
Table 4-21: BESS Sizing Requirements
No UFLS occurs for the improved system for unit contingencies or line outages and no thermal
contingency reserve is required to provide this performance. This is primarily due to the additional
HVDC tie line and 35 MW BESS.
BESS
Size (MW)
both online on on both online 10
both online on on 15
both online on on both online 33
both online on on 33
WP
SP
Season Bradley Lake Nikiski CC Soldotna Cooper Lake
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4.12.2 Alternatives
Several alternatives to the above mentioned projects were considered but rejected, due to costs,
ineffectiveness at solving issues, or due to complexity and technical uncertainty about the
feasibility. These alternatives are discussed below.
4.12.2.1 Reconductoring Soldotna – Diamond Ridge 115 kV line
A project to reconstruct the 115 kV Diamond Ridge – Soldotna transmission line was evaluated
and compared to the construction of a new 115 kV Bradley Lake – Soldotna transmission line.
The Soldotna – Diamond Ridge project would include upgrading the conductor from 4/0 to 556
ACSR “Dove” and would require reconstruction due to distribution underbuild and shorter spans.
The Soldotna – Diamond Ridge reconstruction is a significantly longer line at a higher cost/mile.
In addition to the higher costs, simulations indicate that the reconstructed Soldotna - Diamond
Ridge line cannot provide unconstrained operation of the Bradley Lake project due to instabilities.
Therefore, adding a second Soldotna – Bradley Lake line is the preferred alternative.
4.12.2.2 Bradley Lake – Quartz 115 kV line
A project to add a line directly from Bradley Lake to Quartz Creek (no termination at Soldotna)
was evaluated and compared to the construction of a line from Bradley Lake to Soldotna. The
direct line from Bradley Lake to Quartz Creek cannot provide unconstrained operation of the
Bradley Lake project due to instabilities. Therefore, adding a second line from Bradley Lake to
Soldotna is the preferred alternative.
4.12.2.3 AC Bernice – Anchorage Southern Intertie
A project to add an AC Southern Intertie between Bernice and Pt. Woronzof was evaluated and
compared to the addition of the HVDC line between Bernice and Beluga. The Southern Intertie
was evaluated at both 138 and 230 kV voltages. For both voltage levels, the new intertie would
incur higher costs due to the need for reactive support for the charging current for the cables.
Although feasible, the technical complexities of energizing a 120 MVAr (minimum) submarine
cable/reactor/SVC combination in an isolated electrical system would require specialized studies
(to evaluate (1) possible switching surges encountered during energizing/de-energizing of the
cables and reactors, (2) the possibility of subsynchronous resonance, and (3) different methods
of energization) and would be considerably more complex than the existing system’s operation.
Therefore, the addition of the HVDC tie is the preferred alternative.
4.12.2.4 2nd Soldotna – Quartz 115 kV line
A project to add a second 115 kV transmission line between Soldotna – Quartz Creek was
evaluated. When evaluated together with the HVDC intertie and upgrading the existing Kenai Tie
to 230 kV, the second line shows no increases in transfer capability during winter peak conditions
as well as minimal reduction in losses. During summer peak conditions, an outage of the HVDC
intertie during maximum Kenai exports requires a reduction in Bradley Lake generation of about
20 MW. This reduction can happen in a relatively long amount of time (15 – 30 minutes) and is
not a stability requirement that must happen instantaneously. The BESS and Flexible Gas
Storage projects would facilitate the required Anchorage generation increase to eliminate the
overloads.
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The addition of a second Soldotna – Quartz Creek 115 kV line without the HVDC line was also
evaluated. To achieve unconstrained use of Bradley Lake and Cooper Lake capacity and energy,
the Anchorage area would require a significant increase in both flexible gas s torage and BESS
size and costs due to the single contingency transmission line between Quartz Creek and
University stations.
Due to the high costs, the addition of a second Soldotna – Quartz Creek 115 kV line is not
recommended.
4.12.3 Generation Scenarios
With the recommended Kenai Area improvements all added to the existing system seasonal
models, the system was evaluated to determine the improved export limits and performance of
the Kenai system. The Winter Peak and Summer Peak seasons were the focus of the analysis.
The Summer Valley case was not relevant in determining economic benefits of higher export
limits.
Two basic generation scenarios were created for each season. The difference between the
scenarios is the status of the Cooper Lake generation. No sensitivities for the type of spin were
studied due to the minimal difference in stability results found during the existing system analysis.
For all cases, a scheduled HVDC tie flow of 75 MW was assumed for the initial condition. Tables
4-22 and 4-23 describe the generation scenarios used for the analysis. Note that the
recommended 35 MW Anchorage area BESS is not included in the spinning reserve totals in the
tables.
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Table 4-22: Winter Peak Generation Scenarios
Description
Case Name
Generation Spin Generation Spin
Bradley Lake Hydro 119.8 0.2 119.8 0.2
Cooper Lake Hydro 19.6 - - -
Eklutna Hydro 28.0 12.0 26.0 14.0
Nikiski CC 60.8 0.2 60.8 0.2
Soldotna CT 49.0 0.2 49.0 0.2
Tesoro 10.0 - 10.0 -
Beluga Plant - - - -
SPP 188.5 (0.0) 188.5 (0.0)
Plant 1 - -
Plant 2a 90.6 24.4 94.7 20.4
EGS 119.0 - 136.0 -
Healy 1 28.5 - 28.5 -
Healy 2 61.9 0.0 61.9 0.0
Eva Creek 10.0 - 10.0 -
GVEA BESS - 26.0 - 26.0
North Pole CC 64.7 0.3 64.7 0.3
Chena 5 23.0 - 23.0 -
UAF 11.0 - 11.0 -
Fort Wainwright 19.0 - 19.0 -
Eielson AFB 10.0 - 10.0 -
Fort Knox (11.0) - (11.0) -
Generation/Spin Total 902.3 63.4 901.8 61.3
Dave's North Spin 62.8 60.7
Hydro Spin 12.2 14.2
CT/ST Spin 51.2 47.1
Dave's Creek - Hope Flow 72.5 53.3
HVDC Tie Flow 75.0 75.0
Total Kenai Export 147.5 128.3
Douglas - Stevens Flow 15.7 15.7
Base
wp_g020_s148_n016_h099_u019
Base - Cooper Offline
wp_g021_s128_n016_h099_u019
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Table 4-23: Summer Peak Generation Scenarios
4.12.4 Results
The results of the analysis show that the 2030 proposed system has greatly increased transfer
limits as compared to the existing system. The transfer amounts are not limited by stability,
voltage, or thermal conditions as they are in the existing system, but instead are limited by the
amount of Kenai Area generation. No margin has been applied to these limits.
The generation levels in the Kenai area include the Bradley Lake, Nikiski, and Soldotna Plants at
full output. These units have a total output of 230 MW in the winter and 211 MW in the summer.
These generation and export levels allow for the entire amount of unconstrained Bradley Lake
generation to be provided to each utility.
Table 4-24 describes the improved system export limits along with the existing system limits. For
all seasons and generation scenarios, the transfer capability from the Kenai to Anchorage areas
has more than doubled with the improvements.
In addition, the proposed system eliminates the current generation constraints on the Kenai,
allowing the Kenai system to be operated as part of the Railbelt grid with significantly less
constraints on local generation. The Kenai must still maintain a minimum level of generation to
cover the loss of the transmission lines, however, this is for voltage stability as opposed to
frequency response and therefore the minimum generation constraint could be met with hydro or
thermal resources.
Description
Case Name
Generation Spin Generation Spin
Bradley Lake Hydro 119.8 0.2 119.8 0.2
Cooper Lake Hydro 19.6 - - -
Eklutna Hydro 12.0 28.0 10.0 30.0
Nikiski CC 51.1 - 51.1 -
Soldotna CT 40.0 0.1 40.0 0.1
Tesoro 8.0 - 8.0 -
Beluga Plant - - - -
SPP 141.0 (0.0) 141.0 (0.0)
Plant 1 - -
Plant 2a 81.8 11.1 85.9 7.0
EGS 68.0 - 85.0 -
Healy 1 26.4 - 26.4 -
Healy 2 61.9 - 61.9 -
Eva Creek 6.0 - 6.0 -
GVEA BESS - 26.0 - 26.0
North Pole CC 40.0 - 40.0 -
Chena 5 23.0 - 23.0 -
UAF 11.0 - 11.0 -
Fort Wainwright 15.0 - 15.0 -
Eielson AFB 10.0 - 10.0 -
Fort Knox (11.0) - (11.0) -
Generation/Spin Total 723.6 65.3 723.1 63.2
Dave's North Spin 65.1 63.0
Hydro Spin 28.2 30.2
CT/ST Spin 37.1 33.0
Dave's Creek - Hope Flow 56.0 36.8
HVDC Tie Flow 75.0 75.0
Total Kenai Export 131.0 111.8
Douglas - Stevens Flow 12.9 12.9
sp_g021_s112_n013_h089_u019sp_g020_s131_n013_h089_u019
Base Base - Cooper Offline
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Table 4-24: Existing/Future Kenai Area Export Limits
4.13 Southcentral and Northern Area System Improvements
The system improvements associated with the southcentral and northern areas are required in
order to provide increased and firm energy transfers between the southcentral and northern areas
of the Railbelt system. The recommended projects are the same as those recommended in the
2014 Draft Plan for the southcentral and northern areas. This study establishes updated
operating conditions and limitations with the recommended improvements in place.
4.13.1 Southcentral System Improvement Projects
4.13.1.1 Fossil Creek 115 kV Substation
This project includes the construction of a 115 kV substation near the existing Briggs Tap/Fossil
Creek location on the Eklutna – AML&P transmission line. The 115 kV substation interconnects
the Eklutna Express circuit, the Eklutna local circuit, the Briggs Tap circuit, the AML&P express
circuit and the Raptor Substation tie to AML&P Plant 1, with provisions for possible future 230/115
kV transformers. This project provides a redundant path for the MEA substations between EGS
and Briggs Tap and improves the system compliance with the transmission planning criteria. The
station improves the ties between the EGS plant and the AML&P system by providing multiple
lines between the two areas.
4.13.1.2 Eklutna Hydro 115 kV Substation
This project includes the construction of a new 115 kV substation at the Eklutna Hydro Plant. The
Eklutna substation is currently located on the roof of the Eklutna Power Plant and has no room
for expansion. The new substation will be constructed adjacent to the power plant. The project
includes the construction of a 115 kV substation to interconnect the Eklutna Express circuit, the
Eklutna local circuit, and the 115 kV Palmer circuit as well as the generating units at the plant.
This project is primarily driven by the age and condition of the existing substation which is beyond
the expected life of the substation. The existing station is constructed on the rooftop of the existing
plant precluding its direct replacement.
4.13.1.3 Lake Lorraine 230 kV Substation
This project includes the construction of a 230 kV substation, near the junction where the two 230
kV lines traveling north from Pt. MacKenzie separate and travel in different directions. The line
to Teeland continues north while the line to West Terminal travels east. This location is in the
vicinity of Lake Lorraine. The substation will intersect the Pt. MacKenzie – Teeland and Pt.
MacKenzie – Plant 2 230 kV transmission lines. The substation will be built to include six line
terminations, two 230 kV lines to Pt. MacKenzie, one 230 kV line to Teeland, one 230 kV line to
Limit (MW)Limit Type Limit (MW)Limit Type
both online on on both online 61 Voltage 148 Generation
both online on on 57 Voltage 128 Generation
both online on on both online 55 Thermal 131 Generation
both online on on 48 Thermal 112 Generation
Existing System Future System
WP
SP
Season Bradley Lake Nikiski CC Soldotna Cooper Lake
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Plant 2, and two 230 kV lines to Douglas. Terminals at the substation will also be included for
reactive compensation and a possible future 230/115 kV transformer.
A -40/+25 MVAr SVC is also recommended at Lake Lorraine to control voltages on the 230 kV
Railbelt system. The proposed substation location is near one end of the undersea 230 kV cable,
maximizing the effect of the reactive compensation in terms of its ability to limit the undersea cable
voltages to below 1.02 per unit, per the planning criteria for voltages along the undersea cables.
The addition of the Lake Lorraine 230 kV substation, along with the proposed lines to Douglas,
eliminates 26 miles of single contingency 230 kV line from Pt. MacKenzie to Teeland and an
additional 26 miles of single contingency exposure from Teeland to Douglas (all along the Alaska
Intertie) and provides a connection point for transmission line additions recommended to Douglas
substation.
4.13.1.4 Douglas Substation Expansion
This project includes the construction of a 230 kV/138 kV substation at the existing Douglas
substation near Willow, Alaska. The substation will serve as the voltage conversion for the 138
kV Anchorage-Fairbanks Intertie and will include two 230 kV/138 kV substation transformers. The
station will be constructed to include two 230 kV/138 kV power transformers, two 230 kV
transmission line terminations (Lorraine to Douglas), two 138 kV transmission line terminations
(Healy/Gold Creek) built to 230 kV but operated at 138 kV, one 138 kV/24.9 kV power transformer,
and one 138 kV line (Teeland).
4.13.1.5 Lake Lorraine - Douglas 230 kV Transmission Lines
This project includes the construction of two 42-mile, 230 kV transmission lines from Lake
Lorraine substation to Douglas Substation. The transmission line additions eliminate 50 miles of
single contingency 230 kV/138 kV line to Fairbanks on the Alaska Intertie.
4.13.2 Northern System Improvement Projects
4.13.2.1 Gold Creek 138 kV Substation
This project includes the construction of a 230 kV (operated at 138 kV) substation near Gold
Creek on the Alaska Intertie. The station will provide compensation and sectionalizing support
for the recommended Anchorage – Healy transmission lines and will include 4 line terminals and
two reactors.
The addition of the Gold Creek substation will reduce the reactive support requirements for the
proposed lines by more than 50% compared to locating support at Douglas and/or Healy. The
station also improves the stability and sectionalizing capability by dividing the Douglas to Healy
lines by approximately 50% of its existing length. The Gold Creek substation will utilize two 15
MVAr reactors to control voltage along the lines between Healy and Douglas. The reactors can
remain in service even during heavy transfer conditions without the voltage decreasing below
limits.
4.13.2.2 Healy 230 kV Substation
This project includes the construction of a 230 kV substation near Healy, Alaska on the Alaska
Intertie. The substation will be operated at 138 kV for the lines to the south (operated at 138 kV
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to Gold Creek). The station will provide the termination for a new line from Gold Creek into Healy.
The station will be constructed for possible future operation at 230 kV to Gold Creek. The station
will include terminations for two 230 kV (operated at 138 kV) lines to Gold Creek, one 230 kV line
to GVEA’s Wilson Substation and one 230 kV line to GVEA’s Gold Hill Substation, and a line to
the existing Healy plant.
4.13.2.3 2nd Douglas - Healy 230 kV Transmission line (operated at 138 kV)
This project includes the construction of a 171-mile, 230 kV (operated at 138 kV) transmission
line from Douglas Substation to Healy Substation, interconnecting with the proposed new Gold
Creek Substation. The line will be constructed as a single-circuit transmission line utilizing
construction similar to the existing Anchorage-Fairbanks Intertie at 230 kV. The line will utilize
bundled, 954 ACSR conductor to minimize losses and match the characteristics of the existing
Douglas – Healy line. The line will terminate at the Douglas, Gold Creek, and Healy Substations.
The addition of the second 138 kV line from Healy to Douglas greatly increases the reliability of
energy transfers into Healy and significantly reduces losses. The second line eliminates GVEA
islanding due to single contingencies and allows the import of energy into the GVEA system to
become firm, allowing economic transfer of energy and more flexibility in capacity sharing and
planning. The transfer levels also increase due to the addition of this line.
The addition of this line completes a corridor of transmission infrastructure between the Lake
Lorraine Substation (including the proposed Lorraine – Douglas lines) in the Anchorage area and
the Healy Substation near Fairbanks.
While allowing for increased reliability and potentially reducing energy costs via the ability to utilize
firm energy contracts, the transmission projects will also reduce the losses from Anchorage to
Healy by 70%, from 5.3 MW to 1.7 MW for transfers of 75 MW as measured near the Gold Creek
substation location. Figure 4-2 shows the difference in losses between the base system and the
proposed system, for line flows from 0 to 110 MW. This 3.6 MW loss reduction is due to doubling
the transmission system between Douglas and Healy with the addition of the second Douglas –
Healy line, and due to the addition of the 2 new Lorraine – Douglas transmission lines.
Note that transfers of 110 MW for the base system is well beyond the stability limits of the system
and therefore is not a recommended nor is a realistic operating point.
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0
2
4
6
8
10
12
14
0 10 20 30 40 50 60 70 80 90 100 110Line Losses (MW)Flow on Cantwell -Stevens Line Section (MW)
Loss Analysis: Anchorage to Healy
Base vs Proposed Transmission Configuration
Base
Proposed
Figure 4-2: Anchorage – Healy Loss Analysis: Base vs. Proposed
4.13.2.4 230 kV Conversion Healy – Fairbanks
The recommended 230 kV upgrade includes rebuilding the Healy to Gold Hill line utilizing 230 kV
construction and 954 ACSR “Rail” conductor. The existing Healy – Wilson line is already built to
230 kV standards. The conversion will include 150 MVA, 230 kV/138 kV transformers at Healy,
Gold Hill, and Wilson Substations. The distribution substations located between Healy and Gold
Hill will also be upgraded to 230 kV operation.
4.13.2.5 Communication Infrastructure
This project includes the development and installation of communication infrastructure between
the Teeland, Lorraine, Douglas, Gold Creek, and Healy Substations. The communications is
required for high-speed protective relaying communications between control areas and for control
and monitoring of the substation equipment. This positively impacts the proposed system by
decreasing the clearing times for line faults between Healy and Lorraine Substations. Decreasing
the fault clearing times will increase the transfer capacity between Anchorage and Fairbanks. The
existing clearing times are 30 cycles for line end faults and can be improved to 4 cycles with high-
speed communications.
4.13.3 Generation Scenarios
With the recommended Kenai, Southcentral, and Northern area improvements added to the
existing system seasonal models, the system was re-evaluated to determine the improved export
limits. All seasons were included in the analysis.
Similar to the existing system study for the Northern system, eight generation scenarios for the
Healy area generation were used. Table 4-25 through 4-27 describe the two most extreme
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generation scenarios used for each season. The two scenarios shown illustrate the two extreme
cases with the Healy area generation at its maximum and minimum values. The Kenai area
generation is the same configuration that produced the maximum flow conditions in the
recommended Kenai Intertie results.
No sensitivities for the type of spin were studied due to the minimal difference in stability results
found during the existing system analysis, for line outages. Note that the 35 MW BESS is not
included in the spinning reserve totals in the Tables.
Table 4-25: Winter Peak Generation Scenarios
Description
Case Name
Generation Spin Generation Spin
Bradley Lake Hydro 119.8 0.2 119.8 0.2
Cooper Lake Hydro 19.6 - 19.6 -
Eklutna Hydro 2.0 38.0 32.0 8.0
Nikiski CC 60.8 0.2 60.8 0.2
Soldotna CT 49.0 0.2 49.0 0.2
Tesoro 10.0 - 10.0 -
Beluga Plant 78.6 - 78.6 -
SPP 188.5 (0.0) 188.5 (0.0)
Plant 1 - 32.0 -
Plant 2a 100.7 14.3 101.1 13.9
EGS 136.0 - 153.0 -
Healy 1 28.5 - -
Healy 2 61.9 0.0 -
Eva Creek 24.0 - - -
GVEA BESS - 26.0 - 26.0
North Pole CC - - 39.0 26.0
Chena 5 5.0 - 5.0 -
UAF 11.0 - 11.0 -
Fort Wainwright 14.0 - 14.0 -
Eielson AFB 8.0 - 8.0 -
Fort Knox (11.0) - (11.0) -
Generation/Spin Total 906.4 79.0 910.5 74.5
Dave's North Spin 78.4 73.8
Hydro Spin 38.2 8.2
CT/ST Spin 40.8 66.3
Dave's Creek - Hope Flow 72.5 72.5
HVDC Tie Flow 75.0 75.0
Total Kenai Export 147.5 147.5
Douglas - Stevens/GC Flow 94.0 171.0
Healy Export 189.0 149.0
Healy 1, 2, Eva None
wp_g220_s148_n094_h189_u100 wp_g290_s148_n171_h149_u100
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Table 4-26: Summer Peak Generation Scenarios
Description
Case Name
Generation Spin Generation Spin
Bradley Lake Hydro 119.8 0.2 119.8 0.2
Cooper Lake Hydro 19.6 - 19.6 -
Eklutna Hydro 4.0 36.0 4.0 36.0
Nikiski CC 51.1 - 51.1 -
Soldotna CT 40.0 0.1 40.0 0.1
Tesoro 8.0 - 8.0 -
Beluga Plant - - 59.0 -
SPP 141.0 (0.0) 141.0 (0.0)
Plant 1 - 28.0 -
Plant 2a 81.2 11.7 80.3 12.5
EGS 119.0 - 153.0 -
Healy 1 26.4 - -
Healy 2 61.9 0.0 -
Eva Creek 24.0 - - -
GVEA BESS - 26.0 - 26.0
North Pole CC - - - -
Chena 5 5.0 - 5.0 -
UAF 10.0 - 10.0 -
Fort Wainwright 15.0 - 15.0 -
Eielson AFB 10.0 - 10.0 -
Fort Knox (11.0) - (11.0) -
Generation/Spin Total 725.0 74.0 732.8 74.8
Dave's North Spin 73.7 74.5
Hydro Spin 36.2 36.2
CT/ST Spin 37.8 38.6
Dave's Creek - Hope Flow 56.1 56.1
HVDC Tie Flow 75.0 75.0
Total Kenai Export 131.1 131.1
Douglas - Stevens/GC Flow 54.0 172.0
Healy Export 147.0 147.0
sp_g220_s131_n054_h147_u100 sp_g290_s131_n172_h147_u100
Healy 1, 2, Eva None
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Table 4-27: Summer Valley Generation Scenarios
4.13.4 Results
The analysis shows that the recommended system improvements greatly increase transfer limits
and reliability over the existing system. Similar to the Kenai export limits, the improved Alaska
Intertie limits are not based on stability limits as they are in the existing system, but are limited by
the amount of load found north of Healy.
Tables 4-28 through 4-30 describe the improved system export limits along with the existing
system limits for all seasons. Note that these limits do not include any added margin. For all
seasons and generation scenarios, the transfers from Douglas and Healy have been increased
with the improvements. With the exception of three of the Winter Peak cases with reduced levels
of Healy area generation, the export limits are only limited by the amount of load found north of
Healy and the estimated minimum generation requirements in the Fairbank s area.
Description
Case Name
Generation Spin Generation Spin
Bradley Lake Hydro 119.8 0.2 119.8 0.2
Cooper Lake Hydro 19.6 - 19.6 -
Eklutna Hydro 2.0 38.0 2.0 38.0
Nikiski CC 55.3 - 55.3 -
Soldotna CT - -
Tesoro 2.9 - 2.9 -
Beluga Plant - - - -
SPP 54.5 (0.0) 109.1 (0.1)
Plant 1 - -
Plant 2a 19.3 36.0 47.6 7.8
EGS 17.0 - 51.0 -
Healy 1 28.5 - -
Healy 2 61.9 0.0 -
Eva Creek 24.0 - - -
GVEA BESS - 26.0 - 26.0
North Pole CC - - - -
Chena 5 5.0 - 5.0 -
UAF 1.5 - 1.5 -
Fort Wainwright 5.0 - 5.0 -
Eielson AFB 5.0 - 5.0 -
Fort Knox - - - -
Generation/Spin Total 421.4 100.3 423.8 71.9
Dave's North Spin 143.4 71.7
Hydro Spin 38.2 38.2
CT/ST Spin 105.4 33.7
Dave's Creek - Hope Flow 59.7 59.7
HVDC Tie Flow 75.0 75.0
Total Kenai Export 134.7 134.7
Douglas - Stevens/GC Flow (10.0) 106.0
Healy Export 88.0 88.0
Healy 1, 2, Eva None
sv_g220_s135_n0010_h088_u100 sv_g290_s135_n106_h088_u100
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Table 4-28: Winter Peak Existing/Future Southcentral Export Limits
Table 4-29: Summer Peak Existing/Future Southcentral Export Limits
Dispatch Healy #2 Healy #1 Eva Creek Total (MW)Douglas Healy Douglas Healy
1 on on on 114 54 151 94 189
2 on on -90 67 139 119 190
3 on -on 86 72 139 123 189
4 on --62 72 115 149 190
5 -on on 53 72 106 159 189
6 -on -29 65 75 175 181
7 --on 24 67 73 163 166
8 ---- 68 50 171 149
Shading indicates a Healy export or Northern area limiting contingency
Shading indicates Fairbanks at minimum generation, no stability limit
Healy Area Generation WP - Stability Export Limits (MW)
Existing Future
Dispatch Healy #2 Healy #1 Eva Creek Total (MW)Douglas Healy Douglas Healy
1 on on on 112 47 140 54 147
2 on on -88 61 130 79 147
3 on -on 86 69 135 81 147
4 on --62 79 120 106 147
5 -on on 50 71 101 118 147
6 -on -26 77 83 144 147
7 --on 24 80 83 146 147
8 ---- 81 60 172 147
Shading indicates Fairbanks at minimum generation, no stability limit
Healy Area Generation SP - Stability Export Limits (MW)
Existing Future
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Table 4-30: Summer Valley Existing/Future Southcentral Export Limits
In addition to improved stability limits, the proposed system greatly reduces the minimum
generation requirement in the Fairbanks area. In the existing system, the Fairbanks area has a
minimum generation requirement of approximately 20-30 MW in the Summer Valley, 50-70 MW
in the Summer Peak and 80-130 MW in the winter peak conditions. Following the completion of
the recommended improvements, the minimum generation requirement is 20-40 MW for all cases.
4.13.5 Sensitivity to Fairbanks Area Generation
For the future system cases where the stability limit was not reached (shaded in blue in the tables
above), sensitivity cases were run varying the GVEA generation in Fairbanks. The minimum
generation in Fairbanks was initially assumed to consist of the UAF and milit ary generation, plus
the Aurora unit (Chena 5). Sensitivity cases were run with the Aurora unit offline, such that only
the UAF and DOD units were online in Fairbanks. In almost all cases, the system remained stable
for the contingencies studied and the flows north out of Douglas and Healy were only limited by
the load in the Fairbanks area. For the future system, in the winter peak condition, the only
scenarios where additional generation beyond the UAF and DOD generation were required were
the cases with Healy 2 offline. All other cases were stable with no GVEA generation online in
Fairbanks.
This is not to say there are no generation constraints in the GVEA area, rather that the generation
constraints can be met by non-GVEA generation resources. This is compared to the existing
system which requires both GVEA and non-GVEA generation resources in the northern area.
4.13.6 UFLS
No UFLS occurs for the improved system. This is primarily due to the 35 MW BESS and the other
system improvements that create two transmission paths into each area of the system.
4.14 Conclusions
The system study results with the recommended improvements confirm that the improvements to
the transmission system provide increased transfer capacities and meet the requirements of
AKTPL-001-4 and relieve and / or remove generation constraints per the technical objectives of
the study. Overall, the objectives of the Final Plan are met by improving reliability, mitigating
future cost increases to Railbelt rate payers, allowing unconstrained energy transfers and use of
peaking capacity from the Bradley Lake hydroelectric project, and increasing energy transfers
between all areas of the Railbelt.
The Final Plan meets the recently adopted set of Railbelt Utility Reliability Standards.
Dispatch Healy #2 Healy #1 Eva Creek Total (MW)Douglas Healy Douglas Healy
1 on on on 114 (12) 86 (10) 88
2 on on -90 12 86 14 88
3 on -on 86 16 86 18 88
4 on --62 41 86 43 88
5 -on on 53 49 84 52 88
6 -on -29 64 75 77 88
7 --on 24 79 84 81 88
8 ---- 76 58 106 88
Shading indicates Fairbanks at minimum generation, no stability limit
Healy Area Generation SV - Stability Export Limits (MW)
Existing Future
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5 Project Prioritization
EPS completed an analysis with recommendations for the future transmission system in the
Railbelt. The need for a new transmission plan is driven by changes in the Railbelt generation
and transmission system since the completion of the 2010 Regional Integrated Resource Plan
(RIRP) administered by the Alaska Energy Authority (AEA). The project identification analysis is
included in the prior section of this report. This analysis covers the recommended prioritization
and ranking of projects for construction and funding.
Table 5-1 summarizes the projects and associated production cost benefits identified in the
previous study. In addition to these production cost benefits, the study identified non-production
cost benefits that will increase the total benefits of each project and for the projects as a whole.
Table 5-1: Project Summary Cost
This section of the report outlines the recommended construction and implementation sequence
of projects to the greatest extent possible. Portions of the final sequence may be based on non-
deterministic factors such as funding availability, geographic location, etc. Although these factors
are considered, they are not drivers for the recommended sequence.
The projects that comprise the Bradley Constraints Area (Table 5-1) encompass a group of
projects that mitigate the constraints on Kenai area hydro projects such as Bradley Lake and
Cooper Lake. These projects can be completed in a relatively short period of time, and appear
to be some of the largest benefit drivers. These projects also have the opportunity to bring
benefits forward in time, with relatively short on-line projects, such as the HVDC Intertie, and
Anchorage Area BESS projects. Due to their relatively short design and construction period, and
the ability to incrementally capture benefits as the projects are completed, these projects were
evaluated as the highest overall priority.
The Northern area projects can provide excellent benefits, but require longer planning and
construction periods. In addition, there are no incremental benefits realized until all of the projects
are completed and operational. Although the benefit/cost ratio could be very high for these
projects, the longer-term completion period and the lack of incremental benefits as the project
stages are completed result in these projects being considered slightly lower priority than the
Bradley constraint projects.
The Southcentral area projects are critical to the implementation of both the Northern and
Southern projects, and are critical to new Southcentral area generation, particularly at AML&P
and MEA. These are short-duration projects ready for engineering design and construction.
These projects are reliability driven, with little economic justification.
In assigning the priorities for the projects, each project was divided into several sub-components:
permitting, design, and construction. Prioritization and sequencing were completed on the
component level of the projects, instead of for the overall project. Prioritizing at the component
level allows projects with high-priorities, but long completion times, to start critical permitting and
design processes earlier in the time-line, while optimizing the costs and benefits for the overall
Bradley Constraints 403.0$
Southcentral / Overall 39.2$
Northern System 493.7$
Total 935.9$
Area Total Costs
(Millions)
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plan. It was assumed that several projects would be undertaken concurrently, with different
projects in permitting, design, and construction phases on-going during the same period.
While there may be a single description for a project, in most cases each project contains several
smaller projects forming a larger project. For instance, the Bradley-Soldotna transmission line is
made up of substation changes at Bradley Lake and Soldotna, as well as the transmission line
between the two stations. Each of these smaller divisions is prioritized within the larger project to
ensure the project’s completion is coordinated, and that overall costs and benefits are optimized.
The prioritization assumed a fifteen-year construction period, during which all of the projects
would be permitted, designed, and constructed. Within this period, it was assumed that year one
would be used to initiate design and permitting, and years 2-15 would be used to complete
construction of the remaining projects. The total dollars required in years 2-15 were levelized to
the greatest extent possible for all activities (permitting, design, construction). The desire to
maintain fairly constant dollar expenditures in years 2-15 had significant impacts on the
prioritization and recommended project sequence, however, even with the restructuring of the
projects to levelize expenditures, there are several high dollar outlay years due to large projects
such as the HVDC Intertie, the BESS, and the Lorraine SVC. These cannot be spread over
several years of construction.
A summary of the recommended project sequence is outlined in Table 5-2.
Table 5-2: Recommended Project Sequence
The annual and cumulative cash flow for the recommended sequence is shown on Figure 5-1:
Estimated Yearly and Cumulative Expenditures (USD) below.
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Figure 5-1: Estimated Yearly and Cumulative Expenditures (USD)
6 Prioritization: Process
Each major project was broken into appropriate smaller projects that collectively comprise th e
overall scope of the larger project. Each of the smaller projects was broken into required
permitting, design, and construction tasks with estimated completion times and budgets before
prioritization.
Prioritizing the components of each project allowed some projects to start long-duration activities,
such as permitting as a priority project, while maintaining the construction of the project as a lower
priority. In instances where the project would likely be a design/build type project, such as the
Teeland SVC, the project was not subdivided into separate design and build sections. For
projects that included the design and construction of long transmission lines, the projects were
divided into roughly the same level of effort for each section of the project. Since the preliminary
design has not been authorized for any projects, each section was assumed to require equal
effort. The breakdown of each major section and its subcomponents are shown in Table 6-1.
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Table 6-1: Project Sections and Subcomponents used for Analysis
Priority Group Project Description Phase Duration (months) Cost
1 Kenai 100 MW HVDC Intertie Permitting 24-36 $ 1,278,000
1 Kenai 100 MW HVDC Intertie Engineering 7 $ 19,170,000
1 Kenai 100 MW HVDC Intertie Construction 36 $ 164,862,000
1 Kenai Anchorage area battery Design 8 $ 3,020,000
1 Kenai Anchorage area battery Construction 30 $ 27,180,000
2 Kenai Convert line for 230 kV operation - I Design 3 $ 1,916,667
2 Kenai Convert line for 230 kV operation - I Construction 6 $ 17,250,000
3 Kenai Convert line for 230 kV operation - II Design 3 $ 1,916,667
3 Kenai Convert line for 230 kV operation - II Construction 6 $ 17,250,000
4 Kenai Convert line for 230 kV operation - III Design 3 $ 1,916,667
4 Kenai Convert line for 230 kV operation - III Construction 6 $ 17,250,000
3 Kenai Convert substations for 230 kV operation - I Design 6 $ 2,249,000
4 Kenai Convert substations for 230 kV operation - I Construction 12 $ 15,055,000
4 Kenai Convert substations for 230 kV operation - I Design 6 $ 2,249,000
4 Kenai Convert substations for 230 kV operation - I Construction 12 $ 15,055,000
6 Kenai Quartz Creek modify 115kV station Design 9 $ 135,380
6 Kenai Quartz Creek modify 115kV station Construction 15 $ 1,218,422
5 Kenai Upgrade QC-DC line to Rail conductor Design 4 $ 1,050,000
5 Kenai Upgrade QC-DC line to Rail conductor Construction - I 6 $ 12,600,000
5 Kenai Soldotna 115kV station - Ring bus Design 15 $ 768,441
5 Kenai Soldotna 115kV station - Ring bus Construction 24 $ 6,915,965
5 Kenai Add new bay/115kV cable to Bradley GIS Design 12 $ 286,514
5 Kenai Add new bay/115kV cable to Bradley GIS Construction 15 $ 2,578,627
5 Kenai 115 kV Line Bradley to Soldotna Permitting 30 $ 550,000
5 Kenai 115 kV Line Bradley to Soldotna Design 12 $ 5,500,000
5 Kenai 115 kV Line Bradley to Soldotna Construction 18 $ 48,950,000
2 Kenai Gas storage at local plant design 6 $ 1,200,000
2 Kenai Gas storage at local plant construction 8 $ 17,000,000
1 SouthCentral 115 kV Substation Permitting 24 $ 571,179
1 SouthCentral 115 kV Substation Design 5 $ 925,324
1 SouthCentral 115 kV Substation construction 8 $ 9,182,065
3 SouthCentral 115 kV Substation Design 4 $ 881,122
3 SouthCentral 115 kV Substation Construction 6 $ 8,811,218
4 SouthCentral 230 kV Substation Design 6 $ 1,760,170
4 SouthCentral 230 kV substation Construction 10 $ 20,225,730
5 SouthCentral Lorraine SVC Design/Construction 18 $ 19,224,000
Bernice Lake-Beluga HVDC
25 MW/14 MWh BESS
University-Dave’s 230 kV
Bradley - Soldotna 115 kV Line
262 MWh Flexible Gas Storage
Fossil Creek Substation
Eklutna Substation
Loraine Substation
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Priority Group Project Description Phase Duration (months) Cost
7 Northern Communications Upgrade Design 48-60 $ 3,000,000
7 Northern Communications Upgrade Construction 36-48 $ 12,000,000
6 Northern 230 kV Douglas Substation Design 6 $ 2,914,189
6 Northern 230 kV Douglas Substation Construction 14 $ 29,141,892
6 Northern 230 kV Double Circuit Permitting 6 $ 150,000
6 Northern 230 kV Double Circuit Design 8 $ 6,242,235
6 Northern 230 kV Double Circuit Construction 18 $ 49,688,190
6 Northern 230 kV Gold Creek Substation Design 6 $ 1,575,652
6 Northern 230 kV Gold Creek Substation Construction 18 $ 16,356,520
1 Northern 230 kV T-Line - Doug - Healy Permitting 48-72 $ 1,881,000
7 Northern 230 kV T-Line - Doug - Gold Ck Design - I 15 $ 4,702,500
7 Northern 230 kV T-Line - Doug - Gold Ck Design - II 15 $ 4,702,500
7 Northern 230 kV T-Line - Doug - Gold Ck Construction 18 $ 41,852,250
7 Northern 230 kV T-Line - Doug - Gold Ck Construction 18 $ 41,852,250
7 Northern 230 kV T-Line - Gold Vk - Healy Design 15 $ 4,702,500
7 Northern 230 kV T-Line - Gold Vk - Healy Design 15 $ 4,702,500
7 Northern 230 kV T-Line - Gold Vk - Healy Construction 18 $ 41,852,250
7 Northern 230 kV T-Line - Gold Vk - Healy Construction 18 $ 41,852,250
7 Northern Healy 230kV/138 kV Station Permitting 24 $ 1,454,050
7 Northern Healy 230kV/138 kV Station Design 8 $ 3,302,580
7 Northern Healy 230kV/138 kV Station Construction 18 $ 32,771,750
7 Northern 230 kV Conversion Gold Hill - Healy Permitting 24 $ 103,153
7 Northern 230 kV Conversion Gold Hill - Healy Design 24 $ 1,031,527
7 Northern 230 kV Conversion Gold Hill - Healy Construction 18 $ 28,195,065
7 Northern 230 kV Conversion Gold Hill - Healy Construction 18 $ 28,195,065
7 Northern 230 kV Conversion Gold Hill - Healy Construction 18 $ 28,195,065
7 Northern Healy-Gold Hill Subs (Clear,Nenana,Ester,
Gold Hill) Design 9 $ 1,369,414
7 Northern Healy-Gold Hill Subs (Clear,Nenana,Ester,
Gold Hill) Construction 24 $ 12,324,726
7 Northern Northern Intertie Subs (Eva Creek, Wilson) Design 8 $ 771,600
7 Northern Northern Intertie Subs (Eva Creek, Wilson) Construction 18 $ 6,592,870
Healy-Gold Hill 230 kV T-Line
Northern Intertie Conversion
Douglas-Lorraine 230 kV Double
Circuit Line
Communications Upgrade
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7 Prioritization: Conclusions
The recommended sequence for the design and construction of the projects is a mix of attempting
to bring the largest portion of benefits forward in time, while maintaining a fairly level annual
budget throughout the plan. The recommended plan results in Railbelt utilities realizing
substantial benefits approximately three years after the plan’s approval and funding, with a
significant jump in benefits 1-2 years following that with the completion of the HVDC transmission
line.
There are numerous strategies and possibilities for the plan, for instance construction of the major
230 kV and 115 kV transmission lines could be extended over a longer period. Although it is
possible that the plan could be shortened, this should be analyzed for impacts to the Alaska labor
market, and for associated cost impacts and project financing.
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Appendix: Detailed Cost Estimates
A.1 Bradley Constraints
Table A-1: Bernice Lake-Beluga HVDC
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Table A-2: 35 MW/20 MWh BESS
Table A-3: Bradley-Soldotna 115 kV – Line Sections
Location MW MWh BESS Costs Sub/Connection Costs Total Costs
Anchorage 35 20 35,321,920$ 5,800,000$ 41,121,920$
Line Section
Existing
Structure
Type
Existing
Framing
Existing
Line
Miles
Proposed
Structure
Type
Proposed
Framing
Proposed
Location Total Costs
Bradley - Bradley Jct X-Twr 115kV 19.2 X-Twr 115kV Parallel to Existing 18,000,000$
Bradley Jct - Soldotna STH-1A 115kV 48.6 STH-1A 115kV Parallel to Existing 37,000,000$
Total 55,000,000$
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Table A-4: Bradley Substation
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Table A-5: Soldotna Substation
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Table A-6: Dave’s Creek - Hope 230kV Line
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Table A-7: Hope – Portage 230kV Line
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Table A-8: Portage - Girdwood 230kV Line
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Table A-9: Girdwood - Indian 230kV Line
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Table A-10: Indian - University 230kV Line
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Table A-11: Dave’s Creek Substation
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Table A-12: Summit & Hope Substations
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Table A-13: Portage Substation
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Table A-14: Girdwood Substation
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Table A-15: Indian Substation
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Table A-16: University Substation
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Table A-17: Quartz Creek Substation
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Table A-18: Dave's Creek - Quartz Creek Upgrade
Line Section
Existing
Structure
Type
Existing
Framing
Existing
Line
Miles
Proposed
Structure
Type
Proposed
Framing
Proposed
Location
Total Costs
Quartz Ck - Davis Ck STH-1A 115kV 14.5 STH-1D 115kV DBL Existing Alignment 13,650,000$
Quartz Creek Sub 1,353,802$
Total 15,003,802$
Add breaker position, increase bus ampacity
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A.2 Southcentral / Overall
Table A-19: Fossil Creek Substation
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Table A-20: Eklutna Hydro Substation
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A.3 Northern System
Table A-21: Lorraine Substation
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Table A-22: Douglas Substation
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Table A-23: Healy Substation
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Table A-24: Gold Creek Substation
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Table A-25: Lorraine-Douglas 230 kV Line
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Table A-26: Douglas – Healy 230 kV line
Line Section
Line
Miles
Cost
($/mile)
Proposed
Framing Total Costs
Douglas - Healy 171 1,100,000$ 230kV 188,100,000$
Total 188,100,000$
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Table A-27: Healy – Gold Hill 230 kV Line
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Table A-28: Clear and Eva Creek Substations
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Table A-29: Nenana Substation
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Table A-30: Ester Substation
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March 6, 2017
Page 107
Table A-31: Gold Hill and Wilson Substations
Alaska Energy Authority
Railbelt Transmission Plan
March 6, 2017
Page 108