HomeMy WebLinkAboutWatana AK Railbelt Transmission Study Draft Report MeyerCoteBurlingame 03-17-2014-RB
Alaska Energy Authority
Pre/Post - Watana Transmission Study
Draft Report
Project #11-0514
March 17, 2014
David A. Meyer. P.E.
Dr. James W. Cote, Jr., P.E.
David W. Burlingame, P.E.
Alaska Energy Authority
Pre/Post - Watana Transmission Study
March 17, 2014
Page 2
Summary of Changes
Revision Revision Date Revision Description
0 March 17, 2014 Initial Draft
Table of Contents
1 INTRODUCTION ................................................................................................................... 8
2 PRE-WATANA: EXECUTIVE SUMMARY ............................................................................ 8
2.1 Kenai- Anchorage Transmission ..................................................................................... 10
2.2 Southcentral Alaska Reliability ........................................................................................ 12
2.3 Anchorage-Fairbanks Intertie Reliability/Economics ....................................................... 12
2.4 Proposed System Transmission Maps ............................................................................ 13
3 PRE-WATANA: INTRODUCTION – POWER FLOW & TRANSIENT STABILITY ANALYSIS
16
3.1 Loads .............................................................................................................................. 16
3.2 Generation Dispatches .................................................................................................... 16
4 PRE-WATANA: STUDY METHODOLOGY – TRANSMISSION POWER FLOW &
STABILITY .................................................................................................................................. 19
4.1 Planning Criteria .............................................................................................................. 19
4.1.1 Reliability ........................................................................................................................................ 19
4.1.2 Power Flow .................................................................................................................................... 20
4.1.3 Stability ........................................................................................................................................... 21
4.1.4 Voltage ........................................................................................................................................... 21
4.2 Transmission System ...................................................................................................... 22
5 PRE-WATANA: IMPROVEMENTS TO THE KENAI – ANCHORAGE TRANSMISSION .... 25
5.1 Proposed Improvement Projects ..................................................................................... 25
5.1.1 100 MW HVDC Intertie Beluga – Bernice Lake ............................................................................. 27
5.1.2 25 MW BESS – Anchorage Area ................................................................................................... 27
5.1.3 2nd Bradley Lake – Soldotna line .................................................................................................... 28
5.1.4 Flexible Gas Storage – Anchorage Area ....................................................................................... 28
5.1.5 Conversion University - Dave’s Creek Transmission Line to 230 kV ............................................ 28
5.1.6 University - Dave’s Creek 230 kV Substations and Compensation ............................................... 28
5.1.7 Dave’s Creek – Quartz Creek ........................................................................................................ 29
5.2 Costs ............................................................................................................................... 29
5.3 Alternatives ..................................................................................................................... 29
5.3.1 Reconductoring Soldotna – Diamond Ridge 115 kV line ............................................................... 29
5.3.2 Bradley Lake – Quartz 115 kV line ................................................................................................ 29
5.3.3 AC Bernice – Anchorage Southern Intertie .................................................................................... 29
5.3.4 2nd Soldotna – Quartz 115 kV line .................................................................................................. 30
6 PRE-WATANA: IMPROVEMENTS TO THE SOUTHCENTRAL TRANSMISSION ............ 31
6.1 Proposed Improvement Projects ..................................................................................... 31
6.1.1 Eklutna 115kV Substation .............................................................................................................. 31
6.1.2 Fossil Creek 115 kV Substation ..................................................................................................... 31
6.1.3 Lake Lorraine Station ..................................................................................................................... 32
6.1.4 Douglas Station Expansion ............................................................................................................ 32
6.1.5 Lake Lorraine – Douglas 230 kV Transmission Lines ................................................................... 32
6.2 Costs ............................................................................................................................... 32
6.3 Alternatives and Sensitivity ............................................................................................. 32
7 PRE-WATANA: IMPROVEMENTS TO THE NORTHERN RAILBELT TRANSMISSION ... 33
7.1 Proposed Improvement Projects ..................................................................................... 33
7.1.1 Lake Lorraine Station ..................................................................................................................... 35
7.1.2 Douglas Station Expansion ............................................................................................................ 35
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March 17, 2014
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7.1.3 Lake Lorraine – Douglas 230 kV Transmission Lines ................................................................... 35
7.1.4 Gold Creek Station ......................................................................................................................... 36
7.1.5 Healy Station .................................................................................................................................. 36
7.1.6 2nd Douglas - Healy 230 kV transmission line (operated at 138 kV) .............................................. 36
7.1.7 Communication Infrastructure ........................................................................................................ 36
7.2 Costs ............................................................................................................................... 36
7.3 Sensitivities ..................................................................................................................... 37
7.3.1 Eva Creek Analysis ........................................................................................................................ 37
7.3.2 Zehnder Dispatch Analysis ............................................................................................................ 37
7.3.3 Load Transfer Trip Analysis ........................................................................................................... 38
7.3.4 Healy – Fairbanks Transmission Line Upgrades ........................................................................... 39
7.4 Alternatives ..................................................................................................................... 41
7.4.1 Healy – Douglas 138 kV operation at 230 kV ................................................................................ 41
8 PRE-WATANA: ECONOMIC BENEFIT ANALYSIS ............................................................ 42
8.1 Production Cost Benefits ................................................................................................. 42
8.1.1 Software Employed ........................................................................................................................ 42
8.1.2 Data and Information Sources ....................................................................................................... 42
8.1.3 Transmission Upgrades Examined ................................................................................................ 43
8.1.4 Case NS0 ....................................................................................................................................... 44
8.1.5 Case S1 ......................................................................................................................................... 44
8.1.6 Case S2 ......................................................................................................................................... 44
8.1.7 Case S3 ......................................................................................................................................... 44
8.1.8 Case S4 ......................................................................................................................................... 45
8.1.9 Cases N1 – N3 ............................................................................................................................... 45
8.1.10 Case N1 ......................................................................................................................................... 45
8.1.11 Case N2 ......................................................................................................................................... 45
8.1.12 Case N3 ......................................................................................................................................... 45
8.1.13 Case NS4 ....................................................................................................................................... 45
8.1.14 Total Railbelt Results ..................................................................................................................... 46
8.2 Capacity Deferral ............................................................................................................ 47
8.3 Reservoir Optimization .................................................................................................... 47
8.4 Unserved Energy ............................................................................................................ 48
8.5 Excess Energy ................................................................................................................ 49
8.6 Reduced Regulation ........................................................................................................ 49
8.7 Reduced Spinning reserve costs .................................................................................... 49
8.8 Renewable Resource Integration .................................................................................... 50
8.9 Gas Sensitivities – Fairbanks LNG ................................................................................. 50
8.10 Load Sensitivities ............................................................................................................ 50
8.11 Gas Price Sensitivities .................................................................................................... 50
8.12 Spinning Reserve Determination .................................................................................... 51
9 PRE-WATANA: CONCLUSIONS ........................................................................................ 52
10 PRE-WATANA PRIORITIZATION: EXECUTIVE SUMMARY ............................................. 53
11 PRE-WATANA PRIORITIZATION: PROCESS ................................................................... 55
12 PRE-WATANA PRIORITIZATION: CONCLUSIONS .......................................................... 58
13 POST-WATANA: EXECUTIVE SUMMARY ........................................................................ 59
14 POST-WATANA: OVERALL STUDY OBJECTIVES ........................................................... 64
15 POST-WATANA: WATANA PLANT MODELING ................................................................ 64
16 POST-WATANA: WATANA INTERCONNECT / ALASKA INTERTIE ................................ 65
16.1 Watana Unit Trip Analysis ............................................................................................... 67
17 POST-WATANA: GVEA ...................................................................................................... 69
17.1 Watana – GVEA Transfer Limits ..................................................................................... 69
17.2 GVEA Energy Storage .................................................................................................... 71
18 POST-WATANA: KENAI ..................................................................................................... 71
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March 17, 2014
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19 POST-WATANA: SOUTHCENTRAL .................................................................................. 71
19.1 Watana – Southcentral Transfer Limits ........................................................................... 72
19.2 Anchorage Energy Storage ............................................................................................. 73
20 POST-WATANA: CONCLUSION ........................................................................................ 73
A PRE-WATANA STUDY APPENDIX .................................................................................... 75
B PRIORITIZATION APPENDIX ............................................................................................ 82
C PRE-WATANA DETAILED COST ESTIMATES ................................................................. 86
D POST-WATANA DETAILED COST ESTIMATES ............................................................. 137
E ECONOMIC ANALYSIS SENSITIVITY ............................................................................. 139
F PRODUCTION MODELING PRESENTATION ................................................................. 144
G PRE-WATANA SIMULATION RESULTS .......................................................................... 178
H POST-WATANA SIMULATION RESULTS ....................................................................... 179
I KENAI TRANSMISSION STUDY ...................................................................................... 180
J REGULATION RESOURCE STUDY ................................................................................ 235
Alaska Energy Authority
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March 17, 2014
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List of Tables
Table 2-1 Project Summary Cost and Benefits ............................................................................. 9
Table 2-2 Sensitivity Case Summaries ......................................................................................... 9
Table 2-3 Non-Production Benefit Summaries ........................................................................... 10
Table 2-4 Kenai Project Costs .................................................................................................... 11
Table 2-5 Southcentral Project Costs ......................................................................................... 12
Table 2-6 Northcentral Project Costs .......................................................................................... 13
Table 2-7 Northcentral Project Costs –230 kV Line Upgrades ................................................... 13
Table 3-1 Year 2023 Railbelt Seasonal Load Totals .................................................................. 16
Table 3-2 Railbelt Year 2023 Generation Resources ................................................................. 17
Table 3-3 Generation Dispatch (MW) for Kenai and Southcentral Analysis ............................... 18
Table 3-4 Healy Generation Scenarios ....................................................................................... 18
Table 3-5 Generation Dispatch (MW) for Northcentral Analysis ................................................. 19
Table 4-1 Railbelt Load Totals and UFLS settings ..................................................................... 20
Table 4-2 Railbelt Ratings Example ............................................................................................ 21
Table 5-1 Kenai Export Stability Limits – Base System .............................................................. 25
Table 7-1 Healy Stability Limits – Base System ......................................................................... 33
Table 7-2 Healy Stability Limits – Proposed Upgrades ............................................................... 34
Table 7-3 Eva Creek Analysis ..................................................................................................... 37
Table 7-4 North Pole LM6000 vs. Zehnder Frame 5 Analysis .................................................... 37
Table 7-5 GVEA Unit Inertia Analysis ......................................................................................... 38
Table 7-6 Load Transfer Trip Analysis – Winter Peak System ................................................... 38
Table 7-7 Healy – Fairbanks Transmission Upgrades – Summer Peak ..................................... 39
Table 7-8 Healy – Fairbanks Transmission Upgrades – Winter Peak ........................................ 39
Table 7-9 Load Transfer Trip Analysis – 3rd 138 kV Line – Winter Peak .................................... 40
Table 7-10 Load Transfer Trip Analysis – 230 kV Upgrade – Winter Peak ................................ 41
Table 8-1 Production Cost Results ............................................................................................. 46
Table 10-1 Project Summary Cost and Benefits ......................................................................... 53
Table 10-2 Recommended Project Sequence ............................................................................ 54
Table 11-1 Project Sections and Subcomponents used for Analysis.......................................... 56
Table 13-1 Post - Watana System Project Cost Summary ......................................................... 59
Table 13-2 Watana Interconnection Project Costs ..................................................................... 60
Table 13-3 Southcentral Project Costs ....................................................................................... 60
Table 13-4 Energy Storage Project Costs .................................................................................. 61
Table 15-1 Watana power flow modeling specifics (each) .......................................................... 64
Table 15-2 Susitna turbine governor modeling specifics, IEEEG3 ............................................. 65
Table 16-1 Watana Interconnect / Alaska Intertie Configuration Analysis .................................. 66
Table 16-2 Railbelt Dispatch – Unit Trip Analysis ....................................................................... 68
Table 16-3 Railbelt Load Totals and UFLS settings ................................................................... 68
Table 16-4 Watana Unit Size Analysis – BES Sizing .................................................................. 68
Table 17-1 Winter Peak GVEA Import Analysis .......................................................................... 70
Table 17-2 Summer Peak GVEA Import Analysis ...................................................................... 70
Table A-1 Year 2023 Railbelt Seasonal Loads by Substation .................................................... 76
Table A-2 Conductor Ratings ...................................................................................................... 77
Table A-3 Historically Displaced Energy ..................................................................................... 77
Table A-4 Bradley Stranded Capacity ......................................................................................... 77
Table A-5 Kenai Loss Analysis ................................................................................................... 78
Table A-6 2nd Bradley Lake – Soldotna Line, Substation Costs .................................................. 79
Table A-7 2nd Bradley Lake – Soldotna Line, Line Construction Costs ....................................... 79
Table A-8 Dave’s Creek – University 230 kV Station Conversion Costs .................................... 79
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March 17, 2014
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Table A-9 Dave’s Creek – University 230 kV Line Conversion Costs ......................................... 79
Table A-10 Dave’s Creek – Quartz Creek Line Upgrade ............................................................ 79
Table A-11 HVDC and BES System Costs ................................................................................. 80
Table A-12 Eklutna Express Substation Addition Costs ............................................................. 80
Table A-13 Lorraine & Douglas Substation Addition Costs ........................................................ 80
Table A-14 Lorraine – Douglas 230 kV Line Addition Costs ....................................................... 80
Table A-15 Northern Intertie Station Upgrade Costs .................................................................. 81
Table A-16 2nd Northern Intertie Line .......................................................................................... 81
Table C-1 Bernice Lake-Beluga HVDC ....................................................................................... 86
Table C-2 25 MW/14 MWh BESS ............................................................................................... 87
Table C-3 Bradley-Soldotna 115 kV – Line Sections .................................................................. 87
Table C-4 Bradley Substation ..................................................................................................... 88
Table C-5 Soldotna Substation ................................................................................................... 90
Table C-6 Dave’s Creek - Hope 230kV Line ............................................................................... 92
Table C-7 Hope – Portage 230kV Line ....................................................................................... 93
Table C-8 Portage - Girdwood 230kV Line ................................................................................. 94
Table C-9 Girdwood - Indian 230kV Line .................................................................................... 95
Table C-10 Indian - University 230kV Line ................................................................................. 96
Table C-11 Dave’s Creek Substation .......................................................................................... 97
Table C-12 Summit & Hope Substations .................................................................................... 99
Table C-13 Portage Substation ................................................................................................. 101
Table C-14 Girdwood Substation .............................................................................................. 103
Table C-15 Indian Substation ................................................................................................... 105
Table C-16 University Substation ............................................................................................. 107
Table C-17 Quartz Creek Substation ........................................................................................ 108
Table C-18 Dave's Creek - Quartz Creek Upgrade .................................................................. 110
Table C-19 Fossil Creek Substation ......................................................................................... 111
Table C-20 Eklutna Hydro Substation ....................................................................................... 113
Table C-21 Lorraine Substation ................................................................................................ 115
Table C-22 Douglas Substation ................................................................................................ 117
Table C-23 Healy Substation .................................................................................................... 121
Table C-24 Gold Creek Substation ........................................................................................... 125
Table C-25 Lorraine-Douglas 230 kV Line ................................................................................ 127
Table C-26 Douglas – Healy 230 kV line .................................................................................. 128
Table C-27 Healy – Gold Hill 230 kV Line ................................................................................ 129
Table C-28 Clear and Eva Creek Substations .......................................................................... 130
Table C-29 Nenana Substation ................................................................................................. 131
Table C-30 Ester Substation ..................................................................................................... 133
Table C-31 Gold Hill and Wilson Substations ........................................................................... 135
Table D-1 Watana - Gold Creek 230 kV lines ........................................................................... 137
Table D-2 Healy - Gold Creek - Douglas 230 kV operation ...................................................... 138
Table D-3 Southcentral Upgrades ............................................................................................ 138
Table D-4 Energy Storage Project Costs .................................................................................. 138
Alaska Energy Authority
Pre/Post - Watana Transmission Study
March 17, 2014
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Table of Figures
Figure 2-1 Northern Proposed Transmission System ................................................................. 14
Figure 2-2 Kenai and Southcentral Proposed Transmission System ......................................... 15
Figure 4-1 Northern Base Transmission System ........................................................................ 23
Figure 4-2 Southcentral and Kenai Base Transmission System ................................................. 24
Figure 5-1 Kenai Export Loss Analysis ....................................................................................... 26
Figure 7-1 Anchorage – Healy Loss Analysis: Base vs. Proposed ............................................. 35
Figure 10-1 Estimated Yearly and Cumulative Expenditures (USD)........................................... 55
Figure 13-1 Northern Post – Watana Proposed Transmission System ...................................... 62
Figure 13-2 Kenai and Southcentral Post – Watana Proposed Transmission System ............... 63
Figure 15-1 IEEEG3 Block Diagram ........................................................................................... 65
Alaska Energy Authority
Pre/Post - Watana Transmission Study
March 17, 2014
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1 Introduction
This report includes the findings of the Pre-Watana and Post-Watana studies completed to
determine the future needs of the Railbelt transmission system. The prioritization of the Pre-
Watana projects is also included.
Preliminary study results are included in the Appendix of this report. The preliminary results
consist of the Kenai Transmission Study and the Regulation Resource Study. Both of these
studies were completed in the earlier stages of the project and served as building blocks for the
final Pre-Watana and Post-Watana studies presented in this report. The preliminary results
identified many of the initial Pre-Watana projects needed in the Kenai and Southcentral areas.
Some of the content of these preliminary studies has been refined for this final report. The key
refinements include the cost estimates and study assumptions.
2 Pre-Watana: Executive Summary
Electric Power Systems (“EPS”) has completed an analysis to determine the recommended
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, mitigates future cost increases to
Railbelt rate payers, allows unconstrained energy transfers and the use of peaking capacity
from the Bradley Lake hydroelectric project, provides improved and increased energy transfers
between all areas of the Railbelt, and facilitates the addition of the Watana large hydro project.
The benefit of the projects as a whole results in a net present value savings of over
$2,678,425,000 over the 50-year life of the projects in power production simulations when
compared to projected 2015 operating conditions. The economic benefit of improved reliability
as measured by unserved energy, capacity deferral of individual utilities, reservoir optimization
of the Bradley and Cooper Lake hydro plants, the use of excess energy during high water years,
construction savings during the required rebuild of existing facilities and the amount of capacity
deferral saving further increase the benefit of the projects by an estimated $30-40,000,000 per
year although these additional savings were not evaluated in detail.
The benefit of the improvements with increased energy from Bradley’s Battle Creek project or
the ability to contract for increased base load gas supplies are not considered in the analysis.
With a total construction cost of $903,200,000, this results in a simplified benefit/cost ratio of 3.4
utilizing only the production cost savings, which is an extremely high ratio for electrical
transmission projects. The inclusion of additional benefits would push this number even higher.
There are few projects that can be evaluated individually, since the benefits to the Railbelt
consumers are derived from a combination of individual projects; however the projects can be
evaluated by how they improve reliability and economics for the Anchorage–Kenai area,
Southcentral Alaska and the Anchorage to Fairbanks (Northern) connection. These system
improvements must be constructed and operational prior to commercial operation of the Watana
Hydro Project or any other large energy project in the Railbelt. Although all of these projects are
also required to support a large energy project, improvements that are specifically required to
support a large hydro project or any other large energy project are addressed in a follow-up
study to this report.
A summary of the projects and associated production cost benefits are provided in Table 1-1
below.
Alaska Energy Authority
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March 17, 2014
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Table 2-1 Project Summary Cost and Benefits
Additional studies were completed to determine the sensitivity of the project benefits to differing
gas prices in the Southcentral area, LNG availability in the Fairbanks area, differing spinning
reserve levels, differing regulation levels, loss of existing load and addition of new loads in the
system. The sensitivity cases indicate that the loss of 44 MW of load coupled with the
availability of LNG in the Fairbanks area results in the lowest savings for the projects at
$60.6M/year. However these savings could be increased to over $100M/year by changes in
regulation and spinning reserve allocation. Sensitivities in gas pricing do not have an
appreciable impact on the base case savings. Regulation and spinning reserve changes made
possible by the transmission improvements could increase the savings to $190M/year in the
base case.
A summary of the sensitivity cases is presented in the Table 1-2 below.
Table 2-2 Sensitivity Case Summaries
Benefits other than production cost simulations are more difficult to quantify, however a
summary of the benefits and their estimated value is provided in the Table 1-3 below.
Bradley Constraints 388.2$ 893.1$ 2.3
Southcentral / Overall 20.4$ 482.3$ 23.7
Northern System 494.7$ 1,672.5$ 3.4
Total 903.2$ 3,047.9$ 3.4
Area Total Costs
(Millions)
Summary Benefit
(Millions)
Benefit /
Cost Ratio
Sensitivity Case Description
Annual
Production Cost
Base
Production Cost
Annual
Change
Change in base
case NPV
Base Case Base Case - All improvements in service -$ 140,000$ -$ 2,567,000$
Reduced regulation
Decrease overall regulation requirements by
pool dispatch 141,500$ 140,000$ 1,500$ 27,500$
Reduced Spinning Reserve
Decrease spinning reserve by 75% of BESS
capacity 206,000$ 140,000$ 66,000$ 1,210,000$
Fairbanks LNG Fairbanks LNG at North Pole CC 75,000$ 140,000$ 1,375,000$
44 MW Load Loss Loss of Fort Knox 117,700$ 140,000$ (22,300)$ (409,000)$
44 MW Load Loss/ LNG Loss of Ft Knox/ LNG at North Pole CC 60,600$ 140,000$ (79,400)$ (1,456,000)$
100 MW Load Addition Add 100 MW load in GVEA 309,000$ 140,000$ 169,000$ 3,099,300$
100 MW Load Addition/ LNG Add 100 MW Load in GVEA/ LNG at NPCC 244,800$ 140,000$ 104,800$ 1,922,000$
Gas Prices 2018 Hilcorp prices vs esclated 2012 138,700$ 140,000$ (1,300)$ (23,840)$
Duct Firing Duct firing capacity declared for unit capacity 148,500$ 140,000$ 8,500$ 1,559,000$
Sensitivity Case Summaries ($000)
Alaska Energy Authority
Pre/Post - Watana Transmission Study
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Table 2-3 Non-Production Benefit Summaries
2.1 Kenai- Anchorage Transmission
Transmission between the Kenai Peninsula and the Railbelt transmission system has
essentially depended on a single 115kV transmission line to deliver power to or receive power
from Southcentral Alaska. This line was originally built to transfer a relatively small amount of
Cooper Lake Hydro power (16MW) into the Anchorage area. The Bradley Hydroelectric Project,
added in 1991, has been constrained in its operation since its completion due to the inadequate
transmission system between the Kenai and the Railbelt system. In the past, the Bradley Lake
project participants successfully mitigated the constraints 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 will foreclose many of
the mechanisms historically available to the Railbelt utilities to mitigate the constraints on the
Bradley project. As a result of the loss of the mitigation measures 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 cost increases in both electrical
line losses, lost generation capacity and operating costs due to the constraints placed on the
Bradley project.
In addition to the near-term constraints identified above, the Anchorage-Kenai constraints
severely inhibit the development of both large-scale renewable hydro projects in the Railbelt as
well as the integration of additional variable resources such as wind energy. These constraints
prevent the use of Kenai hydro as part of an overall hydro management or coordination strategy
and could significantly increase the cost of future hydro development projects. The lack of
transmission capacity also limits the amount of Kenai resources that can be used to mitigate the
impacts of variable generation such as wind energy and will significantly increase the cost of
integrating renewables into the Railbelt system. The Eklutna hydro facility is not constrained by
the Railbelt transmission system.
The basic constraint of the Bradley project is the lack of an adequate transmission system used
to deliver the project’s energy from Kachemak Bay to Anchorage and Fairbanks. Besides only a
single transmission line between Kenai and Anchorage, a similar 115 kV transmission line from
Soldotna to the Cooper Lake area make up the connection to Bradley Lake. These two 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.
The solution to eliminating the Bradley constraints is an improved transmission system between
Anchorage and Kenai. This can be accomplished by either an additional transmission path
Benefit Description Annual NPV
Capacity Deferral Defer new unit capacity through resource sharing -$ -$
Reservoir Optimization Allow optimization of CLPP and Bradley lake levels 412.5$ 7.6$
Unserved Energy
Decrease amount of unserved energy due to
transmission/generation outages 0.9$ 16,486.0$
Excess Energy Allow use of excess energy during high water years 1,433.0$ 26,300.0$
Hydro-Hydro Coordination Allow Coordination of Kenai hydro/future hydro -$ -$
Non-Production Benefit Summaries ($000)
Comments
Requires Long-term resource analysis
optimize hydro MWh with lake elevation
decrease customer outages
prevent hydro spill at Bradley
design and optimization studies are
required to estimate benefit
Alaska Energy Authority
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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 unconstrain Bradley, since Bradley must be operated to be in compliance with the
lowest operating conditions of the new line or the existing line. Upgrading only the existing
transmission system from Bradley to Anchorage 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. 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.
Although the individual benefits of each project are difficult to derive in all cases, groups of
projects were developed that can be evaluated to determine their relative benefit to the system.
A summary of the costs of the proposed projects to unconstrain the Bradley Lake hydroelectric
project are presented in Table 2-4. The costs are estimated to be accurate budgetary figures.
Table 2-4 Kenai Project Costs
The groups used to evaluate the benefits of the projects are presented below.
*The benefits of hydro-hydro coordination are very large for the development of future large
hydro projects. The ability to provide hydro regulation from the Kenai hydro resources has a
tremendous benefit in the design and construction costs of the future large hydro projects.
The exact benefit is unknown, but is estimated that it could exceed the combined total of all
other benefits.
1 Bernice Lake-Beluga HVDC 100 MW HVDC Intertie $ 185.3
2 25 MW/14 MWh BESS Anchorage area battery $ 30.2
3 Bradley-Soldotna 115 kV Line New line & Bradley/Soldotna sub $ 65.5
4 University-Dave’s Creek 230kV Reconstruct existing line $ 57.5
5 University-Dave’s Substations Convert line for 230 kV operation $ 34.6
6 Dave's Creek - Quartz Creek Upgrade line to Rail conductor, Quartz sub $ 15.0
Electrical Projects Total $ 388.2
3 262 MWh Flexible Gas Storage Gas storage at local plant $ 18.2
Description Cost
(Millions)ProjectPriority
1 HVDC/ 25 MW BESS $ 215.5 $ 567.8 2.6
2 Bradley-Soldotna 115 kV Line $ 65.5 $ 70.3 1.1
3 Univ-Daves-Quartz Creek 115 kV $ 107.1 $ 496.7 4.6
Totals $ 388.2 $ 1,134.8 2.9
Benefit
(Millions)
Benefit /
CostGroupProjectCost
(Millions)
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2.2 Southcentral Alaska Reliability
A single 115kV transmission line between the Anchorage and the Palmer areas connects
ML&P’s Plant 2 to the Eklutna Hydro Plant. A recent upgrade of this line has added a second
circuit, which is not connected to the system due to limitations in available substation space for
new breaker positions. Improvements to the reliability of the Southcentral Railbelt system
serving Anchorage and the Mat-Su area consist of two substation projects allowing this
additional circuit to be placed into service. The projects are driven by reliability requirements.
The benefits of un-served energy are used through-out the electrical industry to evaluate
potential projects, however the value of un-served energy has not been established by study in
the Railbelt. The Fossil Creek Substation allows the interconnection of the second transmission
line into the Railbelt system and also a second interconnection between the ML&P system
Fossil Creek through Raptor station. This second path into the ML&P system eliminates
generation constraints for the new Eklutna Generation Station and increases the critical clearing
time for 115 kV faults to manageable levels.
A summary of the costs and benefits of the proposed projects for the Southcentral Railbelt are
presented in Table 2-5.
Table 2-5 Southcentral Project Costs
2.3 Anchorage-Fairbanks Intertie Reliability/Economics
Transfers to the Fairbanks area to or from the Anchorage/Kenai systems are currently limited to
a single line between the two areas. Due to the single line, all power transfers are “economic”
transfers that occur only when energy is available in the south and the 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 the areas is out of service. The
absence of a second transmission line between the areas precludes the contracting for firm
power between the 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 transferred between the areas from 75 MW of non-firm to 125 MW of firm power sales.
Transfers can be increased by up to 50 MW by incorporating momentary loadshedding similar
to the existing operating manner following certain fault conditions.
The second transmission line spanning the 171 miles between Healy and Anchorage will
prevent outages to Fairbanks and allow GVEA to access electrical and gas markets in the
Southcentral system. The second line is also required in order to facilitate hydro-hydro
optimization of existing and planned hydro projects in the future. Although the benefit of the
second line is greatly enhanced by a future hydro plant, the economic benefit to the Railbelt
consumers without a future hydro far exceed the costs of the line.
A summary of the costs and benefits of the proposed projects to provide reliability and economic
energy transfers between the northern and southern systems is presented in Table 2-6. While
the costs are estimated to be accurate budgetary figures, the benefits are only production cost
1 Fossil Creek New 115 kV substation 10.7$
1 Eklutna Hydro New 115 kV substation 9.7$
Total 20.4$ 480.5 23.6
Benefits
(Millions)
Benefit /
CostPriority Station Description Costs (Millions)
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benefits and do not include hydro-hydro coordination benefits to future projects and as such
may underestimate the value of the projects to the Railbelt Consumers and the State of Alaska.
Table 2-6 Northcentral Project Costs
**The ability to provide both increased values of firm and non-firm energy to the interior at
significantly lower prices has the potential to allow more development of loads and
industry in the interior. This potential benefit and impact to the state has not been
evaluated in this study.
*** As with the Anchorage-Kenai project, these projects are required in order to capture
the cost savings of hydro-hydro coordination between existing and future hydro projects.
It should be noted that the large benefit associated with the Douglas-Healy line addition cannot
be realized without the construction of the Lorraine-Douglas line section. Therefore, the
analysis related to the Douglas-Healy line section should include the costs and benefits of the
required Lorraine-Douglas line section also.
Due to the large value of economic benefit of these projects, an additional analysis was
completed to determine the transmission improvements required to increase imports into the
Fairbanks area beyond the values found above. The analysis determined that upgrading the
138 kV lines into the Fairbanks area to 230 kV essentially eliminated transfer constraints
between southern generation and resources and the Fairbanks area. The costs and benefits of
the 230 kV transmission line upgrades are presented in the table below.
Table 2-7 Northcentral Project Costs –230 kV Line Upgrades
2.4 Proposed System Transmission Maps
Transmission maps were created for the proposed transmission system and a shown below in
Figure 2-1 Northern Proposed Transmission System and Figure 2-2 Kenai and Southcentral
Proposed Transmission System.
Group Item Description
Costs
(Millions)
Benefit
(Millions)
Benefit /
Cost
1 Lorraine-Douglas Lorraine - Douglas 230 kV line/stations $ 129.3 $ 27.5 0.2
2 Douglas – Healy line New 230 kV line operated at 138 kV $ 243.6 $ 1,497.0 6.1
Communications Upgrade $ 15.0
Total $ 387.9 $ 1,524.5 3.9
Group Item Description
Cost
(Millions)
Benefit
(Millions)
Benefit /
Cost
1 Healy-Fairbanks 230 kV Convert 138 kV to 230 kV $ 106.8 $ 415.9 3.9
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Figure 2-1 Northern Proposed Transmission System
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Figure 2-2 Kenai and Southcentral Proposed Transmission System
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3 Pre-Watana: Introduction – Power Flow & Transient Stability Analysis
Since the completion of the 2010 RIRP, plans for new thermal and hydro generation additions
on the Kenai, thermal generation additions in MEA, AML&P, and CEA systems, and
transmission changes in the MEA and Doyon transmission system, have been proposed or are
under construction for the Railbelt system. The studies and analyses included in the RIRP
required updating to reflect these generation changes and to analyze the impact these changes
would have on the transmission system recommendations included in the RIRP. Evaluation of
the transmission improvements required in the Railbelt transmission system (“backbone”) prior
to the construction of Watana was also completed. For purposes of this study, the backbone
transmission system is defined as the 230, 138, and 115 kV transmission lines from the Kenai
(Soldotna) to Anchorage and to the Gold Hill and Wilson substations in GVEA.
The study used the three seasonal power flow cases, summer valley, summer peak, and winter
peak, using the IOC approved 2020 base cases and utilized version 32.1.1 of Power Systems
Simulator Engineer (“PSS/E”) for power flow and transient contingency analysis.
The 2023 power flow cases were configured based on the analysis needed to identify facility
alternatives and to recommend an overall transmission system plan. EPS also assumed Healy #
2 and Eva Creek wind project were available for dispatch in the study.
3.1 Loads
The Railbelt system loads for the 2023 study year are shown in Table 3-1 below. It is assumed
that the load growth from the 2020 IOC cases to the year 2023 and 2024 load season is
negligible. The winter peak season has a total load of 1034 MW and the summer valley has a
total load of 450 MW. The summer peak season has a total load of 786 MW. The seasonal
loads by substation are shown in Table A-1 Year 2023 Railbelt Seasonal Loads by Substation
of the Appendix.
Table 3-1 Year 2023 Railbelt Seasonal Load Totals
HEA MLP CEA Seward MEA GVEA
Summer Valley 46 108 94 8 68 127 450
Summer Peak 67 210 157 10 116 225 786
Winter Peak 99 226 229 12 186 283 1034
Season Load (MW)Total
Load
3.2 Generation Dispatches
The generation resources for the Railbelt system are shown below in Table 3-2. Indicated in the
table are the plant name, the number of units at the plant, the total power output of the plant
during winter peak conditions, the owner of the plant, as well as a flag for if the plant is a future
addition that is expected to be in place before the 2023 year time frame.
The future or recent plant additions include a new combustion turbine (CT) at Soldotna, and a
just completed new steam turbine (ST) at Nikiski. Two new CT’s will replace older units at Plant
1, and Plant 2 will be expanded with the addition of three new units (two CT’s and one ST). A
new plant at Southcentral was completed with a total of 4 new units (3 CT’s and one ST). The
EGS plant in MEA will be built with 10 reciprocating engines. The Eva Creek wind farm was built
with 12 wind turbines and Fire Island wind farm was built with 11 wind turbines.
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It is assumed that Healy #2 will be refurbished to generate power before the 2023 time period.
The system was evaluated with and without the continuing service of Healy #1 after Healy #2
becomes operational.
Table 3-2 Railbelt Year 2023 Generation Resources
Bradley Lake 3 Hydro 141 State of Alaska
Tesoro 3 CT 10 Tesoro
Soldotna 1 CT 49 HEA x
Nikiski 2 CT & ST 78 HEA
Plant 13CT 96 MLP x
Plant 24CT & ST 254 MLP
Plant 2 Exp. 3 CT & ST 115 MLP x
Eklutna Lake 2 Hydro 40 MLP & CEA
Southcentral 4 CT & ST 193 MLP & CEA
Buluga 7 CT & ST 404 CEA
Fire Island 11 Wind 18 CEA
International 3 CT 51 CEA
Cooper Lake 2 Hydro 20 CEA
Bernice Lake CT 78 CEA
Eklutna 2 / Reed 10 Recip 170 MEA x
Healy #2 1 Steam Boiler 62 GVEA x
Healy #1 1 Steam Boiler 29 GVEA
Eva Creek 12 Wind 24 GVEA
DPP 1 CT 26 GVEA
Zehnder 4 CT / Recip 37 GVEA
North Pole Sub 2 CT 128 GVEA
North Pole CC 2 CT & ST 65 GVEA
Chena 4 CT / Recip 38 IPP
UAF 4 Steam / Recip 14 UAF
Ft. Wainwright 5 Recip 22 DOD
Eielson AFB 5 Recip 21 DOD
Future
AdditionPlantUnits
(#)Type Pmax
(MW)Owner
Table 3-3 lists some generation dispatches that were used for parts of the study. These
dispatches were used to stress the Kenai / Southcentral Railbelt systems for use in power flow
and transient contingency analysis.
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Table 3-3 Generation Dispatch (MW) for Kenai and Southcentral Analysis
sv sp wp sv sp wp sv sp wp sv sp wp sv sp wp
Soldotna 17 14 28 40 49 40 40 49
Bradley Lake 90 90 90 120 120 120 140 140 140 140 140 140 140 140 140
Tesoro 3 7 9 3 7 9 3 7 9 3 7 9 3 7 9
Nikiski 393643 304861 284661
Bernice 7 27
Plant 1 2864 5660 5650 56 50 56 64
Plant 22037
Plant 2 EXP 92 115 92 115 51 92 115 51 92 115 51 93 115
International
Fire Island 00000000000 000 0
Southcentral 161 155 186 135 138 200 106 145 195 106 145 195 110 134 188
Cooper Lake 20 20 20 20 20 20 20 20 20 20 20 20
Eklutna 3736383639383838383838 383838 38
Eklutna Recip 68 112 170 47 129 170 34 102 170 34 102 170 34 102 170
Healy 8788288660 6161 61 61 61 61
N. Pole 79 128 40 128 79 128 79 128 79 128
NPCC 50 40 65 50 40 65 53 40 65 53 40 65 53 40 65
Kenai Export 99 99 96 111 109 108 126 125 122 127 124 123 118 99 77
Healy Import7823 9 5066367449367449 367449 36
Total Generation 482 821 1076 468 814 1063 472 825 1065 864 1573 2018 844 1520 1976
Total Spin 110 74 91 91 80 85 92 68 102 45 52 53 41 72 44
3rd Bradley
Lake, Nikiski
offline,
Cooper offline
Plant
ABCC1C2
Base Full Bradley
Output
3rd Bradley
Lake
3rd Bradley
Lake, Nikiski
offline
The Northcentral Railbelt analysis utilized generation dispatches of varying GVEA import levels
to determine the import limits for eight different Healy generation scenarios. The scenarios
consisted of different unit commitments for Healy #1, Healy #2, and Eva Creek generation and
are shown below in Table 3-4.
Table 3-4 Healy Generation Scenarios
1622624
26226
362 24
462
52624
626
724
8
Case Healy
#2
Healy
#1
Eva
Creek
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To vary the GVEA import level, Fairbanks generation at North Pole (including the combined
cycle unit) was reduced while generation in Anchorage (Southcentral power plant and / or Plant
2 expansion) was increased. The dispatches used for the Northcentral analysis are shown in
Table 3-5.
Table 3-5 Generation Dispatch (MW) for Northcentral Analysis
sv sp wp
sv sp wp
sv sp wp
sv sp wp
sv sp wp
sv sp wp
sv sp wp
sv sp wp
HC2 2 62 62 62 62 62 62 62 62 62 62 62 62
HC1 1 29 26 29 29 26 29 29 26 29 29 26 29
Eva Creek 1 24 24 24 24 24 24 24 24 24 24 24 24
NPOLESUB 1 xx
NPOLESUB2 xxxxxxxxxx
NPCC 13 xx xx xx xx xxxxxxxxxxx
NPCC 24 xx xx xx xx xxxxxxxxxxx
20 25 25 20 25 25 20 25 25 20 25 25 20 25 25 20 25 25 20 25 25 20 25 25
77 77 77 77 77 77 77 77
14 18 14 18 14 18 14 18 14 18 14 18 14 18 14 18
88 88 88 88 88 88 88 88
x
blank cells represent units offline
represents units dispatched as required
UAF Plant
Ft. WW Plant
Elsn Power
8
Chena Plant
4Bus Name Id
312 567
4 Pre-Watana: Study Methodology – Transmission Power Flow & Stability
System changes / additions were made to update the data based on projects that are expected
to be completed before the 2023 time frame, as well as to include proposed transmission and
generation additions for analysis. Generation dispatches were created to stress the regional
transmission facilities to identify system constraints and / or deficiencies. The planning criteria
(listed below) were used to develop preferred solutions in each region along with possible
alternatives to meet the criteria. These solutions were based on technical justifications as well
as cost analysis using the transfer limits determined by these studies.
4.1 Planning Criteria
The planning criteria for the Railbelt system includes desired operating parameters for both
during steady-state conditions as well as transient conditions. The planning criteria are divided
into four main areas; reliability, power flow, stability, and voltage, and are discussed in detail
below.
4.1.1 Reliability
The ultimate goal of any planning criteria is to provide the desired level of reliability at a cost the
system can afford. For islanded systems this level of reliability is often less than large
interconnected systems due to the evaluation of reliability against the costs required to obtain
the same level of reliability standards in the Lower 48.
Each of the Railbelt utilities has planned their individual systems to withstand N-1 contingencies
on their main transmission system without a loss of load. However, the interconnections
between the utility systems have been allowed to utilize single contingency transmission lines,
resulting in large scale loss of loads following the outage of the single interconnection. As a
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result, firm power transfer and capacity sharing among the utilities has been limited to the level
that the utilities can withstand following the loss of the single interconnection.
The Wilson BESS is utilized for spin and also for auto-scheduling to cover outages of major 138
kV lines and units in the GVEA system. It assumed that use of the BESS for auto-scheduling
will continue in the future system and will be increased to cover possible unit trips of Healy #2
and outages of the Healy – Gold Hill line.
The Railbelt Under-Frequency Load Shed (UFLS) settings are shown below in Table 4-1. The
UFLS system is an important part of the Railbelt system and is based on the largest operating
unit’s size and transmission line contingency. Although the UFLS system was designed to
operate in a much different generation system, the UFLS scheme was assumed unchanged for
these studies. Shedding (removing) load from the system allows the Railbelt system to
adequately respond to low frequency events due to multiple contingencies or other severe
outages and quickly restore frequency, preventing the system from collapsing.
Table 4-1 Railbelt Load Totals and UFLS settings
MW % MW % MW %
59.0 1 45.6 10% 73.5 9% 105.5 10%
58.7 2 38.7 9% 60.3 8% 86.3 8%
58.5 3 94.8 21% 167.7 21% 237.1 23%
58.2 4 39.3 9% 74.1 9% 104.4 10%
Frequency
(Hz)
UFLS
Stage
Summer Valley Summer Peak Winter Peak
The overarching goal of this Railbelt transmission planning study is to bring the utility
interconnections up to the same level of reliability that is maintained within each of the utility’s
individual systems. The system will be designed and evaluated such that no single contingency
results in the loss of firm power customers from the bulk transmission system to the extent that
such improvements are technically and economically feasible.
The means used to evaluate the individual components that are required to assess and develop
this level of reliability are outlined below.
4.1.2 Power Flow
The power flow criterion includes limits on voltage levels as well as branch flow levels for the
Railbelt during stead state conditions. The power flow criterion is listed below and was used for
normal (all equipment in service) and N-1 (single outage) contingency analysis:
Flows on transmission lines below their MVA rating (winter or summer)
Flows on transformers below their maximum MVA rating
The Railbelt system experiences large temperature swings between the winter and summer
seasons. These changes in temperature require the power flow analysis to use the appropriate
conductor rating for the specific temperature (load) season. Table A-2 Conductor Ratings in
the Appendix lists typical conductor ratings for different voltages. Table 4-2 shows the ratings for
some of the Railbelt line sections along with the rating reduction for the summer as compared to
the winter ratings.
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Table 4-2 Railbelt Ratings Example
From To kV size name Winter Summer
Dave's Creek Hope 115 556 Dove 173 96 45%
Douglas Stevens 138 2‐954 Rail (x2) 739 521 29%
Healy Gold Hill 138 556 Dove 267 188 30%
Healy Wilson 138 954 Cardinal 374 263 30%
Teeland Herning 115 556 Dove 173 96 45%
Plant 2 Fossil Creek 115 954 Rail 241 154 36%
Plant 2 University 230 954 Rail 483 309 36%
Pt. Mackenzie Teeland 230 795 Drake 439 240 45%
230 1900 Cable 310 281 9%
138 750 Cable 186 169 9%
Pt. Worenzoff Postmark 138 795 Arbutus 253 140 45%
138 Undersea Cable
Line Section Conductor Rating (MVA) Summer
Reduction (%)
230 Undersea Cable
It is assumed that short term thermal overloads are acceptable if planned remedial action
schemes (generation dispatch changes, non-firm energy contract reductions) are designed to
minimize and or eliminate the overload.
4.1.3 Stability
The transient stability criterion includes limits on the system frequency, voltage levels, system
response, and unit response. The transient criteria listed below will be used for N-1 contingency
analysis.
Sustained voltages on the transmission system buses must not be below 0.8 pu
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 / implemented to eliminate the possibility of an unstable
condition occurring.
4.1.4 Voltage
The criterion to be applied includes limits on the maximum and minimum voltages allowed on
the Railbelt system as well as operation limits of the generators and the SVC’s. The criterion is
listed below:
Voltages at 230 kV, 138kV 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
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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
High Voltage limits must be met with online generators operating at unity power factor
Voltage limits must be met with SVC’s operating with a minimum 5 MVAR of margin
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 / implemented to eliminate the possibility of an
unstable condition occurring.
4.2 Transmission System
The following transmission upgrades were assumed to be in place and operational in the
Railbelt system and have been added / verified in the Railbelt database for use in these studies.
HEA
New Sterling 115 kV substation
Rebuilt 69 kV loop between Soldotna – Beaver Tap – Marathon to 115 kV
New 115 kV line from Marathon to Nikiski
New Tesoro 115 kV substation
Expansion of Bernice 115 kV substation
ML&P
New Raptor 115 kV substation
Sub #14 Rebuild
Sub #15 Rebuild
New Sub #22 115 kV substation
New ITSS – Sub #22 115 kV tie
MEA
115 kV Teeland – Herning – Shaw – Lazell – Lucas lines upgraded to 556 ACSR
New EGS 115 kV substation
Rebuild of Hospital 115 kV substation
New Herning – Hospital 115 kV line
2 New Hospital – EGS 115 kV lines
CEA
New 115 kV substation at ITSS
New ITSS – Sub #22 115 kV tie
Maps were created of the initial transmission system used in these studies. This transmission
system is considered the “base” transmission system. Note that it was assumed that no
transmission upgrades are assumed for the 2020 time frame from Teeland north into the
Fairbanks system. Figure 4-1 shows the northern base transmission system. Figure 4-2 shows
the Southcentral and Kenai base transmission system.
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Figure 4-1 Northern Base Transmission System
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Figure 4-2 Southcentral and Kenai Base Transmission System
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5 Pre-Watana: Improvements to the Kenai – Anchorage Transmission
The transmission system between the Bradley Lake Hydro Plant and the Southcentral Railbelt
area consists primarily of single transmission lines. Energy exports from the Kenai are limited by
both thermal and stability constraints both into and out of the region. The existing 115 kV lines
between Bradley Lake and Soldotna are not rated to carry Bradley Lake’s full output without
incurring excessive losses. The Soldotna – Quartz Creek and Quartz Creek – Dave’s Creek
sections have thermal ratings of 96 MVA in the summer. The 2020 Kenai system has stability
limits from 52 – 101 MW depending on the specific Kenai generation unit commitment and
dispatch, as shown in Table 5-1. In addition to the changes in Kenai export limits, the losses
experienced on the Bradley Lake and Cooper Lake energy will approach more than 25% under
peak operating / energy transfer conditions. Plots for the simulation results for the
recommended system can be found in Appendix G.
Table 5-1 Kenai Export Stability Limits – Base System
CT ST #1 #2 #1 #2 SV SP WP
10‐22 max 45‐55 45‐55 10 10 82 84 71
20‐22 max 45‐55 45‐55 63 65 52
3 max max max 30‐38 30‐38 10 10 101 97 85
4 max max max 30‐40 30‐40 86 82 68
714‐43 28 50‐55 50‐55 10 10 92 84 75
814‐43 28 53‐55 53‐55 76 65 56
Soldotna Max output, SV & SP = 40 MW, WP = 49 MW
Nikiski CT Max output, SV = 39 MW, SP = 36 MW, WP = 43 MW
Nikiski ST Max output, SV = 16 MW, SP = 15 MW, WP = 18 MW
Dispatch
Generator Output (MW)Kenai Export
(MW)Nikiski Sold Bradley Lk Cooper Lk
The energy and capacity of Bradley Lake will be constrained during most of the year, with
increased losses and stranded capacity impacting the central and northern Railbelt utilities.
These constraints will also impact the efficiency of the hydro-thermal coordination and access to
spinning reserve by the northern utilities. The economic impact of these constraints is outlined in
detail in the Production Cost Simulation section of the report. Table A-3 and Table A-4 show
the historically displaced energy and stranded capacity.
5.1 Proposed 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 line between University and Dave’s
Creek to 230 kV. The Anchorage area stored energy projects include a 25 MW BESS in the
Anchorage area to provide stability and allow re-dispatching of Kenai and Anchorage area
generation if the HVDC tie fails during high Kenai exports. A new stored gas facility will allow
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gas scheduling to accommodate renewable energy and schedule changes due to transmission
outages.
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 2015 year transmission
system. The results are shown graphically in Figure 5-1. 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. Additional Kenai loss information can be found in Table A-5.
Figure 5-1 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.
Gas storage facilities are recommended in the Anchorage area to alleviate the bottlenecks
associated with gas delivery to the Anchorage area thermal projects. Although this project is
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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not directly an electrical transmission project, the flexible gas storage allows the Railbelt system
to be optimally dispatched to lower the costs, improves the reliability of the electrical system,
and decreases the costs of the Anchorage area BESS.
5.1.1 100 MW HVDC Intertie Beluga – Bernice Lake
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 138kV transmission line between
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 contemplated at the time, but found 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 which should make 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 outage 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 decreases in Kenai export losses and providing damping of inter area oscillations
between the Kenai and the rest of the Railbelt via the HVDC controls.
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 tie was outaged. The
HVDC line flow was then increased (assumed as step change) until the Anchorage area did not
load shed. 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
maximum of around 127 MW.
5.1.2 25 MW BESS – Anchorage Area
A BESS in the Anchorage area has been investigated in a previous study – both in connection
with the Fire Island Wind Farm and to cover the contingency loss of the University-Dave’s Creek
transmission line.
This project includes the installation of a 25 MW / 14 MWh Battery Energy Storage System
(BESS) in the Anchorage area. The exact characteristics of the BESS technology should be
evaluated in the design and procurement process of the BESS. The BESS should also be
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evaluated based on other possible future uses with the addition of the Watana large hydro
project. The capacity and energy requirements of the BESS are driven by the largest
transmission contingency or generation contingency as opposed to providing daily regulation for
variable generation.
The BESS is required to prevent load shedding and transmission overloads in the northern
system following the loss of the HVDC intertie. The BESS was sized to allow re-dispatch of the
Kenai and Anchorage area generation to prevent overloads of the Kenai transmission system
following a single-contingency outage.
5.1.3 2nd Bradley Lake – Soldotna line
The addition of the line allows for a large reduction in losses during high Bradley Lake output
conditions as well as eliminating the stability constraint for Bradley Lake following contingencies
on lines south of Soldotna.
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
existing AEA SVC bay. The line would utilize the same construction configuration and
conductor size as the existing Bradley – Soldotna transmission line.
5.1.4 Flexible Gas Storage – Anchorage Area
This project includes the installation of a 1.91 BCF (262 MWh) gas storage facility at an
Anchorage/Mat-Su area power plant. The facility includes storage tanks for compressed natural
gas, compressor, compressor building, and delivery system. The project would allow utilities to
utilize in-ground storage to serve changes in load/generation without incurring penalties from
the gas producers/transporters. The need for this project should be evaluated as more stringent
gas supply and delivery constraints are enacted in Southcentral Alaska.
5.1.5 Conversion University - Dave’s Creek Transmission Line to 230 kV
This project includes the conversion of 77 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.
5.1.6 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.
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A 10 MVAR fixed reactor would be required at the Dave’s Creek substation. The reactor would
allow 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 conjunction with the existing SVC
or if the existing SVC will require upgrading.
5.1.7 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 line should be reconductored to 954 ACSR “Rail” conductor.
5.2 Costs
A summary of the costs and benefits of the proposed projects to unconstrain the Bradley Lake
hydroelectric project were presented in Table 2-1 of the Pre-Watana Executive Summary.
Further cost analysis for the Kenai transmission is shown in section A.4 of the Appendix.
5.3 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.
5.3.1 Reconductoring Soldotna – Diamond Ridge 115 kV line
A project to reconstruct the 115 kV Diamond Ridge – Soldotna transmission line was evaluated
against the construction of a new 115 kV Bradley Lake – Soldotna transmission line. The 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 section is the preferred
alternative.
5.3.2 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 against 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.
5.3.3 AC Bernice – Anchorage Southern Intertie
A project to add the Southern Intertie between Bernice and Pt. Woronzof was evaluated against
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 intertie would incur
higher costs due to the need for reactive support for the charging current for the cables.
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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 (including switching surges encountered during energizing/de-energization of the cables
and reactors, the possibility of subsynchronous resonance, and the 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.
5.3.4 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.
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 storage 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.
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6 Pre-Watana: Improvements to the Southcentral Transmission
The existing 115 kV transmission system from Briggs Tap to Eklutna consists of a double circuit
115 kV transmission line, with only one energized. Currently there is no room at the Eklutna or
Briggs Tap substations to connect the second line. The single 115 kV connection between MEA
and AML&P (via Briggs Tap) limits the reliability of transfers between the two areas and results
in outages to a significant number of MEA customers as well as isolation of critical ML&P
generation from the ML&P system. A switching station in the Briggs/Fossil area and a new
substation at the Eklutna Hydro Plant will allow energization of the “express” line between
Eklutna and Anchorage. The express line will increase reliability of the MEA system serving
Eagle River and Chugiak and provide a black start-source for the ML&P system.
The single 230kV transmission line between Pt. McKenzie and Teeland is presently the weakest
link in the Southcentral transmission system. Its loss curtails power transfers to the
Matanuska/Susitna Valley as well as to the Northern Intertie. The transmission line is the
primary interconnection to the Anchorage-Fairbanks Intertie. The line increases the single-
contingency outage to the Fairbanks area by 26 miles. Elimination of the single contingency
service from Pt. McKenzie to Teeland increases the reliability of the Anchorage-Fairbanks
Intertie and increases the stability limit between the two systems.
The displacement of Beluga generation with new generation at Southcentral Power Plant, Plant
2A, Nikiski / Soldotna, and EGS, results in many parts of the transmission system unloaded
during light load conditions. The 138 kV and 230 kV undersea cables as well as other parts of
the transmission system will exhibit high voltages during these conditions, especially at the
terminals of the 230 kV undersea cable. These high voltages require reactive compensation on
the transmission system to reduce voltages down to acceptable levels.
6.1 Proposed Improvement Projects
The proposed improvements for the Southcentral transmission system are new substations at
Eklutna and Fossil Creek to allow the existing express line to be energized; a new station at
Lake Lorraine, expansion of the Douglas Station and the construction of new Lorraine –
Douglas transmission lines to eliminate the single contingency transmission line between
Douglas and the Southcentral system.
6.1.1 Eklutna 115kV Substation
This project includes the construction of a new 115 kV substation at Eklutna. 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.
6.1.2 Fossil Creek 115 kV Substation
This project includes the construction of a 115 kV substation near the existing Briggs Tap/Fossil
Creek on the Eklutna – ML&P transmission line. The projects includes the construction of a 115
kV substation to interconnect the Eklutna Express circuit, the Eklutna local circuit, the Briggs
Tap circuit and the ML&P express circuit with provisions for future 230/115 kV transformers and
Raptor substation interconnections.
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The substation would allow a second transmission path between the AML&P and MEA
transmission systems and increase the critical clearing time for transmission lines in the AML&P
and MEA systems.
6.1.3 Lake Lorraine Station
This project includes the construction of a 230 kV substation, near the junction of Chugach’s
230 kV West Terminal and its Teeland transmission line 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, 2 – 230 kV lines
to Pt. Mackenzie, one to Teeland, one to Plant 2, and two for a future 230 kV double circuit line
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 will also be constructed at Lake Lorraine to control voltages on the
Railbelt system. The proposed substation location is near one end of the undersea 230 kV
cable, maximizing the effect of the reactive compensation.
The addition of the Lake Lorraine 230 kV substation eliminates 26 miles of single contingency
230 kV line from Pt. Mackenzie to Teeland and an additional 26 miles of single contingency
from Teeland to Douglas and provides a connection point for transmission line additions to
Douglas substation.
6.1.4 Douglas Station Expansion
This project includes the construction of the 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 for two 230 kV / 138 kV power transformers, two 230kV
transmission line terminations (Lorraine to Douglas), two 138 kV transmission lines (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).
6.1.5 Lake Lorraine – Douglas 230 kV Transmission Lines
This project includes the construction of a 42-mile, 230 kV double circuit transmission line from
Lake Lorraine substation to Douglas Substation. The transmission line addition eliminates 50
miles of single contingency 230 kV/138kV line to Fairbanks on the Alaska Intertie. The line will
be constructed as a single tower, double-circuit transmission line utilizing construction similar to
the Eklutna-Fossil Creek line (double circuit, bundled 954 ACSR “Rail” conductor).
6.2 Costs
A summary of the costs and benefits of the proposed projects for the Southcentral Railbelt were
presented in Table 2-5 of the Pre-Watana Executive Summary. Further cost analysis for the
Southcentral transmission is shown in section A.6 of the Appendix.
6.3 Alternatives and Sensitivity
No alternatives or sensitivities were analyzed.
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7 Pre-Watana: Improvements to the Northern Railbelt Transmission
Anchorage exports to the GVEA system mainly flow through a single 230 kV transmission line
from Pt. Mackenzie to Teeland, then a single 138 kV line from Teeland to Healy. An outage of
the 26 mile 230 kV line severely reduces the energy export capability of Anchorage, forcing
exports to flow through the MEA system. Historically, fault and trips of these line sections
represent the worst contingencies on the Railbelt system.
The single 195 mile, 138 kV line that connects Teeland to Healy limits the ability for GVEA to
contract for firm energy sales due to possible outages of the line that would island GVEA from
the rest of the Railbelt. This single transmission line also limits transfer levels between areas
due both stability limits and single contingency outages. The Healy transfer limits are shown in
Table 7-1. Note that the transfer levels are dependent upon the generation dispatch of the Healy
Plant 2 (Healy #2), the existing Healy plant (Healy #1), and the Eva Creek wind farm.
The summer valley season exhibits no stability limit due to the low load levels in the Fairbanks
area until Healy / Eva Creek generation is reduced below 30 MW. When Healy generation is
reduced, the maximum transfer limits out of Douglas substation is between 57 – 61 MW. The
summer peak cases have a maximum transfer limit of ranging from 58 – 79 MW. The winter
peak cases have a maximum transfer limit from 68-74 MW.
Table 7-1 Healy Stability Limits – Base System
#2 #1 Eva Export Export Export
16226‐29 24 ‐48958 148 68 157
26226‐29 ‐21 89 74 138 73 138
362‐24 22 89 79 141 74 137
462‐‐48 89 79 117 74 112
5 ‐26‐29 24 47 89 74 112 68 107
6 ‐26‐29 ‐61 78 74 88 68 83
7 ‐‐24 57 73 79 91 68 82
8 ‐‐‐62 53 79 68 68 57
Fairbanks at Minimum, no stability limit
Dispatch Healy Summer Valley Summer Peak Winter Peak
Douglas
Export
Healy Douglas
Export
Healy Douglas
Export
Healy
7.1 Proposed Improvement Projects
It is proposed to add transmission infrastructure from the recommended Lorraine substation to
Healy. The result would be a path of two effective circuits of bundled 954 ACSR “Rail” conductor
for 194 miles from Lorraine to Healy. The proposed transmission improvements greatly increase
the reliability of GVEA imports due to new transmission lines that offer parallel paths for energy
to be transferred into the GVEA system from Anchorage.
The addition of the second 138 kV line between Healy and Douglas and the Lorraine 230 kV
substation (including SVC) with 230 kV dual circuit transmission lines to Douglas increase the
Healy transfer limits by different amounts depending on the generation dispatch at Healy, shown
in Table 7-2. One significant difference between the limits in the proposed system compared to
the existing system is the change in power exports from “economy” to firm transfers. In the
present system all transfers are economy and can be interrupted by either the seller or any
number of single contingency transmission paths between the seller and Healy. The proposed
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system provides for firm power sales and purchases, allowing energy transfers north or south
up to the specified limits without interruption for single-contingency events. The firm
transmission system would also allow for sharing of firm capacity between the northern and
southern systems.
The transmission upgrades allow for unconstrained Healy operation while allowing for GVEA
owned Fairbanks generation to be taken off-line for the summer valley cases.
The summer peak cases allow for transfers of up to 173 MW of firm power from Douglas to the
north. The maximum transfer levels (due to stability constraints) are not impacted by changes in
Healy generation. GVEA is able to remove all of its Fairbanks generation for all Healy
generation dispatches.
The winter peak cases allow for transfers of up to 197 MW of firm energy from Douglas to the
north. The maximum transfer levels (due to stability constraints) are not impacted by changes in
Healy generation. GVEA is able to remove most of its Fairbanks generation for many of the
different Healy generation dispatches.
As Healy/Eva Creek generation is increased, the limiting contingency becomes a fault and trip
of the Pt. Mackenzie – Lorraine 230 kV line instead of being limited by the amount of load the
energy is available to serve.
Table 7-2 Healy Stability Limits – Proposed Upgrades
#2 #1 Eva Export Export Export
1 622924 ‐4 89 67 158 127 216
26229‐21 89 92 158 153 216
362‐24 22 89 94 158 155 216
4 62 ‐‐48 89 119 158 181 216
5 ‐29 24 47 89 119 158 181 216
6 ‐29 ‐72 89 145 158 168 179
7 ‐‐24 73 89 147 158 173 183
8 ‐‐‐99 89 173 158 197 144
Anchorage 230 kV Line Outages
Douglas
Export
Healy Healy Douglas
Export
Healy
Fairbanks at Minimum, no stability limit
Dispatch Healy Summer Valley Summer Peak Winter Peak
Douglas
Export
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 7-1 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 that stability limits of the
system and therefore is not a recommended nor is a realistic operating point.
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Figure 7-1 Anchorage – Healy Loss Analysis: Base vs. Proposed
0
2
4
6
8
10
12
14
0 102030405060708090100110Line Losses (MW)Flow on Cantwell ‐Stevens Line Section (MW)
Loss Analysis: Anchorage to Healy
Base vs Proposed Transmission Configuration
Base
Proposed
7.1.1 Lake Lorraine Station
As discussed in 6.1.3 Lake Lorraine Station, this project includes the construction of a 230 kV
substation, in the vicinity of Lake Lorraine. A -40/+25 MVAr SVC will also be constructed at
Lake Lorraine to control voltages on the Railbelt system.
The addition of the Lake Lorraine 230 kV substation eliminates 26 miles of single contingency
230 kV line from Pt. Mackenzie to Teeland and provides a connection point for transmission line
additions to Douglas substation
7.1.2 Douglas Station Expansion
As discussed in 6.1.4 Douglas Station Expansion, this project includes the construction of the
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.
7.1.3 Lake Lorraine – Douglas 230 kV Transmission Lines
As discussed in 6.1.5 Lake Lorraine – Douglas 230 kV Transmission Lines, this project includes
the construction of a 42-mile, 230 kV double circuit transmission line from Lake Lorraine
substation to Douglas Substation. The transmission line addition eliminates 50 miles of single
contingency 230 kV/138kV line to Fairbanks on the Alaska Intertie.
This transmission line and the above mentioned substation additions (Lake Lorraine / Douglas
expansion) will allow large and reliable energy transfers from Anchorage to Fairbanks, as well
as the possible energy transfers associated with future large hydro projects. The addition of this
line completes a corridor of needed transmission infrastructure between the Lake Lorraine
substation in Anchorage and the Healy substation near Fairbanks (including the proposed 2nd
Douglas - Healy line).
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7.1.4 Gold Creek Station
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 Anchorage – Healy transmission lines and will include 4 line terminals and two reactors.
Provisions for 3 additional line terminals could allow the future connection to the Watana Hydro
Project.
The addition of the Gold Creek substation will reduce the reactive support requirement by more
than 50% compared to locating support at Douglas and / or Healy. The station also improves
the stability and sectionalizing by dividing the Douglas to Healy 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.
7.1.5 Healy Station
This project includes the construction of a 230 kV (operated at 138 kV to Gold Creek) substation
near Healy, Alaska on the Alaska Intertie. The station will allow the termination of an additional
line from Gold Creek into the Healy Plant. The station will be constructed for future operation at
230 kV to Gold Creek should a future large hydro project come on-line. The station will include
terminations for two 230 kV (operated at 138 kV) lines to Gold Creek, 230 kV lines to GVEA’s
Wilson Substation and GVEA’s Gold Hill Substation, and a line to the existing Healy plant.
7.1.6 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, connecting 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
conductor to minimize losses and match the characteristics of the existing line. The line will
terminate at the Douglas, Gold Creek, and Healy stations.
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.
7.1.7 Communication Infrastructure
This project includes the development and installation of communication infrastructure between
the Teeland, Lorraine, Douglas, Gold Creek and Healy sub-stations. The communications will
be used for high-speed protective relaying communications between control areas and for
control and monitoring of the substation equipment.
7.2 Costs
A summary of the costs and benefits of the proposed projects to provide reliability and economic
energy transfers between the northern and southern systems was presented in of the Pre-
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Watana Executive Summary. Further cost analysis for the Northcentral transmission is shown in
section A.7 of the Appendix.
7.3 Sensitivities
Sensitivity analysis was completed to determine the impact that changes in generation dispatch
and possible transfer trip of load during contingencies would have on the GVEA import limits.
7.3.1 Eva Creek Analysis
Analysis of the base transmission system was completed with the Eva Creek wind farm to
determine the impact of Eva Creek find farm status on the GVEA import limits with the lines
from Healy into Fairbanks not upgraded to 230 kV. The wind farm was analyzed at minimal
output and with the wind farm offline. The results of this analysis are shown in Table 7-3. When
Eva Creek is online but at minimal output (2 MW), the GVEA import limits are increased 3-4 MW
for the summer peak cases, with no change in the limits for the winter peak cases as compared
with Eva Creek offline.
Table 7-3 Eva Creek Analysis
HC2 HC1 Eva Export Export SP WP
2e 62 29 2 79 143 73 138
26229‐74 138 73 138
4e 62 ‐2 84 122 74 112
462‐‐79 117 74 112
50
50
Dispatch Healy Summer Peak Winter Peak Douglas
Export Douglas
Export
Healy Douglas
Export
Healy
7.3.2 Zehnder Dispatch Analysis
The addition of the transmission upgrades between Anchorage and Healy could allow for
changes in GVEA system dispatch to allow for the light inertial LM6000 at North Pole to be
displaced by the two Frame 5 units at Zehnder during the summer peak load season. The
results of this analysis are shown in Table 7-4. Displacing North Pole generation with the
Zehnder frame 5 units results in increased import limits of 5 – 18 MW with North Pole unit #3
online. The unit commitment change also allows for a total of 5 generation dispatches (increase
from 2) that allow for unconstrained Healy import levels.
Table 7-4 North Pole LM6000 vs. Zehnder Frame 5 Analysis
HC2 HC1 Eva Export Export
1 62 29 24 73 162 73 162 ‐
26229‐84 148 102 162 18
362‐24 100 162 100 162 ‐
462‐‐113 150 118 155 5
5 ‐29 24 113 151 123 162 10
6 ‐29 ‐128 141 135 146 7
7 ‐‐24 133 145 151 162 18
8 ‐‐‐138 125 153 140 15
Fairbanks at Minimum, no stability limit
Dispatch Healy Summer Peak Summer Peak Douglas
Export
Increase
Douglas
Export
Healy Douglas
Export
Healy
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The difference in transfer limits between the North Pole unit 3 and the Zehnder units is due to
light inertia associated with the LM6000 unit at North Pole. A comparison of the inertia of the
LM6000 with the frame 5 and frame 7 units is shown below in Table 7-5. While the light inertia
of the LM6000 allows the unit to respond quickly during low frequency events, fault conditions
can result in the unit accelerating and going out of step with the rest of the system.
Table 7-5 GVEA Unit Inertia Analysis
H ‐ Inertia
Name ID Type
Zehnder 1 Frame 5 20.6 9.0
N. Pole 1 Frame 7 71.9 7.8
N. Pole CC 3 LM6000 60.0 2.2
Unit Mbase
(MVA) MW‐s / MVA
7.3.3 Load Transfer Trip Analysis
The winter peak load season transfer limits do not allow for complete displacement of North
Pole unit 3 generation without upgrading the transmission system between Healy and Fairbanks
to 230 kV. This results in the North Pole unit remaining online with the two Zehnder units at
maximum output. Analysis of the stability results shows that during maximum Healy generation
conditions and maximum Douglas transfers, a low voltage swing occurs for fault and trips of the
transmission lines from Healy to Fairbanks. The low voltage condition (approximately 1 second
long) results in the protection system blocking the BESS, negating any benefits of the auto –
scheduling capability quickly reducing transfers into the GVEA system.
Another method of reducing transfers into the GVEA system quickly is to transfer trip load for
contingencies from Lorraine substation north to the Wilson / Gold Hill substations. Analysis of 20
and 40 MW trip settings was completed for the winter peak cases. It was assumed that the load
would be shed 5 cycles after clearing of the fault (10 cycles after start of fault). The results of the
analysis are shown below in Table 7-6. The results are for a transmission system configuration
with two lines from Healy to Douglas operated at 138 kV and the lines north of Healy not
upgraded.
Table 7-6 Load Transfer Trip Analysis – Winter Peak System
HC2 HC1 Eva Export Export Export 20 MW 40 MW
1 62 29 24 77 167 97 186 107 196 20 30
26229‐97 162 102 167 134 197 5 37
362‐24 107 170 128 190 134 195 21 27
4 62 ‐‐123 161 133 170 154 190 10 31
5 ‐29 24 123 161 133 171 133 171 10 10
6 ‐29 ‐118 132 118 132 118 132 0 0
7 ‐‐24 123 136 123 136 123 136 0 0
8 ‐‐‐128 116 128 116 128 116 0 0
Douglas Export
Increase
no change in results, limiting contingency is Lorraine ‐ Plant 2, or Lorraine ‐ Pt. Mack
Dispatch Healy 2nd Healy ‐ Douglas 20 MW Trip 40 MW Trip
Douglas
Export
Healy Douglas
Export
Healy Douglas
Export
Healy
The results of the transfer trip analysis show that increases in transfer capability occur for
generation scenarios with high levels of Healy output. A 20 MW trip of load results in increases
of the Douglas transfer limits by 5 – 21 MW. A 40 MW trip of load results in increases of 10-37
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MW. As Healy output is decreased the effect of transfer tripping load is mitigated due to the
limiting contingency changing from fault and trips of lines in Fairbanks to fault and trips of the
230 kV system south of the proposed Lorraine substation.
7.3.4 Healy – Fairbanks Transmission Line Upgrades
Analysis of two different transmission upgrades between the Healy and Fairbanks locations
were analyzed. The two transmission upgrades are adding 1) 3rd 138 kV line between Healy and
Fairbanks and 2) upgrading and operating the 2 138 kV lines at 230 kV. The 3rd 138 kV line
would be of similar construction and distance as the current Healy – Wilson 138 kV transmission
line. The 230 kV upgrade includes rebuilding the Healy to Gold Hill line utilizing 230 kV
construction and 954 “Rail” conductor. The Healy – Wilson line is already built to 230 kV
standards. Transfer analysis was completed with the different transmission upgrades to
determine the new transfer limit for the summer peak and winter peak cases. The results are
shown in Table 7-7 and Table 7-8, respectively. Note that the analysis assumes the second line
between Douglas and Healy has been installed and is operated at 138 kV.
Table 7-7 Healy – Fairbanks Transmission Upgrades – Summer Peak
HC2 HC1 Eva Export Export Export
1 62 29 24 73 162 69 160 67 158
26229‐102 162 94 160 92 158
362‐24 100 162 96 160 94 158
4 62 ‐‐100 162 121 160 119 158
5 ‐29 24 123 162 121 160 119 158
6 ‐29 ‐135 146 147 160 145 158
7 ‐‐24 151 162 148 160 147 158
8 ‐‐‐153 140 175 160 173 158
Fairbanks at Minimum, no stability limit
Healy Douglas
Export
Healy Dispatch Healy Base Fairbanks 3rd 138 kV line 230 kV Conversion
Douglas
Export
Healy Douglas
Export
Table 7-8 Healy – Fairbanks Transmission Upgrades – Winter Peak
HC2 HC1 Eva Export Export Export
1 62 29 24 77 167 131 219 127 216
26229‐97 162 157 219 153 216
362‐24 107 170 159 219 155 216
4 62 ‐‐123 161 175 209 181 216
5 ‐29 24 123 161 150 187 181 216
6 ‐29 ‐118 132 131 144 168 179
7 ‐‐24 123 136 171 181 173 183
8 ‐‐‐128 116 152 138 197 144
Fairbanks at Minimum, no stability limit
Healy Douglas
Export
Healy Dispatch Healy Base Fairbanks 3rd 138 kV line 230 kV Conversion
Douglas
Export
Healy Douglas
Export
The summer peak results show that additional transmission upgrades between Healy and
Fairbanks allow for unconstrained Healy generation and the Fairbanks ability to import all
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energy required to serve GVEA loads for many Healy generation dispatches. For the summer
peak cases, the additional 138 kV line has the same results as the 230 kV transmission
upgrades.
The winter peak cases show that the 230 kV transmission upgrades result in higher transfer
limits (127-197 MW) than the additional 138 kV line between Healy and Fairbanks (131 – 175
MW). The 230 kV transmission upgrades also allow for more Healy generation dispatches with
GVEA generation in Fairbanks able to be turned offline.
Load transfer trip analysis was completed for the two different transmission upgrades between
Healy and Fairbanks. The results for the 3rd 138 kV line and the 230 kV upgrade are shown
below in Table 7-9 and Table 7-10, respectively.
Table 7-9 Load Transfer Trip Analysis – 3rd 138 kV Line – Winter Peak
HC2 HC1 Eva Export Export
1 62 29 24 131 219 131 219
26229‐157 219 157 219
362‐24 159 219 159 219
462‐‐175 209 175 209
5 ‐29 24 150 187 185 219
6 ‐29 ‐131 144 131 144
7 ‐‐24 171 181 171 181
8 ‐‐‐152 138 152 138
no change in results, limiting contingency is Lorraine ‐
Plant 2, or Lorraine ‐ Pt. Mack
Fairbanks at Minimum, no stability limit
Dispatch Healy 3rd 138 kV Line 20 MW Trip
Douglas
Export
Healy Douglas
Export
Healy
The load transfer trip analysis shows that only for dispatch case 5, does the trip of load increase
the transfer limits. The other cases do not have an increase in transfer limits due to the limiting
contingency being a fault and trip of the Lorraine – Plant 2 or the Lorraine – Pt. Mack 230 kV
transmission lines.
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Table 7-10 Load Transfer Trip Analysis – 230 kV Upgrade – Winter Peak
HC2 HC1 Eva Export Export Export
1 62 29 24 127 216 127 216 127 216
26229‐153 216 153 216 153 216
362‐24 155 216 155 216 155 216
462‐‐181 216 181 216 181 216
5 ‐29 24 181 216 181 216 181 216
6 ‐29 ‐168 179 173 183 178 187
7 ‐‐24 173 183 173 183 173 183
8 ‐‐‐197 144 197 144 197 144
Fairbanks at Minimum, no stability limit
no change in results, limiting contingency is Lorraine ‐ Plant 2, or Lorraine ‐
Pt. Mack
Dispatch Healy 230 kV Upgrade 20 MW Trip 40 MW Trip
Douglas
Export
Healy Douglas
Export
Healy Douglas
Export
Healy
The analysis shows that when upgrading the lines between Healy and Fairbanks, the load
transfer trip does not increase the transfer limits except for case 6. This is due to the limiting
contingency being a fault and trip of the Lorraine – Plant 2 or the Lorraine – Pt. Mack 230 kV
transmission lines.
Upgrading of the 138 kV lines from Healy north to Gold Hill and Wilson result in significant
increases in transfer limits from Anchorage to the GVEA system in Healy and Fairbanks and
allow for GVEA to serve its load from only Healy generation and imports for many of the Healy
generation dispatches.
7.4 Alternatives
Strengthening the transmission tie between Douglas and Healy can only be accomplished by
adding a second transmission line between these substations. Several options have previously
been investigated to increase the energy transfers between the Anchorage area and Douglas.
The installation of a new substation near Lake Lorraine and constructing new transmission lines
between this station and Douglas has been found to be the most economical solution.
Operation of the Healy – Douglas tie at 230kV and upgrading lines north of Healy has been
investigated below.
7.4.1 Healy – Douglas 138 kV operation at 230 kV
This project includes operating the two lines (one existing, one proposed) from Douglas – Gold
Creek – Healy at 230 kV instead of 138 kV. Operating the lines at 230 kV results in significant
reactive support requirements while providing minimal additional increases in Healy transfer
limits. This is due to transfer constraints from the Healy – Gold Hill and Healy – Wilson 138 kV
line sections (assuming the lines are not operated and / or upgraded to 230 kV).
Based on the expected Healy import levels, it is recommended that if a second line is built
between Healy and Douglas that it is constructed to 230 kV but operated at 138 kV to reduce
the added reactor expense until such a time that energy flows over the tie support the operation
at 230 kV.
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8 Pre-Watana: Economic Benefit Analysis
The economic benefit of the proposed transmission projects can be classified as production cost
benefits and other benefits which include; Capacity Deferral, Reservoir Management, Unserved
Energy, Excess Energy. All estimates in this simplified analysis were based on one years’
worth of production cost benefits analysis and assuming these benefits remain constant
throughout the 50-year life of the project. This is thought to be a conservative assumption since
unit retirements and capacity replacement in the future was not considered in the benefit
analysis, nor were the economic benefits of central plant construction that are possible with an
integrated transmission system.
8.1 Production Cost Benefits
Slater Consulting was asked to examine the impacts of the proposed transmission upgrades on
the Railbelt system production costs.
Slater’s work only examined system production costs, that is, the sum of fuel costs and variable
Operation & Maintenance cost, (V O&M.) No assessment of possible savings in capital costs
for deferment of future generation additions or refurbishments, fixed O&M costs of plants retired
or not added, nor of the benefits to customers of improved system reliability.
The study was performed for the year 2020. All transmission additions and changes currently
planned to be completed by that time have been included. All generation additions and
retirements currently committed or anticipated are included, as are all forecast changes in
system loads.
The objective of the various analyses carried out in this study was to determine the level of
production cost savings that can be realized if all of the transmission upgrades proposed by
EPS are carried out, and to explore the amount of these savings that can be attributed to each
of the individual upgrades. To ensure that these savings are not exaggerated, conservative
assumptions were made where such choices were available.
8.1.1 Software Employed
The software employed in this study was PROMOD IV®. Within that program, there are several
different production simulation algorithms available. Previously, for the Susitna-Watana study,
we had used the Analytical Probabilistic Dispatch algorithm, because of its facility to optimally
allocate an annual resource, Watana water, over the months of the year, respecting the various
inflows, storage constraints, and monthly production cost determinants. For this study, we
used the Hourly Monte Carlo / Transmission Analysis methodology, because of its ability to
represent, within its economic commitment and dispatch modeling, the transmission system on
an individual bus and branch basis in a DC loadflow representation.
This transmission modeling includes the bus-by-bus distribution of generation and load and
allows for the monitoring and respecting of thermal, stability and other operating limits and the
calculation of transmission losses.
8.1.2 Data and Information Sources
The starting point of the company generation and load data was the data used in the 2012
Susitna-Watana studies, as modified by consultations with utility personnel.
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Further modifications and clarifications were provided as interim results were viewed and
discussed. Company specific hourly deterministic dispatch results proved to be very useful for
this purpose.
Obviously, fuel prices have a significant impact on the results of this analysis. To maintain
conservatism, the gas price forecast was one of the Susitna-Watana scenarios, which started at
a 2012 Anchorage area price of $6.50/mmBTU, and escalated at 4% per year. The prices for
other fuels began with actual 2012 prices, and escalated in keeping with the DOE Energy
Information Administration’s Annual Energy Outlook.
The detailed transmission data was obtained from two power flow outputs provided by EPS Inc.,
one for the system with no transmission upgrades, and the second with all upgrades.
Transmission upgrade scenarios that included just some of the upgrades were created within
PROMOD by starting with one of the original power flow representations and replacing certain
elements with appropriate elements from the other power flow.
Stability and interface flow limits, as determined from EPS’s studies were provided for each
transmission upgrade scenario to be examined.
8.1.3 Transmission Upgrades Examined
The upgrades to be examined were grouped into those in the Railbelt system south of the
Anchorage area to Seward and the Kenai peninsula, and those in the Railbelt system north of
the Anchorage area and up to Fairbanks.
The specific southern upgrades are as follows.
Increasing the capability of the AC system from Quartz Creek to University by adding
additional conductor to the Quartz Creek to Dave’s Creek line, and by converting the
lines and substations connecting Dave’s Creek to University to 230 kV operation.
Adding a 100 MW DC tie from Bernice to Beluga.
Adding an appropriately sized BESS in the Anchorage area.
Adding a second direct line from Bradley Lake to Soldotna.
The specific northern changes are as follows, all resulting in N-1 transfer capabilities between
the noted terminals.
A 230 kV upgrade connecting Lake Lorraine to Douglas.
Douglas to Healy upgrade.
Healy to Fairbanks 230 kV
To calculate the production cost savings for these transmission upgrades as a group and to
estimate the savings due to each individual upgrade project, nine production cases were
developed and modeled. During the development of these cases, other cases were run, but
these nine cases were chosen because it was judged that each best represented the way the
system would be run given that particular transmission configuration, and assuming that
operation at N-1 reliability is desired. It is worth noting at this point that the Railbelt system is
not presently operated at N-1 reliability, but to ensure “apples v apples” comparisons among the
cases that were evaluated, they all assumed operation as close to N-1 reliability as practical and
reasonable.
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8.1.4 Case NS0
This case includes all of the northern and southern upgrades listed above. Because all
important transmission interfaces have substantial firm (that is N-1) flow limits, the Railbelt
system is committed and dispatched as a single pool, with the objective of minimizing total
system production costs. In this case, the only transmission interface which has a limit which
affects the system commitment and dispatch is the Kenai-North interface, where the limit of 125
MW is supported by a 25 MW BESS in the Anchorage area. Bradley is modeled as 2 x 45 MW
generating units and 27 MW of spinning reserve capability. The worst contingency is the loss of
the AC circuit from the Kenai to University Substation, while the interface is carrying 125 MW. If
this occurred, the 25 MW BESS and the DC line would have to provide the 125 MW inflow to the
Anchorage area until just one CT unit is successfully started.
8.1.5 Case S1
This case includes all of the northern and southern upgrades listed above, except the upgrading
of the AC circuits from Quartz Creek to University. Because all important transmission
interfaces have firm (that is N-1) flow limits, the Railbelt system is committed and dispatched as
a single pool, with the objective of minimizing total system production costs. In this case, the
only transmission interface which has a limit which affects the system commitment and dispatch
is the Kenai-North interface, where the limit of 100 MW is supported by a 25 MW BESS in the
Anchorage area. Bradley is modeled as 2 x 45 MW generating units and 27 MW of spinning
reserve capability. The worst contingency is the loss of the DC circuit from the Bernice to
Beluga, while the interface is carrying 100 MW. If this occurred, the 25 MW BESS and the
existing AC circuit, which has a capability of 75MW would have to provide the 100 MW inflow to
the Anchorage area until just one CT unit was successfully started.
8.1.6 Case S2
This case includes all of the northern and southern upgrades listed above, except the
installation of the DC line between Bernice and Beluga. Because all important transmission
interfaces have firm (that is N-1) flow limits, the Railbelt system is committed and dispatched as
a single pool, with the objective of minimizing total system production costs. In this case, the
only transmission interface which has a limit which affects the system commitment and dispatch
is the Kenai-North interface, where the limit of 75 MW is supported by a 75 MW BESS in the
Anchorage area. Bradley is modeled as 2 x 45 MW generating units and 27 MW of spinning
reserve capability. The worst contingency is the loss of the AC circuit from the Kenai to
University, while the interface is carrying 75 MW. If this occurred, the 75 MW BESS would have
to provide up to its 75 MW capability until three CT units were successfully started. Even
though this system configuration could be operated as N-1 reliable, it obviously does not provide
the same reliability as Case S1
8.1.7 Case S3
This case includes all of the northern upgrades listed above, but in the south, the only upgrade
is the second direct line from Bradley Lake to Soldotna. Because the Kenai North transmission
interface, now has a 0 MW firm flow limit, the Railbelt system cannot be committed and
dispatched as a single pool. Instead, it is operated as two pools, one with just HEA and the
other with the remaining five utilities. The non-firm Kenai North flow limit is 75 MW, modified by
the presence of Nikiski and Cooper generation. Reservations are made against this limit to
accommodate the shares of the Bradley spinning reserve capability belonging to the utilities
north of the interface and to accommodate the HEA share of system spinning reserve.
Commitment price hurdles are in place between HEA and each of the other utilities to ensure
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that HEA commits its own generation to serve its own needs and only its own needs, while
dispatch hurdles are in place to restrict non-firm transactions to those with high profit margins.
8.1.8 Case S4
This case includes all of the northern upgrades listed above, but no southern upgrades. The
only difference between this case and Case S3 is that without the second direct line from
Bradley to Soldotna, the Stability limit for Bradley Lake generation is only 100 MW. To
accommodate this, Bradley Lake is modeled as 2x45 MW units and 10 MW of spinning reserve
capability.
8.1.9 Cases N1 – N3
These cases include all of the Southern upgrades listed above. In these cases, the Kenai-North
interface, has a 125 MW limit that is supported by a 25 MW BESS in the Anchorage area.
Bradley is modeled as 2 x 45 MW generating units and 27 MW of spinning reserve capability.
8.1.10 Case N1
This case includes the upgrades from Lake Lorraine to Douglas and Douglas to Healy, but
excludes the upgrade from Healy to Fairbanks, leaving the Fairbanks area vulnerable. To
provide a measure of protection for Fairbanks during the winter, it was assumed that the North
Pole CC would be a must run unit from October through March.
8.1.11 Case N2
The only northern project included in this case is the upgrade from Lake Lorraine to Douglas.
Without a firm connection north into Healy, the Railbelt system cannot be run as a single pool.
Instead, it is run as two pools. One pool is GVEA, while the second is the other five utilities.
Connecting the two pools is a non-firm tie with a 75 MW limit.
Commitment price hurdles are in place between GVEA and each of the other utilities to ensure
that GVEA commits its own generation to serve its own needs and only its own needs, while
dispatch hurdles are in place to restrict non-firm transactions to those with high profit margins.
8.1.12 Case N3
This case has no northern upgrades. Without a firm connection north into Healy, the Railbelt
system cannot be run as a single pool. Instead, it is run as two pools. One pool is GVEA, while
the second is the other five utilities. Connecting the two pools is a non-firm tie with a 75 MW
limit.
Commitment price hurdles are in place between GVEA and each of the other utilities to ensure
that GVEA commits its own generation to serve its own needs and only its own needs, while
dispatch hurdles are in place to restrict non-firm transactions to those with high profit margins.
8.1.13 Case NS4
This case has none of the northern or southern upgrades listed above. It is essentially the
same transmission system as exists today, except that the transmission connecting MEA’s
Eklutna diesels to the system is reorganized, and a couple of planned transmission lines serving
load in the central part of the system are included. None of these additions materially affects
the system dispatch or production cost.
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In this case, the Railbelt system operates as five separate companies, each providing for its
own needs. This is accomplished by placing Commitment price hurdles between each pair of
companies to ensure that each commits its own generation to serve its own needs and only its
own needs. Dispatch hurdles are also in place between each pair of companies to restrict non-
firm transactions to those with high profit margins.
The non-firm Kenai North interface limit is 75 MW, (but subject to variation depending on Nikiski
and Cooper generation. Bradley Lake is modeled as 2 x 45 MW generating units plus additional
spinning reserve capability of 10 MW. And, the Douglas-Healy interface is limited to a non-firm
75 MW.
8.1.14 Total Railbelt Results
The 2020 annual system production costs in each of these nine cases is displayed in Table 8-1
below. The sensitivity analysis results are displayed in Appendix E of this report.
Table 8-1 Production Cost Results
2020
Production
Cost
(millions)
NS0 $ 391.2
S1 $ 394.4
S2 $ 401.2
S3 $ 449.2
S4 $ 453.1
N1 $ 413.9
N2 $ 494.1
N3 $ 495.5
NS4 $ 531.1
Case
The difference between the production costs in the NS4 and NS0 cases shows that the
complete set of both northern and southern upgrades would reduce the Railbelt system
production costs by about $140 million/year.
The difference between the NS4 and N3 cases is that the N3 case has all of the southern
upgrades and none of the northern, while NS4 has no upgrades. Then, the $35.6 million
difference between NS4 & N3 production costs indicates that if only the southern upgrades are
performed the production cost savings would be about $35.6 M /year.
Similarly, the difference between the NS4 and S4 cases is that the S4 case has all of the
northern upgrades and none of the southern, while NS4 has no upgrades. Then, the $78.1
million difference between NS4 & S4 production costs indicates that if only the northern
upgrades are performed, the production cost savings would be about $78.1 M/year.
Then, if both the northern and southern upgrades are performed, there is a further saving of
$26.2 million, in addition to the individual savings from the northern and southern upgrades.
This $26.2 million joint saving could be split between the southern and northern upgrades such
that a total of $48.7 M/year savings could be attributed to the southern upgrades, with $91.2
M/year being attributed to the northern upgrades.
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The impact of each of the nine transmission upgrade cases on the production costs of each
individual utility system depends very much on how well the planned generation resources of
that utility match the needs of that utility.
In evaluating the individual projects it can be seen that case S4-S3 provides the value of the
second Bradley-Soldotna direct line at $3.833 M/year.
The improvements of the HVDC line and the improvements to the 115 kV Quartz Creek –
University line can be evaluated individually or collectively, but not a direct comparison against
each other. For instance, the addition of the Quartz Creek – University 230 kV upgrade reduces
production costs by $47.99/year (S3-S2). The HVDC addition provides a benefit of $54.85 (S3-
S1) or the combination of both the 230 kV upgrade and the HVDC line provide a total benefit of
$58.04M/year (S3-NS0). The allocation of benefits in this instance becomes extremely difficult
since the benefits attributed to each individual project exceed the benefits of the projects as a
whole and each is including 100% of the North-South joint benefit. For purposes of this study,
the benefits attributed to each project could be pro-rated to equal the total of the benefits if both
projects were constructed and only 50% of the joint North-South benefit is included, that is, to
equal ($58.04 - $13.1) M/year. The HVDC tie would have allocated annual benefits of $23.97 M
/ year and the 230 kV upgrade would be allocated benefits of $20.97 M/year.
The Northern improvements can be analyzed in a similar manner. The Lake Loraine – Douglas
improvements provide substantial reliability improvements and are required in order to realize
any production cost benefits resulting from improvements between Douglas and Fairbanks.
However, the value of these projects in production cost savings without the other northern
improvements is limited and can be estimated by the difference between case N2 and N3 or
$1.5 M/year.
The improvements between Douglas and Healy, including the Lorraine-Douglas line section can
be estimated by taking the difference between cases N1 and N3 or $81.631 M/year, removing
the North-South joint benefit of $26.2 M/year, which is captured in this number, then adding
back the portion ($13.1 M/year) attributed to the northern upgrades because it is the Lorraine –
Healy upgrade that brings GVEA into the single pool dispatch. That results in $68.53 M/year
being attributed to the Lorraine – Healy upgrade.
The improvements between Healy and Fairbanks can be estimated by the difference between
case N1 and case NSO or $22.68 M/year
8.2 Capacity Deferral
Capacity deferral refers to the ability to defer the construction of new generation capacity in one
utility area by using excess capacity in another utility’s area. Currently, the lack of transmission
infrastructure precludes the use of extensive capacity sharing among utilities.
With the recent construction of new generation facilities in the Railbelt, there does not appear to
be a need for capacity expansion or replacement in the next 10-15 years. Beyond that time
frame, there appears to be a possibility of substantial capacity sharing between the Kenai,
Anchorage and Fairbanks areas. However, the estimates for this capacity deferral are not firm
or based on substantial planning. We have therefore decided to note the potential for capacity
deferral as a benefit, but assign a $0 value to the benefit at this time.
8.3 Reservoir Optimization
Studies indicate that constraints on Bradley Lake capacity usage will not result in a loss of
energy from the project, but will result in the use of project energy in a non-optimized manner.
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The transmission system also results in increased losses from Bradley Lake energy before it is
delivered to the Southcentral and Northern utilities. The constraints on the project will result in a
flatter use of the Bradley energy over the course of any one month or year. The inability to react
to high inflow periods to manage the reservoir level with high energy output will likely lead to a
lower average lake elevation as a means to mitigate the risk of spilling energy from the project.
Assuming only a 10’ difference in lower elevation, the energy production from Bradley Lake will
be reduced by approximately 1% or 3,300 MWH/year. Production cost simulations indicate that
the value of this energy ranges from $81-$250/MWh. Assuming a conservative value of
$125/MWh, this results in an annual loss of $412,500 or $7.56 M NPV for the life of the project.
8.4 Unserved Energy
Unserved energy is a means of establishing the economic cost of an electrical outage to the
consumers of a utility. Unserved energy is the traditional method used for the justification of
projects that provide an increase in reliability but do not necessarily result in lower production or
operating costs.
The value of unserved energy varies widely depending upon the time of year, type of customer
and the length and frequency of the outages. Industry accepted values of unserved energy
range from $800/kWh to $7,500/kWh with most values centered around $3,000/kWh.
A complete statistical analysis for transmission and generation outages for all of the utilities was
not completed, however a brief review of the outages indicate that there is a wide variation in
customer outages from year-to-year in the Railbelt. This variation is most likely due to weather
conditions and variations in unit reliability.
The analysis is also complicated by the changing generation structure of the Railbelt. The move
to smaller, light machines has two consequences to customer reliability, a lower system inertia
and a lower requirement for spinning reserves. The combination of these changes make it
difficult to directly compare historical generation related outages with future operating
conditions.
To estimate the number of unit trips in 2020, the number of turbine trips and operating turbine
generators from 2009 was used as the base case. The number of operating turbine generators
in 2009 was 18, for both summer and winter. The number of turbine trips in 2009 was 27. The
future amount of turbine generators that will be operating in 2020 is 16 and 18, for summer and
winter, respectively (Southcentral Transmission Study). Since the number of operating turbine
generators in 2020 will be about the same as in 2009, we assume the same incident of unit
tripping per turbine will exist in 2020 that existed in 2009.
Due to the change in inertia and spinning reserve, each turbine trip in the future system has a
very high likelihood of causing an outage due to under frequency load shedding. Assuming an
average 30 minute duration for each stage 1 load shed event, generation related outages are
assumed to result in 13.5 hours of consumer outages with an average value of 65 MW, or
$2.63M/year in excess energy attributable to generation related outages.
Transmission related outages have extreme variations in the Railbelt, with major transmission
lines experiencing no outages or in excess of 20 outages per year. The changing nature of the
Railbelt system will also change the impact that transmission outages have on the Railbelt
consumers. For instance, due to import conditions over the single Kenai-Anchorage
transmission system, although historic outages most likely did not result in loadshed events,
future line outages have a high probability of creating customer outages due to under frequency
load shed conditions.
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Assuming an average outage rate of 11 transmission outages per year (less than one outage
per 60 miles of transmission line) with an average duration of 30 minutes, the estimated value of
unserved energy due to transmission related outages is 5.5 hours with an average value of 55
MW or $0.91M/year.
The total NPV of the value of unserved energy is estimated to be $16,688,000.
8.5 Excess Energy
Periodically, Bradley has excess energy that must be used in order to avoid losing energy over
the spillway. In these conditions, Bradley has historically been operated between 90 MW and
115 MW and each participant is allocated a proportional share of the excess energy.
Plant dispatch records from 2002-2010 were correlated with lake level to determine the amount
of energy the participants have been forced to take in order to avoid losing energy over the
spillway. There was an expected wide variation in energy levels, with the high value in 2002 of
61,118 MWh to 0 MWh in 2004, 2005, 2007, 2008, and 2010. The average for the nine years
records available was 11,462 MWh.
Assuming an average value of $125/MWh for the spilled energy, the average annual excess
energy is estimated to be $1,433,000/year with a NPV of $26,300,000.
8.6 Reduced Regulation
In the new Railbelt generation and transmission configuration using distributed power plants,
each utility will be responsible for providing its own regulation and reserve requirements. The
result is that the total amount of regulation carried in the Railbelt will increase since each utility
will need to cover the regulation requirements of its own, relatively small load as opposed to
taking advantage of the load diversity which exists between the Railbelt load centers. This
increase regulation requirement will result in increased production costs for each of the utilities.
When operated as a common pool, the amount of regulation can be reduced to meet the
requirements of the total pool. These reduced regulation requirements are in addition to the
regulation requirements captured in the power production costing simulations. The estimated
reduction in regulation requirements is expected to be in excess of 10 MW per hour for the
Railbelt as a whole.
In addition to the regulation requirements for the system load, renewable resources such as Fire
Island and Eva Creek require separate regulation resources to control the variability of the wind
resource. Under a limited transmission system, each utility is required to provide for regulation
of its wind resources individually rather than taking advantage of the diversity of the wind
resources to create a much lower regulating requirement. The reduced regulation requirement
for the wind resource is expected to be reduced by an additional 10-15 MW over the average
hourly period.
Production cost simulations indicate the reduced regulation requirement can lower power
production costs by $141.5 M/year over the base case or an increase in savings of $1.6 M/year
or $24.6 M over the life of the project.
8.7 Reduced Spinning reserve costs
The addition of a 25 MW BESS in the Anchorage area to provide contingency reserves for the
loss of the AC Kenai-Anchorage transmission line could also be used to reduce the requirement
for on-line spinning reserves in the Railbelt system. Assuming that 75% of the BESS would be
available for spinning reserves and 25% would be used for regulation/charging would reduce
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production costs by approximately $206M/year in the Railbelt or $3,778M over the life of the
project.
8.8 Renewable Resource Integration
In its current configuration, the Railbelt system, is essentially at its limit to accept variable
renewable resources such as wind and solar generation without substantial costs. The limited
ability to provide regulation and reserves across the transmission system requires each utility to
provide reserves and regulation to cover each resource within its boundary. Increased
transmission between utility areas and the operation of the system as a common pool would
allow the geographic diversity of variable generation to be accounted for in power production
regulation and reserve scheduling. This would in effect, increase the amount of variable
generation the system could support without increasing its cost or decreasing its reliability.
It is difficult to quantify or assess the ability to take an increase amount of renewables on the
Railbelt system, however without increased transmission infrastructure, it is doubtful that the
Railbelt could increase its variable generation capacity above current levels.
8.9 Gas Sensitivities – Fairbanks LNG
The Fairbanks utilities and others are currently evaluating the feasibility of importing Liquefied
Natural Gas to the Fairbanks area for heating and electrical energy production. The availability
of gas in the Fairbanks area and in particular at GVEA’s North Pole power plant would reduce
the potential sales from southern utilities to GVEA and thereby reducing the benefits of the
transmission system.
If LNG is available at the North Pole power plant, the estimated savings of the transmission is
$75M/year or a reduction of $64.1M/year, assuming LNG is available at $3.5/MCF above Cook
Inlet Gas prices. The NPV of the savings is $1,175M.
8.10 Load Sensitivities
The possibility of a large industrial load in the GVEA area was evaluated under both existing
and future fuel scenarios. Adding a 100 MW load in the GVEA area without natural gas results
in production costs savings of $309 M/year. Adding a 100 MW load in the GVEA area with
natural gas available at North Pole Combined cycle results in saving of $244.8 M/ year.
The possibility of GVEA losing a large industrial load was also evaluated with and without the
availability of LNG in the Fairbanks area. If a 44 MW load is removed from the GVEA service
area and LNG is not available in Fairbanks, the production cost savings is estimated at $117.7
M/year. If a 44 MW load is removed from the GVEA service area and LNG is available in
Fairbanks, the production cost savings is reduced to $60.6 M/year.
8.11 Gas Price Sensitivities
The production cost cases were based on the gas and fuel pricing forecast developed for the
Watana project evaluation. Since that study Hilcorp has filed a Consent Decree Pricing
schedule that provides gas cost through 2018. These new costs were evaluated to determine
the impact changing gas prices may have on the production costs savings determined in the
original study.
Using the 2018 gas prices in the Hilcorp filing, the production cost savings was $138.7M/year.
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8.12 Spinning Reserve Determination
In the original simulations, utilities with duct firing were allowed to claim the capacity of the duct
firing to meet their spinning reserve obligation but were not required to declare the capacity of
the duct firing as part of the largest committed unit. A sensitivity was requested to evaluate the
impact of a utility not being allowed to utilize duct firing to meet their spinning reserve obligation
unless the capacity of the duct firing was also included in the declaration of the unit capacity.
The change in duct firing spinning reserve increased savings to $148.5M/year, approximately
$9.2M/year over the base case.
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9 Pre-Watana: Conclusions
The proposed transmission plan results in a transmission system for the Railbelt utilities that
allows transfer of power between the different regions of the Railbelt to minimize costs to the
Railbelt utilities and consumers served by these utilities. The plan balances transmission
projects with affordable costs resulting in a transmission plan that provides an extremely
positive benefit to cost ratio. Although the investment required to complete the plan is
substantial, when completed, its benefits far exceed its costs and results in significant savings to
the individual consumers in the Railbelt.
In addition to the benefits to the existing consumers, the plan allows for future load growth within
the Railbelt and also allows for a large energy project such as Watana to be incorporated into
the Railbelt system.
The benefits are fairly immune to sensitivities evaluated from the base case, with the worst case
sensitivity being the loss of a 44 MW load in the GVEA system coupled with the availability of
LNG in the northern system. However, even in this scenario, production cost savings are
estimated at $60.6M/ year. Capitalization of spinning reserve sharing and reduced regulation
would reduce the impact of this decrease by increasing savings an additional $30-50 M/year.
It is important to note that the benefits of the proposed projects are savings related to a
reduction in future cost increases as opposed to an increase in revenues.
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10 Pre-Watana Prioritization: Executive Summary
Electric Power Systems (EPS) has completed an analysis to make 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 and
report covers the recommended prioritization and ranking of projects for construction and
funding.
Table 10-1 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 10-1 Project Summary Cost and Benefits
This 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 10-1) 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 provide
a good benefit/cost ratio. 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 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 is 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 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.
In assigning the priorities for the projects, each 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 process, while optimizing the costs and benefits for the overall
Bradley Constraints 388.2$ 893.1$ 2.3
Flexible Gas Storage 18.2$
Southcentral / Overall 20.4$ 482.3$ 23.7
Northern System 494.7$ 1,672.5$ 3.4
Total 921.4$ 3,047.9$ 3.3
Area Total Costs
(Millions)
Summary Benefit
(Millions)
Benefit /
Cost Ratio
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plan. It was assumed that several projects would be undertaken concurrently, with different
projects in permitting, design and construction phases during the same period.
While there may be a single project 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 14-15 would be used to complete
construction of the remaining projects. The total dollars required in years 2-13 was attempted to
be levelized to the greatest extent possible for all activities (permitting, design, construction).
The desire to maintain fairly constant dollar expenditures in years 2-13 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 10-2:
Table 10-2 Recommended Project Sequence
The annual and cumulative cash flow for the recommended sequence is shown on Figure 10-1
Estimated Yearly and Cumulative Expenditures (USD) below.
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Figure 10-1 Estimated Yearly and Cumulative Expenditures (USD)
11 Pre-Watana Prioritization: Process
Each major project was broken into appropriate smaller projects that collectively comprise the
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 assume to
require equal effort. The breakdown of each major section and its subcomponents are shown in
Table 11-1.
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Table 11-1 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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12 Pre-Watana 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.
A detailed plan of our recommended project sequence is included in Appendix B.
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13 Post-Watana: Executive Summary
EPS has completed analysis for determining the additions required to the recommended
Railbelt transmission system following the addition of the Watana hydroelectric project between
Healy and Douglas stations on the existing transmission system.
The Watana hydro plant was assumed to consist of three 200 MW units for a total plant output
of 600 MW. The exact size and number of the units is currently being evaluated by AEA under
a separate project. The recommended interconnection point for the Watana plant is the Gold
Creek substation due to location, available space for substation equipment, and relevant
distance between the Healy and Douglas substations.
The transmission studies assume the improvements recommended in the Pre Watana part of
this report have been completed prior to the completion of the Watana project. All of the
recommended projects are required to support Watana in addition to being recommended in the
Pre-Watana transmission plan.
The ownership and resolution of the power delivery issues associated with the Watana project
are an important assumption in the development of the required transmission system. The
amount of capacity and energy available to the northern and southern portions of the Railbelt
from Watana have a direct impact on the required transmission system for the project. This
study assumed a wide range of power flows that may not applicable in the final power sales
agreements for the facility. The study assumed power transfers ranging from 280 MW north into
the Fairbanks area to 500 MW flowing south to the Southcentral/Kenai areas.
When the ownership, rights and characteristics of the Watana project have been identified, the
study should be updated to determine any changes in interconnection requirements for the
actual range of power transfers.
The basis or starting point to determine the impact of the Watana large hydro addition is the
proposed Pre – Watana transmission system presented earlier in this report. The same
planning criteria applied to the Pre-Watana studies (4.1 Planning Criteria) was used for the
Post-Watana studies.
A summary of the total Post – Watana project costs are provided in Table 13-1 below.
Table 13-1 Post - Watana System Project Cost Summary
Watana Interconnection / Alaska Intertie
The recommended Watana interconnection consists of three 230 kV transmission lines from the
Watana switchyard to the Gold Creek substation. The lines require protection communications
to ensure 4 cycle clearing times from both ends. A new -/+ 150 MVAR SVC is required at Gold
Creek Substation to maintain stability during contingencies and to provide dynamic voltage
support during the extreme ranges of the Watana power flows. The Healy – Gold Creek –
Douglas lines constructed as part of the recommended transmission plan must be converted to
230 kV operation. Alternative Watana connections utilizing two interconnecting transmission
Watana Interconnection 318.4$
Southcentral 54.5$
75 MW Energy Storage 90.6$
Total 463.5$
Area Total Costs
(Millions)
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lines were evaluated but were not recommended due to additional equipment and system
restrictions outside of the immediate Watana area.
A summary of the costs for the required projects for the Watana interconnection are presented
in Table 13-2.
Table 13-2 Watana Interconnection Project Costs
GVEA System
No system additions are required in the GVEA area to facilitate energy transfers or improve
reliability as a result of the Watana Project. The energy transfers can be supported with the
previously recommended improvements in the Pre – Watana transmission plan (7 Pre-Watana:
Improvements to the Northern Railbelt Transmission).
Southcentral
The Douglas – Teeland line should be converted to operate at 115 kV, removing the 100 MVA
138 kV/115 kV transformer at Teeland, eliminating the possibility of overloading it during heavy
Watana transfers to the south. This will require a 230/115 kV transformer at Douglas and the
conversion of the station at Teeland for the 115 kV line. The SVC at Lorraine should be
increased in size from -40/+25 MVAR capability to -75/+50 MVAR. The SVC at Teeland should
remain in service using the existing 230/138 kV transformer.
For heavy Watana transfers to the south, line outages south of Douglas substation in the
Southcentral Railbelt can create overload conditions during the summer peak load. Increasing
power generation following the line outage can relieve the overload conditions and eliminate the
need for additional transmission system additions. The re-dispatch of generation required to
alleviate the overload conditions is available throughout the Southcentral system.
A summary of the costs for the required projects for the Southcentral are presented in Table
13-3.
Table 13-3 Southcentral Project Costs
Kenai
No system additions are required on the Kenai to facilitate energy transfers or improve reliability
as a result of the Watana Project. Hydro-hydro coordination between the Bradley Lake and
Cooper Lake hydro units and Watana can be supported with the previously recommended
improvements in the Pre - Watana transmission plan (5 Pre-Watana: Improvements to the Kenai
– Anchorage Transmission).
Watana 230 kV substation 32.1$
Watana - Gold Creek 230 kV lines 190.1$
Gold Creek -150 / + 150 MVAR SVC 90.0$
Healy - Gold Creek - Douglas 230 kV operation 6.3$
Total 318.4$
Project Total Costs
(Millions)
Lorraine SVC upgrade to -75 / +50 MVAR 45.0$
Douglas - Teeland 115 kV operation 7.0$
Teeland 10 MVAr Capacitors 2.5$
Total 54.5$
Project Total Costs
(Millions)
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Energy Storage
A unit trip of a 200 MW Watana generator triggers a severe under frequency event that would
be unacceptable to the Railbelt utilities and consumers. A total of 100 MW of Energy Storage
(ES) is required to mitigate the impact of the unit trip to only Stage 1 of the under frequency load
shed scheme. Twenty-five (25) MW of the ES is assumed to be in service as part of the Railbelt
transmission improvements required prior to Watana’s operation. The additional 75 MW of ES
is recommended to be spread throughout the RailbeIt.
The primary purpose of the ES is to mitigate the impact of a Watana unit trip, however the ES
can provide additional support to the Railbelt. Thirty (30) MW of the ES should be located in the
Fairbanks system near the North Pole substation. This ES location can provide the ability to
start and stop large motors associated with possible future mine loads and provide voltage and
frequency support for the GVEA system. Twenty (20) MW should be located on the Kenai near
Soldotna. The Soldotna ES can provide energy to the Kenai system following the loss of one of
the two Kenai – Anchorage transmission lines and will remove generation constraints on the
Kenai. The remaining 25 MW of ES should be located in Anchorage, preferable near ITSS,
University, Plant 2, or adjacent to the previously installed 25 MW BESS. The Anchorage area
BESS increases Kenai – Anchorage transfer limits, allowing full hydro-hydro coordination.
It is important to note that the ES support is required for a brief amount of time (tens of seconds)
and the energy requirement of the ES in MW-hr can be less than the values stated in MW. It is
anticipated that the final solution will include a mix of battery and flywheel technologies, with
flywheel technologies providing the bulk of the required energy delivery to compensate for the
loss of the large hydro unit. The final mix between flywheel and battery technologies will be
determined in the next phase of the project. The mix in ES technologies will be utilized to
address transmission deficiencies where possible in addition to providing energy for the system
as a whole for the loss of a large Watana unit.
The proposed ES system will be a very large system in terms of world-wide installations. The
ES will be a technical challenge with the use of both flywheel and battery technologies.
However, in the time frame of the study, it is expected that such storage systems will be more
common place due to the dependence of renewable energy integration on such systems and
the developing market and production.
A summary of the costs for the required projects for ES are presented in Table 13-4. The costs
represent a battery technology with similar specifications as the initial Anchorage 25 MW BESS.
Table 13-4 Energy Storage Project Costs
GVEA 30 MW ES 35.1$
Anchorage 25 MW ES 30.2$
Kenai 20 MW ES 25.3$
Total 90.6$
Total Costs
(Millions)Project
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Figure 13-1 Northern Post – Watana Proposed Transmission System
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Figure 13-2 Kenai and Southcentral Post – Watana Proposed Transmission System
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14 Post-Watana: Overall Study Objectives
EPS has completed the Post – Watana study for the Alaska Energy Authority. The scope of the
study was to evaluate the transmission required in the Railbelt after the construction of the
Watana large hydro plant. The plant will consist of three 200 MW generators for a total plant
output of 600 MW. The proposed transmission system from the Alaska Railbelt Transmission
Study was used as the initial transmission configuration.
The study focused on determining the following:
- Required configuration of the Watana transmission line interconnection
- Required upgrades / additions to the Railbelt transmission system
- Required Energy Storage (ES) to protect against the loss of a 200 MW Watana unit
The study used the three seasonal power flow cases, summer valley, summer peak, and winter
peak, using the IOC approved 2020 base cases, and version 32.1.0 of Power Systems
Simulator Engineer (“PSS/E”). Power flow and transient contingency simulation methods were
used to perform the analysis.
15 Post-Watana: Watana Plant Modeling
The Watana power plant characteristics have not been finalized. The study assumes the plant
consists of three Frances type turbines. The Watana units were modeled with a maximum
power output of 200 MW, and a reactive capability of -82 to 80.6 MVAR, with an MVA rating of
220 MVA. The data is also listed in Table 15-1.
Table 15-1 Watana power flow modeling specifics (each)
VSched (pu)1.04
Pmax (MW)200
Pmin (MW)0
Qmax (Mvar)80.6
Qmin (Mvar)‐82.0
Mbase (MVA)220
R Source (pu)0
X Source (pu)0.30
A GENSAL model was used to model the Watana generator and an EXST1 model was used to
model the exciter. The parameters for these models were taken after the John Day hydro units
in the Western Electricity Coordinating Council (WECC) territory. It is assumed that the hydro
generators have inertia of 3.006 each.
Governor modeling of the Watana hydro units is important, as governor response is a major part
in determining overall system response during a load rejection event. The governor utilizes an
IEEEG3 model. The parameters for the model are similar to the John Day hydro units and are
shown in Table 15-2. The block diagram for the IEEEG3 governor (taken from the PSS/E
documentation), is shown in Figure 15-1.
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Table 15-2 Susitna turbine governor modeling specifics, IEEEG3
TG, (> 0), Gate Servomotor Time Constant 0.2
TP, (> 0), Pilot Value Time Constant 0.2
UO Opening Gate Rate Limit 0.12
UC Closing Gate Rate Limit (< 0.)‐0.12
PMAX Maximum Gate Position 1
PMIN Minimum Gate Position 0
sigma, Permanent Speed Droop Coefficient 0.05
delta, Transient Speed Droop Coefficient 0.4
TR, (> 0) 5
TW (> 0), Water Starting Time 1
a11 (> 0) 0.5
a13 1
a21 1.4
a23 (> 0) 0.95
Figure 15-1 IEEEG3 Block Diagram
It is important to note that while the Watana units were modeled similar to the John Day units,
the data was adjusted to more accurately represent what would be installed at Watana.
16 Post-Watana: Watana Interconnect / Alaska Intertie
The addition of the Watana plant to the Railbelt system represents a total of 600 MW of new
generation between Anchorage and Healy. This plant can supply a significant portion of the
Railbelt generation during all load conditions. The distribution of the Watana power and energy
has not been determined, however all power and energy from the project must be transmitted to
the Alaska Intertie before being distributed to either northern or southern users. Gold Creek
Substation was chosen as the point of interconnection for the Watana plant in these studies due
to its proximity to Watana, its location on the Alaska intertie and the electrical characteristics of
the interconnection point.
The lines from Healy – Gold Creek and Gold Creek – Douglas were analyzed at 138 kV
operation, resulting in unstable system response during several contingencies. Operating the
lines from Healy – Gold Creek and Gold Creek – Douglas at 230 kV is required with the addition
of the Watana large hydro project to avoid instability for several line fault conditions.
A single 230 kV transmission line between Watana and Gold Creek would be sufficient during
steady state conditions, but a contingency on the line would result in severe under frequency
events due to the loss of energy from the entire Watana plant. Therefore, additional
transmission lines are required to provide transient security as opposed to steady-state security.
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The transmission requirements between Watana and Gold Creek stations were analyzed with
both two and three 230 kV lines.
Previous studies have assumed two circuits would terminate at Gold Creek and the third circuit
would terminate near Cantwell. From a transmission stability / power flow point of view, there is
minimal difference between the two routing options.
The transmission configuration between Gold Creek and Douglas was also analyzed with either
two or three 230 kV lines. The impact of the transmission configuration with the rest of the
Railbelt system and required SVC support are shown below in Table 16-1. The two
transmission lines between Healy and Gold Creek are operated at 230 kV for the transmission
configuration analysis.
Table 16-1 Watana Interconnect / Alaska Intertie Configuration Analysis
Base 2 2 ‐75 / +50 ‐200 /
+200 Requires GVEA ‐ Fairbanks upgrade to 230 kV
13 2‐75 / +50 ‐150 /
+150 Reduced Gold Creek SVC size
23 3‐75 / +50 ‐Elimination of SVC at Gold Creek
Trans
Config
Number of Lines SVC Size (MVAR)
Railbelt System ImpactWatana ‐
Gold
Creek
Gold
Creek ‐
Douglas
Lorraine Gold
Creek
2 Lines Watana – Gold Creek, 2 Lines Gold Creek – Douglas (Base)
Utilizing two transmission lines between Watana – Gold Creek and two transmission lines
between Gold Creek – Douglas (base) requires the transmission lines between GVEA (at Healy)
and Fairbanks (at Gold Hill / Wilson) to be rebuilt and /or converted to 230 kV operation in order
for the Railbelt to remain stable during contingencies or to reduce the power import into the
GVEA system. This transmission configuration would also require a -200 / +200 MVAR SVC to
be built at Gold Creek to maintain stability during contingencies.
3 Lines Watana – Gold Creek, 2 Lines Gold Creek – Douglas (Config 1)
Installing a third transmission line between Watana – Gold Creek (config 1) results in a
reduction in SVC requirement at Gold Creek from -200 / +200 MVAR to -150 / +150 MVAR. This
transmission configuration also allows for the lines from Healy to Fairbanks to be operated at
138 kV (should they not be converted prior to the operation of Watana).
3 Lines Watana – Gold Creek, 3 Lines Gold Creek – Douglas (Config 2)
A transmission configuration of three 230 kV lines between Watana – Gold Creek and three 230
kV lines from Gold Creek – Douglas (config 2) eliminates the requirement of the SVC at Gold
Creek. This configuration provides the most robust system alternative, but is also the most
costly option.
Transmission Configuration Conclusions
Based on the results, the base transmission configuration with only two transmission lines
between Watana – Gold Creek is not preferred due to the large SVC size required at Gold
Creek and the requirement of the GVEA system to be upgraded to 230 kV operation. The large
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SVC represents a significant single contingency risk, with the operation of the Railbelt system
dependent upon its availability.
A third transmission line between Watana – Gold Creek is the preferred interconnection
configuration as the required SVC at Gold Creek is reduced from the base case along with
increased operational flexibility in the GVEA system.
A Power System Stabilizer (PSS) should be installed on all Watana units. The stabilizers
increase the stability of the system and allow for a reduction in the required SVC size at Gold
Creek. PSS’s are available on most all modern day exciter / automatic voltage regulator control
packages. The exact make and model of the stabilizers cannot be specified without final design
data for the Watana units. An IEEE 421.5 2005 PSS2B Dual-Input Stabilizer model (similar to
the Bradley Lake stabilizer) was used in the analysis.
A third transmission line between Gold Creek and Douglas stations eliminates the need for the
SVC at Gold Creek, though with the additional expense of another line between Gold Creek –
Douglas increases the capital costs by approximately $40 M.
The proposed transmission configurations for the Watana interconnect and the Alaska Intertie
are listed below:
New Watana 230 kV substation
Three Watana – Gold Creek 230 kV transmission lines, double bundled Rail conductor
o 4 cycle clearing for Watana – Douglas 230 kV
New Gold Creek -/+ 150 MVAR SVC
Power System Stabilizers installed on all Watana units
Gold Creek substation operated at 230 kV
Healy – Gold Creek – Douglas lines operated at 230 kV
Teeland – Douglas 138 kV line converted to 115 kV operation
16.1 Watana Unit Trip Analysis
The Energy Storage was sized to limit the loss of load to a stage 1 or stage 2 event using unit
trip analysis in PSS/E. While it is not believed that a unit trip of Watana would occur very often,
it is still a possibility. The largest hydro unit currently on the Railbelt system is the Bradley Lake
power plant. A loss of the Bradley Lake unit does not result in a blackout of Homer or any other
sub-region. It is expected that a loss of a Watana unit should have a similar minimal impact.
New generation dispatches were created to minimize the system spin to create worst case
conditions for the unit trip analysis. The generation dispatches are shown in Table 16-2. As
stated previously, the actual generation dispatches for Watana will be dependent upon the final
power sales agreement between the facility and the purchasing utilities. The assumed
dispatches used for this study are intended to stress the limit of the system and may not be
possible in the final power sales agreements. Dispatch cases that stress the system less than
used in the study will result in less improvements required to the transmission system, including
the ES. Plots for the simulation results for the recommended system can be found in Appendix
H.
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Table 16-2 Railbelt Dispatch – Unit Trip Analysis
Bradley Lake ‐1.3 ‐1.3 ‐1.3
Plant 10 0 15
Plant 20 0 70
SCPP 107 91 142
Cooper Lake 0 14 20
Eklutna Lake 0 29 40
Watana 300 600 600
North Pole 54 50 90
Total Spin 596 196 214
Total Load 445 778 1019
Generators Summer
Valley
Summer
Peak
Winter
Peak
The current UFLS system for the Railbelt is shown in Table 16-3. The UFLS system has not
been modified from its original purpose of protecting against under frequency events for a heavy
frame type gas-turbine based power system to protecting a hydro system with lighter aero
derivative machines. The size of the ES may be optimized by modifying the UFLS protection for
a hydro based power system.
Table 16-3 Railbelt Load Totals and UFLS settings
MW % MW % MW %
59.0 1 45.6 10% 73.5 9% 105.5 10%
58.7238.79%60.38%86.38%
58.5 3 94.8 21% 167.7 21% 237.1 23%
58.2 4 39.3 9% 74.1 9% 104.4 10%
Frequency
(Hz)
UFLS
Stage
Summer Valley Summer Peak Winter Peak
450 MW of Load 786 MW of Load 1035 MW of Load
The unit trip analysis shows an increase in need for ES support to keep the Under Frequency
Load Shed (UFLS) system from activating beyond stage 1 or stage 2 as the system load and
therefore unit commitments are reduced from the winter peak load season. The results are
shown in Table 16-4.
Table 16-4 Watana Unit Size Analysis – BES Sizing
Stage 1Stage 2
600 300 200 120 80
600 600 200 100 20
600 600 200 80 0
SV
SP
WP
ES Size (MW)
Case
Watana Plant (MW)
Capacity Output Trip
Freq. Control
The dispatch cases developed for this analysis resulted in a dispatch scenario that may not be
realistic for system operations or within the power sales agreements for the facility. As such, it
may be possible to provide better system performance if the studies were constrained to less
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extreme dispatch scenarios as opposed to the boundary conditions studied using the machine
ratings.
A total of 100 MW ES is recommended to mitigate the UFLS action to a stage 1 event. The
mitigation will limit the UFLS to a Stage 1 event for winter and summer peak load conditions.
Summer valley conditions may reach stage 2 UFLS, however the dispatch scenario required to
allow a 200 MW unit trip is most likely not practical. To stress the system, a dispatch of one unit
at 200 MW with the remaining two units dispatched to 50 MW (300 MW total plant output) was
used. In actual practice, it is unlikely the units would have such a large disparity between
loading amounts.
The location of the ES does not impact the ability of the ES to provide support to the system for
the loss of a large Watana unit trip. Other benefits to the system that are beyond the scope of
this study could be realized by splitting the total ES system into different areas of the Railbelt
and may drive the location of and optimization of the ES.
Locating a portion of the ES on the Kenai would allow total hydro-hydro coordination between
the hydro resources of the Kenai and the Watana project. The ES would eliminate generation
restrictions on the Kenai by providing an energy resource to stabilize the Kenai system following
loss of one of the Kenai-Anchorage transmission lines. Stabilization would be provided by the
ES until Kenai generation could be dispatched on the system. Studies indicate a minimum of 20
MW ES would be required on the Kenai to provide stabilizing support.
Locating a portion of the ES in the GVEA area near the North Pole Station would allow the
system to support large motor cycling for existing and future mine or industrial loads without
additional Fairbanks area generation or transmission improvements.
Siting the remainder of the ES adjacent to the 25 MW ES in the Anchorage area would increase
the transfer capability of the Kenai – Anchorage system and eliminate import restrictions into the
Anchorage area. Elimination of import restrictions would allow full Kenai hydro-hydro and
thermal generation coordination with the Watana project.
17 Post-Watana: GVEA
The Pre-Watana transmission recommendations for the GVEA system recommended the lines
from Healy – Wilson and Healy – Gold Hill be upgraded to 230 kV. The improved power
transfer capability between GVEA and the southern utilities following these improvements
allowed considerable benefits to both. However, the costs of these improvements are high and
will require long-lead construction times. This report looked at the impact to the Watana system
improvements and energy transfers if the Fairbanks area lines are not converted to 230 kV prior
to the Watana project.
17.1 Watana – GVEA Transfer Limits
The transfer limits from Healy into Fairbanks for winter peak and summer peak cases with
varying Healy dispatches were analyzed to show the impact of the above transmission
upgrades. The results are shown below in Table 17-1 and Table 17-2, respectively.
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Table 17-1 Winter Peak GVEA Import Analysis
45 65 61 143 138
‐15 156 239 230
‐‐172 255 230*
45 65 116 143 138
‐15 211 238 230
‐‐227 255 230*
50 65 145 138 138
‐37 227 220 230
‐7.5 254 247 230*
55 65 164 157 138
‐32 252 245 230
‐6 280 273 230*
* 30 MVAR of reactive compensation at Gold Hill and Wilson substation (each)
gl 90.4 24
gk ‐‐
gi 35 ‐
gj ‐24
Case
Plant Output (MW) Healy Flows (MW)Healy ‐
Gold &
Healy ‐
Wilson kVHealy
Plant Eva Crk North P.
Plant
N. Pole
CC Plant
From
South To North
The winter peak cases with the lines between Healy and Gold Hill / Wilson upgraded to 230 kV
result in transfer limits North of Healy around 220 - 245 MW. The Healy imports are further
increased by 16 – 28 MW to around 255 – 273 if reactive compensation is installed at Gold Hill
and Wilson substations (30 MVAR capacitors each). If the Healy – Wilson and Healy – Gold Hill
lines are not upgraded to 230 kV, significant reductions in GVEA imports of 110 – 120 MW will
be required, resulting in Healy export limits (to Fairbanks) of about 140 MW instead of 255 –
273 MW.
Table 17-2 Summer Peak GVEA Import Analysis
x40 ‐7 73 138
‐‐110 191 230
x 40 115 143 138
‐‐163 191 230
x40150 143 138
‐‐190 183 230
x 40 169 162 138
‐‐222 215 230
Healy ‐ Gold &
Healy ‐ Wilson kVHealy
Plant Eva Crk North
P. Plant
N. Pole
CC
Plant
From
South To North
gj ‐24
gi 35 24
Case
Plant Output (MW)Healy Flows (MW)
gk ‐‐
gl 86 24
The summer peak cases with the lines between Healy and Gold Hill / Wilson upgraded to 230
kV result in transfer levels North of Healy around 191 – 215 MW. Additional reactive
compensation is not required for the summer peak cases. If the Healy – Wilson and Healy –
Gold Hill lines are not upgraded to 230 kV, reductions in GVEA imports of 40 – 120 MW will be
required, resulting in Healy export limits (to Fairbanks) of about 140 MW instead of 183 – 215
MW.
Based on these results it is recommended that the 138 kV lines between Healy and Fairbanks
(Gold Hill / Wilson) be upgraded to 230 kV construction and operation. The addition of the 30
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MVAR of reactive compensation at Gold Hill and Wilson substations will depend upon expected
transfer levels into the GVEA system from Watana. It is not recommended that the reactive
compensation be installed until expected power transfers into GVEA are defined.
17.2 GVEA Energy Storage
The 100 MW of ES can be located in various areas in the Railbelt. Locating a portion of the ES
near the North Pole substation reduces the possibility of voltage collapse due to loss of the
transmission lines between Wilson and North Pole. The ES is able to provide reactive power
support as well as providing a generation source to mitigate transmission overloads.
The location of the ES in the North Pole area provides a significant resource to provide energy
for motor starting/stopping and for contingencies within the GVEA system and bulk transmission
system. The ability of the ES to provide service to large mine loads could be significant. Thirty
(30) MW ES of the required 100 MW is recommended to be located in the Fairbanks location to
provide energy during under frequency events and also provide regulation due to possible new
mine loads.
18 Post-Watana: Kenai
No transmission equipment is required for Watana energy to be transferred into the Kenai
system beyond those proposed in the Alaska Railbelt Transmission Study.
The Watana plant is still under development, however an important part of the plant’s design
and integration into the Railbelt concerns the daily load regulation required for the Railbelt
loads. If load regulation is supplied by Watana, costs for the project may increase. The ability
to provide daily load swings by generation other than Watana may contribute to significant cost
savings on the Watana project. The ability to provide load regulation from the Kenai resources
means that Kenai area generation must have the ability to be ramped from off-line to full output,
without generation constraints.
Utilizing the HVDC line and the upgraded Kenai Tie, all of the Kenai loads can be served by
northern and Southcentral generation. An outage of the HVDC line during maximum Kenai
import conditions requires 5 MW of ES located on the Kenai to mitigate low voltage conditions
on the Kenai. The 5 MW ES is required for the condition that all Kenai generation is offline and
only the SVC is providing voltage support and regulation. Operating the Bradley Lake units in
condense mode removes the ES requirement due to an outage of a HVDC line.
An outage of the Kenai 230 kV AC Tie results in the Kenai importing power from Anchorage
through the HVDC line only. An ES of 20 MW is required to provide the necessary power to
serve the combined HEA and SES loads and losses. The ES will be utilized until other Kenai
generation can be increased or brought on-line to make up for this energy shortfall. Sizing the
ES at 20 MW will allow for future load growth and also allow for operational flexibility of the ES
system.
19 Post-Watana: Southcentral
The new equipment associated with transferring up to 500 MW of Watana energy into the
Southcentral system is listed below.
Lorraine SVC upgraded to -75 / +50 MVAR capability
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Douglas – Teeland 115 kV line operated at 115 kV
10 MVAR capacitors at Teeland
The Lorraine SVC in the Pre-Watana transmission system should be upgraded by adding 25
MVAR of capacitors and 35 MVAR of Thyristor Controlled Reactors (TCR) in order to increase
the range of the SVC to -75 / +50 MVAR. This increase is required in order to provide accurate
voltage control and also to maintain stability during contingencies.
The Douglas – Teeland line should be operated at 115 kV. The 230/138/115 kV transformer
installed at Douglas as part of the Railbelt transmission improvements should be converted to
115 kV. The 138/115/34.5 kV 100 MVA 3 winding transformer at Teeland should be removed
and the line connected to the 115 kV breaker position in its place. The 100 MVA transformer
will overload during heavy transfers south from Watana into the Anchorage area during
contingency conditions. 10 MVAR of capacitors should also be added at Teeland 115 kV to aid
in supporting the voltage during contingency conditions.
19.1 Watana – Southcentral Transfer Limits
Transfers of up to 500 MW from Watana into the Southcentral Railbelt are possible with the
identified transmission upgrades. For the winter peak load season, heavy energy imports from
Watana during single contingencies do not result in unstable system response, voltage
violations, or thermal overloads.
The summer peak load cases are dynamically stable for all conditions but have many thermal
overloads following single contingencies. Outages of the 230 kV undersea cable will result in
overloads of the 115 kV lines from Teeland – Cottle – Herning. The opposite is also true, as
outage of the same 115 kV lines in the MEA system will result in overloads of the overhead line
sections of the 230 kV undersea cable (Lorraine – West Term, East Term – Plant 2).
To eliminate these thermal overloads without re-dispatching Railbelt generation requires
additional transmission upgrades to the Southcentral Railbelt, including transmission line
upgrades in the MEA system, or a new 2nd undersea 230 kV cable, or a new 230 kV line from
Douglas to Hospital substation in MEA. The following three options are as follows:
1) Transmission Line Upgrades
a. Upgrade the Teeland – Cottle – Herning 115 kV lines to Rail conductor
b. Upgrade Lorraine – East and West – Plant 2 230 kV lines to Rail conductor
c. Upgrade Transmission Lines from Pt. Mackenzie to ITSS 138 kV substation
2) New Undersea Cable
a. New Fossil Creek 230 kV substation
b. New 230 kV line from Plant 2 to Fossil Creek 230 kV
c. Operate existing 115 kV line from Plant 2 to Fossil Creek at 230 kV
d. New 230 kV undersea line from Lorraine to Fossil Creek
3) New 230 kV line into MEA
a. New 230 kV line from Douglas to Hospital substation
b. New 230 kV substation at Hospital
c. New 230 / 115 kV transformers at Hospital
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Reducing Watana transfers to the south (into the Douglas substation) to 310 MW during these
contingencies will remove these overload conditions. The reduction in Watana transfers can
result from increasing generation in the Southcentral/Kenai areas. The increase in generation
can be completed in a timeframe that prevents conductor damage or long-term overloads and
does not result in voltage violations during the re-dispatch.
No reductions of Watana plant output are required for the summer valley or winter peak load
seasons.
We recommend the system utilize re-dispatch as a method of controlling thermal overloads
following a single contingency event as opposed to the system improvements required to
eliminate the overloads.
19.2 Anchorage Energy Storage
With 30 MW of the required ES located in Fairbanks and 20 MW of the ES located on the Kenai,
the remaining 25 MW of additional ES should be located in Anchorage. The addition will
increase the ES size in Anchorage by 25 MW for a total of 50 MW.
Locations for the ES, such as International or University in the CEA system, or Plant 1 or Plant 2
in the AML&P system would be ideal, allowing for the ES to be used for under frequency events,
but also to mitigate thermal overloads due to outages of major transmission lines south of
Douglas. The increased ES would also increase the Kenai – Anchorage transfer limits,
unconstraining Kenai area generation and allowing full Kenai-Watana generation coordination.
20 Post-Watana: Conclusion
EPS has completed analysis for determining the post – Watana Railbelt system configuration.
The following system additions allow for full utilization of Watana energy and allow for greater
operational flexibility of the energy transfers to different parts of the Railbelt.
The system additions are listed below.
Interconnection / Alaska Intertie
New Watana 230 kV substation
Three New Watana – Gold Creek 230 kV transmission lines
o Double bundled Rail conductor
o 4 cycle clearing for Watana – Douglas 230 kV
New Gold Creek -/+ 150 MVAR SVC
Power System Stabilizers installed on all Watana units
Gold Creek substation operated at 230 kV
Healy – Gold Creek – Douglas lines operated at 230 kV
GVEA System
30 MW Energy Storage System
Southcentral
Lorraine SVC upgraded to -75 / +50 MVAR capability
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New Douglas 115 kV bay
Douglas – Teeland 115 kV line operated at 115 kV
10 MVAR capacitors at Teeland 115 kV bus
25 MW additional Energy Storage System (25 MW assumed to be installed prior to
Watana)
Kenai
20 MW Energy Storage System
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A Pre-Watana Study Appendix
A.1 Notes on Benefit/Cost Ratios
The costs completed for these projects were developed based on a 2012 cost basis using
information supplied by various Railbelt utilities and conceptual designs for each project. The
cost estimates are estimated to be +/- 20% of actual construction costs.
The benefits for the projects are simplified simulations based on one year of the project’s
operation. The identified benefits are assumed to be constant for the life of the project. The
actual benefit of any project will vary over time as energy resources, load, transmission lines
and operating practices change in the Railbelt.
The Net Present Value utilized a discount of 5.00% and an assumed life of each project of 50
years. The Benefit/ Cost ratio was a simplified ratio developed by the ratio of the 2012 costs
over the NPV of the project benefits. The actual construction of the projects will consume 10-15
years and as such the construction sequence will have an impact on the benefits available for
each project. Certain projects for instance, depend on other projects being constructed in order
to obtain the identified benefits. For the feasibility level analysis completed in this study, it was
assumed all projects were available in year one.
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A.2 Railbelt Seasonal Loads
Table A-1 Year 2023 Railbelt Seasonal Loads by Substation
Soldotna 4.3 9.7 9.6 Briggs 1.5 2.6 4.2
Sterling 1.8 1.8 6.1 Johnson 3.6 6.2 10.0
Thompson 4.4 9.1 10.1 Pippel 7.3 12.6 20.1
Kasilof 2.5 0.0 6.8 Parks 2.2 3.7 6.0
Anchor Pt. 2.2 3.9 5.7 Reed 2.5 4.2 6.8
Diamond Ridge 0.8 0.8 2.7 Eklutna 0.0 0.1 0.1
Hatfield 5.0 8.5 12.3 Dow 2.6 4.4 7.1
Fritz Creek 0.7 1.1 1.7 Palmer 1.5 2.5 4.1
Tesoro 12.1 15.1 18.1 Lucas 7.4 12.7 20.3
Bernice 6.4 8.0 11.8 Hospital 4.3 7.4 11.9
Beaver Creek 1.6 2.3 6.8 Oneil 1.9 3.3 5.3
Marathon 3.9 7.1 6.9 Lazelle 3.6 6.2 9.9
Plant 1 28.2 57.6 62.4 Shaw 5.1 8.8 14.1
Sub #6 13.8 25.9 26.5 Herning 8.2 14.2 22.7
SUB#7 5.5 10.3 10.7 Cottle 2.3 3.9 6.3
SUB#8 10.1 19.0 18.1 Theodore 2.7 4.6 7.4
SUB#10 6.2 11.7 13.7 McRae 2.8 4.9 7.8
SUB#12 0.0 2.9 5.2 Redington 1.1 1.9 3.1
SUB#14 7.9 14.9 15.9 Anderson 3.2 5.5 8.8
SUB#15 7.9 14.8 17.3 Douglas 3.7 6.4 10.3
SUB#16 9.4 17.6 15.3 Cantwell 1.2 1.4 1.2
SUB#20 4.0 7.4 9.2 Healy 5.9 7.1 7.1
SUB #22 9.3 17.4 14.8 Nenana 0.9 1.2 2.0
Raptor 10.9 10.9 10.9 Ester 1.4 2.1 3.9
Airport 1.0 1.7 2.5 Gold Hill 0.3 0.5 1.1
Arctic 6.7 11.2 16.3 Musk Ox 2.2 3.6 7.9
Baxter 3.3 5.5 8.0 Chena Pump 2.6 4.5 7.9
Boniface 3.9 6.5 9.5 University Ave 2.2 4.7 5.6
Campbell 5.0 8.4 12.3 Aurora 3.3 7.0 9.0
DeBarr 7.3 12.2 17.9 Zhender 5.0 9.4 9.6
Dowling 6.9 11.5 16.8 Kasalak 3.7 6.1 10.9
Hillside 3.0 5.0 7.4 Fox 1.2 1.7 2.6
Huffman 3.6 6.0 8.7 International 4.5 7.9 11.4
Jewel LA 3.9 6.6 9.6 Peger Rd 3.5 7.4 9.0
Klatt 5.7 9.5 13.8 Chena 11.3 20.1 17.9
LaTouche 5.1 8.5 12.4 South Side 8.7 5.9 12.3
O'Malley 4.3 7.2 10.4 South Fairbanks 2.8 6.7 8.2
Raspberry 4.3 7.1 10.4 Hamilton 5.5 12.5 16.1
Sand Lake 5.3 8.9 12.9 BESS AUX 0.1 0.3 0.2
Spenard 4.5 7.6 11.1 Badger Road 3.2 5.5 10.1
Turnagain 2.7 4.5 6.5 Brockman 1.3 2.3 4.6
Woodland 3.2 5.3 7.7 Hwy Park 3.3 5.8 9.0
Beluga 1.5 2.5 3.7 N. Pole Sub 0.0 0.2 0.2
Tyonek 0.5 0.9 1.3 N. Pole CC1 2.7 2.7 2.7
Loss 5.9 9.8 14.4 Dawson 2.2 4.6 7.4
Post Mark 3.0 5.0 7.3 Johnson 1.1 1.3 2.9
Daves Crk 0.4 0.7 1.0 TECKPOGO 11.6 11.5 12.7
Indian 0.3 0.3 0.3 Jarvis 4.2 3.8 13.3
Girdwood 5.3 5.3 5.3 Pump 9 6.9 6.9 6.9
Portage 1.4 1.4 1.4 Mds 1.7 1.7 1.7
Hope 0.3 0.3 0.3 Wilson 0.2 0.2 0.2
Sewerd Sewerd 7.7 10.3 11.9 Jarvis 0.1 0.1 0.1
Mapco 7.0 19.4 19.4
UAF 0.0 11.9 11.9
Ft. Wainwright 0.0 16.0 16.0
Eielson AFB 0.0 9.6 9.6
FGA 2.0 2.0 2.0
Bus Name Summer
Valley
Summer
Peak
Winter
Peak
HEA
MEA
MLP
GVEA
CEA
Area Bus Name Summer
Valley
Summer
Peak
Winter
Peak Area
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A.3 Conductor Ratings
Table A-2 Conductor Ratings
Winter Summer Winter Summer Winter Summer
4/0 AWG ACSR Penguin OH 88 51 106 61 176 102
336 MCM ACSR Linnet OH 124 70 149 84 249 140
556 MCM ACSR Dove OH 173 96 208 115 347 192
795 MCM ACSR Drake OH 220 120 263 144 439 240
954 MCM ACSR Rail OH 241 154 290 185 483 309
2‐954 MCM ACSR Rail (x2) OH 616 434 739 521 1232 868
1900 MCM Cu Cable UG 155 140 186 169 310 281
Conductor Name
Circuit
Type
Conductor Rating (MVA)
115 kV 138 kV 230 kV
A.4 Loss/Energy/Capacity
Table A-3 Historically Displaced Energy
Table A-4 Bradley Stranded Capacity
Annual
MWh
Historical
losses
Projected
Losses Difference
HEA energy 47,289 946 1,419 473
Northern users 193,973 3,879 21,337 17,458
Battle Creek ‐ HEA 4,680 0 140 140
Battle Creek ‐ Northern Users 34,320 0 3,775 3,775
Wheeled energy 152,738 4,582 16,801 12,219
Total energy losses 34,065
Historically wheeled energy to Northern users (MWh)
Historically Displaced Energy (MWh)
Bradley
output HEA Share SES Load Losses Cooper Export
85.4 14.4 10 6 ‐20 75
Bradley Stranded Capacity (MW)
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Table A-5 Kenai Loss Analysis
base upgraded base upgraded
University Indian 1 1.0 0.3 1.8 0.5
Indian Girdwood 1 0.6 0.2 1.2 0.3
Girdwood Portage 1 0.5 0.2 1.0 0.4
Portage Hope 1 1.4 0.4 2.6 0.7
Hope Daves Creek 1 1.3 0.3 2.2 0.6
Daves Creek Quartz Creek 1 0.7 0.2 1.1 0.3
Quartz Creek XFMR 1 no line 0.0 no line 0.0
Quartz Creek Soldotna 1 3.7 1.0 6.7 1.8
Quartz Creek Soldotna 2 no line 1.0 no line 1.8
9.2 3.4 16.7 6.2
Soldotna Bradley Lake 1 2.2 0.8 4.2 1.5
Soldotna Bradley Lake 2 no line 0.8 no line 1.5
2.2 1.5 4.2 3.0
Soldotna Thompson 1 0.0 0.0 0.0 0.0
Thompson Kasilof 1 0.0 0.0 0.2 0.0
Kasilof Anchor Pt 1 0.4 0.1 1.0 0.3
Anchor Pt Diamond Ridge 1 0.2 0.1 0.4 0.1
Diamond Ridge Fritz Crk 1 0.2 0.1 0.3 0.1
Fritz Crk Bradley Lk 1 0.7 0.4 1.1 0.6
1.6 0.7 3.0 1.1
12.9 5.6 23.9 10.3
77.6 81.5 100.2 107.6
‐3.4 ‐2.7 ‐8.8 ‐7.3
‐3.9 ‐3.1 ‐9.2 ‐7.7
39.5 20.2 51.5 24.0
42.9 22.9 60.3 31.3
Notes:
Cooper Lake unit 1 online, at 9.8 MW
Cooper Lake unit 2 online, at 9.8 MW
only changes are Bradley Lake output
swing bus at Beluga 7
tie flow measured on Dave's Creek ‐ Hope line
HEA taking 14.4 MW of Bradley Lake
Total: University ‐ Bradley Lake (All Lines)
Kenai tie flow
SPP 138 kV angle
University 138 kV angle
Bradley Lake 115 kV angle
Subotal: University ‐ Soldotna
Subtotal: Soldotna ‐ Bradley Lake
Subtotal: Soldotna ‐ Bradley Lake
Kenai Loss Analysis
Bradley Output
90 120From Bus To Bus Ckt ID
Values Line Losses / Bus Angles
20.0 28.9Reduction of angle
Angle Difference Bradley Lake ‐ SPP
Reduction of losses 7.3 13.6
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A.5 Kenai Transmission Cost Analysis
Below are the detailed cost analyses for the different upgrades proposed for the Kenai
transmission system.
A.5.1 2nd Bradley Lake – Soldotna Line
Table A-6 2nd Bradley Lake – Soldotna Line, Substation Costs
Table A-7 2nd Bradley Lake – Soldotna Line, Line Construction Costs
A.5.2 Dave’s Creek – University 230 kV Station Conversion
Table A-8 Dave’s Creek – University 230 kV Station Conversion Costs
A.5.3 Dave’s Creek – University 230 kV Line Conversion
Table A-9 Dave’s Creek – University 230 kV Line Conversion Costs
A.5.4 Dave’s Creek – Quartz Creek Line Upgrade
Table A-10 Dave’s Creek – Quartz Creek Line Upgrade
Station Description Costs
Bradley Lake Add new Bay/115 kV cable to Bradley GIS 2,865,141$
Soldotna 115 kV station - Ring Bus 7,684,406$
Total Substation Additions 10,549,547$
Line Description Costs
Bradley to Bradley Junction New 19.2 mi. 115kV X-tower , Drake Conductor 18,000,000$
Bradley Junction to Soldotna New 48.6 mi. 115kV H-frame, Drake Conductor 37,000,000$
Total Line Construction 55,000,000$
Station Description Costs
Dave's Creek 230 kV Transformer,breaker, reactor 20,216,517$
Summit 230 kV Circuit Switcher/transformer 1,803,319$
Hope 230 kV Circuit Switcher/transformer 1,803,319$
Portage 230 kV Circuit Switcher/transformer 3,791,449$
Girdwood 230 kV GIS, Circuit Switcher/transformers 12,038,689$
Indian 230 kV Circuit Switcher/transformer 3,026,814$
University 230 kV relaying/controls 361,475$
Totals Substation Conversion 43,041,582$
Line Description Costs
University to Daves Creek Upgrade 77 mi. from 115 to 230kV, Drake Conductor 57,500,000$
Line Description Costs
Daves Creek to Quartz Creek Upgrade 14.5 mi. Conductor to Rail 13,650,000$
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A.5.5 HVDC Connection Bernice Lake to Beluga, BES System
Table A-11 HVDC and BES System Costs
A.6 Southcentral Transmission Cost Analysis
Below are the detailed cost analyses for the different upgrades proposed for the Southcentral
transmission system.
A.6.1 Fossil Creek – Eklutna (Eklutna Express) Substation Additions
Table A-12 Eklutna Express Substation Addition Costs
A.6.2 Lorraine – Douglas Station Additions / Upgrades
Table A-13 Lorraine & Douglas Substation Addition Costs
A.6.3 Lorraine – Douglas 230 kV Line Addition
Table A-14 Lorraine – Douglas 230 kV Line Addition Costs
Line/Station Description Costs
100 MW , 80kV Converter 2-36mi. Submarine DC cables, connect to
Bernice 115kv & Beluga 138kV 185,310,000$
25 MW BES BES in Anchorage 30,200,000$
Total New HDVC Tie 215,510,000$
Station Description Costs
Fossil Creek New 115kV Ring Bus, 4 line terminals 10,678,568$
Eklutna Hydro New 115kV Ring Bus, 3 line terminals, 2 Xformers 9,692,340$
Total Substation Additions 20,370,908$
Station Description Costs
Lorraine New 230kV station w. 5 line Terminals, SVC 41,209,900$
Douglas New 230/138kV station w. 5 line terminals & 3 Xformers 32,056,081$
Total Substation improvements 73,265,981$
Line Description Costs
Lorraine to Douglas New 42 mi double circuit 230kV line 56,080,425$
Total Line Construction 56,080,425$
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A.7 Northcentral Transmission Cost Analysis
Below are the detailed cost analyses for the different upgrades proposed for the Northcentral
transmission system.
Table A-15 Northern Intertie Station Upgrade Costs
Table A-16 2nd Northern Intertie Line
Station Description Costs
Healy new 230kV station w. 5 line terminals (oper. 138kV) $37,528,380
Gold Creek new 230kV station w. 4 line terminals & 2 reactors $37,528,380
Total Substation improvements 75,056,760$
Line Description Costs
Douglas to Healy New 171 mi 230kV single circuit line 188,100,000$
Total Line Construction 188,100,000$
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B Prioritization Appendix
ID Task Name Start Finish Cost0Railbelt_ProjectsThu 1/9/14Fri 5/21/27$921,427....1Unconstrain BradleyWed 4/9/14Thu 7/14/22$388,171.362Bernice Lake‐Beluga HVDCWed 4/9/14Thu 6/28/18$185,310.003PermittingWed 4/9/14Tue 1/10/17$1,278.004EngineeringSat 4/12/14Thu 1/12/17$19,170.005ConstructionSun 9/27/15Thu 6/28/18$164,862.00625 MW/14 MWh BESSWed 4/9/14Thu 3/9/17$30,200.007DesignWed 4/9/14Wed 11/18/15$3,020.008ConstructionFri 11/21/14Thu 3/9/17$27,180.009University ‐ Quartz Creek UpgradeWed 5/9/18Mon 5/24/21$107,111.8110University‐Dave's 230 kVSat 6/9/18Mon 5/24/21$57,500.0111Operation ‐ 1 DesignSat 6/9/18Thu 11/22/18$1,916.6712Operation ‐ 1 ConstructionMon 12/3/18Fri 9/6/19$17,250.0013Operation ‐ II DesignSun 3/3/19Thu 8/15/19$1,916.6714Operation ‐ II ConstructionMon 8/26/19Fri 5/29/20$17,250.0015Operation ‐ III DesignMon 8/26/19Fri 2/7/20$1,916.6716Operation ‐ III ConstructioinTue 8/18/20Mon 5/24/21$17,250.0017Dave's Creek ‐ Quartz CreekSun 12/9/18Fri 2/7/20$13,650.0018DesignSun 12/9/18Thu 5/23/19$1,050.0019ConstructionMon 6/3/19Fri 2/7/20$12,600.0020University‐Dave's SubstationsWed 5/9/18Thu 7/9/20$34,608.0021Operation ‐ I DesignWed 5/9/18Tue 10/23/18$2,249.0022Operation ‐ I ConstructionSun 11/4/18Thu 10/3/19$15,055.0023Operation ‐ II DesignSat 1/26/19Thu 7/11/19$2,249.0024Operation ‐ II ConstructionSat 8/10/19Thu 7/9/20$15,055.0025Quartz Creek SubstationSun 12/9/18Thu 10/8/20$1,353.8026DesignSun 12/9/18Thu 8/15/19$135.3827ConstructionSun 8/18/19Thu 10/8/20$1,218.4228New Bradley‐Soldotna 115 kV LineSat 12/9/17Thu 7/14/22$65,549.5529Soldotna SubstationSat 2/9/19Thu 2/3/22$7,684.4130DesignSat 2/9/19Thu 4/2/20$768.4431ConstructionFri 4/3/20Thu 2/3/22$6,915.9732Bradley Lake SubstationThu 5/9/19Wed 6/2/21$2,865.1433DesignThu 5/9/19Wed 4/8/20$286.5134ConstructionThu 4/9/20Wed 6/2/21$2,578.636/28KenaiKenaiKenaiKenaiKenaiKenaiKenaiKenaiKenaiKenaiKenai2/7KenaiKenai7/9KenaiKenaiKenaiKenai10/8KenaiKenai2/3KenaiKenaiKenaiKenaiH1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H22013201420152016201720182019202020212022202320242025202620272028TaskSplitMilestoneSummaryProject SummaryExternal TasksExternal MilestoneInactive TaskInactive MilestoneInactive SummaryManual TaskDuration‐onlyManual Summary RollupManual SummaryStart‐onlyFinish‐onlyDeadlineProgressManual ProgressProject: Railbelt_ProjectsDate: Thu 3/13/14
ID Task Name Start Finish Cost35Bradley‐Soldotna 115 kV LineSat 12/9/17Thu 7/14/22$55,000.0036PermittingSat 12/9/17Thu 3/26/20$550.0037DesignFri 3/27/20Thu 2/25/21$5,500.0038ConstructionFri 2/26/21Thu 7/14/22$48,950.0039262 MWh Flexible Gas StorageTue 12/9/14Mon 1/4/16$18,200.0040DesignTue 12/9/14Mon 5/25/15$1,200.0041ConstructionTue 5/26/15Mon 1/4/16$17,000.0042Southcentral ProjectsThu 1/9/14Tue 6/11/19$61,580.8143Fossil Creek SubstationThu 1/9/14Thu 10/20/16$10,678.5744PermittingThu 1/9/14Wed 2/5/14$571.1845DesignWed 2/12/14Tue 8/26/14$925.3246ConstructionSat 8/29/15Thu 10/20/16$9,182.0747Eklutna SubstationWed 12/9/15Wed 8/23/17$9,692.3448DesignWed 12/9/15Tue 6/21/16$881.1249ConstructionThu 6/30/16Wed 8/23/17$8,811.2250Loraine SubstationWed 12/9/15Thu 10/19/17$21,985.9051DesignWed 12/9/15Tue 8/16/16$1,760.1752ConstructionFri 8/26/16Thu 10/19/17$20,225.7353Loraine Substation ‐ SVCWed 8/9/17Tue 6/11/19$19,224.0054Design/ConstructionWed 8/9/17Tue 6/11/19$19,224.0055Anchorage‐Healy ProjectsWed 4/9/14Mon 10/7/24$346,697.0556Communications UpgradeSun 2/19/17Mon 8/30/21$15,000.0057DesignSun 2/19/17Mon 8/30/21$3,000.0058ConstructionSun 4/1/18Mon 8/30/21$12,000.0059Douglas SubstationThu 2/9/17Fri 4/19/19$32,056.0860PermittingSat 4/1/17Fri 9/1/17$224.1761DesignThu 2/9/17Wed 10/18/17$2,914.1962ConstructionMon 3/26/18Fri 4/19/19$28,917.7263Douglas ‐Lorraine 230 kVWed 4/9/14Thu 12/6/18$56,080.4264PermittingWed 4/9/14Tue 9/23/14$150.0065DesignTue 8/9/16Mon 7/10/17$6,242.2366ConstructionFri 7/21/17Thu 12/6/18$49,688.1967Gold Creek SubstationMon 4/9/18Mon 8/10/20$17,932.1768DesignMon 4/9/18Fri 12/14/18$1,575.6569ConstructionTue 3/26/19Mon 8/10/20$16,356.527/14KenaiKenaiKenai1/4KenaiKenai10/20South CentralSouth CentralSouth Central8/23South CentralSouth Central10/19South CentralSouth Central6/11South Central4/19NorthernNorthern12/6NorthernNorthernNorthern8/10NorthernNorthernH1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H22013201420152016201720182019202020212022202320242025202620272028TaskSplitMilestoneSummaryProject SummaryExternal TasksExternal MilestoneInactive TaskInactive MilestoneInactive SummaryManual TaskDuration‐onlyManual Summary RollupManual SummaryStart‐onlyFinish‐onlyDeadlineProgressManual ProgressProject: Railbelt_ProjectsDate: Thu 3/13/14
ID Task Name Start Finish Cost70Douglas ‐ Healy 230 kv Line Tue 6/17/14Mon 12/23/19$1,881.0071PermittingTue 6/17/14Mon 12/23/19$1,881.0072Douglas‐Gold Creek 230 kVSat 3/9/19Tue 12/13/22$93,109.5073Line I ‐ DesignSat 3/9/19Thu 4/30/20$4,702.5074Line I ‐ ConstructionTue 6/2/20Mon 10/18/21$41,852.2575Line II ‐ DesignTue 6/2/20Mon 7/26/21$4,702.5076Line II ‐ ConstructionWed 7/28/21Tue 12/13/22$41,852.2577Gold Creek‐Healy 230 kVFri 4/9/21Tue 8/13/24$93,109.5078Line I ‐ DesignFri 4/9/21Thu 6/2/22$4,702.5079Line I ‐ ConstructionFri 6/3/22Thu 10/19/23$41,852.2580Line II ‐ DesignWed 2/2/22Tue 3/28/23$4,702.5081Line II ‐ ConstructionWed 3/29/23Tue 8/13/24$41,852.2582Healy SubstationWed 12/9/20Mon 10/7/24$37,528.3883PermittingWed 12/9/20Tue 10/11/22$1,454.0584DesignWed 10/12/22Tue 5/23/23$3,302.5885ConstructionTue 5/23/23Mon 10/7/24$32,771.7586Healy ‐ Fairbanks ProjectsWed 12/9/20Fri 5/21/27$106,778.5087Healy‐Gold Hill 230 kV T‐LineWed 12/9/20Wed 7/15/26$85,719.8988PermittingWed 12/9/20Tue 11/9/21$103.1589DesignThu 12/9/21Wed 10/11/23$1,031.5390Construction ‐ IThu 10/12/23Wed 9/11/24$28,195.0791Construction ‐ IIThu 9/12/24Wed 8/13/25$28,195.0792Construction ‐ IIIThu 8/14/25Wed 7/15/26$28,195.0793Northern Intertie Subs (Eva Creek, Wilson)Mon 12/9/24Fri 5/21/27$7,364.4794DesignMon 12/9/24Fri 11/7/25$771.6095ConstructionMon 7/21/25Fri 5/21/27$6,592.8796Healy‐Gold Hill Subs (Clear, Nenana, Ester, Gold Hill)Wed 3/9/22Thu 1/16/25$13,694.1497DesignWed 3/9/22Tue 2/7/23$1,369.4198ConstructionSat 3/18/23Thu 1/16/25$12,324.7312/23Northern12/13NorthernNorthernNorthernNorthern8/13NorthernNorthernNorthernNorthern10/7NorthernNorthernNorthern7/15NorthernNorthernNorthernNorthernNorthern5/21NorthernNorthern1/16NorthernNorthernH1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H2H1H22013201420152016201720182019202020212022202320242025202620272028TaskSplitMilestoneSummaryProject SummaryExternal TasksExternal MilestoneInactive TaskInactive MilestoneInactive SummaryManual TaskDuration‐onlyManual Summary RollupManual SummaryStart‐onlyFinish‐onlyDeadlineProgressManual ProgressProject: Railbelt_ProjectsDate: Thu 3/13/14
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C Pre-Watana Detailed Cost Estimates
C.1 Bradley Constraints
Table C-1 Bernice Lake-Beluga HVDC
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Table C-2 25 MW/14 MWh BESS
Table C-3 Bradley-Soldotna 115 kV – Line Sections
Location MW MWh BESS Costs Sub/Connection Costs Total Costs
Anchorage 25 14 24,400,000$ 5,800,000$ 30,200,000$
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 C-4 Bradley Substation
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Table C-5 Soldotna Substation
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Table C-6 Dave’s Creek - Hope 230kV Line
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Table C-7 Hope – Portage 230kV Line
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Table C-8 Portage - Girdwood 230kV Line
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Table C-9 Girdwood - Indian 230kV Line
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Table C-10 Indian - University 230kV Line
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Table C-11 Dave’s Creek Substation
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Table C-12 Summit & Hope Substations
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Table C-13 Portage Substation
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Table C-14 Girdwood Substation
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Table C-15 Indian Substation
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Table C-16 University Substation
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Table C-17 Quartz Creek Substation
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Table C-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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C.2 Southcentral / Overall
Table C-19 Fossil Creek Substation
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Table C-20 Eklutna Hydro Substation
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C.3 Northern System
Table C-21 Lorraine Substation
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Table C-22 Douglas Substation
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Table C-23 Healy Substation
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Table C-24 Gold Creek Substation
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Table C-25 Lorraine-Douglas 230 kV Line
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Table C-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 C-27 Healy – Gold Hill 230 kV Line
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Table C-28 Clear and Eva Creek Substations
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Table C-29 Nenana Substation
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Table C-30 Ester Substation
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Table C-31 Gold Hill and Wilson Substations
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D Post-Watana Detailed Cost Estimates
D.1 Watana Interconnection
Table D-1 Watana - Gold Creek 230 kV lines
Description Quantity Unit
Material
Cost
($1,000)
Labor
Cost
($1,000)
Material
& Labor
Cost
($1,000)
Total
Cost
($1,000)
Structures 185 ea $40.0 $28.3 $68.3 $12,667
Foundations 411 Ea $5.2 $21.1 $26.3 $10,782
Conductor 35 crkt mi $88.9 $166.8 $255.7 $8,948
Other* 35 crkt mi $21.4 $83.5 $104.9 $3,673
50% Road $4,328
Subtotal $40,398
Mob/Demob @15% 6,060
Engineering, Management, Permitting @15% Subtotal 6,060
Estimated Construction Cost $52,518
Contingency @20% Total $10,504
Estimated Summer Construction Cost 63,021
Winter Construction Cost adder @ 25% of Subtotal $10,100
Estimated Winter Construction Cost $73,121
Circuit #1 100% $73,121
Circuit #2 (20% reduction for second circuit) 80% $58,497
Circuit #3 (20% reduction for third circuit) 80% $58,497
Total $190,115
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Table D-2 Healy - Gold Creek - Douglas 230 kV operation
D.2 Southcentral
Table D-3 Southcentral Upgrades
D.3 75 MW Energy Storage
Table D-4 Energy Storage Project Costs
Description Total Costs
Operational Conversion 1,000,000$
Cantwell, Steven, Douglas 230 kV Transformers 5,250,000$
Total 6,250,000$
Lorraine SVC upgrade to -75 / +50 MVAR 45.0$
Douglas - Teeland 115 kV operation 7.0$
Teeland 10 MVAr Capacitors 2.5$
Total 54.5$
Project Total Costs
(Millions)
Location MW MWh BESS Costs Sub/Connection Costs Total Costs
GVEA 30 17 29,280,000$ 5,800,000$ 35,080,000$
Anchorage 25 14 24,400,000$ 5,800,000$ 30,200,000$
HEA 20 11 19,520,000$ 5,800,000$ 25,320,000$
Total 90,600,000$
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E Economic Analysis Sensitivity
Sensitivity Analyses
Notes:
NS0: All transmission upgrades
NS4: No transmission upgrades
S2: Case NS0 + remove DC tie
Negative transactions are sales and positive transactions are purchases.
GVEA LNG is priced at $3.5 above cook inlet gas
Base Case
Production Costs $,000 Net Transactions GWh GVEA CC & CT GWh
NS0 NS4 Savings NS0 NS4 NS0 NS4
System 391,193 531,125 139,932 0 ‐3 0.0 7.8 NP 1
GVEA 169,241 220,946 51,705 606 121 0.0 4.0 NP 2
MEA 61,581 84,103 22,521 ‐129 ‐17 1.5 420.2 NPCC
ML&P 54,204 89,886 35,683 ‐291 ‐106 0.0 7.2 Z 1
CEA + SES 87,308 89,069 1,761 41 ‐6 0.0 13.3 Z 2
HEA 18,859 47,122 28,263 ‐227 4
Sensitivity 1: Fairbanks Area Load Development ‐ add 100 MW to GVEA's peak load (60 MW off‐peak.)
Production Costs $,000 Net Transactions GWh GVEA CC & CT GWh
NS0‐1 NS4‐1 Savings NS0‐1 NS4‐1 NS0‐1 NS4‐1
System 483,161 792,318 309,157 0 ‐23 0.0 43.2 NP 1
GVEA 379,769 479,464 99,695 1422 524 0.0 30.3 NP 2
MEA 36,499 84,625 48,126 ‐310 ‐80 3.1 458.9 NPCC
ML&P ‐25,343 92,028 117,371 ‐897 ‐365 0.0 86.5 Z 1
CEA + SES 84,053 87,952 3,899 29 ‐39 0.0 129.6 Z 2
HEA 8,183 48,250 40,067 ‐243 ‐62
Sensitivity 1a: Fairbanks Area LNG ‐ allow Zehnder, North Pole and North Pole combined cycle to use LNG.
Production Costs $,000 Net Transactions GWh GVEA CC & CT GWh
NS0‐1a NS4‐1a Savings NS0‐1a NS4‐1a NS0‐1a NS4‐1a
System 384,022 442,103 58,081 0 0 0.0 36.5 NP 1
GVEA 107,176 132,152 24,976 309 1 0.0 15.3 NP 2
MEA 77,456 84,028 6,572 61 0 283.4 413.8 NPCC
ML&P 74,125 89,491 15,366 ‐216 ‐15 0.0 41.4 Z 1
CEA + SES 91,999 89,358 ‐2,641 43 2 0.0 70.6 Z 2
HEA 33,267 47,074 13,808 ‐197 13
Sensitivity 1aa: Fairbanks Area LNG ‐ allow North Pole combined cycle to use LNG.
Production Costs $,000 Net Transactions GWh GVEA CC & CT GWh
NS0‐1aa NS4‐1aa Savings NS0‐1aa NS4‐1aa NS0‐1aa NS4‐1aa
System 384,041 459,261 75,220 0 ‐3 0.0 7.0 NP 1
GVEA 130,697 149,295 18,598 309 120 0.0 5.4 NP 2
MEA 71,670 84,054 12,384 61 ‐17 283.1 419.8 NPCC
ML&P 65,744 89,516 23,771 ‐216 ‐104 0.0 7.8 Z 1
CEA + SES 89,440 89,143 ‐297 43 ‐6 0.0 14.3 Z 2
HEA 26,490 47,254 20,764 ‐197 4
Sensitivity 1b: Fairbanks Area Load Development and LNG ‐ add 100 MW to GVEA's peak load (60 MW off‐peak) and allow Zehnder,
North Pole and North Pole combined cycle to use LNG.
Production Costs $,000 Net Transactions GWh GVEA CC & CT GWh
NS0‐1b NS4‐1b Savings NS0‐1b NS4‐1b NS0‐1b NS4‐1b
System 472,091 573,985 101,894 0 0 0.2 409.5 NP 1
GVEA 211,282 263,606 52,324 953 20 0.0 123.7 NP 2
MEA 70,780 84,045 13,265 ‐258 ‐4 426.3 436.3 NPCC
ML&P 66,822 89,555 22,734 ‐495 ‐29 0.0 167.7 Z 1
CEA + SES 92,179 89,623 ‐2,556 39 0 0.0 170.8 Z 2
HEA 31,029 47,156 16,127 ‐239 12
Sensitivity 1bb: Fairbanks Area Load Development and LNG ‐ add 100 MW to GVEA's peak load (60 MW off‐peak) and allow North Pole
combined cycle to use LNG.
Production Costs $,000 Net Transactions GWh GVEA CC & CT GWh
NS0‐1bb NS4‐1bb Savings NS0‐1bb NS4‐1bb NS0‐1bb NS4‐1bb
System 472,223 716,967 244,745 0 ‐22 0.0 47.2 NP 1
GVEA 335,685 403,512 67,827 954 519 0.0 29.7 NP 2
MEA 35,919 84,618 48,699 ‐260 ‐77 426.4 459.0 NPCC
ML&P 12,765 92,706 79,941 ‐494 ‐363 0.0 92.5 Z 1
CEA + SES 84,284 87,886 3,602 39 ‐39 0.0 132.3 Z 2
HEA 3,570 48,244 44,674 ‐239 ‐62
Sensitivity 1c: Fairbanks Area Load Decline ‐ 44 MW is subtracted from GVEA's load in every hour due to Ft Knox closing.
Production Costs $,000 Net Transactions GWh GVEA CC & CT GWh
NS0‐1c NS4‐1c Savings NS0‐1c NS4‐1c NS0‐1c NS4‐1c
System 342,794 460,528 117,734 0 0 0.0 1.0 NP 1
GVEA 84,386 157,744 73,357 204 ‐7 0.0 0.2 NP 2
MEA 67,984 78,366 10,381 76 2 0.0 348.3 NPCC
ML&P 69,636 88,484 18,848 ‐173 ‐10 0.0 2.3 Z 1
CEA + SES 89,899 89,120 ‐780 44 3 0.0 10.1 Z 2
HEA 30,888 46,815 15,927 ‐151 12
Sensitivity 1d: Fairbanks Area Load Decline and LNG ‐ 44 MW is subtracted from GVEA's load in every hour due to Ft Knox closing
and allow Zehnder, North Pole and North Pole combined cycle to use LNG.
This is a most unlikely scenario.
Production Costs $,000 Net Transactions GWh GVEA CC & CT GWh
NS0‐1d NS4‐1d Savings NS0‐1d NS4‐1d NS0‐1d NS4‐1d
System 337,802 389,303 51,501 0 1 0.0 7.2 NP 1
GVEA 60,670 85,976 25,306 ‐68 ‐20 0.0 3.4 NP 2
MEA 71,465 78,256 6,791 266 4 263.7 351.7 NPCC
ML&P 76,477 88,842 12,365 ‐160 ‐2 0.0 5.5 Z 1
CEA + SES 92,052 89,166 ‐2,886 48 5 0.0 12.5 Z 2
HEA 37,138 47,063 9,925 ‐86 14
Sensitivity 1dd: Fairbanks Area Load Decline and LNG ‐ 44 MW is subtracted from GVEA's load in every hour due to Ft Knox closing
and allow North Pole combined cycle to use LNG.
This is a most unlikely scenario.
Production Costs $,000 Net Transactions GWh GVEA CC & CT GWh
NS0‐1dd NS4‐1dd Savings NS0‐1dd NS4‐1dd NS0‐1dd NS4‐1dd
System 337,802 398,401 60,599 0 0 0.0 0.8 NP 1
GVEA 64,532 95,456 30,924 ‐68 ‐9 0.0 0.3 NP 2
MEA 70,226 78,309 8,083 266 3 263.7 350.4 NPCC
ML&P 75,419 88,727 13,308 ‐160 ‐9 0.0 1.8 Z 1
CEA + SES 91,495 89,001 ‐2,494 48 3 0.0 10.6 Z 2
HEA 36,130 46,908 10,778 ‐86 12
Sensitivity 2: Companies may not claim duct firing to meet their spinning reserve requirements but are also not required to declare
the duct firing as part of their spinning reserve obligations.
Production Costs $,000 Net Transactions GWh
NS0‐2 NS4‐2 Savings NS0‐2 NS4‐2
System 389,269 537,735 148,466 0 ‐3
GVEA 168,764 221,031 52,267 587 123
MEA 67,706 84,109 16,403 9 ‐17
ML&P 41,489 91,138 49,650 ‐455 ‐100
CEA + SES 91,645 91,094 ‐551 92 ‐5
HEA 19,665 50,362 30,697 ‐233 ‐5
Sensitivity 3: Reduce the Railbelt spinning reserve by 75% of the new Anchorage area BESS rating.
Note: This case only applies to cases where the system is pooled. The effect has been demonstrated for cases NS0 and S2.
Production Costs $,000 Net Transactions GWh
NS0 NS0‐3 Savings NS0 NS0‐3
System 391,193 390,987 206 0 0
GVEA 169,241 169,183 59 606 606
MEA 61,581 62,155 ‐574 ‐129 ‐117
ML&P 54,204 53,553 650 ‐291 ‐299
CEA + SES 87,308 87,374 ‐66 41 42
HEA 18,859 18,721 138 ‐227 ‐231
Production Costs $,000 Net Transactions GWh
S2 S2‐3 Savings S2 S2‐3
System 401,247 401,599 ‐352 0 0
GVEA 171,139 171,131 8 597 596
MEA 60,527 60,705 ‐178 ‐227 ‐224
ML&P 39,363 39,351 11 ‐615 ‐619
CEA + SES 86,406 86,256 150 17 14
HEA 43,813 44,156 ‐343 228 232
Sensitivity 4: Reduce the total regulation in the Raillbelt to 10 MW for load and 15 MW for renewable regulation.
Note: This case only applies to cases where the system is pooled.
The effect of this has been demonstrated by comparing NS0 with reduced regulation to NS4.
Production Costs $,000 Net Transactions GWh
NS0‐4 NS4 Savings NS0‐4 NS4
System 389,617 531,125 141,508 0 ‐3
GVEA 168,624 220,946 52,322 598 121
MEA 63,191 84,103 20,911 ‐101 ‐17
ML&P 50,747 89,886 39,140 ‐331 ‐106
CEA + SES 87,726 89,069 1,343 59 ‐6
HEA 19,329 47,122 27,793 ‐225 4
Sensitivity 5: Use the Hilcorp Consent Decree Pricing as the basis for gas prices going forward.
(Beginning with the 2018 price in the CEA contract, prices were escalated through 2020.
With allowance for storage or swing gas and transportation, the assumed pricing
increased by $0.67 in ML&P, CEA, and HEA and $0.60 in MEA.)
Production Costs $,000 Net Transactions GWh
NS0‐5 NS4‐5 Savings NS0‐5 NS4‐5
System 412,836 551,580 138,744 0 ‐3
GVEA 170,999 222,258 51,258 606 120
MEA 66,275 88,041 21,767 ‐134 ‐18
ML&P 59,731 95,655 35,924 ‐295 ‐103
CEA + SES 92,609 95,220 2,611 41 ‐7
HEA 23,221 50,406 27,185 ‐218 5
Alaska Energy Authority
Pre/Post - Watana Transmission Study
March 17, 2014
Page 144
F Production Modeling Presentation
Railbelt Transmission StudiesSlater ConsultingAugust 2013
Transmission Study OverviewPurpose:To evaluate the impact of various proposed transmission upgrades on Railbelt production costs.Time Frame:The transmission study was performed for 2020. All transmission upgrades, additions and retirements to the system that are currently planned were included.Fuel Prices:Gas prices are based on $6.50/mmbtu in 2012 in Anchorage, escalated at 4% annually. Other fuel prices are based on actual 2012 prices and escalated according to EIA forecasts.Slater ConsultingAugust 2013
Proposed Transmission UpgradesSouthern:AC upgrades Quartz to UniversityAdditional conductor from Quartz Creek to Daves Creek230 kv upgrade from Daves Creek to UniversityDC tie from Bernice to Beluga2nd line from Bradley to SoldotnaAnchorage BatteryNorthern:230 kv Lake Lorraine to Douglas upgradeDouglas to Healy upgradeHealy to Fairbanks upgrade Slater ConsultingAugust 2013
Description of PROMOD CasesSlater ConsultingAugust 2013
PROMOD CasesCase NS0: All transmission upgradesCases S1–S4: Southern transmission upgradesCases N1–N3: Northern transmission upgradesCase NS4: No transmission upgradesSlater ConsultingAugust 2013
All Transmission Upgrades CaseCase NS0▪The system operates as a single pool with a single system reserve requirement▪The interface limit for Kenai North is 125 MW▪Anchorage Battery is 25 MW▪Bradley Spin is 27 MWSlater ConsultingAugust 2013
Southern Transmission CasesCase S1: Case NS0 + remove AC upgrades from Quartz Creek to University▪The system operates as a single pool with a single system reserve requirement▪The interface limit for Kenai North is 100 MW▪Anchorage Battery is 25 MW▪Bradley Spin is 27 MWCase S2: Case NS0 + remove DC tie▪The system operates as a single pool with a single system reserve requirement▪The interface limit for Kenai North is 75 MW▪Anchorage Battery is 75 MW▪Bradley Spin is 27 MW Slater ConsultingAugust 2013
Southern Transmission CasesCase S3: Case S1 + Case S2▪The system effectively operates as 2 pools (HEA and the rest of the Railbelt), with HEA providing its reserves separately from the rest of the system.▪The interface limit for Kenai North is 75 MW▪Bradley Spin is 27 MW▪Commitment/Dispatch Hurdles exist between all other companies and HEASlater ConsultingAugust 2013
Southern Transmission CasesCase S4: Case S3 + remove 2nd line from Bradley to Soldotna▪The system effectively operates as 2 pools (HEA and the rest of the Railbelt), with HEA providing its reserves separately from the rest of the system.▪The interface limit for Kenai North is 75 MW▪Bradley Spin is 10 MW▪Commitment/Dispatch Hurdles exist between all other companies and HEASlater ConsultingAugust 2013
Northern Transmission CasesCase N1: Case NS0 + remove Healy to Fairbanks upgrade ▪The system operates as a single pool with a single system reserve requirement▪The interface limit for Kenai North is 125 MW▪Anchorage Battery is 25 MW▪Bradley Spin is 27 MW▪NPCC is must run Oct through MarSlater ConsultingAugust 2013
Northern Transmission CasesCase N2: Case N1 + remove Douglas to Healy upgrade▪The system operates as two pools (GVEA and the rest of the Railbelt), with GVEA providing its reserves separately from the rest of the system▪The interface limit for Kenai North is 125 MW▪The interface limit from Stevens to Cantwell is 75 MW▪Anchorage Battery is 25 MW▪Bradley Spin is 27 MW▪NPCC is must run Oct through Mar▪Commitment/Dispatch Hurdles exist between GVEA and the rest of the system Slater ConsultingAugust 2013
Northern Transmission CasesCase N3: Case N2 + remove 230 kv upgrade from Lake Lorraine to Douglas▪The system operates as two pools (GVEA and the rest of the Railbelt), with GVEA providing its reserves separately from the rest of the system▪The interface limit for Kenai North is 125 MW▪The interface limit from Stevens to Cantwell is 75 MW▪Anchorage Battery is 25 MW▪Bradley Spin is 27 MW▪NPCC is must run Oct through Mar▪Commitment/Dispatch Hurdles exist between GVEA and the rest of the system Slater ConsultingAugust 2013
No Transmission Upgrades CaseCase NS4▪The system operates as a 5 separate companies, with each company providing its own reserves▪The interface limit for Kenai North is 75 MW▪The interface limit from Stevens to Cantwell is 75 MW▪NPCC is must run Oct through Mar▪Bradley Spin is 10 MW▪Commitment/Dispatch Hurdles exist between all companiesSlater ConsultingAugust 2013
Railbelt PROMOD ResultsSlater ConsultingAugust 2013
Railbelt Annual Production Costs ($,000)Case NS0 391,193Case S1 394,387Case S2 401,247Case S3 449,233Case S4 453,066Case N1 413,869Case N2 494,050Case N3 495,500Case NS4 531,125Slater ConsultingAugust 2013
Value of Individual Upgrades ($,000)All Upgrades 139,932Case S1 3,194Case S2 10,054Case S3 58,039Case S4 3,833Total for Southern Upgrades: 61,873Case N1 22,675Case N2 80,181Case N3 1,450Total for Northern Upgrades: 104,306Slater ConsultingAugust 2013
Company PROMOD ResultsSlater ConsultingAugust 2013
GVEA Annual Production Costs ($,000)Case NS0 169,241 Case S1 170,236 Case S2 171,139 Case S3 143,447 Case S4 145,287 Case N1 182,385 Case N2 212,646 Case N3 213,962 Case NS4 220,946Slater ConsultingAugust 2013
MEA Annual Production Costs ($,000)Case NS0 61,581 Case S1 59,410 Case S2 60,527 Case S3 80,880 Case S4 80,664 Case N1 65,167 Case N2 77,965 Case N3 78,039 Case NS4 84,103 Slater ConsultingAugust 2013
ML&P Annual Production Costs ($,000)Case NS0 54,204 Case S1 41,887 Case S2 39,363 Case S3 94,518 Case S4 95,192 Case N1 58,627 Case N2 76,162 Case N3 76,141 Case NS4 89,886 Slater ConsultingAugust 2013
CEA/SES Annual Production Costs ($,000)Case NS0 87,308 Case S1 87,083 Case S2 86,406 Case S3 84,181 Case S4 84,439 Case N1 87,424 Case N2 92,037 Case N3 92,105 Case NS4 89,069 Slater ConsultingAugust 2013
HEA Annual Production Costs ($,000)Case NS0 18,859 Case S1 35,771 Case S2 43,813 Case S3 46,207 Case S4 47,484 Case N1 20,265 Case N2 35,240 Case N3 35,253 Case NS4 47,122 Slater ConsultingAugust 2013
GVEA January 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsAurora 17.9 744 0 17.9 744 0Healy 1 17.9 671 2 18.1 671 2Healy 2 37.8 744 0 39.2 744 0NPCC 0.0 0 0 41.9 744 0CT 0.0 0 0 1.8 238 101Diesel 0.0 0 0 0.0 0 0Bradley 4.9 4.9Eva Creek 10.8 10.8Inter‐Co Purchases 55.4 8.9Slater ConsultingAugust 2013
GVEA July 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsAurora 17.0 709 3 17.0 709 3Healy 1 20.1 744 0 20.1 744 0Healy 2 26.7 504 1 26.3 504 1NPCC 0.0 0 0 30.2 744 0CT 0.0 0 0 5.8 1030 136Diesel 0.0 0 0 0.0 2 1Bradley 5.9 5.9Eva Creek 4.6 4.6Inter‐Co Purchases 49.5 13.0Slater ConsultingAugust 2013
MEA January 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsEklutna 1‐10 102.5 6874 272 81.5 6246 187Bradley 4.0 4.0Eklutna Lk 1.9 1.9Inter‐Co Purchases 1.8 0.0Inter‐Co Sales‐23.8‐1.5Slater ConsultingAugust 2013
MEA July 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsEklutna 1‐10 70.6 5622 204 56.3 4930 346Bradley 4.8 4.8Eklutna Lk 2.4 2.4Inter‐Co Purchases 5.9 0.1Inter‐Co Sales‐22.8‐3.1Slater ConsultingAugust 2013
ML&P January 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsPlant 1 10.4 424 43 0.7 46 10Plant 2 4.7 149 4 0.0 0 0Plant 2A 84.9 744 0 83.4 744 0SAPP 41.8 744 0 40.0 744 0Bradley 7.5 7.5Eklutna Lk 6.0 6.0Inter‐Co Purchases 0.3 0.0Inter‐Co Sales‐25.2‐7.4Slater ConsultingAugust 2013
ML&P July 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsPlant 1 16.7 648 19 13.1 599 26Plant 2 29.1 425 6 36.8 621 7Plant 2A 20.6 192 1 16.2 192 1SAPP 35.5 744 0 34.2 744 0Bradley 9.0 9.0Eklutna Lk 7.5 7.5Inter‐Co Purchases 10.1 0.0Inter‐Co Sales‐19.8‐8.3Slater ConsultingAugust 2013
CEA/SES January 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsBeluga 1&2 0.0 0 0 0.0 0 0Beluga 3&5 0.0 0 0 19.1 744 0Beluga 6&7 0.0 0 0 0.0 0 0SAPP 97.6 744 0 93.4 744 0Bradley 9.1 9.1Eklutna Lk 3.4 3.4Cooper 4.7 4.7Fire Island 5.8 5.8Inter‐Co Purchases 14.9 0.0Inter‐Co Sales‐0.6‐0.6Slater ConsultingAugust 2013
CEA/SES July 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsBeluga 1&2 0.0 0 0 0.8 199 25Beluga 3&5 0.0 0 0 1.1 164 17Beluga 6&7 0.0 0 0 0.0 0 0SAPP 82.8 744 0 79.9 744 0Bradley 10.9 10.9Eklutna Lk 4.2 4.2Cooper 4.6 4.6Fire Island 3.5 3.5Inter‐Co Purchases 6.3 0.2Inter‐Co Sales‐9.0‐1.8Slater ConsultingAugust 2013
HEA January 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsBernice 2 0.0 0 0 0.4 56 7Bernice 3 0.0 0 0 6.1 464 8Bernice 4 0.0 0 0 2.7 186 6Nikiski 36.9 728 1 37.4 728 1Soldotna 33.7 744 1 1.4 58 5Bradley 3.5 3.5Inter‐Co Purchases 0.6 1.1Inter‐Co Sales‐23.5‐0.8Slater ConsultingAugust 2013
HEA July 2020 DispatchCase NS0 Case NS4Generation (GWH)Hours on LineNumber of StartsGeneration (GWH)Hours on LineNumber of StartsBernice 2 0.0 0 0 0.5 131 9Bernice 3 0.0 0 0 2.3 165 14Bernice 4 0.0 0 0 0.8 56 4Nikiski 34.6 739 1 33.6 739 1Soldotna 27.2 679 3 5.6 231 17Bradley 4.2 4.2Inter‐Co Purchases 0.8 1.4Inter‐Co Sales‐21.1‐2.0Slater ConsultingAugust 2013
QUESTIONSSlater ConsultingAugust 2013
Alaska Energy Authority
Pre/Post - Watana Transmission Study
March 17, 2014
Page 178
G Pre-Watana Simulation Results
The contents of Appendix G can be found in a separate document titled Appendix G: Pre-
Watana Simulation Results.
Alaska Energy Authority
Pre/Post - Watana Transmission Study
March 17, 2014
Page 179
H Post-Watana Simulation Results
The contents of Appendix H can be found in a separate document titled Appendix H: Post-
Watana Simulation Results.
Alaska Energy Authority
Pre/Post - Watana Transmission Study
March 17, 2014
Page 180
I Kenai Transmission Study
WWW.EPSINC.COM
PHONE (425) 883-2833 4020 148th AVE NE, SUITE C, REDMOND, WA 98052 FAX (425) 883-0464
PHONE (907) 522-1953 3305 ARCTIC BLVD., SUITE 201, ANCHORAGE, AK 99503 FAX (907) 522-1182
Alaska Energy Authority
Kenai Transmission Study
Project # 11-0424
March 7, 2014
David A. Meyer, P.E.
Dr. James W. Cote, Jr. P.E.
David W. Burlingame, P.E.
Alaska Energy Authority
Kenai Transmission Study
Page ii
Summary of Changes
Revision Revision Date Revision Description
0 June 4, 2012 Initial release to AEA
1 March 7, 2014 Final release to AEA
Table of Contents
Executive Summary ........................................................................................................ v
1 Introduction .............................................................................................................. 1
2 Kenai Export and Constraints .................................................................................. 1
3 Generation Configuration ......................................................................................... 2
4 Transmission Options .............................................................................................. 3
4.1 Upgrade Dave’s Creek – University Tie to 230 kV ............................................................ 3
4.2 New HVAC Kenai Intertie .................................................................................................. 3
4.3 100 kV HVDC Intertie Beluga – Bernice Lake ................................................................... 4
4.4 Kenai Transmission Upgrades .......................................................................................... 5
4.5 Transmission Configurations ............................................................................................. 5
5 Power flow Analysis ................................................................................................. 5
6 Loss Analysis ........................................................................................................... 7
7 Stability Analysis ...................................................................................................... 9
7.1 DC Size Analysis – Kenai Tie Trip .................................................................................. 10
7.2 Kenai Tie Analysis – DC / Southern Intertie Trip ............................................................. 11
8 Cost Analysis ......................................................................................................... 12
9 Recommendations ................................................................................................. 13
9.1 N-1-1 Analysis – Recommended Transmission Configurations ...................................... 15
10 Conclusions ........................................................................................................ 16
Appendix A – Load Analysis (MW) IOC versus RIRP .................................................... 17
Appendix B – Generation Dispatches ............................................................................ 18
Appendix C – Power Flow Results ................................................................................ 24
Appendix D – Transient Analysis Contingency List ....................................................... 28
Appendix E – Transient Analysis – Winter Peak ........................................................... 29
Appendix F – Transient Analysis – Summer Peak ........................................................ 33
Appendix G – Transient Analysis – Summer Valley ...................................................... 37
Appendix H – DC Size Analysis Detailed Results ......................................................... 41
Appendix I – DC / Southern Intertie Trip Detailed Results ............................................. 43
Appendix J – Costs of Individual Line Improvements .................................................... 44
J.1 Upgrade Existing Kenai Tie to 230 kV ............................................................................ 44
J.2 Modified 115 kV Kenai Transmission Substations .......................................................... 44
J.3 New 115 kV Line – Bradley Lake to Soldotna ................................................................. 45
J.4 New 115 kV Line – Soldotna to Quartz Creek ................................................................ 45
J.5 New 115 kV Line – Bradley Lake to Quartz Creek .......................................................... 45
J.6 New 115 kV Line – Quartz Creek to Dave’s Creek ......................................................... 45
J.7 Reconductor Existing 115 kV Diamond Ridge – Soldotna Line ...................................... 46
J.8 New Kenai Intertie – 230 kV AC ...................................................................................... 46
J.9 New Kenai Intertie – 138 kV AC ...................................................................................... 47
Alaska Energy Authority
Kenai Transmission Study
Page iii
J.10 New Kenai Intertie – 100 kV HVDC Bernice - Beluga ..................................................... 47
List of Tables
Table I. Description – Recommendations, 115 kV Kenai Tie ...................................................... vi
Table II. Description – Recommendations, 230 kV Kenai Tie..................................................... vi
Table 4.2 Proposed Tesoro route per Southern Intertie FEIS ......................................................... 4
Table 4.1 Transmission Configurations .......................................................................................... 5
Table 5.1 Conductor Ratings .......................................................................................................... 6
Table 5.2 Power Flow Results Summary ........................................................................................ 7
Table 6.1 Loss Analysis Results – 99 MW Export Comparisons ................................................... 8
Table 6.2 Loss Analysis Results – 125 MW Export Comparisons ................................................. 9
Table 7.1 Transient Stability Results Summary ........................................................................... 10
Table 8.1 Possible Transmission Configurations .......................................................................... 12
Table 9.1 Preferred Transmission Configurations ........................................................................ 13
Table 9.2 Preferred Transmission Configurations - Costs ............................................................ 13
Table 9.3 Preferred Transmission Configurations – Loss Comparisons ...................................... 14
Table 9.4 N-1-1 Kenai Export Limits - Recommend Transmission Configurations .................... 15
Table A.1 2020 Seasonal Base Case Load from IOC ................................................................... 17
Table A.2 RIRP Winter Peak Loads ............................................................................................. 17
Table A.3 RIRP Summer Peak Loads ........................................................................................... 17
Table A.4 RIRP Summer Valley Loads ........................................................................................ 17
Table B.1 Generation Dispatch – Base, Upgrades, and 3rd Bradley Lake ................................... 19
Table B.2 Generation Dispatch - 3rd Bradley Lake - Sensitivity ................................................. 20
Table B.3 Generation Dispatch - Watana and no 3rd Bradley Lake .............................................. 21
Table B.4 Generation Dispatch - Watana and the 3rd Bradley Lake ............................................. 22
Table C.1 Power flow – Summer Peak – Case B – Bradley and Cooper Export ......................... 24
Table C.2 Power flow – Summer Peak – Case C – 3rd Bradley Lake Unit added ........................ 25
Table C.3 Power flow – Summer Valley – Case B – Bradley and Cooper Export ...................... 26
Table C.4 Power flow – Summer Valley – Case C – 3rd Bradley Lake Unit added ..................... 27
Table D.1 Stability Contingency List ........................................................................................... 28
Table E.1 Stability Results – Winter Peak – Cases A, B, and C .................................................. 29
Table E.2 Stability Results – Winter Peak –Cases C1 and C2 ..................................................... 30
Table E.3 Stability Results – Winter Peak – Cases D and E ........................................................ 31
Table E.4 Stability Results – Winter Peak – Cases F, G, and H ................................................... 32
Table F.1 Stability Results – Summer Peak – Cases A, B, and C ................................................ 33
Table F.2 Stability Results – Summer Peak – Cases C1 and C2 .................................................. 34
Table F.3 Stability Results – Summer Peak – Cases D and E ...................................................... 35
Table F.4 Stability Results – Summer Peak – Cases F, G, and H ................................................ 36
Table G.1 Stability Results – Summer Valley – Cases A, B, and C ............................................. 37
Table G.2 Stability Results – Summer Valley – Cases C1, C2 .................................................... 38
Table G.3 Stability Results – Summer Valley – Cases D and E ................................................... 39
Table G.4 Stability Results – Summer Valley – Cases F, G, and H ............................................. 40
Table H.1 – Kenai Trip Analysis – Summer Valley ..................................................................... 41
Table H.2 – Kenai Trip Analysis – Summer Peak ........................................................................ 41
Table H.2 – Kenai Trip Analysis – Winter Peak .......................................................................... 42
Table I.1 – DC / Southern Intertie Trip Results ............................................................................ 43
Alaska Energy Authority
Kenai Transmission Study
Page iv
Table J.1 Conductor Costs – Upgrade Kenai Tie to 230 kV ........................................................ 44
Table J.2 Substation Costs – Upgrade Kenai Tie to 230 kV ........................................................ 44
Table J.3 Total Costs – Upgrade Kenai Tie to 230 kV ................................................................. 44
Table J.4 Cost Analysis – Kenai Transmission Substations ......................................................... 45
Table J.5 Cost Analysis – New 115 kV line, Bradley Lake - Soldotna ........................................ 45
Table J.6 Cost Analysis – New 115 kV line, Soldotna – Quartz Creek ....................................... 45
Table J.7 Cost Analysis – New 115 kV line, Bradley – Quartz Creek ......................................... 45
Table J.8 Cost Analysis – New 115 kV line, Quartz Creek – Dave’s Creek ................................ 46
Table J.9 Cost Analysis – Reconductor 115 kV line, Diamond Ridge - Soldotna ....................... 46
Table J.10 Conductor Costs – New 230 kV AC Kenai Intertie .................................................... 46
Table J.11 Compensation Costs – New 230 kV AC Kenai Intertie .............................................. 46
Table J.12 Total Costs – New 230 kV AC Kenai Intertie ............................................................ 46
Table J.13 Conductor Costs – New 138 kV AC Kenai Intertie .................................................... 47
Table J.14 Compensation Costs – New 138 kV AC Kenai Intertie .............................................. 47
Table J.15 Total Costs – New 138 kV AC Kenai Intertie ............................................................ 47
Table J.16 Cost Analysis – New 100 kV HVDC Kenai Intertie ................................................... 48
Alaska Energy Authority
Kenai Transmission Study
Page v
Executive Summary
Electric Power Systems (“EPS”) has completed the technical studies to determine the impacts
to the central and southern utilities due to changes in the Kenai generation and transmission
system since the completion of the 2010 Regional Integrated Resource Plan (“RIRP”)
administered by the Alaska Energy Authority (“AEA”). The studies and analysis included in the
RIRP required updating to reflect these generation changes and to analyze the impact these
changes would have on the transmission system recommendations included in the RIRP. The
studies included power flow contingency analysis, loss analysis, and transient stability
contingency analysis.
The focus of the study was to provide unconstrained access to Bradley Lake power and energy
with its current capacity as well as the future possibility of a third turbine at the Bradley Lake
plant. For purposes of this study, the current capacity of the plant is assumed to be 115 MW.
The expanded capacity is assumed to be 135 MW.
Prior to the 2015 addition of Kenai area generation, the Kenai export limit was defined as 71
MW in the summer and 82-99 MW in the winter. Following the addition of the 2015 Kenai area
generation and other changes in northern Railbelt generation, the export limit will vary from 29 –
104 MW, depending on the Kenai generation configuration. To eliminate the wide variations in
Kenai export limits and provide a predictable export limit that allows all Bradley Lake and
Cooper Lake generation to be unconstrained, improvements will be required to the Kenai
transmission system. .
EPS identified various transmission improvements that could alleviate the capacity and energy
constraints of the Anchorage-Kenai system to allow unconstrained use of Bradley Lake and
Cooper Lake hydro energy and capacity. These improvements include the construction of new
transmission facilities, the reconstruction of existing facilities, and the installation of additional
transmission compensation.
Preliminary analysis indicates that a 100 kV DC intertie between Beluga and Bernice Lake may
be the most economical and expeditious method of alleviating the Bradley Lake constraints.
The DC tie would utilize submarine cable for the entire length of the route and would be capable
of 100 MW of transfer between the Anchorage and Kenai systems. However, this routing and
option has only recently been identified and further investigation and cost analysis is required
before we can recommend this alternative.
The recommended construction projects for the Kenai transmission system include the following
two recommendations:
DC tie and Soldotna – Quartz Line
Add new 100 kV HVDC Intertie from Beluga to Bernice Lake
Add new 115 kV transmission line from Bradley Lake to Soldotna
Add new 115 kV transmission line from Soldotna to Quartz Creek
DC tie and Kenai Tie 230 kV upgrade
Add new 100 kV HVDC Intertie from Beluga to Bernice Lake
Add new 115 kV transmission line from Bradley Lake to Soldotna
Add new Dave’s Creek – University 230 kV upgrade
In addition to the projects required for relief of the transmission constraint, analysis of the Kenai
Static VAR Compensator (“SVC”) controls should be included due to the age of equipment and
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consequences of its outage. These controls are almost 20 years old and are no longer readily
supported by the manufacturer. The Power Oscillation Dampening (“POD”) function originally
installed on the SVC has negative impacts on system operations during certain conditions. Also,
the POD has not been modified to account for the relocation of the Soldotna unit to Nikiski or
the construction of additional Kenai generation. Consideration should be given to replacing
these controls with the same controls utilized on the Anchorage-Fairbanks Intertie to provide
common maintenance and training.
Loss analysis show that adding the DC intertie, a 2nd Bradley Lake – Soldotna, and a 2nd
Soldotna – Quartz Creek 115 kV transmission line result in large decreases in the losses during
high Kenai export periods. Losses are decreased over 60% following the proposed
improvements. The decreases in losses are also achieved with the DC intertie, a 2nd Bradley
Lake – Soldotna 115 kV line, and the Kenai Tie upgraded to 230 kV.
A summary of the transmission improvements and their estimated costs are presented in the
tables below:
Table I. Description – Recommendations, 115 kV Kenai Tie
Project Description
100 kV HVDC Bernice ‐ Beluga Tie Alternative, 115 kV Kenai Tie Low High
Beluga ‐ Bernice Lake 100 kV DC Line $134,550 $195,756
Bradley ‐ Soldotna 115 kV line
Soldotna ‐ Quartz Creek 115 kV line
Total Range $246,215 $307,421
Cost Range (1000's)
$62,665
$49,000
Table II. Description – Recommendations, 230 kV Kenai Tie
Project Description
100 kV HVDC Bernice ‐ Beluga Tie Alternative, 230 kV Kenai Tie Low High
Beluga ‐ Bernice Lake 100 kV DC Line $134,550 $195,756
Bradley ‐ Soldotna 115 kV line
Upgrade Kenai Tie to 230 kV
Total Range $282,740 $343,946
Cost Range (1000's)
$62,665
$85,525
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1 Introduction
Electric Power Systems (“EPS”) has conducted a study to determine the impacts to the central
and southern utilities due to changes in the Kenai generation and transmission system since the
completion of the 2010 Regional Integrated Resource Plan (“RIRP”) administered by the Alaska
Energy Authority (“AEA”).
Since the completion of the 2010 RIRP, plans for new thermal generation additions on the Kenai
and some non-dispatchable generation in the Anchorage were finalized. The studies and
analysis included in the RIRP required updating to reflect these generation changes and to
analyze the impact these changes would have on the transmission system recommendations
included in the RIRP.
The purpose of this study is to identify potential changes to the RIRP to mitigate impacts of any
generation changes to the Railbelt and evaluate the cost of the mitigation efforts against the
benefit realized by the same improvements.
The impacts that were evaluated in this RIRP update include the following:
1) Transmission Contingency Analysis
2) Transfer Capacity Analysis
3) Energy and Capacity Loss Analysis
4) Generation Capacity Loss Analysis
5) Penalty Costs for Loss of Hydro-Thermal Coordination Flexibility
The study used the three seasonal power flow cases, summer valley, summer peak, and winter
peak, using the IOC approved 2020 base cases and utilize version 32.1.1 of Power Systems
Simulator Engineer (“PSS/E”) for power flow and transient contingency analysis.
It should be noted that the year 2020 IOC base case corresponds to approximately a year 2040-
45 load as represented in the 2010 RIRP. The differences in loads between the 2020 IOC
cases and the 2010 RIRP for each of the winter peak, summer peak and summer valley cases
are outlined by utility in the tables in Appendix A.
The discrepancies between the 2020 IOC base cases and the 2010 RIRP were not resolved.
However, the loads utilized for long-term transmission and resource planning should be
evaluated and reconciled with the loads used by the IOC.
2 Kenai Export and Constraints
Exports from the Kenai are currently limited by both thermal and stability limitations. The
Soldotna – Quartz Creek and Quartz Creek – Dave’s Creek sections with have thermal ratings
of 96 MVA in the summer, with a Kenai export limit of 71-99 MW limited by stability depending
upon the system dispatch.
Following the planned Kenai generation and northern utility generation changes, the thermal
limits remain the same, however the stability limit for various Kenai exports varies from 29 MW
to 104 MW depending on the Kenai system dispatch. In addition to the changes in Kenai export
limits, the losses experienced on the Bradley Lake energy will approach 25% under peak
operating conditions.
Without improvements to the transmission system, the energy and capacity of Bradley Lake will
be constrained during most of the year, with increased losses and stranded capacity
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experienced by the central and northern Railbelt utilities. These constraints will impact the
efficiency of the hydro-thermal coordination and access to spinning reserve by the northern
utilities. The combination of all these factors has significant economic impacts to the central and
northern Railbelt utilities.
3 Generation Configuration
The 2020 bases cases were modified to include new generation on the Kenai, the MEA system,
and the Watana large hydro project. Without the Watana project, there are significant voltage
issues in the Railbelt in the summer valley cases. Prior to assessing the impacts of the Kenai
transmission system, voltage correction measures were required in the South Central Railbelt.
Planned changes to the MEA transmission system that included a new Hospital-Reed
transmission line and a new Herning-Hospital-Reed transmission line were included with the
new generation. The Watana large hydro project assumes that significant amounts of new
transmission will be required between Healy and the Douglas substations.
Generation additions to the 2020 database to evaluate long-term transmission requirements
include the following:
1) 3rd Bradley Lake unit, with total Bradley Lake output of 135 MW (45 MW each unit)
2) Watana hydro plant consisting of 3 – 200 MW generators
3) Eklutna 2 (Reed) generation plant consisting of ten, 17 MW reciprocating engines (170
MW total plant output)
4) These generation additions are in addition to the 84 MW of generation added to the
Kenai from the 2009 existing system to the 2020 IOC Base Case
These generation additions will be dispatched with the generators currently in the 2020
database to create base cases designed to stress the Railbelt grid. Note that it was assumed
that the Eklutna 2 generation would not be built if the Watana hydro plant was built.
The generation additions were configured into 8 different configurations to be used for each of
the 3 seasonal base cases. Generation Case A was configured to be similar to the present day
system. Generation Case B utilizes transmission upgrades listed in the next section to achieve
high Kenai export conditions. Generation Case C includes the 3rd Bradley Lake unit to achieve
even higher Kenai export conditions than Case B. Generation Case C was used for two
sensitivity cases. Generation Case C1 was configured with the Nikiski units offline and
Generation Case C2 was configured with Nikiski, Bernice Lake, and Cooper Lake units all
offline. Additional cases CA and C1A were created by adjusting the spin to the minimum
requirements for use in analysis of the DC transmission line option.
Cases with Watana online (Generation Cases D and E) were configured with two different
Railbelt spin amounts (100 or 200 MW). Configurations of different combinations of Watana and
the expanded Bradley Lake plant (Generation cases F-H) were created based on total plant
output. The cases were setup with either plant online at their full amount with the other plant at
a reduced output. As with the previous Watana case configurations (D and E), Railbelt spin
amounts of 100 and 200 MW were used.
A list of the different generation configurations is shown below. Summary tables of the different
generation dispatches are listed in Appendix B.
A) Base case, no transmission or generation additions, similar to 2009 generation dispatch
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B) No Generation Additions from 2020 IOC Base Case (includes 2015 Kenai generation
additions – Nikiski 18 MW HSRG, 17 MW Duct Firing, 49 MW-LM 6000)
C) 3rd Bradley Lake addition
CA) 3rd Bradley Lake addition, minimum spin case
C1) 3rd Bradley Lake addition, with Nikiski offline
C1A) 3rd Bradley Lake addition, with Nikiski offline, minimum spin case
C2) 3rd Bradley Lake addition, with Nikiski, Bernice Lake, and Cooper Lake offline
D) Watana generation at 600 MW with 100 MW of spin on Railbelt*
E) Watana generation at 600 MW with 200 MW of spin on Railbelt*
F) 3rd Bradley Lake added, 135 MW, Watana generation reduced
G) 3rd Bradley Lake with Bradley Lake plant output reduced, Watana generation at 600 MW
with 100 MW of spin*
H) 3rd Bradley Lake with Bradley Lake plant output reduced, Watana generation at 600 MW
with 200 MW of spin*
* Except for summer valley cases were low spin values are not possible
4 Transmission Options
The two main areas of focus to relieving the generation constraints are to improve the existing
transmission system between Bradley Lake and Anchorage without a new intertie or construct a
new transmission system between the Kenai and Anchorage in addition to improvements to the
existing transmission system. The specifics for the interties as well as other Kenai transmission
upgrades are listed below.
4.1 Upgrade Dave’s Creek – University Tie to 230 kV
This project includes upgrading the existing 115 kV transmission line to 230 kV construction and
operation. On the northern end, the upgraded line would terminate in Anchorage at the 230 kV
University substation bus. 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 30 MVAR fixed reactor would be required at the Dave’s Creek substation. The
reactor would allow load to be served from the Kenai with the University substation end opened
without units on the Kenai being operated in the “buck” condition. It was assumed that the
Kenai tie transmission upgrades would be wooden H-Frames utilizing 795 ACSR “Drake”
conductor.
Further switching studies will be required to confirm if a switched reactor can be utilized in
conjunction with the existing SVC or if the existing SVC will require upgrading.
4.2 New HVAC Kenai Intertie
A new Kenai Intertie option was studied at two voltage levels, 138 kV and 230 kV. The Kenai
Intertie termination point in Anchorage would be at Point Woronzof substation. The 138 kV
option would assume a direct termination into the 138 kV bus at Point Woronzof. The 230 kV
option was modeled with a single 230/138 kV 150 MVA transformer connection to the 138 kV
bus. The termination point on the Kenai was at Bernice substation. The 138 kV option was
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March 7, 2014 Page 4
modeled with a single 138/115 kV 150 MVA transformer connection to the 115 kV bus. The 230
kV option was modeled with a single 230/115 kV 150 MVA transformer connection to the 115 kV
bus.
The Kenai Intertie utilized the Tesoro route as listed in the Southern Intertie Final Environmental
Impact Study (FEIS). There are three different underground cable sections due to two airports
and crossing the Captain Cook State Recreational Area (SRA). The remainder of the route is
overhead until crossing the Cook Inlet with submarine cable. Table 4.2 lists the distances and
conductors for the Tesoro preferred route option.
Table 4.2 Proposed Tesoro route per Southern Intertie FEIS
type size name
Bernice Lake to Private Airstrip 1 3 overhead 795 Drake
Underground for Airstrip 1 1 underground 1000 copper
Overhead to Airstrip 2 1 overhead 795 Drake
Underground for Airstrip 2 0.5 underground 1000 copper
Overhead to Captain Cook SRA 11.2 overhead 795 Drake
Underground for Captian Cook SRA 3.4 underground 1000 copper
Follow Tesoro pipeline 27.4 overhead 795 Drake
NSubmarine Cable under Cook Inlet 18.1 undersea 1000 copper
Route
Option Details Distance
(mi)
Conductor type
A
The 138 kV intertie required a total of 120 MVAr of compensation in order to control the voltages
created by the submarine cable charging. The 230 kV option required approximately 270 MVAr
of compensation, with at least 65 MVAr of that compensation being a SVC. The values
assumed an additional 40 MVAr of compensation already added to the Railbelt system in the
base case.
4.3 100 kV HVDC Intertie Beluga – Bernice Lake
An HVDC alternative was analyzed due to the complexities found in the HVAC Kenai Intertie
above. With HVDC, the length of the submarine cable becomes a cost consideration, but does
not present a technical challenge. Therefore in order to minimize the overall cost of the project,
a direct tie between Beluga and Bernice Lake was investigated. The direct tie would eliminate
the environmentally sensitive areas along the overhead route and avoid the multiple land cables
and their associated terminations along the overhead route. The submarine cable would also
make entrance into and out of the Beluga and Bernice stations easier than an overhead
alternative.
The size of the HVDC cable was chosen to carry sufficient load such that during the maximum
Anchorage import of 130 MW from Kenai hydro resources, the loss of the existing Anchorage-
Dave’s Creek 115 kV line would not result in load shedding in the Anchorage/Mat-Su/Fairbanks
areas. We also assumed that the HVDC terminals would be mono-pole terminals as opposed to
bi-pole terminals. A mono-pole terminal is similar to an AC transmission line in that a fault on
either the single cable or either of the HVDC terminals would result in the loss of the line.
This sizing and methodology is considerably different than previous analysis which evaluated bi-
pole systems of 125 MW or more capacity. Our studies used a capacity of 100 MW for the
mono-pole converters.
Due to the length of outage delay for a submarine cable failure, we did include two submarine
cables in the project. The route of the cables would result in the majority of the cables being
parallel to the Cook Inlet current flow which should make them less susceptible to damage
caused by high currents than the Pt. Woronzof- Pt. Possession cables. A failure of either cable
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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.
4.4 Kenai Transmission Upgrades
The transmission upgrades for the Kenai system that were evaluated include the following
options:
Reconductor existing Diamond Ridge – Soldotna to 556 MCM
Add new 115 kV line from Bradley Lake to Quartz Creek
Add new 115 kV line from Bradley Lake to Soldotna
Add new 115 kV line from Soldotna to Quartz Creek
Add new 115 kV line from Quartz Creek to Dave’s Creek
4.5 Transmission Configurations
The Kenai Tie, Southern Intertie, DC tie, and other HEA transmission upgrades were organized
into groups of transmission configurations to be studied. The different configurations are listed
below in Table 4.1 and were used for the power flow, transient contingency, and loss analysis
parts of the study.
Table 4.1 Transmission Configurations
1x x x
2x x x x
3x x x
4x x x x
5xx xx
6xx xx
7x xx
8x xx x
9x x x
10 x x x x
11 x x x
12 x x x x
13 x x x x
14 x x x
15 x x x
16 x x x x
17 x x x x x
18 x x x x x
19 x x x x x
20 x x x
21 x x x
Trans
Config
Kenai Tie Southern Intertie add 2nd
Bradley ‐
Quartz115 kV 230 kV 138 kV
Kenai Transmission Upgrades
add 2nd
Quartz ‐
Daves
add 2nd
Bradley ‐
Soldotna
upgrade
Soldotna ‐
Diamond
add 2nd
Soldotna ‐
Quartz230 kV DC
5 Power flow Analysis
Power flow analysis was run on all of the cases listed above. The contingencies consist of all
115 kV branches and associated transformers in the Kenai area as well as the ties connecting
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the Kenai to Anchorage. The ratings used for the power flow contingency analysis are shown in
Table 5.1 below.
Table 5.1 Conductor Ratings
Size Name Winter Summer
4/0 Penguin 88 50
556 ACSR Dove 173 96
795 ACSR Drake 220 120
Conductor Rating (MVA)
The power flow contingency analysis was completed on only two of the generation cases for
each load season. Generation Cases using the 2020 IOC generation capacity (Case B) and the
2020 IOC base case plus the 3rd Bradley Lake unit addition (Case C) were chosen due to the
high Kenai export amounts and represent the worst case scenarios during power flow
contingency analysis.
No branch thermal overloads were found for the winter peak load season for either generation
case and for all transmission configurations.
Many branch thermal overloads for the summer peak and summer valley load seasons were
found for both generation cases (Case B and Case C). Many contingencies for the different
transmission configurations create thermal overloads due to the restricted summer ratings used
for the conductors. Severe contingencies include loss of the ties between the Kenai and
Anchorage and a loss of the transmission line between Bradley Lake and Soldotna.
An outage of the new proposed ties from the Kenai to Anchorage (DC, Southern Intertie) will
overload the existing Kenai tie. Upgrading the Kenai tie to 230 kV and adding new 115 kV
transmission lines between Soldotna – Quartz Creek – Dave’s Creek eliminates the overload
condition. Another severe contingency is an outage of the Soldotna – Bradley Lake line when
Bradley Lake is at peak output. This outage will overload the remaining line sections, even if
reconductored to 556 ACSR or if a 115 kV Bradley Lake – Quartz Creek line is added. A
second Bradley Lake – Soldotna line is required to eliminate the overload condition. Detailed
power flow results for the summer peak and summer valley cases are shown in Appendix C.
Table 5.2 shows the summary of the power flow results. Transmission configurations
highlighted in orange have thermal overloads for contingencies during the summer peak and
summer valley load seasons. Note that an x in a cell denotes what upgrades are applicable for
each different transmission configuration.
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Table 5.2 Power Flow Results Summary
1x x x
2x x x x
3x x x
4x x x x
5xx xx
6xx xx
7x xx
8x xx x
9x x x
10 x x x x
11 x x x
12 x x x x
13 x x x x
14 x x x
15 x x x
16 x x x x
17 x x x x x
18 x x x x x
19 x x x x x
20 x x x
21 x x x
xdenotes equipment upgrades / options
transmission configurations with thermal overloads
230
kV
138
kV
230
kV DC
Trans
Config
Kenai Tie Southern Intertie
115
kV
Kenai Transmission Upgrades
add 2nd
Bradley ‐
Quartz
add 2nd
Quartz ‐
Daves
add 2nd
Bradley ‐
Soldotna
upgrade
Soldotna
‐
add 2nd
Soldotna
‐ Quartz
There are only 3 transmission configurations that produce no overloads for the summer peak
and summer valley load seasons. This configurations are the Kenai Tie upgraded to 230 kV,
with either the DC tie (transmission configuration 17) or the Southern Intertie operated at 138 kV
or 230 kV (transmission configuration 18 or 19, respectively). These configurations assume that
the Kenai transmission system includes new 115 kV transmission lines from Bradley Lake –
Soldotna – Quartz Creek – Dave’s Creek.
The results for the power flow analysis show no overloads for the winter peak load season.
Since the thermal overloads are only for the summer peak and summer valley load seasons,
redispatching generation to alleviate the overloads (reducing Kenai exports) is deemed an
acceptable mitigation measure.
6 Loss Analysis
Loss analysis was performed comparing the existing system to improved systems with Kenai
Transmission upgrades and additions. Comparisons between the different cases were made by
combining the losses for the line sections between Bradley Lake, University, and Pt. Woronzof
(for the Southern Intertie cases). The winter peak cases were used for the loss analysis study.
It is important to note that it is difficult to accurately determine losses of a DC line / system due
to its complexity. Losses of 4% of power transfer were used to model the losses on the DC line.
Table 6.1 shows the results from the loss analysis for Kenai export levels of 99 MW.
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The results show that a large reduction in losses for transferring energy from the Kenai is found
with the addition of the Southern Intertie (at 138 kV or at 230 kV) or a DC tie. The transmission
configuration with the least amount of losses is with the existing tie operated at 230 kV, the
Southern Intertie operated at 230 kV, a second Bradley – Soldotna line, a second Soldotna –
Quartz Creek line, and a second Quartz Creek – Dave’s Creek line section (transmission
configuration 4 and 19). These configurations have 6.6 and 6.3 MW of total losses, respectively.
A comparison of cases with a second 115 kV Bradley Lake – Soldotna line versus
reconductoring the Soldotna – Diamond Ridge line to 556 ACSR conductor can be made with
the results. Adding the second Bradley Lake – Soldotna line reduces losses by about 2 MW in
all cases compared to reconductoring the Soldotna – Diamond Ridge line.
Table 6.1 Loss Analysis Results – 99 MW Export Comparisons
%MW
base x 25.0 0% 0.0
1x x x 7.6‐69% 17.3
2x x x x 7.5‐70% 17.5
3x x x 6.7‐73% 18.3
4x x x x 6.6‐73% 18.3
5xx xx 6.9‐72% 18.0
6xx xx 6.7‐73% 18.3
7x xx 9.9‐60% 15.1
8x xx x9.9‐60% 15.1
9x x x 9.6‐62% 15.4
10 x x x x 9.4 ‐62% 15.5
11 x x x 8.7 ‐65% 16.3
12 x x x x 8.6 ‐65% 16.3
13 x x x x 11.8 ‐53% 13.2
14 x x x 8.4 ‐66% 16.6
15 x x x 10.4 ‐58% 14.6
16 x x x x 8.3 ‐67% 16.7
17 x x x x x 7.9 ‐68% 17.0
18 x x x x x 6.7 ‐73% 18.3
19 x x x x x 6.3 ‐75% 18.7
20 x x x 7.2 ‐71% 17.8
21 x x x 8.1 ‐67% 16.8
Kenai Transmission Upgrades Total
Losses
(MW)
Reduction in
LossesNew
Brad ‐
Qrtz
2nd
Qrtz ‐
Daves
2nd
Brad ‐
Sold
Recd
Sold ‐
Dmnd
2nd
Sold ‐
Qrtz
Current
Limits (99
MW) at
Daves
Creek ‐
Hope 115
kV line
115
kV
230
kV
138
kV
230
kV
Kenai
Export
Levels
Trans
Config
Kenai
Tie
Southern
Intertie
DC
The loss analysis was also completed with a Kenai export level of 125 MW, with results shown
in Table 6.2. Note that the table shows the results sorted by losses, with transmission
configurations with the least amount of losses located at the top. The results show a wide range
of possible losses for the different transmission configurations (8.9 – 17.5 MW). To reduce the
losses to a high degree requires a minimum of another tie to the Kenai (AC or DC), adding a
second Soldotna – Bradley Lake 115 kV line, and adding a second Soldotna – Quartz Creek
115 kV line.
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March 7, 2014 Page 9
Table 6.2 Loss Analysis Results – 125 MW Export Comparisons
19 x x x x x 8.9
6xxxx 9.5
4x x x x9.6
3x x x 9.6
18 x x x x x 9.8
5 x x x x 10.1
20 x x x 10.6
17 x x x x x 10.7
2 x x x x 11.2
1 x x x 11.4
21 x x x 11.5
16 x x x x 12.3
12 x x x x 12.4
11 x x x 12.4
14 x x x 13.0
10 x x x x 13.9
9 x x x 14.1
8 x x x x 14.8
7 x x x 15.0
15 x x x 15.5
13 x x x x 17.5
Total
Losses
(MW)
Trans
Config
Kenai
Tie
Southern
Intertie
Kenai Transmission Upgrades
Recd
Sold ‐
Dmnd
2nd
Sold ‐
Qrtz
115
kV
230
kV
138
kV
New
Brad ‐
Qrtz
2nd
Qrtz ‐
Daves
2nd
Brad ‐
Sold
230
kV DC
7 Stability Analysis
Dynamic stability simulations were run to assess the transient impact of the proposed system
improvements. Simulations of unit trip events and line fault and trip events were conducted.
The simulations were used to evaluate the transfer limits of various system configurations as
well as evaluate any impact of spinning reserve amounts and locations. A complete list of the
disturbances used for stability analysis is shown in Appendix D.
The stability results for all three seasonal cases show that when the Kenai tie is upgraded to
230 kV along with a second Dave’s Creek to Quartz Creek line and a Bradley Lake to Quartz
Creek line section (transmission configuration 7), the system will go out of step for
contingencies on the Soldotna - Sterling – Quartz line sections. Replacing the Bradley Lake to
Quartz Creek line with a second line from Bradley Lake to Soldotna and a second line from
Soldotna to Quartz Creek removes the unstable condition. The Bradley Lake – Quartz Creek
line is not a recommended upgrade.
The results for all three seasonal cases also show that reconductoring the Soldotna to Diamond
Ridge transmission line to 556 ACSR “Dove” conductor results in unstable conditions for a fault
and trip of the Bradley Lake – Soldotna line section. Reconductoring the line section is not a
recommended upgraded. Adding a second Soldotna – Bradley Lake line section is the
preferred alternative.
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The results also show that a second 115 kV line from Soldotna – Quartz Creek is required to
eliminate instabilities due to contingencies of the Southern Intertie or the DC tie.
Detailed stability results for the winter peak, summer peak, and summer valley cases are shown
Appendix E, F, and G, respectively.
There are 7 transmission configurations that produce no instabilities for contingencies with the
three seasonal cases. These configurations include a 2nd Bradley Lake – Soldotna line, a 2nd
Soldotna – Quartz Creek line section, and either the Southern Intertie (138 kV or 230 kV) or the
DC tie. Only transmission configuration case 8 has no other tie besides the Kenai tie upgraded
to 230 kV. It is important to note that since transmission configuration 8 has only one tie
between Anchorage and the Kenai, it is susceptible to islanding for single contingencies
between Dave’s Creek and University. Table 7.1 shows the summary of the transient stability
results. Transmission configurations highlighted in green exhibit instabilities during dynamic
contingencies. Note that an x in a cell denotes what upgrades are applicable for each different
transmission configuration.
Table 7.1 Transient Stability Results Summary
1x x x
2x x x x
3x x x
4x x x x
5xx xx
6xx xx
7x xx
8x xx x
9x x x
10 x x x x
11 x x x
12 x x x x
13 x x x x
14 x x x
15 x x x
16 x x x x
17 x x x x x
18 x x x x x
19 x x x x x
20 x x x
21 x x x
xdenotes equipment upgrades / options
transmission configurations with stability issues
single contingency results in islanding
Trans
Config
Kenai Tie Southern Intertie Kenai Transmission Upgrades
115
kV
230
kV
138
kV
230
kV DC
add 2nd
Bradley ‐
Quartz
add 2nd
Quartz ‐
Daves
add 2nd
Bradley ‐
Soldotna
upgrade
Soldotna ‐
Diamond
add 2nd
Soldotna ‐
Quartz
7.1 DC Size Analysis – Kenai Tie Trip
The addition of the DC tie between Bernice and Beluga adds additional complexity to the
Railbelt system. With the AC Southern Intertie options, a fault and trip of the Kenai Tie would
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result in all available Kenai export energy flowing through the remaining AC Southern Intertie.
Since the DC tie flows must be set and would be scheduled, the size of the DC line including
overload capability was examined. This analysis was completed by scheduling the DC tie with
an initial flow of 75 MW, then tripping the Kenai Tie open. The DC line flow was then increased
until the Anchorage area did not load shed. 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 DC line should have the capability of operating at 100 MW.
Increasing the DC schedule from 75 MW to 100 MW eliminates load shedding that can occur if
the DC schedule is not increased for a loss of the Kenai Tie with total Kenai Exports of around
127 MW. Detailed results are shown in Appendix H.
7.2 Kenai Tie Analysis – DC / Southern Intertie Trip
The loss of the DC Tie or Southern Intertie is a severe outage on the Kenai system. The outage
results in all exports off of the Kenai flowing through the Kenai Tie and can result in instabilities
or unacceptable voltages on the Kenai Tie.
7.2.1 Kenai Tie Analysis – Transient Stability
Transmission configurations with the existing Kenai Tie upgraded to 230 kV show no instability
problems with the loss of the DC or Southern Intertie. The Kenai Tie upgrade to 230 kV was
analyzed with 115 kV line additions from Soldotna – Quartz and Quartz – Dave’s Creek and
without the 115 kV line additions. Analysis of the existing Kenai Tie (115 kV) was completed to
determine what upgrades are required to survive the loss of the DC or Southern Intertie.
The results show that in addition to the 2nd Bradley Lake – Soldotna 115 kV transmission line,
the 2nd Soldotna – Quartz Creek 115 kV transmission line is also required. These transmission
additions allow the export of energy off of the Kenai without problems during DC tie or Southern
Intertie trip events. Detailed results are shown in Appendix I.
7.2.2 Kenai Tie Analysis – Power flow / Voltage
The high transfer levels on the existing Kenai Tie (115 kV) due to an outage of the DC tie or the
Southern Intertie were shown to be stable with the addition of the 2nd Bradley Lake – Soldotna
and 2nd Soldotna – Quartz Creek 115 kV transmission lines. Further analysis was completed to
determine if unacceptable voltages were found on the Kenai Tie and if the SVC’s at Dave’s
Creek and Soldotna were not operating at their limits.
The criteria used for unacceptable voltages were below 1.02 pu for the 24.9 kV buses at
Portage or Girdwood. Load Tap Changer transformers (LTC) were modeled between the 115
kV and 24.9 kV bus locations to determine if the LTC would have enough steps to keep the 24.9
kV voltages acceptable (above 1.02 pu). A 10 MVAR reduction was placed on the SVC limits to
model an appropriate operating margin for the Soldotna and Dave’s Creek SVC’s.
The results show acceptable voltage performance for the 115 kV Kenai Tie with the addition of
the 2nd Bradley Lake – Soldotna 115 kV line and the 2nd Soldotna – Quartz Creek 115 kV line.
The results also show acceptable voltage performance when the Kenai Tie is upgraded to 230
kV with and without line additions to the Soldotna – Quartz – Dave’s Creek substations. The
230 kV Kenai Tie cases include the 2nd Bradley – Soldotna 115 kV line addition.
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 12
8 Cost Analysis
Cost estimates for each of the proposed transmission upgrades are found in Appendix J. The
possible transmission configurations were chosen based on the previous stability results as well
as the costs associated with the individual projects. Comparing the costs of the Southern
Intertie at 138 kV and 230 kV, the 230 kV option is a lot more expensive while providing nominal
increases in transfer capability / reduction in losses. Therefore, the Southern Intertie option at
230 kV is not considered a viable option. Transmission configurations with the Soldotna –
Diamond Ridge line upgraded or with the Bradley Lake – Quartz Creek line are not viable
options due to instabilities that can occur with those transmission configurations. Upgrading the
Kenai Tie to 230 kV without adding a Southern Intertie or a DC tie was deemed not feasible due
to single contingencies on the Kenai Tie resulting in islanding of the Kenai from Anchorage.
The possible transmission configurations include the addition of the 2nd 115 kV Bradley Lake –
Soldotna line for all cases with possible upgrades to the existing Kenai Tie and additional ties
into Anchorage (Southern Intertie and DC Intertie). Table 8.1 shows the possible transmission
configuration specifics and the total costs.
Table 8.1 Possible Transmission Configurations
Low High
2 x x x x $321,665 $388,455
16 x x x x $241,415 $302,621
18 x x x x x $423,430 $490,220
20 xx x $362,990 $429,780
21 xxx $282,740 $343,946
17 x x x x x $343,180 $404,386
xdenotes upgrades / options for transmission configuration
Total Costs Range
(1000's)Trans Config
Kenai Tie Southern
Intertie
Kenai Transmission Upgrades
add 2nd
Quartz ‐
Daves
115
kV DC
add 2nd
Soldotna ‐
Quartz
add 2nd
Bradley ‐
Soldotna
230
kV
138
kV
The cost totals show a significant increase in costs for the 138 kV Southern Intertie options
compared to the DC intertie option. The complex switching and energization requirements of
both the 138 kV Kenai Intertie has increased the cost estimates considerably above prior
studies. For purposes of budgetary estimates, we assumed 25% of the compensation
requirements in the 138 kV option was fixed compensation. The ratio of fixed vs. variable
compensation must be determined by detailed switching studies. These switching studies
should consider the switching surges encountered during energizing/de-energization of the
cables and reactors, the possibility of subsynchronous resonance, and the different methods of
energization.
Although feasible, the technical complexities of energizing a 120 MVAr submarine
cable/reactor/SVC combination in an isolated electrical system would require specialized
studies and would be considerably more complex than the existing system’s operation. The
complexities of the switching and energization should be more fully developed prior to
embarking on this technology in a limited system such as the Railbelt.
The DC is the preferred intertie due to the technical challenges in operating and constructing the
AC intertie and the associated high costs.
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 13
9 Recommendations
The stability results and the cost analysis were used to create a list of more probable
transmission configurations for the Kenai Transmission system. These cases are shown below
in Table 9.1 with a cost comparison shown in Table 9.2.
Table 9.1 Preferred Transmission Configurations
16 x x x x
21 xx x
17 x x x x x
x denotes upgrades / options for transmission configuration
Trans Config
Kenai Tie Kenai Transmission Upgrades
add 2nd
Quartz ‐
Daves115 kV
add 2nd
Soldotna ‐
Quartz
add 2nd
Bradley ‐
Soldotna230 kV
DC
Intertie
Table 9.2 Preferred Transmission Configurations - Costs
Low High Low High
16 0 $134,550 $195,756 $57,865 $49,000 $241,415 $302,621
21 $85,525 $134,550 $195,756 $62,665 $282,740 $343,946
17 $85,525 $134,550 $195,756 $57,865 $49,000 $16,240 $343,180 $404,386
Add 2nd
Quartz ‐
Dave's
DC Intertie
Transmission Upgrades (1000's)Total Costs Range
(1000's)Trans
Config
Add 2nd
Soldotna ‐
Quartz
115
kV
Add 2nd
Bradley ‐
Soldotna230 kV
Kenai Tie
(1000's)
Loss analysis was completed with varying Kenai export levels of 55 MW to 100 MW for the
remaining transmission configurations, comparing the losses to the current 2020 year
transmission system. Table 9.3 shows the results in tabular form while Figure 9.1 shows the
results graphically. Note that the DC Intertie was assumed to schedule all 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. 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 DC Intertie. It is assumed that the DC Intertie has losses that are equal to 4% of the energy
flowing on the line.
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 14
Table 9.3 Preferred Transmission Configurations – Loss Comparisons
59.3 8.6 55.5 3.8 55.5 3.8 55.5 3.8
63.3 9.8 58.3 4.0 58.3 4.0 58.4 4.0
67.4 11.1 63.2 4.5 63.2 4.5 63.2 4.5
71.5 12.6 67.7 5.0 67.7 5.0 67.7 5.0
75.3 14.0 72.4 5.5 72.4 5.5 72.4 5.5
79.2 15.7 77.1 6.0 77.1 6.0 77.1 6.0
83.1 17.4 81.6 6.3 81.6 6.3 81.6 6.3
86.7 19.2 86.3 6.7 86.3 6.7 86.4 6.7
90.5 21.2 91.0 7.2 91.0 7.1 91.1 7.0
94.8 23.7 95.4 7.7 95.3 7.6 95.4 7.5
99.8 27.0 100.0 8.3 99.8 8.1 100.1 7.9
Transmission Configuration
Export
(MW)
Loss
(MW)
Base #16 #21 #17
Loss
(MW)
Export
(MW)
Export
(MW)
Loss
(MW)
Export
(MW)
Loss
(MW)
Figure 9.1 Kenai Export Loss Analysis
The results show a significant reduction in losses with the addition of the DC intertie and / or the
Kenai Tie upgraded to 230 kV. The results also show minimal increased reduction in losses
with the Kenai Tie upgraded to 230 kV and the DC tie added (transmission configuration 17)
compared to the other upgraded configurations. Configuration 17 is not recommended since the
cost is approximately $100 million more than the DC line addition (transmission configuration
16).
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 15
The two recommended transmission configurations are the as follows:
#16 - DC intertie with 2nd Bradley – Soldotna and 2nd Soldotna – Quartz Creek 115 kV line
#21 - DC intertie with 2nd Bradley – Soldotna 115 kV line and Kenai Tie upgraded to 230 kV
9.1 N-1-1 Analysis – Recommended Transmission Configurations
Double contingency analysis (N-1-1) was completed on the two recommended transmission
configurations to determine the transfer capability limit of the Kenai system with the loss of the
DC Intertie. Fault and trips of the Soldotna SVC transformer and the Soldotna – Diamond Ridge
115 kV line were used to determine the Kenai response due to contingencies and the
associated transfer limits for the different cases. Four different generation dispatches were used
to test the two recommended transmission configurations for each of the three load seasons
(summer peak, summer valley, and winter peak). The dispatches are listed below:
B – Full Cooper Lake and Bradley Lake export
C – Full Cooper Lake and Bradley Lake (with 3rd unit) export
C1 - Full Cooper Lake and Bradley Lake (with 3rd unit), Nikiski offline
C2 - Full Bradley Lake (with 3rd unit), Nikiski offline, Bernice offline, Cooper Lake offline
Bradley Lake generation plant output was reduced in 5 MW increments for cases that resulted
in transient instabilities till a stable response was found.
The N-1-1 Kenai Export limits are listed in Tables 9.4 for transmission configurations 16 and 21.
Note that the green shaded cells are cases that have Kenai Export limits due to Bradley Lake
and Cooper Lake maximum output. Cells with red text are cases that must be restricted due to
contingencies. The amount of Bradley Lake excess capacity due to the restriction is also listed
in the table.
The results show that the two recommended transmission configurations have similar (+/- 5
MW) Kenai Export limits due to contingencies with the DC line out of service. The results also
show that turning off Nikiski and Bernice generation and increasing Soldotna generation
reduces the Kenai Export limits by about 20 MW.
Table 9.4 N-1-1 Kenai Export Limits - Recommend Transmission Configurations
b 108 106 103
c 123 120 114 ‐5
c1 111 ‐15 113 ‐10 102 ‐20
c2 98 ‐20 92 ‐5 75
b 104 102 100
c 118 115 113
c1 115 ‐5 112 ‐5 106 ‐10
c2 94 ‐20 88 ‐568‐5
Kenia Export limited by generation
red values ‐ Kenai Export limited by stability
Excess
Brad
(MW)
16
21
Trans
Config
Gen
Case
Kenai
Export
(MW)
Excess
Brad
(MW)
Kenai
Export
(MW)
Excess
Brad
(MW)
Kenai
Export
(MW)
Summer Valley Summer Peak Winter Peak
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 16
10 Conclusions
The northern utilities will be adversely impacted following the addition of Kenai area and
northern generation additions in 2015. Losses for Bradley Lake energy will increase
significantly over historic levels. Portions of Bradley Lake’s capacity will be unavailable to
northern utilities during much of the year and increases in Bradley Lake capacity will not be
possible.
A project to reconstruct the 115 kV Diamond Ridge – Soldotna transmission line from 4/0 was
evaluated against the construction of a new 115 kV Bradley Lake – Soldotna transmission line
but is not recommended due to its higher costs. The Diamond Ridge reconstruction is a
significantly longer project at a higher cost/mile due to distribution underbuild, shorter spans,
and working around energized facilities. In addition to the higher costs, simulations indicate that
the reconductored Diamond Ridge – Soldotna line cannot provide unconstrained operation of
the Bradley Lake project. Operation of Bradley Lake at high generation levels or the installation
of a 3rd turbine with the new generation requires a new 115 kV Bradley Lake – Soldotna
transmission line in addition to the two existing 115 kV lines.
A newly identified alternative of constructing a 100 kV HVDC tie between Beluga and Bernice
Lake in conjunction with a new 115 kV Bradley Lake-Soldotna line and new 115 kV Soldotna –
Quartz Creek line appears to be the most economical and technically feasible solution. We
recommend the 100 kV HVDC Beluga – Bernice alternative be fully evaluated and if
substantiated, it coupled with the construction of a new Bradley Lake – Soldotna 115 kV line.
Additional Kenai transmission upgrades recommended are either a new Soldotna – Quartz
Creek 115 kV line or upgrading the Kenai Tie to 230 kV.
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 17
Appendix A – Load Analysis (MW) IOC versus RIRP
Table A.1 2020 Seasonal Base Case Load from IOC
Season CEA GVEA HEA MEA ML&P SES Total
WP 229 283.3 98.7 186 219.9 11.9 1028.8
SP 159.3 224.6 67.4 116.2 210.4 10.3 788.2
SV 98.3 127.4 45.7 67.5 113.1 7.7 459.7
Table A.2 RIRP Winter Peak Loads
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 234 238 87 146 188 10 869
2015 235 218 89 157 192 10 868
2020 238 226 92 167 197 10 896
2025 242 234 96 178 202 10 928
2030 247 243 100 188 207 10 959
2035 252 252 104 199 212 10 991
2040 256 260 108 210 217 10 1024
2045 261 269 112 222 223 10 1058
2050 266 278 117 234 228 10 1092
2055 271 288 121 247 233 10 1127
2060 276 297 125 260 239 10 1163
Table A.3 RIRP Summer Peak Loads
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 161 191 75 91 167 10 668
2015 161 175 77 96 171 11 667
2020 163 182 79 95 175 11 689
2025 166 188 83 100 180 11 713
2030 170 195 86 106 184 11 737
2035 173 202 90 113 189 11 762
2040 176 209 93 119 193 11 787
2045 180 216 97 126 198 12 813
2050 183 224 101 134 203 12 839
2055 186 231 104 141 207 12 866
2060 190 239 108 149 212 13 894
Table A.4 RIRP Summer Valley Loads
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 95 89 44 53 91 4 414
2015 96 81 46 57 93 5 414
2020 97 84 47 61 95 5 427
2025 99 87 49 65 98 5 441
20301019051691005456
20351039453731035471
20401059755771055486
2045 107 100 57 81 108 5 502
2050 109 104 60 85 110 5 518
2055 111 107 62 90 113 5 534
2060 113 111 64 95 115 5 551
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 18
Appendix B – Generation Dispatches
The specifics of the different generation configuration dispatches for the three seasonal cases
are shown in the tables below. Table B.1 shows the generation dispatches for the base cases
and for cases with the 3rd Bradley Lake unit online. Table B.2 shows the generation dispatches
for the cases the 3rd Bradley Lake unit online, as well as the sensitivity cases based off of the
original case. Table B.3 shows the generation dispatches for the cases with Watana online and
no other generation additions. Table B.4 shows the generation dispatches for the cases with
Watana and the 3rd Bradley Lake unit online.
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 19
Table B.1 Generation Dispatch – Base, Upgrades, and 3rd Bradley Lake
sv sp wp sv sp wp sv sp wp
WILSONB000000000
Soldotna G2 2 17 14
BRADLY 1G1454545606060474747
BRADLY 2G2454545606060474747
BRADLY 3G3 474747
TESORO1G1144144144
TESORO1G2144144144
NIKI GEN 1 39 36 43 30 34 43 20 32 43
Nikiski ST 2 14 18 8 13 18
PLNT1‐2G2 2832 2830 2825
PLNT1‐3G3 3228302825
Plant 2 9G9 3645 3645 3645
Plant 2 10G 10 36 45 36 45 40 36 45
Plant 2 11G 11 20 25 20 25 11 20 25
SPP G1 1 51 45 57 30 39 59 42 59
SPP G2 2 51 45 57 47 46 59 45 42 59
SPP G3 3 38 45 47 43 36 57 47 42 51
SPP G4 4 22 21 25 14 18 27 14 19 27
COOP1&2G 1 10 10 10 10 10 10 10 10 10
COOP1&2G 2 10 10 10 10 10 10 10 10 10
EKLUT 1G1181819181919191919
EKLUT 2G2181819181919191919
Eklutna #11171717
Eklutna #12171717
Eklutna #2 3 17 10 17 17
Eklutna #24 1017 1717 17
Eklutna #25 1717 1717 1717
Eklutna #36 1717 1717 1717
Eklutna #37171717 1717 1717
Eklutna #38171717171717 1717
Eklutna #49171717171717171717
Eklutna #4 10 17 17 17 13 17 17 17 17 17
HCCP#2‐G 2 61 60 60 60 61 61
HLP#1‐G 1 26 28 28 26
NPOLESUB 1 39 64 64 39 64
NPOLESUB 2 4064 4064 4064
NPCC 1 3 40 33 53 40 33 53 43 33 53
NPCC 2 4 10 7 12 10 7 12 10 7 12
99 99 96 111 109 108 126 125 122
450 786 1035 450 786 1035 450 786 1035
32 35 36 18 29 28 23 26 31
482 821 1076 468 814 1063 472 825 1065
11074919180859268102
Total Load
Generator
Name ID
Kenai Transfer
Total Losses
Total Generation
Total Spin
ABC
Base Case With
Current Limits
Trans upgrades, No
gen upgrades 3rd Bradley Lake
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 20
Table B.2 Generation Dispatch - 3rd Bradley Lake - Sensitivity
sv sp wp sv sp wp sv sp wp
WILSONB000000000
Soldotna G22 14284049404049
BRADLY 1G1474747474747474747
BRADLY 2G2474747474747474747
BRADLY 3G3474747474747474747
TESORO1G1144144144
TESORO1G2144144144
NIKI GEN 1 20 32 43
Nikiski ST 2 8 13 18
Bernice 22 7
Bernice 33 27
PLNT1‐2G2 2825 2825 2832
PLNT1‐3G3 2825 2825 2832
PLNT2‐5G 5 20 37
Plant 2 9G9 3645 3645 3645
Plant 2 10G 10 40 36 45 40 36 45 40 36 45
Plant 2 11G 11 11 20 25 11 20 25 11 21 25
SPP G1 1 42 59 42 59 45 59
SPP G2 2 45 42 59 45 42 59 45 45 59
SPP G3 3 47 42 51 47 42 51 51 20 44
SPP G4 4 14 19 27 14 19 27 14 24 27
COOP1&2G 1 10 10 10 10 10 10
COOP1&2G 2 10 10 10 10 10 10
EKLUT 1G1191919191919191919
EKLUT 2G2191919191919191919
Eklutna #11171717
Eklutna #12171717
Eklutna #23171717
Eklutna #24171717
Eklutna #25 1717 1717 1717
Eklutna #36 1717 1717 1717
Eklutna #37 1717 1717 1717
Eklutna #38 1717 1717 1717
Eklutna #49171717171717171717
Eklutna #4 10 17 17 17 17 17 17 17 17 17
HCCP#2‐G 2 61 61 61 61 61 61
NPOLESUB1 3964 3964 3964
NPOLESUB 2 4064 4064 4064
NPCC 1 3 43 33 53 43 33 53 43 33 53
NPCC 2 4 10 7 12 10 7 12 10 7 12
126 125 122 127 124 123 118 99 77
450 786 1035 450 786 1035 450 786 1035
23 26 31 23 26 31 23 26 31
472 825 1065 472 826 1066 469 810 1064
9268102455253417244
Total Generation
Total Spin
Total Load
Total Losses
CC1C2
3rd Bradley Lake 3rd Bradley Lake, Nikiski
offline
3rd Brad; Nikiski,Cooper,
Bernice offline
Generator
Name ID
Kenai Transfer
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 21
Table B.3 Generation Dispatch - Watana and no 3rd Bradley Lake
sv sp wp sv sp wp sv sp wp
WILSONB000000000
BRADLY 1G1606060606060474747
BRADLY 2G2606060606060474747
BRADLY 3G 3 47 47 47
TESORO1G1144144144
TESORO1G2144144144
NIKI GEN 1 5 7 10 0
PLNT1‐2G 2 8 20 20 31
PLNT1‐3G 3 30
Plant 2 9G 9 35 44
Plant 2 10G 10 40 35 44
Plant 2 11G 11 11 19 24
SPP G1 1 37 40
SPP G2 2 50 12 37 40 57
SPP G3 3 14 28 6 25 31 26 37
SPP G4 4 515 61561224
COOP1&2G 1 10 10 10 10 10 10 10 10 10
COOP1&2G 2 10 10 10 10 10 10 10 10 10
EKLUT 1G122821118128
EKLUT 2G232431118124
Susitna 1 1 100 200 200 100 200 200 67 100 100
Susitna 2 2 100 200 200 100 200 200 67 100 100
Susitna 3 3 100 200 200 100 200 200 67 100 100
HCCP#2‐G 2 60 60 60
HLP#1‐G1 28
NPOLESUB 1 60
NPOLESUB 2 5015554064
NPCC 1 3 16 30 53 15 15 53 25 33 53
NPCC 2 44 71247126 712
81 61 30 81 67 37 99 89 49
450 786 1035 450 786 1035 450 786 1035
15 29 33 15 29 35 16 22 25
467 815 1067 466 815 1070 467 808 1060
393 117 128 395 218 212 473 399 410
Total Generation
Total Spin
DEF
Watana Watana
3rd Bradley Full,
Watana Reduced
Generator
Name ID
Kenai Transfer
Total Load
Total Losses
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 22
Table B.4 Generation Dispatch - Watana and the 3rd Bradley Lake
sv sp wp sv sp wp
WILSONB000000
BRADLY 1G1202020202020
BRADLY 2G2202020202020
BRADLY 3G3202020202020
TESORO1G1144144
TESORO1G2144144
NIKI GEN 1 13 10 32
Nikiski ST 2 13
PLNT1‐2G 2 27
Plant 2 10G 10 40 35
Plant 2 11G 11 11 10
SPP G1 1 37
SPP G2 2 42 56 33 37
SPP G3 3 20 24 40 15 22 29
SPP G4 4 3131751017
COOP1&2G 1 10 10 10 10 7 10
COOP1&2G 2 10 10 10 10 7 10
EKLUT 1G18282212
EKLUT 2G28242212
Susitna 1 1 100 200 200 100 200 200
Susitna 2 2 100 200 200 100 200 200
Susitna 3 3 100 200 200 100 200 200
HCCP#2‐G 2 60 24 50
NPOLESUB 264
NPCC 1 3 30 33 53 43 20 53
NPCC 2 48 7 12 10 7 12
26 6 ‐13 26 11 19
450 786 1035 450 786 1035
8243192429
459 810 1066 458 811 1064
428 114 141 429 211 213
GH
3rd Bradley
Reduced, Watana
3rd Bradley
Reduced, Watana
Kenai Transfer
Total Load
Total Losses
Total Generation
Total Spin
Generator
Name ID
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 23
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 24
Appendix C – Power Flow Results
Table C.1 Power flow – Summer Peak – Case B – Bradley and Cooper Export
from bus to bus id from bus to bus id
1
2
Soldotna Tesoro 1 Nikiski Bernice 1 108
Tesoro Bernice 1 Nikiski Bernice 1 103
Nikiski Bernice 1 Soldotna Tesoro 1 101
Soldotna Tesoro 1 Nikiski Bernice 1 104
Tesoro Bernice 1 Nikiski Bernice 1 100
5
6
Soldotna Sterling 1 Bradley Quartz 1 113
Sterling Quartz 1 Bradley Quartz 1 111
Bradley Quartz 1
Daves Quartz 1 Daves Quartz 2 125
Soldotna Sterling 1 Soldotna Quartz 1 108
Sterling Quartz 1 Soldotna Quartz 1 106
Soldotna Quartz 1
Daves Quartz 1 Daves Quartz 2 125
Soldotna Bradley 1
Soldotna Bradley 1
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 107
Nikiski Bernice 1 Soldotna Tesoro 1 102
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 103
Soldotna Bradley 1
Soldotna Sterling 1 Soldotna Quartz 1 106
Soldotna Quartz 1
Daves Quartz 1 Daves Quartz 2 122
14
Soldotna Bradley 1
16
17
18
19
20
21
cases with minimal or no branch overloads
outage of line produces overload on remaining line
no branch overloads
no branch overloads
no branch overloads
B ‐
Cooper
and
Bradley
Lake at
full
export
(109
MW)
Southern Tie 138 kV Soldotna ‐ Daves (max 124%, Daves ‐ Quartz)
DC Tie Soldotna ‐ Daves (max 124%, Daves ‐ Quartz)
12
Southern Tie 230 kV University ‐Quartz(max 123%,Daves ‐Quartz)
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
Soldotna‐Diamond ‐Fritz Bradley‐Soldotna max, 124%
11
Southern Tie 230 kV University ‐Soldotna(max 121%,Daves ‐Quartz)
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
Soldotna‐Diamond ‐Fritz Bradley‐Soldotna max, 124%
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
Soldotna‐Diamond ‐Fritz Bradley‐Soldotna max, 121%
Southern Tie 138 kV University ‐Quartz(max 122%,Daves ‐Quartz)
7
Southern Tie 138 kV
overload %gen
disp
trans
config
outage overload (s)
Solodtna‐Ster‐Quartz (108%, Soldotna‐Sterling
9
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
Soldotna‐Diamond ‐Fritz Bradley‐Soldotna max, 121%
Southern Tie 138 kV University ‐Soldotna(max 121%,Daves ‐Quartz)
10
DC Tie University ‐Quartz(max 124%,Daves ‐Quartz)
no branch overloads
Southern Tie 230 kV
4
Southern Tie 230 kV
Southern Tie 138 kV
3
8
University ‐Soldotna(max 124%,Daves ‐Quartz)
University ‐Quartz(max 124%,Daves ‐Quartz)
University ‐Soldotna(max 124%,Daves ‐Quartz)
University ‐Quartz(max 124%,Daves ‐Quartz)
Soldotna‐Quartz(max 104%,Soldotna ‐Sterling)
no branch overloads
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
Soldotna‐Diamond ‐Fritz Bradley‐Soldotna max, 121%
Solodtna‐Ster‐Quartz (106%, Soldotna‐Sterling
13
DC Tie University ‐Soldotna(max 124%,Daves ‐Quartz)
DC Tie University ‐Soldotna(max 121%,Daves ‐Quartz)15 Soldotna‐Diamond‐Fritz(141% Brad‐Fritz)
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 25
Table C.2 Power flow – Summer Peak – Case C – 3rd Bradley Lake Unit added
from bus to bus id from bus to bus id
Soldotna Tesoro 1 Nikiski Bernice 1 103
Daves Cr Quartz 1 Nikiski Bernice 1 100
Daves Cr Quartz 1 Nikiski Bernice 1 100
Soldotna Tesoro 1 Nikiski Bernice 1 118
Tesoro Bernice 1 Nikiski Bernice 1 113
Nikiski Bernice 1
Daves Cr Quartz 1 Nikiski Bernice 1 103
Soldotna Tesoro 1 Nikiski Bernice 1 114
Tesoro Bernice 1 Nikiski Bernice 1 109
Nikiski Bernice 1
Daves Cr Quartz 1 Nikiski Bernice 1 103
5 Soldotna Bradley 1
6 Soldotna Bradley 1
Soldotna Sterling 1 Bradley Quartz 1 137
Sterling Quartz 1 Bradley Quartz 1 134
Bradley Quartz 1
Daves Quartz 1 Daves Quartz 2 141
Soldotna Sterling 1 Soldotna Quartz 1 124
Sterling Quartz 1 Soldotna Quartz 1 122
Soldotna Quartz 1
Daves Quartz 1 Daves Quartz 2 141
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 101
Soldotna Bradley 1
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 116
Nikiski Bernice 1 Soldotna Tesoro 1 109
Nikiski Bernice 1 Tesoro Bernice 1 104
Daves Quartz 1 Nikiski Bernice 1 102
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 112
Tesoro Bernice 1 Nikiski Bernice 1 107
Nikiski Bernice 1 Soldotna Tesoro 1 104
Soldotna Bradley 1
Soldotna Sterling 1 Soldotna Quartz 1 121
Soldotna Quartz 1
Daves Quartz 1 Daves Quartz 2 138
14
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 100
16
17
18
19 Nikiski Bernice 1 Soldotna Tesoro 1 102
Nikiski Bernice 1 Soldotna Tesoro 1 100
21
line with 50 MVA rating
cases with minimal or no branch overloads
outage of line produces overload on remaining line
Southern Tie 138 kV University ‐Soldotna(max 137%,Daves‐Quartz)
C‐ Cooper
and
Bradley
Lake with
3rd
Bradley
unit at full
export
(125 MW)
20 Southern Tie Soldotna ‐ Daves (max 140%, Daves ‐ Quartz)
DC Tie Soldotna ‐ Daves (max 140%, Daves ‐ Quartz)
University ‐Soldotna(max 137%,Daves‐Quartz)
Soldotna‐Diamond‐Fritz(147% Brad‐Fritz)
8 Solodtna‐Ster‐Quartz (123%, Soldotna‐Sterling
9
Soldotna‐Diamond‐Fritz(141% Brad‐Fritz)
no branch overloads
no branch overloads
Soldotna‐Diamond‐Fritz(149% Brad‐Fritz)
Soldotna‐Diamond‐Fritz Bradley‐Soldotna max, 141%
Solodtna‐Ster‐Quartz (121%, Soldotna‐Sterling
Soldotna‐Diamond‐Fritz(149% Brad‐Fritz)
Soldotna‐Diamond‐Fritz Bradley‐Soldotna max, 141%
Southern Tie 138 kV
1
Southern Tie 138 kV
Soldotna‐Diamond‐Fritz Bradley‐Soldotna max, 141%12
10
Soldotna‐Diamond‐Fritz(148% Brad‐Fritz)
Soldotna‐Diamond‐Fritz Bradley‐Soldotna max, 141%
Southern Tie 138 kV University‐Quartz(max 138%,Daves ‐Quartz)
Southern Tie 230 kV
Soldotna‐Bernice(max 106%,Soldotna‐Tesoro)
2 University‐Quartz(max 141%,Daves ‐Quartz)
Bradley‐Soldotna max, 148%
11
13
Southern Tie 230 kV
gen disp trans
config
outage overload (s)overload %
University‐Quartz(max 138%,Daves ‐Quartz)
Soldotna‐Diamond‐Fritz(148% Brad‐Fritz)
4
Soldotna‐Quartz(max 119%,Soldotna‐Sterling)7
University ‐Soldotna(max 140%,Daves‐Quartz)
Soldotna‐Bernice(max 111%,Soldotna‐Tesoro)
DC Tie University‐Quartz(max 141%,Daves ‐Quartz)
15
DC Tie University ‐Soldotna(max 140%,Daves‐Quartz)
DC Tie University ‐Soldotna(max 137%,Daves‐Quartz)
University ‐Soldotna(max 140%,Daves‐Quartz)
Southern Tie 230 kV
Thompson‐Diamond(max 117%,Anchor‐Diamond)
University‐Quartz(max 141%,Daves ‐Quartz)
Thompson‐Diamond(max 114%,Anchor‐Diamond)
3
Southern Tie 230 kV
Soldotna‐Diamond‐Fritz
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 26
Table C.3 Power flow – Summer Valley – Case B – Bradley and Cooper Export
from bus to bus id from bus to bus id
1
2
Nikiski Bernice 1 Soldotna Tesoro 1 103
Soldotna Tesoro 1 Nikiski Bernice 1 105
Soldotna Tesoro 1 Nikiski Bernice 1 100
5 Soldotna Bradley 1 Anchor Pt. Diamond 1 101
6 Soldotna Bradley 1 Anchor Pt. Diamond 1 103
Soldotna Sterling 1 Bradley Quartz 1 112
Sterling Quartz 1 Bradley Quartz 1 110
Bradley Quartz 1
Daves Quartz 1 Daves Quartz 2 124
Soldotna Sterling 1 Soldotna Quartz 1 112
Sterling Quartz 1 Soldotna Quartz 1 110
Soldotna Quartz 1
Daves Quartz 1 Daves Quartz 2 124
Soldotna Bradley 1
Soldotna Bradley 1
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 107
Nikiski Bernice 1 Soldotna Tesoro 1 104
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 102
Soldotna Bradley 1
Soldotna Sterling 1 Soldotna Quartz 1 105
Soldotna Quartz 1
Soldotna Tesoro 1 Nikiski Bernice 1 103
Daves Quartz 1 Daves Quartz 2 122
14
Soldotna Bradley 1
16
17
18
19
20
21
line with 50 MVA rating
cases with minimal or no branch overloads
outage of line produces overload on remaining line
B ‐
Cooper
and
Bradley
Lake at
full
export
(111
MW)
Southern Tie 138 kV Soldotna ‐ Daves (max 123%, Daves ‐ Quartz)
DC Tie Soldotna ‐ Daves (max 123%, Daves ‐ Quartz)
12
University ‐Soldotna(max 120%,Daves ‐Quartz)Southern Tie 138 kV
9
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
Bradley‐Soldotna max, 121%
Southern Tie 138 kV University ‐Quartz(max 122%,Daves ‐Quartz)
11
Southern Tie 230 kV
10
Solodtna‐Ster‐Quartz (107%, Soldotna‐Sterling
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
Southern Tie 230 kV University ‐Soldotna(max 120%,Daves ‐Quartz)
8
Soldotna‐Diamond‐Fritz
Soldotna‐Diamond‐Fritz Bradley‐Soldotna max, 120%
University ‐Quartz(max 124%,Daves ‐Quartz)
Soldotna‐Quartz(max 103%,Soldotna‐Sterling)
University ‐Quartz(max 124%,Daves ‐Quartz)
Southern Tie 138 kV
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
Soldotna‐Diamond‐Fritz Bradley‐Soldotna max, 121%
University ‐Quartz(max 122%,Daves ‐Quartz)
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
Soldotna‐Diamond‐Fritz Bradley‐Soldotna max, 121%
no branch overloads
no branch overloads
no branch overloads
13
Soldotna‐Diamond‐Fritz(121% Brad‐Fritz)
7
outage
Southern Tie 230 kV
Southern Tie 138 kV
4 Southern Tie 230 kV
3
University ‐Soldotna(max 123%,Daves ‐Quartz)
overload
%
gen
disp
trans
config
overload (s)
University ‐Soldotna(max 124%,Daves ‐Quartz)
Soldotna‐Diamond‐Fritz Bradley‐Soldotna max, 121%
Solodtna‐Ster‐Quartz (105%, Soldotna‐Sterling
Soldotna‐Diamond‐Fritz(124% Brad‐Fritz)
DC Tie University ‐Soldotna(max 124%,Daves ‐Quartz)
15 DC Tie University ‐Soldotna(max 120%,Daves ‐Quartz)
DC Tie University ‐Quartz(max 124%,Daves ‐Quartz)
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 27
Table C.4 Power flow – Summer Valley – Case C – 3rd Bradley Lake Unit added
from bus to bus id from bus to bus id
Soldotna Tesoro 1 Nikiski Bernice 1 103
2
Soldotna Tesoro 1 Nikiski Bernice 1 122
Tesoro Bernice 1 Nikiski Bernice 1 115
Nikiski Bernice 1
Soldotna Tesoro 1 Nikiski Bernice 1 117
Tesoro Bernice 1 Nikiski Bernice 1 110
Nikiski Bernice 1
5 Soldotna Bradley 1
6 Soldotna Bradley 1
Soldotna Sterling 1 Bradley Quartz 1 135
Soldotna Bradley 1 Anchor Pt Diamond 1 103
Sterling Quartz 1 Bradley Quartz 1 133
Bradley Quartz 1
Daves Quartz 1 Daves Quartz 2 140
Soldotna Sterling 1 Soldotna Quartz 1 123
Sterling Quartz 1 Soldotna Quartz 1 121
Soldotna Quartz 1
Daves Quartz 1 Daves Quartz 2 140
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 101
Soldotna Bradley 1
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 120
Nikiski Bernice 1 Soldotna Tesoro 1 114
Nikiski Bernice 1 Tesoro Bernice 1 107
Soldotna Bradley 1
Soldotna Tesoro 1 Nikiski Bernice 1 116
Tesoro Bernice 1 Nikiski Bernice 1 110
Nikiski Bernice 1 Soldotna Tesoro 1 110
Nikiski Bernice 1 Tesoro Bernice 1 103
Soldotna Bradley 1
Soldotna Sterling 1 Soldotna Quartz 1 120
Soldotna Quartz 1
Soldotna Tesoro 1 Nikiski Bernice 1 118
Daves Quartz 1 Daves Quartz 2 137
14
Soldotna Bradley 1
16
17
18
19 Nikiski Bernice 1 Soldotna Tesoro 1 102
20
21
line with 50 MVA rating
cases with minimal or no branch overloads
outage of line produces overload on remaining line
13
Soldotna‐Diamond‐Fritz(149% Brad‐Fritz)
Soldotna‐Diamond‐Fritz Bradley ‐Soldotna max, 141%
Solodtna‐Ster‐Quartz (120%, Soldotna‐Sterling
12
Southern Tie 230 kV University ‐Quartz(max 140%,Daves‐Quartz)
Soldotna‐Diamond‐Fritz(148% Brad‐Fritz)
Soldotna‐Diamond‐Fritz Bradley ‐Soldotna max, 141%
Soldotna‐Diamond‐Fritz(148% Brad‐Fritz)
Soldotna‐Diamond‐Fritz Bradley ‐Soldotna max, 141%
University ‐Quartz(max 137%,Daves‐Quartz)
Southern Tie 230 kV University ‐Soldotna(max 136%,Daves ‐Quartz)
Soldotna‐Diamond‐Fritz(148% Brad‐Fritz)
Soldotna‐Diamond‐Fritz
Soldotna‐Diamond‐Fritz(141% Brad‐Fritz)
no branch overloads
Southern Tie 138 kV
no branch overloads
Southern Tie 138 kV Soldotna ‐ Daves (max 139%, Daves ‐ Quartz)
DC Tie
Bradley ‐Soldotna max, 141%
University ‐Soldotna(max 136%,Daves ‐Quartz)
Soldotna‐Bernice(max 110%,Soldotna‐Tesoro)
Bradley ‐Soldotna max, 141%
4
Southern Tie
10
Soldotna‐Diamond‐Fritz(148% Brad‐Fritz)
Soldotna‐Diamond‐Fritz
9
11
8 Solodtna‐Ster‐Quartz (123%, Soldotna‐Sterling
Southern Tie 138 kV
Thompson‐Diamond(max 119%,Anchor ‐Diamond)
gen disp trans
config
outage overload (s) overload
%
3
Southern Tie 230 kV
Soldotna‐Bernice(max 115%,Soldotna‐Tesoro)
University ‐Quartz(max 140%,Daves‐Quartz)
University ‐Soldotna(max 139%,Daves ‐Quartz)
C ‐
Cooper
and
Bradley
Lake with
3rd
Bradley
unit at full
export
(126 MW)
Soldotna ‐ Daves (max 139%, Daves ‐ Quartz)
DC Tie University ‐Quartz(max 140%,Daves‐Quartz)
DC Tie University ‐Soldotna(max 140% ,Daves‐Quartz)
15 DC Tie University ‐Soldotna(max 136%,Daves ‐Quartz)
7
Southern Tie 138 kV
Soldotna‐Diamond(max 121%,Anchor‐Diamond)
Soldotna‐Quartz(max 118%,Soldotna‐Sterling)
University ‐Quartz(max 140%,Daves ‐Quartz)
University ‐Soldotna(max 140% ,Daves‐Quartz)
Southern Tie 138 kV
1
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 28
Appendix D – Transient Analysis Contingency List
Table D.1 Stability Contingency List
Near Far
a1 Bradley‐Soldotna 115 Soldotna 5 5
a2 Bradley‐Soldotna 115 Brad_Lk 5 5
a3 Soldotna‐Sterling 115 Soldotna 5 5
a4 Soldotna‐Sterling 115 Sterling 5 5
a5 Sterling‐Quartz 115 Sterling 5 5
a6 Sterling‐Quartz 115 Quartz 5 5
a7 Quartz‐Daves 115 Quartz 5 5
a8 Quartz‐Daves 115 Daves_Ck 5 5
a9 University‐Plant_2 230 University 5 5
a10 University‐Plant_2 230 Plant_2 5 5
a11 Soldotna_SVC 115 Soldotna 5 5
a12 Daves_SVC 115 Quartz 5 5
a13 230_Cable Pt. MacKenzie Plant 2 230 Plant_2 5 5
b1 230_Cable Pt. MacKenzie Plant 2 230 Pt_Mack 5 5
b2 Pt.Mack‐Teeland 230 Pt_Mack 5 5
b3 Pt.Mack‐Teeland 230 Teeland 5 5
w1 Pt.Mack‐Douglas 230 Pt_Mack 5 5
w2 Pt.Mack‐Douglas 230 Douglas 5 5
w3 Pt.Mack‐Lorraine 230 Pt_Mack 5 5
w4 Pt.Mack‐Lorraine 230 Lorraine 5 5
w5 Watana‐Gold Creek 115 Watana 5 5
w6 Watana‐Gold Creek 115 Gold_Ck 5 5
c1 Kenai_Tie 115 University 5 5
c2 Kenai_Tie 115 Daves_Ck 5 5
c3 Kenai_Tie 230 University 5 5
c4 Kenai_Tie 230 Daves_Ck 5 5
c5 South_Tie 138 ITSS 5 5
c6 South_Tie 138 Bernice 5 5
c7 South_Tie 230 ITSS 5 5
c8 South_Tie 230 Bernice 5 5
c9 Bradley ‐Quartz 115 Brad_Lk 5 5
c10 Bradley ‐Quartz 115 Quartz 5 5
c11 DC_tie 100 Bernice 5 5
c12 DC_tie 100 Beluga 5 5
g1 ITSS_Unit_Trip n/a
g2 Bradley_Unit_Trip n/a
g3 Watana_Unit_Trip n/a
Dist
Name
Bernice International
Bernice International
Watana Gold Creek
Dave's Creek University
Dave's Creek University
Fault
Location
Clearing Time
(cycles)
Quartz Creek Daves Creek
University Plant 2
Volt
(kV)
Dave's Creek SVC
Soldotna Bradley Lake
Soldotna Sterling
Sterling Quartz Creek
Soldotna SVC
Beluga Bernice
Bradley Lake Unit #2 Trip
Watana Unit Trip
Name From Bus To Bus
Pt. MacKenzie Teeland
Pt. MacKenzie Douglas
Pt. MacKenzie Lorraine
ITSS Unit #3 Trip
Quartz Creek Bradley Lake
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 29
Appendix E – Transient Analysis – Winter Peak
Table E.1 Stability Results – Winter Peak – Cases A, B, and C
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11 a12 a13 b1 b2 b3 c1 c2 c3 c4 c5 c6 c7 c8 c9 c10 c11 c12 g1 g2 g3
Abase 96 xxxxxxxxxxxxxxxxxx x x
B 1 108 xxxxxxxxxxxxxxxxxx xx x x
B 2 108 xxxxxxxxxxxxxxxxxx xx x x
B 3 108 xxxxxxxxxxxxxxxxxx xx x x
B 4 108 xxxxxxxxxxxxxxxxxx xx x x
B 5 108 xxxxxxxxxxxxxxxx xxxx xx x x
B 6 108 xxxxxxxxxxxxxxxx xx xxxx x x
B 7 108 xxxxxxxxxxxxxxxx xx xx x x
B 8 108 xxxxxxxxxxxxxxxx xx x x
B 9 108 xxxxxxxxxxxxxxxxxx xx x x
B 10 108 xxxxxxxxxxxxxxxxxx xx x x
B 11 108 xxxxxxxxxxxxxxxxxx xx x x
B 12 108 xxxxxxxxxxxxxxxxxx xx x x
B 13 108 xxxxxxxxxxxxxxxx xx x x
B 14 108 xxxxxxxxxxxxxxxxxx xxx x
B 15 108 xxxxxxxxxxxxxxxxxx xxx x
B 16 108 xxxxxxxxxxxxxxxxxx xxx x
B 17 108 xxxxxxxxxxxxxxxx xx xxx x
B 18 108 xxxxxxxxxxxxxxxx xxxx x x
B 19 108 xxxxxxxxxxxxxxxx xx xx x x
C 1 122 xxxxxxxxxxxxxxxxxx xx x x
C 2 122 xxxxxxxxxxxxxxxxxx xx x x
C 3 122 xxxxxxxxxxxxxxxxxx xx x x
C 4 122 xxxxxxxxxxxxxxxxxx xx x x
C 5 122 xxxxxxxxxxxxxxxx xxxx xx x x
C 6 122 xxxxxxxxxxxxxxxx xx xxxx x x
C 7 122 xxxxxxxxxxxxxxxx xx xx x x
C 8 122 xxxxxxxxxxxxxxxx xx x x
C 9 122 xxxxxxxxxxxxxxxxxx xx x x
C 10 122 xxxxxxxxxxxxxxxxxx xx x x
C 11 122 xxxxxxxxxxxxxxxxxx xx x x
C 12 122 xxxxxxxxxxxxxxxxxx xx x x
C 13 122 xxxxxxxxxxxxxxxx xx x x
C 14 122 xxxxxxxxxxxxxxxxxx xxx x
C 15 122 xxxxxxxxxxxxxxxxxx xxx x
C 16 122 xxxxxxxxxxxxxxxxxx xxx x
C 17 122 xxxxxxxxxxxxxxxx xx xxx x
C 18 122 xxxxxxxxxxxxxxxx xxxx x x
C 19 122 xxxxxxxxxxxxxxxx xx xx x x
out of step on Soldotna ‐ Diamond local line
out of step on Quartz ‐ Bradley Lake line
out of step on Dave's Creek ‐ Hope
Gen
Case
Kenai
Export
(MW)
Trans
Config
ITSS_Unit_TripBradley_Unit_TripWatana_Unit_TripSouth_Tie_230@BerniceKenai_Tie_115@UniversityKenai_Tie_115@Daves_CkKenai_Tie_230@UniversityKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@BerniceSouth_Tie_230@ITSS'DC_tie_100@Bernice''DC_tie_100@Beluga'Pt.Mack‐Teeland_230@TeelandSterling‐Quartz_115@QuartzBradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@QuartzSterling‐Quartz_115@SterlingQuartz‐Daves_115@QuartzQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityUniversity‐Plant_2_230@Plant_2Soldotna_SVC_115@SoldotnaDaves_SVC_115@Quartz230_Cable_230@Plant_2230_Cable_230@Pt_MackPt.Mack‐Teeland_230@Pt_Mack
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 30
Table E.2 Stability Results – Winter Peak –Cases C1 and C2
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11 a12 a13 b1 b2 b3 c1 c2 c3 c4 c5 c6 c7 c8 c9 c10 c11 c12 g1 g2 g3
C1 1 123 xxxxxxxxxxxxxxxxxx xx x x
C1 2 123 xxxxxxxxxxxxxxxxxx xx x x
C1 3 123 xxxxxxxxxxxxxxxxxx xx x x
C1 4 123 xxxxxxxxxxxxxxxxxx xx x x
C1 5 123 xxxxxxxxxxxxxxxx xxxx xx x x
C1 6 123 xxxxxxxxxxxxxxxx xx xxxx x x
C1 7 123 xxxxxxxxxxxxxxxx xx xx x x
C1 8 123 xxxxxxxxxxxxxxxx xx x x
C1 9 123 xxxxxxxxxxxxxxxxxx xx x x
C1 10 123 xxxxxxxxxxxxxxxxxx xx x x
C1 11 123 xxxxxxxxxxxxxxxxxx xx x x
C1 12 123 xxxxxxxxxxxxxxxxxx xx x x
C1 13 123 xxxxxxxxxxxxxxxx xx x x
C1 14 123 xxxxxxxxxxxxxxxxxx xxx x
C1 15 123 xxxxxxxxxxxxxxxxxx xxx x
C1 16 123 xxxxxxxxxxxxxxxxxx xxx x
C1 17 123 xxxxxxxxxxxxxxxx xx xxx x
C1 18 123 xxxxxxxxxxxxxxxx xxxx x x
C1 19 123 xxxxxxxxxxxxxxxx xx xx x x
C2 1 77 xxxxxxxxxxxxxxxxxx xx x x
C2 2 77 xxxxxxxxxxxxxxxxxx xx x x
C2 3 77 xxxxxxxxxxxxxxxxxx xx x x
C2 4 77 xxxxxxxxxxxxxxxxxx xx x x
C2 5 77 xxxxxxxxxxxxxxxx xxxx xx x x
C2 6 77 xxxxxxxxxxxxxxxx xx xxxx x x
C2 7 77 xxxxxxxxxxxxxxxx xx xx x x
C2 8 77 xxxxxxxxxxxxxxxx xx x x
C2 9 77 xxxxxxxxxxxxxxxxxx xx x x
C2 10 77 xxxxxxxxxxxxxxxxxx xx x x
C2 11 77 xxxxxxxxxxxxxxxxxx xx x x
C2 12 77 xxxxxxxxxxxxxxxxxx xx x x
C2 13 77 xxxxxxxxxxxxxxxx xx x x
C2 14 77 xxxxxxxxxxxxxxxxxx xxx x
C2 15 77 xxxxxxxxxxxxxxxxxx xxx x
C2 16 77 xxxxxxxxxxxxxxxxxx xxx x
C2 17 77 xxxxxxxxxxxxxxxx xx xxx x
C2 18 77 xxxxxxxxxxxxxxxx xxxx x x
C2 19 77 xxxxxxxxxxxxxxxx xx xx x x
out of step on Soldotna ‐ Diamond local line
out of step on Quartz ‐ Bradley Lake line
out of step on Dave's Creek ‐ Hope
out of step on Soldotna ‐ Quartz Creek
out of step on Quartz ‐ Sterling 230_Cable_230@Plant_2Pt.Mack‐Teeland_230@Pt_MackPt.Mack‐Teeland_230@Teeland230_Cable_230@Pt_MackQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityUniversity‐Plant_2_230@Plant_2Soldotna_SVC_115@SoldotnaDaves_SVC_115@QuartzSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@SterlingSterling‐Quartz_115@QuartzQuartz‐Daves_115@QuartzGen
Case
Trans
Config
Kenai
Export
(MW)Bradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkITSS_Unit_TripBradley_Unit_TripWatana_Unit_TripKenai_Tie_115@UniversityKenai_Tie_115@Daves_CkKenai_Tie_230@UniversityKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@BerniceSouth_Tie_230@ITSSSouth_Tie_230@BerniceBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@Quartz'DC_tie_100@Bernice''DC_tie_100@Beluga'
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 31
Table E.3 Stability Results – Winter Peak – Cases D and E
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11a12a13w1w2w3w4w5w6 c1 c2 c3 c4 c5 c6c7c8c9c10c11c12 g1 g2 g3
D 1 30 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 2 30 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 3 30 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 4 30 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 5 30 xxxxxxxxxxxxxxxxxxx xxxx xx xxx
D 6 30 xxxxxxxxxxxxxxxxxxx xx xxxx x x x
D 7 30 xxxxxxxxxxxxxxxxxxx xx xx xxx
D 8 30 xxxxxxxxxxxxxxxxxxx xx xxx
D 9 30 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 10 30 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 11 30 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 12 30 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 13 30 xxxxxxxxxxxxxxxxxxx xx xxx
D 14 30 xxxxxxxxxxxxxxxxxxxxx xxxxx
D 15 30 xxxxxxxxxxxxxxxxxxxxx xxxxx
D 16 30 xxxxxxxxxxxxxxxxxxxxx xxxxx
D 17 30 xxxxxxxxxxxxxxxxxxx xx xxxxx
D 18 30 xxxxxxxxxxxxxxxxxxx xxxx xxx
D 19 30 xxxxxxxxxxxxxxxxxxx xx xx xxx
E 1 37 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 2 37 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 3 37 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 4 37 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 5 37 xxxxxxxxxxxxxxxxxxx xxxx xx xxx
E 6 37 xxxxxxxxxxxxxxxxxxx xx xxxx x x x
E 7 37 xxxxxxxxxxxxxxxxxxx xx xx xxx
E 8 37 xxxxxxxxxxxxxxxxxxx xx xxx
E 9 37 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 10 37 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 11 37 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 12 37 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 13 37 xxxxxxxxxxxxxxxxxxx xx xxx
E 14 37 xxxxxxxxxxxxxxxxxxxxx xxxxx
E 15 37 xxxxxxxxxxxxxxxxxxxxx xxxxx
E 16 37 xxxxxxxxxxxxxxxxxxxxx xxxxx
E 17 37 xxxxxxxxxxxxxxxxxxx xx xxxxx
E 18 37 xxxxxxxxxxxxxxxxxxx xxxx xxx
E 19 37 xxxxxxxxxxxxxxxxxxx xx xx xxx
out of step on Soldotna ‐ Diamond local line Watana_Unit_TripKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@BerniceSouth_Tie_230@ITSSSouth_Tie_230@Bernice'DC_tie_100@Bernice''DC_tie_100@Beluga'Watana‐Gold Creek_115@WatanaWatana‐Gold Creek_115@Gold_CkKenai_Tie_115@UniversityKenai_Tie_115@Daves_CkKenai_Tie_230@UniversityBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@QuartzITSS_Unit_TripPt.Mack‐Douglas_230@Pt_MackPt.Mack‐Douglas_230@DouglasPt.Mack‐Lorraine_230@Pt_MackPt.Mack‐Lorraine_230@LorraineSoldotna_SVC_115@SoldotnaDaves_SVC_115@Quartz230_Cable_230@Plant_2Gen
Case
Trans
Config
Kenai
Export
(MW)Bradley_Unit_TripSterling‐Quartz_115@QuartzQuartz‐Daves_115@QuartzQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityUniversity‐Plant_2_230@Plant_2Bradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@Sterling
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 32
Table E.4 Stability Results – Winter Peak – Cases F, G, and H
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11a12a13w1w2w3w4w5w6c1c2c3c4c5c6c7c8c9c10c11c12 g1 g2 g3
F 1 49 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 2 49 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 3 49 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 4 49 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 5 49 x xxxxxxxxxxxxxxxxxx xxxx xx xxx
F 6 49 x xxxxxxxxxxxxxxxxxx xx xxxx xxx
F 7 49 x xxxxxxxxxxxxxxxxxx xx xx xxx
F 8 49 x xxxxxxxxxxxxxxxxxx xx xxx
F 9 49 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 10 49 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 11 49 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 12 49 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 13 49 x xxxxxxxxxxxxxxxxxx xx xxx
F 14 49 x xxxxxxxxxxxxxxxxxxxx xxxxx
F 15 49 x xxxxxxxxxxxxxxxxxxxx xxxxx
F 16 49 x xxxxxxxxxxxxxxxxxxxx xxxxx
F 17 49 x xxxxxxxxxxxxxxxxxx xx xxxxx
F 18 49 x xxxxxxxxxxxxxxxxxx xxxx xxx
F 19 49 x xxxxxxxxxxxxxxxxxx xx xx xxx
G1‐13 x xxxxxxxxxxxxxxxxxxxx xx xxx
G2‐13 x xxxxxxxxxxxxxxxxxxxx xx xxx
G3‐13 x xxxxxxxxxxxxxxxxxxxx xx xxx
G4‐13 x xxxxxxxxxxxxxxxxxxxx xx xxx
G5‐13 x xxxxxxxxxxxxxxxxxx xxxx xx xxx
G6‐13 x xxxxxxxxxxxxxxxxxx xx xxxx xxx
G7‐13 x xxxxxxxxxxxxxxxxxx xx xx xxx
G8‐13 x xxxxxxxxxxxxxxxxxx xx xxx
G9‐13 x xxxxxxxxxxxxxxxxxxxx xx xxx
G10‐13 x xxxxxxxxxxxxxxxxxxxx xx xxx
G11‐13 x xxxxxxxxxxxxxxxxxxxx xx xxx
G12‐13 x xxxxxxxxxxxxxxxxxxxx xx xxx
G13‐13 x xxxxxxxxxxxxxxxxxx xx xxx
G14‐13 x xxxxxxxxxxxxxxxxxxxx xxxxx
G15‐13 x xxxxxxxxxxxxxxxxxxxx xxxxx
G16‐13 x xxxxxxxxxxxxxxxxxxxx xxxxx
G17‐13 x xxxxxxxxxxxxxxxxxx xx xxxxx
G18‐13 x xxxxxxxxxxxxxxxxxx xxxx xxx
G19‐13 x xxxxxxxxxxxxxxxxxx xx xx xxx
H 1 19 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 2 19 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 3 19 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 4 19 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 5 19 x xxxxxxxxxxxxxxxxxx xxxx xx xxx
H 6 19 x xxxxxxxxxxxxxxxxxx xx xxxx xxx
H 7 19 x xxxxxxxxxxxxxxxxxx xx xx xxx
H 8 19 x xxxxxxxxxxxxxxxxxx xx xxx
H 9 19 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 10 19 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 11 19 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 12 19 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 13 19 x xxxxxxxxxxxxxxxxxx xx xxx
H 14 19 x xxxxxxxxxxxxxxxxxxxx xxxxx
H 15 19 x xxxxxxxxxxxxxxxxxxxx xxxxx
H 16 19 x xxxxxxxxxxxxxxxxxxxx xxxxx
H 17 19 x xxxxxxxxxxxxxxxxxx xx xxxxx
H 18 19 x xxxxxxxxxxxxxxxxxx xxxx xxx
H 19 19 x xxxxxxxxxxxxxxxxxx xx xx xxx
out of step on Soldotna ‐ Diamond local line
Kenai
Export
(MW)Bradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSouth_Tie_230@BerniceBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@QuartzKenai_Tie_230@UniversityKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@BerniceSouth_Tie_230@ITSSWatana‐Gold Creek_115@Gold_CkKenai_Tie_115@UniversityKenai_Tie_115@Daves_CkWatana_Unit_TripITSS_Unit_TripBradley_Unit_Trip'DC_tie_100@Bernice''DC_tie_100@Beluga'Pt.Mack‐Douglas_230@Pt_MackPt.Mack‐Douglas_230@DouglasPt.Mack‐Lorraine_230@Pt_MackUniversity‐Plant_2_230@Plant_2Soldotna_SVC_115@SoldotnaDaves_SVC_115@Quartz230_Cable_230@Plant_2Pt.Mack‐Lorraine_230@LorraineWatana‐Gold Creek_115@WatanaGen
Case
Trans
Config
Sterling‐Quartz_115@SterlingSterling‐Quartz_115@QuartzQuartz‐Daves_115@QuartzQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@University
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 33
Appendix F – Transient Analysis – Summer Peak
Table F.1 Stability Results – Summer Peak – Cases A, B, and C
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11a12a13b1b2b3c1c2c3c4c5c6c7c8c9c10c11c12 g1 g2 g3
Abase 99 x xxxxxxxxxxxxxxxxx xx
B 1 109 x xxxxxxxxxxxxxxxxx xx xx
B 2 109 x xxxxxxxxxxxxxxxxx xx xx
B 3 109 x xxxxxxxxxxxxxxxxx xx xx
B 4 109 x xxxxxxxxxxxxxxxxx xx xx
B 5 109 x xxxxxxxxxxxxxxx xxxx xx xx
B 6 109 x xxxxxxxxxxxxxxx xx xxxx xx
B 7 109 x xxxxxxxxxxxxxxx xx xx xx
B 8 109 x xxxxxxxxxxxxxxx xx xx
B 9 109 x xxxxxxxxxxxxxxxxx xx xx
B 10 109 x xxxxxxxxxxxxxxxxx xx xx
B 11 109 x xxxxxxxxxxxxxxxxx xx xx
B 12 109 x xxxxxxxxxxxxxxxxx xx xx
B 13 109 x xxxxxxxxxxxxxxx xx xx
B 14 109 x xxxxxxxxxxxxxxxxx xxxx
B 15 109 x xxxxxxxxxxxxxxxxx xxxx
B 16 109 x xxxxxxxxxxxxxxxxx xxxx
B 17 109 x xxxxxxxxxxxxxxx xx xxxx
B 18 109 x xxxxxxxxxxxxxxx xxxx xx
B 19 109 x xxxxxxxxxxxxxxx xx xx xx
C 1 125 x xxxxxxxxxxxxxxxxx xx xx
C 2 125 x xxxxxxxxxxxxxxxxx xx xx
C 3 125 x xxxxxxxxxxxxxxxxx xx xx
C 4 125 x xxxxxxxxxxxxxxxxx xx xx
C 5 125 x xxxxxxxxxxxxxxx xxxx xx xx
C 6 125 x xxxxxxxxxxxxxxx xx xxxx xx
C 7 125 x xxxxxxxxxxxxxxx xx xx xx
C 8 125 x xxxxxxxxxxxxxxx xx xx
C 9 125 x xxxxxxxxxxxxxxxxx xx xx
C 10 125 x xxxxxxxxxxxxxxxxx xx xx
C 11 125 x xxxxxxxxxxxxxxxxx xx xx
C 12 125 x xxxxxxxxxxxxxxxxx xx xx
C 13 125 x xxxxxxxxxxxxxxx xx xx
C 14 125 x xxxxxxxxxxxxxxxxx xxxx
C 15 125 x xxxxxxxxxxxxxxxxx xxxx
C 16 125 x xxxxxxxxxxxxxxxxx xxxx
C 17 125 x xxxxxxxxxxxxxxx xx xxxx
C 18 125 x xxxxxxxxxxxxxxx xxxx xx
C 19 125 x xxxxxxxxxxxxxxx xx xx xx
out of step on Soldotna ‐ Diamond local line
out of step on Quartz ‐ Bradley Lake line
Gen
Case
Trans
Config
Kenai_Tie_230@UniversityKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@BerniceSouth_Tie_230@ITSSSouth_Tie_230@BerniceBradley‐Quartz_115@Brad_LkKenai_Tie_115@Daves_CkQuartz‐Daves_115@QuartzKenai
Export
(MW)Kenai_Tie_115@UniversitySterling‐Quartz_115@QuartzBradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@SterlingQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityUniversity‐Plant_2_230@Plant_2Soldotna_SVC_115@Soldotna'DC_tie_100@Bernice''DC_tie_100@Beluga'Daves_SVC_115@Quartz230_Cable_230@Plant_2230_Cable_230@Pt_MackPt.Mack‐Teeland_230@Pt_MackPt.Mack‐Teeland_230@TeelandBradley‐Quartz_115@QuartzITSS_Unit_TripBradley_Unit_TripWatana_Unit_Trip
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 34
Table F.2 Stability Results – Summer Peak – Cases C1 and C2
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11a12a13b1b2b3c1c2c3c4c5c6c7c8c9c10c11c12 g1 g2 g3
C1 1 124 xxxxxxxxxxxxxxxxxx xx xx
C1 2 124 xxxxxxxxxxxxxxxxxx xx xx
C1 3 124 xxxxxxxxxxxxxxxxxx xx xx
C1 4 124 xxxxxxxxxxxxxxxxxx xx xx
C1 5 124 xxxxxxxxxxxxxxxx xxxx xx xx
C1 6 124 xxxxxxxxxxxxxxxx xx xxxx xx
C1 7 124 xxxxxxxxxxxxxxxx xx xx xx
C1 8 124 xxxxxxxxxxxxxxxx xx xx
C1 9 124 xxxxxxxxxxxxxxxxxx xx xx
C1 10 124 xxxxxxxxxxxxxxxxxx xx xx
C1 11 124 xxxxxxxxxxxxxxxxxx xx xx
C1 12 124 xxxxxxxxxxxxxxxxxx xx xx
C1 13 124 xxxxxxxxxxxxxxxx xx xx
C1 14 124 xxxxxxxxxxxxxxxxxx xxxx
C1 15 124 xxxxxxxxxxxxxxxxxx xxxx
C1 16 124 xxxxxxxxxxxxxxxxxx xxxx
C1 17 124 xxxxxxxxxxxxxxxx xx xxxx
C1 18 124 xxxxxxxxxxxxxxxx xxxx xx
C1 19 124 xxxxxxxxxxxxxxxx xx xx xx
C2 1 99 xxxxxxxxxxxxxxxxxx xx xx
C2 2 99 xxxxxxxxxxxxxxxxxx xx xx
C2 3 99 xxxxxxxxxxxxxxxxxx xx xx
C2 4 99 xxxxxxxxxxxxxxxxxx xx xx
C2 5 99 xxxxxxxxxxxxxxxx xxxx xx xx
C2 6 99 xxxxxxxxxxxxxxxx xx xxxx xx
C2 7 99 xxxxxxxxxxxxxxxx xx xx xx
C2 8 99 xxxxxxxxxxxxxxxx xx xx
C2 9 99 xxxxxxxxxxxxxxxxxx xx xx
C2 10 99 xxxxxxxxxxxxxxxxxx xx xx
C2 11 99 xxxxxxxxxxxxxxxxxx xx xx
C2 12 99 xxxxxxxxxxxxxxxxxx xx xx
C2 13 99 xxxxxxxxxxxxxxxx xx xx
C2 14 99 xxxxxxxxxxxxxxxxxx xxxx
C2 15 99 xxxxxxxxxxxxxxxxxx xxxx
C2 16 99 xxxxxxxxxxxxxxxxxx xxxx
C2 17 99 xxxxxxxxxxxxxxxx xx xxxx
C2 18 99 xxxxxxxxxxxxxxxx xxxx xx
C2 19 99 xxxxxxxxxxxxxxxx xx xx xx
out of step on Soldotna ‐ Diamond local line
out of step on Quartz ‐ Bradley Lake line
out of step on Dave's Creek ‐ HopeUniversity‐Plant_2_230@Plant_2Soldotna_SVC_115@SoldotnaDaves_SVC_115@Quartz230_Cable_230@Plant_2230_Cable_230@Pt_MackPt.Mack‐Teeland_230@Pt_MackPt.Mack‐Teeland_230@TeelandKenai_Tie_115@UniversityKenai_Tie_115@Daves_CkWatana_Unit_TripQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityKenai_Tie_230@UniversityKenai_Tie_230@Daves_CkSouth_Tie_138@BerniceSouth_Tie_230@ITSSSouth_Tie_230@BerniceBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@Quartz'DC_tie_100@Bernice''DC_tie_100@Beluga'ITSS_Unit_TripBradley_Unit_TripSouth_Tie_138@ITSSGen
Case
Trans
Config
Kenai
Export
(MW)Bradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@SterlingSterling‐Quartz_115@QuartzQuartz‐Daves_115@Quartz
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 35
Table F.3 Stability Results – Summer Peak – Cases D and E
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11a12a13w1w2w3w4w5w6 c1 c2 c3 c4 c5 c6c7c8c9c10c11c12 g1 g2 g3
D 1 61 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 2 61 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 3 61 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 4 61 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 5 61 xxxxxxxxxxxxxxxxxxx xxxx xx xxx
D 6 61 xxxxxxxxxxxxxxxxxxx xx xxxx xxx
D 7 61 xxxxxxxxxxxxxxxxxxx xx xx xxx
D 8 61 xxxxxxxxxxxxxxxxxxx xx xxx
D 9 61 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 10 61 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 11 61 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 12 61 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 13 61 xxxxxxxxxxxxxxxxxxx xx xxx
D 14 61 xxxxxxxxxxxxxxxxxxxxx xxxxx
D 15 61 xxxxxxxxxxxxxxxxxxxxx xxxxx
D 16 61 xxxxxxxxxxxxxxxxxxxxx xxxxx
D 17 61 xxxxxxxxxxxxxxxxxxx xx xxxxx
D 18 61 xxxxxxxxxxxxxxxxxxx xxxx xxx
D 19 61 xxxxxxxxxxxxxxxxxxx xx xx xxx
E 1 67 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 2 67 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 3 67 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 4 67 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 5 67 xxxxxxxxxxxxxxxxxxx xxxx xx xxx
E 6 67 xxxxxxxxxxxxxxxxxxx xx xxxx xxx
E 7 67 xxxxxxxxxxxxxxxxxxx xx xx xxx
E 8 67 xxxxxxxxxxxxxxxxxxx xx xxx
E 9 67 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 10 67 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 11 67 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 12 67 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 13 67 xxxxxxxxxxxxxxxxxxx xx xxx
E 14 67 xxxxxxxxxxxxxxxxxxxxx xxxxx
E 15 67 xxxxxxxxxxxxxxxxxxxxx xxxxx
E 16 67 xxxxxxxxxxxxxxxxxxxxx xxxxx
E 17 67 xxxxxxxxxxxxxxxxxxx xx xxxxx
E 18 67 xxxxxxxxxxxxxxxxxxx xxxx xxx
E 19 67 xxxxxxxxxxxxxxxxxxx xx xx xxx
out of step on Soldotna ‐ Diamond local line
Tesoro out of step, Tesoro ‐ Soldotna line ITSS_Unit_TripPt.Mack‐Lorraine_230@Pt_MackSouth_Tie_230@ITSSSouth_Tie_230@BerniceBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@QuartzKenai_Tie_115@Daves_CkKenai_Tie_230@UniversityKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSBradley_Unit_TripWatana_Unit_TripSouth_Tie_138@Bernice'DC_tie_100@Bernice''DC_tie_100@Beluga'Watana‐Gold Creek_115@WatanaWatana‐Gold Creek_115@Gold_CkKenai_Tie_115@UniversitySoldotna_SVC_115@SoldotnaDaves_SVC_115@Quartz230_Cable_230@Plant_2Pt.Mack‐Douglas_230@Pt_MackPt.Mack‐Douglas_230@DouglasGen
Case
Trans
Config
Sterling‐Quartz_115@QuartzQuartz‐Daves_115@QuartzQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityBradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@SterlingKenai
Export
(MW)University‐Plant_2_230@Plant_2Pt.Mack‐Lorraine_230@Lorraine
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 36
Table F.4 Stability Results – Summer Peak – Cases F, G, and H
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10a11a12a13w1 w2 w3 w4 w5 w6 c1 c2 c3 c4 c5 c6 c7 c8 c9 c10c11c12 g1 g2 g3
F 1 89 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 2 89 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 3 89 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 4 89 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 5 89 x xxxxxxxxxxxxxxxxxx xxxx xx xxx
F 6 89 x xxxxxxxxxxxxxxxxxx xx xxxx xxx
F 7 89 x xxxxxxxxxxxxxxxxxx xx xx xxx
F 8 89 x xxxxxxxxxxxxxxxxxx xx xxx
F 9 89 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 10 89 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 11 89 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 12 89 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 13 89 x xxxxxxxxxxxxxxxxxx xx xxx
F 14 89 x xxxxxxxxxxxxxxxxxxxx xxxxx
F 15 89 x xxxxxxxxxxxxxxxxxxxx xxxxx
F 16 89 x xxxxxxxxxxxxxxxxxxxx xxxxx
F 17 89 x xxxxxxxxxxxxxxxxxx xx xxxxx
F 18 89 x xxxxxxxxxxxxxxxxxx xxxx xxx
F 19 89 x xxxxxxxxxxxxxxxxxx xx xx xxx
G 1 6 x xxxxxxxxxxxxxxxxxxxx xx xxx
G 2 6 x xxxxxxxxxxxxxxxxxxxx xx xxx
G 3 6 x xxxxxxxxxxxxxxxxxxxx xx xxx
G 4 6 x xxxxxxxxxxxxxxxxxxxx xx xxx
G 5 6 x xxxxxxxxxxxxxxxxxx xxxx xx xxx
G 6 6 x xxxxxxxxxxxxxxxxxx xx xxxx xxx
G 7 6 x xxxxxxxxxxxxxxxxxx xx xx xxx
G 8 6 x xxxxxxxxxxxxxxxxxx xx xxx
G 9 6 x xxxxxxxxxxxxxxxxxxxx xx xxx
G 10 6 x xxxxxxxxxxxxxxxxxxxx xx xxx
G 11 6 x xxxxxxxxxxxxxxxxxxxx xx xxx
G 12 6 x xxxxxxxxxxxxxxxxxxxx xx xxx
G 13 6 x xxxxxxxxxxxxxxxxxx xx xxx
G 14 6 x xxxxxxxxxxxxxxxxxxxx xxxxx
G 15 6 x xxxxxxxxxxxxxxxxxxxx xxxxx
G 16 6 x xxxxxxxxxxxxxxxxxxxx xxxxx
G 17 6 x xxxxxxxxxxxxxxxxxx xx xxxxx
G 18 6 x xxxxxxxxxxxxxxxxxx xxxx xxx
G 19 6 x xxxxxxxxxxxxxxxxxx xx xx xxx
H 1 11 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 2 11 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 3 11 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 4 11 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 5 11 x xxxxxxxxxxxxxxxxxx xxxx xx xxx
H 6 11 x xxxxxxxxxxxxxxxxxx xx xxxx xxx
H 7 11 x xxxxxxxxxxxxxxxxxx xx xx xxx
H 8 11 x xxxxxxxxxxxxxxxxxx xx xxx
H 9 11 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 10 11 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 11 11 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 12 11 x xxxxxxxxxxxxxxxxxxxx xx xxx
H 13 11 x xxxxxxxxxxxxxxxxxx xx xxx
H 14 11 x xxxxxxxxxxxxxxxxxxxx xxxxx
H 15 11 x xxxxxxxxxxxxxxxxxxxx xxxxx
H 16 11 x xxxxxxxxxxxxxxxxxxxx xxxxx
H 17 11 x xxxxxxxxxxxxxxxxxx xx xxxxx
H 18 11 x xxxxxxxxxxxxxxxxxx xxxx xxx
H 19 11 x xxxxxxxxxxxxxxxxxx xx xx xxx
out of step on Soldotna ‐ Diamond local line Kenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@Bernice'DC_tie_100@Bernice''DC_tie_100@Beluga'Gen
Case
Trans
Config
Sterling‐Quartz_115@QuartzQuartz‐Daves_115@QuartzQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@SterlingKenai
Export
(MW)Bradley‐Soldotna_115@SoldotnaUniversity‐Plant_2_230@Plant_2Pt.Mack‐Lorraine_230@LorraineWatana‐Gold Creek_115@WatanaWatana‐Gold Creek_115@Gold_CkKenai_Tie_115@UniversitySoldotna_SVC_115@SoldotnaDaves_SVC_115@Quartz230_Cable_230@Plant_2Pt.Mack‐Douglas_230@Pt_MackPt.Mack‐Douglas_230@DouglasPt.Mack‐Lorraine_230@Pt_MackBradley_Unit_TripWatana_Unit_TripSouth_Tie_230@ITSSSouth_Tie_230@BerniceBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@QuartzITSS_Unit_TripKenai_Tie_115@Daves_CkKenai_Tie_230@University
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 37
Appendix G – Transient Analysis – Summer Valley
Table G.1 Stability Results – Summer Valley – Cases A, B, and C
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11a12a13b1b2b3c1c2c3c4c5c6c7c8c9c10c11c12 g1 g2 g3
Abase 99 x xxxxxxxxxxxxxxxxx xx
B 1 111 x xxxxxxxxxxxxxxxxx xx xx
B 2 111 x xxxxxxxxxxxxxxxxx xx xx
B 3 111 x xxxxxxxxxxxxxxxxx xx xx
B 4 111 x xxxxxxxxxxxxxxxxx xx xx
B 5 111 x xxxxxxxxxxxxxxx xxxx xx xx
B 6 111 x xxxxxxxxxxxxxxx xx xxxx xx
B 7 111 x xxxxxxxxxxxxxxx xx xx xx
B 8 111 x xxxxxxxxxxxxxxx xx xx
B 9 111 x xxxxxxxxxxxxxxxxx xx xx
B 10 111 x xxxxxxxxxxxxxxxxx xx xx
B 11 111 x xxxxxxxxxxxxxxxxx xx xx
B 12 111 x xxxxxxxxxxxxxxxxx xx xx
B 13 111 x xxxxxxxxxxxxxxx xx xx
B 14 111 x xxxxxxxxxxxxxxxxx xxxx
B 15 111 x xxxxxxxxxxxxxxxxx xxxx
B 16 111 x xxxxxxxxxxxxxxxxx xxxx
B 17 111 x xxxxxxxxxxxxxxx xx xxxx
B 18 111 x xxxxxxxxxxxxxxx x xxx xx
B 19 111 x xxxxxxxxxxxxxxx x x xx xx
Ca 1 126 x xxxxxxxxxxxxxxxxx xx xx
Ca 2 126 x xxxxxxxxxxxxxxxxx xx xx
Ca 3 126 x xxxxxxxxxxxxxxxxx xx xx
Ca 4 126 x xxxxxxxxxxxxxxxxx xx xx
Ca 5 126 x xxxxxxxxxxxxxxx xxxx xx xx
Ca 6 126 x xxxxxxxxxxxxxxx xx xxxx xx
Ca 7 126 x xxxxxxxxxxxxxxx xx xx xx
Ca 8 126 x xxxxxxxxxxxxxxx xx xx
Ca 9 126 x xxxxxxxxxxxxxxxxx xx xx
Ca 10 126 x xxxxxxxxxxxxxxxxx xx xx
Ca 11 126 x xxxxxxxxxxxxxxxxx xx xx
Ca 12 126 x xxxxxxxxxxxxxxxxx xx xx
Ca 13 126 x xxxxxxxxxxxxxxx xx xx
Ca 14 126 x xxxxxxxxxxxxxxxxx xxxx
Ca 15 126 x xxxxxxxxxxxxxxxxx xxxx
Ca 16 126 x xxxxxxxxxxxxxxxxx xxxx
Ca 17 126 x xxxxxxxxxxxxxxx xx xxxx
Ca 18 126 x xxxxxxxxxxxxxxx xxxx xx
Ca 19 126 x xxxxxxxxxxxxxxx xx xx xx
out of step on Soldotna ‐ Diamond local line
out of step on Quartz ‐ Bradley Lake line
out of step on Dave's Creek ‐ Hope Pt.Mack‐Teeland_230@TeelandKenai_Tie_115@University'DC_tie_100@Bernice''DC_tie_100@Beluga'ITSS_Unit_TripBradley_Unit_TripWatana_Unit_TripKenai_Tie_230@UniversityBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@QuartzSouth_Tie_230@ITSSSouth_Tie_230@BerniceKenai_Tie_115@Daves_CkKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@BerniceGen
Case
Daves_SVC_115@QuartzBradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@SterlingSterling‐Quartz_115@QuartzQuartz‐Daves_115@QuartzQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityUniversity‐Plant_2_230@Plant_2Soldotna_SVC_115@Soldotna230_Cable_230@Plant_2230_Cable_230@Pt_MackPt.Mack‐Teeland_230@Pt_MackTrans
Config
Kenai
Export
(MW)
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 38
Table G.2 Stability Results – Summer Valley – Cases C1, C2
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11a12a13b1b2b3c1c2c3c4c5c6c7c8c9c10c11c12g1g2g3
C1a 1 127 xxxxxxxxxxxxxxxxxx xx xx
C1a 2 127 xxxxxxxxxxxxxxxxxx xx xx
C1a 3 127 xxxxxxxxxxxxxxxxxx xx xx
C1a 4 127 xxxxxxxxxxxxxxxxxx xx xx
C1a 5 127 xxxxxxxxxxxxxxxx xxxx xx xx
C1a 6 127 xxxxxxxxxxxxxxxx xx xxxx xx
C1a 7 127 xxxxxxxxxxxxxxxx xx xx xx
C1a 8 127 xxxxxxxxxxxxxxxx xx xx
C1a 9 127 xxxxxxxxxxxxxxxxxx xx xx
C1a 10 127 xxxxxxxxxxxxxxxxxx xx xx
C1a 11 127 xxxxxxxxxxxxxxxxxx xx xx
C1a 12 127 xxxxxxxxxxxxxxxxxx xx xx
C1a 13 127 xxxxxxxxxxxxxxxxx xx xx
C1a 14 127 xxxxxxxxxxxxxxxxxx xxxx
C1a 15 127 xxxxxxxxxxxxxxxxxx xxxx
C1a 16 127 xxxxxxxxxxxxxxxxxx xxxx
C1a 17 127 xxxxxxxxxxxxxxxx xx xxxx
C1a 18 127 xxxxxxxxxxxxxxxx xxxx xx
C1a 19 127 xxxxxxxxxxxxxxxx xx xx xx
C2a 1 118 xxxxxxxxxxxxxxxxxx xx xx
C2a 2 118 xxxxxxxxxxxxxxxxxx xx xx
C2a 3 118 xxxxxxxxxxxxxxxxxx xx xx
C2a 4 118 xxxxxxxxxxxxxxxxxx xx xx
C2a 5 118 xxxxxxxxxxxxxxxx xxxx xx xx
C2a 6 118 xxxxxxxxxxxxxxxx xx xxxx xx
C2a 7 118 xxxxxxxxxxxxxxxx xx xx xx
C2a 8 118 xxxxxxxxxxxxxxxx xx xx
C2a 9 118 xxxxxxxxxxxxxxxxxx xx xx
C2a 10 118 xxxxxxxxxxxxxxxxxx xx xx
C2a 11 118 xxxxxxxxxxxxxxxxxx xx xx
C2a 12 118 xxxxxxxxxxxxxxxxxx xx xx
C2a 13 118 xxxxxxxxxxxxxxxx xx xx
C2a 14 118 xxxxxxxxxxxxxxxxxx xxxx
C2a 15 118 xxxxxxxxxxxxxxxxxx xxxx
C2a 16 118 xxxxxxxxxxxxxxxxxx xxxx
C2a 17 118 xxxxxxxxxxxxxxxx xx xxxx
C2a 18 118 xxxxxxxxxxxxxxxx xxxx xx
C2a 19 118 xxxxxxxxxxxxxxxx xx xx xx
out of step on Soldotna ‐ Diamond local line
out of step on Quartz ‐ Bradley Lake line
out of step on Dave's Creek ‐ Hope
out of step on Soldotna ‐ Quartz Creek Bradley‐Quartz_115@Brad_LkBradley‐Quartz_115@Quartz'DC_tie_100@Bernice''DC_tie_100@Beluga'ITSS_Unit_TripBradley_Unit_TripWatana_Unit_TripGen
Case
Trans
Config
Kenai
Export
(MW)Bradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@SterlingSterling‐Quartz_115@QuartzQuartz‐Daves_115@QuartzQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityUniversity‐Plant_2_230@Plant_2Soldotna_SVC_115@SoldotnaDaves_SVC_115@Quartz230_Cable_230@Plant_2230_Cable_230@Pt_MackPt.Mack‐Teeland_230@TeelandPt.Mack‐Teeland_230@Pt_MackKenai_Tie_115@UniversityKenai_Tie_115@Daves_CkKenai_Tie_230@UniversityKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@BerniceSouth_Tie_230@ITSSSouth_Tie_230@Bernice
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 39
Table G.3 Stability Results – Summer Valley – Cases D and E
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11a12a13w1w2w3w4w5w6c1 c2 c3 c4 c5 c6c7c8c9c10c11c12g1 g2 g3
D 1 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 2 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 3 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 4 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 5 81 xxxxxxxxxxxxxxxxxxx xxxx xx xxx
D 6 81 xxxxxxxxxxxxxxxxxxx xx xxxx xxx
D 7 81 xxxxxxxxxxxxxxxxxxx xx xx xxx
D 8 81 xxxxxxxxxxxxxxxxxxx xx xxx
D 9 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 10 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 11 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 12 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
D 13 81 xxxxxxxxxxxxxxxxxxx xx xxx
D 14 81 xxxxxxxxxxxxxxxxxxxxx xxxxx
D 15 81 xxxxxxxxxxxxxxxxxxxxx xxxxx
D 16 81 xxxxxxxxxxxxxxxxxxxxx xxxxx
D 17 81 xxxxxxxxxxxxxxxxxxx xx xxxxx
D 18 81 xxxxxxxxxxxxxxxxxxx xxxx xxx
D 19 81 xxxxxxxxxxxxxxxxxxx xx xx xxx
E 1 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 2 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 3 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 4 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 5 81 xxxxxxxxxxxxxxxxxxx xxxx xx xxx
E 6 81 xxxxxxxxxxxxxxxxxxx xx xxxx xxx
E 7 81 xxxxxxxxxxxxxxxxxxx xx xx xxx
E 8 81 xxxxxxxxxxxxxxxxxxx xx xxx
E 9 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 10 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 11 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 12 81 xxxxxxxxxxxxxxxxxxxxx xx xxx
E 13 81 xxxxxxxxxxxxxxxxxxx xx xxx
E 14 81 xxxxxxxxxxxxxxxxxxxxx xxxxx
E 15 81 xxxxxxxxxxxxxxxxxxxxx xxxxx
E 16 81 xxxxxxxxxxxxxxxxxxxxx xxxxx
E 17 81 xxxxxxxxxxxxxxxxxxx xx xxxxx
E 18 81 xxxxxxxxxxxxxxxxxxx xxxx xxx
E 19 81 xxxxxxxxxxxxxxxxxxx xx xx xxx
out of step on Soldotna ‐ Diamond local line 'DC_tie_100@Bernice''DC_tie_100@Beluga'Kenai
Export
(MW)Bradley_Unit_TripWatana_Unit_TripSouth_Tie_230@ITSSSouth_Tie_230@BerniceBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@QuartzITSS_Unit_TripSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@SterlingPt.Mack‐Lorraine_230@Pt_MackPt.Mack‐Lorraine_230@LorraineWatana‐Gold Creek_115@WatanaWatana‐Gold Creek_115@Gold_CkKenai_Tie_115@UniversitySoldotna_SVC_115@SoldotnaDaves_SVC_115@Quartz230_Cable_230@Plant_2Pt.Mack‐Douglas_230@Pt_MackPt.Mack‐Douglas_230@DouglasKenai_Tie_115@Daves_CkGen
Case
Trans
Config
Quartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityUniversity‐Plant_2_230@Plant_2Bradley‐Soldotna_115@SoldotnaBradley‐Soldotna_115@Brad_LkSterling‐Quartz_115@QuartzQuartz‐Daves_115@QuartzKenai_Tie_230@UniversityKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@Bernice
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 40
Table G.4 Stability Results – Summer Valley – Cases F, G, and H
a1 a2 a3 a4 a5 a6 a7 a8 a9 a10 a11a12a13w1w2w3w4w5w6 c1 c2 c3 c4 c5 c6c7c8c9c10c11c12g1 g2 g3
F 1 99 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 2 99 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 3 99 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 4 99 x xxxxxxxxxxxxxxxxxxxx xx xxx
F 5 99 x xxxxxxxxxxxxxxxxxx xxxx xx xxx
F 6 99 x xxxxxxxxxxxxxxxxxx xx xxxx xxx
F 7 99 x xxxxxxxxxxxxxxxxxx xx xx xxx
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G 1 26 x xxxxxxxxxxxxxxxxxxxx xx xxx
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G 6 26 x xxxxxxxxxxxxxxxxxx xx xxxx xxx
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out of step on Soldotna ‐ Diamond local line Watana_Unit_TripSouth_Tie_230@ITSSSouth_Tie_230@BerniceBradley‐Quartz_115@Brad_LkBradley‐Quartz_115@QuartzITSS_Unit_TripBradley_Unit_TripPt.Mack‐Lorraine_230@Pt_MackPt.Mack‐Lorraine_230@LorraineWatana‐Gold Creek_115@WatanaWatana‐Gold Creek_115@Gold_CkKenai_Tie_115@UniversitySoldotna_SVC_115@SoldotnaDaves_SVC_115@Quartz230_Cable_230@Plant_2Pt.Mack‐Douglas_230@Pt_MackPt.Mack‐Douglas_230@Douglas'DC_tie_100@Bernice''DC_tie_100@Beluga'Kenai_Tie_115@Daves_CkKenai_Tie_230@UniversityKenai_Tie_230@Daves_CkSouth_Tie_138@ITSSSouth_Tie_138@BerniceSterling‐Quartz_115@QuartzQuartz‐Daves_115@QuartzQuartz‐Daves_115@Daves_CkUniversity‐Plant_2_230@UniversityBradley‐Soldotna_115@Brad_LkSoldotna‐Sterling_115@SoldotnaSoldotna‐Sterling_115@SterlingSterling‐Quartz_115@SterlingGen
Case
Trans
Config
Kenai
Export
(MW)University‐Plant_2_230@Plant_2Bradley‐Soldotna_115@Soldotna
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 41
Appendix H – DC Size Analysis Detailed Results
Table H.1 – Kenai Trip Analysis – Summer Valley
Initia Post MW %
75 39 9%
80 39 9%
90 29 6%
100 0 0%
75 39 9%
80 29 6%
90 0 0%
100 0 0%
75 39 9%
80 39 9%
90 39 9%
100 0 0%
75 39 9%
80 39 9%
90 0 0%
100 0 0%
load shedding in Anchorage and GVEA
75
75
DC Flow
(MW)
UFLS
Action
75
75
C1A 74 123 56
21
CA 73 127 59.8
Summer
Valley
16
CA 73 127 60.4
C1A 74 123 56.5
Kenai
Export
Daves ‐
Quartz
Season Trans
Config
Gen
Case
Spin
(MW)
Line Flow
Table H.2 – Kenai Trip Analysis – Summer Peak
Initial Post MW %
75 44 6%
80 44 6%
90 44 6%
100 0 0%
75 44 6%
80 44 6%
90 0 0%
100 0 0%
75 68 9%
80 44 6%
90 44 6%
100 0 0%
75 44 6%
80 44 6%
90 0 0%
100 0 0%
load shedding in Anchorage and GVEA
60.5
C1A 72 125 60.4
61.1
C1A 72 125 61.1
Summer
Peak
16
CA 82 125
16
CA 82 125
Season Trans
Config
Gen
Case
Spin
(MW)Kenai
Export
Daves ‐
Quartz
Line Flow DC Flow
(MW)UFLS Action
75
75
75
75
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 42
Table H.2 – Kenai Trip Analysis – Winter Peak
Initial Post MW %
75 62 6%
80 62 6%
90 62 6%
100 0 0%
75 62 6%
80 29 3%
90 0 0%
100 0 0%
75 62 6%
80 62 6%
90 62 6%
100 0 0%
75 62 6%
80 62 6%
90 0 0%
100 0 0%
load shedding in Anchorage and GVEA
60.8
C1A 66 125 62.7
61.5
C1A 66 125 63.4
Winter
Peak
16
CA 73 123
21
CA 73 123
Season Trans
Config
Gen
Case
Spin
(MW)Kenai
Export
Daves ‐
Quartz
Line Flow DC Flow
(MW)UFLS Action
75
75
75
75
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 43
Appendix I – DC / Southern Intertie Trip Detailed Results
Table I.1 – DC / Southern Intertie Trip Results
c5 c6 c7 c8 c11 c12 c5 c6 c7 c8 c11 c12 c5 c6 c7 c8 c11 c12
C 1 126 x x 125 x x 122 x x
C 2 126 x x 125 x x 122 x x
C 3 126 x x 125 x x 122 x x
C 4 126 x x 125 x x 122 x x
C 14 126 x x 125 x x 122 x x
C 16 126 x x 125 x x 122 x x
C 20 126 x x 125 x x 122 x x
C 21 126 x x 125 x x 122 x x
C1 1 127 x x 124 x x 123 x x
C1 2 127 x x 124 x x 123 x x
C1 3 127 x x 124 x x 123 x x
C1 4 127 x x 124 x x 123 x x
C1 14 127 x x 124 x x 123 x x
C1 16 127 x x 124 x x 123 x x
C1 20 127 x x 124 x x 123 x x
C1 21 127 x x 124 x x 123 x x
C2 1 118 x x 99 x x 77 x x
C2 2 118 x x 99 x x 77 x x
C2 3 118 x x 99 x x 77 x x
C2 4 118 x x 99 x x 77 x x
C214118 xx99 xx77 xx
C216118 xx99 xx77 xx
C220118xx99xx77xx
C221118 xx99 xx77 xx'DC_tie_100@Beluga'Kenai
Export
(MW)South_Tie_138@BerniceSouth_Tie_230@ITSSSouth_Tie_230@Bernice'DC_tie_100@Bernice'South_Tie_138@BerniceSouth_Tie_230@ITSSSouth_Tie_230@Bernice'DC_tie_100@Bernice''DC_tie_100@Beluga'Season Summer Valley Summer Peak Winter Peak
Gen
Case
Trans
Config
Kenai
Export
(MW)South_Tie_138@ITSSSouth_Tie_138@BerniceSouth_Tie_230@ITSSSouth_Tie_138@ITSSSouth_Tie_230@Bernice'DC_tie_100@Bernice''DC_tie_100@Beluga'Kenai
Export
(MW)South_Tie_138@ITSS
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 44
Appendix J – Costs of Individual Line Improvements
Cost estimates for each of the proposed transmission upgrades are presented below:
J.1 Upgrade Existing Kenai Tie to 230 kV
The project includes the rebuild of 76.8 miles of 115 kV transmission line to 230 kV. The project
includes removal of the existing 115 kV intertie and reconstruction of the intertie to 230 kV. The
detailed line sections and their estimates are outlined in Table J.1 below.
Table J.1 Conductor Costs – Upgrade Kenai Tie to 230 kV
Line Section
Existing
Structure
Type*
Existing
Framing
Existing
Line
Miles
Proposed
Structure
Type*
Proposed
Framing Proposed Location Construction
Estimate
Daves Creek - Hope STH-1A 115kV 18.9 230-H 230kV Existing Alignment $14,000,000
Hope - Portage STH-1A 115kV 19.7 230-H 230kV Existing Alignment $15,000,000
Portage - Girdwood STH-1A 138kV 11.0 230-H 230kV Existing Alignment $8,000,000
Girdwood - Indian STH-1A 115kV 10.7 230-H 230kV Existing Alignment $7,500,000
Indian - University STH-1A 115kV 16.5 230-H 230kV Existing Alignment $13,000,000
Total 76.8 $57,500,000
The project includes the installation of 30 MVAr of reactive compensation at Dave’s Creek for
voltage control. The project will require the construction of a new 230 kV bay at Dave’s Creek
Station and the addition of a 230 kV termination at University station. Existing 115 kV stations
at Summit Lake, Hope, Portage, Girdwood and Indian stations would require conversion to 230
kV. The detailed substations and their estimates are outlined in Table J.2 below.
Table J.2 Substation Costs – Upgrade Kenai Tie to 230 kV
Station Description Costs
Daves Creek 230 kV Transformer,breaker $5,383,168
Daves Creek 30 MVAr Reactor/SVC integration $1,450,000
Summit 230 kV Circuit Switcher/transformer $1,803,319
Hope 230 kV Circuit Switcher/transformer $180,332
Portage 230 kV Circuit Switcher/transformer $3,791,449
Girdwood 230 kV GIS, two 230 kV transformers $12,028,689
Indian 230 kV Circuit Switcher/transformer $3,026,814
University 230 kV relaying/controls $361,475
Total $28,025,245
The total costs for upgrading the existing Kenai Tie to 230 kV are shown in Table J.3.
Table J.3 Total Costs – Upgrade Kenai Tie to 230 kV
Item Costs
Total Conductor Upgrade Costs $57,500,000
Total Substation Upgrade Costs $28,025,245
Total Costs $85,525,245
J.2 Modified 115 kV Kenai Transmission Substations
This cost estimate provides the costs for the modifications to each of the substations required
between Bradley Lake and Dave’s Creek stations. The station costs can be used in
combination with the appropriate line costs to arrive at the total project costs.
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 45
Table J.4 Cost Analysis – Kenai Transmission Substations
Station Description Costs
Bradley Lake Add new Bay/115 kV cable to Bradley GIS $2,865,141
Soldotna 115 kV station ‐ Ring Bus $4,800,000
Quartz Creek Add 115 kV station $2,580,000
Daves Creek Add 115 kV Bay $1,480,000
Total $11,725,141
J.3 New 115 kV Line – Bradley Lake to Soldotna
This project includes the construction of a new transmission line along the existing Bradley –
Bradley Junction – Soldotna transmission line. The line would utilize 556 MCM Dove conductor
and wooden H-structures for the line construction.
Table J.5 Cost Analysis – New 115 kV line, Bradley Lake - Soldotna
Line Section
Existing
Structure
Type*
Existing
Framing
Existing
Line
Miles
Proposed
Structure
Type*
Proposed
Framing Proposed Location
Construction
Estimate
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
$55,000,000Total
J.4 New 115 kV Line – Soldotna to Quartz Creek
This project includes the construction of a new 115 kV transmission line adjacent to the existing
115 kV Quartz Creek – Soldotna 115 kV Transmission line. Station costs would be the same as
previously listed.
Table J.6 Cost Analysis – New 115 kV line, Soldotna – Quartz Creek
Existing
Structure
Type*
Existing
Framing
Existing
Line
Miles
Proposed
Structure
Type*
Proposed
Framing Proposed Location
Construction
Estimate
Soldotna - Quartz Ck STH-1A 115kV 54.8 STH-1A 115kV Parallel to Existing $44,000,000
J.5 New 115 kV Line – Bradley Lake to Quartz Creek
This project includes the construction of a new 115 kV line from Bradley Lake to Quartz Creek
station. The line would by-pass Bradley Junction and Soldotna stations, but would be routed
adjacent to these facilities. The substation facilities are the same as previously listed.
Table J.7 Cost Analysis – New 115 kV line, Bradley – Quartz Creek
Existing
Structure
Type*
Existing
Framing
Existing
Line
Miles
Proposed
Structure
Type*
Proposed
Framing Proposed Location
Construction
Estimate
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
Soldotna - Quartz Ck STH-1A 115kV 54.8 STH-1A 115kV Parallel to Existing $44,000,000
Total $99,000,000
J.6 New 115 kV Line – Quartz Creek to Dave’s Creek
This project includes the construction of a new 115 kV line from Quartz Creek to Dave’s Creek.
The structures would be a single pole, double circuit configuration with the exception of the
Kenai Lake Crossing.
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 46
Table J.8 Cost Analysis – New 115 kV line, Quartz Creek – Dave’s Creek
Existing
Structure
Type*
Existing
Framing
Existing
Line
Miles
Proposed
Structure
Type*
Proposed
Framing Proposed Location
Construction
Estimate
Quartz Ck - Daves Ck STH-1A 115kV 14.5 STH-1D 115kV DBL Existing Alignment $12,180,000
The substation improvements for this project include a new 115 kV breaker bay at Quartz Creek
and a new 115 kV breaker position at Dave’s Creek.
J.7 Reconductor Existing 115 kV Diamond Ridge – Soldotna Line
This project includes the reconstruction of the existing 4/0 sections of the Diamond Ridge –
Soldotna transmission line to 556 MCM “Dove” conductor. The reconductor is required due to
heavy losses and severe thermal limits on the 4/0 conductor.
Table J.9 Cost Analysis – Reconductor 115 kV line, Diamond Ridge - Soldotna
Existing
Structure
Type*
Existing
Framing
Existing
Line
Miles
Proposed
Structure
Type*
Proposed
Framing Proposed Location
Construction
Estimate
Diamond Ridge - Soldotna HPT-1 115kV 75 HPT-1 115kV $75,500,000
J.8 New Kenai Intertie – 230 kV AC
This project includes the reconstruction of the new Kenai intertie from Pt. Woronzof to Bernice
Lake Substation. The line consists 18.2 miles of submarine cable, 4.9 miles of land cable and
38.0 miles of overhead.
Table J.10 Conductor Costs – New 230 kV AC Kenai Intertie
Line Section
Line
Miles
Sub Cable - Worz. to Pt. Possession 18.6 $143,000,000 $205,000,000
Pt. Possession - Captain Cook Park 26.2 $19,000,000 $19,000,000
Land Cable - Captain Cook Park 4.0 $33,000,000 $43,000,000
Captain Cook to Bernice 11.8 $11,000,000 $11,000,000
60.6 $206,000,000 $278,000,000
Construction Estimate Range
Table J.11 Compensation Costs – New 230 kV AC Kenai Intertie
Compensation ‐ 230 kV Cable option MVAr
Fixed Compensation 135 6,350,000$ 8,255,000$
SVC compensation 135 48,750,000$ 63,375,000$
Total 270 55,100,000$ 71,630,000$
Installed Costs ‐ Range
Table J.12 Total Costs – New 230 kV AC Kenai Intertie
Item
Total Conductor Upgrade Costs $206,000,000 $278,000,000
Total Compensation Costs $55,100,000 $71,630,000
Total Costs $261,100,000 $349,630,000
Costs Range
The total installed costs for this option is the combined costs of the transmission lines plus the
required compensation. The specialized switching for this project may require an energization
resistor in the cable circuit such that the cable could only be energized from one end. Although
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 47
we have no doubt the project could be technically completed, the project has risk in the
switching and performance studies that will be required to define the energization and de-
energization sequence. There is a risk that due to the heavy compensation required and the
direct connection to hydro, steam and Frame type combustion turbines that sub-synchronous
resonance will require mitigating measures.
J.9 New Kenai Intertie – 138 kV AC
This project is essentially identical to the 230 kV option above, but assumes the line is
constructed and operated at 138 kV.
Table J.13 Conductor Costs – New 138 kV AC Kenai Intertie
Line Section
Line
Miles
Sub Cable - Worz. to Pt. Possesion 18.6 $107,250,000 $153,700,000
Pt. Possession - Captain Cook Park 26.2 $14,250,000 $14,250,000
Land Cable - Captain Cook Park 4.0 $24,750,000 $32,250,000
Captain Cook to Bernice 11.8 $8,250,000 $8,250,000
60.6 $154,500,000 $208,450,000
Construction Estimate Range
Table J.14 Compensation Costs – New 138 kV AC Kenai Intertie
Compensation ‐ 230 kV Cable option MVAr
Fixed Compensation 30 5,300,000$ 6,890,000$
SVC compensation 90 37,500,000$ 48,750,000$
Total 120 42,800,000$ 55,640,000$
Installed Costs ‐ Range
Table J.15 Total Costs – New 138 kV AC Kenai Intertie
Item
Total Conductor Upgrade Costs $154,500,000 $208,450,000
Total Compensation Costs $42,800,000 $55,640,000
Total Costs $197,300,000 $264,090,000
Costs Range
The total installed costs for this option is the combined costs of the transmission lines plus the
required compensation. Similar to the 230 kV option, specialized switching for this project may
require an energization resistor in the cable circuit such that the cable could only be energized
from one end. Although we have no doubt the project could be technically completed and the
project has less risk than the 230 kV project, the project has risk in the switching and
performance studies that will be required to define the energization and de-energization
sequence. There is a risk that due to the heavy compensation required and the direct
connection to hydro, steam and Frame type combustion turbines that subsynchronous
resonance will require mitigating measures. The implementation will not be straight-forward and
could result in unforeseen operating issues.
J.10 New Kenai Intertie – 100 kV HVDC Bernice - Beluga
This project has not been evaluated in terms of detailed routing and environmental studies as
has the other two options, however the HVDC interconnection will be much more
straightforward and present less risk than either of the two AC options. The project appears
more economically and technically feasible than the 138 kV or 230 kV alternatives. The project
also allows a more diverse interconnected system to future generation resources in the Beluga
Alaska Energy Authority
Kenai Transmission Study
March 7, 2014 Page 48
area. The cost estimate below is for an 80 MW, mono-pole system with redundant submarine
cables. If redundant cables are not required, the cost of the cables could be reduced by 35-
40%.
Table J.16 Cost Analysis – New 100 kV HVDC Kenai Intertie
+/‐ 100 kV HVDC Beluga ‐ Bernice Qty
Submarine Cable (33 mi) 33 74,050,000$ 113,256,000$
SVC compensation (100 MW) 2 60,500,000$ 82,500,000$
Total 35 134,550,000$ 195,756,000$
Installed Costs ‐ Range
Alaska Energy Authority
Pre/Post - Watana Transmission Study
March 17, 2014
Page 235
J Regulation Resource Study
Alaska Energy Authority
Regulation Resource Study
Technology Recommendation and Cost Estimates
March 7, 2014
John DL Hieb
David W. Burlingame, P.E.
March 7, 2014 Page ii
Summary of Changes
Revision Revision Date Revision Description
0 August 6, 2012 Initial Rough Draft
1 March 7, 2014 Report Revision Based on Comments Received from AEA
Table of Contents
EXECUTIVE SUMMARY ................................................................................................. 1
1 INTRODUCTION ...................................................................................................... 3
2 REGULATION RESOURCES .................................................................................. 4
3 AVAILABLE ENERGY STORAGE TECHNOLOGIES .............................................. 5
3.1 Lead-Acid .......................................................................................................................... 5
3.2 Nickel-Cadmium ................................................................................................................ 6
3.3 Nickel Metal Hydride ......................................................................................................... 6
3.4 Lithium-Ion ........................................................................................................................ 7
3.5 Sodium-Sulfur ................................................................................................................... 7
3.6 Vanadium-Redox .............................................................................................................. 7
3.7 Zinc-Bromine ..................................................................................................................... 8
3.8 Advanced Flywheels ......................................................................................................... 8
3.9 Applicable Technologies for Railbelt Regulation Application ............................................ 9
4 PRELIMINARY WIND ANALYSIS ............................................................................ 9
4.1 Regulation Resource Power Requirement ........................................................................ 9
4.2 One Hour Regulation Resource Energy Requirement .................................................... 10
4.3 Battery Life Evaluation .................................................................................................... 17
5 TECHNOLOGY RECOMMENDATION .................................................................. 19
5.1 Financial Considerations ................................................................................................. 19
5.2 Economic Analysis – Advanced Lead-Acid vs. Lithium-Ion ............................................. 20
6 SIX HOUR ENERGY NEEDS ................................................................................ 22
6.1 Wind Regulation .............................................................................................................. 22
6.2 Loss of Kenai Tie ............................................................................................................ 28
6.3 Gas Storage Description and Costs ................................................................................ 33
7 CONCLUSIONS AND RECOMMENDATIONS ...................................................... 34
8 REFERENCES ....................................................................................................... 36
March 7, 2014 Page iii
List of Tables
Table 1: Regulation Shortfall and Feathering Analysis Results ................................................... 13
Table 2: Regulation Shortfall and Feathering Analysis Results ................................................... 16
Table 3: Energy Storage Systems Cost Update ............................................................................ 20
Table 4: Battery Life Based on Battery Capacity ......................................................................... 21
Table 5: Battery Initial Installation Cost and 20 Year Project Cost ............................................. 22
Table 6: 52 MW Wind Schedules for September 1 through September 2 .................................... 25
Table 7: Six-Hour Regulation Simulation Results for a 52 MW Wind Farm .............................. 27
Table of Figures
Figure 1: Desired Regulation Characteristic ................................................................................. 11
Figure 2: Desired Regulation Characteristic ................................................................................. 15
Figure 3: Battery Cycle-Life vs. Depth of Discharge ................................................................... 17
Figure 4: Cycle Counting Method ................................................................................................ 18
Figure 5: Six Hour Energy Needs Based on Wind Schedule ........................................................ 23
Figure 6: Wind Power for First Provided Days ............................................................................ 25
Figure 7: Summer Valley Loss of Kenai Tie at Maximum Flow ................................................. 30
March 7, 2014 Page 1
Executive Summary
The intent of this phase of the study is to provide a recommendation on the technology and
develop a budgetary cost estimate of regulation technology for the Railbelt. The selected
regulation resource should enable the electrical system to accept more renewable energy by
alleviating the gas constraints on utility generation that are currently prohibiting its development
and secondarily provide contingency reserves for loss of generation or transmission resources
in the Railbelt.
The study evaluated the impact of the single transmission line from the Kenai and the changing
generation characteristics of the Railbelt. These factors were included in the selection and
sizing of the regulation resources evaluated in the study.
Due to both gas and electrical system constraints faced by the Railbelt utilities, the ability to
regulate an intermittent resource such as wind generation is limited. In order to deal with these
system constraints a regulation resource that could use energy storage to regulate an
intermittent wind resource is required prior to developing a renewable energy portfolio for the
Railbelt.
The changing generation technology of the Railbelt has a dramatic impact on the regulation
capability of the Railbelt. As the Railbelt utilities move towards smaller, more efficient units that
more closely matches their capacity requirements, the chances of having “excess” regulation
capability on the system to respond to unexpected events decreases dramatically. Even if
sufficient gas supplies were available, operating capacity to respond to unexpected changes in
non-dispatchable renewable energy or the loss of the Anchorage – Kenai Intertie will be
minimal. Consequently, flexible regulation resources must be developed to allow additional
renewables to be incorporated into the system, protect against sudden loss of generation or
transmission resources, and to optimize the use of the new generation of high-efficiency gas
generation.
This study evaluated three major technologies and their applicability in the Railbelt. These three
technologies were: Battery Energy Storage Systems (BESS), Flywheel or rotating inertia
technology, and Flexible Gas Storage (FGS). The selected technologies would augment the
regulation capability of the Railbelt hydro resources and be used in conjunction with other
regulation capabilities of the Railbelt.
The criteria used for the regulation evaluation were that no single event should result in the loss
of load in the Railbelt and that the regulation system must work with any single regulation
resource out of service or unavailable. For example, if the Kenai intertie was out service and
hydro regulation was unavailable or if hydro was not scheduled for generation, the remaining
regulation resources in the Southcentral Railbelt must be capable of providing the required
regulation.
The driving force for determining the regulation requirement in the existing system is the loss of
the single Anchorage – Kenai Intertie under maximum import conditions. Following the
retirement of the large gas turbines, this contingency will be the largest resource loss for the
Southcentral area.
The regulation requirements of the Railbelt are divided into short-term regulation requirements
caused by variations in load and variable generation and long-term regulation required by
sustained wind ramp events, loss of transmission interconnections, or the loss of a generation
unit. The long-term regulation requirements exceed the capabilities of flywheel technology,
consequently, this technology was dropped from consideration.
March 7, 2014 Page 2
BESS and FGS technologies are ideally suited for the Railbelt and can be used in
complimentary fashions to provide the optimum system performance. During normal operation,
regulation would be provided by a combination of BESS, FGS and hydro resources. The system
is capable of providing the required regulation following the loss of any one regulation resource.
By utilizing complimentary regulation resources, the costs and sizes of each resource can be
optimized to meet the Railbelt needs.
The BESS was sized to be the primary resource for short-term variable energy deviations from
renewable projects such as wind or solar or from the instantaneous loss of generation. The goal
for sizing the BESS was to provide regulation such that that the reliability of the Railbelt would
be maintained at approximately its current levels following the addition of variable generation to
the grid. The target is to provide enough regulation energy such that on average only twelve
events which exceed the regulation capabilities of the BESS are expected during an average
year.
The requirements for FGS were developed to enable the Southcentral utilities sufficient storage
at gas generation plants to provide fuel for thermal regulation following the loss of the largest
contingency (Anchorage-Kenai Intertie). The thermal regulation capacity must be capable of
allowing the utilities to schedule gas from in-ground storage at the next scheduling interval,
estimated at 6 hours.
Based on these criteria, we recommend the utilities use a BESS and on-site gas storage
systems to provide the required regulation during both the short-term and long-term events.
With the construction of the Beluga – Bernice tie, the BESS should be constructed with a
capacity/energy rating of 25 MW/ 14 MWH and the FGS should be constructed to provide 1.91
MCF (262.5 MWh) to cover the small wind farm and the loss of one of the Kenai ties under
maximum import conditions. Both the proposed BESS system and the FGS systems can be
constructed in blocks either simultaneously or independently. However, construction of the
facilities in blocks will increase the total costs over the duration of the project.
If the HVDC line is not constructed, the size of the BESS and FGS will increase significantly.
The final size will be determined by the largest expected transfer of the single Kenai –
Anchorage Intertie. To maintain reliability equivalent to the HVDC system, the BESS capacity
would need to be increased to approximately 100 MW. It is unlikely that this BESS could be
economically installed; therefore, lower import or lower reliability measures would need to be
adopted. For the larger regulation requirement we recommend the FGS be located at two
different locations with thermal generation. Two different locations are recommended to
maximize the availability of on-line and off-line regulation resources.
The cost of the recommended alternative is as follows:
Description Wind Farm Size Capacity Energy Costs
BESS – HVDC 17 MW 25 MW 14 MWh $26.7 M
FGS – HVDC 17 MW NA 1.91 MCF (262.5 MWh) $18.2 M
March 7, 2014 Page 3
1 Introduction
The purpose of this report is to provide the results of a regulation resource technology
evaluation and a preliminary cost estimate for the recommended alternative. EPS will
recommend a regulation technology to provide the best-fit for the regulation application. EPS
will then provide the life-cycle costs of different storage technologies based on their ability to
meet the regulation needs.
The full breadth of the study includes the evaluation of BESS, FGS and Flywheel technologies
in the South-central Railbelt area. Each of these technologies was evaluated independently and
in combination with each other in order to provide the optimum solution for the Railbelt utilities.
The primary goal of the regulation resource is to provide the Railbelt utilities the ability provide
regulation capability for renewable energy resources in the region that cannot be regulated by
the current generation’s fuel supply system.
In addition to providing regulation for renewable energy projects, the proposed system’s
secondary goal is to provide response to the loss of the Anchorage-Kenai intertie which will
soon be the largest operating contingency in the Southcentral area. It is assumed that the
Railbelt transmission planning study will recommend a second line connecting the Kenai
Peninsula with the Southcentral transmission system (the Beluga – Bernice Lake HVDC
Intertie). The regulation requirements were studied with and without this second transmission
line to determine the impact on the regulation size and technology. However, due to the impact
on transfer capability of the second transmission line between the Kenai and Anchorage, this
study reduced the maximum import level into Anchorage from 125 MW to 75 MW.
The regulation resource must be capable of relieving the gas constraints placed on the
Southcentral utilities by both gas transportation and gas producing entities in providing
regulation for both non-dispatchable resources and system contingencies.
The system should be flexible in its response and implementation. No single failure of a
regulation resource should result in the lack of regulation capability in the system. The
regulation resource must also be designed to not place scheduling requirements on the Railbelt
generation, it must be available if no hydro is scheduled to meet system load. The system
should also be flexible in terms of its implementation and construction, allowing for modular
implementation if budgetary constraints require it.
The regulation technologies to be evaluated are as follows:
Battery Energy Storage System (BESS) – A BESS consists of large battery systems
designed to provide both energy input to the system during generation shortfall and
absorb energy during generation excess conditions
Flexible Gas Storage (FGS) – FGS consists of compressed gas storage facilities located
at or near thermal generation resources. FGS can provide stored gas to generation
during energy shortfalls or absorb scheduled gas during excess energy production.
Flywheel Technology – Flywheel technology consists of using the inertia of a rotating
mass to provide or absorb energy stored in the rotating mass to the power system.
Earlier flywheels were directly connected to the power system and their discharge or
absorption was determined by frequency fluctuations of the power system. Modern
inertia systems are connected by an inverter system, allowing the characteristics of the
flywheel to be manipulated by the inverter controller.
March 7, 2014 Page 4
2 Regulation Resources
As this study is highly sensitive to initial assumptions, it is important that the various project
assumptions be understood when evaluating the results of the study. The following sections
highlight the major assumptions used in the study, along with the expected impact of the
assumptions. In order to determine the energy and power requirements provided by the
proposed storage devices, the current and expected future regulation capabilities must be
defined. EPS assumed the following regulation capabilities for the various Railbelt resources:
2015 Cases:
o Natural Gas Turbines
Due to gas scheduling constraints, the Railbelt natural gas turbines will
provide no regulation power or energy other than the requirements to
meet the scheduled load ramp (absent the installation of flexible gas
storage).
The gas turbines are set on a six-hour schedule that should not be
revised except for emergency conditions. If the severe wind ramp events
occur as infrequently as a couple of times per year, then the capability of
changing the gas schedules at the hour will be analyzed as it pertains to
the storage capabilities. However, excursions greater than one time per
month (one average) must be compensated by other means.
o Hydro Turbines
The hydro turbines at Cooper and Eklutna will provide no regulation
power or energy during the hour.
The hydro resource schedules will be fully dispatchable at the hour from
the maximum to minimum capabilities of the units. This will result in
“ponding” water during those times when wind is available and hydro is
scheduled, but is being displaced by wind energy.
The hydro resources may not be scheduled 24 hours/day for energy
delivery to the utilities.
o Wind Turbines
The study will assume no capability to forecast wind power output or
ramps other than utilizing the same day patterns to predict the next few
hours. This will provide a solution that will be capable of responding to the
most likely, unconstrained wind changes.
Self-regulation by feathering the wind turbine blades will be evaluated as
part of the storage solutions.
Both large and small wind farm sizes will be evaluated. EPS has
projected wind power outputs for both wind farm sizes.
It is assumed that the northern Railbelt system will provide the regulation
for the wind generation at Eva Creek. Additionally, since there is only one
tie to the northern system, the two areas must be able to be operated so
as to not impact the other, or in the extreme case, operated islanded from
each other.
2025 Cases:
March 7, 2014 Page 5
o Watana Hydro Addition
The proposed Watana hydro plant will not provide any sub-hour
regulation power or energy during the hour due to downstream flow
restrictions.
Time Frames:
o Since the utilities must account for all wind variations in order to maintain
frequency stability, the required power and energy will be analyzed for several
different time frames including 20, 30, and 60 minutes for electrical energy
requirements and up to six hours for the flexible gas storage options.
o Since the hydro resource schedules are able to change at the hour, the 60-
minute time frame will take precedence over the other time frames, however, it is
recognized that the majority of hydro resources are only available through a
single contingency transmission line unless the Beluga-Bernice Lake HVDC line
is constructed and that hydro resources are not typically scheduled 24-hours/day.
In addition to the regulation requirements, the capacity and energy requirements
for the loss of the largest intertie and largest unit will be evaluated.
o The installation of a second Anchorage – Kenai transmission line will reduce the
maximum capacity lost in the Anchorage area to 30 MW for the loss of the
existing Anchorage – Kenai Intertie.
Criteria
o Due to the critical nature of the regulation requirements, the regulation system
must be capable of operation during the loss of any single regulation source, i.e.
loss of stored energy, loss of hydro, loss of gas storage. The system will not be
required to operate during an N-2 condition.
3 Available Energy Storage Technologies
This section gives a basic summary of the battery and flywheel technologies that are currently
available. The applicability for each technology for use as a regulation resource is determined.
For each technology that is deemed applicable, an economic analysis will be performed to
determine the lowest-cost option for the Railbelt regulation resource.
3.1 Lead-Acid
The lead-acid battery is the most mature battery technology with well over 100 years of service.
Currently, there are three types of lead-acid batteries. The first of which is the flooded cell lead-
acid battery. This technology is the most common form of the lead-acid battery. This technology
uses lead/ lead alloy plates that will react with a sulfuric acid electrolyte to produce the
movement of charge.
The flooded cell lead-acid battery has the advantage of being the lowest cost battery option with
excellent shelf life, and good efficiency. The main problems with the flooded cell lead-acid
battery are the numerous environmental concerns and the low cycle-life (only a couple hundred
cycles for deep discharges). Since the regulation application will require thousands of cycles per
year, the flooded cell lead-acid battery should not be considered for a regulation application.
The second type of lead-acid battery is the valve regulated lead-acid battery (VRLA). The VRLA
battery was designed to reduce some of the maintenance concerns with the flooded cell lead-
March 7, 2014 Page 6
acid battery. Unfortunately, the changes required to reduce the maintenance needs further
reduced the cycle-life of the battery, as such, should not be considered for a regulation
application.
The third type of lead-acid battery is the advanced lead-acid. Due to continuing research into
the lead-acid technology, some breakthroughs in the electrode materials have resulted in
drastically improved battery cycle-life. With the cycle-life improvement, the advanced lead-acid
batteries could be a potential solution for providing regulation services for the intermittent wind
resource and should be further investigated, and included in the economic analysis. The two
main competing companies using advanced lead-acid batteries are Axion Power and Xtreme
Power. The Xtreme Power dynamic power resource (DPR) has been used in conjunction with
several wind farm applications in Hawaii, and has recently been proposed as the battery
technology to provide 36 MW, 24 MWh in conjunction with a large wind farm in Texas. This
Texas installation represents one of the largest battery installations in the world, and is on the
same scale as would be required for a Railbelt regulation resource. At a much smaller scale,
Axion Power has recently connected to the PJM regulation market. This connection is significant
in that it is also a regulation application that requires many charge/discharge cycles. The
advanced lead-acid battery is recommended for further consideration as an option for the
Railbelt regulation resource.
3.2 Nickel-Cadmium
The nickel-cadmium battery technology is the most common nickel-electrode battery in the utility
industry. The nickel-cadmium battery is a favored alternative to the traditional lead-acid batteries
due to the advantages of 1) greater depth of discharge, 2) greater tolerance of extreme
temperature variation, 3) greater tolerance to over/under charging, and 4) lower maintenance
requirements. This battery technology does have some setbacks that include 1) lower efficiency
than lead-acid and, 2) environmental concerns due to the cadmium.
Although the nickel-cadmium battery is superior to the traditional lead-acid battery in
performance, it does have a higher rate of self-discharge and requires continuous charge
maintenance. The Railbelt system has experience with a nickel-cadmium battery system since
the GVEA BESS uses the nickel-cadmium technology. The GVEA BESS was designed for VAr
support, spinning reserve, and power system stabilization, but it was not designed for
regulation. Due to the relatively limited cycle-life of nickel-cadmium batteries and the maturation
of the nickel metal hydride battery, this technology should not be considered for a regulation
application.
3.3 Nickel Metal Hydride
The Nickel Metal Hydride battery (NiMH) has basically displaced the nickel-cadmium battery
since it has better energy density, better cycle-life, and no heavy metals (fewer environmental
concerns). This battery technology was used in the early Toyota Prius Hybrid vehicles (the
newest plug-in model uses lithium-ion). Due to the use in the plug-in hybrid vehicle market,
these batteries are among the most field-tested solutions. The NiMH battery technology does
not have the same discharge capabilities that a Ni-Cd battery has. Hence, NiMH batteries are
used more often for low-current applications such as portable computers and cell phones, while
the Ni-Cd batteries are used for high current applications such as portable power tools [2]. The
Ni-MH batteries have slightly worse charge retention than their Ni-Cd counterparts and would
require continuous charge maintenance.
Currently, there are no large format NiMH batteries. Large format NiMH cells would be better
suited to a large-scale stationary battery system for utility use. The NiMH battery has largely
March 7, 2014 Page 7
been replaced by the lithium-ion technologies in consumer electronics, and does not have the
same level of investment that it once had. Due to these factors, the Nickel Metal Hydride battery
would not be a good selection for the Railbelt regulation application.
3.4 Lithium-Ion
The lithium-ion battery technology has rapidly taken over the consumer electronics industry due
to its energy density advantage over the nickel metal hydride battery technology. This battery
technology comes in several flavors based on the specific chemistry of the cathode. The
different types include lithium-ion cobalt, lithium-ion manganese, lithium-ion phosphate, and
lithium-ion titanate. The different chemistries offer differing specific power (charge/discharge
rate), safety characteristics, and cycle-life [1].
The Chevrolet Volt and the newest Toyota Prius vehicles use lithium-ion battery packs. The
selection of the lithium-ion technology for the transportation sector suggests that the regulation
market might be an acceptable utility application for this technology since the frequent battery
usage associated with a hybrid vehicle is similar usage that would be seen in utility regulation
applications. Additionally, the new manufacturing capacity required by the electric vehicle
industry will have a price reduction effect due to economies of scale.
The lithium-ion batteries have several desirable characteristics such as long-cycle lives, good
energy density, and high power density. The lithium-ion batteries, however, are more expensive
than many of the competing battery technologies, but due to their superior performance,
particularly the excellent cycle-life, this battery technology should be considered for the
regulation resource project.
3.5 Sodium-Sulfur
The sodium-sulfur battery is currently the most widely used utility-scale battery technology. It
has been heavily used in Japan by TEPCO (Tokyo Electric Power Company) and is produced
by NGK. There are several installations in the United States.
The sodium-sulfur battery must maintain high operating temperatures (> 250°C). As such, the
batteries must be heavily insulated to maintain the temperature, and when the batteries are not
providing power, must be heated via resistor banks. These batteries are primarily used for
uninterruptible power supplies in Japan, but are beginning to see applications such as load
shifting and wind smoothing here in the United States.
There was a sodium-sulfur battery fire on September 21, 2011 which has brought some scrutiny
toward the battery safety. The cause has not been identified, and the production of these
batteries has been put on hold until the safety concerns are resolved.
The sodium-sulfur batteries advantages are that the technology has a high round-trip efficiency.
It has good energy density and cycle-life for large discharge depths (>5,000 at 90%), but poor
cycle-life for smaller discharge depths (45,000 at 10%). The sodium-sulfur technology is not
well-suited to frequent charge/discharge as would be expected with a regulation application.
The sodium-sulfur battery technology should not be considered for the Railbelt regulation
application.
3.6 Vanadium-Redox
The Vanadium-redox battery is a flow type battery. Flow batteries store their energy in liquid
electrolytes, and pump the liquid to a fuel cell where the electro-chemical reactions occur. The
vanadium-redox battery basically stores the energy in different ionic forms of vanadium. One of
March 7, 2014 Page 8
the advantages of this flow battery system is that the energy capacity (MWh) and the power
capability (MW) can be sized separately based on the application. For example, if more energy
is needed, simply adding electrolyte storage tanks will increase the battery energy. This is a
desirable attribute for matching a vanadium-redox battery to an application that may require
additional capacity at a later date.
The vanadium-redox battery technology is being developed by Prudent Energy. This battery
technology is currently being tested at the University of Alaska Fairbanks. The vanadium-redox
battery has decent AC-to-AC efficiency of 70% to 75%, good cycle-life, and good reliability. The
vanadium-redox battery has some disadvantages such as have high cost, low energy density,
and a limited number of installations in the field. The vanadium-redox battery technology is
better suited to applications requiring several hours of stored energy such as peak shaving or
energy arbitrage. Due to these disadvantages, the vanadium-redox battery is not recommended
for the Railbelt regulation application.
3.7 Zinc-Bromine
The zinc-bromine battery is also a flow type battery. This technology has a significant promise,
but has very limited field applications. During charging, metallic zinc is plated from the
electrolyte onto the negative electrode and bromide is converted to bromine at the positive
electrode. During discharge, the metallic zinc dissolves into the electrolyte.
The zinc-bromine technology has several advantages over the vanadium-redox battery. Zinc-
bromine batteries have better energy density, lower cost, and fewer environmental concerns
since zinc-bromine technology uses less toxic materials. However, the zinc-bromine batteries do
not have independent sizing like the vanadium-redox battery. Also, the power capacity of the
zinc-bromine battery is low which limits the charge/discharge rate.
The zinc-bromine battery technology is being developed and manufactured by ZBB Energy
Corp. and Premium Power Corp. ZBB Energy has more utility scale projects online, but still has
limited experience in the utility sector. Due to the poor power capability of this technology, a 50
MW system would require at least 150 MWh of storage. This would add to the cost of such a
system compared to other technologies that could have a 50 MW / 50MWh configuration.
Another disadvantage of this battery technology is that the battery maintenance requires
“stripping”. Stripping is performed by discharging the battery cell down to zero volts. This will
remove all zinc from the negative electrode. This process is performed to increase efficiency,
and ensure consistent operation of all battery cells. Due to the poor power capability, the need
for ‘stripping”, and the minimal field applications the zinc-bromine technology should not be
considered for the regulation application.
3.8 Advanced Flywheels
Flywheels convert the electrical energy from the grid and convert it into rotating kinetic energy.
The advanced flywheels spin at high speeds. In order to reduce the frictional losses, these
flywheels operate with magnetic bearings in a vacuum. In order to maintain structural integrity at
high rotational speeds, these flywheels are made of high-tech composite materials.
These advanced flywheels can charge and discharge without performance degradation which
makes them ideally suited to regulation applications. Unfortunately, the advanced flywheel
systems are quite expensive. The flywheel technology is primarily used in uninterruptible power
supply applications. There are several flywheel manufacturers, but only Beacon Power is
marketing towards utility applications. All the other companies are marketing toward
uninterruptible power supplies. Beacon Power has a 20MW, 5 MWh flywheel system used for
March 7, 2014 Page 9
the New York regulation market. This project cost a reported $69 million. The Railbelt regulation
application will need at least five times the storage, and that would make the flywheel option too
expensive for the hour-long energy needs. Advanced flywheels are not recommended for the
Railbelt regulation application.
3.9 Applicable Technologies for Railbelt Regulation Application
The need for near-constant charging and discharging characteristics of a regulation application
removes several technologies from consideration based on limited cycle-lives (nickel-cadmium,
sodium-sulfur, traditional lead-acid). Limited field experience and high costs also removes some
technologies from consideration (vanadium-redox, advanced flywheels). The two technologies
that should be further investigated are advanced lead-acid batteries, and lithium-ion battery
technology.
4 Preliminary Wind Analysis
4.1 Regulation Resource Power Requirement
4.1.1 52 MW Wind Farm
With the assumption that the regulation resource must provide all the regulation within the hour,
the wind data was analyzed to determine the power capacity needed to fully regulate a large
wind farm with a capacity of 52 MW. The wind data was provided by Clarity Analytical in a one-
minute time series showing wind farm power output. The maximum power required by the
regulation resource was determined by the maximum inter-hour power change.
For each minute in the two years of analyzed wind data, the inter-hour maximum and minimum
wind power output were found and compared. Using this method, the maximum inter-hour
power change for the wind farm was approximately a net of 48.25 MW for the 52 MW wind
Farm. Therefore, the estimated wind farm output can almost go from maximum power output to
zero within one hour. In order for the regulation resource to prevent the rest of the Railbelt from
seeing power fluctuations from the wind farm, the regulation resource, including the option of
curtailment must compensate for the full net power of 48 MW. EPS recommends a regulation
resource with at least 50 MW power capability in order to fully regulate the wind farm.
4.1.2 17 MW Wind Farm
With the assumption that the regulation resource must provide all the regulation within the hour,
the wind data was analyzed to determine the power capacity needed to fully regulate a smaller
wind farm with a capacity of 17 MW. The wind data was provided by Clarity Analytical in a one-
minute time series showing wind farm power output. The maximum power required by the
regulation resource was determined by the maximum inter-hour power change.
For each minute in the two years of analyzed wind data, the inter-hour maximum and minimum
wind power outputs were found and compared. Using this method, the maximum inter-hour
power change for the wind farm was approximately a net of 17 MW for the 17 MW wind Farm.
Therefore, the estimated wind farm output can almost go from maximum power output to zero
within one hour. In order for the regulation resource to prevent the rest of the Railbelt from
seeing power fluctuations from the wind farm, the regulation resource, including the option of
curtailment must compensate for the full net power of 17 MW. EPS recommends a regulation
resource with at least 17 MW power capability in order to fully regulate the wind farm.
March 7, 2014 Page 10
4.2 One Hour Regulation Resource Energy Requirement
4.2.1 52 MW Wind Farm
One way of determining the regulation energy requirement was based on the worst case one-
hour need. This need is based on the upward regulation requirement to compensate for the
wind output. The worst case scenario is the one-hour interval that represents the maximum
amount of regulation energy that the utilities must provide for in the regulation scenario.
Conditions where the wind turbines are operating near cut-out or are experiencing severe
fluctuations are assumed to be curtailed by the operating utility.
The wind was analyzed for each year of data available. For each minute of wind data, the
change in wind output was integrated over a one-hour time period to provide the necessary
energy for that hour. The worst-case hour would require 36 MWh from the regulation resource.
Sizing the regulation resource to provide for the worst case scenario would result in an
expensive, over-sized regulation resource. A simple control method was developed in an
attempt to minimize the battery energy sizing using two years’ worth of wind data. This method
and its results are described in the next few paragraphs.
First, the worst-case hourly regulation requirement based on the initial wind power was
calculated from the two years’ worth of wind data. This worst case regulation was calculated
using a very simple method. The next hour wind schedule was set to the value of the wind plant
at the beginning of the hour. Any downward movement in the wind would be balanced out by
the regulation resource such that the net power out of the wind farm plus the regulation
resource would stay flat for the entire hour. The worst case energy requirement was tabulated
for each 2 MW range of wind starting power. The resulting energy need was calculated and put
on a graph to visualize the results. The following two examples should provide some assistance
in understanding the blue curve shown below in Figure 1. The blue curve represents the largest
amount of regulation energy required to fully regulate the wind farm output based on the initial
power output at the beginning of the hour.
For a starting wind power output of 0 to 2 MW, the worst case energy needs for a wind
down ramp is 1.86 MWh. This would occur if the wind started at 2 MW and quickly
ramped down to 0 MW and stayed there for the rest of the hour.
For a starting wind power output between 32 and 34 MW, the worst case energy needs
for a wind down ramp is 27.1 MWh. Again, this would occur if the wind quickly ramps
down from the starting value to near zero and stays there for the rest of the hour.
A linear characteristic was selected to represent the necessary battery regulation based on the
starting wind power output. The slope of this line is approximately 0.83 MWh required per MW
initial power output. The characteristic is shown in red in Figure 1. It is assumed that the battery
power rating is such that the battery can provide a power output equal to the large wind farm
plant output (50 MW). The red characteristic curve shows a desired regulation resource charge
level. A control strategy should attempt to keep the regulation resource energy at the desired
energy in real time. By controlling the regulation resource to the resource characteristic, two
benefits are realized:
1. For lower wind power outputs (0 – 30 MW), the regulation resource would provide
enough energy for all wind down ramps. In order to minimize the regulation resource
energy requirement, the loss of a large amount of wind power will require grid regulation
resources to survive. This can occur when the blue curve is above the red curve for
large starting power outputs (30 – 50 MW). The regulation resource should be sized to
keep the occurrences of this shortfall to fewer than once per month.
March 7, 2014 Page 11
2. By maintaining a minimum charge level that will survive all wind down ramps, the
regulation resource will have a maximum amount of room to absorb energy for wind up
ramps. This will minimize the need to feather the wind turbine blades and maximize the
amount of energy captured from the wind farm.
Figure 1: Desired Regulation Characteristic
Stated again, the characteristic shown in Figure 1 would represent the desired regulation from
the regulation resource up to its energy limit (25MWh in this example). There will be instances, if
the wind is near its maximum power output, when there can be a regulation resource shortfall.
When the blue curve is above the red curve, it is possible to run into these shortfall conditions.
The battery energy management system should try to keep the battery state of charge near the
red regulation characteristic. It is not prudent to always keep the battery charged near its
maximum output since this would mean that the battery could not absorb the positive changes
in wind power. So in order to maximize the battery’s usefulness, the battery should be kept near
the desired regulation characteristic. This way the battery has the maximum ability to absorb the
wind energy when its power increases while always maintaining enough energy to survive
severe wind down ramps.
Due to the limitation of battery sizing, there will be times when the battery will have insufficient
energy to fully regulate all wind down ramps. Additionally, there will be times when the battery
does not have sufficient room to absorb the wind up ramps. The wind plant can be controlled to
limit the up ramps to prevent battery overcharging, but results in unused wind energy. For the
extreme wind down ramps, the grid will need to supply for the regulation shortfall. To determine
the number of hours, and amount of shortfall and feathered energy, a simulation was run for the
two years’ worth of wind data. This simulation can determine the effect that battery sizing and
0
5
10
15
20
25
30
35
0 102030405060Regulation Resource Required Energy (MWh)Initial Wind Power (MW)
Desired Regulation Resource Characteristic (25 MWh Capacity)
DesReg
Up Reg
March 7, 2014 Page 12
control strategy have on the amount and frequency of regulation shortfall, and wind turbine
feathering.
The following battery control strategy was implemented to keep the battery near the desired
regulation characteristic using the following equation.
ܹ݅݊݀௦ௗ௨ ൌ ܣݒ݁ݎܽ݃݁௦௦ ൫ܧ݊݁ݎ݃ݕ௧௧௬ െ ܧ݊݁ݎ݃ݕ௦ௗ ൯ ∗ ܥݎݎ݁ܿݐ݅݊ ܨܽܿݐݎ
Equation 1: Basic Wind Scheduling Method
The Average term is equal to the average value of the wind power output for x number of
samples before the hour schedule begins. The battery energy is the available energy in the
battery at the start of the hour. The desired energy is the energy value taken from the
characteristic from Figure 1 using the average power as a look-up value. The correction factor is
a value used to determine how quickly the controls will adjust the battery to the desired energy
level.
For example, let’s assume that the battery has an energy level of 20 MWh, and the wind has
been steady at 20 MW. The desired energy is approximately 17 MWh. In order to maximize the
ability of the battery to absorb energy if the wind increases, the battery charge should be
reduced to the ideal value of 17 MWh. Therefore, the wind schedule will be adjusted for the next
hour so that the battery will discharge its excess energy. Going through the calculation Wind
schedule = 20 MW + (20 MWh – 17 MWh) * (1/5hours) = 20.6 MW. The wind schedule for the
next hour would be 20.6 MW. Again, if the wind holds steady at 20 MW, the battery will
discharge 0.6 MW for the entire hour to maintain the wind schedule of 20.6 MW. By providing
this energy, the battery will be closer to the desired energy value for the next hour. A larger
correction factor will move the battery charge level to the desired level more quickly. This control
strategy was implemented for the two years’ worth of wind data using different battery energy
ratings and correction factors. Table 1 shows the results of the analysis.
March 7, 2014 Page 13
Table 1: Regulation Shortfall and Feathering Analysis Results
Average Shortfall
Case Battery Size Correction Factor Samples Total Wind Feathered Shortfall % Feathered Hours
1 35 0.2 5 152666 233 0.4 0.2% 5
2 35 0.5 5 152666 625 0.0 0.4% 0
3 30 0.2 5 152666 870 5.5 0.6% 6
4 30 0.5 5 152666 2008 5.4 1.3% 2
5 25 0.2 5 152666 1830 21.1 1.2% 11
6 25 0.5 5 152666 3892 18.5 2.5% 5
7 20 0.2 5 152666 3100 82.8 2.0% 48
8 20 0.5 5 152666 6280 52.0 4.1% 16
1a 35 0.2 5 162228 369 1.2 0.2% 3
2a 35 0.5 5 162228 773 0.0 0.5% 0
3a 30 0.2 5 162228 1122 1.2 0.7% 3
4a 30 0.5 5 162228 2319 0.0 1.4% 0
5a 25 0.2 5 162228 2203 21.7 1.4% 19
6a 25 0.5 5 162228 4424 16.2 2.7% 9
7a 20 0.2 5 162228 3613 120.5 2.2% 70
8a 20 0.5 5 162228 7018 67.5 4.3% 25
Energy (MWh)
Cases 1-8 show the results for the first year of wind data, whereas 1a – 8a represent the
second year. Battery sizes were selected from 35 MWh to 20 MWh in increments of 5 MWh.
Correction factors of 0.2 and 0.5 were used for each battery size using the 5 minute wind
average to determine the wind scheduling. Case 1 resulted in 233 MWh of lost energy due to
the need to feather the blades when the battery could not absorb the entire wind increase which
corresponds to 0.2% of the annual wind energy. Case 1 resulted in shortfall of only 0.4 MWh
that occurred over 5 separate hours throughout the year. The grid would need to supply this
additional energy.
The general observations from the results shown in Table 1 are that as the battery energy level
decreases, the amount and frequency of feathering and shortfalls increases. Also, the smaller
correction factor results in less energy lost due to feathering, but more regulation shortfall. The
recommended regulation resource should only rely on the grid for regulation for emergency
conditions. For this reason, a 20 MWh battery that would rely on the grid to supply shortfall
energy more than once per month should not be considered. The 25 MWh battery should be the
smallest battery considered for further analysis for a 52 MW wind project since it would have
between 5 and 19 shortfall hours per year. Economic analysis will determine the appropriate
amount of battery storage as it compares to the value of the unused wind energy, and frequency
of battery pack replacement.
4.2.2 17 MW Wind Farm
Similar to the 52 MW scenario, the wind output was analyzed for each year of data available.
For each minute of wind data, the change in wind output was integrated over a one-hour time
period to provide the necessary energy for that hour. The worst-case hour would require 13
MWh from the regulation resource. Sizing the regulation resource to provide for the worst case
scenario would result in an expensive, over-sized regulation resource. The same control method
used for the 52 MW wind farm was used for the 17 MW wind farm. The worst case energy
March 7, 2014 Page 14
requirement was tabulated for each 1 MW range of wind starting power. The resulting energy
need was calculated and put on a graph to visualize the results. The following two examples
should provide some assistance in understanding the blue curve shown below in Figure 2. The
blue curve represents the largest amount of regulation energy required to fully regulate the wind
farm output based on the initial power output at the beginning of the hour.
For a starting wind power output of 0 to 1 MW, the worst case energy needs for a wind
down ramp is 0.95 MWh. This would occur if the wind started at 1 MW and quickly
ramped down to 0 MW and stayed there for the rest of the hour.
For a starting wind power output between 14 and 15 MW, the worst case energy needs
for a wind down ramp is 12.1 MWh. Again, this would occur if the wind quickly ramps
down from the starting value to near zero and stays there for the rest of the hour.
A linear characteristic was selected to represent the necessary battery regulation based on the
starting wind power output. The slope of this line is approximately 0.83 MWh required per MW
initial power output. The characteristic is shown in red in Figure 2. It is assumed that the battery
power rating is such that the battery can provide a power output equal to the wind farm plant
output (17 MW). The red characteristic curve shows a desired regulation resource charge level.
A control strategy should attempt to keep the regulation resource energy at the desired energy
in real time. By controlling the regulation resource to the resource characteristic, two benefits
are realized:
3. For lower wind power outputs (0 – 12 MW), the regulation resource would provide
enough energy for all wind down ramps. In order to minimize the regulation resource
energy requirement, the loss of a large amount of wind power will require grid regulation
resources to survive. This can occur when the blue curve is above the red curve for
large starting power outputs (12 – 17 MW). The regulation resource should be sized to
keep the occurrences of this shortfall to fewer than once per month.
4. By maintaining a minimum charge level that will survive all wind down ramps, the
regulation resource will have a maximum amount of room to absorb energy for wind up
ramps. This will minimize the need to feather the wind turbine blades and maximize the
amount of energy captured from the wind farm.
March 7, 2014 Page 15
Figure 2: Desired Regulation Characteristic
Stated again, the characteristic shown in Figure 2 would represent the desired regulation from
the regulation resource up to its energy limit (10 MWh in this example). There will be instances if
the wind is near its maximum power output, when there can be a regulation resource shortfall.
When the blue curve is above the red curve, it is possible to run into these shortfall conditions.
The battery energy management system should try to keep the battery state of charge near the
red regulation characteristic. It is not prudent to always keep the battery charged near its
maximum output since this would mean that the battery could not absorb the positive changes
in wind power. So in order to maximize the battery’s usefulness, the battery should be kept near
the desired regulation characteristic. This way the battery has the maximum ability to absorb the
wind energy when its power increases while always maintaining enough energy to survive
severe wind down ramps.
Due to the limitation of battery sizing, there will be times when the battery will have insufficient
energy to fully regulate all wind down ramps. Additionally, there will be times when the battery
does not have sufficient room to absorb the wind up ramps. The wind plant can be controlled to
limit the up ramps to prevent battery overcharging, but results in unused wind energy. For the
extreme wind down ramps, the grid will need to supply for the regulation shortfall. To determine
the number of hours, and amount of shortfall and feathered energy, a simulation was run for the
two years’ worth of wind data. This simulation can determine the effect that battery sizing and
control strategy have on the amount and frequency of regulation shortfall, and wind turbine
feathering.
The following battery control strategy was implemented to keep the battery near the desired
regulation characteristic using the following equation.
0
2
4
6
8
10
12
14
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19Regulation Required (MWh)Initial Power (MW)
Desired Regulation Resource Characteristic with
10 MWh Capacity (17 MW Wind)
Worst Case Reg
Desired Characteristic
March 7, 2014 Page 16
ܹ݅݊݀௦ௗ௨ ൌ ܣݒ݁ݎܽ݃݁௦௦ ൫ܧ݊݁ݎ݃ݕ௧௧௬ െ ܧ݊݁ݎ݃ݕ௦ௗ ൯ ∗ ܥݎݎ݁ܿݐ݅݊ ܨܽܿݐݎ
Equation 2: Basic Wind Scheduling Method
The Average term is equal to the average value of the wind power output for x number of
samples before the hour schedule begins. The battery energy is the available energy in the
battery at the start of the hour. The desired energy is the energy value taken from the
characteristic from Figure 2 using the average power as a look-up value. The correction factor is
a value used to determine how quickly the controls will adjust the battery to the desired energy
level.
For example, let’s assume that the battery has an energy level of 8 MWh, and the wind has
been steady at 7 MW. The desired energy is approximately 7 MWh. In order to maximize the
ability of the battery to absorb energy if the wind increases, the battery charge should be
reduced to the ideal value of 7 MWh. Therefore, the wind schedule will be adjusted for the next
hour so that the battery will discharge its excess energy. Going through the calculation Wind
schedule = 7 MW + (8 MWh – 7 MWh) * (1/5hours) = 7.2 MW. The wind schedule for the next
hour would be 7.2 MW. Again, if the wind holds steady at 7 MW, the battery will discharge 0.2
MW for the entire hour to maintain the wind schedule of 7.2 MW. By providing this energy, the
battery will be closer to the desired energy value for the next hour. A larger correction factor will
move the battery charge level to the desired level more quickly. This control strategy was
implemented for the two years’ worth of wind data using different battery energy ratings and
correction factors. Figure 2 shows the results of the analysis.
Table 2: Regulation Shortfall and Feathering Analysis Results
Average Shortfall
Case Battery Size Correction Factor Samples Total Wind Feathered Shortfall % Feathered Hours
1 8 0.2 5 56320 1035 13.75 1.8% 20
2 8 0.5 5 56320 1933 7.2 3.4% 9
3 10 0.2 5 56320 545 1.2 1.0% 5
4 10 0.5 5 56320 1053 0.5 1.9% 2
5 12 0.2 5 56320 176 0.2 0.3% 2
6 12 0.5 5 56320 402 0 0.7% 0
7 14 0.2 5 56320 15.1 0 0.0% 0
8 14 0.5 5 56320 402 0 0.7% 0
1a 8 0.2 5 59083 1101 13 1.9% 31
2a 8 0.5 5 59083 2097 5 3.5% 12
3a 10 0.2 5 59083 589 0.3 1.0% 4
4a 10 0.5 5 59083 1154 0 2.0% 0
5a 12 0.2 5 59083 198 0 0.3% 0
6a 12 0.5 5 59083 444 0 0.8% 0
7a 14 0.2 5 59083 3.7 0 0.0% 0
8a 14 0.5 5 59083 14.6 0 0.0% 0
Energy (MWh)
Cases 1-8 show the results for the first year of wind data, whereas 1a – 8a represent the
second year. Battery sizes were selected from 8 MWh to 14 MWh in increments of 2 MWh.
Correction factors of 0.2 and 0.5 were used for each battery size using the 5 minute wind
average to determine the wind scheduling. Case 3 resulted in 545 MWh of lost energy due to
the need to feather the blades when the battery could not absorb the entire wind increase which
March 7, 2014 Page 17
corresponds to 1.0% of the annual wind energy. Case 1 resulted in shortfall of only 1.2 MWh
that occurred over 5 separate hours throughout the year. The grid would need to supply this
additional energy.
The general observations from the results shown in Figure 2 are that as the battery energy level
decreases, the amount and frequency of feathering and shortfalls increases. Also, the smaller
correction factor results in less energy lost due to feathering, but more regulation shortfall. The
recommended regulation resource should only rely on the grid for regulation for emergency
conditions. For this reason, a 8 MWh battery that would rely on the grid to supply shortfall
energy more than once per month should not be considered. The 10 MWh battery should be the
smallest battery considered for further analysis for a 17 MW wind project since it would have
between 0 and 5 shortfall hours per year. Economic analysis will determine the appropriate
amount of battery storage as it compares to the value of the unused wind energy, and frequency
of battery pack replacement.
4.3 Battery Life Evaluation
It is well understood that as batteries go through charge and discharge cycles, their effective life
is reduced. Additionally, large charge/discharge cycles degrade the battery life more quickly
than the small cycles. Many battery manufacturers provide curves that show the expected
number of charge/discharge cycles based on the depth of discharge. The newer battery
technologies can have a million or more cycles at low discharge depths, but approximately
3,000 cycles at 80% depth of discharge. A curve showing a SAFT Li-ion battery characteristic is
shown in Figure 3.
Figure 3: Battery Cycle‐Life vs. Depth of Discharge
In order to determine the length of battery life, the wind data was analyzed to give a count of the
different depths of discharge. Figure 4 is shown to explain the method behind the cycle
March 7, 2014 Page 18
counting. The blue trace shows a fictional wind power output over the course of 5 hours. The
red trace represents the wind schedule. The area between the two curves would be where the
battery would either charge or discharge to keep the total wind plus battery output equal to the
schedule.
0
5
10
15
20
25
30
35
40
45
50
0123456Power (MW)Time (hours)
Cycle Counting Methodology
Wind Output
Wind Schedule
Figure 4: Cycle Counting Method
In the first hour, there are several very small wind fluctuations. The analysis assumed that
deviations less than 500kW away from the schedule would not cause the battery to charge or
discharge. As such, the first hour has no charge/discharge cycles. The second hour, the wind
increases, therefore the battery would charge. The total energy absorbed by the battery (the
area between the curves represents the energy). During the third hour, the wind decreases, and
the battery would discharge. At the beginning of the fourth hour, the wind is still decreasing.
However, since the battery did not switch from charging to discharging, the beginning of the
fourth hour counts as a continuation of the third hour discharge. This five hour example results
in two large charge/discharge cycles followed by three smaller cycles.
Analysis was performed using the described cycle counting method and the simulated wind data
for a large wind farm. The charge/discharge cycles were tabulated for the entire year and
resulted in approximately 21,000 cycles. The majority of the cycles occur at small discharge
depths of less than 10%. Using an Excel curve fit equation to describe the battery cycle-life
characteristic shown in Figure 3, the expected battery life was calculated at 8.7 years. An
example of the calculation is shown below:
∑௧௨ ௬௦ ௧ % ை
ோ௧ௗ ௬௦ ௧ % ை
ଵ%ୀ%,ଶ%… for n = 6% ହଶ
ସ ൌ 0.143% of total battery life
There were 572 charge/discharge cycles between 4 and 6 percent for the 35 MWh battery
control strategy shown in Table 1 as case 1. At 6% depth of discharge, the SAFT Li-Ion battery
could withstand 400,000 cycles. Therefore, the 4-6% discharges account for 0.1% yearly battery
life degradation. This was added to all the other depth of discharge ranges, and resulted in an
annual battery degradation of 11.5%, or a battery life of 8.7 years for the first year’s data set,
and 8 years for the second year’s data set. Using the same controls, a battery with a 25 MWh
size would last for 6.3 years and 5.7 years respectively. When combined with the expected
need for feathering and regulation shortfall the economic impact of battery size can be
March 7, 2014 Page 19
determined. This analysis was performed for both the 17 MW wind farm and the 52 MW wind
farm options.
5 Technology Recommendation
When combined with the mature technology and lowest installation price, the recent
breakthroughs in the lead-acid battery technology make the advanced lead-acid battery
technology a front-runner for the stationary utility application market. The Sandia report further
reinforces the market trend toward lead-acid batteries with carbon enhanced electrodes such as
those provided by Xtreme Power, and Axion Power.
However, with lithium-ion’s dominance in the consumer electronics industry and its move into
the hybrid electric vehicle market, the lithium-ion battery technology should be considered. The
lithium-ion battery technology does provide superior performance when compared to the
advanced lead-acid battery technology. The high initial price of lithium-ion systems could be
offset by its superior cycle-life which would mean fewer replacement battery packs. Therefore, it
is important to study the impact of battery pack replacement costs when determining the best-fit
battery technology.
5.1 Financial Considerations
The Sandia National Laboratories recently updated an Energy Storage Systems Cost report
[2,3]. This report compared the different storage technologies and application types. The energy
storage types studied included lead-acid batteries, sodium-sulfur (Na/S), zinc-bromine (Zn/Br),
vanadium-redox (V-redox), Lithium-ion, compressed air (CAES), Pumped Hydro, High-speed
flywheels, and super capacitors. The analysis studied the 10-year ownership of the storage
device using the following factors:
Efficiency
Cycle-life
Initial Capital Costs
Operations and Maintenance
Storage-device Replacement
Of course, the storage system cycle-life, and replacement costs are dependent on the
application. The Railbelt regulation application is most closely represented in the Sandia report
[3] by frequent, short-duration discharges. Table 3 which was taken from the Sandia report
shows the costs in $/kW of the different technologies and applications. The most applicable data
set is the row inside the gold box. The results of this study give an idea of the cheapest
technological selection. The flywheel and super-capacitors are not suited for the Railbelt
regulation application due to their limited storage capacities. The cheapest choices are the
Carbon-enhanced electrode Lead-acid batteries, and the zinc-bromine batteries. While the cost
analysis used for the Sandia report did not have the level of detail that will be used to determine
the battery cycle-life for the Railbelt application, but it does provide a good baseline.
March 7, 2014 Page 20
Table 3: Energy Storage Systems Cost Update
The battery technologies that should be evaluated in greater depth for the Railbelt regulation
application are the advanced lead-acid battery technology and the lithium-ion technology. By
combining the battery sizing, expected regulation shortfall, expected wind feathering, battery
efficiency, and battery pack replacement frequency, the battery lifetime costs can be estimated.
The battery size and replacement frequency are closely related. If a large battery is purchased,
it will have a large initial capital cost. Since the battery is large, the same charge/discharge
cycles would result in a lower depth of discharge. Both the advanced lead-acid and the lithium-
ion battery technologies can withstand orders of magnitude more charge/discharge cycles at
low discharge depths. The result is that a larger battery will last longer and may need fewer
battery pack replacements during the battery system design life as was shown in the Battery
Life Evaluation section.
5.2 Economic Analysis – Advanced Lead-Acid vs. Lithium-Ion
A preliminary economic analysis was performed to compare the advanced lead-acid technology
against the lithium-ion technology. For the 52 MW and 17 MW wind farms’ various battery
energy capacities, the economic analysis took into account the following costs for assuming a
project life of 20 years and a discount rate of 5%:
Initial battery cost
Cost of battery losses (lithium-Ion batteries have better round-trip efficiency)
Battery pack replacement(s)
The battery life was calculated using the method discussed in the Battery Life Evaluation
section. The analysis determined the expected time between battery pack replacements. The
results of this analysis are shown below in Table 4.
March 7, 2014 Page 21
Table 4: Battery Life Based on Battery Capacity
10 6.2 6.6 26.5
12 8.3 8 30.4
14 11.2 9.8 34.8
25 5.2 6.3 22.4
30 6.4 7.4 24.7
35 8 8.7 27
42 11.4 11.3 31.3
17 MW Wind Farm
Battery
Size (MWh)
Xtreme
Power Saft Li ‐Ion Altair Nano
Li ‐Tritanate
Xtreme
Power Saft Li ‐Ion Altair Nano
Li ‐Tritanate
Battery
Size (MWh)
52 MW Wind Farm
The following assumptions were made for the economic analysis:
A 5% discount rate was used
Cost for energy lost due to battery inefficiency is assumed to be 100 $/MWh
Interconnection costs including a building to house the battery, the step-up transformer,
and circuit breakers will cost a total of $2.25M. The same interconnection costs will be
used for all energy storage capabilities, even though a smaller battery will need a
smaller building.
The Xtreme Power Battery costs that are based on a smaller-scale battery quote are:
o $500,000 per MW of power conditioning system
o $850,000 per MWh of initial battery pack installation
o $300,000 per MWh of replacement battery packs
The Saft Li-Ion battery costs that are based on smaller-scale battery quote are:
o $500,000 per MW of power conditioning system
o $2,500,000 per MWh of initial battery pack installation
o $1,250,000 per MWh of replacement battery packs (No quote received, assumed
½ initial cost)
The Altair Nanotechnolgies Li-Titanate battery costs that are based on smaller-scale
battery quote are:
o $1,500,000 per MW of power conditioning system
o $2,417,000 per MWh of initial battery pack installation
o $1,208,500 per MWh of replacement battery packs (No quote received, assumed
½ initial cost)
The results of the basic net present cost economic analysis are shown below in Table 5.
March 7, 2014 Page 22
Table 5: Battery Initial Installation Cost and 20 Year Project Cost
Case
(MWh) Initial $20‐year $Initial $20‐year $Initial $20‐year $
Case 10 19.25$ 26.41$ 35.75$ 58.84$ 51.92$ 53.53$
Case 12 20.95$ 27.04$ 40.75$ 59.38$ 56.75$ 58.36$
Case 14 22.65$ 27.11$ 45.75$ 65.91$ 61.59$ 63.19$
Case
(MWh) Initial $20‐year $Initial $20‐year $Initial $20‐year $
Case 25 48.50$ 66.95$ 89.75$ 133.96$ 137.68$ 141.16$
Case 30 52.75$ 72.40$ 102.25$ 152.66$ 149.76$ 153.25$
Case 35 57.00$ 73.28$ 114.75$ 166.94$ 161.85$ 165.33$
Case 42 62.95$ 74.68$ 132.25$ 166.44$ 178.76$ 182.25$
17 MW Wind Farm
Xtreme Power Saft Li ‐Ion Altair Nano Li ‐Titanate
Xtreme Power Saft Li ‐Ion Altair Nano Li ‐Titanate
52 MW Wind Farm
The economic results show that the initial cost is the dominant term of the 20-year project cost.
Also, the high cost of the lithium-ion battery technologies is not offset by its superior cycle-life.
This basic analysis shows that the lithium-ion technology is not as cost effective as the Xtreme
Power even though the Case 25 Xtreme Power battery packs needed three sets of replacement
battery packs over the 20-year project life. Due to the large price differential, additional factors
that would have slightly improve the lithium economics such as: smaller building and lower
shipping costs due to better energy density, lower maintenance costs, and a better
environmental image would likely not make up for the significant price differential. EPS
recommends the advanced lead-acid technology be used as the regulation resource.
When selecting a battery energy storage size, the frequency of shortfall hours should be
considered. Shortfall hours are the hours that the battery runs out of energy during the hour,
and the grid must supply for the shortfall. If a 25 MWh battery is selected to regulate the 52 MW
wind farm, the number of shortfall hours would be between 5 and 19 hours per year. It would be
up to the utilities to determine the best mix of battery size and frequency of shortfall. The 42
MWh case has been included since it is a combination of 25 and 16.67 MWh. This battery size
would mimic the control characteristics of the 25 MWh, but would leave 16.67 MWh as a
reserve for transient response to the loss of a generation unit, or the Kenai tie. The shortfall
hours would be eliminated since the 16.67 reserve capacity could be used for severe wind ramp
events, but during typical wind conditions, the 16.67 MWh would be reserved for a trip event.
The 42 MWh battery system would be more expensive, but would require fewer replacement
battery packs, and would provide the additional system benefit of transient event response to
the loss of a unit or Kenai tie.
6 Six Hour Energy Needs
6.1 Wind Regulation
The one hour analysis assumes the ability to change the unit schedules each hour. The single
contingency outage of the Kenai tie can island the Cooper Lake, and Bradley Lake regulation
resources. There are also many hours during a typical day when hydro resources are not
scheduled to meet the utility’s energy demands. The loss of these regulation resources severely
March 7, 2014 Page 23
limits the Anchorage area utilities’ ability to deal with the intermittent wind resource. This is due,
in part, to the current gas delivery contracts which are scheduled every six hours. So, when
either the Kenai tie is not energized or hydro is not scheduled, additional storage is necessary to
regulate the wind farm output or the wind farm must be curtailed. Due to the amount of energy
required for a six hour window (up to 300 MWh for a 52 MW wind farm), the battery and flywheel
technologies will not be economical at this scale. Therefore, the addition of flexible fuel storage
will be investigated as a means to regulate the intermittent wind resource while the Kenai
regulation resources are not available. Even with a second transmission line connecting the
Southcentral transmission system to the Kenai Peninsula, the loss of either transmission line
can reduce the transfer capacity by approximately 30 MW. Flexible fuel storage would be
needed to make up this shortfall until new gas schedules can be implemented.
Again, a power and energy requirement must be determined before any economic analysis can
be performed. The six-hour energy requirement for wind regulation will be determined in much
the same way that the one hour requirement was evaluated. The wind data was analyzed and
the largest wind down ramps were sorted by the initial wind power output were plotted in blue on
Figure 5. As an example, let’s assume the wind starts out at 25 MW. The worst possible case
would be an immediate ramp down to zero followed by six hours at 0 MW. This would result in
an energy need of 150 MWh (25 MW* 6 hours). However, in the field, the wind never ramps
down immediately, so the curve actually shows the worst case at 25 MW initial wind power to be
145 MWh. A linear curve was created to represent the six-hour energy needs against the wind
starting power, and is shown in red.
Figure 5: Six Hour Energy Needs Based on Wind Schedule
0
50
100
150
200
250
300
0 1020304050606 Hour Energy Needs (MWh)Starting Power (MW)
6 Hour Energy Needs Assuming No Capability to
Forecast Wind Ramps (52 MW Wind Farm)
Worst Energy Needs
Characteristic
March 7, 2014 Page 24
The years of wind data were analyzed by setting up a six-hour scheduling method. This
assumes that the Kenai intertie is out of service which isolates the hourly regulation resources
on the Kenai. Several different methods for creating a six-hour wind schedule were tested. Each
method that was tested assumed there is no ability to forecast wind production. Each of these
schedules was set and maintained for the entire six-hour time frame. For example, if the wind
schedule is 25 MW, and the wind stops at the beginning of the first hour, the rest of the six hour
scheduling period, the 25 MW wind schedule will be provided by the regulation resource.
The first method of setting a wind schedule uses the average wind output from the last 5
minutes of the previous hour as the basis for a wind schedule for the next six hours. This
method simply averages the 5 minutes before the hour begins and uses the average as the
schedule. The basic assumption made by the first method is “whatever the wind is doing now, it
will continue in the future.”
Second, the average wind power output of the previous six hours was used to create the
schedule for the next six hours. Again, the assumption is that the wind will continue what it did in
the previous six hours, but by using a longer time-frame, will not be influenced by short-term
wind fluctuations.
Third, the six-hour time frame from the previous day was used. This method assumes that the
wind will follow a daily cycle, and the six hours from the previous day are a good indication of
what will occur today.
Finally, a six-hour weighted average wind power was used. The weighting was assigned as
(hour-1)*0.5 + (hour-2)*0.2 + (hour-3)*0.1 + (hour-4)*0.1 + (hour-5)*0.05 + (hour-6)*0.05. This
method puts extra weight on the most recent hour, but would help remove some of the shorter
term volatility from the wind scheduling.
A simulation was run for a 17 MW and a 52 MW wind farm with each of the scheduling methods
discussed above. During this simulation, the wind data was used to determine the impact of
different scheduling philosophies on the amount of wind spilled, and the amount of regulation
shortfall. Based on the wind schedule, the regulation resource would either supply or absorb
power to maintain the wind schedule using the same formula used for the one hour regulation
analysis shown as Equation 1. The energy provided by the regulation resource during the six
hour schedule was calculated. For the six hour periods where more energy to regulate a
downward wind ramp is required than was available at the beginning of the six-hour schedule,
the time frame is listed as a shortfall. For the six-hour periods where more energy to regulate an
upward wind ramp is required than was available at the beginning of the six-hour schedule, the
time frame is listed as feathered, and the energy difference would be “spilled”. The first few days
of data is shown in Figure 6 and Table 6 below.
March 7, 2014 Page 25
Figure 6: Wind Power for First Provided Days
Table 6: 52 MW Wind Schedules for September 1 through September 2
Hour Schedule Type Initial StorageScheduleEnergy Used Schedule Type Initial Storage Schedule Energy Used
05 Min Avg 123 MWh 18.4 58.8 6 Hr Avg 123 MWh 18.4 58.8
65 Min Avg 64.2MWh 8.4 48.6 6 Hr Avg 64.2 MWh 10.1 58.5
12 5 Min Avg 15.7 MWh 1.5 8.9 6 Hr Avg 5.8 MWh 0.3 1.4
18 5 Min Avg 6.8MWh 0.3 ‐115.8 6 Hr Avg 4.4 MWh 0.0 ‐117.5
24 5 Min Avg 122.6 MWh 27.2 ‐107.0 6 Hr Avg 121.9 MWh 20.4 ‐147.5
30 5 Min Avg 229.5 MWh 41.1 ‐26.7 6 Hr Avg 269.5 MWh 46.2 3.5
36 5 Min Avg 256.2 MWh 42.5 197.5 6 Hr Avg 266.0 MWh 45.8 217.4
42 5 Min Avg 58.7 MWh 7.3 ‐49.5 6 Hr Avg 48.6 MWh 8.2 ‐43.8
0Prev Day 6hr Avg 123 MWh 18.4 58.8 6hr Weighted 123 MWh 18.4 58.8
6Prev Day 6hr Avg 64.2 MWh 10.1 58.5 6hr Weighted 64.2 MWh 9.1 52.8
12 Prev Day 6hr Avg 5.8 MWh 0.3 1.4 6hr Weighted 11.3 MWh 1.0 5.7
18 Prev Day 6hr Avg 4.4 MWh 0.0 ‐117.5 6hr Weighted 5.6 MWh 24.2 ‐116.6
24 Prev Day 6hr Avg 121.9 MWh 20.4 ‐147.5 6hr Weighted 123 MWh 43.3 ‐124.8
30 Prev Day 6hr Avg 269.5 MWh 37.4 ‐49.0 6hr Weighted 64.2 MWh 44.5 ‐13.8
36 Prev Day 6hr Avg 300 MWh 0.3 ‐55.8 6hr Weighted 123 MWh 7.0 209.5
42 Prev Day 6hr Avg 300 MWh 0.1 ‐92.9 6hr Weighted 64.2 MWh 20.9 ‐50.9
Figure 6 shows the first four days from the first year of wind power data with each vertical axis
line representing a six-hour period. During these 4 days there are three spikes of full/near full
0
10000
20000
30000
40000
50000
60000
0 1440 2880 4320 5760kW
Minute
Sept 1‐4
Series1
March 7, 2014 Page 26
wind power output. The first spike lasts for a full 12 hours. There are several ramps of the full
wind output within the six-hour schedules. Again, without the ability to forecast the wind, these
ramps must either be mitigated by the regulation resource, curtailing the wind, or a combination
of the two. An improved forecasting system could reduce the energy needs for regulating the
wind resources, and should be evaluated by the utilities. However, the impact of a state-of-the-
art wind forecasting system was not evaluated as part of this study.
Table 6 shows the energy storage usage for the first two days based on the different scheduling
methods described above. The top left quadrant shows the five minute averaging method. The
top right quadrant shows the six-hour average method. The bottom left quadrant shows the
results for the previous day six-hour average method. Finally, the bottom right quadrant shows
the results for using a six-hour weighted average scheduling method. The initial storage column
lists the amount of gas energy in storage at the beginning of each six-hour time frame. The
schedule lists the wind schedule used for the next six-hour time frame. The energy used column
lists the amount of gas storage energy that was used or saved during the six-hour time frame.
The five-minute average scheduling method example is explained below:
At hour zero, the gas storage has 123 MWh of energy. And the wind power output over five
minutes preceding the zero hour was 18.4 MW (schedule). During the next six hours, the wind
output steadily drops. In order to make up for the shortfall from the schedule, the gas storage
supplies the difference between the actual wind power, and the scheduled wind power. The total
energy used to maintain the wind schedule was 58.8 MWh. At hour six, the initial storage is 123
MWh – 58.8 MWh = 64.2 MWh. The new schedule is 8.4 MW, and again, the wind power drops
to zero over the next six hours, and the gas storage uses another 48.6 MWh. This process was
repeated for the entire year.
This analysis clearly showed that the best method for creating a schedule in terms of minimizing
feathered energy, minimizing shortfall energy, and minimizing total regulation usage was to use
the first method of averaging the last five minutes of the previous hour to create a wind
schedule. This means that the previous five minutes of wind data did the best job forecasting
the next six hours of wind power. This result is not surprising since there is a weak correlation of
wind power from day to day. This is easily observed by reviewing minutes 2880, and 4320
which are one day apart and vary by the full wind output.
Several year-long operational simulations using the five minute average wind scheduling
method were run to determine the frequency of regulation shortfall and wind feathering based
on the six-hour regulation resource and correction factor. Table 7 shows the results for a six-
hour regulation resource designed for the regulation of wind farm output.
March 7, 2014 Page 27
Table 7: Six‐Hour Regulation Simulation Results for a 52 MW Wind Farm
1 300 0.8 152666 0.0 0.0 0.0% 0
2 300 0.5 152666 8.6 32.0 0.0% 3
3 250 0.8 152666 461.7 0.0 0.3% 0
4 250 0.5 152666 289.1 32.8 0.2% 3
5 225 0.8 152666 2361.0 0.0 1.5% 0
6 225 0.5 152666 1397.4 34.5 0.9% 3
7 200 0.8 152666 5767.0 45.5 3.8% 2
8 200 0.5 152666 3329.0 56.7 2.2% 4
1a 300 0.8 162228 0.0 12.0 0.0% 1
2a 300 0.5 162228 0.0 91.3 0.0% 4
3a 250 0.8 162228 592.0 12.0 0.4% 1
4a 250 0.5 162228 380.0 91.9 0.2% 4
5a 225 0.8 162228 2477.8 28.6 1.5% 3
6a 225 0.5 162228 1435.6 98.2 0.9% 4
7a 200 0.8 162228 5406.9 70.8 3.3% 3
8a 200 0.5 162228 3276.0 170.2 2.0% 6
%feathered 6‐hr Schedule
Shortfall CountCaseEnergy
MWh
Correction
Factor
Total
wind
Feathered
MWh
Shortfall
MWh
The Energy MWh column lists the size of the gas storage facilities. The Feathered MWh lists the
energy that the gas storage facility would not be able to store during the simulation year, and
would force curtailment of the wind. The Shortfall MWh column lists the amount of energy that
the gas storage facility is unable to supply during the simulation. The 6-hr Schedule Shortfall
Count lists the number of six-hour schedules during which the gas storage is insufficient to
cover a wind down ramp. Based on these results, a 300 MWh gas storage facility would be
capable of providing the storage to fully regulate all wind up and down ramps for a year as
shown in case 1. However, in order to minimize the project cost, a storage facility could regulate
the large wind farm with as little as 200 MWh. It is recommended that the six-hour energy
storage be at least 200 MWh for the purpose of regulating the wind farm output.
March 7, 2014 Page 28
Table 8: Six‐Hour Regulation Simulation Results 17 MW Wind Farm
1 100 0.8 56320 0.0 0.0 0.0% 0
2 100 0.5 56320 8.6 18.7 0.0% 3
3 85 0.8 56320 556.0 0.0 1.0% 0
4 85 0.5 56320 351.0 6.0 0.6% 4
5 75 0.8 56320 1694.6 2.0 3.0% 2
6 75 0.5 56320 1085.6 6.7 1.9% 5
7 65 0.8 56320 3229.0 55.0 5.7% 10
8 65 0.5 56320 2124.3 51.2 3.8% 13
1a 100 0.8 59083 0.0 0.1 0.0% 1
2a 100 0.5 59083 8.6 18.7 0.0% 3
3a 85 0.8 59083 589.9 0.5 1.0% 1
4a 85 0.5 59083 366.5 18.7 0.6% 3
5a 75 0.8 59083 1631.6 16.7 2.8% 4
6a 75 0.5 59083 1029.8 32.0 1.7% 6
7a 65 0.8 59083 3354.3 73.2 5.7% 12
8a 65 0.5 59083 2061.3 66.7 3.5% 13
%feathered 6‐hr Schedule
Shortfall CountCaseEnergy
MWh
Correction
Factor
Total
wind
Feathered
MWh
Shortfall
MWh
The same analysis was performed to determine the regulation requirements for a 17 MW wind
farm as opposed to a 52 MW wind farm. The results of this analysis are shown above in Table
8. The storage sizes were selected to be approximately one third of the sizes studied for the 52
MW wind farm. However, this analysis shows that the percentage of feathered energy is greater
for the 17 MW wind farm for a storage facility of proportional size. This suggests that the 17 MW
wind farm size could be more volatile and may require more storage as a percentage of the
power than a larger wind farm. EPS would not recommend a gas storage facility smaller than 65
MWh for a 17 MW wind farm due to the frequency of energy shortfall, but anything 75 MWh or
bigger would be acceptable. The costs of the feathered energy would need to be weighed
against the cost of gas storage installation.
6.2 Loss of Kenai Tie
A secondary storage system sizing requirement is to compensate for the loss of the largest unit,
or the Kenai tie. Since the largest unit on the system in 2015 is expected to be 61 MW, the
largest single contingency in the existing transmission system will be the loss of the Kenai tie at
its maximum import into the Anchorage area. The line’s existing limit is 75 MW leaving Dave’s
Creek substation. When subtracting the loads along the line, this 75 MW import is less than 60
MW in the winter peak conditions, and as much as 68 MW in the summer valley condition.
However the loss of the Quartz Creek – Daves line section results in a loss of generation of
approximately 86 MW in the winter and 80 MW in the summer.
There are a few issues when considering energy storage for the loss of the Kenai tie. First, the
ability to reschedule the hydro resources to compensate for the wind ramps is removed since
these resources are islanded from the wind. Based on current gas scheduling contracts, the gas
turbines are scheduled for six hours at a time. This could result in up to six hours of schedule
mismatch. Second, the loss of the power import into the Anchorage area could result in load
shedding for cases that have minimal spinning reserve in the Anchorage area. The
recommended battery system for this secondary criterion could be used to supply for the lost
March 7, 2014 Page 29
import until the balancing authority has sufficient time to start a unit and prevent loadshedding
following the loss of the tie.
Following the construction of the recommended HVDC Beluga-Bernice Lake transmission line,
the outage of the existing Daves Creek – University line would result in a loss of approximately
30 MW of power during the maximum power transfer of 130 MW due to the 100 MW transfer
limit of the HVDC Intertie. This could result in the need for 180 MWh (30 MW * 6 hours) of
energy storage.
Prior to the construction of the new HVDC Intertie, or if the HVDC line is not constructed, the
maximum import capability into Anchorage is assumed to be 75 MW.
In order to give the balancing authority sufficient time to start a unit, the battery must be sized to
cover for the loss. PSS/E dynamics simulations were run with the Kenai tie importing 75 MW
into the Anchorage area. The case was created with minimal spinning reserve. Setting the case
up with minimal spinning reserve will give a worst-case simulation for any loss of generation or
import into the Anchorage area. A 50 MW battery system was added to the Railbelt database.
The battery was setup with a droop value that would force the battery to full output before the
first stage of load shed. The Kenai tie was then tripped. The result of a PSS/E simulation is
shown below in Figure 7.
It should be noted that the 75 MW import is not the worst case, single contingency event under
this import condition. The loss of the Quartz Creek – Daves Creek Line section results in a loss
of generation into the Anchorage area of 85-95 MW depending on the loads at Seward and
along the University – Daves Creek transmission line. However, the loss of this line is extremely
rare and it is unknown if the Railbelt utilities would limit the imports to cover the loss of this line
or accept limited load shedding should it occur. For purposes of this study, we have assumed
the utilities will accept limited load shedding for this contingency.
March 7, 2014 Page 30
Figure 7: Summer Valley Loss of Kenai Tie at Maximum Flow
The top set of traces show the frequencies at various places in the Railbelt system. The bottom
traces show the battery power outputs in red (MW) and blue (MVAR). The battery system
prevented load shed by quickly ramping up to its maximum power output of 50 MW. This
simulation resulted in the continued low frequency 30 seconds after the initial trip since there is
no additional room on any of the units to restore the frequency to 60 Hz. Without operator
intervention, the system would remain in this state until a unit could be started to restore
frequency and off-load the battery. It is assumed that a unit could be started in 20 minutes after
the loss of the Kenai tie. Therefore, a minimum of 16.67 MWh of battery storage is needed in
March 7, 2014 Page 31
order to supply 50 MW between the time when the tie is tripped, and a unit is started. The unit
would then run using the gas storage system for the remainder of the six-hour schedule.
After starting a gas turbine using gas storage and restoring the load along the Anchorage –
Kenai intertie, approximately 60 MW would be required from the gas turbine until the gas
schedules can be changed. In order to provide this energy for six hours, the energy requirement
would be approximately 60 MW for six hours or 360 MWh. This energy storage would be
sufficient to prevent scheduling conflicts with the gas delivery companies for the worst case
conditions of a) maximum import into the Anchorage area from the Kenai tie and, b) the loss of
the tie immediately after the current gas schedule begins. The 360 MWh of energy storage
would not be able to provide for any additional wind down ramps during the six-hour schedule.
Therefore, in order to provide some margin, EPS recommends that the storage requirement be
increased by 25% to 450 MWh to allow for additional gas storage to provide for some regulation
for wind up or down ramps after the loss of the Kenai tie. While the 450 MWh of storage is not
enough energy to deal with both the loss of the full wind output and the Kenai tie, it will be able
to fully handle the loss of the Kenai tie along with a moderate wind down ramp. The loss of the
full wind plant output coupled with the loss of the tie at its maximum import should be
considered an N-2 contingency, and should not be part of the requirements of the storage
system.
With the Kenai tie open, the utilities can change the gas schedules every six hours. With the
450 MWh of gas energy storage, the wind output could be fully regulated. In fact, the 52 MW
wind could be regulated with at least 200 MWh of gas storage as was shown in case 1 in Table
7.
Assuming the second Anchorage – Kenai intertie is built, the loss of the existing intertie would
result in the loss of 30 MW of capacity for the Anchorage utilities. In order to regulate the 17 MW
wind farm, and provide for the 30 MW lost capacity 250 MWh (70 MWh + 180 MWh) would be
needed. In order to regulate the 52 MW wind farm and provide for the 30 MW lost capacity, 380
MWh (200 MWh + 180 MWh) would be needed.
March 7, 2014 Page 32
Figure 8: Loss of AC Anchorage ‐ Kenai Intertie, 17 MW BESS, 30 MW Lost Import
Figure 8 shows the simulation result for the loss of the AC Anchorage – Kenai intertie with a 17
MW battery. It can be seen that the 17 MW battery can prevent the load shedding. The top left
set of traces show the frequencies at various places in the Railbelt system. The top left traces
show the battery signals such as power output (blue), per-unit energy (red), reactive power
(green). The bottom left set of traces show the line flows in (MW). The bottom right traces show
the bus voltages in per-unit at various places throughout the Railbelt system. This simulation
resulted in the continued low frequency 30 seconds after the initial trip since there is no
additional room on any of the units to restore the frequency to 60 Hz. Without operator
intervention, the system would remain in this state until a unit could be started to restore
frequency and off-load the battery. It is assumed that a unit could be started in 20 minutes after
the loss of the AC Anchorage – Kenai tie.
In order to provide some margin for the condition where the wind is decreasing, and the AC
Anchorage – Kenai Intertie is tripped, the recommended power and energy ratings are 25 MW
and 14 MWh respectively. This would allow the capability of regulating a smaller wind ramp
down coupled with the loss of the tie, but would not be able to respond to the full loss of the
wind farm and the tie.
This study assumes that the recommended HVDC tie is being constructed. However, another
option is to upgrade the existing line to allow a transfer capability of 125 MW. This case was not
March 7, 2014 Page 33
evaluated in this study. The minimum battery size and energy would be based on the trip of the
upgraded transmission line and the loss of the 125 MW import into the Anchorage area. For this
transmission configuration, the BESS should be sized as part of the overall transmission plan.
6.3 Gas Storage Description and Costs
In order to provide the energy required for longer term regulation of a six hour schedule, a
battery system is not financially reasonable. Therefore, EPS recommends the use of a
compressed natural gas storage system.
EPS recommends the use of containerized storage modules which store the natural gas at high
pressure in trailer-sized transportable modules. For a design capacity of 360 MWh, eleven
storage modules would be required. These storage modules would have approximately 25% of
“emergency” capacity that could be used to supply regulation energy for extreme wind ramp
events. Each storage module has 4 tanks that contain a total of 355,440 SCF of natural gas
compressed to 3,600 psig. Eleven storage modules would results in a total storage capacity of
3,909,840 SCF. This storage could supply approximately 450 MWh of energy.
The gas storage facility would be placed immediately adjacent to an existing power plant. The
storage facility consists of the gas storage modules, a compressor, and an electric driver motor,
and associated piping etc. The compressor requires a 1250 hp motor and would take the gas
from the pipeline which operates at 100 psig and compress it to 3,600 psig for storage.
The compressor and motor driver will be inside a pre-engineered metal building with concrete
floor slab and foundation which will protect the compressor and driver motor from the elements
and provide comfortable working conditions for maintenance. The storage modules will be
located outdoors, anchored to concrete slabs. The compressor building will incorporate electric
unit heaters for periods when the compressor is shut down for maintenance or repair. The
building would also have a ventilation system capable of discharging the heat rejected from the
motor and compressor. The ventilation system would also provide adequate air movement to
prevent the buildup of flammable gas within the building.
The facility would tie in to the existing natural gas pipeline serving the power plant. The natural
gas would be piped to the storage facility compressed and stored when the wind turbines are
producing excess energy. When the wind turbines are providing less power than scheduled, the
generators would ramp up and draw natural gas from the storage modules. During the storage
discharge, a pressure regulating station will knock down the gas pressure from its storage
pressure of 3,600 psig to the generator input pressure of 100 psig. The total cost for a 360 MWh
gas storage facility would be approximately $22.8 million.
The cost analysis assumed a two gas storage facilities with associated compressors, buildings,
site piping, storage modules, and labor expenses. A compressor building is included for the
ML&P power plant facility. The cost analysis assumes that the Southcentral Power Plant has
available room to house the natural gas compressor. One facility would have five gas storage
modules while the other would have six. Two storage facilities would provide increased flexibility
for maximizing the availability of on-line and off-line regulation resources.
Five different gas storage sizes were evaluated depending on the design criteria and the size of
the wind farm.
For a 17 MW Wind Farm
o A 70 MWh gas storage facility with 25% “emergency” capacity (87.5 MWh)
March 7, 2014 Page 34
o Gas storage located at one generation station
o Total system cost of $9.3 million
For a 17 MW Wind Farm with capability to pick up 30 MW import reduction for 6 hours
o A second Anchorage – Kenai intertie line is built, but the loss of the existing line
would result in a 30 MW reduction in the Anchorage import capacity
o A 250 MWh gas storage facility would be needed
o Gas storage located at two generation stations
o Total system cost of $18.2 million
For a 52 MW wind Farm
o A 210 MWh gas storage facility with 25% “emergency” capacity (262.5 MWh)
o Gas storage located at two generation stations for improved availability
o Total system cost of $18.2 million
For a 52 MW Wind Farm with capability to pick up 30 MW import reduction for 6 hours
o A second Anchorage – Kenai intertie line is built, but the loss of the existing line
would result in a 30 MW reduction in the Anchorage import capacity
o A 380 MWh gas storage facility would be needed
o Gas storage located at two generation stations
o Total system cost of $23.5 million
For capacity restoration for loss of largest unit/Kenai Tie
o No new Anchorage – Kenai Intertie
o A 360 MWh gas storage facility with 25% “emergency” capacity (450 MWh)
o Gas storage located at two generation stations for improved availability
o Total system cost of $23.5 million
7 Conclusions and Recommendations
To provide Railbelt utilities with the ability to regulate both variable generation resources and the
loss of the largest contingency in the Southcentral Railbelt, additional regulation resources are
required in the Railbelt system. Regulation resources utilizing batteries, flywheels and
compressed natural gas were evaluated in this study. Different battery and flywheel
technologies were evaluated first by their suitability to a regulation application, and secondarily
by their relative cost-effectiveness. Based on the long-term energy requirements, flywheel
technology was considered infeasible for the Railbelt system. Based on the suitability and cost-
effectiveness, EPS recommends the advanced lead-acid technology. The two main
manufacturers of suitable lead-acid technology include Xtreme Power Inc., and Axion Power
Inc. This report has focused on the Xtreme Power Inc. specific battery, but it is assumed that the
Axion Power manufacturer would provide a system with similar capabilities and costs.
The regulation resource sizing has been evaluated using primary and secondary criteria.
Primarily, the regulation resource should provide adequate regulation for the intermittent wind
resource. Secondarily, the regulation resource could be able to provide adequate response to
March 7, 2014 Page 35
prevent load shedding in the Anchorage area for the loss of either a large unit, or the Kenai tie
(with or without a HVDC intertie).
The power and energy requirements were evaluated separately. For a 17 MW wind farm
configuration EPS recommends a power capability of at least 17 MW. For a 52 MW wind farm,
EPS recommends a power capability of at least 50 MW. This power capability would be
sufficient to regulate the full range of net power from the 52 MW wind farm. Additionally, the 50
MW is the minimum power capability to prevent load-shedding for the loss of the Kenai tie while
operating at a maximum import into the Anchorage area.
For a 17 MW wind farm, to prevent an excessive number of hours during which the battery
cannot account for wind down ramps, the minimum battery energy that should be considered is
10 MWh. The one-hour regulation resource energy capability was evaluated using economic
analysis based on several factors including initial purchase price, battery pack replacement
frequency, and losses due to battery inefficiency. The lowest installation cost was for a 17 MW,
10 MWh battery energy storage system.
For a 52 MW wind farm, to prevent an excessive number of hours during which the battery
cannot account for wind down ramps, the minimum battery energy that should be considered is
25 MWh. The one-hour regulation resource energy capability was evaluated using economic
analysis based on several factors including initial purchase price, battery pack replacement
frequency, and losses due to battery inefficiency. The lowest installation cost was for a 50 MW,
25 MWh battery system.
However, a battery system with 42 MWh of energy capacity would be a reasonable alternative.
It would increase the original purchase price by 30%, but would provide the additional system
benefit of carrying enough storage capacity to provide 50 MW for 20 minutes. The reserve
capacity would be enough to provide enough energy to survive the loss of the Kenai tie at 75
MW import in to the Anchorage area without load shedding, and provide enough time to start an
additional gas turbine. The 42 MWh battery would only cost 11.5% more over the 20 year life of
the project since the battery packs would need less frequent replacement. EPS recommends a
battery energy capacity of 25 MWh solely for the regulation of the wind farm. However, with the
additional system benefits of a 42 MWh battery, the larger battery energy capacity should be
considered as an alternative in the final regulation resource decision process. Additionally, if the
DC tie is not built and the utilities move forward with an upgrade of the AC tie, the battery
MW/MWH capabilities should be determined as part of the coordinated transmission plan.
Similarly, for a 17 MW wind farm and the addition of a HVDC Beluga-Bernice Lake intertie, a
BESS capacity of 25 MW and 14 MWH of energy is recommended to prevent load shedding in
the Southcentral area following the largest contingency and to provide regulation of the wind
resource.
In order to minimize costs, it could be possible to implement a battery system with a smaller
power capability. An example would be to use the 25 MW battery system to regulate a 52 MW
wind farm. During a system configuration with both minimal online reserves, and a risk of losing
the full wind output, the wind farm could be curtailed prior to the loss of the total wind farm to
prevent an energy shortfall. This would result in a slight reduction of renewable energy over the
year, but would provide significant savings in the form of a smaller battery inverter system.
Due to the current gas contract schedule, the natural gas delivery amounts are set with six-hour
schedules. With the loss of the Kenai tie and the associated hydro regulation resources, the
Anchorage area utilities have very little capability to provide regulation for an intermittent
resource. With the installation of gas storage facilities, the utilities will have the ability to regulate
an intermittent resource such as wind. Again, the sizing of this resource was evaluated using
March 7, 2014 Page 36
the primary design criteria of providing wind regulation and the secondary criteria to cover the
loss of the Kenai tie. In order to fully regulate the full wind output over a six hour schedule for a
17 MW or a 52 MW wind farm, approximately 100 MWh or 270 MWh of energy is needed,
respectively. In order to minimize the costs, the gas storage capacity was reduced to a level that
would minimize costs while still minimizing the frequency of storage energy shortfall.
The secondary criteria of covering the loss of the Kenai tie would need 360 MWh without a
Beluga-Bernice HVDC tie or 180 MWH if the HVDC tie is constructed. In order to survive the
worst case loss of the Kenai tie and provide minimal wind regulation, EPS recommends a 25%
reserve margin of 90 MWh above the 360 MWh or 450 MWh for the no HVDC option and 45
MWH if the HVDC tie is constructed.
8 References
1. National Rural Electric Cooperative Association, Cooperative Research Network, “Energy
Storage for Renewable Energy and Transmission and Distribution Asset Deferral,” November
2009.
2. EPRI-DOE Handbook of Energy Storage for Transmission & Distribution Applications, EPRI,
Palo Alto, CA, and the U.S. Depatrment of Energy, Washington, DC: 2003. 1001834.
3. Schoenung, Susan and Eyer, James. Benefit/Cost Framework for Evaluating Modular Energy
Storage. SAND2008-0978. 2008.