HomeMy WebLinkAboutAlaska Railbelt Integrated Resource Plan (RIRP) Study 2010
Alaska Railbelt
Regional Integrated Resource Plan
(RIRP) Study
Final Report
February 2010
DISCLAIMER
ALASKA RIRP STUDY
Black & Veatch i February 2010
DISCLAIMER STATEMENT
In conducting our analysis and in forming the recommendations summarized in this report, Black &
Veatch Corporation (Black & Veatch) has made certain assumptions with respect to conditions, events,
and circumstances that may occur in the future. In addition, Black & Veatch has relied upon information
provided by others. Black & Veatch has assumed that the information, both verbal and written, provided
by others is complete and correct; however, Black & Veatch does not guarantee the accuracy of the
information, data, or opinions contained herein. The methodologies we utilized in performing the
analysis and developing our recommendations follow generally accepted industry practices. While we
believe that such assumptions and methodologies, as summarized in this report, are reasonable and
appropriate for the purpose for which they are used, depending upon conditions, events, and
circumstances that actually occur but are unknown at this time, actual results may materially differ from
those projected. Such factors may include, but are not limited to, the ability of the Railbelt electric
utilities and the State of Alaska to implement the recommendations and execute the implementation plan
contained herein, the regional and national economic climate, and growth in the Railbelt region.
Readers of this report are advised that any projected or forecasted financial, operating, growth,
performance, or strategy merely reflects the reasonable judgment of Black & Veatch at the time of the
preparation of such information and is based on a number of factors and circumstances beyond our
control. Accordingly, Black & Veatch makes no assurances that the projections or forecasts will be
consistent with actual results or performance.
Any use of this report, and the information therein, constitutes agreement that: 1) Black & Veatch makes no
warranty, express or implied, relating to this report, 2) the user accepts the sole risk of any such use, and
3) the user waives any claim for damages of any kind against Black & Veatch. The benefit of such releases,
waivers, or limitations of liability shall extend to the related companies, and subcontractors of any tier of
Black & Veatch and the directors, officers, partners, employees, and agents of all released or indemnified
parties.
ACKNOWLEDGEMENTS
ALASKA RIRP STUDY
Black & Veatch ii February 2010
ACKNOWLEDGEMENTS
The Black & Veatch project team would like to thank the following individuals for their valuable
contributions to this project.
Alaska Energy Authority
• Steve Haagenson, AEA Executive Director
• Jim Strandberg, Project Manager
• Bryan Carey, Project Manager
• David Lockard, Geothermal and Ocean
Energy Program Manager
• Doug Ott, Hydroelectric Program Manager
• James Jensen, Wind Program Manager
• Jim Hemsath, Deputy Director, Development
• Christopher Rutz, Procurement Manager
• Sherrie Siverson, Administrative Assistant
Railbelt Utilities (numerous management personnel from the following Railbelt utilities)
• Anchorage Municipal Light & Power
• Chugach Electric Association
• City of Seward Electric System
• Golden Valley Electric Association
• Homer Electric Association
• Matanuska Electric Association
Advisory Working Group Members
• Norman Rokeberg, Retired State of Alaska
Representative, Chairman
• Chris Rose, Renewable Energy Alaska
Project
• Brad Janorschke, Homer Electric Association
• Carri Lockhart, Marathon Oil Company
• Colleen Starring, Enstar Natural Gas
Company
• Debra Schnebel, Scott Balice Strategies
• Jan Wilson, Regulatory Commission of
Alaska
• Jim Sykes, Alaska Public Interest Research
Group
• Lois Lester, AARP
• Marilyn Leland, Alaska Power Association
• Mark Foster, Mark A. Foster & Associates
• Nick Goodman, TDX Power, Inc.
• Pat Lavin, National Wildlife
Federation - Alaska
• Steve Denton, Usibelli Coal Mine, Inc.
• Tony Izzo, TMI Consulting
Additional Individuals That Provided Substantive Input to Project
• Alan Dennis, Alaska Department of Natural
Resources
• Bob Butera, HDR, Inc.
• Bob Swenson, Alaska Department of Natural
Resources
• David Burlingame, Electric Power Systems,
Inc. (EPS)
• Dick Schober, Seattle-Northwest Securities
Corporation
• Harry Noah, Alaska Mental Health Lands
Trust Office
• Harold Heinze, Alaska Natural Gas
Development Authority
• Jeb Spengler, Seattle-Northwest Securities
Corporation
• Joe Balash, Alaska Governor’s Office
• Ken Fonnesbeck, HDR, Inc.
• Ken Vassar, Birch, Horton, Bittner, Cherot
• Kevin Banks, Alaska Department of Natural
Resources
• Mark Myers, Alaska Department of Natural
Resources
• Paul Berkshire, HDR, Inc.
• Stephen Spain, HDR, Inc.
PURPOSE AND LIMITATIONS OF THE RIRP
ALASKA RIRP STUDY
Black & Veatch iii February 2010
Purpose and Limitations of the RIRP
• The development of this RIRP is not the same as the development of a State Energy Plan; nor does it set
State policy. Setting energy-related policies is the role of the Governor and State Legislature. With regard
to energy policy making, however, the RIRP does provide a foundation of information and analysis that
can be used by policy makers to develop important policies.
Having said this, the development of a State Energy Policy and or related policies could directly impact
the specific alternative resource plan chosen for the Railbelt region’s future. As such, the RIRP may need
to be readdressed as future energy-related policies are enacted.
• This RIRP, consistent with all integrated resource plans, should be viewed as a “directional” plan. In this
sense, the RIRP identifies alternative resource paths that the region can take to meet the future electric
needs of Railbelt citizens and businesses; in other words, it identifies the types of resources that should be
developed in the future. The granularity of the analysis underlying the RIRP is not sufficient to identify
the optimal configuration (e.g., specific size, manufacturer, model, location, etc.) of specific resources
that should be developed. The selection of specific resources requires additional and more detailed
analysis.
• The alternative resource options considered in this study include a combination of identified projects
(e.g., Susitna and Chakachamna hydroelectric projects, Mt. Spurr geothermal project, etc.), as well as
generic resources (e.g., Generic Hydro – Kenai, Generic Wind – GVEA, generic conventional generation
alternatives, etc.). Identified projects are included, and shown as such, because they are projects that are
currently at various points in the project development lifecycle. Consequently, there is specific capital
cost and operating assumptions available on these projects. Generic resources are included to enable the
RIRP models to choose various resource types, based on capital cost and operating assumptions
developed by Black & Veatch. This approach is common in the development of integrated resource plans.
Consistent with the comment above regarding the RIRP being a “directional” plan, the actual resources
developed in the future, while consistent with the resource type identified, may be: 1) the identified
project shown in the resource plan (e.g., Chakachamna), 2) an alternative identified project of the same
resource type (e.g., Susitna); or 3) an alternative generic project of the same resource type. One reason for
this is the level of risks and uncertainties that exist regarding the ability to plan, permit, and develop each
project. Consequently, when looking at the resource plans shown in this report, it is important to focus on
the resource type of an identified resource, as opposed to the specific project.
• The capital costs and operating assumptions used in this study for alternative DSM/EE, generation and
transmission resources do not consider the actual owner or developer of these resources. Ownership could
be in the form of individual Railbelt utilities, a regional entity, or an independent power producer (IPP).
Depending upon specific circumstances, ownership and development by IPPs may be the least-cost
alternative.
• As with all integrated resource plans, this RIRP should be periodically updated (e.g., every three years) to
identify changes that should be made to the preferred resource plan to reflect changing circumstances
(e.g., resolution of uncertainties), improved cost and performance of emerging technologies (e.g., tidal),
and other developments.
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-1 February 2010
Table of Contents
1.0 Executive Summary...............................................................................................................1-1
1.1 Current Situation Facing the Railbelt Utilities...........................................................1-1
1.2 Project Overview .......................................................................................................1-3
1.3 Evaluation Scenarios..................................................................................................1-7
1.4 Summary of Key Input Assumptions.........................................................................1-8
1.5 Susitna Analysis.........................................................................................................1-8
1.6 Transmission Analysis.............................................................................................1-11
1.7 Summary of Results.................................................................................................1-12
1.7.1 Results of Reference Cases .......................................................................1-13
1.7.2 Sensitivity Cases Evaluated.......................................................................1-16
1.7.3 Summary of Results – Economics and Emissions ....................................1-16
1.7.4 Results of Transmission Analysis .............................................................1-19
1.7.5 Results of Financial Analysis....................................................................1-22
1.8 Implementation Risks and Issues.............................................................................1-26
1.8.1 General Risks and Issues...........................................................................1-26
1.8.2 Resource Specific Risks and Issues...........................................................1-27
1.9 Conclusions and Recommendations........................................................................1-29
1.9.1 Conclusions ...............................................................................................1-29
1.9.2 Recommendations .....................................................................................1-33
1.10 Near-Term Implementation Action Plan (2010-2012) ............................................1-40
1.10.1 General Actions.........................................................................................1-41
1.10.2 Capital Projects..........................................................................................1-43
1.10.3 Supporting Studies and Activities.............................................................1-44
1.10.4 Other Actions.............................................................................................1-45
2.0 Project Overview and Approach............................................................................................2-1
2.1 Project Overview .......................................................................................................2-1
2.2 Project Approach .......................................................................................................2-2
2.3 Modeling Methodology .............................................................................................2-5
2.3.1 Study Period and Considerations.................................................................2-5
2.3.2 Strategist® and PROMOD® Overview.........................................................2-5
2.3.3 Benchmarking..............................................................................................2-5
2.3.4 Hydroelectric Methodology.........................................................................2-6
2.3.5 Evaluation Scenarios...................................................................................2-7
2.4 Stakeholder Input Process..........................................................................................2-8
2.5 Role of Advisory Working Group and Membership.................................................2-9
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-2 February 2010
Table of Contents (Continued)
3.0 Situational Assessment..........................................................................................................3-1
3.1 Uniqueness of the Railbelt Region ............................................................................3-2
3.2 Cost Issues .................................................................................................................3-2
3.3 Natural Gas Issues......................................................................................................3-6
3.4 Load Uncertainties...................................................................................................3-10
3.5 Infrastructure Issues.................................................................................................3-10
3.6 Future Resource Options..........................................................................................3-11
3.7 Political Issues .........................................................................................................3-13
3.8 Risk Management Issues..........................................................................................3-13
4.0 Description of Existing System .............................................................................................4-1
4.1 Existing Generating Resources..................................................................................4-1
4.1.1 Anchorage Municipal Light & Power.........................................................4-1
4.1.2 Chugach Electric Association......................................................................4-2
4.1.3 Golden Valley Electric Association ............................................................4-2
4.1.4 Homer Electric Association.........................................................................4-3
4.1.5 Matanuska Electric Association..................................................................4-3
4.1.6 Seward Electric System...............................................................................4-3
4.1.7 Hydroelectric Resources..............................................................................4-3
4.1.8 Railbelt System............................................................................................4-5
4.2 Committed Generating Resources.............................................................................4-5
4.2.1 Southcentral Power Project .........................................................................4-5
4.2.2 ML&P Units................................................................................................4-5
4.2.3 Healy Clean Coal Project ............................................................................4-7
4.2.4 HEA Units...................................................................................................4-7
4.2.5 MEA Units...................................................................................................4-7
4.2.6 City of Seward Diesels................................................................................4-7
4.3 Existing Transmission Grid.......................................................................................4-8
4.3.1 Alaska Intertie ...........................................................................................4-10
4.3.2 Southern Intertie........................................................................................4-10
4.3.3 Transmission Losses..................................................................................4-11
4.4 Must Run Capacity ..................................................................................................4-11
5.0 Economic Parameters.............................................................................................................5-1
5.1 Inflation and Escalation Rates ...................................................................................5-1
5.2 Financing Rates..........................................................................................................5-1
5.3 Present Worth Discount Rate.....................................................................................5-1
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-3 February 2010
Table of Contents (Continued)
5.4 Interest During Construction Interest Rate................................................................5-1
5.5 Fixed Charge Rates....................................................................................................5-1
6.0 Forecast of Electrical Demand and Consumption .................................................................6-1
6.1 Load Forecasts...........................................................................................................6-1
6.2 Load Forecasting Methodology.................................................................................6-1
6.3 Peak Demand and Net Energy for Load Requirements.............................................6-1
6.4 Significant Opportunities for Increased Loads..........................................................6-4
6.4.1 Plug-In Hybrid Vehicles..............................................................................6-4
6.4.2 Electric Space and Water Heating Load....................................................6-10
6.4.3 Economic Development Loads..................................................................6-10
7.0 Fuel and Emissions Allowance Price Projections..................................................................7-1
7.1 Fuel Price Forecasts...................................................................................................7-1
7.1.1 Natural Gas Availability and Price Forecasts..............................................7-1
7.1.2 Methodology for Other Fuel Price Forecasts ..............................................7-9
7.1.3 Resulting Fuel Price Forecasts ..................................................................7-10
7.2 Emission Allowance Price Projections....................................................................7-10
7.2.1 Existing Legislation...................................................................................7-10
7.2.2 Proposed Legislation.................................................................................7-10
7.2.3 Development of CO2 Emission Price Projection.......................................7-10
8.0 Reliability Criteria .................................................................................................................8-1
8.1 Planning Reserve Margin Requirements ...................................................................8-1
8.2 Operating Reserve Margin Requirements..................................................................8-1
8.2.1 Spinning Reserves.......................................................................................8-1
8.2.2 Non-Spinning Operating Reserves..............................................................8-2
8.3 Renewable Considerations.........................................................................................8-2
8.4 Regulation..................................................................................................................8-2
9.0 Capacity Requirements..........................................................................................................9-1
10.0 Supply-Side Options............................................................................................................10-1
10.1 Conventional Technologies .....................................................................................10-1
10.1.1 Introduction...............................................................................................10-1
10.1.2 Capital, and Operating and Maintenance (O&M) Cost Assumptions.......10-1
10.1.3 Generating Alternatives Assumptions.......................................................10-1
10.1.4 Conventional Technology Options............................................................10-5
10.2 Beluga Unit 8 Repowering.....................................................................................10-17
10.3 GVEA North Pole 1x1 Retrofit..............................................................................10-17
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-4 February 2010
Table of Contents (Continued)
10.4 Renewable Energy Options....................................................................................10-17
10.4.1 Hydroelectric Project Options.................................................................10-17
10.4.2 Ocean (Tidal Wave) Project Option........................................................10-27
10.4.3 Geothermal Project Option......................................................................10-32
10.4.4 Wind Project Options..............................................................................10-35
10.4.5 Modular Nuclear Project Option.............................................................10-40
10.4.6 Municipal Solid Waste Project Options..................................................10-45
10.4.7 Central Heat and Power...........................................................................10-45
11.0 Demand-Side Management/Energy Efficiency Resources..................................................11-1
11.1 Introduction..............................................................................................................11-1
11.2 Background and Overview ......................................................................................11-2
11.2.1 Current Railbelt Utility DSM/EE Programs..............................................11-2
11.2.2 Literature Review......................................................................................11-4
11.2.3 Characterization of the Customer Base.....................................................11-4
11.3 DSM/EE Potential....................................................................................................11-6
11.3.1 Methodology for Determining Technical Potential...................................11-6
11.3.2 Intuitive Screening.....................................................................................11-6
11.3.3 Program Design Process............................................................................11-7
11.3.4 Achievable DSM Potential from Other Studies ........................................11-8
11.4 DSM/EE Measures...................................................................................................11-8
11.5 DSM/EE Program Delivery...................................................................................11-16
12.0 Transmission Projects..........................................................................................................12-1
12.1 Existing Railbelt System..........................................................................................12-1
12.2 The GRETC Transmission Concept........................................................................12-3
12.3 Project Categories....................................................................................................12-4
12.4 Summary of Transmission Analysis Conducted......................................................12-4
12.4.1 Cases Reviewed.........................................................................................12-5
12.4.2 Results of 2060 Analysis...........................................................................12-6
12.5 Proposed Projects.....................................................................................................12-6
12.6 Susitna....................................................................................................................12-26
12.7 Summary of Transmission Projects.......................................................................12-27
12.8 Other Reliability Projects.......................................................................................12-30
12.9 Projects Priorities...................................................................................................12-31
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-5 February 2010
Table of Contents (Continued)
13.0 Summary of Results.............................................................................................................13-1
13.1 Results of Reference Cases......................................................................................13-1
13.1.1 Results - DSM/EE Resources....................................................................13-1
13.1.2 Results - Scenarios 1A/1B Reference Cases.............................................13-2
13.1.3 Results - Scenario 2A Reference Case Results .........................................13-3
13.1.4 Results - Scenario 2B Reference Case Results..........................................13-3
13.2 Results of Sensitivity Cases.....................................................................................13-3
13.2.1 Sensitivity Cases Evaluated.......................................................................13-3
13.2.2 Sensitivity Results – Scenarios 1A/1B Without DSM/EE Measures........13-4
13.2.3 Sensitivity Results – Scenarios 1A/1B With Double DSM/EE
Measures....................................................................................................13-4
13.2.4 Sensitivity Results – Scenarios 1A/1B With Committed Units
Included.....................................................................................................13-5
13.2.5 Sensitivity Results – Scenarios 1A/1B Without CO2 Costs......................13-5
13.2.6 Sensitivity Results – Scenarios 1A/1B With Higher Gas Prices...............13-6
13.2.7 Sensitivity Results – Scenarios 1A/1B Without Chakachamna................13-6
13.2.8 Sensitivity Results – Scenarios 1A/1B With Chakachamna Capital
Costs Increased by 75%.............................................................................13-6
13.2.9 Sensitivity Results – Scenarios 1A/1B With Susitna (Lower Low
Watana Non-Expandable Option) Forced.................................................13-7
13.2.10 Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana
Non-Expandable Option) Forced ..............................................................13-7
13.2.11 Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana
Expandable Option) Forced.......................................................................13-7
13.2.12 Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana
Expansion Option) Forced.........................................................................13-8
13.2.13 Sensitivity Results – Scenarios 1A/1B With Susitna (Watana
Option) Forced...........................................................................................13-8
13.2.14 Sensitivity Results – Scenarios 1A/1B With Susitna (High Devil
Canyon Option) Forced.............................................................................13-9
13.2.15 Sensitivity Results – Scenarios 1A/1B With Modular Nuclear.................13-9
13.2.16 Sensitivity Results – Scenarios 1A/1B With Tidal..................................13-10
13.2.17 Sensitivity Results – Scenarios 1A/1B With Lower Coal Capital
and Fuel Costs .........................................................................................13-10
13.2.18 Sensitivity Results – Scenarios 1A/1B With Federal Tax Credits for
Renewables..............................................................................................13-10
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-6 February 2010
Table of Contents (Continued)
13.3 Summary of Results...............................................................................................13-11
13.3.1 Summary of Results - Economics ...........................................................13-11
13.3.2 Summary of Results - Emissions.............................................................13-11
13.4 Results of Transmission Analysis..........................................................................13-11
13.5 Results of Financial Analysis.................................................................................13-16
14.0 0BImplementation Risks and Issues.........................................................................................14-1
14.1 1BGeneral Risks and Issues .........................................................................................14-1
14.1.1 3BOrganizational Risks and Issues................................................................14-1
14.1.2 4BResource Risks and Issues.........................................................................14-4
14.1.3 5BFuel Supply Risks and Issues....................................................................14-4
14.1.4 6BTransmission Risks and Issues..................................................................14-5
14.1.5 7BMarket Development Risks and Issues......................................................14-5
14.1.6 8BFinancing and Rate Risks and Issues.........................................................14-6
14.1.7 9BLegislative and Regulatory Risks and Issues ............................................14-7
14.1.8 10BValue of Optionality..................................................................................14-7
14.2 2BResource Specific Risks and Issues.........................................................................14-8
14.2.1 11BIntroduction...............................................................................................14-8
14.2.2 12BResource Specific Risks and Issues – Summary.......................................14-8
14.2.3 13BResource Specific Risks and Issues – Detailed Discussion.....................14-12
15.0 Conclusions and Recommendations....................................................................................15-1
15.1 Conclusions..............................................................................................................15-2
15.2 Recommendations....................................................................................................15-6
15.2.1 Recommendations - General .....................................................................15-7
15.2.2 Recommendations – Capital Projects......................................................15-11
15.2.3 Recommendations - Other.......................................................................15-12
16.0 Near-Term Implementation Action Plan (2010-2012) ........................................................16-1
16.1 General Actions .......................................................................................................16-1
16.2 Capital Projects........................................................................................................16-3
16.3 Supporting Studies and Activities............................................................................16-4
16.4 Other Actions...........................................................................................................16-5
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-7 February 2010
Table of Contents (Continued)
Appendix A Susitna Analysis
Appendix B Financial Analysis
Appendix C Existing Generation Units
Appendix D Regional Load Forecasts
Appendix E Detailed Results – Scenarios 1A / 1B
Appendix F Detailed Results – Scenario 2A
Appendix G Detailed Results – Scenario 2B
Tables
Table 1-1 Summary Listing of Issues Facing the Railbelt Region.............................................1-3
Table 1-2 Alternative Resource Options Considered.................................................................1-5
Table 1-3 Susitna Summary.....................................................................................................1-10
Table 1-4 Summary of Results – Economics...........................................................................1-17
Table 1-5 Summary of Results – Emissions ............................................................................1-18
Table 1-6 Summary of Proposed Transmission Projects.........................................................1-19
Table 1-7 Resource Specific Risks and Issues - Summary......................................................1-28
Table 1-8 Resources Selected in Scenario 1A/1B Resource Plan............................................1-35
Table 1-9 Impact of Selected Issues on the Preferred Resource Plan......................................1-36
Table 1-10 Projects Significantly Under Development .............................................................1-37
Table 1-11 Near-Term Implementation Action Plan – General Actions...................................1-41
Table 1-12 Near-Term Implementation Action Plan – Capital Projects....................................1-43
Table 1-13 Near-Term Implementation Action Plan – Supporting Studies and Activities........1-44
Table 1-14 Near-Term Implementation Action Plan – Other Actions.......................................1-45
Table 3-1 Relative Cost per kWh (Alaska Versus Other States) - 2007....................................3-4
Table 3-2 Relative Monthly Electric Bills Among Alaska Railbelt Utilities.............................3-5
Table 4-1 ML&P Existing Thermal Units..................................................................................4-1
Table 4-2 Chugach Existing Thermal Units...............................................................................4-2
Table 4-3 GVEA Existing Thermal Units..................................................................................4-3
Table 4-4 HEA Existing Thermal Units.....................................................................................4-3
Table 4-5 Railbelt Hydroelectric Generation Plants..................................................................4-4
Table 4-6 Hydroelectric Monthly and Annual Energy (MWh)..................................................4-4
Table 4-7 Railbelt Installed Capacity.........................................................................................4-5
Table 4-8 Railbelt Committed Generating Resources................................................................4-6
Table 5-1 Cost of Capital and Fixed Charge Rates for the GRETC System..............................5-2
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-8 February 2010
Table of Contents (Continued)
Tables (Continued)
Table 6-1 GRETC’s Winter Peak Load Forecast for Evaluation (MW) 2011 - 2060................6-2
Table 6-2 GRETC’s Summer Peak Load Forecast for Evaluation (MW) 2011 - 2060.............6-2
Table 6-3 GRETC’s Annual Valley Load Forecast for Evaluation (MW) 2011 - 2060............6-3
Table 6-4 GRETC’s Net Energy for Load Forecast for Evaluation (GWh) 2011 - 2060..........6-3
Table 6-5 Projected PHEV Penetration in the American Auto Market .....................................6-4
Table 6-6 Electric Consumption for a PHEV33 PNNL Kinter-Meyer......................................6-5
Table 6-7 Additional Annual Energy Required in the Alaska Railbelt Region from
PHEVs........................................................................................................................6-5
Table 6-8 Hourly Distribution of PHEV Load on a Typical Day – Alaska Railbelt
Region........................................................................................................................6-7
Table 6-9 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt
System’s Energy Requirement...................................................................................6-9
Table 6-10 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt
System’s Peak Demand..............................................................................................6-9
Table 6-11 2007 Natural Gas Consumption for the State of Alaska (Source: EIA)..................6-10
Table 6-12 Calculated Railbelt System Energy and Demand by Customer Type for
Electric Space and Water Heating...........................................................................6-10
Table 6-13 Potential Economic Development Projects..............................................................6-11
Table 6-14 GRETC’s Winter Peak Large Load Forecast for Evaluation (MW) 2011 -
2060..........................................................................................................................6-12
Table 6-15 GRETC’s Large Load Net Energy for Load Forecast for Evaluation (GWh)
2011 - 2060..............................................................................................................6-12
Table 7-1 Representative Risk-Based Metrics for Railbelt Natural Gas Demand Based
on Historical Data and Known Changes in Gas Consumption..................................7-4
Table 7-2 Representative Forecasts of Railbelt Natural Gas Price According to
Different Benchmarks................................................................................................7-9
Table 7-3 Nominal Fuel Price Forecasts ($/MMBtu) ..............................................................7-11
Table 7-4 CO2 Allowance Price Projections............................................................................7-13
Table 8-1 Railbelt Spinning Reserve Requirements ..................................................................8-1
Table 8-2 Quick-Start Units.......................................................................................................8-3
Table 10-1 Possible Owner’s Costs............................................................................................10-2
Table 10-2 Nonrecoverable Degradation Factors ......................................................................10-6
Table 10-3 GE LM6000 PC Combustion Turbine Characteristics............................................10-8
Table 10-4 GE LM6000 PC Estimated Emissions.....................................................................10-8
Table 10-5 GE LMS100 Combustion Turbine Characteristics................................................10-10
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-9 February 2010
Table of Contents (Continued)
Tables (Continued)
Table 10-6 GE LMS100 Estimated Emissions.........................................................................10-10
Table 10-7 GE 1x1 6FA Combined Cycle Characteristics......................................................10-12
Table 10-8 GE 1x1 6FA Combined Cycle Estimated Emissions.............................................10-12
Table 10-9 GE 2x1 6FA Combined Cycle Characteristics......................................................10-13
Table 10-10 GE 2x1 6FA Combined Cycle Estimated Emissions.............................................10-13
Table 10-11 Subcritical PC Thermal Performance Estimates....................................................10-15
Table 10-12 Subcritical PC Estimated Air Emissions................................................................10-15
Table 10-13 Capital Costs, O&M Costs, and Schedules for the Generating Alternatives
(All Costs in 2009 Dollars)....................................................................................10-16
Table 10-14 AEA Recommended Funding Decisions - Hydro..................................................10-18
Table 10-15 Susitna Summary...................................................................................................10-21
Table 10-16 Average Annual Monthly Generation from Susitna Projects (MWh)...................10-23
Table 10-17 Monthly Average and Annual Generation.............................................................10-25
Table 10-18 Glacier Fork Hydroelectric Project Average Monthly Energy Generation..........10-26
Table 10-19 AEA Recommended Funding Decisions - Wind...................................................10-36
Table 11-1 Current Railbelt Electric Utility DSM/EE-Related Activities.................................11-2
Table 11-2 DSM/EE-Related Literature Sources.......................................................................11-4
Table 11-3 Railbelt Electric Utility Customer Base...................................................................11-5
Table 11-4 Residential and Commercial DSM/EE Technologies Evaluated...........................11-10
Table 11-5 Input Assumptions - Residential DSM/EE Measures............................................11-12
Table 11-6 Input Assumptions - Commercial DSM/EE Measures..........................................11-13
Table 12-1 Summary of Proposed Transmission Projects.......................................................12-27
Table 13-1 Summary of Results – Economics.........................................................................13-12
Table 13-2 Summary of Results – Emissions ..........................................................................13-13
Table 13-3 Summary of Proposed Transmission Projects.......................................................13-14
Table 14-1 Resource Specific Risks and Issues - Summary......................................................14-9
Table 14-2 Resource Specific Risks and Issues – DSM/EE ....................................................14-13
Table 14-3 Resource Specific Risks and Issues – Generation – Natural Gas..........................14-16
Table 14-4 Resource Specific Risks and Issues – Generation – Coal......................................14-18
Table 14-5 Resource Specific Risks and Issues – Generation – Modular Nuclear..................14-19
Table 14-6 Resource Specific Risks and Issues – Generation – Large Hydro.........................14-20
Table 14-7 Resource Specific Risks and Issues – Generation – Small Hydro.........................14-21
Table 14-8 Resource Specific Risks and Issues – Generation – Wind ....................................14-22
Table 14-9 Resource Specific Risks and Issues – Generation – Geothermal ..........................14-23
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-10 February 2010
Table of Contents (Continued)
Tables (Continued)
Table 14-10 Resource Specific Risks and Issues – Generation – Solid Waste..........................14-24
Table 14-11 Resource Specific Risks and Issues – Generation – Tidal.....................................14-25
Table 14-12 Resource Specific Risks and Issues – Transmission..............................................14-27
Table 15-1 Resources Selected in Scenario 1A/1B Resource Plan............................................15-8
Table 15-2 Impact of Selected Issues on the Preferred Resource Plan......................................15-9
Table 15-3 Projects Significantly Under Development ...........................................................15-10
Table 16-1 Near-Term Implementation Action Plan – General Actions...................................16-1
Table 16-2 Near-Term Implementation Action Plan – Capital Projects....................................16-3
Table 16-3 Near-Term Implementation Action Plan – Supporting Studies and Activities........16-4
Table 16-4 Near-Term Implementation Action Plan – Other Actions.......................................16-5
Figures
Figure 1-1 Evaluation Scenarios..................................................................................................1-7
Figure 1-2 Comparison of Project Cost Versus Installed Capacity...........................................1-11
Figure 1-3 Impact of DSM/EE Resources – Base Case Load Forecast.....................................1-14
Figure 1-4 Results – Scenarios 1A/1B Reference Cases...........................................................1-15
Figure 1-5 Results – Scenario 2A Reference Case....................................................................1-15
Figure 1-6 Results – Scenario 2B Reference Case....................................................................1-15
Figure 1-7 Location of Proposed Transmission Projects (Without Susitna).............................1-20
Figure 1-8 Required Cumulative Capital Investment for Each Base Case................................1-23
Figure 1-9 Required Cumulative Capital Investment (Scenarios 1A/1B) Relative to
Railbelt Utility Debt Capacity .................................................................................1-24
Figure 1-10 Cumulative Present Value Cost – Selected Reference and Sensitivity Cases.........1-30
Figure 1-11 Annual Wholesale Power Cost – Selected Reference and Sensitivity Cases..........1-30
Figure 1-12 Comparison of Results - Scenario 1A/1B Versus Committed Units
Sensitivity Case........................................................................................................1-32
Figure 1-13 Interplay Between GRETC and Regional Integrated Resource Plan.......................1-33
Figure 2-1 Project Approach Overview.......................................................................................2-3
Figure 2-2 Evaluation Scenarios..................................................................................................2-7
Figure 2-3 Elements of Stakeholder Involvement Process..........................................................2-8
Figure 3-1 Summary of Issues Facing the Railbelt Region.........................................................3-1
Figure 3-2 Chugach’s Reliance on Natural Gas..........................................................................3-8
Figure 3-3 Overview of Cook Inlet Gas Situation.......................................................................3-8
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-11 February 2010
Table of Contents (Continued)
Figures (Continued)
Figure 3-4 Historical Chugach Natural Gas Prices Paid .............................................................3-9
Figure 3-5 Chugach Residential Bills Based on 700 kWh Consumption....................................3-9
Figure 4-1 Railbelt Existing Transmission System as Modeled..................................................4-9
Figure 6-1 US Daily Driving Patterns.........................................................................................6-6
Figure 6-2 PHEV Daily Charging Availability Profile...............................................................6-6
Figure 6-3 Hourly Distribution of PHEV Load on a Typical Day – Alaska Railbelt
Region........................................................................................................................6-8
Figure 6-4 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt
System’s Energy Requirement...................................................................................6-8
Figure 6-5 Impact of a High PHEV Penetration Scenario Over the Alaska Railbelt
System’s Peak Demand..............................................................................................6-9
Figure 7-1 Results of a Risk-Based Gas Supply Model Simulation for the Year 2017..............7-2
Figure 7-2 Schematic Summary of the Probabilistic Gas Supply Forecast Model.....................7-3
Figure 7-3 Comparison of Natural Gas Price Forecasts Relevant to Railbelt Resource
Plans...........................................................................................................................7-8
Figure 9-1 Scenario 1A Capacity Requirements Without DSM/EE ...........................................9-2
Figure 9-2 Scenario 1A Capacity Requirements With DSM/EE.................................................9-3
Figure 9-3 Scenario 2A Capacity Requirements Without DSM/EE ...........................................9-4
Figure 9-4 Scenario 2A Capacity Requirements With DSM/EE.................................................9-5
Figure 9-5 Scenario 1A Capacity Requirements Including Committed Units Without
DSM/EE.....................................................................................................................9-6
Figure 9-6 Scenario 1A Capacity Requirements Including Committed Units With
DSM/EE.....................................................................................................................9-7
Figure 10-1 Proposed Susitna Hydro Project Location (Source: HDR)...................................10-19
Figure 10-2 Comparison of Project Cost Versus Installed Capacity.........................................10-22
Figure 10-3 Proposed Chakachamna Hydro Project Location (Source: TDX)........................10-24
Figure 10-4 Blue Energy’s Tidal Bridge With Davis Turbine (Source: Blue Energy).............10-28
Figure 10-5 Cutaway Graphic of a Mid-Range-Scale Vertical Axis Tidal Turbine
(Source: Blue Energy)...........................................................................................10-29
Figure 10-6 Proposed Layout of the Turnagain Arm Tidal Project (Source: Little Susitna
Construction Co. and Blue Energy of Canada)......................................................10-30
Figure 10-7 Turnagain Arm Tidal Project Monthly Generation ...............................................10-31
Figure 10-8 Simplified Binary Geothermal Power Plant Process (Source: Ormat).................10-33
Figure 10-9 Simplified Geothermal Combined Cycle Power Plant Process (Source:
Ormat)....................................................................................................................10-33
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-12 February 2010
Table of Contents (Continued)
Figures (Continued)
Figure 10-10 Estimated Mount Spurr Project Development Plan (Source: Ormat)...................10-35
Figure 10-11 Visual Simulation of Fire Island Wind Generation Project (Source:
CIRI/enXco Joint Venture)....................................................................................10-37
Figure 10-12 Preliminary Site Arrangement and Interconnection Route (Source:
CIRI/enXco Joint Venture)....................................................................................10-38
Figure 10-13 Kenai Peninsula, Nikiski (Source: Kenai Winds LLC)........................................10-39
Figure 10-14 Simplified Hyperion Power Cycle Diagram (Source: Hyperion Power
Generation) ............................................................................................................10-41
Figure 10-15 Requested Potential Advanced Reactor Licensing Application Timelines
(Source: NRC February 20, 2008 Briefing Presentation Slide)............................10-43
Figure 10-16 NRC New Licensing Process and Construction Timelines for New Reactors
(Source: NEI website)...........................................................................................10-44
Figure 11-1 Common DSM/EE Program Development Process ................................................11-7
Figure 11-2 EPRI/EEI Assessment: West Census Region Results .............................................11-9
Figure 12-1 Railbelt Transmission System Overview.................................................................12-2
Figure 12-2 Bernice Lake Power Plant to International 230 kV Transmission Line (New
Build).......................................................................................................................12-7
Figure 12-3 Soldotna to Quartz Creek 230kV Transmission Line (Repair and
Replacement)...........................................................................................................12-8
Figure 12-4 Quartz Creek to University 230kV Transmission Line (Repair and
Replacement)...........................................................................................................12-9
Figure 12-5 Douglas to Teeland 230 kV Transmission Line (Repair and Replacement) .........12-10
Figure 12-6 Lake Lorraine to Douglas 230 kV Transmission Line (New Build) .....................12-12
Figure 12-7 Douglas to Healy 230 kV Transmission Line (Upgrade)......................................12-13
Figure 12-8 Douglas to Healy 230 kV Transmission Line (New Build)...................................12-14
Figure 12-9 Eklutna to Fossil Creek 230 kV Transmission Line (Upgrade).............................12-15
Figure 12-10 Healy to Gold Hill 230 kV Transmission Line (Repair and Replacement)...........12-16
Figure 12-11 Healy to Wilson 230 kV Transmission Line (Upgrade)........................................12-17
Figure 12-12 Soldotna to Diamond Ridge 115 kV Transmission Line (Repair and
Replacement).........................................................................................................12-18
Figure 12-13 Lawing to Seward 115 kV Transmission Line (Upgrade).....................................12-19
Figure 12-14 Eklutna to Lucas 230 kV Transmission Line (Repair and Replacement)..............12-20
Figure 12-15 Lucas to Teeland 230 kV Transmission Line (Repair and Replacement).............12-21
Figure 12-16 Fossil Creek to Plant 2 230 kV Transmission Line (Upgrade)..............................12-22
Figure 12-17 Pt. Mackenzie to Plant 2 230 kV Transmission Line (Repair and
Replacement).........................................................................................................12-23
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-13 February 2010
Table of Contents (Continued)
Figures (Continued)
Figure 12-18 Bernice Lake to Soldotna 115 kV Transmission Line (Rebuild)...........................12-24
Figure 12-19 Bernice Lake to Beaver Creek to Soldotna 115 kV Transmission Line
(Rebuild)................................................................................................................12-25
Figure 12-20 Susitna to Gold Creek 230 kV Transmission Line................................................12-26
Figure 12-21 Location of Proposed Transmission Projects (Without Susitna)...........................12-28
Figure 12-22 Location of Proposed Transmission Projects (With Susitna)................................12-29
Figure 13-1 Impact of DSM/EE Resources – Base Case Load Forecast.....................................13-2
Figure 13-2 Results – Scenarios 1A/1B Reference Cases...........................................................13-2
Figure 13-3 Results – Scenario 2A Reference Case....................................................................13-3
Figure 13-4 Results – Scenario 2B Reference Case....................................................................13-3
Figure 13-5 Sensitivity Results – Scenarios 1A/1B Without DSM/EE Measures......................13-4
Figure 13-6 Sensitivity Results – Scenarios 1A/1B With Double DSM/EE Measures...............13-4
Figure 13-7 Sensitivity Results – Scenarios 1A/1B With Committed Units Included................13-5
Figure 13-8 Sensitivity Results – Scenarios 1A/1B Without CO2 Costs ....................................13-5
Figure 13-9 Sensitivity Results – Scenarios 1A/1B With Higher Gas Prices.............................13-6
Figure 13-10 Sensitivity Results – Scenarios 1A/1B Without Chakachamna...............................13-6
Figure 13-11 Sensitivity Results – Scenarios 1A/1B With Susitna (Lower Low Watana
Non-Expandable Option) Forced.............................................................................13-7
Figure 13-12 Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana Non-
Expandable Option) Forced.....................................................................................13-7
Figure 13-13 Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana
Expansion Option) Forced.......................................................................................13-8
Figure 13-14 Sensitivity Results – Scenarios 1A/1B With Susitna (Watana Option) Forced.......13-8
Figure 13-15 Sensitivity Results – Scenarios 1A/1B With Susitna (High Devil Canyon
Option) Forced.........................................................................................................13-9
Figure 13-16 Sensitivity Results – Scenarios 1A/1B With Modular Nuclear...............................13-9
Figure 13-17 Sensitivity Results – Scenarios 1A/1B With Tidal................................................13-10
Figure 13-18 Sensitivity Results – Scenarios 1A/1B With Lower Coal Capital and Fuel
Costs.......................................................................................................................13-10
Figure 13-19 Sensitivity Results – Scenarios 1A/1B With Federal Tax Credits for
Renewables............................................................................................................13-10
Figure 13-20 Required Cumulative Capital Investment for Each Reference Case.....................13-16
Figure 13-21 Required Cumulative Capital Investment (Scenarios 1A/1B) Relative to
Railbelt Utility Debt Capacity ...............................................................................13-17
TABLE OF CONTENTS
ALASKA RIRP STUDY
Black & Veatch TC-14 February 2010
Table of Contents (Continued)
Figures (Continued)
Figure 15-1 Cumulative Present Value Cost – Selected Reference and Sensitivity Cases.........15-3
Figure 15-2 Annual Wholesale Power Cost – Selected Reference and Sensitivity Cases..........15-3
Figure 15-3 Comparison of Results - Scenario 1A/1B Versus Committed Units
Sensitivity Case........................................................................................................15-5
Figure 15-4 Interplay Between GRETC and Regional Integrated Resource Plan.......................15-6
ACRONYM LIST
ALASKA RIRP STUDY
Black & Veatch AL-1 February 2010
ACEEE American Council for an Energy Efficiency Economy
ACESA American Clean Energy and Security Act of 2009
AEA Alaska Energy Authority
AHFC Alaska Housing Finance Corporation
AIDEA Alaska Industrial Development and Export Authority
APA Alaska Power Authority
ARRA American Recovery and Reinvestment Act of 2009
Bcf Billion cubic feet
BESS Battery energy storage system
CCS Carbon capture and sequestration
CFL Compact fluorescent light
C/I Commercial and industrial
CO2 Carbon dioxide
COLA Construction and operation license application
CTG Combustion turbine generator
CWIP Construction-work-in-progress
DPP Delta Power Plant
DR Demand response
DSM/EE Demand-side management/energy efficiency
EEI Edison Electric Institute
EIA Energy Information Administration
EPA Environmental Protection Agency
EPRI Electric Power Research Institute
EPS Electric Power Systems, Inc.
FERC Federal Energy Regulatory Commission
FGD Flue gas desulfurization
GE General Electric
GHG Greenhouse gas
GRETC Greater Railbelt Energy & Transmission Company
G&T Generation and transmission
GVEA Golden Valley Electric Association
HAGO High atmospheric gas oil
HCCP Healy Clean Coal Project
HDR HDR, Inc.
HEA Homer Electric Association
HHV Higher heating value
HPC High-pressure compressor
HPT High-pressure turbine
HSRG Heat recovery steam generators
Hz Hertz
IP Intermediate-pressure
IPP Independent power producers
ACRONYM LIST
ALASKA RIRP STUDY
Black & Veatch AL-2 February 2010
IRS Interconnection requirements studies
JV Joint venture
kV Kilovolt
KW Kilowatt
kWh Kilowatt-hour
LEEP Lighting Energy Efficiency Pledge
LNG Liquefied natural gas
LP Low-pressure
LPT Low-pressure turbine
MEA Matanuska Electric Association
ML&P Anchorage Municipal Light & Power
MMBtu Million British thermal units
MMcf/d Million cubic feet per day
MSW Municipal solid waste
MW Megawatt
NOx Nitrogen oxides
OEM Original equipment manufacturer
O&M Operations and maintenance
PC Pulverized coal
PHEV Plug-in hybrid vehicles
PPA Power purchase agreement
PPM Part per million
REC Renewable energy credits
REGA Railbelt Electrical Grid Authority
RIRP Railbelt Integrated Resource Plan
ROW Right-of-way
RPM Revolutions per minute
RPS Renewable portfolio standard
SBC System benefit charge
SCR Selective catalytic reduction
SES City of Seward Electric System
SILOS Shed in lieu of spin
SNW Seattle-Northwest Securities Corporation
SOx Sodium oxides
SVC Static var compensators
TOU Time-of-use
ULSD Ultra-low sulfur diesel
USDA-RUS United States Department of Agriculture/Rural Utilities Service
WGA Western Governor’s Association
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-1 February 2010
1.0 EXECUTIVE SUMMARY
In response to a directive from the Alaska Legislature, the Alaska Energy Authority (AEA) was the lead State
agency for the development of a Regional Integrated Resource Plan (RIRP) for the Railbelt Region. This
region is defined as the service areas of six regulated public utilities, including: Anchorage Municipal Light &
Power (ML&P), Chugach Electric Association (Chugach), Golden Valley Electric Association (GVEA),
Homer Electric Association (HEA), Matanuska Electric Association (MEA), and the City of Seward Electric
System (SES). A seventh utility, Doyon, is interconnected to the Railbelt system serving the military bases of
Fort Greely, Fort Wainwright, and Fort Richardson, but is not included in this RIRP.
The purpose of this document is to provide the results of the RIRP study. This section includes the following
subsections:
• Current Situation Facing the Railbelt Utilities
• Project Overview
• Evaluation Scenarios
• Summary of Key Input Assumptions
• Susitna Analysis
• Transmission Analysis
• Summary of Results
• Implementation Risks and Issues
• Conclusions and Recommendations
• Near-Term Implementation Plan (2010-2012)
1.1 Current Situation Facing the Railbelt Utilities
The Railbelt generation, transmission, and distribution infrastructure did not exist prior to the 1940s. At that
time, citizens in separate areas within the Railbelt region joined together to form four cooperatives (Chugach,
GVEA, HEA, and MEA) and two municipal utilities (ML&P and SES) to provide electric power to the
consumers and businesses within their service areas. Collectively, these utilities are referred to as the Railbelt
utilities.
Some Definitions
• REGA means “Railbelt Electrical
Grid Authority”
• GRETC means “Greater Railbelt
Energy & Transmission Company”
• RIRP means “Railbelt Integrated
Resource Plan”
Three Discrete Tasks
• REGA study determined the business structure
for future Railbelt generation and transmission
(G&T)
• GRETC initiative is the joint effort between
Railbelt Utilities and AEA to unify Railbelt G&T
• RIRP is the economic plan for future capital
investment in G&T and in fuel portfolios that
GRETC would build, own and operate
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-2 February 2010
The independent and cooperative decisions made over time by utility managers and Boards, as well as the
State, in a number of areas have significantly improved the quality of life and business environment in the
Railbelt. Examples include:
• Infrastructure Investments – the State and the Railbelt utilities have made significant investments
in the region’s generation and transmission infrastructure. Examples include the Alaska Intertie and
Bradley Lake Hydroelectric Plant.
• Gas Supply Investments and Contracts – ML&P took a bold step when it purchased a portion of
the Beluga River Gas Field, a decision that has produced a significant long-term benefit for ML&P’s
customers and others within the Railbelt. Additionally, Chugach was able to enter into attractive gas
supply contracts. These decisions have resulted in historical low gas prices which have significantly
offset the region’s inability to achieve economies of scale in generation due to its small size.
• Innovative Solutions – GVEA’s Battery Energy Storage System (BESS) is one example of
numerous innovative decisions that have been made by utility managers and Boards to address issues
that are unique to the Railbelt region.
• Joint Operations and Contractual Arrangements – over the years, the Railbelt utilities have joined
together for joint benefit in terms of coordinated operation of the Railbelt transmission grid and have
entered into contractual arrangements that have benefited each utility.
The evolution of the business and operating environment, and changes in the mix of
stakeholders, presents new dynamics for the way decisions must be made. This
changing environment poses significant challenges for the Railbelt utilities and, indeed,
all stakeholders. In fact, it is not an overstatement to say that the Railbelt is at a
historical crossroad, not unlike the period of time when the Railbelt utilities were
originally formed.
Categories of issues facing the Railbelt utilities include:
• Uniqueness of the Railbelt region
• Cost issues
• Natural gas issues
• Load uncertainties
• Infrastructure issues
• Future resource options
• Political issues
• Risk management issues
Table 1-1 provides a listing of the issues within each of these categories. A detailed discussion of these issues
is provided in Section 3.
Current
Situation
• Limited redundancy
• Limited economies
of scale
• Dependence on
fossil fuels
• Limited Cook Inlet
gas deliverability
and storage
•Aging G&T
infrastructure
• Inefficient fuel use
• Difficult financing
• Duplicative G&T
expertise
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-3 February 2010
Table 1-1
Summary Listing of Issues Facing the Railbelt Region
Uniqueness of the Railbelt Region
• Size and geographic expanse
• Limited interconnections and
redundancies
Load Uncertainties
• Stable native growth
• Potential major new loads
Political Issues
• Historical dependence on
State funding
• Proper role for State
Cost Issues
• Relative costs – Railbelt region
versus other states
• Relative costs – among Railbelt
utilities
• Economies of scale
Infrastructure Issues
• Aging generation
infrastructure
• Baseload usage of inefficient
generation facilities
• Operating and spinning
reserve requirements
Risk Management Issues
• Need to maintain flexibility
• Future fuel diversity
• Aging infrastructure
• Ability to spread regional
risks
Natural Gas Issues
• Historical dependence
• Expiring contracts
• Declining developed reserves
and deliverability
• Historical increase in gas prices
• Potential gas supplies and prices
Future Resource Options
• Acceptability of large hydro
and coal
• Carbon tax and other
environmental restrictions
• Optimal size and location of
new generation and
transmission facilities
• Limited development –
renewables
• Limited development –
demand-side
management/energy
efficiency (DSM/EE)
programs
1.2 Project Overview
The goal of this project is to minimize future power supply costs, and
maintain or improve on current levels of power supply reliability,
through the development of a single comprehensive RIRP for the
Railbelt region. The intent of the RIRP project, as stated in the AEA
request-for-proposal, is to provide:
• An up-to-date model that the utilities and AEA can use as a
common database and model for future planning studies and
analysis.
• An assessment of loads and demands for the Railbelt electrical
grid for a time horizon of 50 years including new potential
industrial demands.
• Projections for Railbelt electrical capacity and energy growth, fuel prices, and resource options.
• An analysis of the range of potential generation resources available, including costs, construction
schedule, and long-term operating costs.
RIRP Objective Function
Minimize regional power
supply costs, and maintain or
improve current reliability, as
opposed to minimizing power
supply costs for any individual
utility.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-4 February 2010
• A schedule for existing generating unit retirement, new generation construction, and construction of
backbone transmission lines that will allow the future Railbelt electrical grid to operate reliably under
a transmission tariff which allows access by all potential power producers, and with a postage-stamp
rate for electric energy and demand for the entire Railbelt as a whole.
• A long-term schedule for developing new fuel supplies that will provide for reliable, stable priced
electrical energy for a 50-year planning
horizon.
• A short-term schedule that coordinates
immediate network needs (i.e., increasing
penetration level of non-dispatchable
generation, such as wind) within the first 10
years of the planning horizon, consistent
with the long-term goals.
• A short-term plan addressing the transition
from the present decentralized ownership
and control to a unified G&T entity that
identifies unified actions between utilities
that must occur during this transition period.
• A diverse portfolio of power supply that
includes, in appropriate portions, renewable
and alternative energy projects and fossil
fuel projects, some or all of which could be
provided by independent power producers
(IPPs).
• A comprehensive list of current and future
generation and transmission power infrastructure projects.
The alternative resource options considered in the RIRP analysis are shown in Table 1-2.
Black & Veatch conducted the REGA study for the AEA and the final report was released in September 2008.
That study evaluated the feasibility of the Railbelt utilities forming an organization to provide coordinated
unit commitment and economic dispatch of the region’s generation resources, generation and transmission
system planning, and project development. As a result of that study, legislation was proposed to create
GRETC with a 10-year transition period to achieve these goals. This RIRP is based on the GRETC concept
being implemented from the beginning of the study’s time horizon.
Black & Veatch had primary responsibility for conducting this Railbelt RIRP. In addition to Black & Veatch,
three other AEA contractors (HDR Inc., Electric Power Systems, Inc., and Seattle-Northwest Securities
Corporation) played important roles in the development of the RIRP.
HDR updated work from the mid-1980s on the Susitna Hydroelectric Project and developed the capital and
operating costs, as well as the generating characteristics, for several smaller-sized Susitna projects. HDR’s
work was used by Black & Veatch in the Strategist® and PROMOD® modeling discussed below. HDR’s
report summarizing the results of its work is provided in Appendix A.
Electric Power Systems, Inc. (EPS) assisted in the evaluation of the region’s transmission system.
Current
Situation
• Limited redundancy
• Limited economies
of scale
• Dependence on
fossil fuels
• Limited Cook Inlet
gas deliverability
and storage
•Aging G&T
infrastructure
• Inefficient fuel use
• Difficult financing
• Duplicative G&T
expertise
RIRP Study
• Plan that economically
schedules what, when,
and where to build, based
on available fuel and
energy supplies
• 50-year time horizon
• Competes generation,
transmission, fuel supply
and DSM/energy
efficiency options
•Considers CO2regulation
• Includes renewable
energy projects
• Arrives at a plan to build
future infrastructure for
minimum long-run cost to
ratepayers
• Considers fuel supply
options and risks
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-5 February 2010
Table 1-2
Alternative Resource Options Considered
Demand-Side Management/Energy
Efficiency (DSM/EE) Measure
Categories Conventional Generation Resources Renewable Resources
Residential Simple Cycle Combustion Turbines Hydroelectric Projects
• Appliances • LM6000 (48 MW) • Susitna
• Water Heating • LMS100 (96 MW) • Chakachamna
• Lighting Combined Cycle • Glacier Fork
• Shell • 1x1 6FA (154 MW) • Generic Hydro – Kenai
• Cooling/Heating • 2X1 6FA (310 MW) • Generic Hydro - MEA
Commercial Coal Units Wind
• Water Heating • Healy Clean Coal • BQ Energy/Nikiski
• Office Loads • Generic – 130 MW • Fire Island
• Motors • Generic Wind – Kenai
• Lighting • Generic Wind - GVEA
• Refrigeration Geothermal
• Cooling/Heating • Mt. Spurr
Municipal Solid Waste
• Generic – Anchorage
• Generic - GVEA
Other Resources Included in Sensitivity Cases
• Modular Nuclear
• Tidal
Seattle-Northwest Securities Corporation (SNW) developed the financial model used to determine the overall
financing costs for the portfolio of generation and transmission projects developed as part of this project, and
evaluated the impact of some financial options that could be used to address financing issues and mitigating
related rate impacts. The results of SNW’s analysis are provided in Appendix B.
Additional information regarding Black & Veatch’s approach to the completion of this study is provided in
Section 2.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-6 February 2010
Purpose and Limitations of the RIRP
• The development of this RIRP is not the same as the development of a State Energy Plan; nor does it set State
policy. Setting energy-related policies is the role of the Governor and State Legislature. With regard to energy
policy making, however, the RIRP does provide a foundation of information and analysis that can be used by
policy makers to develop important policies.
Having said this, the development of a State Energy Policy and or related policies could directly impact the
specific alternative resource plan chosen for the Railbelt region’s future. As such, the RIRP may need to be
readdressed as future energy-related policies are enacted.
• This RIRP, consistent with all integrated resource plans, should be viewed as a “directional” plan. In this
sense, the RIRP identifies alternative resource paths that the region can take to meet the future electric needs
of Railbelt citizens and businesses; in other words, it identifies the types of resources that should be developed
in the future. The granularity of the analysis underlying the RIRP is not sufficient to identify the optimal
configuration (e.g., specific size, manufacturer, model, location, etc.) of specific resources that should be
developed. The selection of specific resources requires additional and more detailed analysis.
• The alternative resource options considered in this study include a combination of identified projects (e.g.,
Susitna and Chakachamna hydroelectric projects, Mt. Spurr geothermal project, etc.), as well as generic
resources (e.g., Generic Hydro – Kenai, Generic Wind – GVEA, generic conventional generation alternatives,
etc.). Identified projects are included, and shown as such, because they are projects that are currently at
various points in the project development lifecycle. Consequently, there is specific capital cost and operating
assumptions available on these projects. Generic resources are included to enable the RIRP models to choose
various resource types, based on capital cost and operating assumptions developed by Black & Veatch. This
approach is common in the development of integrated resource plans.
Consistent with the comment above regarding the RIRP being a “directional” plan, the actual resources
developed in the future, while consistent with the resource type identified, may be: 1) the identified project
shown in the resource plan (e.g., Chakachamna), 2) an alternative identified project of the same resource type
(e.g., Susitna); or 3) an alternative generic project of the same resource type. One reason for this is the level of
risks and uncertainties that exist regarding the ability to plan, permit, and develop each project. Consequently,
when looking at the resource plans shown in this report, it is important to focus on the resource type of an
identified resource, as opposed to the specific project.
• The capital costs and operating assumptions used in this study for alternative DSM/EE, generation and
transmission resources do not consider the actual owner or developer of these resources. Ownership could be
in the form of individual Railbelt utilities, a regional entity, or an independent power producer (IPP).
Depending upon specific circumstances, ownership and development by IPPs may be the least-cost
alternative.
• As with all integrated resource plans, this RIRP should be periodically updated (e.g., every three years) to
identify changes that should be made to the preferred resource plan to reflect changing circumstances
(e.g., resolution of uncertainties), improved cost and performance of emerging technologies (e.g., tidal), and
other developments.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-7 February 2010
1.3 Evaluation Scenarios
Black & Veatch, in collaboration with the Advisory Working Group that was assembled by the AEA for this
project, developed four Evaluation Scenarios; Black & Veatch then developed a 50-year resource plan for
each of these Evaluation Scenarios.
The primary objective of these Evaluation Scenarios was to evaluate two key drivers. The first driver was to
look at what the impacts would be if the demand in the region was significantly greater than it is today; of
primary interest was to see if higher demands would result in greater reliance on large generation resource
options and allow for more aggressive expansion of the region’s transmission network.
The second driver was to determine the impact associated with the pursuit of a significant amount of
renewable resources over the 50-year time horizon.
As a result, Black & Veatch evaluated the four Evaluation Scenarios shown in Figure 1-1.
Figure 1-1
Evaluation Scenarios
The key assumptions underlying each Evaluation Scenario include:
• Scenario 1 – Base Case Load Forecast
o Current regional loads with projected growth
o All available resources – fossil fuel, renewables, and DSM/EE
o Probabilistic estimate of gas supply availability and prices
o Deterministic price forecasts for other fossil fuels
o Emissions including CO2 costs
o Transmission system investments required to support selected resources
o Scenario 1A – Least Cost Plan
o Scenario 1B – Force 50% Renewables
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-8 February 2010
• Scenario 2 – Large Growth Load Forecast
o Significant growth in regional loads due to economic development efforts or large scale
electrification (e.g., economic development loads, space and water heating fuel switching, and
electric vehicles)
o Base case resources, fuel availability/price forecasts and CO2 costs
o Transmission system investments required to support selected resources
o Scenario 2A – Least Cost Plan
o Scenario 2B – Force 50% Renewables
1.4 Summary of Key Input Assumptions
The completion of this RIRP required the development of a large number of assumptions in the following
categories:
• Section 4 – Description of Existing System, including information on existing generation resources,
committed generation resources, and the existing Railbelt transmission network.
• Section 5 – Economic Parameters, including inflation rates, financing rates, present worth discount
rate, interest during construction rate, and fixed charge rates.
• Section 6 – Forecast of Electrical Demand and Consumption, including 50-year peak demand
forecasts and net energy for load requirements.
• Section 7 – Fuel and Emissions Allowance Price Projections, including price forecasts for various
fuels and emission allowance price projections.
• Section 8 – Reliability Criteria, including the region’s planning and operating reserve margin
requirements.
• Section 9 – Capacity Requirements, including the region’s capacity requirements over the 50-year
planning horizon.
• Section 10 – Supply-Side Options, including an overview of the supply-side resource option input
assumptions used in this study, including both conventional technologies and renewable energy
options.
• Section 11 – DSM/EE Resources, including a summary of the methodology and assumptions that
Black & Veatch used to evaluate potential DSM/EE measures.
• Section 12 – Transmission Projects, including an overview of the transmission projects required to
improve the overall reliability of the region’s transmission network and connect the generation
resources included in the alternative resource plans that were developed as part of this project.
1.5 Susitna Analysis
A hydroelectric project on the Susitna River has been studied for more than 50 years and is again being
considered by the State of Alaska as a long term source of energy. In the 1980s, the project was studied
extensively by the Alaska Power Authority (APA) and a license application was submitted to the Federal
Energy Regulatory Commission (FERC). Developing a workable financing plan proved difficult for a project
of this scale. When this existing difficulty was combined with the relatively low cost of gas-fired electricity in
the Railbelt and the declining price of oil throughout the 1980s, and its resulting impacts upon the State
budget, the APA terminated the project in March 1986.
In 2008, the Alaska State Legislature authorized the AEA to perform an update of the project. That
authorization also included this RIRP project to evaluate the ability of this project and other sources of energy
to meet the long term energy demand for the Railbelt region of Alaska. Of all the hydro projects in the
Railbelt region, the Susitna projects are the most advanced and best understood.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-9 February 2010
HDR was contracted by AEA to update the cost estimate, energy estimates and the project development
schedule for a Susitna River hydroelectric project. The initial alternatives reviewed were based upon the 1983
FERC license application and subsequent 1985 amendment which presented several project alternatives:
Watana. This alternative consists of the construction of a large storage reservoir on the Susitna River
at the Watana site with an 885-foot-high rock fill dam and a six-unit powerhouse with a total installed
capacity of 1,200 MW.
Low Watana Expandable. This alternative consists of the Watana dam constructed to a lower height
of 700 feet and a four-unit powerhouse with a total installed capacity of 600 MW. This alternative
contains provisions that would allow for future raising of the dam and expansion of the powerhouse.
Devil Canyon. This alternative consists of the construction of a 646-foot-high concrete dam at the
Devil Canyon site with a four-unit powerhouse with a total installed capacity of 680 MW.
Watana/Devil Canyon. This alternative consists of the full-height Watana development and the
Devil Canyon development as presented in the 1983 FERC license application. The two dams and
powerhouses would be constructed sequentially without delays. The combined Watana/Devil Canyon
development would have a total installed capacity of 1,880 MW.
Staged Watana/Devil Canyon. This alternative consists of the Watana development constructed in
stages and the Devil Canyon development as presented in the 1985 FERC amendment. In stage one
the Watana dam would be constructed to the lower height and the Watana powerhouse would only
have four out of the six turbine generators installed, but would be constructed to the full sized
powerhouse. In stage two the Devil Canyon dam and powerhouse would be constructed. In stage
three the Watana dam would be raised to its full height, the existing turbines upgraded for the higher
head, and the remaining two units installed. At completion, the project would have a total installed
capacity of 1,880 MW.
As the RIRP process defined the future Railbelt power requirement it became evident that lower cost
hydroelectric project alternatives, that were a closer fit to the energy needs of the Railbelt, should be sought.
As such, the following single dam configurations were also evaluated:
Low Watana Non-Expandable. This alternative consists of the Watana dam constructed to a height
of 700 feet, along with a powerhouse containing four turbines with a total installed capacity of
600 MW. This alternative has no provisions for future expansion.
Lower Low Watana. This alternative consists of the Watana dam constructed to a height of 650 feet
along with a powerhouse containing three turbines with a total installed capacity of 380 MW. This
alternative has no provisions for future expansion.
High Devil Canyon. This alternative consists of a roller-compacted concrete (RCC) dam constructed
to a height of 810 feet, along with a powerhouse containing four turbines with a total installed
capacity of 800 MW.
Watana RCC. This alternative consists of a RCC Watana dam constructed to a height of 885 feet,
along with a powerhouse containing six turbines with a total installed capacity of 1,200 MW.
The results of this study are summarized in Table 1-3 and a comparison of project size versus project cost is
shown in Figure 1-2.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-10 February 2010
Table 1-3
Susitna Summary
Alternative Dam Type
Dam
Height
(feet)
Ultimate
Capacity
(MW)
Firm
Capacity,
98%
(MW)
2008
Construction
Cost
($ Billion)
Energy
(GWh/yr)
Schedule
(Years from
Start of
Licensing)
Lower Low Watana Rockfill 650 380 170 $4.1 2,100 13-14
Low Watana Non-
expandable
Rockfill 700 600 245 $4.5 2,600 14-15
Low Watana
Expandable
Rockfill 700 600 245 $4.9 2,600 14-15
Watana Rockfill 885 1,200 380 $6.4 3,600 15-16
Watana RCC RCC 885 1,200 380 $6.6 3,600 15-16
Devil Canyon Concrete Arch 646 680 75 $3.6 2,700 14-15
High Devil Canyon RCC 810 800 345 $5.4 3,900 13-14
Watana/Devil
Canyon
Rockfill/Concr
ete Arch
885/646 1,880 710 $9.6 7,200 15-20
Staged
Watana/Devil
Canyon
Rockfill/Concr
ete Arch
885/646 1,880 710 $10.0 7,200 15-24
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-11 February 2010
Figure 1-2
Comparison of Project Cost Versus Installed Capacity
In all cases, the ability to store water increases the firm capacity over the winter. Projects developed with
dams in series allow the water to be used twice. However, because of their locations on the Susitna River, not
all projects can be combined. The Devil Canyon site precludes development of the High Devil Canyon site
but works well with Watana. The High Devil Canyon site precludes development of Watana but could
potentially be paired with other sites located further upstream.
The detailed results of the HDR Susitna study, except for the detailed appendices, are provided in
Appendix A. One of the appendices contained within the HDR report (Appendix D), which is not included in
Appendix A of this report, addresses the issue of the potential impact of climatic changes on Susitna’s
resource potential; this appendix can be viewed in the full HDR report which is available on the AEA web
site.
1.6 Transmission Analysis
An important element of this RIRP was the analysis of transmission investments required to integrate the
generation resources in each resource plan, ensure reliability and enable the region to take advantage of
economy energy transfers between load areas within the region.
The fundamental objective underlying the transmission analysis was to upgrade the transmission system over
a 10-year period to remove transmission constraints that currently prevent the coordinated operation of all the
utilities as a single entity.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-12 February 2010
The study included all assets 69 kV and above. These assets, over a transition period, may flow into GRETC
and form the basis for a phased upgrade of the system into a robust, reliable transmission system that can
accommodate the economic operation of the interconnected system. The transmission analysis also assumed
that all utilities would participate in GRETC with planning being conducted on a GRETC (i.e., regional)
basis. The common goal would be the tight integration of the system operated by GRETC.
Potential transmission investments in each of the following four categories were considered:
• Transmission systems that need to be replaced because of age and condition (Category 1)
• Transmission projects required to improve grid reliability, power transfer capability, and reserve
sharing (Category 2)
• Transmission projects required to connect new generation projects to the grid (Category 3)
• Transmission projects to upgrade the grid required by a new generation project (Category 4)
In developing the transmission system, reliability remains a significant focus. Redundancy is one way to
increase reliability, but may not be the only way to improve or maintain reliability.
The results of Black & Veatch’s transmission assessment are discussed later in this section.
1.7 Summary of Results
The purpose of this subsection
is to summarize the results of
the RIRP analysis. We begin
by providing a summary of
the base case results for each
of the four Evaluation
Scenarios. We then provide a
comparative summary of the
economic and emission results
for all base cases and
sensitivity cases. This is
followed by a summary of the
results of the transmission
analysis that was completed
and, finally, the results of the
financial analysis. More
detailed information regarding
the results of the RIRP study
is provided in Section 13.
Current
Situation
• Limited redundancy
• Limited economies
of scale
• Dependence on
fossil fuels
• Limited Cook Inlet
gas deliverability
and storage
•Aging G&T
infrastructure
• Inefficient fuel use
• Difficult financing
• Duplicative G&T
expertise
RIRP Study
• Plan that economically
schedules what, when,
and where to build, based
on available fuel and
energy supplies
• 50-year time horizon
• Competes generation,
transmission, fuel supply
and DSM/energy
efficiency options
•Considers CO2regulation
• Includes renewable
energy projects
• Arrives at a plan to build
future infrastructure for
minimum long-run cost to
ratepayers
• Considers fuel supply
options and risks
RIRP
Results
• Increased
DSM/energy
efficiency
• Increased
renewables
•Reduced
dependence
on natural gas
• Increased
transmission
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-13 February 2010
1.7.1 Results of Reference Cases
In this subsection, we provide summaries of the reference case results for each of the following four
Evaluation Scenarios:
• Scenario 1A – Base Case Load Forecast – Least Cost Plan
• Scenario 1B - Base Case Load Forecast – Force 50% Renewables
• Scenario 2A – Large Growth Load Forecast – Least Cost Plan
• Scenario 2B - Large Growth Load Forecast – Force 50% Renewables
Our analysis shows that Scenarios 1A and 1B result in the same resources and, consequently, the same costs
and emissions. In other words, the cost of achieving a renewable energy target of 50 percent by 2025
(Scenario 1B) is no greater than the cost of the unconstrained solution (Scenario 1A). This result applies only
if a large hydroelectric project is built. Hereafter, we will refer to Scenarios 1A and 1B together.
We begin with a summary of the impact that DSM/EE measures have on the region’s capacity and annual
energy requirements. This is followed by summary graphics and information for each of the Evaluation
Scenarios. Detailed model output for each of the reference cases are provided in Appendices E-G.
1.7.1.1 DSM/EE Resources
As discussed in Section 11, Black & Veatch screened a broad array of residential and commercial DSM/EE
measures. Based on this screening, 21 residential and 51 commercial DSM/EE measures were selected for
inclusion in the RIRP models, Strategist® and PROMOD®, as potential resources to be selected.
Based upon the relative economics and savings of these screened residential and commercial DSM/EE
measures, from the utility perspective, all of the residential and commercial DSM/EE measures were selected
in each of the four Evaluation Scenarios. As discussed in Section 11, the penetration of the measures was
based on technology adoption curves for DSM/EE studies from the BASS model; additionally, DSM/EE
measures are treated by Strategist® and PROMOD® as a reduction to the load forecast from which the
alternative supply-side options are considered for adding generation resources.
As can be seen in Figure 1-3, DSM/EE measures result in a significant impact on the region’s capacity and
energy requirements. After the initial program start-up years, DSM/EE measures reduce the region’s capacity
requirements by approximately 8 percent. A similar level of impact is also shown for annual energy
requirements.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-14 February 2010
Figure 1-3
Impact of DSM/EE Resources – Base Case Load Forecast
Demand (MW)
0
200
400
600
800
1,000
1,200
1,400
20112014201720202023202620292032203520382041204420472050205320562059YearDemand (MW)Without DSM/EE
With DSM/EE
Energy Requirements (MWh)
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
20112014201720202023202620292032203520382041204420472050205320562059YearEnergy Requirements (MWh)Without DSM/EE
With DSM/EE
It should be noted that this study did not include an evaluation of innovative rate designs (e.g., real-time
pricing and demand response rates), nor did it consider the potential benefits of a Smart Grid, and the
associated widespread implementation of smart meters. These options could result in even greater reductions
in peak demand and annual energy usage.
A Note Regarding DSM/EE Resources
• This RIRP demonstrates the economic potential of DSM/EE resources.
• Due to limited Alaska-specific DSM/EE-related data and experience, Black & Veatch limited the amount
of DSM/EE resources included in the preferred resource plan.
• Additional analysis, both by Black & Veatch as part of this study and by others, along with the experience
of other utilities throughout the US, suggest that additional levels of DSM/EE resources may be
economic.
• However, given the lack of Alaska-specific data and experience, additional data gathering and analysis is
required before the optimal level of DSM/EE resources can be determined.
• Furthermore, the isolated nature of the Railbelt coupled with severe weather conditions, dictates caution
with regard to the ultimate reliance on DSM/EE resources.
• Additionally, the limited penetration of electric space heating in the Railbelt region affects the ultimate
level of DSM/EE savings.
• To develop the full potential of DSM/EE resources, it will be necessary to collect baseline end-use
saturation, customer and vendor information, as well as address the reduction in utility margins that result
from the implementation of DSM/EE programs.
• Additionally, Black & Veatch believes that a regional approach to the development of DSM/EE programs
(e.g., GRETC) will be more successful than if the six Railbelt utilities develop independent DSM/EE
programs.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-15 February 2010
1.7.1.2 Results – Scenarios 1A/1B Reference Cases
Figure 1-4
Results – Scenarios 1A/1B Reference Cases
Capacity By Resource Type
0
200
400
600
800
1000
1200
1400
1600
1800
2000
20112014201720202023202620292032203520382041204420472050205320562059Capacity (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
1000
2000
3000
4000
5000
6000
7000
20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
1.7.1.3 Results – Scenario 2A Reference Case
Figure 1-5
Results – Scenario 2A Reference Case
Capacity By Resource Type
0
500
1000
1500
2000
2500
3000
3500
20112014201720202023202620292032203520382041204420472050205320562059Capacity (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
2000
4000
6000
8000
10000
12000
14000
2011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059Energy (GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
1.7.1.4 Results – Scenario 2B Reference Case
Figure 1-6
Results – Scenario 2B Reference Case
Capacity By Resource Type
0
500
1000
1500
2000
2500
3000
3500
2011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059CAPACITY (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
2000
4000
6000
8000
10000
12000
14000
2011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059ENERGY(GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-16 February 2010
1.7.2 Sensitivity Cases Evaluated
The following sensitivity cases were evaluated:
• Scenarios 1A/1B Without DSM/EE Measures
• Scenarios 1A/1B With Double DSM/EE Measures
• Scenarios 1A/1B With Committed Units Included
• Scenarios 1A/1B Without CO2 Costs
• Scenarios 1A/1B With Higher Gas Prices
• Scenarios 1A/1B Without Chakachamna
• Scenarios 1A/1B With Chakachamna Capital Costs Increased by 75%
• Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option) Forced
• Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option) Forced
• Scenarios 1A/1B With Susitna (Low Watana Expandable Option) Forced
• Scenarios 1A/1B With Susitna (Low Watana Expansion Option) Forced
• Scenarios 1A/1B With Susitna (Watana Option) Forced
• Scenarios 1A/1B With Susitna (High Devil Canyon Option) Forced
• Scenarios 1A/1B With Modular Nuclear
• Scenarios 1A/1B With Tidal
• Scenarios 1A/1B With Lower Coal Capital and Fuel Costs
• Scenarios 1A/1B With Federal Tax Credits for Renewables
1.7.3 Summary of Results – Economics and Emissions
In this subsection, we provide a comparative summary of the economic and emissions results for all of the
reference cases and sensitivity cases.
1.7.3.1 Summary of Results - Economics
Table 1-4 summarizes the economic results, including:
• Cumulative present value cost (from the utility perspective)
• Average wholesale power cost (from the utility perspective)
• Renewable energy in 2025
• Total capital investment
A Note Regarding Emerging Technologies
• In the economic analysis underlying this RIRP, Black & Veatch used current cost and performance
assumptions for all generation technology options considered. This was done because of the inherent
difficulty in predicting the future cost and performance of technologies, particularly emerging
technologies (e.g., on-shore and off-shore wind and tidal).
• Recent improvements in wind-related costs and performance demonstrate the potential for emerging
technologies. Conversely, the cost and performance of conventional resource technologies are stable at
best and not likely to improve.
• Further development of tidal power should be encouraged due to its resource potential in the Railbelt
region. Although this technology is not commercially available, in Black & Veatch’s opinion, at this point
in time, it has the potential to become economic within the planning horizon.
• These diverging cost and performance trends are one reason why this RIRP needs to be updated
periodically; by so doing, emerging technologies can be added to the region’s preferred resource plan as
their costs and performance improve.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-17 February 2010
Table 1-4
Summary of Results – Economics
Case
Cumulative
Present Value
Cost
($000,000)
Average
Wholesale
Power Cost
(¢ per kWh)
Renewable
Energy in
2025
(%)
Total Capital
Investment
($000,000)
Scenarios
Scenario 1A $13,625 17.26 62.32% $9,087
Scenario 1B $13,625 17.26 62.32% $9,087
Scenario 2A $20,162 19.75 42.64% $14,111
Scenario 2B $21,109 20.68 65.83% $18,805
Sensitivities
1A/1B Without DSM/EE Measures $14,507 17.40 67.10% $8,603
1A/1B With Double DSM $12,546 15.89 65.15% $8,861
1A/1B With Committed Units Included $14,109 17.87 46.84% $8,090
1A/1B Without CO2 Costs $11,206 14.20 49.07% $8,381
1A/1B With Higher Gas Prices $14,064 17.82 61.95% $9,248
1A/1B Without Chakachamna $14,332 18.16 38.06% $7,719
1A/1B With Chakachamna Capital Costs
Increased by 75%
$14,332 18.16 38.06% $7,719
1A/1B With Susitna (Lower Low Watana
Non-Expandable Option) Forced
$15,228 19.29 61.01% $12,421
1A/1B With Susitna (Low Watana Non-
Expandable Option) Forced
$15,040 19.05 63.01% $15,057
1A/1B With Susitna (Low Watana
Expandable Option) Forced
$15,346 19.44 63.01% $15,588
1A/1B With Susitna (Low Watana
Expansion Option) Forced
$14,854 18.82 66.90% $14,069
1A/1B With Susitna (Watana Option) Forced $15,683 19.87 70.97% $13,211
1A/1B With Susitna (High Devil Canyon
Option) Forced
$14,795 18.74 66.92% $11,633
1A/1B With Modular Nuclear $13,841 17.53 60.51% $9,105
1A/1B With Tidal $13,712 17.37 65.52% $9,679
1A/1B With Lower Coal Fuel and Lower
Coal Capital Costs
$13,625 17.26 62.32% $9,087
1A/1B With Tax Credits for Renewables $12,954 16.41 67.56% $9,256
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-18 February 2010
1.7.3.2 Summary of Results - Emissions
Table 1-5 summarizes the emissions-related results of all of the reference and sensitivity cases. The following
information is provided for each case:
• CO2 emissions
• NOx emissions
• SOx emissions
Table 1-5
Summary of Results – Emissions
Case
CO2
('000 tons)
NOx
('000 tons)
SO2
('000 tons)
Scenarios
Scenario 1A 80,259,047 124,215 21,768
Scenario 1B 80,259,047 124,215 21,768
Scenario 2A 152,318,066 133,642 24,476
Scenario 2B 125,498,202 140,897 26,348
Sensitivities
1A/1B Without DSM/EE Measures 88,181,350 139,179 30,605
1A/1B With Double DSM 69,324,920 131,299 18,994
1A/1B With Committed Units Included 91,212,598 136,946 16,482
1A/1B Without CO2 Costs 100,753,030 134,031 23,960
1A/1B With Higher Gas Prices 78,323,066 121,700 25,232
1A/1B Without Chakachamna 105,643,650 133,577 25,700
1A/1B With Chakachamna Capital Costs Increased by 75% 105,643,650 133,577 25,700
1A/1B With Susitna (Lower Low Watana Non-Expandable
Option) Forced
82,328,762 127,921 22,124
1A/1B With Susitna (Low Watana Non-Expandable Option)
Forced
69,133,553 124,640 19,620
1A/1B With Susitna (Low Watana Expandable Option) Forced 69,133,553 124,640 19,620
1A/1B With Susitna (Low Watana Expansion Option) Forced 67,724,563 136,906 23,589
1A/1B With Susitna (Watana Option) Forced 70,966,059 111,307 19,171
1A/1B With Susitna (High Devil Canyon Option) Forced 71,853,368 121,538 19,909
1A/1B With Modular Nuclear 79,664,701 126,881 22,787
1A/1B With Tidal 75,598,948 121,306 21,067
1A/1B With Lower Coal Fuel and Lower Coal Capital Costs 80,259,047 124,215 21,768
1A/1B With Tax Credits for Renewables 74,046,352 129,384 18,832
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-19 February 2010
1.7.4 Results of Transmission Analysis
Table 1-6 lists the proposed transmission system expansions and enhancements that resulted from our
transmission analysis. More detailed information on each of the identified transmission projects is provided
in Section 12.
Table 1-6
Summary of Proposed Transmission Projects
Project
No. Transmission Projects Type Cost ($000)
A Bernice Lake – International New Build (230 kV) 227,500
B Soldotna – Quartz Creek R&R (230 kV) 126,500
C Quartz Creek – University R&R (230 kV) 165,000
D Douglas – Teeland R&R (230 kV) 62,500
E Lake Lorraine – Douglas New Build (230 kV) 80,000
F Douglas – Healy Upgrade (230 kV) 30,000
G Douglas – Healy New Build (230 kV) 252,000
H Eklutna – Fossil Creek Upgrade (230 kV) 65,000
I Healy – Gold Hill R&R (230 kV) 180,500
J Healy – Wilson Upgrade (230 kV) 32,000
K Soldotna – Diamond Ridge R&R (115 kV) 66,000
L Lawing – Seward Upgrade (115 kV) 15,450
M Eklutna – Lucas R&R(115 kV/230 kV) 12,300
N Lucas – Teeland R&R (230 kV) 51,100
O Fossil Creek – Plant 2 Upgrade (230 kV) 13,650
P Pt. Mackenzie – Plant 2 R&R (230 kV) 32,400
Q Bernice Lake – Soldotna Rebuild (115 kV) 24,000
R Bernice Lake – Beaver Creek - Soldotna Rebuild (115 kV) 24,000
S Susitna Transmission Additions New Build (230 kV) 57,000
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-20 February 2010
A diagram that shows the location of the proposed transmission system enhancements is shown in Figure 1-7.
This graphic shows the proposed transmission projects if the Susitna hydroelectric project is not developed. A
similar graphic of proposed transmission projects if Susitna is built is provided in Section 12.
Figure 1-7
Location of Proposed Transmission Projects (Without Susitna)
The following issues result from our transmission analysis:
• We were unable to complete a stability analysis based upon our proposed transmission system
configuration prior to the completion of this project. This analysis is required to ensure that the
proposed transmission system expansions and enhancements result in the necessary stability to ensure
reliable electric service over the planning horizon. This analysis should be completed as part of the
future work to further define, prioritize, and design specific transmission projects.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-21 February 2010
• In addition to the transmission lines listed above, other projects were considered that could contribute
to improving the reliability of the Railbelt system. These projects generally fall into one or more of
the following categories:
o Providing reactive power (static var compensators – SVCs)
o Providing or assisting with the provision of other ancillary services (regulation and/or
spinning reserves)
o Assistance in control of line flows or substation voltages
o Assistance in the transition and coordination of transmission project implementation (mobile
transforms or substations)
o Communications and control facilities
Several of these projects have been identified and discussed while others will result from the
transmission reliability assessment. Potential projects in this category include:
o Substation capacitor banks
o Series capacitors
o SVCs
o Battery energy storage systems (BESS)
o Mobile substations that could provide construction flexibility during the implementation
phase
• Projects that could facilitate or complement the implementation of other projects (e.g., wind), were of
particular interest during project discussions. These projects, if implemented, could smooth the
transition and adoption by the utilities of the GRETC concept. One such project was the BESS that
could provide much needed frequency regulation and potentially some spinning reserves when
non-dispatchable projects, such as wind, are considered. A BESS was specified that could provide
frequency regulation required by the system when wind projects were selected by the RIRP. The
BESS was sized in relation to the size of the non-dispatchable project to be 50 percent of the project
nominal capacity for a 20-minute duration. Although the performance of the BESS has not yet been
analyzed as part of the stability analysis, the costs for each such system were included in the analysis.
Other options (e.g., fly wheel storage technologies and compressed air energy storage) that could
provide the required frequency regulation should also be considered.
• It should be noted that if the need for frequency regulation is driven in part by an IPP-sponsored
renewable project, policies will need to be adopted to allocate an appropriate portion of the regulation
costs to those projects.
• The Fire Island Wind Project is a 54 MW maximum output wind project. Each wind turbine will be
equipped with reactive power and voltage support capabilities that should facilitate interconnection
into the transmission grid. Current plans are to interconnect the project to the grid via a 34.5 kV
underground and submarine cable to the Chugach 34.5 kV Raspberry Substation. There has been
some discussions regarding the most appropriate transmission interconnection for the Fire Island
Project and detailed interconnection studies have not been completed. The timeframe for
implementing this project in order to qualify for available grants under the American Recovery and
Reinvestment Act of 2009 (ARRA) could preclude more detailed transmission studies and
consideration of alternatives to the currently proposed 34.5 kV interconnection. An option to
consider if Fire Island is constructed is to lay cables from Fire Island to Anchorage insulated for
230 kV and review a transmission routing for the new transmission connection to the Kenai peninsula
that would begin at the International 230 kV Substation to Bernice Lake Substation along the Kenai
cost line then via submarine cable across the Cook Inlet to Fire Island. The interconnection would
then use the 230 kV submarine cable previously laid over to the Anchorage coast then into the
International 230 kV Substation.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-22 February 2010
• The recommended transmission system expansions and enhancements can not be justified based
solely on economics. However, in addition to their underlying economics, these transmission projects
are required to ensure the reliable delivery of electricity throughout the region over the 50-year
planning horizon and to provide the foundation for future economic development efforts.
The proposed projects identified in Section 12 are not presented in any specific order or priority. It was felt
that the information currently available, as well as the uncertainty which exists surrounding the selected
generation plans, did not permit a more definitive prioritization of projects. This does not mean, however, that
all the projects in the list have the same impact on the reliability of the Railbelt system, or that the projects are
equally important to each utility. In several instances the projects were in extremely poor physical condition
and were scheduled to be repaired or rebuilt to prevent the lines from literally falling to the ground. To
facilitate the immediate repairs to these lines, the projects that should be addressed within the next five years
because of their potential impact on the reliability of the system have been identified. Additionally, some of
the projects will need to be evaluated and specified further and funds have been identified to facilitate the
studies that are required to further identify and schedule the transmission improvements that will be required.
The following projects and studies have been identified for priority attention (i.e., to be completed within the
next five years) because of their immediate impact on the reliability of the existing system. All of the projects
will require detailed system feasibility studies prior to actual implementation.
1. Soldotna to Quartz Creek Transmission Line ($126.5 million – Project B)
2. Quartz Creek to University Transmission Line ($165.0 million – Project C)
3. Douglas to Teeland Transmission Line ($62.5 million – Project D)
4. Lake Lorraine to Douglas Transmission Line ($80.0 million – Project E)
5. SVCs ($25.0 million - Other Reliability Projects)
6. Funds to undertake the study of the Southern Intertie ($1.0 million)
7. Funds to investigate the provision of regulation that will facilitate the integration of renewable energy
projects into the Railbelt system ($50.0 million, including cost of BESS – Other Reliability Projects)
The total estimate costs necessary for transmission projects during the initial five years of the RIRP is
$510 million in 2009 dollars.
1.7.5 Results of Financial Analysis
It will be difficult for the region to obtain the necessary financing for the DSM/EE, generation and
transmission resources included in the alternative resource plans that were developed. The formation of a
regional entity with some form of State assistance will help meet this challenge.
Figure 1-8 summarizes the cumulative capital investment required for each of the four base cases.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-23 February 2010
Figure 1-8
Required Cumulative Capital Investment for Each Base Case
Cumulative Capital Investment
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
$14,000,000
$16,000,000
$18,000,000
$20,000,000
2011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059YearCumulative Capital Investment ($000)Scenario 1A/1B
Scenario 2A
Scenario 2B
To assist in the completion of the financial analysis, AEA contracted with SNW to:
• Provide a high-level analysis of the capital funding capacity of each of the Railbelt utilities.
• Analyze strategies to capitalize selected RIRP assets by integrating State (which could include loans,
State appropriations, Permanent Fund, State moral obligation bonds, etc.) and federal
(e.g., USDA-RUS) financing resources with debt capital market resources.
• Develop a spreadsheet model that utilizes inputs from this RIRP analysis and overlays realistic debt
capital funding to provide a total cost to ratepayers of the optimal resource plan.
The results of the financial analysis completed by SNW are provided in Appendix B.
Important conclusions from SNW’s report include:
• The scope of the RIRP projects is too great, and for certain individual projects, it is reasonable to
conclude that there is no ability for a municipality or cooperative utility to independently secure debt
financing without committing substantial amounts of equity of cash reserves.
• Figure 1-9 helps to put into context the scope of the required RIRP capital investments relative to the
estimated combined debt capacity of the Railbelt utilities. The lines toward the bottom of the graph
represent SNW’s estimate of the bracketed range of additional debt capacity collectively for the
Railbelt utilities, adjusted for inflation and customer growth over time.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-24 February 2010
Figure 1-9
Required Cumulative Capital Investment (Scenarios 1A/1B) Relative to Railbelt Utility Debt Capacity
Source: SNW Report included in Appendix C.
• A regional entity, such as GRETC, with “all outputs” contracts migrating over time to “all
requirements” contracts will have greater access to capital than the combined capital capacity of the
individual utilities.
• There are several strategies that could be employed to lower the RIRP-related capital costs to
customers, including:
o Ratepayer Benefits Charge – A charge levied on all ratepayers within the Railbelt system that
would be used to cash fund and thereby defer borrowing for infrastructure capital.
o “Pay-Go” Versus Borrowing for Capital – A pay-go financing structure minimizes the total
cost of projects through the reduction in interest costs. A “pay-go” capital financing program is
one in which ongoing capital projects are paid for from remaining revenue after operations and
maintenance (O&M) expenses and debt service are paid for. A balance of these two funding
approaches appears to be the most effective in lowering the overall cost of the RIRP, as well as
spreading out the costs over a longer period of time.
o Construction Work in Progress (CWIP) – CWIP is a rate methodology that allows for the
recovery of interest expense on project construction expenditures through the base rate during
construction, rather than capitalizing the interest until the projects are on-line and generating
power. It should be noted that this rate methodology is sometimes criticized for shifting risks for
shareholders to ratepayers; however, in the case of a public cooperative or municipal utility, the
“shareholders” are the ratepayers.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-25 February 2010
o State Financial Assistance – State financial assistance could take a variety of forms as
previously noted; for the purposes of this project, SNW focused on State assistance structured
similarly to the Bradley Lake project. The benefits of State funding include: repayment
flexibility, credit support/risk mitigation, and potential interest cost benefit.
It should be noted that the economic comparison of resource options (using Strategist™ and
PROMOD™) does not assume any of these financing strategies, including any State grants
of Federal tax credits, with the exception of the Federal Tax Credits for Renewables
Sensitivity Case.
• The overall objective of SNW’s analysis was to identify ways to overcome the funding challenges
inherent with large-scale projects, including the length of construction time before the project is
online and access to capital markets, and to develop strategies that could be used to produce equitable
rates over the useful life of the assets being financed. With these challenges in mind, SNW developed
separate versions of its model to capture the cost of financing under a “base case” scenario and an
“alternative” scenario. The base case financing model was structured such that the list of RIRP
projects during the first 20 years would be financed through the capital markets in advance of
construction and that the cost of the financing in the form of debt service on the bonds would
immediately be passed through to the ratepayers; the projects being financed over the balance of the
50-year period would be financed through cash flow created through normal rates and charges
(“pay-go”), once debt service coverage from previous years has grown to levels that create cash flow
balance amounts sufficient to pay for the projects as their construction costs come due. The
alternative model was developed with the goal of minimizing the rate shock that may otherwise occur
with such a large capital plan, and levelizing the rate over time so that the economic burden derived
from these projects can be spread more equitably over the useful life of the projects being
contemplated.
• In both the base and alternative cases, SNW transferred the excess operating cash flow that is
generated to create the debt service coverage level, and using that balance to both partially fund the
capital projects in the early years and almost fully fund the projects in the later years. In the
alternative case, SNW also included: 1) a Capital Benefits Surcharge ($0.01 per kWH) over the first
17 years, when approximately 75 percent of the capital projects will have been constructed, and
2) State assistance as an equity participant, structured in a manner similar to the Bradley Lake
financing model (SNW assumed that the State would provide a $2.4 billion zero-interest loan to
GRETC to provide the upfront funding for the Chakachamna project, only to be paid back by GRETC
out of system revenues over an extended period of time, and following the repayment of the
potentially more expensive capital market debt).
• Under the base case, the maximum fixed charge rate on the capital portion alone is estimated to cost
$0.13 per kWH, while the average fixed charge rate over the 50-year period is $0.07 per kWh.
• In the alternative case, the maximum fixed charge rate on the capital portion alone is estimated to cost
$0.08 per kWH, while the average fixed charge rate over the 50-year period is $0.06 per kWh, not
including the $0.01 consumer benefit surcharge that is in place for the first 17 years.
• While the average rates between the two cases are essentially the same, the maximum rate in
the alternative case is much lower, showing the ability of innovative financing tools and
ratemaking methodologies to overcome the funding challenges and provide equitable rates over
the 50-year period.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-26 February 2010
• The formation of a regional entity, such as GRETC, that would combine the existing resources and
rate base of the Railbelt utilities, as well as provide an organized front in working to obtain private
financing and the necessary levels of State assistance, would be, in SNW’s opinion, a necessary next
step towards achieving the goal of reliable energy for the Railbelt region now and in the future.
1.8 Implementation Risks and Issues
There are a number of general risks and issues that must be addressed regardless of the resource future that is
chosen by stakeholders, including the utilities and State policy makers. Additionally, each alternative
DSM/EE, generation and transmission resource type has its own specific risks and issues. Section 14 includes
a detailed discussion of these general and resource-specific implementation-related risks and issues.
1.8.1 General Risks and Issues
General issues and risks related to the implementation of the RIRP include the following:
• Organizational, including:
o The lack of a regional entity with the responsibility for implementing the RIRP will lead to
suboptimal solutions, resulting in higher costs, lower reliability and the inability to manage the
successful integration of DSM/EE and renewable resources into the Railbelt system.
o To date, the Railbelt utilities have not been able to take full advantage of economies of scale for
several reasons. Absent taking a regional approach to future resource planning and development,
this reality will continue.
o Fuel supply risks, including the future deliverability and price of natural gas.
o Risks resulting from the inadequacy of the current regional transmission network.
o Market development risks and issues, including the need to implement a competitive power
procurement process to encourage the development of generation projects by IPPs, and the
potential for large load increases.
o Financing and rate issues, related to the ability of the region to finance the capital investments
identified in the RIRP and the need to mitigate the rate impact of those investments.
o Legislative and regulatory issues, including the potential impact that a State Energy Plan and the
passage of energy-related policies could have on the RIRP.
A Note Regarding Risks
• Risk is an inherent element of any long-term integrated resource plan. This RIRP is not different.
• Risks associated with fuel supply, project development, operations, environmental, transmission,
regulatory, and so forth, all affect the region’s optimal future resource path. These risks are identified and
discussed in this report.
• In many ways, this RIRP is the beginning of a journey; hard work is required to address these risks and
make the difficult policy choices necessary to secure a reliable energy future.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-27 February 2010
1.8.2 Resource Specific Risks and Issues
Table 1-7 provides Black & Veatch’s assessment of the relative
magnitude of various categories of risks and issues for each
resource type, including:
• Resource Potential Risks – the risk associated with the
total energy and capacity that could be economically
developed for each resource option.
• Project Development and Operational Risks – the
risks and issues associated with the development of
specific projects, including regulatory and permitting
issues, the potential for construction costs overruns,
actual operational performance relative to planned
performance, and so forth. This category also includes
non-completion risks once a project gets started, the risk
that adverse operating conditions will severely damage
the facilities resulting in a shorter useful life than
expected, and project delay risks.
• Fuel Supply Risks – the risks and issues associated with
the adequacy and pricing of required fuel supplies.
• Environmental Risks – the risks of environmental-
related operational concerns and the potential for future
changes in environmental regulations.
• Transmission Constraint Risks – the risk that the
ability to move power from a specific generation
resource to where that power is needed will be
inadequate, an issue that is particularly important for
large generation projects and remote renewable projects.
• Financing Risks – the risk that a regional entity or
individual utility will not be able to obtain the financing
required for specific resource options under reasonable
and affordable terms and conditions.
• Regulatory/Legislative Risks – the risk that regulatory
and legislative issues could affect the economic feasibility of specific resource options.
• Price Stability Risks – the risk that wholesale power costs will increase significantly as a result of
changes in fuel prices and other factors (e.g., CO2 costs).
Fundamental RIRP-Related
Risks and Uncertainties
General
• Regional implementation of RIRP elements
• Financial capability of Railbelt utilities
DSM/Energy Efficiency (DSM/EE)
• Lack of Alaska-specific information
• Total achievable resource potential
• Long-term reliability of savings
• Funding source
Generation Resources – Conventional
• Natural gas supplies, deliverability and prices
• Future emissions regulations (including CO2)
Generation Resources – Renewables
• Total economic resource potential
• Optimization of potential sites
• Project completion risks associated with large
hydro and tidal
• Integration of non-dispatchable resources
• Environmental and permitting issues
Transmission
• Adequacy of backbone grid to move power and
ensure reliability
• Generation site-specific interconnections
• Siting and permitting issues
SECTION 1 EXECUTIVE SUMMARY ALASKA RIRP STUDY Black & Veatch 1-28 February 2010 Table 1-7 Resource Specific Risks and Issues - Summary Relative Magnitude of Risk/Issue Resource Resource Potential Risks Project Development and Operational Risks Fuel Supply Risks Environmental Risks Transmission Constraint Risks Financing Risks Regulatory/ Legislative Risks Price Stability Risks DSM/EE Moderate Limited N/A N/A N/A Limited - Moderate Moderate Limited Generation Resources Natural Gas Limited Limited Significant Moderate Limited Moderate Moderate Significant Coal Limited Moderate-Significant Limited Moderate - Significant Limited - Significant Moderate – Significant Moderate Moderate Modular Nuclear Limited Significant Moderate Significant Limited Significant Significant Significant Large Hydro Limited Significant Limited Significant Significant Significant Significant Limited Small Hydro Moderate Moderate Limited Moderate Moderate Limited - Moderate Limited Limited Wind Moderate Moderate N/A Limited Moderate Limited - Moderate Limited Limited - Moderate Geothermal Moderate Limited - Moderate N/A Limited - Moderate Moderate – Significant Limited – Moderate Limited Limited Solid Waste Limited Moderate-Significant N/A Significant Moderate Limited – Moderate Limited-Moderate Moderate Tidal Limited Significant N/A Significant Moderate - Significant Moderate – Significant Moderate -Significant Limited - Moderate Transmission Limited Significant N/A Moderate N/A Significant Moderate -Significant N/A
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-29 February 2010
1.9 Conclusions and Recommendations
1.9.1 Conclusions
The primary conclusions from the RIRP study are discussed below.
1. The current situation facing the Railbelt utilities includes a number of challenging issues that place
the region at a historical crossroad regarding the mix of DSM/EE, generation, and transmission
resources that it will rely on to economically and reliably meet the future electric needs of the
region’s citizens and businesses. As a result of these issues, the Railbelt utilities are faced with the
following challenges:
o A transmission network that is isolated and has limited total transfer capabilities and
redundancies.
o The inability of the region to take full advantage of economies of scale due to its limited size.
o A heavy dependence on natural gas from the Cook Inlet for electric generation.
o Limited and declining Cook Inlet gas deliverability.
o Lack of natural gas storage capability.
o The region’s aging generation and transmission infrastructure.
o A heavy reliance on older, inefficient natural gas generation assets.
o The region’s limited financing capability, both individually and collectively among the Railbelt
utilities.
o Duplicative and diffused generation and transmission expertise among the Railbelt utilities.
2. The key factors that drive the results of Black & Veatch’s analysis include the following:
o The risks and uncertainties that exist for all alternative DSM/EE, generation, and transmission
resource options.
o The future availability and price of natural gas.
o The public acceptability and ability to permit a large hydroelectric project which is a greater
concern, based upon Black & Veatch’s discussions with numerous stakeholders, than the
acceptability and ability to permit other types of renewable projects, such as wind and
geothermal.
o Potential future CO2 prices, which would impact all fossil fuels, that may or may not result from
proposed Federal legislation.
o The region’s existing transmission network, which limits: 1) the ability to transfer power between
areas within the region to minimize power costs, and 2) places a maximum limit on the amount of
non-dispatchable resources that can be integrated into the region’s transmission grid.
o The ability of the region to raise the required financing, either by the utilities on their own or
through a regional G&T entity.
o Whether the Railbelt utilities develop a number of currently proposed projects that were selected
outside of a regional planning process.
Figures 1-10 and 1-11 graphically demonstrate how the results of the various reference and sensitivity
cases are impacted by these important uncertainties. Figure 1-10 shows the cumulative present value
cost for each year over the 50-year planning horizon; similarly, Figure 1-11 shows the annual
wholesale power cost (cents/kWh) in 2010 dollars. In both cases, we have shown selected reference
and sensitivity cases to highlight how dependent the results are to these key uncertainties.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-30 February 2010
Figure 1-10
Cumulative Present Value Cost – Selected Reference and Sensitivity Cases
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
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$12,000,000
$14,000,000
$16,000,000
2011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059YearCumulative Present Value Cost ($000)Plan 1A/1B 1A/1B With Double DSM/EE Programs 1A/1B Without DSM/EE Programs
1A/1B With High Gas Prices 1A/1B Without CO2 Taxes 1A/1B Without Chakachamna
1A/1B With Susitna (Low Watana Expansion)1A/1B With Committed Units
Figure 1-11
Annual Wholesale Power Cost – Selected Reference and Sensitivity Cases
0.00
5.00
10.00
15.00
20.00
25.002011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059
YearWholesale Power Cost (cents/kWh) - 2010 DollarsPlan 1A/1B Plan 2A
1A/1B With Double DSM/EE Programs 1A/1B Without DSM/EE Programs
1A/1B With High Gas Prices 1A/1B Without CO2 Taxes
1A/1B Without Chakachamna 1A/1B With Susitna (Low Watana Expansion)
1A/1B With Committed Units
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-31 February 2010
As can be seen in Figure 1-10, which shows cumulative net present value costs over the 50-year
planning horizon, the 1A/1B With Susitna (Low Watana Expansion), 1A/1B With no DSM/EE
Programs, 1A/1B Without Chakachamna, 1A/1BWith Committed Units, and 1A/1B With High Gas
Prices Sensitivity Cases are all higher cost than Scenario 1A/1B, in descending order. The 1A/1B
With Double DSM/EE Programs and 1A/1B With No CO2 Taxes Sensitivity Cases are lower cost that
Scenario 1A/1B.
Figure 1-11 shows how significant the uncertainty regarding CO2 taxes is with regard to the results.
It also shows the economic value of achieving higher DSM/EE savings that were assumed in the
Scenario 1A/1B Reference Case if those savings can be achieved. Also, shown is the fact that the
other sensitivity cases are higher cost than Scenario 1A/1B.
3. The resource plans that were developed as part of this study for each Evaluation Scenario include a
diverse portfolio of resources. If implemented, the RIRP will lead to:
o The development of a resource mix resulting from a regional planning process.
o Greater reliance on DSM/EE and renewable resources and a lower dependence on natural gas.
o A more robust transmission network.
o More effective spreading of risks among all areas of the region.
o A greater ability to respond to large load growth should these load increases occur. Stated
another way, the implementation of the RIRP will provide a stronger foundation upon which to
base future economic development efforts.
4. The cost of this greater reliance on DSM/EE and renewable resources is less than the continued heavy
reliance on natural gas based upon the base case gas price forecast that was used in this analysis. This
result is achievable if the region builds a large hydroelectric project. There are uncertainties, at this
point in time, regarding the environmental and/or geotechnical conditions under which a large
hydroelectric project could be built. If a large hydroelectric facility can not be developed, or if the
cost of the large hydroelectric project significantly exceeds the current preliminary estimates, then the
costs associated with a predominately renewable future would be greater than continuing to rely on
natural gas.
5. Our analysis shows that Scenarios 1A and 1B result in the same resources and, consequently, the
same costs and emissions. In other words, the cost of achieving a renewable energy target of
50 percent by 2025 (Scenario 1B) is no greater than the cost of the unconstrained solution
(Scenario 1A). This result applies only if a large hydroelectric project is built.
6. Scenarios 2A and 2B were evaluated to determine what the impact would be if the demand in the
region was significantly greater than it is today. In fact, the per unit power costs were not less than
Scenario 1A/1B due to the cost of Susitna which was the resource chosen to meet this additional load.
7. Additionally, the implementation of a regional plan will result in lower costs than if the individual
Railbelt utilities continue to go forward on their own. While the scope of this study did not include
the development of separate integrated resource plans for each of the six Railbelt utilities, we did
complete a sensitivity analysis to show the cost impact if the utilities develop their currently proposed
projects (referred to as committed units) that were selected outside of a regional planning process.
The Railbelt utilities are moving forward with these projects due to the existing uncertainty regarding
the formation of GRETC. While this sensitivity case does not fully capture the incremental cost of
the utilities acting independently over the 50-year planning horizon, it does provide an indication of
the relative cost differential. Figure 1-12 shows the resulting total annual costs of the two different
resource plans. In the aggregate, the cost of the Committed Unit Sensitivity Case was approximately
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-32 February 2010
5.6 percent, or $484 million on a cumulative net present value cost basis, higher than Scenario 1A/1B.
The main conclusion to draw from this graphic is that there are significant cost savings associated
with the Railbelt utilities implementing a plan that has been developed to minimize total regional
costs, while ensuring reliable service, as opposed to the individual utilities working separately to meet
the needs of their own customers.
Figure 1-12
Comparison of Results - Scenario 1A/1B Versus Committed Units Sensitivity Case
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
$14,000,000
$16,000,0002011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059
YearCumulative Present Value Cost ($000)Plan 1A/1B 1A/1B With Committed Units
8. There are a number of risks and uncertainties regardless of the resource options chosen. For example:
1) there is a lack of Alaska-specific data upon which to build an aggressive region-wide DSM/EE
program, 2) the future availability and price of natural gas affects the viability of natural gas
generation, and 3) the total economic potential of various renewable resources is unknown at this
time. In some cases, these risks and uncertainties (e.g., the ability to permit a large hydroelectric
facility) might completely eliminate a particular resource option. Due to these risks and uncertainties,
it will be important for the region to maintain flexibility so that changes to the preferred resource plan
can be made, as necessary, as these resource-specific risks and uncertainties become more clear or get
resolved.
9. Significant investments in the region’s transmission network need to be made within the next 10 years
to ensure the reliable and economic transfer of power throughout the region. Without these
investments, providing economic and reliable electric service will be a greater challenge.
10. The increased reliance on non-dispatchable renewable resources (e.g., wind) will require a higher
level of frequency regulation within the region to handle swings in electric output from these
resources. An increased level of regulation has been included in Black & Veatch’s transmission plan.
Even with this increased regulation, however, the challenges associated with the integration of non-
dispatchable resources will ultimately place a maximum limit on the amount of these resources that
can be developed.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-33 February 2010
11. The implementation of the RIRP does not require that a regional generation and transmission entity
(e.g., GRETC) be formed. However, the absence of a regional entity with the responsibility for
implementing the RIRP will increase the difficulty of the region’s ability to implement a regional plan
and, in fact, Black & Veatch believes that the lack of a regional entity will, as a practical matter, mean
that the RIRP will not be fully implemented. As a consequence, the favorable outcomes of the RIRP
discussed above would not be realized. The interplay between the formation of a regional entity and
the RIRP is shown in Figure 1-13.
Figure 1-13
Interplay Between GRETC and Regional Integrated Resource Plan
1.9.2 Recommendations
This subsection summarizes the overall recommendations arising from this study, broken down into the
following three categories:
• Recommendations – General
• Recommendations – Capital Projects
• Recommendations – Other
1.9.2.1 Recommendations - General
The following general actions should be taken to ensure the timely implementation of the RIRP:
1. The State should work closely with the utilities and other stakeholders to make a decision regarding
the formation of GRETC and to develop the required governance plan, financial and capital
improvement plan, capital management plan and transmission access plan, and address other matters
related to the formation of the proposed regional entity.
Current
Situation
• Limited redundancy
• Limited economies
of scale
• Dependence on
fossil fuels
• Limited Cook Inlet
gas deliverability
and storage
•Aging G&T
infrastructure
• Inefficient fuel use
• Difficult financing
• Duplicative G&T
expertise
RIRP Study
• Plan that economically
schedules what, when,
and where to build, based
on available fuel and
energy supplies
• 50-year time horizon
• Competes generation,
transmission, fuel supply
and DSM/energy
efficiency options
•Considers CO2 regulation
• Includes renewable
energy projects
• Arrives at a plan to build
future infrastructure for
minimum long-run cost to
ratepayers
•Considers fuel supply
options and risks
RIRP
Results
• Increased
DSM/energy
efficiency
• Increased
renewables
•Reduced
dependence
on natural gas
• Increased
transmission
GRETC - Enabler
REGA Study
Proposed
GRETC
Formation
Future Situation
• Robust transmission
• Diversified fuel supply
• System-wide power rates
• Spread risk
• State financial assistance
• Regional planning
• Wise resource use
• Respond to large load
growth
• Technical resources
• New technologies
10-Year Transition Period
Financing Options
• Pre-funding of capital
requirements
• Commercial bond market
• State financial assistance
(Bradley Lake model)
• Construction-work-in-progress
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-34 February 2010
2. The State should establish certain energy-related policies, including:
o The pursuit of large hydroelectric facilities
o DSM/EE program targets
o RPS (i.e., target for renewable resources), and the pursuit of wind, geothermal, and tidal (which
will become commercially mature during the 50-year planning horizon) projects in addition to
large hydroelectric projects; the passage of an RPS would be meaningful as a policy statement
even though the preferred resource plan would achieve a 50 percent renewable level by 2025.
o System benefit charge to fund DSM/EE programs and or renewable projects
3. The State should work closely with the Railbelt utilities and other stakeholders to establish the
specific preferred resource plan. In establishing the preferred resource plan, the economic results of
the various reference cases and sensitivity cases evaluated in this study should be considered, as well
as the environmental impacts discussed in Section 13 and the project-specific risks discussed in
Section 14.
4. Black & Veatch believes that the Scenario 1A/1B resource plan should be the starting point for the
selection of the preferred resource plan as discussed below. Table 1-8 provides a summary of the
specific resources that were selected, based upon economics, in the Scenario 1A/1B resource plan
during the first 10 years.
A project selected in Scenario 1A/1B after the first 10 years especially worthy of mention is the
Chakachamna Hydroelectric Project in 2025.
Another important consideration in the selection of a preferred resource plan is evaluation of the
sensitivity cases evaluated, as presented in Section 13. Issues addressed through the sensitivity cases
and considered in Black & Veatch’s selection of a preferred resource plan include the following and
are discussed in Table 1-9. Following that discussion,
o What if CO2 regulation doesn’t occur?
o What is the effect if the committed units are installed?
o What if Chakachamna doesn’t get developed?
o What would be the impact of the alternative Susitna projects?
There are several projects that are significantly under development and included in the preferred
resource plan. These significantly developed projects include:
o Healy Clean Coal Project (HCCP)
o Southcentral Power Project
o Fire Island Wind Project
o Nikiski Wind Project
These projects are discussed in Table 1-10.
In addition to these resources, Black & Veatch believes that Mt. Spurr, Glacier Fork, Chakachamna
and Susitna should be pursued further to the point that the uncertainties regarding the environmental,
geotechnical and capital cost issues become adequately resolved to determine if any of the projects
could actually be built.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-35 February 2010
Table 1-8
Resources Selected in Scenario 1A/1B Resource Plan
Project Discussion
DSM/EE Resources The full level of DSM/EE resources evaluated was selected based upon their relative
economics. Sensitivity analysis indicates that even greater levels of DSM/EE may be
cost-effective. The lack of Alaska-specific DSM/EE data causes the exact level of
cost-effective DSM/EE to remain uncertain.
Nikiski Wind The RIRP selected this project in the initial year. It is being developed as an IPP
project and is well along in the development process. The ARRA potentially offers
significant financial incentives if this project is completed by January 1, 2013. These
incentives could further improve its competitiveness. As a wind unit, it has no impact
on planning reserves, but contributes to renewable generation.
HCCP HCCP is completed and GVEA has negotiated with AIDEA for its purchase. This
project was selected in the initial year of the plan.
Fire Island Wind Project The Fire Island Wind Project is being developed as an IPP project with proposed
power purchase agreements provided to the Railbelt utilities. The project may be able
to benefit significantly from ARRA and the $25 million grant from the State for
interconnection. This project was selected in 2012.
Anchorage 1x1 6FA Combined
Cycle
The RIRP selected this unit for commercial operation in 2013. This unit is very
similar in size and performance to the Southcentral Power Project being developed as
a joint ownership project by Chugach and ML&P for 2013 commercial operation.
The project appears well under development with the combustion turbines already
under contract. The project fits well with the RIRP and the joint ownership at least
partially reflects the GRETC joint development concept.
Glacier Fork Hydroelectric
Project
The RIRP selected this project for commercial operation in 2014, the first year that it
was available for commercial operation in the models. Of the large hydroelectric
projects, Glacier Fork is by far the least developed. Glacier Fork has very limited
storage and thus does not offer the system operating flexibility of the other large
hydroelectric units. There is also significant uncertainty with respect to its capital
cost and ability to be licensed. Because it has such a minimal level of firm generation
in the winter, it does not contribute significantly to planning reserves, but does
contribute about 6 percent of the renewable energy to the Railbelt. Detailed
feasibility studies and licensing are required to advance this option.
Anchorage and GVEA MSW
Units
The RIRP selected these units in 2015 and 2017. Historically, mass burn MSW units
such as those modeled, have faced significant opposition due to emissions of
mercury, dioxin, and other pollutants. Other technologies which result in lower
emissions, such as plasma arc, are not commercially demonstrated. The units
included in the RIRP are relatively small (26 MW in total) and are not required to be
installed to meet planning reserve requirements, but their base load nature contributes
nearly 4 percent of the renewable energy. Detailed feasibility studies would be
required to advance this alternative.
GVEA North Pole Retrofit The retrofitting of GVEA’s North Pole combined cycle unit with a second train using
a LM6000 combustion turbine and heat recovery steam generator was selected in
2018 coincident with the assumption of the availability of natural gas to GVEA. The
retrofit takes advantage of capital and operating cost savings resulting from the
existing installation.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-36 February 2010
Table 1-8 (Continued)
Resources Selected in Scenario 1A/1B Resource Plan
Project Discussion
Mt. Spurr Geothermal Project The first unit at Mt. Spurr was selected in 2020. Mt. Spurr’s developer, Ormat,
currently has commercial operation scheduled for 2017. Significant development
activity remains for the project including verifying the geothermal resource. Mt.
Spurr will also require significant infrastructure development including access roads
and transmission lines. This infrastructure may correspond to similar infrastructure
development required for Chakachamna which is selected in 2025 in the RIRP. As
the implementation of the RIRP unfolds, there will likely be the need to adjust the
timing of the resource additions following the implementation of the initial projects.
Table 1-9
Impact of Selected Issues on the Preferred Resource Plan
Issue Discussion
CO2 Regulation The sensitivity case for Scenario 1A without CO2 regulation selects
the Anchorage LMS 100 project instead of Fire Island and Mt. Spurr
in the first 10 years.
Committed Units Installation of the committed units significantly increases the cost of
Scenario 1A/1B. In addition to the committed units, this plan selects
five wind units from 2016 through 2024 in response to CO2
regulation. The plan with the committed units eliminates
Chakachamna and does not meet the 50 percent renewable target by
2025.
Chakachamna Chakachamna could fail to develop because of licensing or technical
issues. Also, if the cost of Chakachamna were to increase to be
equivalent to the alternative Susitna projects on a GWh basis, it would
not be selected. The sensitivity case without Chakachamna for the
first 10 years is identical to Scenario 1A/1B. The case does not meet
the 50 percent renewable target by 2025 and is 5.2 percent higher in
cost than the preferred resource plan.
Susitna None of the alternative Susitna projects are selected in the
Scenario 1A/1B resource plan. The least cost Susitna option, which is
Low Watana Expansion, is 15.3 percent more than the preferred
resource plan and 9.0 percent more than the case without
Chakachamna. The 50 percent renewable requirement can not be met
without Susitna if Chakachamna is not available.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-37 February 2010
Table 1-10
Projects Significantly Under Development
Project Discussion Preferred Resource Plan Recommendation
HCCP HCCP is completed and GVEA has negotiated with
AIDEA for its purchase. The project is part of the
least cost scenario. While CO2 regulation has been
assumed in the RIRP, those regulations are not in
place and there is no absolute assurance that they
will be in place or what the costs from the
regulations will be. HCCP adds further fuel
diversity to the Railbelt, especially to GVEA who
doesn’t currently have access to natural gas. As a
steam unit, HCCP improves transmission system
stability.
Black & Veatch recommends that HCCP be
included in the preferred resource plan.
Southcentral
Power Project
The Southcentral Power Project is well under
development with the combustion turbines
purchased. The timing and technology are
generally consistent with the preferred resource
plan. The project will improve the efficiency of
natural gas generation in the Railbelt and permit the
retirement of aging units.
Black & Veatch recommends the continued
development of the Southcentral Power Project
as part of the preferred resource plan.
Fire Island
Wind Project
The Fire Island Wind Project is being developed as
an IPP project with proposed power purchase
agreements provided to the Railbelt utilities. The
project may be able to benefit significantly from
ARRA and the $25 million grant from the State for
interconnection. This project is part of the least
cost plan and provides renewable energy to the
Railbelt system. Issues with interconnection and
regulation will need to be resolved.
Subject to the successful negotiation of a
purchase power agreement and successful
negotiation of the interconnection and
regulation issues, Black & Veatch recommends
that it be part of the preferred resource plan in a
time frame that allows for the ARRA benefits
to be captured.
Nikiski Wind
Project
The Nikiski Wind Project is an IPP project like Fire
Island and has the same potential to benefit from
ARRA. It is also part of the least cost plan.
Like Fire Island, subject to successful
negotiation of a purchase power agreement and
successful negotiation of the interconnection
and regulation issues, Black & Veatch
recommends that it be part of the preferred
resource plan in a time frame that allows for the
ARRA benefits to be captured.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-38 February 2010
In the case of the Mt. Spurr Geothermal Project, exploration should continue to determine the extent
and characteristics of the geothermal resource at the site.
In the case of Susitna, the primary focus should be on completing engineering studies to optimize the
size and minimize the costs of the project. In the case of Glacier Fork and Chakachamna, the
additional work should look for “fatal flaws”.
Additionally, further analysis needs to be completed relative to integrating wind and other non-
dispatchable renewable resources into the transmission network.
5. The State and Railbelt utilities should develop a public outreach program to inform the general public
regarding the preferred resource plan, including the costs and benefits.
6. The State Legislature should make decisions regarding the level and form of State financial assistance
that will be provided to assist the Railbelt utilities and AEA, under a unified regional G&T entity
(i.e., GRETC), develop the generation resources and transmission projects identified in the preferred
resource plan.
7. The electric utilities, various State agencies, Enstar and Cook Inlet producers need to work more
closely together to address short-term and long-term gas supply issues. Specific actions that should
be taken include:
o Development of local gas storage capabilities with open access among all market participants as
soon as possible.
o Undertake efforts to secure near-term LNG supplies to ensure adequate gas over the 10-year
transition period until additional gas supplies can be secured either in the Cook Inlet, from the
North Slope or from long-term LNG supplies.
o The State should complete a detailed cost and risk evaluation of available long-term gas supply
options to determine the best options. Once the most attractive long-term supplies of natural gas
have been identified, detailed engineering studies and permitting activities should be undertaken
to secure these resources.
o Appropriate commercial terms and pricing structures should be established through State and
regulatory actions to provide producers with the incentive to increase exploration for additional
gas supplies in the Cook Inlet or nearby basins. This action is required to provide the necessary
long-term contractual certainty to result in additional exploration and development.
1.9.2.2 Recommendations – Capital Projects
Efforts should be undertaken to begin the development, including detailed engineering and permitting
activities, of the following capital projects, which are included in Black & Veatch’s recommended preferred
resource plan.
1. Develop a comprehensive region-wide portfolio of DSM/EE programs.
2. Generation projects:
o Projects under development (HCCP, Southcentral Power Project, Fire Island Wind Project, and
Nikiski Wind Project)
o Glacier Fork Hydroelectric Project
o Generic Anchorage MSW Project
o Generic GVEA MSW Project
o GVEA North Pole Retrofit Project
o Mt. Spurr Geothermal Project
o Chakachamna Hydroelectric Project
o Susitna Hydroelectric Project
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-39 February 2010
3. Transmission and related substation projects, including the following projects which have been
identified for priority attention because of their immediate impact on the reliability of the existing
system. These projects are estimated to be required within the next five years.
o Soldotna to Quartz Creek Transmission Line ($84 million – Project B)
o Quartz Creek to University Transmission Line ($112.5 million – Project C)
o Douglas to Teeland Transmission Line ($37.5 million – Project D)
o Lake Lorraine to Douglas Transmission Line ($80 million – Project E)
o SVCs ($25 million - Other Reliability Projects)
o Funds to undertake the study of the Southern Intertie ($1 million)
o Funds to investigate the provision of regulation that will facilitate the integration of renewable
energy projects into the Railbelt system ($50 million, including cost of BESS – Other Reliability
Projects)
1.9.2.3 Recommendations - Other
Other actions, related to the implementation of the RIRP, that should be undertaken include:
1. The State Legislature should appropriate funds for the initial stages of the development of a regional
DSM/EE program, including 1) region-wide residential and commercial end-use saturation surveys,
2) residential and commercial customer attitudinal surveys, 3) vendor surveys, 4) comprehensive
evaluation of economically achievable potential, and 5) detailed DSM/EE program design efforts.
2. Develop a regional DSM/EE program measurement and evaluation protocol.
3. If GRETC is not formed, some type of a regional entity should be formed to develop and deliver
DSM/EE programs to residential and commercial customers throughout the Railbelt region, in close
coordination with the Railbelt utilities.
4. Likewise, if GRETC is not formed, some type of a regional entity should be formed to develop the
renewable resources included in the preferred resource plan.
5. Establish close coordination between the Railbelt electric utilities, Enstar and AHFC regarding the
development and delivery of DSM/EE programs.
6. Aggressively pursue available Federal funding for DSM/EE programs and renewable projects.
7. Further development of tidal power should be encouraged due to its resource potential in the Railbelt
region. Although this technology is not commercially available, in Black & Veatch’s opinion, at this
point in time, it has the potential to be economic within the planning horizon.
8. The State and Railbelt utilities should work closely with resource agencies to identify environmental
issues and permitting requirements related to large hydroelectric and tidal projects, and conduct the
necessary studies to address these issues and requirements.
9. Complete a regional economic potential assessment, including the identification of the most attractive
sites, for all renewable resources included in the preferred resource plan.
10. Develop streamlined siting and permitting processes for transmission projects.
11. Develop a regional frequency regulation strategy for non-dispatchable resources.
12. Develop a regional competitive power procurement process and a standard power purchase agreement
to provide IPPs an equal opportunity to submit qualified proposals to develop specific projects.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-40 February 2010
13. Federal legislative and regulatory activities, including those related to emissions regulations, should
be monitored closely and influenced to the degree possible.
14. Monitor the licensing progress of small modular nuclear units.
1.10 Near-Term Implementation Action Plan (2010-2012)
The purpose of this subsection section is to identify our overall recommendations regarding the near-term
implementation plan, covering the period from 2010 to 2012. Our recommended actions are grouped into the
following categories:
• General actions
• Capital projects
• Supporting studies and activities
• Other actions
In many ways, this near-term implementation plan shown in Tables 1-11 through 1-14 serves two objectives.
First, it identifies that steps that should be taken during the next three years regardless of the alternative
resource plan that is chosen as the preferred resource plan. Second, it is intended to maintain flexibility as the
uncertainties and risks associated with each alternative resource plan become more clear and or resolved.
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-41 February 2010
1.10.1 General Actions
Table 1-11
Near-Term Implementation Action Plan – General Actions
Actions
Category Description Timeline Est. Cost
General Actions • The State should work closely with the utilities and other
stakeholders to make a decision regarding the formation of
GRETC and to develop the required governance plan,
financial and capital improvement plan, capital
management plan and transmission access plan, and
address other matters related to the formation of the
proposed regional entity
2010 $6.8 million
• Establish State energy-related policies regarding:
o The pursuit of large hydroelectric facilities
o DSM/EE program targets
o RPS (i.e., target for renewable resources), and the
pursuit of wind, geothermal, and tidal projects
o System benefit charge to fund DSM/EE programs and
or renewable projects
2010-2011 $0.2 million
• The State should work closely with the Railbelt utilities
and other stakeholders to establish the preferred resource
plan, using the Scenario 1A/1B resource plan as the
starting point
2010 Not
applicable
• Mt. Spurr, Glacier Fork, Chakachamna and Susitna should
be pursued further to the point that the uncertainties
regarding the environmental, geotechnical and capital cost
issues become adequately resolved to determine if any of
these projects could actually be built
2010-2011 To be
determined
• Develop a public outreach program to inform the public
regarding the preferred resource plan, including the costs
and benefits
2010-2011 $0.1 million
• The State Legislature should make decisions regarding the
level and form of State financial assistance that will be
provided to assist the Railbelt utilities and AEA, under a
unified regional G&T entity (i.e., GRETC), develop the
generation resources and transmission projects identified
in the preferred resource plan
2010-2011 Not
applicable
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-42 February 2010
Table 1-11 (Continued)
Near-Term Implementation Action Plan – General Actions
Actions
Category Description Timeline Est. Cost
• The electric utilities, various State agencies, Enstar and
Cook Inlet producers need to work more closely together
to address short-term and long-term gas supply issues;
specific actions that should be taken include:
o Development of local gas storage capabilities as soon
as possible
o Undertake efforts to secure near-term LNG supplies
to ensure adequate gas over the 10-year transition
period until additional gas supplies can be secured
o The State should complete a detailed cost and risk
evaluation of available long-term gas supply options
to determine the best options; once the most attractive
long-term supplies of natural gas have been identified,
detailed engineering studies and permitting activities
should be undertaken to secure these resources
o Appropriate commercial terms and pricing structures
should be established through State and regulatory
actions to provide producers with the incentive to
increase exploration for additional gas supplies in the
Cook Inlet or nearby basins
2010-2012 To be
determined
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-43 February 2010
1.10.2 Capital Projects
Table 1-12
Near-Term Implementation Action Plan – Capital Projects
Actions
Category Description Timeline Est. Cost
Capital Projects • Develop a comprehensive region-wide portfolio of
DSM/EE programs within first six years
2011-2016 $34 million
• Begin detailed engineering and permitting activities
associated with the generation projects identified in the
initial years of the preferred resource plan, including:
o Projects under development (HCCP, Southcentral
Power Project, Fire Island Wind Project, and Nikiski
Wind Project)
o Glacier Fork Hydroelectric Project
o Generic Anchorage MSW Project
o Generic GVEA MSW Project
o GVEA North Pole Retrofit Project
o Mt. Spurr Geothermal Project
o Chakachamna Hydroelectric Project
o Susitna Hydroelectric Project
2011-2016 Varies by
project
• Begin detailed engineering and permitting activities
associated with the transmission projects identified in the
initial years of the preferred resource plan, including:
o Soldotna to Quartz Creek Transmission Line
o Quartz Creek to University Transmission Line
o Douglas to Teeland Transmission Line
o Lake Lorraine to Douglas Transmission Line
o SVCs
o Funds to undertake the study of the Southern Intertie
o Funds to investigate the provision of regulation that
will facilitate the integration of renewable energy
projects into the Railbelt system
2011-2016 Varies by
project
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-44 February 2010
1.10.3 Supporting Studies and Activities
Table 1-13
Near-Term Implementation Action Plan – Supporting Studies and Activities
Actions
Category Description Timeline Est. Cost
Supporting
Studies and
Activities
• The State Legislature should appropriate funds for the
initial stages of the development of a regional DSM/EE
program, including 1) region-wide residential and
commercial end-use saturation surveys, 2) residential and
commercial customer attitudinal surveys, 3) vendor
surveys, 4) comprehensive evaluation of economically
achievable potential, and 5) detailed DSM/EE program
design efforts
2010-2011 $1.0 million
• Develop a regional DSM/EE program measurement and
evaluation protocol
2012 $0.1 million
• The State and Railbelt utilities should work closely with
resource agencies to identify environmental issues and
permitting requirements related to large hydroelectric and
tidal projects
2010-2011 $0.2 million
• Conduct necessary studies to address resource agencies’
issues and data requirements related to large hydroelectric
and tidal projects
2011-2012 To be
determined
• Complete a regional economic potential assessment,
including the identification of the most attractive sites, for
all renewable projects included in the preferred resource
plan
2010-2012 $1.5 million
• Develop a regional frequency regulation strategy for non-
dispatchable resources
2011 $0.5 million
• Develop a regional standard power purchase agreement
for IPP-developed projects
2011-2012 $0.2 million
• Develop a regional competitive power procurement
process to encourage IPP development of projects
included in the preferred resource plan
2011-2012 $0.2 million
SECTION 1 EXECUTIVE SUMMARY
ALASKA RIRP STUDY
Black & Veatch 1-45 February 2010
1.10.4 Other Actions
Table 1-14
Near-Term Implementation Action Plan – Other Actions
Actions
Category Description Timeline Est. Cost
Other Actions • Form a regional entity (if GRETC is not formed) to
develop and deliver DSM/EE programs to residential and
commercial customers throughout the Railbelt region, in
close coordination with the Railbelt utilities
2010-2011 Subject to
decision
regarding
formation of
GRETC
• Establish close coordination between the Railbelt electric
utilities, Enstar and AHFC regarding the development and
delivery of DSM/EE programs
2010-2011 $0.2 million
• Aggressively pursue available Federal funding for
DSM/EE programs
2010-2011 $0.2 million
• Form a regional entity (if GRETC is not formed) and
encourage IPPs to identify and develop renewable projects
that are included in the preferred resource plan
2011-2012 Subject to
decision
regarding
formation of
GRETC
• Further encourage the development of tidal power Ongoing To be
determined
• Monitor, and influence to the degree possible, Federal
legislative and regulatory activities, including those related
to emissions regulations
Ongoing Not
applicable
• Aggressively pursue available Federal funding for
renewable projects
2010-2012 $0.2 million
• Develop streamlined siting and permitting processes for
transmission projects
2010-2011 $0.5 million
• Monitor the licensing progress of small modular nuclear
units
Ongoing Not
applicable
PROJECT OVERVIEW
SECTION 2 AND APPROACH
ALASKA RIRP STUDY
Black & Veatch 2-1 February 2010
2.0 PROJECT OVERVIEW AND APPROACH
This section provides an overview of the RIRP and Black & Veatch’s approach to the completion of this
study.
2.1 Project Overview
In response to a directive from the Alaska Legislature, the AEA was the lead agency for the development of
this RIRP for the Railbelt region. This region is defined as the service areas of six regulated public utilities
that comprise the region, including: Anchorage ML&P, Chugach, GVEA, HEA, MEA, and SES.
The goal of this project is to minimize future power supply costs and maintain or improve on current levels of
power supply reliability through the development of a single comprehensive RIRP for the Railbelt region.
The intent of the RIRP project is to provide:
• An up-to-date model that the utilities and AEA can use as a common database and model for future
planning studies and analysis.
• An assessment of loads and demands for the Railbelt electrical grid for a time horizon of 50 years
including new potential industrial demands.
• Projections for Railbelt electrical capacity and energy growth, fuel prices, and resource options.
• An analysis of the range of potential generation resources available, including costs, construction
schedule, and long-term operating costs.
• A schedule for existing generating unit retirement, new generation construction, and construction of
backbone redundant transmission lines that will allow the future Railbelt electrical grid to operate
reliably under a transmission tariff which allows access by all potential power producers, and with a
postage-stamp rate for electric energy and demand for the entire Railbelt as a whole.
• A long-term schedule for developing new fuel supplies that will provide for reliable, stable priced
electrical energy for a 50-year planning horizon.
• A short-term schedule that coordinates immediate network needs (i.e., increasing penetration level of
non-dispatchable generation, such as wind) within the first 10 years of the planning horizon with the
long-term goals.
• A short-term plan addressing the transition from the present decentralized ownership and control to a
unified G&T entity that identifies unified actions between utilities that must occur during this
transition period.
• A diverse portfolio of power supply that includes, in appropriate portions, renewable and alternative
energy projects and fossil fuel projects, some or all of which could be provided by IPPs.
• A comprehensive list of current and future generation, transmission and electric power infrastructure
projects.
PROJECT OVERVIEW
SECTION 2 AND APPROACH
ALASKA RIRP STUDY
Black & Veatch 2-2 February 2010
Black & Veatch conducted the REGA study for the AEA, which evaluated the feasibility of the Railbelt
utilities forming an organization to provide coordinated unit commitment and economic dispatch of the
region’s generation resources, generation and transmission system planning, and project development for the
Railbelt. As a result of that study, legislation was proposed to create GRETC, with a 10-year transition period
in to achieve these goals. This RIRP is based on the GRETC concept being implemented from the beginning
of the study’s time horizon.
Black & Veatch had primary responsibility for conducting this Railbelt RIRP. In addition to Black & Veatch,
three other AEA contractors (HDR, EPS, and SNW) played important roles in the development of the RIRP.
HDR updated work from the mid-1980s on the Susitna Hydroelectric Project and developed the capital and
operating costs, as well as the generating characteristics, for several smaller sized Susitna options. HDR’s
work was used by Black & Veatch in the Strategist® and PROMOD® modeling discussed below. HDR’s
report summarizing the results of its work is provided in Appendix A.
EPS assisted in the evaluation of the region’s transmission system.
SNW developed the financial model used to determine the overall financing costs for the portfolios of
generation and transmission projects developed as part of this project, and evaluated the impact of some
financial options that could be used to address financing issues and mitigating related rate impacts. The
results of SNW’s analysis are provided in Appendix B.
2.2 Project Approach
The RIRP study process for the Railbelt system consisted of three key stages: data collection, optimal
generation expansion along with integrated transmission expansion planning and production cost modeling,
and report writing and documentation. Throughout this process, data related to alternative demand-side,
supply-side, and transmission resource options were compiled, reviewed, screened for appropriateness, and
modeled using Ventyx’s Strategist® and PROMOD® optimal generation expansion and production cost
models. Model inputs and assumptions take into consideration possible sensitivity cases and any
considerations unique to the six utilities to derive the least-cost plan for the Railbelt region’s electric system.
To complete this study, the Black & Veatch project team, in collaboration with the other aforementioned
AEA contractors, completed the tasks shown in Figure 2-1.
PROJECT OVERVIEW
SECTION 2 AND APPROACH
ALASKA RIRP STUDY
Black & Veatch 2-3 February 2010
Figure 2-1
Project Approach Overview
Task 1 – Collect Data – Existing Reports and Documents
Black & Veatch issued data requests to the six Railbelt utilities to update and add to the data previously
obtained in the REGA study. These data included existing generating resources and operating data, load and
energy requirements, transmission characteristics, purchase power transactions, and DSM/EE programs.
Task 2 – Attend and Assist in Initial Technical Workshop
Black & Veatch worked with the AEA to sponsor a Technical Workshop near the beginning of the project to
obtain information and input from the various regional stakeholders and to enable the development of
scenarios for evaluation which provided the basis for the assessment of future fuel supply, generation, and
transmission resource alternatives for the Railbelt.
Task 3 – Collect Data – Current Information From Stakeholders
Black & Veatch collected additional information from other regional stakeholders, including producers,
ratepayer groups, and representatives from project developers, as well as the DSM/EE, environmental and
renewables communities.
PROJECT OVERVIEW
SECTION 2 AND APPROACH
ALASKA RIRP STUDY
Black & Veatch 2-4 February 2010
Task 4 – Participate in Advisory Working Group Meetings
Black & Veatch participated in five meetings with the Advisory Working Group that was formed for the
project. The role of this Advisory Working Group is described later in this section.
Task 5 – Develop Resource Plan Scenarios
This task involved the following activities:
Subtask 5.1 – Development of Economic Parameters
Subtask 5.2 – Development of Regional Load Forecast
Subtask 5.3 – Development of Fuel Price Forecasts
Subtask 5.4 – Development of Reserve Criteria
Subtask 5.5 – Evaluation of Conventional Supply-Side Alternatives
Subtask 5.6 – Evaluation of Hydro Projects
Subtask 5.7 – Evaluation of Wind and Other Renewable Projects
Subtask 5.8 – Evaluation of Transmission System Expansions
Subtask 5.9 – Evaluation of Generation Unit Retirements
Subtask 5.10 – Evaluation of DSM/EE Measures
Subtask 5.11 – Scenario Mapping
Subtask 5.12 – Benchmarking Analysis
Task 6 – Present Resource Plan Scenarios
Black & Veatch made a presentation to the RIRP Advisory Working Group and AEA explaining the resource
scenarios and describing the recommended Evaluation Scenarios.
Task 7 – Develop Regional Integrated Resource Plan
Black & Veatch then developed alternative resource plans for each of the four Evaluation Scenarios, based
upon the results of Task 5.
Task 8 – Present Scenarios and Plans to Stakeholders
Black & Veatch presented its preliminary results, conclusions and recommendations to interested parties at a
second Technical Conference that was held in December.
Task 9 – Develop Draft Report
Black & Veatch prepared a Draft Report that was provided to the AEA and made available to interested
parties for review and comment.
Task 10 – Develop Final Report
Black & Veatch prepared a Final Report that incorporated comments received on the Draft Report.
PROJECT OVERVIEW
SECTION 2 AND APPROACH
ALASKA RIRP STUDY
Black & Veatch 2-5 February 2010
2.3 Modeling Methodology
2.3.1 Study Period and Considerations
The evaluation timeframe consists of a 50-year study period from 2011 through 2060. Evaluations were
conducted in nominal dollars with the annual costs discounted to 2011 dollars for comparison using the
present worth discount rate discussed in Section 5. After evaluating the seasonal month definitions of the
utilities, Black & Veatch defined the summer season as May 1 through October 31, and the winter season as
November 1 through April 30.
The 50-year planning period presented challenges to reduce the running time for the Strategist® model to
acceptable levels. Several techniques were used including bracketing years and pre-screening alternatives to
reduce the number of alternatives included in the Strategist® runs to reduce run time to a target level of
approximately 24 hours per run.
For comparison purposes, existing project capital costs are not carried forward. Only new generation,
transmission, and DSM/EE costs, as well as system fuel, O&M and emission allowance costs, are considered
when comparing the various expansion plan scenarios.
2.3.2 Strategist® and PROMOD® Overview
For the RIRP Study, Black & Veatch used Ventyx’s Strategist® optimal generation expansion model to
evaluate the various alternatives and scenarios. The Strategist® model is capable of evaluating a large number
of plans with generating, transmission, and DSM/EE alternatives by using probabilistic dispatch, dynamic
programming, and elimination of factors that typically are not taken into account when comparing thousands
(or millions) of plans, such as ramp-up and ramp-down rates and start-up energy and start-up fuel costs.
The model utilizes a typical week methodology and evaluates the relative economics between all possible
plans within a given set of criteria and minimizes utility costs through optimization. The model checks all
feasible combinations in every year of the study period using dynamic programming. At the end of the study
period, the model traces back through the matrix of feasible states to find the plans with the best financial or
other operational criteria (cumulative present worth cost in this case) and ranks these plans according to this
criteria. The plans that are shown to be most promising from an economic standpoint are then input into
Ventyx’s hourly chronological model, PROMOD®, for additional analysis with this more detailed production
costing model.
PROMOD® performs unit commitment and economic dispatch under a wide array of operation constraints
along with detailed transmission simulation. The model develops hourly generation, production costs, and
fuel consumption for generating units utilizing detailed operating characteristic inputs. Hours on-line and
start-up hours are also calculated. Transmission line information such as hourly flow and constraints are
available for output along with unserved energy. Debt service (i.e., return on investment and depreciation) for
capital additions are added externally to the operating costs developed by PROMOD®.
2.3.3 Benchmarking
With the uniqueness of the Railbelt electric system, it was important that Black & Veatch benchmark the
models’ production costing against an actual year in order to validate the models’ abilities to appropriately
model the characteristics of the Railbelt. The benchmarking exercise was based on 2008 actual data as that
was the most recent year with complete generation, transmission, and purchases and sales data to benchmark
against. Actual 2008 data was gathered from the utilities regarding generating unit performance, outages, and
costs, as well as information on purchases and sales of economy energy and corresponding costs.
PROJECT OVERVIEW
SECTION 2 AND APPROACH
ALASKA RIRP STUDY
Black & Veatch 2-6 February 2010
The goal of the benchmarking effort was to model system inputs and validate the outputs against actual values
for 2008 for each utility. Outputs to be validated were generating unit capacity factors, hydroelectric
generation amounts, generation costs, economy energy purchases and sales, and resulting costs. Wheeling
rates, fuel costs, operations and maintenance (O&M) costs, and other costs were input on a per unit basis.
Scheduled and forced outages were input directly to reflect actual unit availability.
Accurately benchmarking the Railbelt’s hydroelectric generation was important to validate the models. Much
of the Railbelt system in 2008 was powered by combined cycle and simple cycle turbines. With most of the
scheduled maintenance on combined cycles occurring in the summer months due to high electric demand in
the winter, less-efficient, more costly combustion turbines must be used for generation. When total system
costs begin to rise, hydroelectric storage units can be used to generate a portion of the Railbelt’s requirements.
The fact that storage water for hydro is finite must also be taken into account. Water levels in hydroelectric
reservoirs have minimums and maximums. The model was set up to limit the amount of generation available
in each month to avoid exhausting all of the available water in one month and not having enough remaining in
other months.
Overall, the benchmarking process verified that the models adequately reflect operation in the Railbelt for
purposes of the RIRP. While the models have limitations in their modeling of the Railbelt system, they also
have other benefits for their use in this study.
2.3.4 Hydroelectric Methodology
Strategist® treats hydroelectric generation as a load modifier, while PROMOD® offers the option of treating
hydroelectric as a load modifier or dispatching it. In Strategist® hydroelectric generating units are dispatched
one at a time. Each unit has a maximum and minimum capacity level at which it operates. Each unit can also
be given a monthly total energy that is available. The utility’s overall load is reduced by the minimum hydro
generation available in each hour. The difference between the total hydroelectric energy in the month and the
minimum hydro energy is the energy available for peak shaving. Capacity available for peak shaving is the
difference between the maximum and minimum capacities of the unit. The resulting load shape is then met
by unit dispatch of other available resources.
Black & Veatch provided the model with the monthly energy limits for hydroelectric units and allowed the
model to perform the load modifications. These limits were calculated from the average monthly historical
generation of the units provided by the utilities. Providing monthly energy limits for each hydroelectric unit
prevents the model from taking an unrealistic amount of water from the reservoirs, but still allows for
variance throughout the year. The amount of baseload energy to be met will be reduced, thereby allowing
some units to be shut down, or run minimally. This methodology will also lower the amount of load to be
met by less-efficient thermal units and lowers production costs. Peak load reduction will also work to reduce
the amount of units that need to be started to handle peak times.
There are several factors that drive hydroelectric generation in the Railbelt system. Summer maintenance
outages on other generating units can increase the amount of hydroelectric generation necessary to reduce
system costs. Limitations on the deliverability of natural gas in the winter for thermal generating units can
also drive the use of hydroelectric generation in the region. As the system ages, the correlation between
higher system costs and generating unit maintenance will be reduced as less efficient units will be retired and
replaced. With multiple factors influencing hydroelectric generation in the Railbelt region, Black & Veatch
believes that the load modification technique is an appropriate method to model hydroelectric generation in
the Railbelt. Modeling assumptions specific to each hydroelectric unit are presented in Section 4.
PROJECT OVERVIEW
SECTION 2 AND APPROACH
ALASKA RIRP STUDY
Black & Veatch 2-7 February 2010
PROMOD® offers the additional modeling feature that, on a weekly basis, PROMOD® will dispatch available
hydro energy at the times when avoided thermal unit costs are greatest. This feature was used in the
PROMOD® modeling.
2.3.5 Evaluation Scenarios
Black & Veatch, in collaboration with the Advisory Working Group, developed four Evaluation Scenarios for
this project. Black & Veatch then developed a 50-year resource plan for each of these Evaluation Scenarios.
The primary objective of these Evaluation Scenarios was to evaluate two key drivers. The first driver was to
look at what the impacts would be if the demand in the region was significantly greater than it is today; of
primary interest was to see if higher demands would result in greater reliance on large generation resource
options and allow for more aggressive expansions of the region’s transmission network.
The second driver was to determine the impact associated with the pursuit of a significant amount of
renewable resources over the 50-year time horizon.
As a result, Black & Veatch evaluated the four Evaluation Scenarios shown on Figure 2-2.
Figure 2-2
Evaluation Scenarios
PROJECT OVERVIEW
SECTION 2 AND APPROACH
ALASKA RIRP STUDY
Black & Veatch 2-8 February 2010
The key assumptions underlying each Evaluation Scenario include:
• Scenario 1 – Base Case Load Forecast
o Current regional loads with projected growth
o All available resources – fossil fuel, renewables, and DSM/EE
o Probabilistic estimate of gas supply availability and prices
o Deterministic price forecasts for other fossil fuels
o Emissions including CO2 costs
o Transmission system investments required to support selected resources
o Scenario 1A – Least Cost Plan
o Scenario 1B – Force 50% Renewables
• Scenario 2 – Large Growth Load Forecast
o Significant growth in regional loads due to economic development efforts or large scale
electrification (e.g., economic development loads, space and water heating fuel switching, and
electric vehicles)
o Base case resources, fuel availability/price forecasts and CO2 costs
o Transmission system investments required to support selected resources
o Scenario 2A – Least Cost Plan
o Scenario 2B – Force 50% Renewables
2.4 Stakeholder Input Process
One of the AEA’s directives to Black & Veatch, related to the completion of this project, was to proactively
solicit input from a broad cross-section of the Railbelt region’s stakeholders. Elements of the stakeholder
involvement process are summarized in Figure 2-3.
Figure 2-3
Elements of Stakeholder Involvement Process
PROJECT OVERVIEW
SECTION 2 AND APPROACH
ALASKA RIRP STUDY
Black & Veatch 2-9 February 2010
As the first element of this public participation process, the AEA held a two-day Technical Conference near
the beginning of the project. The purpose of this conference was to enable a number of industry participants
to provide their views regarding the broad array of issues confronting the Railbelt utilities and to provide
comments specific to the completion of this study. Approximately 100 individuals, including Black & Veatch
project team members, participated in this conference.
Additionally, Black & Veatch met with a number of non-utility stakeholders to provide them with the
opportunity to present their input directly to the Black & Veatch project team members. These meetings were
in addition to the meetings that Black & Veatch held with Railbelt utility representatives.
Black & Veatch and the AEA also held several meetings with the Advisory Working Group that was
assembled for this project. The role and membership of this Advisory Working Group is discussed in the next
subsection.
Additionally, the AEA held a second Technical Conference during which the Black & Veatch project team
presented our preliminary results, conclusions and recommendations. Subsequent to that presentation, all
stakeholders were provided the opportunity to review and comment on our Draft Report.
2.5 Role of Advisory Working Group and Membership
Another important element of this project’s stakeholder input process was the formation of an Advisory
Working Group, assembled by the AEA, which provided input to the Black & Veatch/AEA project team
throughout the study. This Group, which met five times during the course of the project, included the
following members:
• Norman Rokeberg, Retired State of Alaska
Representative, Chairman
• Chris Rose, Renewable Energy Alaska
Project
• Brad Janorschke, Homer Electric Association
• Carri Lockhart, Marathon Oil Company
• Colleen Starring, Enstar Natural Gas
Company
• Debra Schnebel, Scott Balice Strategies
• Jan Wilson, Regulatory Commission of
Alaska
• Jim Sykes, Alaska Public Interest Group
• Lois Lester, AARP
• Marilyn Leland, Alaska Power Association
• Mark Foster, Mark A. Foster & Associates
• Nick Goodman, TDX Power, Inc.
• Pat Lavin, National Wildlife
Federation - Alaska
• Steve Denton, Usibelli Coal Mine, Inc.
• Tony Izzo, TMI Consulting
The Advisory Working Group provided input on a number of project-related issues, including the following:
• Project objectives, scope, and approach
• Evaluation Scenarios to be considered
• Input assumptions for each Evaluation Scenario
• Tax and legal issues
• Preliminary results, conclusions and recommendations
• Draft Report
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-1 February 2010
3.0 SITUATIONAL ASSESSMENT
The purpose of this section is to discuss the myriad of issues facing the Railbelt electric utilities; the major
categories of issues are shown on Figure 3-1. This discussion is largely drawn from the REGA study that was
completed by Black & Veatch.
Figure 3-1
Summary of Issues Facing the Railbelt Region
Each of these issue categories is discussed below.
Cost
Issues
RAILBELT
Future
Adopt New Direction
Maintain Status Quo
Businesses and Consumers
Power Costs
Future
Resource
Options
Uniqueness
of the Railbelt
Region
Natural Gas
Issues
Infrastructure
Issues
Load
Uncertainties
Political
Issues
Cost
Issues
RAILBELT
Future
Adopt New Direction
Maintain Status Quo
Impact on Railbelt
Reliability
Sustainability
Risks
Future
Resource
Options
Uniqueness
of the Railbelt
Region
Natural Gas
Issues
Infrastructure
Issues
Load
Uncertainties
Political
Issues
Management
Risk
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-2 February 2010
3.1 Uniqueness of the Railbelt Region
In comparison to the business and operating environment of the utility industry in the lower-48 states, the
Railbelt region is unique. The following presents a summary of the more significant issues that cause the
uniqueness of the Railbelt region:
Issue Description
Size and Geographic
Expanse
First, the overall size of the Railbelt region is small when compared to other
utilities or areas. The total combined peak load of all six utilities is
approximately 870 MW. When compared to the peak loads of other utilities
throughout the U.S., a combined “Railbelt utility” would still be relatively small.
As an example, many electric utilities have single coal or nuclear plants that
exceed 900 MW of capacity (based on Energy Information Administration plant
data, there are 100 generating units in the U.S. with nameplate capacity greater
than 900 MW). This relative size, coupled with the geographic expanse and
diversity of the Railbelt region, creates certain issues and affects the solutions
available to the Railbelt utilities.
Limited Interconnections
and Redundancies
The Railbelt electric transmission grid has been described as a long straw, as
opposed to the integrated, interconnected, and redundant grid that is in place
throughout the lower-48 states. This characterization reflects the fact that the
Railbelt electric transmission grid is an isolated grid with no external
interconnections to other areas and that it is essentially a single transmission line
running from Fairbanks to the Kenai Peninsula, with limited total transfer
capabilities and redundancies.
As a consequence, each Railbelt utility is required to maintain much higher
generation reserve margins than elsewhere in order to ensure reliability in the
case of a transmission grid outage. Furthermore, the lack of interconnections
and redundancies exacerbates a number of the other issues facing the Railbelt
region.
3.2 Cost Issues
The following issues relate to the current cost structure of the Railbelt utilities.
Issue Description
Relative Costs – Railbelt
Region Versus Other
States
Alaska has the seventh highest cost of any state based on the total cost per kWh,
as shown in Table 3-1. Alaska’s average retail rate was 13.3 cents per kWh; in
comparison, Hawaii was the highest ranked state at 21.3 cents per kWh and
Idaho was the lowest at 5.1 cents per kWh. The U.S. average was 9.1 cents per
kWh.
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-3 February 2010
Issue Description
Relative Costs – Among
Railbelt Utilities
ML&P’s customers pay the lowest monthly electric bills in the region; GVEA’s
residential customers pay the highest monthly bills. Chugach, MEA, Seward
and Homer are in the middle.
Table 3-2 provides a comparison of the monthly electric bills paid by the
residential, small commercial and large commercial customers of each of the six
Railbelt utilities. Monthly bills are shown for residential customers assuming
average monthly usage of 750 kWh based upon the rates of each Railbelt utility.
Also shown are the monthly bills paid by small commercial (10,000 kWh
average monthly usage) and large commercial (150,000 kWh average monthly
usage) customers.
Economies of Scale The Railbelt utilities have not been able to take full advantage of economies of
scale and scope. With respect to scale economies, there are several reasons that
the region has been limited by scale constraints. First, as previously noted, the
combined peak load of the six Railbelt utilities is still relatively small. Second,
the Railbelt transmission grid’s lack of redundancies and interconnections with
other regions has placed reliability-driven limits on the size of generation
facilities that could be integrated into the Railbelt region.
Third, the fact that each utility has developed their own long-term resource plans
has led to less optimal results (from a regional perspective) relative to what
could be accomplished through a rational, fully coordinated regional planning
process. Finally, the existence of six separate utilities, and their small size on an
individual utility basis, has restricted their ability to take advantage of economies
of scale with regards to staffing and their skill sets. For example, the
development of six separate programs to develop and deliver DSM and energy
efficiency programs is a considerably more difficult challenge than would be the
case if there was one regional entity responsible for developing and delivering
DSM and energy efficiency programs to residential and commercial customers
throughout the Railbelt region.
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-4 February 2010
Table 3-1
Relative Cost per kWh (Alaska Versus Other States) - 2007
Name
Average Retail Price
(cents/kWh) Name
Average Retail Price
(cents/kWh)
Hawaii 21.29 North Carolina 7.83
Connecticut 16.45 Colorado 7.76
New York 15.22 Alabama 7.57
Massachusetts 15.16 Minnesota 7.44
Maine 14.59 New Mexico 7.44
New Hampshire 13.98 Oklahoma 7.29
Alaska 13.28 South Carolina 7.18
Rhode Island 13.12 Montana 7.13
New Jersey 13.01 Virginia 7.12
California 12.80 Tennessee 7.07
Vermont 12.04 Oregon 7.02
District of Columbia 11.79 Arkansas 6.96
Maryland 11.50 South Dakota 6.89
Delaware 11.35 Kansas 6.84
Florida 10.33 Iowa 6.83
Texas 10.11 Missouri 6.56
Nevada 9.99 Indiana 6.50
Pennsylvania 9.08 North Dakota 6.42
Arizona 8.54 Utah 6.41
Michigan 8.53 Washington 6.37
Wisconsin 8.48 Nebraska 6.28
Illinois 8.46 Kentucky 5.84
Louisiana 8.39 West Virginia 5.34
Mississippi 8.03 Wyoming 5.29
Ohio 7.91 Idaho 5.07
Georgia 7.86 US Average 9.13
Source: Energy Information Administration, “State Electricity Profiles,” DOE/EIA-0348, April 2009.
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-5 February 2010
Table 3-2
Relative Monthly Electric Bills Among Alaska Railbelt Utilities
RESIDENTIAL
Fuel
Adjustment
Regulatory
Cost
Charge
Energy
Charge
Total Energy
Charge
Customer
Charge
Usage Factor
(kWh) Typical Bill
GVEA 0.05903 0.000274 0.11153 0.170834 15 750 $143.13
Chugach 0.02478 0.000274 0.09282 0.117874 8.42 750 $96.83
MEA 0.03084 0.000274 0.09447 0.125584 5.65 750 $99.84
ML&P -0.00655 0.000274 0.09476 0.088484 6.56 750 $72.92
Homer (North of
Kachemak Bay)
0.00078 0.000274 0.12718 0.128234 11 750 $107.18
Homer (South of
Kachemak Bay)
0.00078 0.000274 0.13056 0.131614 11 750 $109.71
City of Seward NA NA NA NA NA NA NA
Average $104.93
SMALL
COMMERCIAL
Fuel
Adjustment
Regulatory
Cost
Charge
Energy
Charge
Total Energy
Charge
Customer
Charge
Usage Factor
(kWh) Typical Bill
GVEA 0.05903 0.000274 0.10957 0.168874 20 10,000 $1,708.74
Chugach 0.02478 0.000274 0.08001 0.105064 18.26 10,000 $1,068.90
MEA 0.03084 0.000274 0.07677 0.107884 5.65 10,000 $1,084.49
ML&P -0.00655 0.000274 0.09182 0.085544 12.88 10,000 $868.32
Homer (North of
Kachemak Bay)
0.00078 0.000274 0.1181 0.119154 24 10,000 $1,215.54
Homer (South of
Kachemak Bay)
0.00078 0.000274 0.11479 0.115844 40 10,000 $1,198.44
City of Seward NA NA NA NA NA NA NA
Average $1,190.74
LARGE
COMMERCIAL
Fuel
Adjustment
Regulatory
Cost
Charge
Energy
Charge
Total Energy
Charge
Customer
Charge
Demand
Charge
Usage
Factor
(kWh)
Demand
Usage (kW)Typical Bill
GVEA 0.05903 0.000274 0.7835 0.137654 50 8.55 150,000 500 $24,973.10
Chugach 0.02478 0.000274 0.0462 0.071254 58.85 11.65 150,000 500 $16,571.95
MEA 0.03084 0.000274 0.06004 0.091154 13.37 4.85 150,000 500 $16,111.47
ML&P -0.00655 0.000274 0.05351 0.047234 44.15 11.85 150,000 500 $13,054.25
Homer (South of
Kachemak Bay)
0.00078 0.000274 0.11479 0.115844 40 6.73 150,000 500 $20,781.60
City of Seward NA NA NA NA NA NA NA NA NA
Average $18,298.47
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-6 February 2010
3.3 Natural Gas Issues
The Railbelt utilities use Cook Inlet natural gas as a significant generation fuel source and have done so for
decades; the future ability of the Railbelt region to continue to rely on natural gas is in question.
Issue Description
Historical Dependence Natural gas has been the predominant source of fuel for electric generation used
by the customers of ML&P, Chugach, MEA, Homer and Seward. Additionally,
customers in Fairbanks have benefited from natural gas-generated economy
energy sales in recent years.
For example, Figure 3-2 shows the current dependence that Chugach (as well as
MEA, Homer and Seward as a result of their full requirements contracts with
Chugach) has on natural gas-fired generation, based on 2007 statistics. ML&P
has a similar level of dependence on natural gas.
Expiring Contracts There are a number of inherent risks whenever a utility or region is so dependent
upon one fuel source; risks with regard to prices, availability and deliverability.
An additional risk faced by Chugach is the fact that its current gas supply
contracts are expected to expire in the 2010-2012 timeframe.
Chugach is currently working with its natural gas suppliers to renegotiate these
contracts. Although those negotiations are have not all been finalized, it is
expected that future natural gas prices paid by Chugach will increase once the
existing contracts expire.
Declining Developed
Reserves and
Deliverability
An additional problem faced by the Railbelt utilities, due to their dependence on
natural gas, is the fact that existing developed reserves in the Cook Inlet are
declining as well as the current deliverability of that gas. This is shown in
Figure 3-3.
As can be seen in Figure 3-3, the population of the Anchorage, Mat-Su, and
Kenai Peninsula areas has increased 170% from 1970 to 2005. At the same
time, known reserves in the Cook Inlet have declined by 80%. As a result, one
prediction is that gas supplies from known reserves will meet less than one-half
of the residential and commercial demand for heating and electricity by 2017.
This will have a significant impact on all Railbelt utilities, including ML&P as
its owned gas supply is experiencing the same dynamics.
Related to the decline in reserves is the decline in deliverability. Historically,
deliverability of natural gas to electric generation facilities, and to residential and
commercial customers in the Railbelt region for heating, was not a problem.
However, deliverability is increasingly becoming an issue as the Cook Inlet gas
fields age, reserves decline, and pressures drop.
Consequently, the Railbelt region will not be able to continue its dependence
upon natural gas in the future unless additional reserves are discovered in the
Cook Inlet, new sources of supply become available from the North Slope, or a
liquefied natural gas (LNG) import terminal is developed to supplement Cook
Inlet supplies.
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-7 February 2010
Issue Description
Historical Increase in
Gas Prices
Railbelt residential and commercial customers are directly feeling the rise in
natural gas prices that have occurred in recent years. These price increases are
shown in Figure 3-4, which shows historical gas prices paid by Chugach.
Figure 3-5 shows the resulting rise in Chugach’s residential bills from 1994 to
2007. As can be seen, the fuel component of the customer’s bill has increased
significantly in recent years while the base rate component has remained roughly
the same until very recently. With natural gas prices expected to continue
increasing, Railbelt consumers and businesses will experience even greater
electric prices in the future.
Potential Gas Supplies
and Prices
Regardless of the future source of additional natural gas supplies (whether new
gas supplies from the Cook Inlet, gas from the North Slope, or imported LNG
supplies), one reality can not be escaped: future gas supply prices will be higher.
For additional gas supplies in the Cook Inlet to become available, prices will
need to increase to encourage exploration and development. This results from
the fact that oil and gas producers make investment decisions based upon
expected returns relative to investment opportunities available elsewhere in the
world.
In the case of North Slope gas supplies, the cost, probability and timing of
potential gas flows to the Railbelt region are unknown at this time.
Nevertheless, given the construction lead times for a potential gas pipeline to
provide gas from the North Slope, gas from that region is unlikely to be
available for a number of years. Furthermore, if gas from the North Slope
becomes available in the Railbelt region through either the Bullet Line or Spur
Line, prices will be tied to market prices since potential natural gas flows to the
Railbelt region will be just one of the competing demands for the available gas.
Additionally, the pipeline transmission rates that will be paid to move gas to the
Railbelt region will be significantly higher than the transportation rates that are
imbedded in the delivered cost of gas from Cook Inlet suppliers under existing
contracts.
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-8 February 2010
Figure 3-2
Chugach’s Reliance on Natural Gas
7%
93%
Natural Gas-Fired Hydro
Total Power Produced in 2007: 2,628 gWh
Source: Chugach Electric Association.
Figure 3-3
Overview of Cook Inlet Gas Situation
1970 2005
147,150
398,626
Population of
Anchorage, Mat-Su,
and Kenai Peninsula
up 170% Since 1970
Source: Alaska Department of Labor, Alaska Division of Oil and Gas, and Science Applications International Corporation.
8.8
1.7
All
Discoveries
2005
Reserves
Known Reserves
Down 80%
(In trillion cubic feet)
Supply Demand
Supply From Known
Reserves Projected
to Meet Half of
Demand for
Residential and
Commercial Heating
and Electricity
By 2017
(In billion cubic feet)
44
95
1970 2005
147,150
398,626
Population of
Anchorage, Mat-Su,
and Kenai Peninsula
up 170% Since 1970
1970 2005
147,150
398,626
Population of
Anchorage, Mat-Su,
and Kenai Peninsula
up 170% Since 1970
Source: Alaska Department of Labor, Alaska Division of Oil and Gas, and Science Applications International Corporation.
8.8
1.7
All
Discoveries
2005
Reserves
Known Reserves
Down 80%
(In trillion cubic feet)
8.8
1.7
All
Discoveries
2005
Reserves
Known Reserves
Down 80%
(In trillion cubic feet)
Supply Demand
Supply From Known
Reserves Projected
to Meet Half of
Demand for
Residential and
Commercial Heating
and Electricity
By 2017
(In billion cubic feet)
44
95
Supply Demand
Supply From Known
Reserves Projected
to Meet Half of
Demand for
Residential and
Commercial Heating
and Electricity
By 2017
(In billion cubic feet)
44
95
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-9 February 2010
Figure 3-4
Historical Chugach Natural Gas Prices Paid
$-
$2
$4
$6
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008$ per mcfChugach
Source: Chugach Electric Association.
Figure 3-5
Chugach Residential Bills Based on 700 kWh Consumption
1994 – 2007
Total
Residential
Bill
$35
$45
$55
$65
$75
$85
$95
$105
1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006Total Bill ($)Fuel and Power
Production Expense
Base Rate Revenue
(A&G, O&M, customer expense, debt service costs and margins)
2007
Total
Residential
Bill
$35
$45
$55
$65
$75
$85
$95
$105
1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006Total Bill ($)Fuel and Power
Production Expense
Base Rate Revenue
(A&G, O&M, customer expense, debt service costs and margins)
2007 Source: Chugach Electric Association.
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-10 February 2010
3.4 Load Uncertainties
Load uncertainties are always an issue of concern for electric utilities as they make investment decisions
regarding which generation resources to add to their system.
Issue Description
Stable Native Growth With regard to native load growth (e.g., normal load growth resulting from
residential and commercial customers), Railbelt utilities have experienced stable
growth in recent years. This stable native load growth is expected to continue in
the years ahead, absent significant economic development gains in the region.
Potential Major New
Loads
There are, however, a number of potential significant load additions that could
result from economic development efforts. These potential load additions could
result from the development of new, or expansion of existing, mines
(e.g., Pebble and Donlin Creek), continued military base realignment, and other
economic development efforts or the enactment of policies that would result in
increased electric loads (e.g., gas to electric fuel switching, electric vehicles,
etc.). Additionally, there will likely be a significant increase in Railbelt
population if the proposed North Slope natural gas pipeline, and or the Spur Line
or Bullet Line, is built.
Any significant growth in Railbelt electric loads will lead to increased stress on
the ability of the region’s utilities to meet demand, particularly if this demand
has to be met by one utility. This is particularly true given the fact that a
significant portion of the Railbelt’s electric generation facilities are approaching
their planned retirement dates.
3.5 Infrastructure Issues
The challenges faced by the Railbelt utilities are magnified by the aging nature of existing generation
facilities in the region.
Issue Description
Aging Generation
Infrastructure
Approximately 67 percent of the existing generation capability within the
Railbelt region is scheduled to be retired within 15 years. During this period,
decisions relative to retirement, refurbishment, and life extension must be made.
Replacing this capacity with more efficient capacity requires substantial new
capital investment, which is offset by the lower cost of generation with better
heat rates or when plants incorporate lower fuel cost resources.
Baseload Usage of
Inefficient Generation
Facilities
Another issue that is directly related to the aging nature of the existing Railbelt
generation fleet is the fact that certain older, inefficient generation units are
being used as baseload, or near-baseload, generation facilities, raising regional
operating costs. Since the cost of energy production is a combination of fuel
costs and heat rate, the combination of rising energy costs and more production
from high heat rate units causes large increases in the cost of energy. As more
high heat rate units operate more hours, the average cost of power increases even
without a fuel cost increase. In addition, it is typical that as generation units
mature past the mid-point of their average life there is a strong likelihood that
heat rates will rise the further their age goes beyond the mid-point of the
expected life.
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-11 February 2010
Issue Description
Operating and Spinning
Reserve Requirements
Railbelt reliability criteria require spinning reserves equal to the largest
operating unit and an operating reserve level of an additional 50% of the largest
unit. In addition, the region’s system target reserve margin is set at 30%. These
reserve levels reflect the absence of interconnections, the relative operating
impacts of limited resources and the necessity of maintaining reliability with the
existing size of the system. Such high reserve margins affect total fuel and
maintenance costs.
3.6 Future Resource Options
There are several issues regarding the future resource options that will be available to meet demand within the
Railbelt region.
Issue Description
Acceptability of Large
Hydro and Coal
Much discussion has occurred in recent years about the future role that large
hydroelectric and coal projects might play in meeting the electricity needs of the
Railbelt region. Like other parts of the country and the world, the acceptability
and economics of large hydroelectric and coal facilities are uncertain. Resolving
the acceptability issues, and other related economic and environmental issues,
associated with large hydro and coal will require the active involvement of the
Governor and Legislature, as well as the Railbelt utilities and other stakeholders.
Carbon Tax and Other
Environmental
Restrictions
Another uncertainty facing the Railbelt utilities relates to the restrictions on
carbon emissions, and the related economic impact, that might be imposed by
Federal and/or State legislation, as well as other environmental restrictions
(e.g., mercury limits) that will impact the technical and economic feasibility of
various generation technologies. In the case of the imposition of carbon taxes,
bills are currently working their way through the Federal legislative process, and
additional bills may be introduced in the future. These bills each have different
targets for the reduction of carbon emissions, and each will result in different
levels of carbon taxes and/or different costs for the capturing and sequestering of
carbon emissions. Depending upon the form of Federal and/or State carbon
legislation ultimately enacted, the economics of fossil-fueled generation
technologies could be significantly impacted.
Optimal Size and
Location of New
Generation and
Transmission Facilities
Given the need to replace existing generation facilities and meet expected load
growth, significant investments in new generation resources will be required. A
very important issue that needs to be addressed by the Railbelt utilities is the
optimal size and location of new generation and transmission facilities. This is,
in fact, one of the factors driving the interest in the formation of a regional
generation and transmission entity, and one of the primary reasons why this
RIRP project was commissioned. When individual utilities make resource
decisions that optimize the future resource mix for their own needs, the resulting
regional resource mix will simply not be as optimal relative to the resource mix
that result from a regional planning process. Additionally, decisions that will be
made with regard to improving and expanding the Railbelt electric transmission
grid will have a direct bearing of determining the optimal size and location of
future generation resources.
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-12 February 2010
Issue Description
Limited Development –
Renewables
Renewable generation technologies represent a significant opportunity for the
Railbelt utilities relative to replacing aging generation facilities and meeting
future load growth. To date, the Railbelt utilities have developed renewable
resource technologies to a very limited degree, relative to the technical potential
of these resources as well as relative to the level of deployment of these
technologies in other regions of the country. While this limited use of renewable
resources reflects, to a certain degree, the challenges of integrating such
resources into a transmission-constrained grid and managing the power
fluctuations on an individual utility basis, enhanced transmission infrastructure
and regional coordination will create additional opportunities for renewables as
part of the portfolio of resources.
The issue of integrating technologies having variable outputs (i.e., non-
dispatchable resources), such as wind and solar, into a fossil-fueled grid presents
substantial operational challenges including the determination of the optimal
level of these resources.
Additionally, an important issue related to the implementation of renewables that
needs to be addressed is whether the development of renewable resources should
be accomplished by the individual Railbelt utilities or whether a regional
approach would result in the more efficient and cost-effective deployment of
these resources.
Limited Development –
DSM/EE Programs
Similar to the comments above related to renewable resource technologies, the
Railbelt utilities have limited experience with the planning, developing and
delivering of DSM/EE programs. To date, the majority of efforts in the Railbelt
region and the State as a whole have been focused on the implementation of
home weatherization programs. These programs can significantly reduce the
energy consumption within individual homes; however, given the limited
saturation of electric space heating equipment and the general lack of air
conditioning loads, the potential for DSM/EE programs are limited from the
perspective of the Railbelt electric utilities. Notwithstanding this, additional
opportunities do exist in this area.
An implementation issue that needs to be addressed is whether the development
and deployment of DSM/EE programs throughout the Railbelt region should be
accomplished by the individual Railbelt utilities or whether a regional approach
would result in more efficient and cost-effective deployment of these resources.
Additionally, given the fact that the total monthly energy bills paid by residential
and commercial customers in the Railbelt have increased significantly in recent
years and given that natural gas is the predominant form of space heating within
the majority of the Railbelt region, it may be appropriate for the electric utilities
to work jointly with Enstar to develop DSM/EE programs that would be
beneficial to both. This would create economies of scope for the region and
reduce the delivery costs of DSM/EE programs.
SECTION 3 SITUATIONAL ASSESSMENT
ALASKA RIRP STUDY
Black & Veatch 3-13 February 2010
3.7 Political Issues
The following political issues impact the current situation in the Railbelt region.
Issue Description
Historical Dependence
on State Funding
The Railbelt utilities have been dependent upon State funding for certain
portions of the regional generation and transmission infrastructure, as well as for
certain local infrastructure investments. Some of these investments have been
made through the Railbelt Energy Fund; others have been direct appropriations
by the Legislature. Regional State-funded infrastructure investments include the
Alaska Intertie and Bradley Lake Hydroelectric Plant.
Proper Role for State Historical State infrastructure-related investments have provided significant
benefits to the residential and commercial customers in the Railbelt. Going
forward, one question that needs to be answered is what the proper role of the
State should be relative to the further development of the Railbelt region’s
generation and transmission infrastructure.
3.8 Risk Management Issues
The following issues relate to risk management, which has become increasingly important for all utilities.
Issue Description
Need to Maintain
Flexibility
As previously discussed, the recent increase in natural gas prices highlights the
dangers inherent with an over-reliance on one fuel source or generation
technology. Just as investors rely on a portfolio of assets, it is important for
utilities to develop a portfolio of assets to ensure safe, reliable and cost-effective
service to customers. It also demonstrates the importance of maintaining
flexibility.
Future Fuel Diversity Fuel supply diversity inherently has value in terms of risk management. Simply
stated, the greater a region’s dependence upon one fuel source, the less
flexibility the region will have to react to future price and availability problems.
Aging Infrastructure The fact that the generation and transmission infrastructure in the Railbelt region
is aging, and that a significant percentage of the region’s generation units are
approaching the end of their expected lives, adds to the challenges facing utility
managers. That represents the “half empty” view of the situation. The “half
full” views leads one to a more positive perspective that the region has an
unprecedented opportunity to diversify its resource mix and improve the overall
efficiency of its generation fleet.
Ability to Spread
Regional Risks
The level of uncertainty facing the Railbelt region continues to grow, as do the
risks attendant to utility operations. One important approach to risk management
is to spread the risk to a greater base of investors and consumers so that the
impact of those risks on individuals is reduced. Simply stated, the ability of the
region to absorb the risks facing it is greater on a regional basis than it is on an
individual utility basis.
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-1 February 2010
4.0 DESCRIPTION OF EXISTING SYSTEM
This section contains a general description of the generation and transmission resources currently in use in the
Railbelt region. The existing system data was provided by the Railbelt utilities in response to data requests by
Black & Veatch. Black & Veatch reviewed the data and, where necessary, applied judgment to the data to
obtain a consistent set of existing system data for planning purposes. Detailed information on each existing
generating unit is presented in Appendix C.
4.1 Existing Generating Resources
4.1.1 Anchorage Municipal Light & Power
ML&P operates seven combustion turbines (Units 1-5, 7, and 8) between two power plants, which operate on
natural gas, and one steam turbine (Unit 6), which derives its steam from un-fired heat recovery steam
generators (HRSGs). Units 1 and 2 are not available for normal dispatch, but are available if needed in an
emergency. Unit 4 is dispatched on a normal, but infrequent basis. For this study, Units 1, 2, and 4 were not
modeled. ML&P’s other units provide approximately 280 MW of generating capability. Combustion
turbines 5 and 7 have HRSGs, which allow them to operate in a combined cycle mode with the Unit 6 steam
turbine. Unit 5 is frequently cycled when used in combined cycle or simple cycle mode. Unit 5 or Unit 7
may be operated in simple cycle mode when the steam turbine is unavailable. ML&P’s existing thermal units
are shown in Table 4-1.
Table 4-1
ML&P Existing Thermal Units
Name Unit Primary Fuel
Winter
Rating
(MW)
Retirement
Date
Anchorage ML&P – Plant 1 1(1) Natural Gas 16.2 N/A
Anchorage ML&P – Plant 1 2(1) Natural Gas 16.2 N/A
Anchorage ML&P – Plant 1 3 Natural Gas 32 2037
Anchorage ML&P – Plant 1 4(1) Natural Gas 34.1 N/A
Anchorage ML&P – Plant 2 5 Natural Gas 37.4 2020
Anchorage ML&P – Plant 2 5/6 Natural Gas 49.2 2020
Anchorage ML&P – Plant 2 7 Natural Gas 81.8 2030
Anchorage ML&P – Plant 2 7/6 Natural Gas 109.5 2020
Anchorage ML&P – Plant 2 8 Natural Gas 87.6 2030
Anchorage ML&P – Plant 2 6 N/A N/A 2030
(1)Denotes units not included in modeling for this study.
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-2 February 2010
4.1.2 Chugach Electric Association
Chugach operates 13 combustion turbines between three power plants (Bernice 2-4, Beluga 1-7, and
International 1-3) which operate on natural gas and one steam turbine (Beluga 8) which derives its steam from
HRSGs. Chugach has approximately 500 MW of generating capability. Chugach’s existing thermal units are
shown in Table 4-2.
Table 4-2
Chugach Existing Thermal Units
Name Unit Primary Fuel
Winter
Rating
(MW)
Retirement
Date
Bernice 2 Natural Gas 19 2014
Bernice 3 Natural Gas 25.5 2014
Bernice 4 Natural Gas 25.5 2014
Beluga 1 Natural Gas 17.5 2011
Beluga 2 Natural Gas 17.5 2011
Beluga 3 Natural Gas 66.5 2014
Beluga 5 Natural Gas 65 2017
Beluga 6 Natural Gas 82 2020
Beluga 6/8 Natural Gas 108.5 2014
Beluga 7 Natural Gas 82 2021
Beluga 7/8 Natural Gas 108.5 2014
International 1 Natural Gas 14 2011
International 2 Natural Gas 14 2011
International 3 Natural Gas 19 2012
4.1.3 Golden Valley Electric Association
GVEA’s generating capability of 278 MW is supplied by four generating facilities. The Healy Power Plant is
a 27 MW coal-fired unit located adjacent to the Usibelli Coal Mine. GVEA’s 187 MW North Pole Power
Plant is oil-fired and built next to the Flint Hills refinery. The oil-fired Zehnder Power Plant in Fairbanks can
provide 39 MW. The Delta Power Plant (DPP), formerly the Chena 6 Power Plant, can produce 26 MW.
GVEA’s existing thermal units are shown in Table 4-3.
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-3 February 2010
Table 4-3
GVEA Existing Thermal Units
Name Unit Primary Fuel
Winter
Rating
(MW)
Retirement
Date
Zehnder GT1 HAGO 19.2 2030
Zehnder GT2 HAGO 19.6 2030
North Pole GT1 HAGO 62.6 2017
North Pole GT2 HAGO 60.6 2018
North Pole GT3 NAPHTHA 51.3 2042
North Pole ST4 STEAM 12 2042
Healy ST1 COAL 27 2022
DPP 1 HAGO 25.8 2030
4.1.4 Homer Electric Association
HEA owns the natural gas Nikiski combustion turbine. During the summer months it can produce a
maximum of 35 MW, whereas in the winter it provides 42 MW. This unit is shown in Table 4-4.
Table 4-4
HEA Existing Thermal Units
Name Unit Primary Fuel
Winter
Rating
(MW)
Retirement
Date
Nikiski 1 Natural Gas 42.0 2026
4.1.5 Matanuska Electric Association
MEA does not have any existing thermal units.
4.1.6 Seward Electric System
The City of Seward currently has three diesel generators in operation, each with capacities of 2.5 MW, and
one diesel generator with a capacity of 2.9 MW. In this study, these small existing diesel generators are not
included since the City of Seward is a full requirements customer of Chugach and the existing diesels are
mainly used for back-up.
4.1.7 Hydroelectric Resources
Currently, each of the utilities in the Railbelt region has full or partial ownership in existing hydroelectric
generation facilities. The hydroelectric generation plants include Bradley Lake (a 120 MW hydroelectric
plant that under normal conditions dispatches up to 90 MW and provides an additional 27 MW of spinning
reserves), Eklutna Lake hydroelectric facility (maximum capacity of 40 MW), and Cooper Lake hydroelectric
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-4 February 2010
facility (20 MW of capacity). Table 4-5 gives the percent ownership, average annual energy, and capacity for
each utility for each of the existing hydroelectric plants. In the existing system, hydroelectric capacity and
energy allocations are based on percent ownership, but in the RIRP modeling runs, all hydroelectric
generation is placed geographically such that capacity and energy enter the Railbelt system from the areas in
which the projects are physically located. The annual and monthly energy is based on the average historical
energy generated at each plant for the previous 9-10 years (depending on historical plant data provided) and is
presented in Table 4-6.
Table 4-5
Railbelt Hydroelectric Generation Plants
Bradley Lake(1) Eklutna Lake Cooper Lake
Utility
Percent
Allocation
Annual
Energy
(MWh)
Capacity
(MW)
Spinning
Reserves
(MW)
Percent
Allocation
Annual
Energy
(MWh)
Capacity
(MW)
Percent
Allocation
Annual
Energy
(MWh)
Capacity
(MW)
MEA 13.8 54,383 12.4 3.7 16.7 26,056 6.7 0 0 0
HEA 12 47,289 10.8 3.2 0 0 0 0 0 0
CEA 30.4 119,800 27.4 8.2 30 46,806 12 100 41,342 20
GVEA 16.9 66,599 15.2 4.6 0 0 0 0 0 0
ML&P 25.9 102,066 23.3 7 53.3 83,159 21.3 0 0 0
SES 1 3,941 0.9 0.3 0 0 0 0 0 0
Total 100 394,078 90 27 100 156,021 40 100 41,342 20
(1)The values for capacity and spinning reserves represent normal operation. The plant has a nameplate capacity of 126 MW with a nominal
rating of 120 MW.
Table 4-6
Hydroelectric Monthly and Annual Energy (MWh)
Month
Bradley
Lake
Eklutna
Lake
Cooper
Lake
January 28,688 11,153 3,696
February 29,448 10,653 3,421
March 31,737 12,374 3,967
April 28,829 12,039 3,687
May 28,643 10,094 3,854
June 31,586 13,425 4,072
July 35,372 14,547 4,361
August 37,881 17,954 3,328
September 37,728 17,494 3,388
October 37,654 14,102 2,421
November 34,152 11,452 2,198
December 32,360 10,734 2,951
Total 394,078 156,021 41,342
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-5 February 2010
4.1.8 Railbelt System
Table 4-7 shows the resulting total capacity for each utility within the Railbelt region.
Table 4-7
Railbelt Installed Capacity
Utility
Thermal
Existing
Capacity
Bradley
Lake
Capacity(1)
Eklutna
Lake
Capacity
Cooper
Lake
Capacity Total
MEA 0 16.1 6.7 0 22.8
HEA 42 14.0 0 0 56.0
CEA 500.5 35.6 12 20 568.1
GVEA 278.1 19.8 0 0 297.9
ML&P 278.3 30.3 21.3 0 329.9
SES 0 1.2 0 0 1.2
Total 1,098.9 117 40 20 1,275.9
(1)The nameplate rating for Bradley Lake is 126 MW with 90 MW dispatchable
and 27 MW available for spinning reserves under normal conditions.
4.2 Committed Generating Resources
Committed generating resources are generating units planned by the individual Railbelt utilities and which are
considered committed for installation by the individual Railbelt utilities. Table 4-8 summarizes the cost and
performance estimates for the committed units. The cost and performance information was either provided by
the individual Railbelt utilities or estimated by Black & Veatch. Cost information is presented in 2009
dollars. The following subsections briefly describe each of the committed units. The committed units are not
included in the Reference Case Scenarios; this is discussed further in Section 13.
4.2.1 Southcentral Power Project
The Southcentral Power Project, previously known as the South Central Alaska Power Project, is a 3x1
natural gas fired, combined cycle project that utilizes GE LM6000 combustion turbines for a total capacity of
approximately 180 MW. Currently, the project is to be jointly owned by Chugach and ML&P with 70 percent
of the capacity owned by Chugach and the remaining 30 percent to be owned by ML&P. For modeling
purposes, the entire 180 MW is included in the Anchorage area, which is comprised of both Chugach’s and
ML&P’s service areas. The capital cost for the Southcentral Power Project is approximately $370 million
with an estimated 2013 commercial operation date. A significant portion of the cost of this unit has already
been spent.
4.2.2 ML&P Units
ML&P plans to add two units to its system by 2014. The addition of these units will allow ML&P to retire
some of its older, less efficient units. In 2012, ML&P plans to install a GE LM2500 simple cycle combustion
turbine with an estimated output of 30 MW. The capital cost associated with this unit is estimated to be
$43 million in 2009 dollars. ML&P also plans to construct a GE LM6000 combined cycle plant for
commercial operation by 2014. The output of this plant is estimated at 58 MW. The capital cost associated
with this project is approximately $95 million in 2009 dollars.
SECTION 4 DESCRIPTION OF EXISTING SYSTEM ALASKA RIRP STUDY Black & Veatch 4-6 February 2010 Table 4-8 Railbelt Committed Generating Resources(1) Plant Name Area Capital Cost ($000) Maximum Winter Capacity (MW) Full Load Heat Rate (Btu/kWh) Variable O&M ($/MWh) Fixed O&M ($/kW-yr) Commercial Online Date Southcentral Power Project Anchorage 370,000 180 7,091 4.29 15.38 2013 ML&P 2500 Simple Cycle Anchorage 43,200 30 9,960 2.32 28.72 2012 MLP LM6000 Combined Cycle Anchorage 95,200 58 7,091 2.32 26.45 2014 Healy Clean Coal Project GVEA 95,000 50 11,090 8.44 79.53 2011/2014 HEA Aeroderivative HEA (2) 34 8,800 3.85 64.42 2014 HEA Frame HEA (2) 42 11,500 3.08 79.07 2014 Nikiski Upgrade HEA (2) 77 (34 incremental) 10,000 2.91 4.83 2012 Eklutna Generation Station MEA 356,000 187 8,500 4.29 15.38 2015 Seward Diesel #N1 City of Seward 7,200 2.9 9,200 11.41 31.93 2010 Seward Diesel #N2 City of Seward 1,100 2.5 9,200 11.41 31.93 2011 (1) 2009 dollars (2)HEA has requested that their cost estimates remain confidential while they are obtaining their bids.
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-7 February 2010
4.2.3 Healy Clean Coal Project
The Healy Clean Coal Project (HCCP) resulted from a nationwide competition held by the Department of
Energy (DOE) to address the issues surrounding acid rain. The project is located adjacent to Golden Valley’s
current Healy 1 coal-fired power plant. HCCP utilizes a staged combustion process and other methods to
minimize the formation of nitrogen and sulfur oxides. Construction and testing of the project was completed
in December 1999, but issues were raised concerning the operations and maintenance cost, reliability, and
safety of the project 1.
After several years of legal disputes, an agreement was reached for the sale of HCCP to GVEA. GVEA will
pay $50 million for the plant “as is” and will have a line of credit up to $45 million to get the unit operating
up to GVEA’s standards and to integrate the plant into its system. For the RIRP, Black & Veatch has
assumed the entire $95 million will be paid by GVEA. The project has an assumed commercial on-line date
of 2011, but is expected to have poor reliability initially. GVEA will back up 100 percent of the plant’s
output with spinning reserve and its battery energy storage system (BESS) until plant reliability improves and
settles by 2014. For modeling purposes, Black & Veatch has assumed a 50 percent forced outage rate for
HCCP beginning in 2011 and decreasing linearly to the steady state forced outage rate of 3 percent in 2014.
Because the HCCP is currently built, it is considered as an alternative in all the model runs except for the
committed units case, where it is forced in along with the other committed units in this section.
4.2.4 HEA Units
Currently, HEA is an all requirements customer of Chugach in that they receive all of their electric needs
from Chugach. The existing agreement expires in 2014 at which time HEA plans to supply its own load. In
order to reliably serve its customers at that time, HEA must have generation built or supply contracts to
support its service area. HEA has indicated plans to upgrade one of its existing units and build two new units
before becoming independent. In 2012, HEA plans to complete an upgrade of its existing Nikiski unit from
simple cycle to a combined cycle configuration. The upgrade would add 34 MW to the power plant and bring
the plant’s capacity from 43 MW to 77 MW. HEA is also planning to construct a new simple cycle
aeroderivative unit in 2014 with approximately 34 MW of capacity. HEA may purchase reserves instead of
installing the aeroderivative. Also in 2014, HEA plans to build a simple cycle frame unit with approximately
42 MW of capacity.
4.2.5 MEA Units
In a situation similar to that of HEA, MEA is currently an all requirements customer of Chugach and plans to
be responsible for supplying their own load by 2015. In order to provide reliable service to MEA’s
customers, it must plan to build generation at that time. Currently, MEA’s only source of power generation is
the Eklutna hydroelectric power plant. MEA plans to build the Eklutna Generation Station in 2015 with an
estimated 180 MW of natural gas fired capacity. Since the project is in the early stages of conceptualization,
much of the unit’s performance and cost information have been estimated by Black & Veatch and is similar to
that of the Southcentral Power Project. The capital cost for this project was developed using the same $/kW
amount as the Southcentral Power Project and is estimated at $370 million in 2009 dollars.
4.2.6 City of Seward Diesels
The City of Seward currently has four diesel generators in operation totaling approximately 10 MW.
Although these four generators have not been included in the existing RIRP modeling, the City of Seward’s
future diesel generators are being included in the committed units sensitivity case. The existing diesels were
not included because Seward is a full requirements customer of Chugach and the existing diesels are primarily
used for back-up. Seward plans to install two more diesel generators in 2010 and 2011. Generator #N1 is
1 http://www.aidea.org/PDF%20files/HCCP/HCCPFactSheet.pdf.
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-8 February 2010
scheduled to be installed in the spring 2010 with an output of 2.9 MW. The capital cost for #N1 is estimated
at $7.2 million in 2009 dollars. Generator #N2 is scheduled to be installed in the spring 2011 with an output
of 2.5 MW. Generator #N2 currently exists, but is not connected to the City of Seward’s electrical system.
The estimated cost for bringing #N2 to operation and for interconnection is $1.0 million in 2009 dollars.
4.3 Existing Transmission Grid
For purposes of the RIRP study, the Railbelt transmission system is separated into four main load centers:
GVEA or the interior, MEA, Anchorage comprised of Chugach’s and ML&P’s service areas, and the Kenai
comprised of HEA and the City of Seward. Within each load center, energy is assumed to flow freely without
transmission constraints. The existing transmission system of the Railbelt may be characterized as weak and
in need of development. Power transfer between areas of the system is currently constrained by weak
transmission links and stability constraints. Generating reserves cannot be readily shared between areas and
project development activities are seriously affected.
GVEA’s service area is connected with 138 kV lines that supply Delta Junction, Fairbanks, and Healy.
The interior and MEA load centers are interconnected via the Alaska Intertie and the Healy-Fairbanks and
Teeland-Douglas transmission lines. The Alaska Intertie is a 345 kV (operated at 138 kV), 170-mile
transmission line that is owned by the AEA connecting the Douglas and Healy substations. The Healy-
Fairbanks transmission line is a 230 kV, 90-mile transmission line, operated at 138 kV, and runs from the
Healy to the Wilson substations which deliver power from the Alaska Intertie directly into the city of
Fairbanks. Another 138 kV transmission line also runs from Healy to Nenana to Goldhill and delivers power
to Fairbanks. The 138 kV, 20-mile Douglas-Teeland transmission line stretches between the Douglas and
Teeland substations and connects the southern portion of the Alaska Intertie to the MEA load center. The
current transfer capability of the Alaska Intertie and Healy-Fairbanks transmission lines is assumed to be
75 MW and 140 MW, respectively.
MEA serves customers down the southern half of the intertie and south of the intertie through the towns of
Wasilla and Palmer.
The Anchorage load center consists of ML&P’s, and Chugach’s service territories. ML&P serves the load of
the residents and businesses in the central core of Anchorage. Chugach also serves residents and businesses
in Anchorage along with the area south of Anchorage, the City of Seward, and into the southern portion of the
Kenai Peninsula. For modeling purposes, the City of Seward’s load and generation have been placed in the
Kenai peninsula to allow economic commitment and dispatch in accordance with GRETC.
The MEA and Anchorage load centers are connected via two transmission lines. A 230 kV transmission line
connects the Teeland substation to Chugach’s Beluga plant in the western portion of the Anchorage load
center. A 115 kV transmission line connects the Eklutna Hydro Project and runs through ML&P’s area,
continuing into Chugach’s service territory. The current total transfer capability of these lines is assumed to
be 250 MW when power is flowing north into MEA and 50 MW when power is flowing south into
Anchorage.
The Anchorage and Kenai load centers are connected via a 135-mile, 115 kV transmission line, referred to as
the “Southern Intertie,” which connects the Chugach system to that of the Kenai Peninsula. The current
transfer capability of the Southern Intertie is assumed to be 75 MW when power is flowing north to
Anchorage, and 60 MW when the flow is south into the Kenai.
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-9 February 2010
The Kenai load center consists of HEA’s and the City of Seward’s service territories. The HEA service area
includes the cities of Homer and Soldotna.
Figure 4-1 shows the current Railbelt transmission transfer paths, four load centers, and existing transfer
capability as modeled. Transfer capability varies depending on generating unit availability and performance
as well as on direction of power flow between the areas. The transfer capabilities shown in Figure 4-1
represent the total MW transferable between the respective areas in the indicated direction with no
transmission criteria violated. Major generating project additions requiring interconnection to the system are
modeled as specific additional areas to appropriately account for transmission losses. Projects that require
such areas are Susitna and Chakachamna hydroelectric, Mt. Spurr geothermal, and Turnagain Arm tidal. As
transmission lines are added to the system throughout the planning period, transfer capabilities and
transmission losses are modified.
Figure 4-1
Railbelt Existing Transmission System as Modeled
GVEA
Anchorage
Kenai
MEA
75 MW
75 MW
247 MW
50 MW
60 MW
75 MW
6% Losses
0% Losses
8% Losses
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-10 February 2010
4.3.1 Alaska Intertie
The Alaska Intertie is a 170-mile long, 345 KV transmission line between Willow and Healy that is owned by
the AEA. The Intertie was built in the mid-1980s with State of Alaska appropriations totaling $124 million.
There is no outstanding debt associated with this asset.
The Intertie is one of a number of transmission segments that, when connected together, can move power
throughout the network from Delta, through Fairbanks to Anchorage down to Seldovia in the south. This
interconnected system of utilities, tied together with the Intertie is collectively termed the “Railbelt Electric
Grid System.”
The operation of the Intertie is governed by an agreement that was negotiated in 1985 between the
predecessor of AEA, the Alaska Power Authority (APA), and four utility participants: ML&P, Chugach,
GVEA, and AEG&T Cooperative, Inc., which is comprised of HEA and MEA. All of the utility participants
are connected to the Intertie and can move power on and off the Intertie.
For example, GVEA uses the Intertie to purchase non-firm economy energy from ML&P and Chugach. As
another example, the Railbelt Electric Grid System is used to transfer power from the Bradley Lake
Hydroelectric Plant, which is located east of Homer just below the glacier-fed Bradley Lake. Each of the
Railbelt utilities has rights for a specified percentage of the power output from Bradley Lake as shown in
Table 4-5. GVEA owns a portion of the capacity and energy available from Bradley Lake, and it transmits
this power north to its service area over the AEA Intertie. In practice, however, the GVEA’s power from
Bradley Lake is displaced by power sold by Chugach to HEA and Seward.
Both functional operation of the transmission line, as well as arrangements for the collection of and
expenditure of annual operations and maintenance funds, are a part of the agreement. The agreement also
specifies a governance structure that consists of representatives from the participating utilities and AEA.
The agreement specifies, through interconnection terms and conditions, how utilities are allowed access to the
Intertie. Each utility is required to maintain spinning reserve to preserve the reliability of electrical supply
throughout the network.
4.3.2 Southern Intertie
The Southern Intertie consists of approximately 130 miles of 115 kV transmission line constructed some
50 years ago that connects the Anchorage area operated by the Chugach, and the Kenai peninsula operated by
HEA. The Southern Intertie connects the Soldotna substation and the University substation by way of Quartz
Creek, Daves Creek and several other load serving taps between Daves Creek and the University substation.
The section from Soldotna to Quartz Creek is owned and operated by HEA while the section from Daves
Creek to the University substation is owned and operated by Chugach.
The HEA section of the Southern Intertie is in poor condition, routed through swampy terrain, and is
consequently affected by frost jacking which pushes the poles out of the ground. The Chugach section of the
intertie runs through areas susceptible to frequent avalanches. Several sections have been rebuilt; however,
over 60 percent of the line’s structures are in need of repairs. Although the thermal limit of the 115 kV line is
considered to be approximately 145 MW, this intertie is limited to a transfer limit of approximately 75 MW
by stability considerations. The intertie is currently used to transfer power from the jointly owned Bradley
Lake Hydro Units to utilities in the Anchorage area. This line is considered essential to the development and
operation of an integrated Railbelt transmission system.
DESCRIPTION OF
SECTION 4 EXISTING SYSTEM
ALASKA RIRP STUDY
Black & Veatch 4-11 February 2010
4.3.3 Transmission Losses
Existing transmission losses have been modeled between the four major load centers. The percentage of
losses varies with the load on the transmission lines. Losses for each of the connections between the four load
centers that are included in the models are illustrated in Figure 4-1 and represent a percentage of the total flow
along the lines. The losses shown represent the losses applied to power flowing both north and south.
4.4 Must Run Capacity
Must run capacity are units that are run to maintain the reliability of the Railbelt system regardless of whether
they are the most economical generation available. Must run capacity can also result from purchase power
contracts which require the utility to purchase the power at all times. Additionally, must run capacity can
result from a generating unit not having the capability to be shutdown and started up in response to economic
commitment and dispatch. Units are also required to run to maintain voltage and stability. The Railbelt
Utilities have indicated the following three units are current must run capacity units and have been modeled as
such.
• Nikiski through 2013
• Healy 1
• Aurora Purchase Power
SECTION 5 ECONOMIC PARAMETERS
ALASKA RIRP STUDY
Black & Veatch 5-1 February 2010
5.0 ECONOMIC PARAMETERS
The economic parameters are those necessary for developing the expansion plans using Strategist® and
determining the costs associated with those expansion plans. They include inflation, escalation, financing,
present worth discount rate, interest during construction interest rate, and development of fixed charge rates.
5.1 Inflation and Escalation Rates
Escalation rates have been developed for capital and O&M costs and are consistent with the general inflation
rate. The same general inflation rate and escalation rates were used for all Railbelt utilities. For evaluation
purposes, 2.5 percent was used for annual general inflation and escalation.
5.2 Financing Rates
The cost of capital was assumed to be 7 percent.
5.3 Present Worth Discount Rate
The present worth discount rate was assumed to be equal to the cost of capital, of 7 percent.
5.4 Interest During Construction Interest Rate
The interest during construction interest rate was assumed to be 7 percent.
5.5 Fixed Charge Rates
Fixed charge rates were developed for new capital additions based on the cost of capital. The fixed charge
rates were based on the assumption of using taxable financing, and further assumed 100 percent debt. In
developing financing assumptions, Seattle Northwest Securities Corporation was consulted and a general
consensus developed for purposes of estimating the cost of capital for evaluation purposes.
The fixed charge rates include the following components in addition to debt amortization:
• Issuance costs for debt - 2 percent
• Property insurance - 0.5 percent
• Property taxes - 0.5 percent
• Debt service reserve funds - 1 year
• Earnings on reserve funds - 7 percent
Levelized fixed charge rates were developed for the following financing terms as appropriate. Table 5-1
summarizes these terms as modeled for the GRETC system:
• Simple Cycle Combustion Turbines - 25 years
• Combined Cycle Units - 30 years
• Coal Units - 30 years
• Hydro Units - 100 years
• Wind - 20 years
• Municipal Solid Waste – 30 years
• Tidal - 20 years
• Geothermal - 25 years
• Generic Greenfield Nuclear - 30 years
SECTION 5 ECONOMIC PARAMETERS
ALASKA RIRP STUDY
Black & Veatch 5-2 February 2010
Table 5-1
Cost of Capital and Fixed Charge Rates for the GRETC System
Levelized Fixed Charge Rates (%)
Financing Terms (Years) Cost of
Capital (%) 20 25 30 100
7.0 10.543 9.536 8.925 8.163
The fixed charge rates were used for Strategist® to ensure that all alternatives for expansion plans were
selected on a consistent basis. The 100-year term for hydro units, while longer than traditional financing, was
selected based on the long life span of hydro units so that hydro units would be considered on this consistent
basis by Strategist®.
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-1 February 2010
6.0 FORECAST OF ELECTRICAL DEMAND AND CONSUMPTION
6.1 Load Forecasts
Load forecasts were provided by the utilities in response to a Black & Veatch data request. Since the RIRP
Study has a 50-year planning horizon, load forecast data was extrapolated through 2060. The load forecast
does not include incremental DSM/EE programs not inherently included in the utilities’ forecasts.
6.2 Load Forecasting Methodology
Each of the utilities provided load forecasts spanning different lengths of time that required extrapolation to
develop annual peak and energy requirements for the GRETC electrical system over the 50-year study period.
Typically, simple extrapolation of load forecasts is based on exponential growth by using the average annual
percentage growth rate for the last 5 or 10 years. This potentially can lead to over forecasting when these
percentage growth rates are applied over long periods of time. To compensate for this potential over
forecasting, Black & Veatch extrapolated the load forecasts in two different ways and took the average of the
two extrapolated forecasts as the forecast used in the RIRP. The first method of extrapolation was the typical
approach of extrapolating at the average annual percentage load growth over the last 10 years of the forecast.
The second method extrapolated the average annual increase in load over the last 10 years of the forecast. In
addition to peak load forecasts, annual minimum load, or valley, forecasts were also developed for the
GRETC system. The peak and valley demand and net energy for load requirements forecasts are provided in
the following subsection; it should be noted that demand and energy forecasts do not include transmission
losses between utilities.
6.3 Peak Demand and Net Energy for Load Requirements
Tables 6-1 and 6-2 present the winter and summer peak demand forecasts for each utility as well as the
coincident winter and summer peak demands for the GRETC system. The coincident peak demand forecasts
were developed by combining all of the utilities’ hourly load profiles for 2008 and calculating the 2008
coincident peak demands. The resulting coincident peak demands were compared to the 2008 non-coincident
peak demands to develop coincident factors. These factors were applied seasonally to the noncoincident peak
demand for both winter and summer months of the study period to develop the resulting coincident peak
demand forecasts for the GRETC system.
Table 6-3 presents the annual valley demand forecasts for each utility and the coincident valley demands for
the GRETC system. The valley demand forecasts for each utility were developed by taking the minimum
load for each utility from the provided hourly load information for 2008. Valley demand forecasts for 2011
and beyond were calculated for each utility by applying the annual increase in peak demands to the valleys.
A non-coincident value was calculated by summing up the minimum load for each utility and the result was
compared to the coincident minimum load value for the GRETC system that was developed by taking the
minimum load from the GRETC hourly profile to develop a valley coincident factor. The resulting valley
coincident factor was applied to the annual non-coincident valley load for the GRETC system to develop a
coincident valley demand forecast through 2060.
The net energy for load requirements for the GRETC system were developed by taking the sum of all the
utilities’ individual energy requirements. The resulting net energy for load forecast is provided in Table 6-4.
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-2 February 2010
Table 6-1
GRETC’s Winter Peak Load Forecast for Evaluation (MW)
2011 - 2060
Winter Peak Demand (MW)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 233.9 238.1 87.0 146.0 188.0 9.5 869.3
2015 234.5 217.5 89.0 157.0 192.0 10.4 867.8
2020 238.1 226.0 92.0 167.0 197.0 10.4 896.3
2025 242.2 234.3 96.0 178.0 202.0 10.4 927.5
2030 246.9 242.8 100.0 188.0 207.0 10.4 959.0
2035 251.6 251.5 104.0 199.0 212.1 10.4 991.2
2040 256.3 260.3 108.1 210.4 217.2 10.4 1,024.1
2045 261.1 269.2 112.3 222.1 222.5 10.4 1,057.7
2050 265.9 278.4 116.5 234.2 227.7 10.4 1,092.0
2055 270.7 287.7 120.9 246.8 233.1 10.4 1,127.1
2060 275.7 297.3 125.4 259.7 238.5 10.4 1,163.0
Table 6-2
GRETC’s Summer Peak Load Forecast for Evaluation (MW)
2011 - 2060
Summer Peak Demand (MW)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 160.6 191.4 75.1 91.1 167.2 10.0 668.0
2015 161.3 174.8 76.8 95.5 170.8 11.0 666.8
2020 163.4 181.6 79.4 95.0 175.2 11.0 688.7
2025 166.3 188.3 82.8 99.9 179.7 11.0 712.7
2030 169.9 195.2 86.3 105.9 184.1 11.0 736.9
2035 173.1 202.1 89.7 112.5 188.7 11.0 761.6
2040 176.3 209.2 93.3 119.3 193.2 11.3 786.9
2045 179.6 216.4 96.9 126.4 197.9 11.6 812.7
2050 182.9 223.8 100.5 133.7 202.6 11.9 839.1
2055 186.3 231.3 104.3 141.3 207.3 12.2 866.0
2060 189.6 238.9 108.2 149.1 212.2 12.5 893.6
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-3 February 2010
Table 6-3
GRETC’s Annual Valley Load Forecast for Evaluation (MW)
2011 - 2060
Annual Valley Demand (MW)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 95.4 88.6 44.4 53.2 91.0 4.4 413.5
2015 95.8 81.0 45.5 57.2 92.9 4.8 413.7
2020 97.1 84.1 47.0 60.9 95.3 4.8 426.9
2025 98.8 87.2 49.0 64.9 97.7 4.8 441.4
2030 100.9 90.4 51.1 68.5 100.2 4.8 456.1
2035 102.8 93.6 53.1 72.6 102.6 4.8 471.1
2040 104.8 96.9 55.2 76.7 105.1 4.8 486.4
2045 106.7 100.2 57.3 81.0 107.6 4.8 502.0
2050 108.7 103.6 59.5 85.4 110.2 4.8 517.9
2055 110.7 107.1 61.7 90.0 112.8 4.8 534.2
2060 112.7 110.7 64.0 94.7 115.4 4.8 550.9
Table 6-4
GRETC’s Net Energy for Load Forecast for Evaluation (GWh)
2011 - 2060
Utility Net Energy for Load Forecast (GWh)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 1,302.0 1,522.7 554.5 771.2 1,162.8 64.6 5,377.8
2015 1,311.4 1,333.5 568.1 831.9 1,184.9 65.6 5,295.3
2020 1,334.5 1,373.4 591.2 888.3 1,213.0 67.4 5,467.8
2025 1,359.2 1,403.8 615.5 946.4 1,241.7 69.3 5,636.0
2030 1,384.5 1,434.7 640.0 1,004.7 1,271.2 71.2 5,806.3
2035 1,409.9 1,465.7 665.1 1,065.4 1,300.9 73.1 5,980.1
2040 1,435.5 1,497.1 690.7 1,128.1 1,330.9 75.1 6,157.4
2045 1,461.4 1,528.9 716.8 1,192.9 1,361.3 77.1 6,338.4
2050 1,487.5 1,561.1 743.5 1,259.9 1,392.1 79.1 6,523.2
2055 1,513.9 1,593.6 770.8 1,329.4 1,423.2 81.1 6,712.0
2060 1,540.5 1,626.5 798.7 1,401.4 1,454.7 83.2 6,905.0
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-4 February 2010
The GRETC peak demand is projected to increase at an average annual rate of 0.6 percent and average annual
GRETC system energy is projected to increase at 0.5 percent.
Appendix D presents the annual forecasts for winter and summer peak demand, system valley, and net energy
for load.
6.4 Significant Opportunities for Increased Loads
As discussed in Section 2, a scenario representing a significant increase in load was evaluated in addition to
the base case load forecast. This section evaluates some potential increases in load that could lead to the large
increase in load scenario; Black & Veatch is not predicting that these additional loads will occur (such
prediction is outside of the scope of this project) but, rather, offers this discussion to illustrate some of the
ways that the regional load could increase significantly.
6.4.1 Plug-In Hybrid Vehicles
Energy security and climate change issues are driving change in the transportation sector now more than ever.
With the potential of carbon legislation and the possibility of high gasoline prices returning , there is an
increased need to consider new advanced technology vehicles that hold the promise of considerably
improving fleet energy efficiency and reducing fleet carbon footprint, such as plug-in hybrid vehicles
(PHEV).
According to a recent study conducted by the Transportation Research Institute at University of Michigan
(UMTRI)1, fleet penetration of PHEVs is expected to reach 1 percent of the national market by 2015,
2 percent by 2020, and 16 percent by 2040 (Table 6-5). Since these vehicles cost a lot more than their
conventional counterparts, especially in the near term, their market viability depends heavily on government
subsidies and incentives. This study assumes that appropriate government policy initiatives were instituted to
enable successful market penetration. Market penetration estimates from an ORNL study 2 predict that
nationwide penetration will not surpass 25 percent (Table 6-5).
Table 6-5
Projected PHEV Penetration in the American Auto Market
Year
PHEV Penetration
(%)
2015 1
2020 2
2040 16
2060 25
1 “PHEV Marketplace Penetration: An Agent Based Simulation;” Sullivan, Salmeen, and Simon; July 2009.
2 “Potential Impacts of Plug-in Hybrid Electric Vehicles on Regional Power Generation;” Hadley and Tsvetkova;
January 2008.
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-5 February 2010
Given that the Alaska Railbelt region had 53 percent of all vehicles in the state in 2008 (338,943)3, that the
average daily personal vehicle travel in the Alaska Railbelt area is 32 miles/day 4, and that the average
PHEV33 (a vehicle capable of running 33 miles on a single charge) requires 0.35 kWh of energy per mile 5
(Table 6-6), it is assumed the Alaska Railbelt region could experience an increase in annual energy as shown
in Table 6-7.
Table 6-6
Electric Consumption for a PHEV33 PNNL Kinter-Meyer
Vehicle Class
Specific Energy
Requirements (kWh/mile)
Compact Sedan 0.26
Mid-size Sedan 0.30
Mid-size SUV 0.38
Full-size SUV 0.46
Average 0.35
Table 6-7
Additional Annual Energy Required in the Alaska Railbelt Region from PHEVs
Year
Additional Load from
PHEVs (MWh/year)
2015 14,736
2020 31,242
2040 327,489
2060 679,391
PHEVs can be plugged in and recharged when they are not on the road, which according to Figure 6-1 occurs
in the late evening or early morning.
Consistent with the previous observation, a study conducted by EPRI/NRDC assumed that 70 percent of the
charging would occur “off-peak,” when electric demand is relatively low (Figure 6-2). Rate designs, such as
night rates, and time-of-use rates, could provide electric customers with incentives to utilize “off-peak”
charging.
3 Registered vehicles in 2008, including only pickups and passenger vehicles. Division of Motor Vehicles from the
Alaska Department of Administration.
4 From interviews to local car insurance companies conducted by NORECON.
5 Pacific Northwest National Laboratory (PNNL). Kinter-Meyer.
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-6 February 2010
Figure 6-1
US Daily Driving Patterns
Figure 6-2
PHEV Daily Charging Availability Profile
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-7 February 2010
Table 6-8 and Figure 6-3 show how the extra load from PHEVs would likely be distributed on a typical day.
This high penetration of PHEVs scenario has the potential to increase the energy requirement of the Alaska
Railbelt system by as much as 9.8 percent in 2060. Figure 6-4 and Table 6-9 illustrate these impacts.
This high penetration of PHEVs scenario has the potential to increase the peak demand of the Alaska Railbelt
system by as much as 5.5 percent in 2060. There would also be a shift in the peak hour from the 18th hour to
the 22nd hour of the peak day by 2060. Figure 6-5 and Table 6-10 illustrate these impacts.
Table 6-8
Hourly Distribution of PHEV Load on a Typical Day – Alaska Railbelt Region
2010 2015 2020 2040 2060
1 10 0 4.0 8.6 89.7 186.1
2 10 0 4.0 8.6 89.7 186.1
3 9 0 3.6 7.7 80.8 167.5
4 6 0 2.4 5.1 53.8 111.7
5 4 0 1.6 3.4 35.9 74.5
6 2 0 0.8 1.7 17.9 37.2
7 1 0 0.4 0.9 9.0 18.6
8 0.5 0 0.2 0.4 4.5 9.3
9 0.5 0 0.2 0.4 4.5 9.3
10 1.5 0 0.6 1.3 13.5 27.9
11 2.5 0 1.0 2.1 22.4 46.5
12 2.5 0 1.0 2.1 22.4 46.5
13 2.5 0 1.0 2.1 22.4 46.5
14 2.5 0 1.0 2.1 22.4 46.5
15 2.5 0 1.0 2.1 22.4 46.5
16 1 0 0.4 0.9 9.0 18.6
17 0.5 0 0.2 0.4 4.5 9.3
18 0.5 0 0.2 0.4 4.5 9.3
19 2 0 0.8 1.7 17.9 37.2
20 4 0 1.6 3.4 35.9 74.5
21 6 0 2.4 5.1 53.8 111.7
22 9 0 3.6 7.7 80.8 167.5
23 10 0 4.0 8.6 89.7 186.1
24 10 0 4.0 8.6 89.7 186.1
Total 100 0 40 86 897 1,861
Hour of
Day
Charging
Fraction
(%)
Typical Day Hourly Load (MW)
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-8 February 2010
Figure 6-3
Hourly Distribution of PHEV Load on a Typical Day – Alaska Railbelt Region
0
20
40
60
80
100
120
140
160
180
200
123456789101112131415161718192021222324
Hour of DayPHEV Extra Load (MW)2015 2020 2040 2060
Figure 6-4
Impact of a High PHEV Penetration Scenario Over the
Alaska Railbelt System’s Energy Requirement
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
2015 2020 2040 2060
Energy (GWh)Alaska Railbelt GWh
Alaska Railbelt GWh - With PHEVs
+0.28%+0.57%
+5.32%
+9.84%
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-9 February 2010
Table 6-9
Impact of a High PHEV Penetration Scenario Over the
Alaska Railbelt System’s Energy Requirement
2015 2020 2040 2060
Alaska Railbelt GWh 5,295 5,468 6,157 6,905
Alaska Railbelt GWh - With PHEVs 5,310 5,499 6,484 7,584
Percent Increase 0.28 0.57 5.32 9.84
Figure 6-5
Impact of a High PHEV Penetration Scenario Over the
Alaska Railbelt System’s Peak Demand
0
200
400
600
800
1,000
1,200
1,400
2015 2020 2040 2060
Load (MW)Alaska Railbelt Peak Load
Alaska Railbelt Peak Load - With PHEVs
+0.02%+0.05%
+1.59%
+5.46%
Table 6-10
Impact of a High PHEV Penetration Scenario Over the
Alaska Railbelt System’s Peak Demand
2015 2020 2040 2060
Alaska Railbelt Peak Load 882.70 896.30 1,024.10 1,163.00
Alaska Railbelt Peak Load - With PHEVs 882.90 896.73 1,040.36 1,226.45
Percent Increase 0.02 0.05 1.59 5.46
Peak Hour 18 18 20 22
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-10 February 2010
6.4.2 Electric Space and Water Heating Load
Another means of significantly increasing electric demand within the region would to encourage increased
penetration of electric space and water heating. ENSTAR Natural Gas is the primary supplier of natural gas
within the State of Alaska along with Barrow Utilities Electric Coop and Fairbanks Natural Gas. Natural gas
consumption within the State is almost evenly distributed between residential, commercial and industrial
customers. The Energy Information Administration (EIA) publishes statistics on natural gas on an annual
basis. Table 6-11 provides a summary of 2007 data for the state of Alaska.
Table 6-11
2007 Natural Gas Consumption for the State of Alaska (Source: EIA)
Residential
Customers
Commercial
Customers
Industrial
Customers
Natural Gas Delivered (MMcf) 19,840 18,760 19,750
For purposes of this discussion, it is assumed that 100 percent of the gas consumption within the State of
Alaska applies to the Railbelt region, given that an estimated 97 percent or more of natural gas is consumed
within the region. According to the American Gas Association, space and water heating accounts for
approximately 85 percent of the natural gas application in the New England region for residential customers.
It is assumed that a similar proportion is applicable to commercial customers. The percentage of industrial
consumption related to space and water heating is negligible compared to other applications and, therefore, is
not included in this study. Table 6-12 contains the calculated energy and demand if all residential and
commercial space and water heating requirements were met through electricity, based on a 2007 heating value
of 1,005 Btu/cf, published by the EIA for the State of Alaska. The energy and demand calculations assume
that natural gas space and water heating are 85 percent efficient. Peak demand is based on the residential
natural gas load factor for the state of 39 percent.
Table 6-12
Calculated Railbelt System Energy and Demand by
Customer Type for Electric Space and Water Heating
Residential
Customers
Commercial
Customers
Calculated Space and Water Heating Energy, MWh 4,222,640 3,991,324
Calculated Space and Water Heating Demand, MW 1,243 1,174
6.4.3 Economic Development Loads
Another opportunity for increased loads in the Railbelt is from large new industrial loads. Black &Veatch
obtained a list of potential economic development projects from the Alaska Industrial Development & Export
Authority (AIDEA) presented in Table 6-13, as well as possible areas in which they might be located. For
purposes of this study, Chugach’s and ML&P’s service areas have been combined as the Anchorage area. For
purposes of load forecasting, Interior loads were assumed to be in GVEA’s service area. Loads in the Kenai
area were assumed as occurring in HEA’s area.
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-11 February 2010
Table 6-13
Potential Economic Development Projects
Potential Project Area Location Size (MW)
Ore Processing Facility Anchorage 300
Internet Server Facility Anchorage 300
Coal Mine Anchorage 50
Subtotal – Anchorage Area 650
Gold Mine Interior 150
Mine Interior 200
Subtotal - Interior 350
Nitrogen/Urea Facility Kenai 50
Total 1,050
In addition to the loads identified in Table 6-13, the Pebble Mine is another potential large load estimated to
be approximately 300 MW. While it appears likely that if it is developed, it will develop on-site power, there
has been some consideration that it could be supplied by the Railbelt through HEA’s system. Other potential
large loads could be from electric compressors for the proposed natural gas pipelines from the North Slope.
Many of these compressors, however, would likely be remotely located.
It appears conceivable that a 1,000 MW of new load could potentially be developed in the Railbelt within the
time frame of this study. Such new load would likely require specific policies to be implemented whether if
from fuel switching or large industrial loads. For the purposes of creating a load forecast for the large load
scenarios, new loads of 500 MW will be added in both 2025 and 2040, with 350 MW of each addition of new
load being assumed in the Anchorage area and 150 MW of the new load being assumed in the Interior. For
load forecasting purposes, the new load was assumed to have a 75 percent load factor. Tables 6-14 and 6-15
present the winter peak demand and net energy for load forecasts for the large load scenarios. Annual
forecasts for the large load scenario are presented in Appendix D.
FORECAST OF ELECTRICAL
SECTION 6 DEMAND AND CONSUMPTION
ALASKA RIRP STUDY
Black & Veatch 6-12 February 2010
Table 6-14
GRETC’s Winter Peak Large Load Forecast for Evaluation (MW)
2011 - 2060
Large Load Winter Peak Demand (MW)
Year GVEA Anchorage MEA Kenai GRETC
2011 238.1 412.2 146.0 96.3 869.3
2015 217.5 417.1 157.0 99.2 867.8
2020 226.0 425.1 167.0 102.2 896.3
2025 384.3 734.0 178.0 156.2 1,398.3
2030 392.8 744.0 188.0 160.1 1,429.5
2035 401.5 753.5 199.0 164.1 1,461.4
2040 560.3 1063.2 210.4 218.5 1,975.7
2045 569.2 1072.9 222.1 222.9 2,009.3
2050 578.4 1082.8 234.2 227.4 2,043.6
2055 587.7 1092.8 246.8 232.1 2,078.8
2060 597.3 1102.9 259.7 236.8 2,114.7
Table 6-15
GRETC’s Large Load Net Energy for Load Forecast for Evaluation (GWh)
2011 - 2060
Utility Large Load Net Energy for Load Forecast (GWh)
Year GVEA Anchorage MEA Kenai GRETC
2011 1522.7 2464.8 771.2 619.1 5,377.8
2015 1333.5 2496.2 831.9 633.7 5,295.3
2020 1373.4 2547.4 888.3 658.6 5,467.8
2025 2389.3 4572.0 946.4 1013.3 8,921.0
2030 2420.2 4626.7 1,004.7 1039.7 9,091.3
2035 2451.2 4681.8 1,065.4 1066.7 9,265.1
2040 3473.5 6719.2 1,128.1 1424.6 12,745.4
2045 3499.9 6764.7 1,192.9 1450.9 12,908.4
2050 3532.1 6821.6 1,259.9 1479.6 13,093.2
2055 3564.6 6879.1 1,329.4 1508.9 13,282.0
2060 3602.9 6948.0 1,401.4 1540.7 13,493.0
FUEL AND EMISSIONS
SECTION 7 ALLOWANCE PRICE PROJECTIONS
ALASKA RIRP STUDY
Black & Veatch 7-1 February 2010
7.0 FUEL AND EMISSIONS ALLOWANCE PRICE PROJECTIONS
7.1 Fuel Price Forecasts
7.1.1 Natural Gas Availability and Price Forecasts
7.1.1.1 Description of Risk-Based Assessment Methodology
Risk-based forecasts differ from other types of forecasts by acknowledging the element of chance in the way
that multiple factors can combine to produce a range of outcomes. For example, there might be a 60 percent
chance that a gas field will produce 150 million cubic feet per day (MMcf/d) in a given year but only a
20 percent chance that it will produce 200 MMcf/d. Likewise, a new gas pipeline might be 25 percent likely
to begin flowing gas at 200 MMcf/d in a given year but 55 percent likely to begin flowing at 250 MMcf/d two
years later. In both cases, an analysis is required to convert the best estimates of chance into a mathematical
formula that will support a risk-based forecast of what the total gas supply might be in a given year if the gas
field and pipeline were considered together in the range of possible outcomes.
For development of the RIRP, Black & Veatch’s risk-based natural gas supply forecasts employed a model
that considered performance prospects of each of several prospective gas sources and their variations over the
50-year planning horizon. The model was constructed using Palisade DecisionTools Professional 5.0
software. A decision-tree architecture was employed where each gas supply node was supported by a
mathematical probability distribution function that described the node’s annualized performance over the 50-
year period. Monte Carlo methods were used to run gas supply simulations using alternative sets of
assumptions about performance of each supply node. The purpose of the model was to run “what if” types of
scenarios that would provide information about the aggregate supplies of gas in a specified year. The main
gas sources included production from the Cook Inlet basin, importation of LNG from outside Alaska, and
delivery of gas from the Alaska North Slope to the Railbelt by means of an instate pipeline. Variations
among the model runs featured different sets of assumptions about the future capacity of Cook Inlet
production, including possible enhancements, as well as the timing and volume throughput of LNG imports
and the instate pipeline, respectively.
Model runs analyzed individual years for the decade of 2010-2019. For the years 2020-2060, model runs
were made by five-year intervals (for example, 2020-2024, 2025-2029, etc.).
In evaluating results, attention was focused on probabilities for attainment of gas supplies at three benchmark
levels:
• P90: Gas capacity achievable with 90% probability
• P50: Gas capacity achievable with 50% probability
• P10: Gas capacity achievable with 10% probability
Figure 7-1 illustrates the P90, P50 and P10 metrics from an actual gas supply model simulation. Clearly, as
the gas capacity goes up, the probability for attaining that capacity goes down. Although conservatism might
argue for using P90 values (the lowest of the three capacities) for all planning purposes, the P50 value is a
reasonable choice for two primary reasons. First, P50 is easier to intuitively reference and visualize because it
always falls near the middle of the range of possibilities. Second, P50 is the metric most comparable to
“average expectation” forecasts that can be made with assumptions about average performance of gas sources
where probabilities are ignored. Indeed, P50 supply was the metric chosen for the reference price forecast.
FUEL AND EMISSIONS
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Black & Veatch 7-2 February 2010
Figure 7-1
Results of a Risk-Based Gas Supply Model Simulation for the Year 2017
Results from the risk-based model forecasts comprised gas volumes, in annualized units of MMcf/d, that
served as inputs into separate price forecasts. The price forecasts employed conventional methods from
energy market analysis that used the interplay of supply and demand to predict a commodity value for gas that
would be delivered at the Cook Inlet as if from the historical Cook Inlet gas production. Black & Veatch
developed mathematical relationships for the commodity value using historical Alaska gas supply, gas
demand and gas price data published by the U. S. Energy Information Administration as well as from
additional research.
To that commodity value, estimated transportation costs were added for any volume of gas that was obtained
from a non-local source; namely, LNG imports or the instate pipeline. Black & Veatch conducted research to
estimate reasonable transportation costs. LNG costs were based on market knowledge of the Asia-Pacific
Basin LNG markets. Pipeline costs were based on previously published studies of instate gas pipelines, both
for stand-alone direct lines from the North Slope to the Anchorage area and for lateral lines from a large
pipeline that might carry gas from the North Slope to Alberta, Canada.
The final price estimate, consisting of the commodity value and transportation adders, is equivalent to a “city
gate” price that would be available to a high-volume buyer such as an electric utility or a gas distribution
company. As used by the U. S. Energy Information Administration, a “city gate” price is the first point of
sale for gas before it enters the wholesale markets. Ownership of gas beyond the “city gate” typically changes
several times before it reaches residential consumers, with price increases at each change of ownership.
Therefore, “city gate” prices are substantially lower that residential retail prices. Because the price forecasts
used risk-based model gas supplies as input, separate prices were associated with P90, P50 and P10 supplies,
respectively.
FUEL AND EMISSIONS
SECTION 7 ALLOWANCE PRICE PROJECTIONS
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Black & Veatch 7-3 February 2010
7.1.1.2 Gas Stakeholder Input Process
Black & Veatch conducted multiple rounds of reviews with numerous stakeholders to discuss the construction
of the gas supply forecast model, as well as preliminary results for supply and price forecasts. These
stakeholders included State of Alaska officials; technical specialists and executives from the Railbelt electric
utilities; technical specialists and executives from Enstar; producers; and independent, Alaska-based energy
consultants.
The gas stakeholder meetings were conducted over a three-month period and involved four different editions
of the Black & Veatch gas supply forecast model. After each round of stakeholder meetings, Black & Veatch
made changes to the gas supply forecast model in response to stakeholder feedback. The fourth version of the
model was used to produce the results reported in this report.
7.1.1.3 Structure of the Natural Gas Decision Tree
The gas supply and price forecasts considered a variety of possibilities but utilized only those that could be
supported quantitatively with the necessary degree of mathematical precision. Specifically, model attributes
were separated into factors that were modeled and factors that were not modeled as summarized in Figure 7-2
and discussed below.
Figure 7-2
Schematic Summary of the Probabilistic Gas Supply Forecast Model
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SECTION 7 ALLOWANCE PRICE PROJECTIONS
ALASKA RIRP STUDY
Black & Veatch 7-4 February 2010
7.1.1.4 Decision Tree Input Assumptions
7.1.1.4.1 Gas Demand
Black & Veatch reviewed publicly-available data on historical consumption of natural gas in the Railbelt
region and re-calculated those data into mathematical functions that were compatible with the risk-based, gas
supply forecast model. Sources included the U.S. Energy Information Administration, State of Alaska and
Enstar. As shown in Table 7-1, adjustments were made for the fact that traditional consumers of gas are
changing as the decade of 2000-2009 gives way to the decades of 2010-2019 and forward. For example, the
decade of 2000-2009 included major use of gas by the Agrium fertilizer plant and by the Nikiski LNG plant
(as exports to Japan). But the Agrium fertilizer plant ceased operations in 2007 and the Nikiski LNG exports
are expected to end by March 2011. So going forward, the main consumers of gas are expected to be electric-
utilities, and gas pipeline users (including space heating) plus oilfield operations. Accordingly, the P90, P50
and P10 metrics for gas demand reflect a significant downturn in risk-based demand in 2010-2019 followed
by slow growth in the expected use of gas for power, heating and field operations.
Table 7-1
Representative Risk-Based Metrics for Railbelt Natural Gas Demand
Based on Historical Data and Known Changes in Gas Consumption
Annualized Gas Demand (MMcf /d)
Risk-Based Demand Metric 2000-2009 2010-2019 2020-2029
P90 (90% likely that this demand will occur) 415 216 252
P50 (50% likely that this demand will occur) 524 245 257
P10 (10% likely that this demand will occur) 632 275 262
It should be noted that the 2006-2009 decade was one of rapid change, both in gas demand and gas
production. The curve-fitting approach needed to render demand data into a probability curve, as required for
the probabilistic supply forecasts, displayed large spreads in key percentages in the decadal curve as a
consequence of large year-to-year changes in the historical data there were used as input.
7.1.1.4.2 Gas Supplies
7.1.1.4.2.1 Cook Inlet Gas Production
Prospects included a “legacy” component based on the expected future performance of historically known,
producing gas reservoirs. A “re-developed” component represented additional performance that might be
possible from “legacy” reservoirs through new or re-worked gas wells. Finally, a “New E&P” component
represented geoscience-based estimates of discoverable, new gas reservoirs within the greater Cook Inlet
region. After consulting subject matter experts among the Railbelt gas stakeholders, and reviewing
previously published reports about gas resources and reserves, Black & Veatch concluded that enhanced Cook
Inlet gas production could be made to meet P50 gas demand through 2016 with plausible assumptions about
re-working and re-investment. Enhanced Cook Inlet production was retained as a source in the gas supply
model through 2039 but with significant performance decline after 2017.
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Black & Veatch 7-5 February 2010
7.1.1.4.2.2 Instate Gas Pipeline
This supply node was predicated upon construction of a pipeline to deliver gas from the Alaska North Slope
(Prudhoe Bay, Point Thomson) to the Anchorage area. Prospects included a stand-alone, direct line as well as
a lateral from a larger pipeline that might carry gas into Canada and the USA Lower-48 states. After
consulting subject matter experts among the Railbelt gas stakeholders, and reviewing previously published
reports about possible instate pipeline projects, Black & Veatch concluded that an instate pipeline was
plausible after 2018 and with a maximum capacity of 350 MMcf/d. Such an instate pipeline source was
included in the gas supply model with ramp-up from 2018 through 2022 and maximum capacity thereafter.
No attempt was made to analyze the economics of building smaller or larger pipelines. Although published
descriptions of possible pipeline projects cover the range of about 50-500 MMcf/d capacities, the limit of
350 MMcf/d was chosen as the largest capacity likely to be built given the demand outlook (Table 7-1).
7.1.1.4.2.3 LNG Imports (With Storage)
This supply node was premised on bringing LNG to the Cook Inlet through ocean tankers supplied from
sources within the Asia-Pacific basin. Prospects included re-engineering the Nikiski export plant to become a
receiving and storage facility or building a new receiving facility with associated storage.
For a re-developed (i.e., brownfield) Nikiski facility, storage capacity would be limited to the liquid
equivalent of about 2,300 MMcf of gas. Although re-developed Nikiski could provide peak deliverability of
100 MMcf/d for short durations, total storage volume translated to annualized deliverability would be only
about 6 MMcf/d. Black & Veatch research found that a plausible design for a new (i.e., greenfield) LNG
facility with tank storage might increase the total available storage to a liquid equivalent of 5,700 MMcf
which would have an annualized deliverability equivalent of about 15 MMcf/d. But the latter facility likely
would require a capital investment at least several times that of the re-developed Nikiski facility.
A new receiving facility built with associated underground geologic storage (depleted oil or gas reservoir), in
principle, could be made more scalable than for tank storage based on phased expansion of storage capacity
through successive re-commissioning of depleted reservoirs. Because geologic-based storage typically scales
in multiples of one billion cubic feet (1 Bcf = 1,000 MMcf), the two limiting factors for the Cook Inlet would
be how fast depleted reservoirs could be re-developed into storage (Bcf per unit time) and what practical
limits would apply to ocean tanker-based deliveries (tanker deliveries per unit time). After consulting subject
matter experts among the Railbelt stakeholders, researching performance characteristics of LNG ocean
tankers, and reviewing previously published reports about possible gas storage projects, Black & Veatch
arrived at a plausible order of magnitude for LNG imports with associated geologic-based storage. A
reasonable lower-end estimate would be five (5) deliveries per year, by a tanker with 138,000 cubic meter
(liquid) capacity, and as supported by an available (working gas) storage capacity of at least 15-20 Bcf to
produce the equivalent of an annualized gas supply of 42 MMcf/d. A reasonable upper-end limit would be 12
deliveries per year, by a tanker with 150,900 cubic meter (liquid) capacity, and as supported by an available
(working gas) storage capacity of at least 40-45 Bcf to produce the equivalent of an annualized gas supply of
106 MMcf/d. For the gas supply model, Black & Veatch used the 41 MMcf/d capacity limit, beginning
imports and ramp-up in 2013, for the base case. But alternative simulations also were made using the
106 MMcf/d capacity limit.
7.1.1.4.3 Other Considerations
Regional pipeline distribution systems, and gas storage not affiliated with LNG imports, were considered not
to be performance bottlenecks so they were treated as non-issues in the gas supply model (Figure 7-2). Black
& Veatch interviews with stakeholders led to the conclusion that the gas pipeline distribution system, at least
in the Cook Inlet region, has sufficient capacity to handle new gas supplies without requiring significant
FUEL AND EMISSIONS
SECTION 7 ALLOWANCE PRICE PROJECTIONS
ALASKA RIRP STUDY
Black & Veatch 7-6 February 2010
capital investments. Also, published reports on geologic gas-storage prospects identified suitable volumes of
reservoirs that could, in principle, be re-commissioned before the instate pipeline appeared in 2018 and
ramped-up to maximum capacity in 2022. Gas storage required for earlier imports of LNG was treated as
storage implicit in the import project and scaled as discussed above.
Stakeholders suggested other possible sources of gas that Black & Veatch did not include in the gas supply
model for lack of the necessary quantitative supporting information. Although such sources might become
viable in the future, the performance data required to model their probabilities for performance were not
available either through published or unpublished sources.
First, overland trucking of LNG from the North Slope to Fairbanks was proposed. Although such a supply
could be significant for residential space heating, the plausible scale of such deliveries is virtually immaterial
to gas-fired power plants. Specifically, a 10,000-gallon LNG tanker truck delivered five (5) times per week
for every week of the year provides a gas equivalent of less than 1 MMcf/d whereas a continuously-run,
100 MW gas-fired power plant would need about 20-30 MMcf/d. So given the emphasis of the current report
on power generation, overland LNG trucking was not selected as a gas source in the supply simulations.
Second, gas production from Railbelt geologic sources other than Cook Inlet has not been confirmed in
publicly-available reports. The Nenana Basin was mentioned specifically by several stakeholders but Black
& Veatch was not able to confirm whether gas had been proven or resources estimated through ongoing
exploratory drilling activities.
Third, gas production from coalbed methane was mentioned by a few stakeholders who did not provide
supporting data. Black & Veatch researched available reports but could not confirm plausible projects that
would deliver significant amounts of gas within the same timeframe as LNG imports or an instate gas
pipeline.
7.1.1.5 Natural Gas Price Forecasts
Black & Veatch approached the price forecast as:
Price = Commodity Value (supply, demand) + Delivery Cost
using the following main premises:
• Metric is a single, pooled Railbelt price as if for a single, unified consumer
• Focus on “city gate” price that would be a proxy for fuel procurement plans by electric utilities – not
retail consumer prices
• Commodity value estimated from historical-empirical data regressions
• A premium adder included for Cook Inlet enhanced production
• All-in delivery and storage costs for imported LNG
• Tariffs for instate pipeline, North Slope to Anchorage
For the commodity value, Black & Veatch analyzed historical supply, demand and price data for Alaska to
develop five empirical relationships, each with an individual strength of correlation. Those five model
relationships were combined using weighting factors proportional to the strengths of the respective correlation
coefficients.
FUEL AND EMISSIONS
SECTION 7 ALLOWANCE PRICE PROJECTIONS
ALASKA RIRP STUDY
Black & Veatch 7-7 February 2010
For the delivery cost, Black & Veatch reviewed publicly-available information on LNG ocean-tanker
transportation and alternative proposals for Alaska instate pipeline projects. Although LNG transportation
costs are well-established, Alaska pipeline projects remain incompletely defined and, therefore, carry larger
associated uncertainties. Both for LNG and instate pipeline, anticipated costs fell within the range of $1.50-
$2.00/MMBtu. In addition, Black & Veatch estimated that investments to realize the postulated enhancement
to Cook Inlet production would require additional costs in the range of $0.25-$1.00/MMBtu.
To develop the price forecast for a given year, Black & Veatch applied the P50 supply output from the risk-
based gas supply forecast to the commodity value model. Then delivery adders were applied for all of the
supply sources that were presumed to be operational in that year. The result effectively was a weighted-
average cost of gas involving the various gas sources.
7.1.1.6 Summary of Results
Black & Veatch selected two sets of gas supply simulations to illustrate the challenges that exist in providing
suitable volumes of natural gas to Railbelt users, as follows:
Base Case (used for Scenario 1A in the RIRP model)
• Expanded Cook Inlet production, beginning in 2012, matched P50 demand but with decline toward a
supply-demand deficit beginning in 2017 and with end of production as of 2039
• LNG imports began in 2013, and ramped-up to annualized equivalent of 41 MMcf/d, before ending in
2018 (when the instate pipeline appeared)
• Instate pipeline began in 2018, with ramp-up to maximum capacity of 350 MMcf/d by 2022, and
continued operation thereafter
• Met anticipated P50 demand (with P90 to P50 supplies) through 2060
• Performance sensitivities during 2018-2024 related to uncertainties in appearance and ramp-up of the
instate pipeline
Sensitivity Case (for comparison and contrast with Base Case)
• Expanded Cook Inlet production as in Base Case
• LNG imports began in 2013, with ramp-up to annualized equivalent of 106 MMcf/d, and continuous
operation thereafter
• No instate pipeline was available
• Failed to meet anticipated P50 gas demand after 2018
• Performance sensitivities during 2017-2024 related to uncertainties in ramp-up of LNG imports
Railbelt gas price forecasts derived from the P50 supply simulated in the Base Case are shown in Figure 7-3
along with alternative forecasts for comparison. Before 2018, the Railbelt forecast resembles projections of
bi-lateral contracts executed in the Cook Inlet in 2008. But the Railbelt forecasts are higher than the subject
contracts because of additional costs associated with importation of non-Alaska LNG as well as enhanced
Cook Inlet production. After 2018, the Railbelt forecasts trend much higher under heavy influence of the
transportation costs assumed for the instate gas pipeline. It should be noted that the bi-lateral contracts
referenced have terms only through 2013 and 2017, respectively, and are predicated on Cook Inlet production
as the sole source of gas. Also, the prices projected from those contract terms pertain to the “base tier” or
“base load” price that is the lowest price available; both contracts provide for multipliers up to 130 percent of
the base price for gas sold under peak-demand conditions. Finally, the price for “LNG Delivered in Japan” is
considered an upper limit for the Railbelt price, including the supply-starved Sensitivity Case.
FUEL AND EMISSIONS
SECTION 7 ALLOWANCE PRICE PROJECTIONS
ALASKA RIRP STUDY
Black & Veatch 7-8 February 2010
Figure 7-3
Comparison of Natural Gas Price Forecasts Relevant to Railbelt Resource Plans
4
6
8
10
12
14
2010 2015 2020 2025 2030
YearGas Price ($US / MMBtu). Forecast of Railbelt Gas (purchase price for electric utility)
Forecast of LNG Delivered in Japan
Projection of ConocoPhillips-ENSTAR Contract (2008, terms through 2013)
Projection of Marathon-ENSTAR Contract (2008, terms through 2017)
Armstrong (North Fork)-ENSTAR contract (2009, floor & ceiling)
Gas pricing in the bi-lateral sales contracts referenced in Figure 7-3 utilize formulas that reference an
assortment of non-Alaska price points with various provisions for floor and ceiling pricing. For the two
contracts collectively, the reference price points include Alberta, Canada; the border of British Columbia,
Canada with Washington state; the Oregon-California border; northern California; southern California; and
Chicago, Illinois. Therefore, the Black & Veatch projections of those contract prices are based on forecasts of
annualized prices at each of those reference price points.
Black & Veatch used conventional market analysis methods to correlate historical prices at reference price
points with historical prices at the Henry Hub, LA price point. Based on those correlations, individual
forecast models were developed for each reference price point in order to accomplish the individualized price
forecast for each reference point, based on Black & Veatch selection of a forecast for Henry Hub.
From the price curves depicted in Figure 7-3, representative prices are summarized in Table 7-2. For reasons
discussed above, the Railbelt forecast prices fall between the Cook Inlet bi-lateral contracts from 2008 and the
anticipated forward price in Japan.
The “Forecast of Railbelt Gas” curve is the price corresponding to the P50 supply output from the Base Case
described above. Projections for the ConocoPhillips and Marathon contracts were made by Black & Veatch
using the price terms in the 2008 contracts which end in 2013 and 2017, respectively.
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Black & Veatch 7-9 February 2010
Table 7-2
Representative Forecasts of Railbelt Natural Gas Price
According to Different Benchmarks
Natural Gas “City Gate” Price ($US / MMBtu)
as Delivered at Cook Inlet AK
(unless noted otherwise)
Price Reference 2011 2013 2015 2017 2019 2021 2023
LNG Delivered in Japan 8.02 9.61 10.89 11.69 12.25 12.54 12.74
Forecast for Railbelt 6.30 7.12 7.70 8.08 9.03 11.21 12.43
Projection of ConocoPhillips-
Enstar Contract (Base Tier)
5.97 6.29 N/A N/A N/A N/A N/A
Projection of Marathon-Enstar
Contract (Base Load)
6.29 6.63 7.00 7.49 N/A N/A N/A
The main conclusions from these gas supply analyses are as follows:
• There are plausible scenarios for long-term supplies of natural gas in the Alaska Railbelt but they will
require new capital investments that include enhanced production from the Cook Inlet, as well as
importation of LNG from non-Alaska sources and or North Slope gas through an instate pipeline.
• LNG imports are a useful supplement to Cook Inlet production but are not likely to supplant the
higher capacity provided by an instate pipeline.
• Both LNG imports and instate gas pipeline supplies will be more costly than historical production
from the Cook Inlet and will necessitate significantly higher gas prices than in historical experience.
7.1.2 Methodology for Other Fuel Price Forecasts
7.1.2.1 Coal
The price forecast for the RIRP study represents the EIA AEO2009 1 delivered industrial price (dollars per
short ton) but with an energy conversion factor of 20.169 MMBtu/ton and with the low end of possible
transportation costs. The energy conversion factor was chosen to resemble available assays of Alaska coal.
In addition to the delivered price of coal, a minemouth coal price estimate was developed for the Healy plant
and for a coal sensitivity analysis. The minemouth price is based on the delivered price less an estimate for
delivery costs.
7.1.2.2 HAGO
High Atmospheric Gas Oil (HAGO) was treated as materially equivalent to a sub-grade of Fuel Oil No. 4.
The price forecast adopted here represents a 75 percent multiplier applied to the EIA AEO2009 2 forecast for
distillate fuel oil delivered for electric power and using an energy conversion factor of 0.139 MMBtu/gallon.
1 EIA AEO2009. U. S. Energy Information Administration, Annual Energy Outlook 2009, March 2009. Available
online at http://www.eia.doe.gov/oiaf/aeo/index.html.
2 EIA AEO2009 (previously referenced).
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Black & Veatch 7-10 February 2010
7.1.2.3 Naphtha
Naphtha was treated as materially equivalent to a sub-grade of jet fuel. The price forecast adopted here
represents a 75 percent multiplier applied to the EIA AEO2009 3 forecast for jet fuel delivered for aviation and
using an energy conversion factor of 0.139 MMBtu/gallon.
7.1.2.4 Propane
Propane is not currently used as a fuel for electric power generation in the Railbelt region. However, in
response to a stakeholder request, propane was added for comparison as an alternative fuel. The price
forecast reported here utilized an historical-empirical relationship developed for propane and natural gas in
the Lower-48 states as applied to the natural gas price predicted for the Railbelt.
7.1.3 Resulting Fuel Price Forecasts
Table 7-3 summarizes the resulting annualized prices predicted for hydrocarbon fuels from 2011 to 2060.
Although seasonal variation of price can be expected to occur in response to demand swings, the prices
represented here reflect a single average price for a given year.
7.2 Emission Allowance Price Projections
7.2.1 Existing Legislation
Currently, there is no existing legislation in place that subjects electric generating units in Alaska to an
emission allowance trading program for NOx, SO2, CO2, or Hg emissions. As a result, no emission allowance
costs are included in the economic evaluations other than for CO2 as discussed in the next subsection. Capital
and operating costs are included for generating units in order for the units to meet expected emission
limitations under the Environmental Protection Agency’s Prevention of Significant Deterioration Program.
7.2.2 Proposed Legislation
Currently, there is no proposed federal or state legislation that would subject electric generating units in
Alaska to an emission allowance trading program for NOx, SO2, or Hg. There have been a number of bills
introduced in the U.S. Congress that would create an emission allowance trading program and corresponding
emission reductions for CO2. The only bill that has passed either House of Congress is H.R. 2454, the
American Clean Energy and Security Act of 2009 (ACESA), which was passed in the House of
Representatives in 2009. While it is unknown if H.R. 2454 will ultimately be passed into law, after vetting
the issue with numerous stakeholders in the RIRP process, it was decided that CO2 allowance costs would be
included in the economic evaluations for the RIRP. The development of those allowance costs is presented in
the following subsection.
7.2.3 Development of CO2 Emission Price Projection
The CO2 emission price projection used in this analysis is based upon price projections developed by the
Energy Information Administration (EIA) and by the Environmental Protection Agency (EPA). The base
price projection is presented in EIA report number SR-OIAF/2009-05, entitled Energy Market and Economic
Impacts of H.R. 2454, the American Clean Energy and Security Act of 2009 (ACESA), dated August 4, 2009.
The EIA report considered the energy-related provisions in ACESA that could be analyzed using EIA’s
National Energy Modeling System. The ACESA basic case was used for the CO2 emission price projection
for the years 2012 through 2030.
3 EIA AEO2009 (previously referenced).
FUEL AND EMISSIONS
SECTION 7 ALLOWANCE PRICE PROJECTIONS
ALASKA RIRP STUDY
Black & Veatch 7-11 February 2010
Table 7-3
Nominal Fuel Price Forecasts ($/MMBtu)
Year Natural Gas Delivered Coal Minemouth Coal HAGO Naphtha Propane
2011 6.30 2.94 2.18 12.98 13.77 9.05
2012 6.62 2.99 2.21 14.52 15.24 9.45
2013 7.12 3.02 2.24 15.26 16.16 10.08
2014 7.42 3.08 2.28 16.31 17.24 10.46
2015 7.70 3.19 2.36 17.23 18.11 10.81
2016 8.05 3.23 2.39 17.79 18.71 11.25
2017 8.08 3.29 2.44 18.23 19.25 11.29
2018 8.25 3.36 2.49 18.71 19.79 11.50
2019 9.03 3.43 2.54 19.29 20.45 12.49
2020 10.60 3.50 2.59 19.77 20.85 14.46
2021 11.21 3.55 2.63 20.26 21.33 15.23
2022 11.79 3.61 2.67 20.78 21.86 15.96
2023 12.43 3.67 2.72 20.98 22.09 16.76
2024 12.77 3.73 2.76 21.50 22.56 17.19
2025 13.06 3.80 2.81 21.98 23.09 17.56
2026 13.23 3.86 2.86 22.43 23.57 17.77
2027 13.30 3.93 2.91 22.98 24.03 17.86
2028 13.47 4.00 2.96 23.76 24.83 18.07
2029 13.53 4.07 3.01 24.38 25.50 18.15
2030 13.58 4.11 3.04 25.07 26.01 18.21
2031 13.72 4.24 3.14 25.82 26.79 18.39
2032 13.92 4.36 3.23 26.60 27.59 18.64
2033 14.00 4.49 3.33 27.40 28.42 18.74
2034 14.08 4.63 3.43 28.22 29.27 18.84
2035 14.21 4.77 3.53 29.07 30.15 19.00
2036 14.11 4.91 3.64 29.94 31.06 18.88
2037 13.93 5.06 3.75 30.84 31.99 18.65
2038 13.84 5.21 3.86 31.76 32.95 18.54
2039 13.59 5.37 3.98 32.72 33.93 18.22
2040 13.91 5.53 4.10 33.70 34.95 18.63
2041 13.96 5.69 4.21 34.71 36.00 18.69
FUEL AND EMISSIONS
SECTION 7 ALLOWANCE PRICE PROJECTIONS
ALASKA RIRP STUDY
Black & Veatch 7-12 February 2010
Table 7-3 (Continued)
Nominal Fuel Price Forecasts ($/MMBtu)
Year Natural Gas Delivered Coal Minemouth Coal HAGO Naphtha Propane
2042 14.17 5.86 4.34 35.75 37.08 18.95
2043 14.30 6.04 4.47 36.82 38.19 19.12
2044 14.59 6.22 4.61 37.93 39.34 19.48
2045 14.73 6.41 4.75 39.06 40.52 19.66
2046 14.94 6.60 4.89 40.24 41.73 19.92
2047 15.07 6.80 5.04 41.45 42.98 20.08
2048 15.37 7.00 5.19 42.68 44.27 20.46
2049 15.50 7.21 5.34 43.97 45.60 20.63
2050 15.64 7.43 5.50 45.29 46.97 20.80
2051 15.77 7.65 5.67 46.64 48.38 20.97
2052 16.08 7.88 5.84 48.05 49.83 21.36
2053 16.21 8.12 6.01 49.49 51.33 21.52
2054 16.34 8.36 6.19 50.97 52.87 21.68
2055 16.57 8.61 6.38 52.50 54.45 21.97
2056 16.80 8.87 6.57 54.08 56.09 22.26
2057 16.93 9.14 6.77 55.70 57.77 22.43
2058 17.17 9.41 6.97 57.37 59.51 22.73
2059 17.30 9.69 7.18 59.09 61.29 22.89
2060 17.75 9.98 7.39 60.86 63.13 23.46
FUEL AND EMISSIONS
SECTION 7 ALLOWANCE PRICE PROJECTIONS
ALASKA RIRP STUDY
Black & Veatch 7-13 February 2010
The EPA has also made an analysis of ACESA. EPA’s CO2 emission price projection is presented in a
presentation, entitled EPA Analysis of the American Clean Energy and Security Act of 2009 H.R. 2454 in the
111th Congress, dated June 23, 2009. The EPA report provides CO2 emission prices for the years 2015,
2030, and 2050. The EPA analysis was used to develop CO2 emission price projections for 2030 through
2050. Emission price projections from 2050 through 2060 were escalated at the general inflation rate of
2.5 percent annually. The CO2 emission allowance price projections are presented in Table 7-4.
Both the EIA and EPA analyses of H.R 2454 consider the development and deployment of carbon capture and
sequestration (CCS).
Table 7-4
CO2 Allowance Price Projections
Year $/ton
2012 18.41
2020 39.70
2030 103.78
2040 213.91
2050 440.89
2060 564.38
SECTION 8 RELIABILITY CRITERIA
ALASKA RIRP STUDY
Black & Veatch 8-1 February 2010
8.0 RELIABILITY CRITERIA
The purpose of this section is to discuss the reliability criteria that were used in this study.
8.1 Planning Reserve Margin Requirements
Currently, the Railbelt utilities maintain a 30 percent reserve margin. For planning purposes, GRETC is
assumed to be required to maintain a 30 percent reserve margin. As the GRETC transmission projects are
implemented and experience is gained in the Railbelt with a more robust transmission system, it may be
possible to reduce the 30 percent planning reserve margin which would further increase benefits under
GRETC. This potential additional savings, however, is not modeled in this study.
8.2 Operating Reserve Margin Requirements
8.2.1 Spinning Reserves
Spinning reserve requirements for the Railbelt system are based on the largest unit on-line. Currently,
Chugach, GVEA, HEA, and ML&P share that spinning reserve requirement in relation to their largest units
on-line. Table 8-1 presents the largest unit for each of the Railbelt utilities and shows their share of the
largest unit.
Table 8-1
Railbelt Spinning Reserve Requirements
Utility Largest Unit
Capacity
(MW)
Percentage of
Largest Unit
Spinning Reserve
Requirement (MW)
CEA Beluga 7/8 108.6 33.6 36.9
GVEA North Pole 2 62.6 19.4 21.2
HEA Nikiski 42.0 13.0 14.3
ML&P Plant 2 Units 7/6 109.6 34.0 37.2
Total 319.5 100.0 109.6
Spinning reserve requirements vary continuously based on the largest unit operating. Throughout the study
period, the spinning reserve requirements increase when new units become the largest unit on the system.
Generally, any unit operating below its maximum load can contribute to the spinning reserve requirement. In
addition, Bradley Lake can provide up to 27 MW of spinning reserves as shown in Table 4-5.
GVEA also has a Battery Energy Storage System (BESS) which provides 27 MW of equivalent spinning
reserves. GVEA currently employs Shed in Lieu of Spin (SILOS) for a portion of GVEA’s spinning reserve
responsibility. In this RIRP, SILOS is not considered for spinning reserve.
SECTION 8 RELIABILITY CRITERIA
ALASKA RIRP STUDY
Black & Veatch 8-2 February 2010
8.2.2 Non-Spinning Operating Reserves
The Railbelt currently requires total operating reserves to be 150 percent of the spinning requirement. This
results in an amount of non-spinning reserves up to 50 percent of spinning reserve capacity that may be
provided by quick-start capacity in order to meet the operating reserve requirement. This non-spinning
operating reserve is proportioned between the Railbelt utilities in the same proportions as spinning reserves.
The units that qualify as quick-start units for meeting operating reserves are presented in Table 8-2.
8.3 Renewable Considerations
Wind, solar, and tidal renewable technologies are not dispatchable; consequently, they are not counted toward
planning or operating reserves.
8.4 Regulation
Resources that are not dispatchable and subject to varying output due to factors that cannot be controlled such
as weather (e.g., variations in wind speed that result in variable wind power output), require additional
regulating capacity in order to maintain system reliability when the wind does not blow or the sun does not
shine. For evaluation purposes, it is assumed that 50 percent of the nameplate capacity of wind and solar
resources will be required to be maintained as additional regulating capacity. Tidal resources, while not
dispatchable, are more predictable, and for evaluation purposes, additional regulating capacity is not included.
SECTION 8 RELIABILITY CRITERIA
ALASKA RIRP STUDY
Black & Veatch 8-3 February 2010
Table 8-2
Quick-Start Units
Name Unit
Winter
Rating
(MW)
Anchorage ML&P – Plant 1 3 32
Anchorage ML&P – Plant 1 4 34.1
Anchorage ML&P – Plant 2 5 37.4
Anchorage ML&P – Plant 2 7 81.8
Anchorage ML&P – Plant 2 8 87.6
Beluga 1 17.5
Beluga 2 17.5
Beluga 3 66.5
Beluga 5 65
Beluga 6 82
Beluga 7 82
Bernice 2 19
Bernice 3 25.5
Bernice 4 25.5
DPP 1 25.8
International 1 14
International 2 14
International 3 19
Nikiski 1 42
North Pole GT1 62.6
North Pole GT2 60.6
Zehnder GT1 19.2
Zehnder GT2 19.6
SECTION 9 CAPACITY REQUIREMENTS
ALASKA RIRP STUDY
Black & Veatch 9-1 February 2010
9.0 CAPACITY REQUIREMENTS
When the 30 percent planning reserve criteria described in Section 8 is applied to the load forecasts presented
in Section 6, the capacity requirements for the Railbelt are established. Comparing those capacity
requirements to the existing generating units and their expected retirement dates results in the capacity
addition requirements for the Railbelt. Figures 9-1 through 9-6 present the capacity requirements for the
following cases.
• Figure 9-1 - Scenario 1A Capacity Requirements Without DSM/EE
• Figure 9-2 - Scenario 1A Capacity Requirements With DSM/EE
• Figure 9-3 - Scenario 2A Capacity Requirements Without DSM/EE
• Figure 9-4 - Scenario 2A Capacity Requirements With DSM/EE
• Figure 9-5 - Scenario 1A Capacity Requirements Including Committed Units Without DSM/EE
• Figure 9-6 - Scenario 1A Capacity Requirements Including Committed Units With DSM/EE
SECTION 9 CAPACITY REQUIREMENTS
ALASKA RIRP STUDY
Black & Veatch 9-2 February 2010
Figure 9-1
Scenario 1A Capacity Requirements Without DSM/EE
0
200
400
600
800
1000
1200
1400
1600
1800
2011 2018 2025 2032 2039 2046 2053 2060
Year(MW)Load 30% Reserves Existing Generation Capacity
SECTION 9 CAPACITY REQUIREMENTS
ALASKA RIRP STUDY
Black & Veatch 9-3 February 2010
Figure 9-2
Scenario 1A Capacity Requirements With DSM/EE
0
200
400
600
800
1000
1200
1400
1600
1800
2011 2018 2025 2032 2039 2046 2053 2060
Year(MW)DSM Adjusted Load 30% Reserves Existing Generation Capacity
SECTION 9 CAPACITY REQUIREMENTS
ALASKA RIRP STUDY
Black & Veatch 9-4 February 2010
Figure 9-3
Scenario 2A Capacity Requirements Without DSM/EE
0.0
500.0
1000.0
1500.0
2000.0
2500.0
3000.0
2011 2018 2025 2032 2039 2046 2053 2060
Year(MW)Load under Large Load Scenario 30% Reserves under Large Load Scenario Existing Generation Capacity
SECTION 9 CAPACITY REQUIREMENTS
ALASKA RIRP STUDY
Black & Veatch 9-5 February 2010
Figure 9-4
Scenario 2A Capacity Requirements With DSM/EE
0
500
1000
1500
2000
2500
3000
2011 2018 2025 2032 2039 2046 2053 2060
Year(MW)DSM Adjusted Load under Large Load Scenario 30% Reserves under Large Load Scenario Existing Generation Capacity
SECTION 9 CAPACITY REQUIREMENTS
ALASKA RIRP STUDY
Black & Veatch 9-6 February 2010
Figure 9-5
Scenario 1A Capacity Requirements Including Committed Units Without DSM/EE
0
200
400
600
800
1000
1200
1400
1600
1800
2011 2018 2025 2032 2039 2046 2053 2060
Year(MW)Load 30% Reserves Existing and CommittedGeneration Capacity
SECTION 9 CAPACITY REQUIREMENTS
ALASKA RIRP STUDY
Black & Veatch 9-7 February 2010
Figure 9-6
Scenario 1A Capacity Requirements Including Committed Units With DSM/EE
0
200
400
600
800
1000
1200
1400
1600
1800
2011 2018 2025 2032 2039 2046 2053 2060
Year(MW)DSM Adjusted Load 30% Reserves Existing and CommittedGeneration Capacity
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-1 February 2010
10.0 SUPPLY-SIDE OPTIONS
The purpose of this section is to summarize the input assumptions that Black & Veatch used related to the
various supply-side resource options considered in the RIRP study. Information is provided for both
conventional technologies and renewable resources.
10.1 Conventional Technologies
10.1.1 Introduction
This subsection describes and characterizes various conventional supply-side technologies including General
Electric (GE) LM6000 and LMS100 simple cycle units, GE 6FA combined cycle units and a 130 MW
pulverized coal (PC) facility. In addition to greenfield developments, the option of repowering Beluga Unit 8
has been considered.
10.1.2 Capital, and Operating and Maintenance (O&M) Cost Assumptions
The capital cost estimates developed in this report include both direct and indirect costs. An allowance for
general owner’s cost items (exclusive of escalation, financing fees, and interest during construction), as
summarized in Table 10-1, has been accounted for in the cost estimates or provided as a percentage of total
costs. The capital cost estimates were developed on an engineer, procure, and construct (EPC) basis.
The O&M cost estimates were derived from proprietary Black & Veatch O&M estimating tools and
representative estimates for similar projects. Costs are based on vendor estimates and recommendations, and
estimated performance information. The cost estimates are divided into fixed and variable O&M. Fixed
O&M costs, expressed as dollars per unit of capacity per year ($/kW-yr), do not vary directly with plant
power generation and consist of wages and wage-related overheads for the permanent plant staff, routine
equipment maintenance and other fees. Variable O&M costs, expressed as dollars per unit of generation
($/MWh) tend to vary in near direct proportion to the output of the unit. Variable O&M include costs
associated with equipment outage maintenance, utilities, chemicals, and other consumables. Fuel costs are
determined separately and are not included in either fixed or variable O&M costs.
10.1.3 Generating Alternatives Assumptions
10.1.3.1 General Capital Cost Assumptions
Unless otherwise discussed, the following general assumptions were applied in developing the cost and
performance estimates:
• The site has sufficient area available to accommodate construction activities including, but not limited
to, office trailers, lay-down, and staging.
• All buildings will be pre-engineered unless otherwise specified.
• Construction power is available at the boundary of the site.
• The plant will not be located on wetlands nor require any other mitigation.
• Service and fire water will be supplied via on-site groundwater wells.
• Potable water will be supplied from the local water utility.
• Wastewater disposal will utilize local sewer systems.
• Costs for transmission lines and switching stations are included as part of the owner’s cost.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-2 February 2010
Table 10-1
Possible Owner’s Costs
Project Development Owner’s Contingency
• Site selection study • Owner’s uncertainty and costs pending final negotiation
• Land purchase/rezoning for greenfield sites • Unidentified project scope increases
• Transmission/gas pipeline right-of-way • Unidentified project requirements
• Road modifications/upgrades
• Demolition
• Costs pending final agreements (e.g., interconnection
contract costs)
• Environmental permitting/offsets Owner’s Project Management
• Public relations/community development
• Legal assistance
• Preparation of bid documents and the selection of contractors
and suppliers
• Provision of project management • Performance of engineering due diligence
• Provision of personnel for site construction management
Spare Parts and Plant Equipment Taxes/Advisory Fees/Legal
• Combustion turbine materials, gas
compressors, supplies, and parts
• Taxes
• Market and environmental consultants
• Steam turbine materials, supplies, and parts • Owner’s legal expenses
• Boiler materials, supplies, and parts • Interconnect agreements
• Balance-of-plant equipment/tools • Contracts (procurement and construction)
• Rolling stock • Property
• Plant furnishings and supplies
Plant Start-up/Construction Support Utility Interconnections
• Owner’s site mobilization • Natural gas service
• O&M staff training • Gas system upgrades
• Initial test fluids and lubricants • Electrical transmission
• Initial inventory of chemicals and reagents • Water supply
• Consumables • Wastewater/sewer
• Cost of fuel not recovered in power sales
• Auxiliary power purchases Financing (included in fixed charge rate, but not in direct
capital cost)
• Acceptance testing • Financial advisor, lender’s legal, market analyst, and engineer
• Construction all-risk insurance • Loan administration and commitment fees
• Debt service reserve fund
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-3 February 2010
10.1.3.2 Combustion Turbine Capital Cost Assumptions
• Combustion turbines will be fueled with natural gas as the primary fuel with an option provided for
dual fuel with No. 2 ultra-low sulfur diesel (ULSD) fuel oil as the backup fuel. The cost of fuel
unloading and delivery to the site(s) is included.
• The LM6000 and the LMS100 will utilize water injection for primary NOx control when operating on
fuel oil. The 6FA configurations will utilize dry low NOx burners when operating on natural gas and
water injection when operating on fuel oil.
• All of the combustion turbine configurations will include selective catalytic reduction (SCR) and a
CO catalyst.
• Standard sound enclosures will be included for the combustion turbines.
• Natural gas pressure is assumed to be adequate for the LM6000 and the combined cycle alternatives.
Gas compressors will be included for the LMS100 combustion turbine. A regulating and metering
station is assumed to be part of the owner’s cost for each alternative.
• Demineralized water will be provided via portable demineralizers for simple cycle alternatives and
will be supplied by a demineralized water treatment system for the combined cycle options.
• Both of the combustion turbine combined cycle configurations will utilize air cooled condensers for
heat rejection.
• None of the combustion turbine configurations will utilize inlet cooling.
• Field erected storage tanks include the following:
o Service/fire water storage tank.
o Fuel oil storage tank (3 days storage capacity).
o Demineralized water storage tank (3 days storage capacity).
10.1.3.3 Coal Facility Capital Cost Assumptions
• The PC plant will be equipped with an SCR for NOx control, an activated carbon injection system for
mercury reduction, a dry flue gas desulfurization unit for sulfur reduction and a fabric filter system
for managing particulate emissions.
• The subcritical PC plant will utilize an air cooled condenser for heat rejection.
10.1.3.4 Direct Cost Assumptions
• Total direct capital costs are expressed in 2009 dollars.
• Direct costs include the costs associated with the purchase of equipment, erection, and contractors’
services.
• Construction costs are based on an EPC contracting philosophy.
• Spare parts for start-up are included. Initial inventory of spare parts for use during operation is
included in the owner’s costs.
• Permitting and licensing are included in the owner’s costs.
10.1.3.5 Indirect Cost Assumptions
• General indirect costs, including all necessary services required for checkout, testing, and
commissioning.
• Insurance, including builder’s risk, general liability, and liability insurance for equipment and tools.
• Engineering and related services.
• Field construction management services including field management staff with supporting staff
personnel, field contract administration, field inspection and quality assurance, and project control.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-4 February 2010
• Technical direction and management of start-up and testing, cleanup expense for the portion not
included in the direct cost construction contracts, safety and medical services, guards and other
security services, insurance premiums, and performance bonds.
• Contractor’s contingency and profit.
• Transportation costs for delivery to the jobsite.
• Start-up and commissioning spare parts.
• Allowance for funds used during construction and financing fees will be accounted for separately as
part of the economic evaluations and, therefore, are not included in the capital cost or owner’s cost
estimates.
10.1.3.6 Combustion Turbine O&M Cost Assumptions
• O&M cost estimates are provided based on an assumed capacity factor of 75 percent.
• Simple cycle units are assumed to start 200 times per year.
• Combined cycle units are assumed to start 50 times per year.
• Location was considered to be a greenfield site.
• Plant staff wage rates are based on an operator rate of $93,200 per year.
• Burden rate is 56 percent.
• Staff supplies and materials are estimated to be 5 percent of staff salary.
• Estimated employee training cost and incentive pay/bonuses are included.
• Routine maintenance costs are estimated based on Black & Veatch experience and manufacturer
input.
• Contract services include costs for services not directly related to power production.
• Insurance and property taxes are not included.
• The variable O&M analysis is based on a repeating maintenance schedule over the life of the plant.
• Variable O&M costs are estimated through at least one major overhaul.
• Combustion turbine combustion inspections, hot gas path inspections, and major overhauls are based
on Original Equipment Manufacturer (OEM) pricing and recommendations.
• Steam turbine, generator, heat recovery steam generator and other balance of plant maintenance costs
are based on Black & Veatch experience and vendor data and recommendations.
• SCR was included for NOx control for the simple cycle and combined cycle equipment.
• SCR uses 19 percent aqueous ammonia. Aqueous ammonia cost was estimated at $250/wet ton.
• Costs associated with a CO catalyst are included.
• Raw water costs are $0.77 per 1,000 gallons.
• Water treatment costs are included for water make-up and demineralized water where needed.
• Demineralized water treatment costs are $3.00 per 1,000 gallons.
• Station net capacity output is based on fired operation (duct burners) at annual average ambient
conditions.
• The O&M analysis was completed in 2009 dollars.
10.1.3.7 Coal Facility O&M Cost Assumptions
• Fuel is pulverized coal.
• Net plant heat rate is 9,698 Btu/kWh.
• O&M cost estimates are based on an assumed gross capacity factor of 75 percent.
• O&M cost estimates assume the unit will start 50 times per year.
• Location was considered to be a greenfield site.
• Plant staff wage rates are based on an operator rate of $93,200 per year.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-5 February 2010
• Burden rate was 56 percent.
• Staff supplies and material are estimated to be 5 percent of staff salary.
• Estimated employee training cost and incentive pay/bonuses are included.
• Routine maintenance costs are estimated based on Black & Veatch experience and manufacturer
input.
• Contract services include costs for services not directly related to power production.
• Insurance and property taxes are not included.
• The variable O&M analysis is based on a repeating maintenance schedule over the life of the plant.
• Variable O&M costs are estimated through at least one major overhaul.
• Steam turbine, generator, boiler and other balance of plant maintenance costs are based on Black &
Veatch experience and vendor data and recommendations.
• SCR is included for NOx control.
• SCR uses anhydrous ammonia with an estimated cost of $800/wet ton.
• Powdered activated carbon is included for mercury control.
• Activated carbon costs are estimated to be $1,600/ton.
• Dry Flue Gas Desulfurization (FGD) is used for SO2 control.
• Dry FGD uses lime with an estimated cost of $75/ton.
• A fabric filter system is included for particulate control.
• Raw water costs are $0.77 per 1,000 gallons.
• Water treatment costs are included for cycle make-up and service water where needed.
• Cycle make-up water treatment costs are $5.00 per 1,000 gallons.
• The O&M analysis was completed in 2009 dollars.
10.1.4 Conventional Technology Options
The conventional technology supply-side options are discussed in this section. In addition to a general
description, a summary of projected performance, emissions, capital costs, O&M costs, construction
schedules, scheduled maintenance requirements, and forced outage rates have been developed for each option.
The conventional technologies considered include simple cycle combustion turbines, combined cycle
configurations and a PC coal generating plant.
Although the combustion turbines and the combined cycle alternatives discussed herein assume a specific
manufacturer and specific models (e.g., aeroderivative and frame combustion turbines), doing so is not
intended to limit the alternatives considered solely to these models. Rather, such assumptions were made to
provide indicative output and performance data. Several manufacturers offer similar generating technologies
with similar attributes, and the performance data presented in this analysis should be considered indicative of
comparable technologies across a wide array of manufacturers.
Power plant output and heat rate performance will degrade with hours of operation due to factors such as
blade wear, erosion, corrosion, and increased tube leakage. Periodic maintenance and overhauls can recover
much, but not all, of the degraded performance when compared to the unit’s new and clean performance. The
average degradation over the unit’s operating life that cannot be recovered is referred to herein as
nonrecoverable degradation, and estimates have been developed by Black & Veatch to capture its impacts.
Nonrecoverable degradation will vary from unit to unit, so technology-specific nonrecoverable output and
heat rate factors have been developed and are presented in Table 10-2. The degradation percentages are
applied one time to the new and clean performance data, and reflect average lifetime aggregate
nonrecoverable degradation.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-6 February 2010
Table 10-2
Nonrecoverable Degradation Factors
Degradation Factor
Unit Description Output (%) Heat Rate (%)
GE LM6000 Simple Cycle 3.2 1.75
GE LMS100 Simple Cycle 3.2 1.75
GE 1x1 6FA Combined Cycle 2.7 1.50
GE 2x1 6FA Combined Cycle 2.7 1.50
10.1.4.1 Simple Cycle Combustion Turbine Alternatives
Combustion turbine generators (CTGs) are sophisticated power generating machines that operate according to
the Brayton thermodynamic power cycle. A simple cycle combustion turbine generates power by
compressing ambient air and then heating the pressurized air to approximately 2,000ºF or more, by burning
oil or natural gas, with the hot gases then expanding through a turbine. The turbine drives both the
compressor and an electric generator. A typical combustion turbine would convert 30 to 35 percent of the
fuel to electric power. A substantial portion of the fuel energy is wasted in the form of hot (typically 900ºF to
1,100ºF) gases exiting the turbine exhaust. When the combustion turbine is used to generate power and no
energy is captured and utilized from the hot exhaust gases, the power cycle is referred to as a “simple cycle”
power plant.
Combustion turbines are mass flow devices, and their performance changes with changes in the ambient
conditions at which the unit operates. Generally speaking, as temperatures increase, combustion turbine
output and efficiency decrease due to the lower density of the air. To lessen the impact of this negative
characteristic, most of the newer combustion turbine-based power plants often include inlet air cooling
systems to boost plant performance at higher ambient temperatures.
Combustion turbine pollutant emission rates are typically higher on a part per million (ppm) basis at part load
operation than at full load. This limitation has an effect on how much plant output can be decreased without
exceeding pollutant emissions limits. In general, combustion turbines can operate at a minimum load of about
50 percent of the unit’s full load capacity while maintaining emission levels within required limits.
Advantages of simple cycle combustion turbine projects include low capital costs, short design and
construction schedules, and the availability of units across a wide range of capacity. Combustion turbine
technology also provides rapid start-up and modularity for ease of maintenance.
The primary drawback of combustion turbines is that, due to the cost of natural gas and fuel oil, the variable
cost per MWh of operation is high compared to other conventional technologies. As a result, simple cycle
combustion turbines are often the technology of choice for meeting peak loads in the power industry, but are
not usually economical for baseload or intermediate service.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-7 February 2010
GE LM6000PC Combustion Turbine
The GE LM6000PC was selected as a potential simple cycle alternative due to its modular design, efficiency,
and size. It is a two-shaft gas turbine engine derived from the core of the CF6-80C2, GE’s high thrust, high
efficiency aircraft engine.
The LM6000 consists of a five-stage low-pressure compressor (LPC), a 14-stage variable geometry high-
pressure compressor (HPC), an annular combustor, a two-stage air-cooled high-pressure turbine (HPT), a
five-stage low-pressure turbine (LPT), and an accessory drive gearbox. The LM6000 has two concentric rotor
shafts, with the LPC and LPT assembled on one shaft, forming the LP rotor. The HPC and HPT are
assembled on the other shaft, forming the HP rotor.
The LM6000 uses the LPT to power the output shaft. The LM6000 design permits direct-coupling to 3,600
revolutions per minute (rpm) generators for 60 hertz (Hz) power generation. The gas turbine drives its
generator through a flexible, dry type coupling connected to the front, or “cold,” end of the LPC shaft. The
LM6000 gas turbine generator set has the following attributes:
• Full power in approximately 10 minutes
• Cycling or peaking operation
• Synchronous condenser capability
• Compact, modular design
• More than 5 million operating hours
• More than 450 turbines sold
• Dual fuel capability
The capital cost estimate was based on utilizing GE’s Next-Gen package for the LM6000. This package
includes more factory assembly, resulting in less construction time. Table 10-3 presents the operating
characteristics of the LM6000 combustion turbine. Water injection and high temperature SCR would be used
to control NOx to 3 ppmvd while operating on natural gas and on ULSD. Table 10-4 presents estimated
emissions for the LM6000.
GE LMS100 Combustion Turbine
The LMS100 is a newer GE unit and has the disadvantage of not having as much commercial experience. As
the LMS100 gains commercial acceptance, it will likely replace the use of two-unit blocks of LM6000s in the
future.
The LMS100 is currently the most efficient simple cycle gas turbine in the world. In simple cycle mode, the
LMS100 has an approximate efficiency of 46 percent, which is 10 percent greater than the LM6000. It has a
high part-load efficiency, cycling capability (without increased maintenance cost), better performance at high
ambient temperatures, modular design (minimizing maintenance costs), the ability to achieve full power from
a cold start in 10 minutes, and is expected to have high availability, though this availability must be
commercially demonstrated through additional LMS100 experience.
The LMS100 is an aeroderivative turbine and has many of the same characteristics of the LM6000. The
former uses off-engine intercooling within the turbine’s compressor section to increase its efficiency. The
process of cooling the air optimizes the performance of the turbine and increases output efficiency. At
50 percent turndown, the part-load efficiency of the LMS100 is 40 percent, which is a greater efficiency than
most simple cycle combustion turbines at full load.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-8 February 2010
Table 10-3
GE LM6000 PC Combustion Turbine Characteristics
Ambient Condition
Net Capacity
(MW)(1, 2)
Net Plant Heat Rate
(Btu/kWh, HHV)(1, 2)
Winter (-10º F and 100% RH) (Full Load) 46.6 9,636
Winter (15º F and 68% RH) (Full Load) 47.5 9,662
Winter (15º F and 68% RH) (75% Load) 35.5 10,313
Winter (15º F and 68% RH) (50% Load) 23.5 11,791
Average (30º F and 68% RH) (Full Load) 47.6 9,741
Average (30º F and 68% RH) (75% Load) 35.6 10,365
Average (30º F and 68% RH) (50% Load) 23.6 11,828
Summer (59º F and 68% RH) (Full Load) 39.9 10,058
RH = Relative humidity.
(1)Net capacity and net plant heat rate include degradation factors.
(2)Net capacity and heat rate assume operation on natural gas.
Table 10-4
GE LM6000 PC Estimated Emissions(1)
NOx, ppmvd at 15% O2 3
NOx, lb/MBtu 0.0108
SO2, lb/MBtu 0.0022
CO2, lb/MBtu 115.1
CO, ppmvd at 15% O2 3
(1)Emissions are at full load at 30º F, reflect operation on
natural gas, and include the effects of SCR, water injection
and CO catalyst.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-9 February 2010
There are two main differences between the LM6000 and the LMS100. The LMS100 cools the compressor
air after the first stage of compression with an external heat exchanger and unlike the LM6000, which has an
HPT and a power turbine, the LMS100 has an additional IPT to increase output efficiency.
As a packaged unit, the LMS100 consists of a 6FA turbine compressor, which outputs compressed air to the
intercooling system. The intercooling system cools the air, which is then compressed in a second compressor
to a high pressure, heated with combusted fuel, and then used to drive the two-stage IP/HP turbine described
above. The exhaust stream is then used to drive a five-stage power turbine. Exhaust gases are at a
temperature of less than 800º F, which allows the use of a standard SCR system for NOx control.
Table 10-5 presents the operating characteristics of the LMS100 combustion turbine. Standard SCR will be
used to control NOx to 3 ppmvd while operating on natural gas. Water injection and SCR will be used to
control NOx while operating on ULSD. Table 10-6 presents estimated emissions for the LMS100.
10.1.4.2 Combined Cycle Alternatives
Combined cycle power plants use one or more CTGs and one or more steam turbine generators to produce
energy. Combined cycle power plants operate according to a combination of both the Brayton and Rankine
thermodynamic power cycles. High pressure (HP) steam is produced when the hot exhaust gas from the CTG
is passed through a heat recovery steam generator (HRSG). The HP steam is then expanded through a steam
turbine, which spins an electric generator.
Combined cycle configurations have several advantages over simple cycle combustion turbines. Advantages
include increased efficiency and potentially greater operating flexibility if duct burners are used.
Disadvantages of combined cycles relative to simple cycles include a small reduction in plant reliability and
an increase in the overall staffing and maintenance requirements due to added plant complexity.
1x1 GE 6FA Combined Cycle Alternative
The 1x1 combined cycle generating unit would include one GE 6FA CTG, one HRSG, one steam turbine
generator, and an air cooled condenser. The combined cycle unit will be dual-fueled, with natural gas as the
primary fuel and ULSD as the backup fuel.
The GE 6FA heavy-duty gas turbine is an aerodynamic scale of the GE 7FA. In the development of the
turbine GE scaled a proven advanced-technology design and combined it with advanced aircraft engine
cooling and sealing technology. The 6FA fleet has over two million operating hours logged with more than
100 units installed or on order. The 6FA gas turbine configuration includes an 18-stage compressor, six
combustion chambers and a three-stage turbine. The shaft is supported on two bearings. The combustion
system standard offering includes dry low NOx burners capable of multi-fuel applications.
The HRSG will convert waste heat from the combustion turbine exhaust to steam for use in driving the steam
turbine generator. The HRSG is expected to be a natural circulation, three pressure, reheat unit. The
combined cycle alternative will be designed for supplemental duct firing (on natural gas only). Supplemental
firing necessitates a larger steam turbine and changes to other plant components, leading to an increase in
total capital cost and a decrease in plant efficiency in order to realize the additional output. SCR and dry low-
NOx burners will be included to control NOx to 3 ppmvd while burning natural gas, and a CO catalyst will be
included to reduce emissions. Water injection will be used for NOx control when burning ULSD.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-10 February 2010
Table 10-5
GE LMS100 Combustion Turbine Characteristics
Ambient Condition
Net Capacity
(MW)(1, 2)
Net Plant Heat Rate
(Btu/kWh, HHV)(1, 2)
Winter (-10º F and 100% RH) (Full Load) 95.3 8,894
Winter (15º F and 68% RH) (Full Load) 95.5 8,925
Winter (15º F and 68% RH) (75% Load) 71.4 9,445
Winter (15º F and 68% RH) (50% Load) 47.3 10,489
Winter (15º F and 68% RH) (Min Load) 35.7 11,444
Average (30º F and 68% RH) (Full Load) 96.0 8,963
Average (30º F and 68% RH) (75% Load) 71.8 9,456
Average (30º F and 68% RH) (50% Load) 47.6 10,501
Average (30º F and 68% RH) (Min Load) 36.3 11,415
Summer (59º F and 68% RH) (Full Load) 97.4 9,041
RH = Relative humidity.
(1)Net capacity and net plant heat rate include degradation factors.
(2)Net capacity and heat rate assume operation on natural gas.
Table 10-6
GE LMS100 Estimated Emissions(1)
NOx, ppmvd at 15% O2 3
NOx, lb/MBtu 0.0108
SO2, lb/MBtu 0.0022
CO2, lb/MBtu 115.1
CO, ppmvd at 15% O2 3
(1)Emissions are at full load at 30º F, and include the effects
of SCR, water injection and CO catalyst.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-11 February 2010
The steam turbine is based on a tandem-compound, single reheat condensing turbine operating at 3,600 rpm.
The steam turbine will have one HP section, one intermediate-pressure (IP) section, and a two-flow low-
pressure (LP) section. Turbine suppliers’ standard auxiliary equipment, lubricating oil system, hydraulic oil
system, and supervisory, monitoring, and control systems are included. A single synchronous generator is
included, which will be direct coupled to the steam turbine.
Table 10-7 presents the operating characteristics of the 1x1 GE 6FA combined cycle generating unit.
Table 10-8 presents estimated emissions for the 1x1 GE 6FA combined cycle generating unit.
2x1 GE 6FA Combined Cycle Alternative
The 2x1 combined cycle generating unit would include two GE 6FA CTG, two HRSGs, one steam turbine
generator, and an air cooled condenser. The combined cycle unit will be dual-fueled, with natural gas as the
primary fuel and ULSD as the backup fuel.
The HRSG will convert waste heat from the combustion turbine exhaust to steam for use in driving the steam
turbine generator. The HRSG is expected to be a natural circulation, three pressure, reheat unit. The
combined cycle alternative will be designed for supplemental duct firing (on natural gas only). SCR and dry
low- NOx burners will be included to control NOx to 3 ppmvd while burning natural gas, and a CO catalyst
will be included to reduce emissions. Water injection will be used for NOx control when burning ULSD.
The steam turbine is based on a tandem-compound, single reheat condensing turbine operating at 3,600 rpm.
The steam turbine will have one HP section, one IP section, and a two-flow LP section. Turbine suppliers’
standard auxiliary equipment, lubricating oil system, hydraulic oil system, and supervisory, monitoring, and
control systems are included. A single synchronous generator is included, which will be direct coupled to the
steam turbine.
Table 10-9 presents the operating characteristics of the 2x1 GE 6FA combined cycle generating unit.
Table 10-10 presents estimated emissions for the 2x1 GE 6FA combined cycle generating unit.
10.1.4.3 Coal Technologies
The coal technology presented in this technology assessment includes a subcritical PC generating facility.
Other coal technologies such as integrated gasification combined cycle (IGCC) or carbon capture and
sequestration (CCS) could also be considered, but those technologies have not developed to a point where
they have significantly penetrated the coal generation market. In addition, generating costs from these
technologies generally exceed those of PC’s. Therefore, this technology assessment provides estimates of the
performance and cost for the PC alternative.
Subcritical Pulverized Coal (PC) (130 MW)
Coal is the most widely used fuel for the production of power, and most coal-burning power plants use PC
boilers. PC units utilize a proven technology with a very high reliability level. These units have the
advantage of being able to accommodate a single unit size of up to 1,300 MW, and the economies of scale can
result in low busbar costs. PC units are relatively easy to operate and maintain.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-12 February 2010
Table 10-7
GE 1x1 6FA Combined Cycle Characteristics
Net Capacity
(MW)(1, 2)
Net Plant Heat Rate
(Btu/kWh, HHV)(1, 2)
Ambient Condition Fired Unfired Fired Unfired
Winter (-10º F and 100% RH) (Full Load) 161.3 120.8 7,814 7,581
Winter (15º F and 68% RH) (Full Load) 153.7 118.1 7,770 7,307
Winter (15º F and 68% RH) (75% Load) (3) 115.1 7,290
Winter (15º F and 68% RH) (50% Load) (3) 76.6 8,288
Winter (15º F and 68% RH) (Min Load) (3) 50.6 9,187
Average (30º F and 68% RH) (Full Load) (3) 150.4 113.8 7,751 7,418
Average (30º F and 68% RH) (75% Load) (3) 112.7 7,426
Average (30º F and 68% RH) (50% Load) (3) 75.4 8,047
Average (30º F and 68% RH) (Min Load) (3) 48.5 9,531
Summer (59º F and 68% RH) (Full Load) 143.0 110.6 7,768 7,282
RH = Relative humidity.
(1)Net capacity and net plant heat rate include degradation factors
(2)Net capacity and heat rate assume operation on natural gas.
(3)Part load performance percent load is based on gas turbine load point.
Table 10-8
GE 1x1 6FA Combined Cycle Estimated Emissions(1)
NOx, ppmvd at 15% O2 3
NOx, lb/MBtu 0.0109
SO2, lb/MBtu 0.0020
CO2, lb/MBtu 115.1
CO, ppmvd at 15% O2 3
(1)Emissions are at full load at 30º F, reflect operation on natural gas,
and include the effects of SCR and CO catalyst.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-13 February 2010
Table 10-9
GE 2x1 6FA Combined Cycle Characteristics
Net Capacity
(MW)(1, 2)
Net Plant Heat Rate
(Btu/kWh, HHV)(1, 2)
Ambient Condition Fired Unfired Fired Unfired
Winter (-10º F and 100% RH) (Full Load) 325.0 248.4 7,755 7,374
Winter (15º F and 68% RH) (Full Load) 310.2 237.6 7,698 7,264
Winter (15º F and 68% RH) (75% Load) (3) 229.8 7,366
Winter (15º F and 68% RH) (50% Load) (3) 154.9 8,089
Winter (15º F and 68% RH) (Min Load) (3) 99.4 9,335
Average (30º F and 68% RH) (Full Load) (3) 303.9 231.9 7,684 7,281
Average (30º F and 68% RH) (75% Load) (3) 227.6 7,283
Average (30º F and 68% RH) (50% Load) (3) 151.7 7,996
Average (30º F and 68% RH) (Min Load) (3) 99.6 9,277
Summer (59º F and 68% RH) (Full Load) 289.2 222.9 7,698 7,224
RH = Relative humidity.
(1)Net capacity and net plant heat rate include degradation factors
(2)Net capacity and heat rate assume operation on natural gas.
(3)Part load performance percent load is based on gas turbine load point.
Table 10-10
GE 2x1 6FA Combined Cycle Estimated Emissions(1)
NOx, ppmvd at 15% O2 3
NOx, lb/MBtu 0.0109
SO2, lb/MBtu 0.0020
CO2, lb/MBtu 115.1
CO, ppmvd at 15% O2 3
(1)Emissions are at full load at 30º F, reflect operation on natural gas,
and include the effects of SCR and CO catalyst.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-14 February 2010
New-generation PC boilers can be designed for supercritical steam pressures of 3,500 to 4,500 psig, compared
to the steam pressure of 2,400 psig for conventional subcritical boilers. The increase in pressure from
subcritical (2,400 psig) to supercritical (3,500 psig) generally improves the net plant heat rate by about
200 Btu/kWh (higher heating value [HHV]), assuming the same main and reheat steam temperatures and the
same cycle configuration. This increase in efficiency comes at a cost, however, and the economics of the
decision between subcritical and supercritical design depend on the cost of fuel, expected capacity factor of
the unit, environmental factors, and the cost of capital.
The subcritical PC generating unit characterized here includes a single steam turbine generator and subcritical
PC boiler fueled by low-grade sub-bituminous coal. Air quality control systems include low- NOx burners,
SCR for NOx control, dry FGD for SO2 control, activated carbon injection for mercury control, and fabric
filters for particulate control. Heat rejection is accomplished by an air cooled condenser.
Table 10-11 presents the operating characteristics of the subcritical PC generating unit and Table 10-12
presents the estimated.
10.1.4.4 Conventional Technology Alternatives Capital Costs, O&M Costs, Schedule, and
Maintenance Summary
The estimated capital costs, O&M costs, schedules, forced outage, and maintenance assumptions for the
conventional alternatives are summarized in Table 10-13. All costs are provided in 2009 dollars. The EPC
cost is inclusive of engineering, procurement, construction, and indirect costs for construction of each
alternative utilizing a fixed price, turnkey type contracting structure. Owner’s costs were developed using the
previously described assumptions, with site-specific cost additions or reductions as discussed previously. The
assumed owner’s cost allowance is representative of typical owner’s costs, exclusive of escalation, financing
fees, and interest during construction, which will be accounted for separately in the economic analyses.
Owner’s costs are specific to individual projects and may change from those presented in Table 10-13.
Fixed and variable O&M costs are also provided in 2009 dollars. Fixed costs include labor, maintenance, and
other fixed expenses excluding backup power, property taxes, and insurance. Variable costs include outage
maintenance, consumables, and replacements dependent upon unit operation. Construction schedules are
indicative of typical construction durations for the alternative technologies and plant sizes and represent
estimated schedules from receipt of notice-to-proceed to commercial operation. Actual construction
schedules will depend upon equipment delivery schedules, which are highly market driven, and therefore may
be longer than those presented in Table 10-13. Actual costs may also vary from the estimates provided in
Table 10-13.
The annual average scheduled and forced outage assumptions for the generating alternatives are also
presented in Table 10-13. The scheduled forced outages represent the average outage through a complete
maintenance cycle.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-15 February 2010
Table 10-11
Subcritical PC Thermal Performance Estimates
Ambient Condition
Net Capacity
(MW)(1, 2)
Net Plant Heat Rate
(Btu/kWh, HHV)(1, 2)
Winter (-10º F and 100% RH) (Full Load) 128.1 9,830
Winter (15º F and 68% RH) (Full Load) 128.1 9,834
Winter (15º F and 68% RH) (75% Load) 96.0 10,143
Winter (15º F and 68% RH) (50% Load) 64.0 12,030
Winter (15º F and 68% RH) (Min Load) 51.2 12,246
Average (30º F and 68% RH) (Full Load) 128.1 9,843
Average (30º F and 68% RH) (75% Load) 96.0 10,109
Average (30º F and 68% RH) (50% Load) 64.0 11,734
Average (30º F and 68% RH) (Min Load) 51.2 12,547
Summer (59º F and 68% RH) (Full Load) 128.1 10,004
RH = Relative humidity.
(1)Net capacity and net plant heat rate include an applied 1.5% degradation factor.
(2)Net capacity and heat rate assume operation on a bituminous coal and petcoke blend.
Table 10-12
Subcritical PC Estimated Air Emissions(1)
NOx, lb/MBtu 0.05
SO2, lb/MBtu 0.06
CO2, lb/MBtu 212
CO, lb/MBtu 0.10
PM10, lb/MBtu 0.018
(1)Emissions are at full load at 30º F, reflect operation on sub-
bituminous coal. All estimates are presented on the basis of
HHV.
SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Black & Veatch 10-16 February 2010 Table 10-13 Capital Costs, O&M Costs, and Schedules for the Generating Alternatives (All Costs in 2009 Dollars) Supply Alternative EPC Cost ($Millions)(1) Owner’s Cost ($Millions)(2) Total Cost ($Millions) Full Load Net Capacity at 70° F (MW) Total Cost ($/kW) at 70° F Fixed O&M ($/kW-yr) at 70° F Variable O&M ($/MWh) Construction Schedule (Months)(3) Scheduled Maintenance (days) Forced Outage (percent) GE LM6000 SC 49.71 12.43 62.14 49.2 1,263 64.41 3.85 21 10 2 GE LMS100 SC 100.54 25.14 125.68 99.2 1,267 32.5 3.08 24 10 2 1x1 GE 6FA CC w/ Supplemental Firing 259.11 64.78 323.89 154.6 2,095 24.61 2.71 30 14 3 2x1 GE 6FA CC w/ Supplemental Firing 409.20 102.30 511.50 312.3 1,638 16.12 2.61 30 14 3 130 MW sub-critical PC 688.30 206.49 894.79 130.1 6,878 100.89 2.59 62 16 5 (1)EPC costs include SCR, CO catalyst, and dual fuel capability as applicable to each alternative. (2)Owner’s costs are specific to individual projects and may change from those presented. (3)Construction schedules will depend upon equipment delivery schedules, which are highly market driven, and therefore may be longer than those presented.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-17 February 2010
10.2 Beluga Unit 8 Repowering
Currently, Chugach Electric plans to retire its Beluga Generation Unit Number 8, which is the steam turbine
unit at the Beluga 2x1 combined cycle facility, at the end of 2014. As an alternative to building new gas fired
generation, Chugach identified an option that would include rebuilding Unit 8 and continuing to operate the
Beluga Generation plant in combined cycle mode through the end of 2034. The rebuild would occur over a
three year period from 2014 through 2016 with a total cost of $50 million.
10.3 GVEA North Pole 1x1 Retrofit
GVEA identified an opportunity for a combined cycle retrofit at the existing North Pole combined cycle
facility. The 1x1 North Pole combined cycle facility was built to accommodate another 1x1 train and the
steam turbine is already sized for a 2x1. The retrofit involves adding an LM6000 and a heat recovery steam
generator to the existing facility. The new 1x1 combined cycle train has a maximum capacity of 64 MW and
a full load heat rate of 8,270 Btu/kWh. The capital cost for the retrofit has a total cost of $83 million in
2009 dollars. The variable O&M for the unit is modeled at $2.19/MWh. Since the fixed O&M costs are
already modeled in the existing North Pole combined cycle unit, they are set at $0/kW-yr for the retrofitted
unit.
10.4 Renewable Energy Options
10.4.1 Hydroelectric Project Options
Hydroelectric power is currently the Railbelt’s largest source of renewable energy, responsible for
approximately 9 percent of the Railbelt’s electrical energy. Many of the State’s developed hydro resources
are located near communities in Southcentral, the Alaska Peninsula, and Southeast. Hydro projects include
those that involve storage, both with and without dam construction, and smaller “run-of-river” projects. A
number of potential hydro projects exist within or near the Railbelt region. The locations for the projects
shown below represent either the service area in which the project is located or the transmission area shown in
Figure 4-1 in which the project is interconnected to the Railbelt grid.
• Susitna - 380 – 1,880 MW, MEA
• Glacier Fork – 75 MW, MEA
• Chakachamna – 330 MW, Chugach (Anchorage)
• South Fork/Eagle River – 1 MW, MEA
• Fishhook – 2 MW, MEA
• Grant Lake/Falls Creek – 5 MW, Kenai
• 7 Other Small Hydro Projects in AEA’s database
In addition, the developers of several proposed hydro projects (each with $5 million or above estimated
project cost) on the Railbelt have applied for grant requests from the AEA Renewable Energy Fund Grant
Program, which was established by Alaska Legislature in 2008. Table 10-14 shows each proposed hydro
project’s name, applicant, estimated project cost, grant requested, funding decision and amount recommended
by AEA after two rounds of ranking and funding allocations conducted by AEA.
Based on review of the above information and discussion with stakeholders including the Railbelt Utilities,
Black & Veatch assumed that the proposed Susitna, Chakachamna, and Glacier Fork projects will be
considered as potential supply-side alternatives in this RIRP study along with a 5 MW generic hydro unit in
the Kenai and a 2 MW generic hydro unit in MEA’s service area. The following subsections discuss further
details of these proposed projects.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-18 February 2010
Table 10-14
AEA Recommended Funding Decisions - Hydro
Project Name Applicant
Project Cost
($000)
Grant
Requested
($000)
Recommended
Funding
Decision
Recommended
Funding
Amount
($000)
Grant Lake/Falls
Creek Hydro
Feasibility Study
Kenai Hydro,
LLC
$26,924 $816 Full funding $816
Fourth of July
Creek Hydro
Reconnaissance
Independence
Power, LLC
$15,675 $7,838 Partial funding $20
Victor Creek
Hydro(1)
Kenai Hydro,
LLC
$19,860 $88 Full funding $88
Glacier Fork
Hydro
Glacier Fork
Hydro, LLC
$330,000 $5,000 Partial funding $500
Archangel Creek
Hydro
Archangel
Green Power,
LLC
$6,420 $100 Not
recommended(2)
None
Nenana Healy
Hydro Phase II
GVEA $24,000 $2,200 Application
Withdrawn
None
Note:
1. Project failed to get funding after the appropriation for Round 2 was limited to $25 million.
2. The project did not pass Stage 2 review or was excluded in Stage 3 review for geographical spreading.
10.4.1.1 Susitna Project
Description of Project
A hydroelectric project on the Susitna River has been studied for more than 50 years and is again being
considered by the State of Alaska as a long term source of energy. In the 1980s, the project was studied
extensively by the Alaska Power Authority (APA) and a license application was submitted to the Federal
Energy Regulatory Commission (FERC). Developing a workable financing plan proved difficult for a project
of this scale. When this existing difficulty was combined with the relatively low cost of gas-fired electricity in
the Railbelt and the declining price of oil throughout the 1980s, and its resulting impacts upon the State
budget, the APA terminated the project in March 1986. The project’s location is shown in Figure 10-1.
In 2008, the Alaska State Legislature authorized the AEA to perform an update of the project. That
authorization also included this RIRP project to evaluate the ability of this project and other sources of energy
to meet the long term energy demand for the Railbelt region of Alaska. Of all the hydro projects in the
Railbelt region, the Susitna projects are the most advanced and best understood.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-19 February 2010
Figure 10-1
Proposed Susitna Hydro Project Location
(Source: HDR)
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-20 February 2010
HDR was contracted by AEA to update the cost estimate, energy estimates and the project development
schedule for a Susitna River hydroelectric project. The results of that study, except for the detailed
appendices, are included in Appendix A (note: one of the detailed appendices in the HDR Report
[Appendix D], which is not included in Appendix A of this report, addresses the issue of the potential impact
of climate changes on Susitna’s resource potential; this appendix can be viewed in the full HDR report which
is available on the AEA web site).
The initial alternatives reviewed were based upon the 1983 FERC license application and subsequent 1985
amendment which presented several project alternatives:
• Watana. This alternative consists of the construction of a large storage reservoir on the Susitna River
at the Watana site with an 885-foot-high rock fill dam and a six-unit powerhouse with a total installed
capacity of 1,200 MW.
• Low Watana Expandable. This alternative consists of the Watana dam constructed to a lower
height of 700 feet and a four-unit powerhouse with a total installed capacity of 600 MW. This
alternative contains provisions that would allow for future raising of the dam and expansion of the
powerhouse.
• Devil Canyon. This alternative consists of the construction of a 646-foot-high concrete dam at the
Devil Canyon site with a four-unit powerhouse with a total installed capacity of 680 MW.
• Watana/Devil Canyon. This alternative consists of the full-height Watana development and the
Devil Canyon development as presented in the 1983 FERC license application. The two dams and
powerhouses would be constructed sequentially without delays. The combined Watana/Devil Canyon
development would have a total installed capacity of 1,880 MW.
• Staged Watana/Devil Canyon. This alternative consists of the Watana development constructed in
stages and the Devil Canyon development as presented in the 1985 FERC amendment. In stage one
the Watana dam would be constructed to the lower height and the Watana powerhouse would only
have four out of the six turbine generators installed, but would be constructed to the full sized
powerhouse. In stage two the Devil Canyon dam and powerhouse would be constructed. In stage
three the Watana dam would be raised to its full height, the existing turbines upgraded for the higher
head, and the remaining two units installed. At completion, the project would have a total installed
capacity of 1,880 MW.
As the RIRP process defined the future Railbelt power requirement it became evident that lower cost
hydroelectric project alternatives, that were a closer fit to the energy needs of the Railbelt, should be sought.
As such, the following single dam configurations were also evaluated:
• Low Watana Non-Expandable. This alternative consists of the Watana dam constructed to a height
of 700 feet, along with a powerhouse containing four turbines with a total installed capacity of
600 MW. This alternative has no provisions for future expansion.
• Lower Low Watana. This alternative consists of the Watana dam constructed to a height of 650 feet
along with a powerhouse containing three turbines with a total installed capacity of 380 MW. This
alternative has no provisions for future expansion.
• High Devil Canyon. This alternative consists of a roller-compacted concrete (RCC) dam constructed
to a height of 810 feet, along with a powerhouse containing four turbines with a total installed
capacity of 800 MW.
• Watana RCC. This alternative consists of a RCC Watana dam constructed to a height of 885 feet,
along with a powerhouse containing six turbines with a total installed capacity of 1,200 MW.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-21 February 2010
The results of this study are summarized in Table 10-15 and a comparison of project size versus project cost
is shown in Figure 10-2.
Table 10-15
Susitna Summary
Alternative Dam Type
Dam
Height
(feet)
Ultimate
Capacity
(MW)
Firm
Capacity,
98%
(MW)
2008
Construction
Cost
($ Billion)
Energy
(GWh/yr)
Schedule
(Years
from
Start of
Licensing)
Lower Low Watana Rockfill 650 380 170 $4.1 2,100 13-14
Low Watana Non-
expandable
Rockfill 700 600 245 $4.5 2,600 14-15
Low Watana
Expandable
Rockfill 700 600 245 $4.9 2,600 14-15
Watana Rockfill 885 1,200 380 $6.4 3,600 15-16
Watana RCC RCC 885 1,200 380 $6.6 3,600 15-16
Devil Canyon Concrete Arch 646 680 75 $3.6 2,700 14-15
High Devil Canyon RCC 810 800 345 $5.4 3,900 13-14
Watana/Devil
Canyon
Rockfill/Concrete
Arch
885/646 1,880 710 $9.6 7,200 15-20
Staged
Watana/Devil
Canyon
Rockfill/Concrete
Arch
885/646 1,880 710 $10.0 7,200 15-24
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-22 February 2010
Figure 10-2
Comparison of Project Cost Versus Installed Capacity
In all cases, the ability to store water increases the firm capacity over the winter. Projects developed with
dams in series allow the water to be used twice. However, because of their locations on the Susitna River, not
all projects can be combined. The Devil Canyon site precludes development of the High Devil Canyon site
but works well with Watana. The High Devil Canyon site precludes development of Watana but could
potentially be paired with other sites located further upstream.
Mode of Operation
All of the alternatives identified have significant storage capability which enhances their benefits to the
Railbelt Utilities. Table 10-16 presents the average annual and average monthly generation from each of the
alternatives.
Capital Costs
The estimated capital costs for the alternative Susitna projects are presented in Table 10-15. For evaluation
purposes, the capital cost for the Low Watana expansion to Watana is estimated as the difference in costs
between Watana and Low Watana (Expansion) since it was not part of HDR’s scope and they did not
explicitly develop the cost for expansion.
SECTION 10 SUPPLY-SIDE OPTIONS ALASKA RIRP STUDY Black & Veatch 10-23 February 2010 Table 10-16 Average Annual Monthly Generation from Susitna Projects (MWh) Alternative Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Lower Low Watana (non-expandable) 2,006,000 127,000 116,000 127,000 117,000 101,000 208,000 270,000 28,000 256,000 153,000 123,000 128,000 Low Watana (non-expandable) 2,617,000 182,000 166,000 183,000 176,000 119,000 241,000 334,000 378,000 315,000 157,000 180,000 186,000 Low Watana (expandable) 2,617,000 182,000 166,000 183,000 176,000 119,000 241,000 334,000 378,000 315,000 157,000 180,000 186,000 Watana 3,676,000 280,000 254,000 279,000 261,000 498,000 443,000 370,000 326,000 237,000 169,000 275,000 284,000 High Devil Canyon 3,891,000 262,000 235,000 257,000 247,000 287,000 382,000 468,000 522,000 467,000 251,000 252,000 261,000 Low Watana (Expansion) 1,059,000 73,648 67,174 74,053 71,220 48,155 97,524 135,157 152,962 127,468 63,532 72,839 75,267
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-24 February 2010
O&M Costs
O&M costs include fixed and variable costs. Fixed O&M costs for the Susitna hydro projects vary based on
the number of turbines, transformers, and dams in each specific project. A schedule and cost estimate of
major maintenance items were provided by HDR through time.
Schedule
HDR provided development schedules for the original Susitna alternatives as shown in Table 10-15.
10.4.1.2 Chakachamna Project
Description of Project
TDX Power, Incorporated (TDX) is developing a hydro project on the Chakachamna River system. The
proposed project will divert stream flow via a lake tap from the Chakachamna River to a powerhouse on the
McArthur River via a 25 foot diameter power tunnel that will be approximately 10 miles long. The project
will be located approximately 42 miles from Chugach’s Beluga power generating facility. Figure 10-3
illustrates the proposed project’s location. According to TDX, the proposed project will have an installed
capacity of 330 MW, and will be able to generate approximately 1,600 GWh of electricity annually.
Table 10-17 shows the average monthly and annual energy that will be generated by the project.
Figure 10-3
Proposed Chakachamna Hydro Project Location
(Source: TDX)
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-25 February 2010
Table 10-17
Monthly Average and Annual Generation
Month Generation (GWh)
January 163
February 140
March 138
April 120
May 113
June 106
July 108
August 113
September 120
October 142
November 158
December 177
Total 1,598
The project will not require the construction of a dam on the Chakachamna Lake, but fish gates will be
installed at the outlet of the lake. The reservoir has approximately 16,700 acres of water surface at an
elevation of 1,142 feet. Other facilities that will be constructed include fish passage facilities for adult
migration and juvenile outmigration, a 42-mile transmission line from the project site to Chugach’s Beluga
substation, and site access.
Mode of Operation
It is expected that this project will be designed and permitted as a diverted flow type hydroelectric generating
facility.
Capital Costs
According to TDX, the total capital cost of the proposed project will be approximately $1.6 billion in 2008
dollars or $5,100/kW in 2009 dollars. Transmission costs of $58 million are included in capital costs.
O&M Costs
O&M costs include fixed and variable costs. Fixed costs are independent of plant operation while variable
costs are directly related to the plant operation.
According to TDX, the total O&M cost for the proposed project will be approximately $10 million per year in
2008 dollars or $30/kW-Yr in 2009 dollars.
For the purpose of this study, Black & Veatch assumes that the variable O&M costs will be zero, and the
fixed O&M costs will be $30/kW-Yr in 2009 dollars.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-26 February 2010
Schedule
Base on the schedule provided by TDX in their April 2009 presentation, TDX expects that the proposed hydro
generating project could be available for commercial operations starting in 2017.
10.4.1.3 Glacier Fork
Description of Project
The proposed Glacier Fork project is a 75 MW hydroelectric project being developed by Glacier Fork
Hydropower LLC on the Knik River, approximately 25 miles southeast of Palmer in the Matanuska-Susitna
Borough.
According to information provided by Glacier Fork Hydropower LLC, the project would consist of: 1) a
proposed 800-foot-long, 430-foot-high dam; 2) a proposed reservoir having a surface area of 390 acres and a
storage capacity of 75,000 acre-feet and normal water surface elevation of 980 feet above mean low sea level
(msl); 3) a proposed 8,300-foot-long, 12-foot diameter steel penstock; 4) a proposed powerhouse containing
three generating units having an installed capacity of 75 MW; 5) a proposed tailrace; 6) a proposed 25-mile-
long, 115-kilovolt transmission line; and 7) appurtenant facilities.
The proposed Glacier Fork Hydroelectric Project would have an average annual generation of 330 GWh. The
estimated average monthly generation is presented in Table 10-18.
Table 10-18
Glacier Fork Hydroelectric Project
Average Monthly Energy Generation
Month
Average Monthly
Energy (MWh)
Installed Capacity (MW) 75
January 6,755
February 5,314
March 4,882
April 6,727
May 28,794
June 53,612
July 55,400
August 55,400
September 53,305
October 35,964
November 13,767
December 7,617
Annual Total (MWh) 327,538
Note: Data based on USGS Gauge on Knik River.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-27 February 2010
Mode of Operation
As indicated in Table 10-18, the Glacier Fork project is primarily a run-of-river project with the ability to
provide firm capacity significantly reduced from its nameplate ratings during winter and spring. This reduced
output during these periods was included in the Strategist® and PROMOD® modeling.
Capital Costs
The total capital cost of the proposed project will be approximately $4,400/kW, or $330 million, in 2009
dollars. Transmission costs are assumed to be $22.5 million (25 miles, 115 kV @ $900K/mile) and are
included in capital cost.
Operation and Maintenance Cost
O&M costs include fixed and variable costs. Fixed costs are independent of plant operation while variable
costs are directly related to the plant operation.
The total O&M cost for the proposed project will be approximately $68/kW-Yr in 2009 dollars. For the
purpose of this study, Black & Veatch assumed that the variable O&M costs will be zero, and the fixed O&M
costs will be $68/kW-Yr in 2009 dollars.
Schedule
Based on information provided by Glacier Fork Hydropower LLC, the proposed hydro generating project
could be available for commercial operations starting Fall 2014 at the earliest.
10.4.1.4 Generic Hydroelectric Projects
Black & Veatch developed two small, generic hydroelectric project alternatives to represent several
hydroelectric opportunities that have been identified in the Railbelt. The first hydroelectric project is a 5 MW
project located in the Kenai area. The project is assumed to have 20 GWh of average annual energy with a
capital cost of $35 million in 2009 dollars. The other generic project is a 2 MW project located in MEA’s
area. The MEA project is assumed to have an average annual energy of 7.5 GWh and a capital cost of
$16 million in 2009 dollars.
10.4.2 Ocean (Tidal Wave) Project Option
Alaska has a wide coastal area that allows for the consideration of renewable tidal resources. The Cook Inlet
in particular offers a great potential for tidal projects since it has the fourth highest tide in the world with 25
feet (7.6m) between low tide and high tide. Also, it is located between Anchorage, Alaska’s largest city, and
Kenai, where a number of industries are located.
Some institutions are already interested in taking advantage of this resource in this particular location and
have started studies and licensing for tidal projects including the Turnagain Arm Tidal Electric Generation
Project.
There are several different technologies available for tidal projects. Based on Black & Veatch’s review of
available information, we assumed that the proposed Turnagain Arm tidal project would be representative of
the technologies available, although it is Black & Veatch’s opinion that tidal energy is not to the level of
commercialization equivalent to other conventional and renewable alternatives considered in the RIRP. The
ultimate selection of the optimal technology for Railbelt conditions will need to be based on additional
analysis. As a result, tidal energy will be considered as a sensitivity case in the evaluations. The following
subsections discuss further details of the proposed project.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-28 February 2010
10.4.2.1 Turnagain Arm
Description of Project
Little Susitna Construction Co. and Blue Energy Canada filed an application for a preliminary FERC permit
for the Turnagain Arm Tidal Project, to be developed in Cook Inlet.
According to the preliminary permit application, the project calls for the use of Blue Energy’s Tidal Bridge
which will use the Davis Turbine to generate electricity with the movement of the tides. The Davis Turbine is
a mechanical device that employs a hydrodynamic lift principle, causing vertically oriented foils to turn a
shaft and a generator. Figure 10-4 shows an array of vertical-axis tidal turbines stacked and joined in series
across a marine passage.
Figure 10-4
Blue Energy’s Tidal Bridge With Davis Turbine
(Source: Blue Energy)
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-29 February 2010
This turbine is comprised of vertical hydrofoils attached to a central shaft transmitting torque to a generator.
The kinetic energy from tidal flows can thus be harnessed and converted to electrical energy. Contrary to the
traditional drag driven paddle wheel design, the Davis turbine rotor is designed to be lift driven, much like the
modern wind turbines, thus allowing the blades to operate at a significantly higher efficiency. In order to
further increase the efficiency of the turbine, the entire rotor assembly is housed in a thin-shell marine
concrete caisson structure that channels the water flow and acts as a housing for the generator and electrical
components. The shape of the caisson inner walls accelerate the velocity of the water flow through the
turbine rotor by acting as a venturi and controls flow direction to provide more uniform turbine performance.
In addition, the Davis turbine is designed to work through the entire tidal range with a typical cut-in speed of
1m/s. Figure 10-5 shows the configuration of a Davis tidal turbine.
Figure 10-5
Cutaway Graphic of a Mid-Range-Scale Vertical Axis Tidal Turbine
(Source: Blue Energy)
The Turnagain Arm tidal project would be comprised of two tidal fences each eight miles long extending
from Kenai to Anchorage, with minimum separation of five miles to allow the tidal force to recover its
strength after going through the first fence. The tidal fence will have a service road across the top and
connected to the land. Two control buildings would be required, one located near Possession Point in Kenai
Borough and the other along Raspberry Road in Anchorage. They will be connected by a pair of transmission
lines across the tidal fence and connect to the HEA grid on the Kenai side and to the Chugach grid on the
Anchorage side. From there, the power can be moved throughout the Railbelt grid. Figure 10-6 depicts the
proposed layout of the tidal plant.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-30 February 2010
Figure 10-6
Proposed Layout of the Turnagain Arm Tidal Project
(Source: Little Susitna Construction Co. and Blue Energy of Canada)
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-31 February 2010
Mode of Operation
Tidal energy while fairly predictable is very variable. Black & Veatch conducted a high level analysis of the
monthly generation from the Turnagain Arm tidal project. That analysis is presented in Figure 10-7.
Figure 10-7
Turnagain Arm Tidal Project Monthly Generation
-2.00
-1.50
-1.00
-0.50
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
4.50
5.00
5.50
6.00
6.50
7.00
7.50
8.00
8.50
9.00
9.50
10.00
0.00 100.00 200.00 300.00 400.00 500.00 600.00 700.00
Time (hours)Velocity (m/s)-2000.0
-1500.0
-1000.0
-500.0
0.0
500.0
1000.0
1500.0
2000.0
2500.0
3000.0
Power (MW)Velocity (m/s)
Power (MW)
As discussed for the large Susitna options, the capacity of the Turnagain Arm tidal project significantly
exceeds the Railbelt loads. For evaluation purposes, Black & Veatch modeled a 100 MW project with
following $/kW cost.
Capital Costs
Capital costs of $2.5 billion in 2009 dollars for the 1,200 MW Turnagain Arm tidal project or approximately
$2,100/kW are expected, including supporting infrastructure. Black & Veatch’s experience with the
development of similar projects indicates that the Turnagain Arm tidal project costs are significantly lower
than other projects that Black & Veatch has worked with. For evaluation purposes, Black & Veatch has used
a capital cost of $4,200/kW.
O&M Costs
O&M costs include fixed and variable costs.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-32 February 2010
Fixed O&M Costs
Fixed O&M costs include labor, payroll burden, fixed routine maintenance, and administration costs. For the
purpose of this study, the fixed O&M costs associated with the project are estimated to be $42 /kW-year in
2009 dollars.
Variable O&M
Variable O&M costs include consumables, chemicals, lubricants, major inspections, and overhauls of the
turbine generators and associated equipment. Variable O&M costs vary as a function of plant generation. For
the purpose of this study, Black & Veatch has assumed no Variable O&M costs for this project.
Schedule
Black & Veatch expects that the proposed tidal generating project will be available for commercial operations
starting in 2020 at the earliest.
10.4.3 Geothermal Project Option
Description of Project
Ormat Technologies, Inc (Ormat) has approached the AEA for the potential development of a geothermal
power plant project at Mount Spurr, which is located approximately 33 miles from Tyonek, Alaska.
According to Ormat, there is the potential geothermal resource to develop a geothermal power plant project
with an estimated maximum output of 50–100 MW at Mount Spurr.
Depending on the specific resource conditions available at Mount Spurr, the proposed geothermal project
option will likely be based on either a binary geothermal power plant configuration or a geothermal combined
cycle power plant configuration.
Figure 10-8 illustrates a simplified binary geothermal power plant process diagram. A geothermal fluid
(brine, or steam, or a mixture of brine and steam) from an underground reservoir can be used to drive a binary
plant. The geothermal fluid flows from the wellhead to heat exchangers through pipelines. The fluid is used
to heat and vaporize a secondary working fluid in the heat exchangers. The secondary working fluid is
typically an organic fluid with a low boiling temperature point. The generated vapors are used to drive an
organic vapor turbine, which powers the generator, and then are condensed in a dry cooled or wet cooled
condenser. The condensed secondary fluid is then recycled back into the heat exchangers by a pump while
the geothermal fluid is re-injected into the reservoir.
Figure 10-9 illustrates a simplified geothermal combined cycle power plant process diagram. A geothermal
combined cycle is most effective when the available geothermal resource is mostly steam. The high-pressure
steam from a separator drives a back pressure turbine. The low-pressure steam exits this turbine at a positive
pressure and flows into the vaporizer. The heat of condensation of the low-pressure steam is used to vaporize
a secondary working fluid and the expansion of these secondary fluid vapors drives the secondary turbine.
The secondary fluid vapors are then condensed, and pumped back into the pre-heater and the geothermal fluid
is re-injected into the reservoir.
For the purpose of this study, Black & Veatch assumed that the proposed geothermal project can be
developed in two 50 MW blocks.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-33 February 2010
Figure 10-8
Simplified Binary Geothermal Power Plant Process
(Source: Ormat)
Figure 10-9
Simplified Geothermal Combined Cycle Power Plant Process
(Source: Ormat)
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-34 February 2010
Mode of Operation
It is expected that the geothermal power plant project will be designed and permitted for baseload operations.
Black & Veatch assumed that the proposed geothermal plant will be able to achieve 95 percent availability
factor during its first commercial operation year and will experience approximately 0.5 percent output
degradation annually for the following nine years until new wells are drilled to replace old wells. Black &
Veatch also assumed that the estimated cost for drilling a new well to replace an old well will be
approximately $2 million per well in 2009 dollars.
Based on the above assumptions and for the purpose of this study, Black & Veatch assumed that the proposed
geothermal plant will operate at an average capacity factor of approximately 90 percent for 30 years, with an
estimated levelized well drilling and replacement cost of $20/kW-year.
Capital Costs
Ormat did not provide estimated capital cost data for review by Black & Veatch. For the purpose of this
study, Black & Veatch assumed that the construction cost for the first block of the proposed geothermal
project will be approximately $4,000/kW in 2009 dollars. Black & Veatch assumed that this cost includes
engineering, procurement, and construction costs for equipment, materials, construction contracts, and other
indirect costs. Black & Veatch assumed that owner’s cost items such as land, contingency, etc., will be
approximately $1,000/kW in 2009 dollars, or 25.0 percent of the project construction cost. Therefore, it is
anticipated that the total capital cost for the proposed project will be approximately $5,000/kW in 2009
dollars. The capital cost for the second block is assumed to be 10 percent less than the first block.
O&M Costs
O&M costs include fixed and variable costs.
Fixed O&M Costs
Fixed O&M costs include labor, payroll burden, fixed routine maintenance, and administration costs.
Therefore, for the purpose of this study the fixed O&M costs associated with the project are estimated to be
$300/kW-year in 2009 dollars.
Variable O&M Costs
Variable O&M costs include consumables, chemicals, lubricants, water, major inspections, and overhauls of
the steam turbine generator and associated equipment. Variable O&M costs vary as a function of plant
generation. For the purpose of this study, Black & Veatch assumed that the non-fuel variable O&M costs will
be $2.00/MWh in 2009 dollars.
Availability Factor
Availability factor is a measure of the availability of a generating unit to produce power considering
operational limitations such as unexpected equipment failures, repairs, routine maintenance, and scheduled
maintenance activities. For the purpose of this study, Black & Veatch assumed that the initial availability
factor of this proposed geothermal plant will be 95 percent.
Schedule
Figure 10-10 illustrates the estimated project development plan that Ormat presented to AEA on June 16,
2009. The plan indicates that the proposed geothermal project can be available for commercial operation by
the end of 2016. For the purpose of this study, Black & Veatch assumed that the first proposed 50 MW
geothermal generating units will be available for commercial operations starting in 2016.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-35 February 2010
Figure 10-10
Estimated Mount Spurr Project Development Plan
(Source: Ormat)
10.4.4 Wind Project Options
Alaska has abundant wind resources suitable for power development. Much of the best wind sites are located
in the western and coastal portions of the State. The wind in these regions tends to be associated with strong
high and low pressure systems and related storm tracks. Wind power technologies being used or planned in
Alaska range from small wind chargers at off-grid homes or remote camps, to medium-sized machines
displacing diesel fuel in isolated village wind-diesel hybrid systems, to large turbines greater than 1 MW.
Alaska appears to also have significant potential for off-shore wind projects. Since off-shore wind projects
are generally more expensive than on-shore projects, off-shore projects are not explicitly considered in this
study.
In the Railbelt, several of the utilities are examining wind power projects, including:
• BQ Energy/Nikiski – 15 MW, HEA
• Fire Island – 54 MW, Chugach
• Eva Creek – 24 MW, GVEA
• Delta Junction – 50 MW, GVEA
• Arctic Valley – 25 MW, Chugach
• Bird Point – 10 MW, Chugach
• Alaska Environmental Power – 15 MW, GVEA
• 63 Other Projects in AEA’s Data Base
In addition, the developers of several proposed wind projects in the Railbelt have applied for grant requests
from the AEA Renewable Energy Fund Grant Program, which was established by Alaska Legislature in 2008.
Table 10-19 shows each proposed wind project’s name, applicant, estimated project cost, grant requested, and
funding decision and amount recommended by AEA after two rounds of ranking and funding allocations
conducted by AEA.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-36 February 2010
Table 10-19
AEA Recommended Funding Decisions - Wind
Project
Name Applicant
Project Cost
($000)
Grant
Requested
($000)
Recommended
Funding Decision
Recommended
Funding
Amount
($000)
Nikiski
Wind Farm
Kenai Winds,
LLC
$46,800 $11,700 Partial funding $80
Kenai
Winds
Kenai Winds,
LLC
$21,000 $5,850 Partial funding $2,000
AVTEC
Wind
Alaska
Vocational
Technical
Center
$709 $635 Not recommended(1) None
Delta Wind Alaska Wind
Power, LLC
$135,300 $13,000 Not recommended(1) None
Note:
1. The project did not pass Stage 2 review or was excluded in Stage 3 review for geographical spreading.
Black & Veatch studied the details of each proposed wind project and applied the following screening criteria
to determine which developments could be considered as a potential supply-side alternative in this RIRP
study:
• Project size: Larger than 5 MW
• Permitting: In place or in progress
• Power Purchase Agreements (PPA): In place or in progress
• Readiness: Prepared for construction by end of 2010
Based on the review of the above information, Black & Veatch assumed that the proposed Fire Island project
and the proposed BQ Energy/Nikiski project be considered as potential supply-side alternatives in this RIRP
study. The following subsections discuss further details of these proposed projects.
10.4.4.1 Fire Island
Description of Project
A joint venture (JV) of CIRI, an Alaska Native Corporation, and enXco Development Corporation (enXco)
has approached AEA for the potential development of a wind generation project on Fire Island, which is
located in Cook Inlet approximately three miles off Point Campbell in Anchorage, Alaska. On May 14, 2009,
the JV made a presentation to AEA to provide AEA staff with the latest status update of the proposed Fire
Island Project. According to the JV, there is the potential to develop a wind generation plant with an
estimated maximum output of 54 MW on Fire Island. Figure 10-11 illustrates a visual simulation of the
proposed Fire Island wind generation project.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-37 February 2010
Figure 10-11
Visual Simulation of Fire Island Wind Generation Project
(Source: CIRI/enXco Joint Venture)
Figure 10-12 illustrates a preliminary site arrangement and interconnection route of the proposed wind
project. The project will be based on installation of up to 36 GE 1.5 MW wind turbines. Each wind turbine
will be equipped with reactive power and voltage support capabilities. The project is planned to be
interconnected via 34.5 kV underground and submarine cables from an on-site 34.5 kV collector substation to
Chugach’s Raspberry substation. In addition, it is expected that the project will require the construction of a
5,000 square foot maintenance facility, approximately nine miles of gravel roads, and on-island housing
facility for five maintenance staff.
For the purpose of this study, Black & Veatch assumed that the proposed wind generation project will be
developed as a 54 MW nameplate-rated project.
Mode of Operation
It is expected that the wind generation project will be designed and permitted for intermittent operations
subject to wind resource availability at the project site.
Capital Costs
EnXco provided estimated installed capital cost of $3,100/kW including interconnection costs. Since
providing the cost estimate, enXco has closed their Anchorage office and Black & Veatch has been unable to
confirm if the $3,100/kW capital cost included benefits of the American Recovery and Reinvestment Act of
2009. In 2008 the Alaska Legislature appropriated $25 million for the construction of the proposed
underground and submarine cable project to interconnect the proposed wind generation project to the Railbelt
grid.
SECTION 10 SUPPLY-SIDE OPTIONS
ALASKA RIRP STUDY
Black & Veatch 10-38 February 2010
Figure 10-12
Preliminary Site Arrangement and Interconnection Route
(Source: CIRI/enXco Joint Venture)
O&M Costs
O&M costs include fixed and variable costs.
Fixed O&M Costs
Fixed O&M costs include labor, payroll burden, fixed routine maintenance, and administration costs.
Black & Veatch assumed $122/kW-yr in $2009 for fixed O&M costs.
Variable O&M
Variable O&M costs include consumables, lubricants, and major inspections of the wind turbine generators
and associated equipment. Variable O&M costs vary as a function of plant generation. AEA provided and
estimate of $9.75/MWh in 2008 dollars for variable O&M costs for Fire Island. For the purpose of this
study, Black & Veatch assumed that the non-fuel variable O&M costs will be $10.00/MWh in 2009 dollars.
Capacity Factor
According the JV’s May 14, 2009 presentation, the proposed wind generation plant will be able to achieve
approximately 33 percent average capacity factor during its operating years.
Schedule
It is Black & Veatch understanding the proposed wind generation project has completed the following
activities:
• Reached consensus to interconnect the project with Chugach at 34.5 kV level in the June 2008
meeting with Chugach, ML&P, HEA, and GVEA.
• Received proposals and met with potential construction contractors.
• Submitted draft power purchase agreements (PPAs) to Chugach, ML&P, HEA, and GVEA.
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Black & Veatch 10-39 February 2010
• Initiated integration studies.
• Received the U.S. Army Corps of Engineers permit approval for the proposed wind generation and
related electricity transmission infrastructure project.
According the JV’s May 14, 2009 presentation, the JV expects to begin site preparation work in 2009,
complete the project design and site preparation in 2010, and begin erection of wind turbines in 2011. For the
purpose of this study, Black & Veatch assumed that the proposed wind generation project will be available for
commercial operations starting in 2012.
10.4.4.2 BQ Energy/Nikiski
Description of Project
The project, being developed by Kenai Winds LLC, is a 15 MW wind energy generation facility to be located
in the Nikiski Industrial Area, in Nikiski, on the Kenai Peninsula, close to the Tesoro Refinery (Figure 10-13).
There is very little supporting infrastructure required. Kenai Winds does not require new power lines (other
than local collection system) and does not require new roads, ports, nor aircraft access facilities.
There are several possible points of delivery in the area of the wind farm. The optimum location among those
choices has not been selected, but HEA has agreed to purchase the full output of the Kenai Winds project.
The developer applied for a grant from the AEA Renewable Energy Fund Grant Program and was approved,
during Round 1, funding for $80,000 to complete development activities.
On March 6, 2009 the developer submitted Supplemental Information to its previous Request for Grant
Application to provide AEA staff with the latest status update of the proposed BQ Energy/Nikiski project.
Details of the information contained in this document will be presented in the following subsections.
Figure 10-13
Kenai Peninsula, Nikiski
(Source: Kenai Winds LLC)
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Black & Veatch 10-40 February 2010
Mode of Operation
It is expected that the wind generation project will be designed and permitted for intermittent operations
subject to wind resource availability at the project site.
Capital Costs
Capital costs are estimated to be $1,933/kW in 2009$ with limited supporting infrastructure required.
O&M Costs
O&M costs include fixed and variable costs. O&M costs of $0.023/kWh in 2009 dollars based on AEA’s
analysis of non-rural projects.
Capacity Factor
According to the March 6, 2009 document presented by Kenai Winds to AEA, preliminary review of the
meteorological data available yields that the net capacity factor from the project is expected to be 28 percent.
Schedule
It is Black & Veatch understanding the proposed wind generation project has completed the following
activities:
• Received the US Federal Aviation Administration permit approval for the proposed wind generation.
• Reached consensus to interconnect the project with HEA.
• Submitted draft power sales term sheet to HEA and discussions around those terms are underway.
• Initiated Interconnection Requirements Studies (IRS).
According to the Kenai Wind’s document dated March 6, 2009, the developer is expecting to complete the
project design and start site preparation by August 2009, and begin erection of wind turbines in November
2009. For the purpose of this study, Black & Veatch assumed that the proposed wind generation project will
be available for commercial operations starting in 2010.
10.4.5 Modular Nuclear Project Option
Description of Project
Alutiiq has been marketing a new small, modular nuclear power plant. This alternative would be available for
use at most sites. Alutiiq has approached Chugach for a specific application of repowering at the Beluga
power plant site.
The proposed nuclear project option is based on an advanced reactor design from Hyperion Power Generation
(Hyperion) and Los Alamos National Laboratory. The project will consist of the following major
components:
• A single unit, self-regulating, reactor module with heat exchanger.
• A uranium hydride fuel/moderator system.
• A steam turbine generator.
• Balance of plant mechanical, electrical, chemical, water, and interconnection systems.
SECTION 10 SUPPLY-SIDE OPTIONS
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Black & Veatch 10-41 February 2010
Figure 10-14 illustrates a simplified power cycle process of the proposed nuclear project. The reactor will be
designed to operate at an optimum temperature of 550°C and produce approximately 68 MW of thermal
output. The thermal output from the reactor will be converted to approximately 27 MW of electrical output
through a steam turbine generator.
Figure 10-14
Simplified Hyperion Power Cycle Diagram
(Source: Hyperion Power Generation)
Mode of Operation
It is expected that the project will be designed and permitted for both load following and base load operations.
Fuel Supply
Although it is anticipated that the reactor design for this project can accommodate a variety of fuel
compositions, the initial reactor design and calculations were based on the use of uranium hydride.
Depending on its use and mode of operations, each reactor is expected to last 7 to 10 years. The design
proposed for this project does not allow for in-field refueling of the reactor. Each reactor will be sealed at the
factory and transported to the project site for initial installation. When refueling is required after the
anticipated 7- to 10-year period, a new reactor will need to be installed and the used reactor will need to be
removed and transported back to the Hyperion factory for refurbishing and refueling.
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Black & Veatch 10-42 February 2010
For the purpose of economic evaluation for this study, Black & Veatch assumed that the project will incur
zero variable fuel cost. However, Black & Veatch assumed that the project’s reactor will be replaced every
seven years. It is assumed that the reactor replacement cost will be approximately $25.0 million in 2008
dollars.
Capital Costs
Generic Greenfield Capital Costs
According to Hyperion’s June 2008 “Brief for Public” presentation, General Atomics estimated that the
construction cost for a 27 MW electrical output generic greenfield project will be approximately $37.0 million
in 2008 dollars. Black & Veatch assumes that this cost includes engineering, procurement, and construction
costs for equipment, materials, construction contracts, and other indirect costs. Black & Veatch assumes that
owner’s cost items such as land, contingency, etc., will be approximately $8.0 million in 2008 dollars, or
22 percent of the project construction cost. Therefore, it is anticipated that the total capital cost for the
generic greenfield project will be approximately $45.0 million in 2008 dollars or approximately $1,667/kW.
Additional costs estimates provided by Chugach for small nuclear units include a 10 MW facility for $200
million or $20,000/kW and a 50 MW facility for $300 million or $6,000/kW. For evaluation purposes,
Hyperion’s cost estimates will be used in this study, but based on the other estimates, they appear to have the
potential to be low.
Specific Chugach Repowering Capital Costs
Alutiiq provided a confidential rough cost for a Hyperion unit for repowering Beluga. Black & Veatch
estimated the cost to connect the Hyperion unit to the Beluga steam turbine as well as an estimate of owner’s
cost. The total estimate cost of repowering the Beluga steam turbine is $39.6 million in 2009 dollars.
Non-fuel O&M Cost
Non-fuel O&M costs include fixed and variable costs.
Non-fuel Fixed O&M Costs
Non-fuel fixed O&M costs include labor, payroll burden, fixed routine maintenance, and administration costs.
It is assumed that the project will have a full-time plant staff of 15 personnel consisting of a plant manager, an
administrative staff, a nuclear safety officer, and 12 O&M personnel. Therefore, for the purpose of this study
the non-fuel fixed O&M costs associated with the project are estimated to be $2.6 million per year in 2009
dollars.
Non-fuel Variable O&M Costs
Non-fuel variable O&M costs include consumables, chemicals, lubricants, water, major inspections, and
overhauls of the steam turbine generator and associated equipment. Non-fuel variable O&M costs vary as a
function of plant generation. For the purpose of this study, Black & Veatch assumed that the non-fuel
variable O&M costs will be $2.56/MWh in 2009 dollars.
Availability Factor
Availability factor is a measure of the availability of a generating unit to produce power considering
operational limitations such as unexpected equipment failures, repairs, routine maintenance, and scheduled
maintenance activities. For the purpose of this study, Black & Veatch assumed that the average availability
factor of this proposed nuclear plant will be 90 percent.
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Black & Veatch 10-43 February 2010
Schedule
According to the February 20, 2008 “Periodic Briefings on New Reactors” transcript and presentation
Black & Veatch obtained from the Nuclear Regulatory Commission (NRC) website, Hyperion had submitted
a letter of intent to NRC and met with the NRC in May 2007 to discuss the NRC licensing process. At the
May 2007 meeting, Hyperion stated to NRC that Hyperion intended to submit a design certification
application to the NRC in early 2012 as part of Hyperion’s plan to obtain a manufacturing license from NRC.
A schedule (See Figure 10-15) illustrating the requested application timelines based on NRC receipt of letters
of intent from all potential advanced reactor license applicants was presented by NRC during the February 20,
2008 briefing. The schedule shows that the Hyperion manufacturing license review process will be
completed by the end of 2015 based on the assumption that the NRC will have appropriate staffing level and
capability to review licensing applications submitted by all applicants.
Figure 10-15
Requested Potential Advanced Reactor Licensing Application Timelines
(Source: NRC February 20, 2008 Briefing Presentation Slide)
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Black & Veatch 10-44 February 2010
Figure 10-16 illustrates the Nuclear Energy Institute (NEI) latest understanding of the NRC’s new licensing
process. Figure 10-16 indicates that the expected time frame to process a Combined Construction and
Operation License Application (COLA) is 27 to 48 months. Assuming that Hyperion proceeds in parallel, the
license should be issued coincident with the Manufacturing License. Based on information provided by
Hyperion, engineering, prototype, and testing will take four years. Further, it was assumed that it will take
three years to manufacture and install the unit from issuance of the license to manufacture. Thus, the first of
the units will be available for commercial operation in 2020.
Figure 10-16
NRC New Licensing Process and Construction Timelines for New Reactors
(Source: NEI website)
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Black & Veatch 10-45 February 2010
10.4.6 Municipal Solid Waste Project Options
Generic municipal solid waste projects were considered for the Anchorage and Interior areas. Black &
Veatch sized the projects based on an estimated amount of trash produced in each area on a tons per day basis.
This estimate was developed by multiplying the number of residents in each area by an estimated average of
4.5 pounds of trash per day, per person. The resulting tons per day number was compared with a list of
municipal solid waste projects proposed and operating in the US to identify project sizes with similar tons per
day consumption. As a result, 22 MW and 4 MW project capacities were developed for Anchorage and the
Interior, respectively.
Black & Veatch assumed that the municipal solid waste projects would charge fees for taking the trash at a
similar tipping fee rate currently charged by local landfills. Black & Veatch estimated capital costs of both
projects to be $5,750/kW in 2009 dollars.
It should be noted that previous studies have been conducted regarding the feasibility of municipal solid waste
projects in the Railbelt region. Furthermore, while Black & Veatch did not specifically evaluate landfill gas to
energy technologies, they warrant further consideration.
10.4.7 Central Heat and Power
Central heat and power projects have not been explicitly modeled in this study. These projects are often
developed by IPPs. If these projects meet the efficiency requirements to be certified as a Qualifying Facility
(QF), then the existing utilities can be required to purchase the power from a central heat and power project at
avoided costs. Since the qualification is very site specific, the development of specific projects to evaluate is
beyond the scope of this study. It should be noted that under the GRETC concept, standard purchase power
agreements will be available. The use of standard purchase power agreements will eliminate the specific need
to be a FERC Qualifying Facility.
SECTION 11 DSM/EE RESOURCES
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Black & Veatch 11-1 February 2010
11.0 DEMAND-SIDE MANAGEMENT/ENERGY EFFICIENCY RESOURCES
11.1 Introduction
The purpose of this section is to summarize Black & Veatch’s approach to the assessment of DSM/EE
measures as part of the overall RIRP project. A very important element of any comprehensive integrated
resource plan is the development of a portfolio of proposed energy efficiency and demand reduction programs
that can contribute energy savings and winter peak load reductions, and then evaluate these potential
programs relative to alternative supply-side electric generation options on a cost per kWh and per kW basis.
Those demand-side resources that prove to be more cost-effective than supply alternatives are then typically
included in integrated resource planning model or models (in this case, Strategist® and PROMOD®) as a
reduction to the load forecast. The resulting lower forecast then serves as the basis from which the alternative
supply-side options are considered for adding generation resources when and as needed.
Black & Veatch has conducted a review of the Railbelt utilities’ existing DSM/EE programs and developed a
portfolio of potential DSM/EE measures for evaluation against supply-side alternatives. The costs and
benefits associated with the DSM/EE measures are taken from existing data sources as described later in this
section. Data on non-weather sensitive measures (e.g., lighting, appliances) are directly transferred from
existing nationally-known sources, and data on weather-sensitive measures are transferred from existing
sources using a regression model that considers both heating and cooling degree days as an adjustment factor.
This approach has been used successfully in various other jurisdictions and has received general regulatory
acceptance.
The design of DSM/EE programs involves three basic elements: 1) identification of target customer segments
and end uses with the capacity to reduce energy use, 2) identification of technologies and behaviors that will
result in the desired changes in consumption and load shape, and 3) identification of marketing approaches or
program concepts to achieve the desired behavioral changes.
The short time frame, budget and limited data availability for this study precluded a rigorous analysis of
electric DSM/EE potential (i.e., technical potential and maximum achievable potential) in the Railbelt region.
However, Black & Veatch has made maximum use of existing data, augmented by interviews with a number
of individuals, and employed industry-accepted data sources and analytical tools to produce a preliminary
estimate of the cost-effective DSM/EE resources that exist within the Railbelt region.
In the next subsection, we present some background information on the Railbelt utilities’ current DSM/EE
programs and the literature sources that we reviewed. We then present a summary and characterization of the
customer base for energy efficiency and demand reduction by company and sector. An estimate of DSM/EE
potential is presented in the next subsection, followed by a discussion of the DSM/EE technologies or
measures considered, screened, and included in the RIRP modeling. We conclude with some comments
regarding the delivery of DSM/EE programs.
SECTION 11 DSM/EE RESOURCES
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Black & Veatch 11-2 February 2010
11.2 Background and Overview
11.2.1 Current Railbelt Utility DSM/EE Programs
Black & Veatch conducted two investigations to assess the current level of energy efficiency program activity
at the Railbelt utilities. First, inquiries were made to the six Railbelt utilities and, second, websites of the
utilities were researched.
Based upon the information gathered, Table 11-1 summarizes the current DSM/EE programs and related
information offered by the Railbelt utilities.
Table 11-1
Current Railbelt Electric Utility DSM/EE-Related Activities
Utility DSM/EE Programs and Other Assistance/Information Offered
Chugach Residential
• Provides compact fluorescent light (CFL) bulb coupons.
Other Assistance/Information
• Refers to a 2008 Board of Directors policy to establish an energy efficiency and
conservation program.
• Provides a calendar of events, workshops (sponsored by AHFC) and other activities
(e.g. tours, fairs, contests, etc.) with links to the specific events.
• Provides tips for buying and using appliances, CO2 detectors, heating and cooling,
holiday lighting, insulation, lighting, water heating, and windows.
• Provides a tool to analyze accounts, which includes a table of costs for typical
appliance usage and a link to the Energy Star® webpage’s home energy yardstick
which is a tool to analyze energy usage.
• Provides a variety of documents related to energy efficiency.
GVEA Residential
• Home$ense: $40 energy audit that includes energy saving tips and installation of
energy efficient products at no additional cost.
Commercial
• Builder$ense: rebate program for home builders who install electrical energy
efficiency measures during construction.
• Business$ense: rebate program of up to $20,000 for commercial members who
reduce their lighting loads through energy efficient lighting retrofit projects.
Other Assistance/Information
• Link to AHFC and University of Alaska Fairbanks-Alaska Cooperative Extension
Service, energy and housing.
• Department of Energy document with tips and ideas on how to increase home energy
efficiency and how to buy energy efficient products.
• Calculator to determine savings by replacing standard incandescent light bulbs with
compact fluorescents.
SECTION 11 DSM/EE RESOURCES
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Black & Veatch 11-3 February 2010
Table 11-1 (Continued)
Current Railbelt Electric Utility DSM/EE-Related Activities
Utility DSM/EE Programs and Other Assistance/Information Offered
HEA Residential
• Information on WiseWatts program and incentives.
• Offers a Black & Decker Power Monitor for $50.
• Line of credit for HEA customers from $200 to $5,000 for the purchase of approved
energy-efficient electrical appliances and other approved merchandise. The
repayment period can be from 6 to 36 months upon approved credit. There is an
application fee of $35 at the time the loan closes.
Other Assistance/Information
• Touchstone Energy Savers: contains links to Touchstone Energy® tools, tips and
resources designed to create greater home comfort and promote energy efficiency.
Included on this page are an on-line home energy saver audit, information about
stimulus package energy efficiency and weatherization programs, and a link to
Alaska Building Science Network.
• Offers advice on how to select new energy efficient appliances and products for
homes and businesses. Also provides appliance usage tips to reduce energy
consumption.
• Information on CFL and old refrigerator disposal in the area.
MEA Other Assistance/Information
• Provides information on the benefits of Energy Star® appliances, including a link to
the EnergyGuide label.
• Provides information on how to save energy by managing monitor and PC power.
• Provides energy saving tips, including heating and cooling, home electronics,
lighting, and new energy efficient homes.
• Provides a link to Energy Star® Home Energy Yardstick, a tool to analyze your
energy usage.
• Provides links to the AHFC and Cold Climate Housing Research Center.
ML&P Commercial
• Sponsor of Green Star's Lighting Energy Efficiency Pledge (LEEP) which
encourages businesses to upgrade and retrofit their lighting. Participating businesses
receive technical support and resources to help them achieve energy savings and
Green Star promotes participating businesses.
Other Assistance/Information
• Provides a link to Home Energy Saver, which is the Department of Energy’s free
home energy audit tool as part of the Energy Star® program.
• Provides tips to reduce utility bills and provides links to the Municipality of
Anchorage’s low-income weatherization program and the AHFC Research
Information Center.
SECTION 11 DSM/EE RESOURCES
ALASKA RIRP STUDY
Black & Veatch 11-4 February 2010
11.2.2 Literature Review
As previously stated, the Railbelt utilities have limited experience in the implementation of DSM/EE
programs; likewise, there is limited Alaska-specific information available typically required to complete an
evaluation of the resource potential and cost-effectiveness of DSM/EE resources. To supplement the
information available from the utilities, Black & Veatch relied on other Alaskan sources of information as
shown in Table 11-2.
Table 11-2
DSM/EE-Related Literature Sources
Printed Materials Reviewed Websites Reviewed
Alaska Energy Authority; Alternative Energy
and Energy Efficiency Assistance Plan July 1,
2007 to June 30, 2009; 2009.
ACEP – Alaska Center for Energy and Power
(University of Alaska);
http://www.uaf.edu/acep/publications/detail/index.xml.
Alaska Energy Authority; Alternative Energy
& Energy Efficiency Update; 2007.
Alaska Housing Corporation;
http://www.ahfc.state.ak.us/home/index.cfm.
Alaska Energy Authority, et al.; Village End-
Use, Energy Efficiency Projects Phase II
Results -2007-2008; 2009.
Alaska Energy Authority;
http://www.akenergyauthority.org/.
Chugach Electric Association; End Use
Model Results; 1991. (provides residential
and commercial end-use projections for
Chugach, HEA, and MEA)
Cold Climate Housing Research Center (CCHRC);
http://www.cchrc.org/default.aspx.
Information Insights, Inc.; Alaska Energy
Efficiency Program and Policy
Recommendations; 2008.
Denali Commission; http://www.denali.gov/index.php.
Information Insights, Inc.; Alaska Energy
Efficiency Program and Policy
Recommendations – Appendices; 2008.
Municipality of Anchorage, Alaska;
http://www.muni.org/OECD/energyEfficiency.cfm.
Renewable Energy Alaska Project (REAP);
http://alaskarenewableenergy.org/tag/energy-efficiency/.
11.2.3 Characterization of the Customer Base
Table 11-3 provides a summary of the customer base for each of the six Railbelt utilities, including the total
number of customers for each utility, as well as information on the numbers of customers in the largest
population centers. This table also shows a breakdown of customers into residential, commercial and
industrial sectors.
This information was used in the analysis of potential penetration rates for various DSM/EE measures as
discussed later.
SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY Black & Veatch 11-5 February 2010 Table 11-3 Railbelt Electric Utility Customer Base Total Number of MajorRes. Comm. Ind. Number of Govt & LowCust. PopulationPopulationPop. Cust. Cust. Cust. Schools in all Schools IncomeCenters Center(s)Pop. Centers in cityRes in cityFairbanks34,54037 4,076North Pole2,1838 227Delta Junction9429 98Nenana3522 37Anderson2741 28Wasilla9,78027 1,017Palmer7,80413 812Houston2,0170 210Chugach Electric Association & Anchorage Municipal Light and PowerCEA and ML&P108,472 10 Anchorage279,671 93,493 14,973 6 125 104 18,458Homer5,69110 592Soldotna4,28910 446Kenai7,686Kachemak City4430 46Seldovia3061 32City of Seward Electric System CES 2,567 1 Seward3,061 1,973 476 118 4 4 318234,809 82359,039 205,611 28,584 614 268 226 26,397state citiesGolden Valley Electric Association5.6% 7.8%Anchorage Municipal Light & Power40.9% 57.2%Matanuska Electric Association2.9% 4.0%Chugach Electric Association0.0% 0.0%Homer Electric Association2.7% 3.8%City of Seward Electric System0.4% 0.6%Total Pop in Railbelt 52.53% 73.42%Sources: Customer informationEnergy Velocity by VentixPopulation datahttp://www.census.gov/Economic data:http://www.census.gov/Schools data:http://www.eed.state.ak.us/Alaskan_Schools/Public/HEA 27,40149,939Alaska Railbelt UtilitiesMatanuska Electric Association MEA 53,5033,5642227 2920463 6149023,811 3,563TOTAL:OrganizationGVEAGolden Valley Electric Association42,866 2936,395Homer Electric Association6,008
SECTION 11 DSM/EE RESOURCES
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Black & Veatch 11-6 February 2010
11.3 DSM/EE Potential
The purpose of this subsection is to provide an overview of Black & Veatch’s estimate of the potential for
DSM/EE measures in the Railbelt region.
11.3.1 Methodology for Determining Technical Potential
The general approach for developing an estimate of the DSM/EE technical potential consisted primarily of the
following three steps:
1. Black & Veatch reviewed the universe of measures that are available in the marketplace to increase
energy efficiency. This review included not only the limited DSM/EE program experience in Alaska
but also a review of the DSM/EE program experience of other utilities throughout the U.S.
2. Black & Veatch eliminated non-electric energy savings measures since this study is focused on
meeting the demand and energy requirements of the electric utilities within the Railbelt region.
3. Black & Veatch conducted an intuitive, or qualitative, screening of potential DSM/EE measures
based on certain criteria, which are discussed below.
11.3.2 Intuitive Screening
A universe of DSM/EE measures exists that provide energy savings over standard products that serve the
same end uses. The majority of these measures are well proven in terms of their impact on electric demand
and energy requirements based upon the experience of utilities in other regions of the country. To cull this
list, Black & Veatch used a process to screen measures to identify those that are most appropriate for the
Railbelt region. The primary objective of this effort was to select the most appropriate measures for further
analysis.
There is a considerable range of new products and technology options that are available for energy efficiency
and demand reduction applications. Many of these are available today to consumers in the Railbelt region,
while others are less prevalent or readily available. Black & Veatch examined a broad array of the most
relevant technologies and measures for residential and commercial (non-residential) applications, and
considered the extent to which each technology and measure makes sense for the Railbelt region.
To ascertain which electric end-use measures would best provide energy efficiency opportunities for Railbelt
electric customers, as well as help the Railbelt utilities meet their long-term energy and capacity planning
goals, Black & Veatch felt that the initial step to aid in sifting through the number of measures would be to
use an intuitive or qualitative technology screen. This process, first developed through the Electric Power
Research Institute (EPRI) Customer Preference and Behavior Research Project in the 1980s, has been used by
utilities across the nation as a first pass at the screening and ranking of DSM technologies.
Numerous measures were considered for the residential and commercial sectors. Certain criteria were
developed to gauge the relative value of each measure for the Railbelt region, including: 1) the impact that
each measure would have on the winter system load, 2) a preference for conservation measures (rather than
peak impacting), and 3) whether the measure is currently offered in the marketplace. The Black & Veatch
team felt that a review of each measure within these descriptive criteria would aid in indicating which
measures “rise to the top” as “best” candidates and, as such, should be investigated for possible program
inclusion.
SECTION 11 DSM/EE RESOURCES
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Black & Veatch 11-7 February 2010
11.3.3 Program Design Process
Once this initial screening was completed, Black & Veatch then grouped similar, or related, DSM/EE
measures into potential DSM/EE programs that were further evaluated within the RIRP models. This
approach is consistent with the approach typically used by utilities to develop DSM/EE programs, as shown
on Figure 11-1.
Figure 11-1
Common DSM/EE Program Development Process
Typically, utilities develop detailed DSM/EE program plans for each program selected for implementation.
These DSM/EE program plans commonly include the following elements:
• Detailed description of the program--Derived from best practices from various sources.
• Reasons why the program would be successful in utility’s service territory--Derived from a
comprehensive market assessment and background research.
• Number of customers within the customer class/segment that are likely to adopt/use the
proposed program--Derived from market assessments and surveys, with a percent or modeled
participation estimate based on experience from other utilities with similar programs; informed by
actual results from other utilities offering similar programs.
• Achievable energy savings--From a variety of sources, consistent with a technology assessment and
published reports.
• Cost-effectiveness ratios/rating per individual program--Calculated using standard tests, such as
the Total Resource Cost (TRC), Participant, Administrators (or Utility) Cost, or Ratepayer Impact
Measure (RIM) Tests, applying appropriate avoided cost figures.
• Marketing plans which should include incentives, rebates and preferred distribution channels
and how each reduces existing barriers to proposed program adoption/acceptance--Based on
best practices from a variety of sources; incentive amounts based on examples from other companies.
• Detailed budget plans complete with explanations of anticipated increases/decreases in financial
and human resources during the expected life of the program--Based on best practices from a
variety of sources, over a designated time period for the program life.
SECTION 11 DSM/EE RESOURCES
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Black & Veatch 11-8 February 2010
• Recommended methodology or tracking tools for recording actual performance to budget--
Based on current standard practice using simple commercially available software.
• Proposed program evaluations and reports--Based on current standard practice using a logic
model approach.
11.3.4 Achievable DSM Potential from Other Studies
There are several organizations that have estimated the potential for energy savings on a regional and
statewide basis in recent years; most notably EPRI and the Edison Electric Institute (EPRI/EEI), and the
American Council for an Energy Efficient Economy (ACEEE). None of these studies, however, specifically
and exclusively examined Alaska. However, one study by the Energy Efficiency Task Force of the Western
Governor’s Association (WGA) was conducted under the Clean and Diversified Energy Initiative and
published in January 2006. The states included in the study were Alaska, Arizona, California, Colorado,
Hawaii, Idaho, Kansas, Montana, Nebraska, Nevada, New Mexico, North Dakota, Oregon, South Dakota,
Texas, Utah, Washington, and Wyoming. The study estimates achievable potential for three years (2010,
2015, and 2020) at 7, 14, and 20 percent, respectively.
Taking Ohio as an example of a state with relatively little prior DSM/EE program offerings, the ACEEE
estimates a total achievable energy savings potential of 33 percent by 2025. Other higher end percentages are
seen in Illinois (ACEEE 1998) with 43 percent achievable energy efficiency potential, and a regional study
for the Southwest that rendered 33 percent energy savings potential. 1
The EPRI/EEI Assessment looked at the amount of energy savings deemed to be achievable in each of three
time periods by sector and end use. The top 10 end uses did not vary considerably by region, and are shown
on Figure 11-2 for the Western Census Region, which includes Alaska.
The EPRI/EEI report also indicates a demand response potential of 88 MW based on a 2006 assessment for
Alaska and Hawaii combined (note: there is no indication of whether this is from the summer or winter peak).
These studies all provide comparative “top down” estimates from which to gauge the reasonableness of the
estimates that Black & Veatch has derived from a “bottom up” assessment of DSM/EE potential in the
Railbelt region.
11.4 DSM/EE Measures
This section discusses the DSM/EE measures that are commonly considered in market potential studies of
recent vintage. The standard approach to designing programs is to consider a wide range of measures, and
then screen them by applying a set of criteria appropriate to the individual utility or region. The measures are
then ranked and the most appropriate ones retained for modeling purposes.
Since there are numerous combinations of technology replacement situations (e.g., standard light bulbs with a
75 watt rating can be replaced with a compact fluorescent light bulb, CFL, using 15 watts; a standard 60 watt
light bulb can be replaced with a 15 CFL, etc.), the modeling of measures only requires consideration of a
representative group of measures in order to assess the potential benefits of promoting such measures in the
region and service territory.
1 US Department of Energy; National Action Plan for Energy Efficiency; Table A6-4 - Achievable Energy Efficiency
Potential from Recent Studies; pages 6-16; July 2006.
SECTION 11 DSM/EE RESOURCES
ALASKA RIRP STUDY
Black & Veatch 11-9 February 2010
Figure 11-2
EPRI/EEI Assessment: West Census Region Results
0 5 10 15 20 25
Res - Water Heating
Ind - Lighting
Res - Lighting
Res - Appliances
Com - Cooling
Res - Cooling
Com - Other
Ind - Machine Drive
Res-Electronics
Com-Lighting
Annual Electricity Savings (TWh)
2030
2020
2010
Black & Veatch began this phase of the work by considering a large number of residential and commercial/
industrial (C/I) measures. As previously discussed, two initial screens (i.e., removal on non-electric measures
and intuitive screening) were applied to these lists.
This shorter list of electric-only measures was then reduced based on a set of four additional screening criteria
as follows:
1. Relevance to the regional weather patterns
2. Commercial availability
3. Incremental cost per kWh over standard options
4. Contribution to winter peak load reduction
This review and ranking of the measures resulted in an abbreviated list of 21 residential and 51 C/I measures
for further analysis. Table 11-4 summarizes this abbreviated list of residential and C/I measures that was
selected for further analysis. It also provides the following information for each DSM/EE measure:
• Measure life
• Estimated kWh savings per customer
• Estimated kW savings per customer
• Incremental cost per installation
SECTION 11 DSM/EE RESOURCES ALASKA RIRP STUDY Black & Veatch 11-10 February 2010 Table 11-4 Residential and Commercial DSM/EE Technologies Evaluated MeasureSectorTechnologyMeasure lifeEstimated kWh percustEstimated kW percustCost per installation ($2009)MeasureSectorTechnologyMeasure lifeEstimated kWh percustEstimated kW percustCost per installation ($2009)MeasureSectorTechnologyMeasure lifeEstimated kWh percustEstimated kW percustCost per installation ($2009)Freezers Energy Star-Chest FreezerResid-NonWeatherAppliance 12 46.0 0.0 50.88$ Motors 1 to 5 HP Comm-NonWeatherMotor 15 113.3 0.024 97.60$ High Bay 6L T5HO replacing 400W HIDComm-NonWeatherLighting 12 374.0 0.1 369.27$ Clothes DryersResid-NonWeatherAppliance 14 144.0 0.0 82.50$ Motors 25 to 100 HP Comm-NonWeatherMotor 15 1,056.0 0.224 331.90$ High Bay Fluorescent 6LF32T8 Replacing 400W HIDComm-NonWeatherLighting 12 961.0 0.2 70.84$ Refrigerators-Freezers Energy Star - Top FreezerResid-NonWeatherAppliance 12 79.0 0.0 50.88$ Motors 7.5 to 20 HPComm-NonWeatherMotor 15 408.4 0.087 149.85$ High Bay Fluorescent 8LF32T8 Double fixture replace 1000W HIDComm-NonWeatherLighting 12 2,005.0 0.5 136.84$ Refrigerators-Freezers Energy Star - Side by SideResid-NonWeatherAppliance 12 109.0 0.0 50.88$ LED Exit Signs Electronic Fixtures (Retrofit Only)Comm-NonWeatherLighting 15 201.0 0.023 33.00$ CFL FixtureComm-NonWeatherLighting 12 342.0 0.1 21.70$ Pump and Motor Single SpeedResid-NonWeatherAppliance 10 694.0 0.4 23.38$ LED Auto Traffic SignalsComm-NonWeatherLighting 6 275.0 0.085 49.50$ CFL Screw inComm-NonWeatherLighting 2 202.0 0.0 8.29$ Smart Strip plug outletResid-NonWeatherAppliance 5 184.0 0.0 11.00$ LED Pedestrian SignalsComm-NonWeatherLighting 8 150.0 0.044 77.00$ Daylight Sensor controlsComm-NonWeatherLighting 12 14,800.0 3.8 1,100.00$ Freezer recyclingResid-NonWeatherAppliance 6 1,551.0 0.2 75.00$ VFD HP 1.5 Process PumpingComm-NonWeatherMotor 15 1,623.4 0.343 1,192.13$ Central Lighting ControlComm-NonWeatherLighting 12 11,500.0 2.8 2,035.00$ Refrigerator recyclingResid-NonWeatherAppliance 6 1,672.0 0.2 130.00$ VFD HP 10 Process PumpingComm-NonWeatherMotor 15 10,713.4 2.286 811.50$ Occupancy Sensors under 500 W Comm-NonWeatherLighting 10 397.0 0.1 79.20$ Heat Pump Water HeatersResid-NonWeatherWater Heater15 2,885.0 0.3 242.50$ VFD HP 20 Process PumpingComm-NonWeatherMotor 15 21,643.1 4.571 1,266.63$ Low Watt T8 lampsComm-NonWeatherLighting 12 15.0 0.0 3.43$ Low Flow ShowerheadsResid-NonWeatherWater Heater12 518.0 0.1 36.76$ Vending Equipment ControllerComm-NonWeatherRefrigeration5 800.0 0.210 78.76$ 3 Lamp T5 replacing T12Comm-NonWeatherLighting 12 99.4 0.0 110.09$ Pipe WrapResid-NonWeatherWater Heater6 257.0 0.0 2.09$ Efficient Refrigeration Condenser Comm-NonWeatherRefrigeration15 120.0 0.118 9.63$ 4 Lamp T5HO replacing T12Comm-NonWeatherLighting 12 191.0 0.0 168.33$ Holiday LightsResid-NonWeatherLighting 10 10.6 0.0 14.20$ ENERGY STAR Commercial Solid Door Freezers less than 20ft3Comm-NonWeatherRefrigeration12 520.0 0.059 41.25$ HPT8 4ft 3 lamp, T12 to HPT8Comm-NonWeatherLighting 12 145.2 0.0 75.99$ CFL fixturesResid-NonWeatherLighting 12 78.0 0.0 24.75$ ENERGY STAR Commercial Solid Door Freezers 20 to 48 ft3Comm-NonWeatherRefrigeration12 507.0 0.058 330.00$ HPT8 4ft 4 lamp, T12 to HPT8Comm-NonWeatherLighting 12 169.7 0.0 80.88$ Torchiere Floor LampsResid-NonWeatherLighting 12 164.0 0.0 10.00$ ENERGY STAR Commercial Solid Door Refrigerators less than 20ft3Comm-NonWeatherRefrigeration12 905.0 0.103 68.75$ T12HO 8ft 1 lamp retrofit to HPT8 T8 4ft 2 lampComm-NonWeatherLighting 12 174.0 0.0 62.34$ LED Night LightResid-NonWeatherLighting 12 22.0 0.0 6.50$ ENERGY STAR Commercial Solid Door Refrigerators 20 to 48 ft3Comm-NonWeatherRefrigeration12 1,069.0 0.122 275.00$ T12HO 8ft 2 lamp retrofit to HPT8 T8 4ft 4 lampComm-NonWeatherLighting 12 293.0 0.1 80.88$ CFL bulbs regular - OutsideResid-NonWeatherLighting 9 191.6 0.0 0.83$ ENERGY STAR Ice Machines less than 500 lbsComm-NonWeatherRefrigeration12 1,652.0 0.189 330.00$ T8 4ft 3 lampComm-NonWeatherLighting 12 128.8 0.0 107.38$ CFL bulbs regularResid-NonWeatherLighting 9 44.1 0.0 2.83$ ENERGY STAR Ice Machines 500 to 1000 lbsComm-NonWeatherRefrigeration12 2,695.0 0.308 825.00$ T8 4ft 4 lampComm-NonWeatherLighting 12 139.8 0.0 113.90$ Ceiling FansResid-WeatherShell 15 47.8 0.0 151.25$ ENERGY STAR Ice Machines more than 1000 lbsComm-NonWeatherRefrigeration12 6,048.0 0.690 550.00$ T8 HO 8 ft 2 LampComm-NonWeatherLighting 12 184.0 0.0 124.92$ Duct sealing 20 leakage baseResid-WeatherShell 18 41.7 0.0 143.70$ Pumps HP 1.5Comm-NonWeatherMotor 15 302.0 0.064 313.75$ Window FilmComm-WeatherCooling/Heating10 256.0 0.1 84.60$ Roof InsulationResid-WeatherShell 20 41.7 0.0 441.32$ Pumps HP 10Comm-NonWeatherMotor 15 2,014.0 0.427 116.30$ Refrigerant charging correctionComm-WeatherCooling/Heating10 712.4 1.0 21.10$ Setback thermostat - moderate setbackResid-WeatherCooling/Heating9 152.1 0.0 45.31$ Pre Rinse SprayersComm-NonWeatherWater Heater5 1,396.0 0.116 9.63$ VFD FanComm-WeatherCooling/Heating10 1,185.6 0.0 42.89$ ENERGY STAR Steam Cookers 3 Pan Comm-NonWeatherWater Heater12 11,188.0 2.6 1,141.25$ Exterior HID replacement above 250W to 400W HID retrofitComm-NonWeatherLighting 12 706.0 0.000 585.20$ VFD PumpComm-WeatherCooling/Heating10 3,959.2 0.3 41.01$ Plug Load Occupancy Sensors Document StationsComm-NonWeatherOffice Load5 803.0 0.1 50.88$ High Bay 3L T5HO Replacing 250W HIDComm-NonWeatherLighting 12 449.0 0.103 222.91$ Refrigeration Commissioning Comm-NonWeatherRefrigeration3 375.0 0.0 37.29$ HP Water Heater 10 to 50 MBHComm-NonWeatherWater Heater15 21,156.0 4.2 1,100.00$ High Bay 4LT5HO Replacing 400W HIDComm-NonWeatherLighting 12 882.0 0.200 159.28$ Strip curtains for walk-ins - freezer Comm-NonWeatherRefrigeration4 613.0 0.1 77.00$
SECTION 11 DSM/EE RESOURCES
ALASKA RIRP STUDY
Black & Veatch 11-11 February 2010
Tables 11-5 and 11-6 provide additional information regarding the input assumptions used in the evaluation
of the residential and commercial DSM/EE measures, respectively. This information includes:
• Incremental equipment cost
• Rebate as a percentage of incremental equipment cost
• Rebate amount
• Administrative costs
• Vendor or other costs
• Total per unit costs
It should be noted that Black & Veatch did not complete a comprehensive cost-effectiveness evaluation of
these measures using the traditional DSM cost-effectiveness tests (i.e., TRC, Participant, Utility and RIM
tests). Regional avoided costs are required to evaluate DSM/EE measure using these tests, and these avoided
costs were not available when this evaluation was completed as part of this project. Rather, Black & Veatch
achieved the cost-effectiveness assessment of these measures by including them directly in the RIRP models,
which allowed for a direct comparison of the economics of DSM/EE measures relative to alternative supply-
side alternatives.
Furthermore, once the most appropriate technologies were screened, Black & Veatch estimated how many
customers would adopt each technology each year in order to arrive at potential energy savings to be used in
the RIRP modeling. Even though technologies are grouped into one or more program(s) for going to market,
the application of a participation rate is done at the measure level. The number of customers available to
adopt the technology was based upon the customer counts and appliance saturations discussed earlier. From
this starting point, a set of technology adoption curves were applied that characterize the pattern of acceptance
(or purchase) typical of products at different levels of marketing. For example, a high rebate amount for a
product might be expected to achieve a high penetration in the early years, translating into a “steep” curve.
On the other hand, a program that merely provides consumers with information about changing their
behavior, but offers no monetary incentive, may result in an increase in related participation over time, but at
a lower level and slower pace. To estimate maximum penetration rates for purposed of RIRP modeling,
Black & Veatch used a series of technology adoption curves for DSM/EE studies from the BASS model.
These curves are built from the original “S” shaped curve of product adoption and are a generally-accepted
tool for characterizing consumer adoption patterns. Since Alaska is fairly new territory for DSM/EE
programs, Black & Veatch assumed that the level of incentives required to move the market to adopt
DSM/EE measures would average approximately 45 percent of incremental equipment costs.
SECTION 11 DSM/EE RESOURCES
ALASKA RIRP STUDY
Black & Veatch 11-12 February 2010
Table 11-5
Input Assumptions - Residential DSM/EE Measures
Residential Measures
Incremental
Equipment
Cost ($)
Rebate as
% of
Incremental
Equipment
Cost
Rebate
Amount ($)
Administrative
Costs (10%)
Vendor or
Other Costs
Total per
Unit
Program
Costs
Freezers Energy
Star-Chest Freezer
$92.50 50% $46.25 $4.63 -- $50.88
Clothes Dryers $150.00 50% $75.00 $7.50 -- $82.50
Refrigerators-Freezers
Energy Star-Top Freezer
$92.50 50% $46.25 $4.63 -- $50.88
Refrigerators-Freezers
Energy Star-Side by Side
$92.50 50% $46.25 $4.63 -- $50.88
Pump and Motor Single
Speed
$85.00 25% $21.25 $2.13 -- $23.38
Smart Strip Plug Outlet $40.00 25% $10.00 $1.00 -- $11.00
Freezer Recycling $93.00 0% -- -- $75.00 $75.00
Heat Pump Water Heaters $700.00 25% $175.00 $17.50 $50.00 $242.50
Refrigerator Recycling $93.00 0% -- -- $130.00 $130.00
Low Flow Showerheads $31.60 100% $31.60 $3.16 $2.00 $36.76
Pipe Wrap $7.60 25% $1.90 $0.19 -- $2.09
Holiday Lights $12.00 100% $12.00 $1.20 $1.00 $14.20
CFL Fixtures $45.00 50% $22.50 $2.25 -- $24.75
Torchiere Floor Lamps $50.00 0% -- -- $10.00 $10.00
LED Night Light $5.00 100% $5.00 $0.50 $1.00 $6.50
CFL Bulbs
Regular-Outside
$3.00 25% $0.75 $0.08 -- $0.83
CFL Bulbs Regular $3.00 25% $0.75 $0.08 $2.00 $2.83
Ceiling Fans $275.00 50% $137.50 $13.75 -- $151.25
Duct Sealing 20 Leakage
Base
$215.82 50% $107.91 $10.79 $25.00 $143.70
Roof Insulation $756.95 50% $378.48 $37.85 $25.00 $441.32
Setback
Thermostat-Moderate
Setback
$18.46 100% $18.46 $1.85 $25.00 $45.31
SECTION 11 DSM/EE RESOURCES
ALASKA RIRP STUDY
Black & Veatch 11-13 February 2010
Table 11-6
Input Assumptions - Commercial DSM/EE Measures
Commercial Measures
Incremental
Equipment
Cost ($)
Rebate as
% of
Incremental
Equipment
Cost
Rebate
Amount ($)
Administrative
Costs (10%)
Vendor or
Other Costs
Total per
Unit
Program
Costs
ENERGY STAR Steam
Cookers 3 Pan
$4,150.00 25% $1,037.50 $103.75 -- $1,141.25
Plug Load Occupancy
Sensors Document Stations
$185.00 25% $46.25 $4.63 -- $50.88
HP Water Heater 10 to 50
MBH
$4,000.00 25% $1,000.00 $100.00 -- $1,100.00
Motors 1 to 5 HP $88.00 75% $66.00 $6.60 $25.00 $97.60
Motors 25 to 100 HP $558.00 50% $279.00 $27.90 $25.00 $331.90
Motors 7.5 to 20 HP $227.00 50% $113.50 $11.35 $25.00 $149.85
LED Exit Signs Electronic
Fixtures (Retrofit Only)
$60.00 50% $30.00 $3.00 -- $33.00
LED Auto Traffic Signals $90.00 50% $45.00 $4.50 -- $49.50
LED Pedestrian Signals $140.00 50% $70.00 $7.00 -- $77.00
VFD HP 1.5 Process
Pumping
$1,445.00 75% $1,083.75 $108.38 -- $1,192.13
VFD HP 10 Process
Pumping
$2,860.00 25% $715.00 $71.50 $25.00 $811.50
VFD HP 20 Process
Pumping
$4,515.00 25% $1,128.75 $112.88 $25.00 $,266.63
Vending Equipment
Controller
$195.50 25% $48.88 $4.89 $25.00 $78.76
Efficient Refrigeration
Condenser
$35.00 25% $8.75 $0.88 -- $9.63
ENERGY STAR
Commercial Solid Door
Freezers -Less Than 20ft3
$150.00 25% $37.50 $3.75 -- $41.25
ENERGY STAR
Commercial Solid Door
Freezers-20 to 48 ft3
$400.00 75% $300.00 $30.00 -- $330.00
ENERGY STAR
Commercial Solid Door
Refrigerators-Less Than
20ft3
$250.00 25% $62.50 $6.25 -- $68.75
ENERGY STAR
Commercial Solid Door
Refrigerators-20 to 48 ft3
$500.00 50% $250.00 $25.00 -- $275.00
SECTION 11 DSM/EE RESOURCES
ALASKA RIRP STUDY
Black & Veatch 11-14 February 2010
Table 11-6 (Continued)
Input Assumptions - Commercial DSM/EE Measures
Commercial Measures
Incremental
Equipment
Cost ($)
Rebate as
% of
Incremental
Equipment
Cost
Rebate
Amount ($)
Administrative
Costs (10%)
Vendor or
Other Costs
Total per
Unit
Program
Costs
ENERGY STAR Ice
Machines-Less Than 500
lbs
$600.00 50% $300.00 $30.00 -- $330.00
ENERGY STAR Ice
Machines-500 to 1,000 lbs
$1,500.00 50% $750.00 $75.00 -- $825.00
ENERGY STAR Ice
Machines-More Than
1,000 lbs
$2,000.00 25% $500.00 $50.00 -- $550.00
Pumps HP 1.5 $350.00 75% $262.50 $26.25 $25.00 $313.75
Pumps HP 10 $332.00 25% $83.00 $8.30 $25.00 $116.30
Pre Rinse Sprayers $35.00 25% $8.75 $0.88 -- $9.63
Exterior HID Replacement
Above 250W to 400W
HID Retrofit
$1,064.00 50% $532.00 $53.20 -- $585.20
High Bay 3L T5HO
Replacing 250W HID
$277.60 73% $202.65 $20.26 -- $222.91
High Bay 4LT5HO
Replacing 400W HID
$289.60 50% $144.80 $14.48 -- $159.28
High Bay 6L T5HO
Replacing 400W HID
$447.60 75% $335.70 $33.57 -- $369.27
High Bay Fluorescent
6LF32T8 Replacing 400W
HID
$257.60 25% $64.40 $6.44 -- $70.84
High Bay Fluorescent
8LF32T8 Double Fixture
Replace 1,000W HID
$497.60 25% $124.40 $12.44 -- $136.84
CFL Fixture $78.92 25% $19.73 $1.97 -- $21.70
CFL Screw-in $30.14 25% $7.53 $0.75 -- $8.29
Daylight Sensor Controls $4,000.00 25% $1,000.00 $100.00 -- $1,100.00
Central Lighting Control $3,700.00 50% $1,850.00 $185.00 -- $2,035.00
Occupancy Sensors-Under
500 W
$144.00 50% $72.00 $7.20 -- $79.20
Low Watt T8 Lamps $6.24 50% $3.12 $0.31 -- $3.43
3 Lamp T5 Replacing T12 $200.16 50% $100.08 $10.01 -- $110.09
4 Lamp T5HO Replacing
T12
$306.06 50% $153.03 $15.30 -- $168.33
SECTION 11 DSM/EE RESOURCES
ALASKA RIRP STUDY
Black & Veatch 11-15 February 2010
Table 11-6 (Continued)
Input Assumptions - Commercial DSM/EE Measures
Commercial Measures
Incremental
Equipment
Cost ($)
Rebate as
% of
Incremental
Equipment
Cost
Rebate
Amount ($)
Administrative
Costs (10%)
Vendor or
Other Costs
Total per
Unit
Program
Costs
HPT8 4ft 3 Lamp, T12 to
HPT8
$138.16 50% $69.08 $6.91 -- $75.99
HPT8 4ft 4 Lamp, T12 to
HPT8
$147.06 50% $73.53 $7.35 -- $80.88
T12HO 8ft 1 Lamp
Retrofit to HPT8 T8 4ft 2
Lamp
$113.35 50% $56.68 $5.67 -- $62.34
T12HO 8ft 2 Lamp
Retrofit to HPT8 T8 4ft 4
Lamp
$147.06 50% $73.53 $7.35 -- $80.88
T8 4ft 3 Lamp $130.16 75% $97.62 $9.76 -- $107.38
T8 4ft 4 Lamp $138.06 75% $103.55 $10.35 -- $113.90
T8 HO 8 ft 2 Lamp $151.42 75% $113.57 $11.36 -- $124.92
Window Film $153.81 50% $76.91 $7.69 -- $84.60
Refrigerant Charging
Correction
$38.36 50% $19.18 $1.92 -- $21.10
VFD Fan $155.96 25% $38.99 $3.90 -- $42.89
VFD Pump $149.14 25% $37.28 $3.73 -- $41.01
Refrigeration
Commissioning
$113.00 30% $33.90 $3.39 -- $37.29
Strip Curtains for Walk-
ins-Freezer
$200.00 35% $70.00 $7.00 -- $77.00
SECTION 11 DSM/EE RESOURCES
ALASKA RIRP STUDY
Black & Veatch 11-16 February 2010
11.5 DSM/EE Program Delivery
As will be discussed in Section 13, the RIRP models selected all DSM/EE measures for inclusion in each of
the four alternative resource plans, based upon the costs incurred and savings achieved from the utility
persepctive. The successful implementation of these resources, however, is dependent on several factors.
First, it is important that a comprehensive technical and achievable potential study be completed, including
the comprehensive cost-effectiveness evaluation of the available DSM/EE measures and using Railbelt-
specific information.
Second, it is Black & Veatch’s belief that a regional entity should be formed to develop and deliver DSM/EE
programs on a regional basis, in close coordination with the six Railbelt utilities. This entity could be the
proposed GRETC organization or another entity focused exclusively on DSM/EE programs.
This was addressed in the REGA Study Final Report, which included the following observations regarding
the potential deployment of DSM programs by the Alaska Railbelt utilities:
“ …, the Railbelt utilities have limited experience with the planning, developing and delivering of DSM
and energy efficiency programs. To date, the majority of efforts in the Railbelt region and the State as a
whole have been focused on the implementation of home weatherization programs. These programs can
significantly reduce the energy consumption within individual homes; however, given the limited
saturation of electric space heating equipment and the general lack of air conditioning loads, the
potential for DSM and energy programs are limited from the perspective of the Railbelt electric utilities.
An implementation issue that needs to be addressed is whether the development and deployment of DSM
and energy efficiency programs throughout the Railbelt region should be accomplished by the individual
Railbelt utilities or whether a regional approach would result in more efficient and cost-effective
deployment of these resources. Additionally, given the fact that the total monthly energy bills paid by
residential and commercial customers in the Railbelt have increased significantly in recent years and
given that natural gas is the predominant form of space heating within the majority of the Railbelt region,
it may be appropriate for the electric utilities to work jointly with Enstar to develop DSM and energy
efficiency programs that would be beneficial to both. This would create economies of scope for the region
and reduces the delivery costs of DSM and energy efficiency programs.” (pps. 49-50)
Third, the Railbelt electric utilities should work closely with Enstar and the AHFC with regard to the
implementation of DSM/EE programs.
These points are discussed further in Section 16.
SECTION 12 TRANSMISSION PROJECTS
ALASKA RIRP STUDY
Black & Veatch 12-1 February 2010
12.0 TRANSMISSION PROJECTS
The Railbelt transmission system included in this study consists of six independent utilities loosely
interconnected by a transmission system that is constrained and inadequate to support interconnected
operation envisioned by the GRETC concept of robust reliable service for all Railbelt utilities. One of the
primary objectives of the current RIRP is to develop a transmission system that can support the economic
development and operation of an integrated Railbelt system.
12.1 Existing Railbelt System
The Alaskan transmission infrastructure is relatively new compared with other transmission and distribution
facilities in the lower-48 states. In the 1940s, the Chugach, GVEA, HEA, MEA, ML&P, and SES systems
were formed to provide electric service to consumers within their respective service areas. The Doyon service
area which is not explicitly included in this study was established in 2007 to serve the loads of the US Army
bases at Fort Greely, Fort Wainwright in Fairbanks and Fort Richardson in Anchorage.
These utilities developed and operated independently of each other and were successful in providing
reasonable service to businesses and residences. In 1984, the State of Alaska constructed the Anchorage-
Fairbanks Intertie, and Chugach and ML&P strengthened their interconnection allowing improved operation
and reliability among the utilities. In that same year, the State of Alaska and the Railbelt utilities established
the Alaska Intertie Agreement. This agreement has served as the operating contract between all utilities for
the past 25 years, but will expire within the next two years. Also, the expiration of the thirty-year power sales
agreements between Chugach, MEA and HEA will terminate in 2014. Presumably, following the expiration
of the current power sales contracts, each of the Railbelt utilities will assume the responsibility of planning
the transmission system to serve its own requirements. However, the planning, repair, and construction of
transmission facilities required to continue to provide economic and reliability benefits to all utilities does not
fall under the responsibility of any of the specific Railbelt utilities. The expiration of the Chugach power
supply contracts and the Intertie Operating Agreement leaves a void in the planning and operation of critical
transmission assets required for inter-utility power transfers and reliability improvements. Changing
generation plans may decrease the importance of transmission to a single utility, but the transmission will
remain critical to the interconnected system. However, with the changing power supply conditions which
include heightened environmental awareness, fuel cost volatility and availability, and the aging generation
plants of the Railbelt, it became evident that investigation of a more coordinated approach of the Railbelt
utilities to planning and operating together could provide significant benefits for the people of Alaska. The
first obstacle to the goal of coordinated planning and operation is the lack of an entity that has the
responsibility and authority for the planning and operation of the transmission system utilized to interconnect
the systems of individual utilities. The second obstacle to coordinated generation planning and operations is
the lack of an adequate transmission infrastructure to support joint economic and reliable operations. This
section focuses on the transmission projects that may be necessary for the Railbelt utilities to construct a
reliable transmission system that is capable of providing transfers of firm and economy energy transactions
and also allow for the economic planning of firm generation capacity and reserves.
The existing Railbelt utilities cover the Fairbanks area, the Anchorage area, and the Kenai Peninsula and are
interconnected between Fairbanks and Anchorage via a single transmission line known as the Anchorage-
Fairbanks Intertie, while Anchorage and the Kenai are connected by a single transmission line known as the
Anchorage-Kenai Intertie. These existing facilities are discussed in Section 4.
SECTION 12 TRANSMISSION PROJECTS
ALASKA RIRP STUDY
Black & Veatch 12-2 February 2010
The existing Railbelt transmission system, as well as the loads supplied in each area, is presented in
Figure 12-1. A significant issue affecting the existing Railbelt system results from the constrained
transmission infrastructure interconnecting the utilities. This existing transmission infrastructure results in the
system operation being severely constrained by stability and power transfer limits. As a result of being
stability constrained, individual transmission projects constructed to increase transmission capacity cannot be
fully loaded to their thermal limits and the economic sharing of reserves between utilities is also inhibited.
This void cannot be filled by the existing planning and development strategy of independent utilities but
should be tackled by an integrated development of the transmission system by an independent entity
responsible for the planning, construction and operation of the interconnected system.
Figure 12-1
Railbelt Transmission System Overview
SECTION 12 TRANSMISSION PROJECTS
ALASKA RIRP STUDY
Black & Veatch 12-3 February 2010
12.2 The GRETC Transmission Concept
One of the goals of the current study is to facilitate the development of generation and transmission systems
in the most economic and reliable manner possible. By coordinating the needs of all utilities, common
problems such as aging generation, unequal reliability and more levelized power supply rate structures can be
developed for the Railbelt region. By assessing the problems of the system as a whole, projects that may be
more economic and offer a more stable rate structure for the entire Railbelt may be developed, bringing rate
stability and a dependable power cost to the entire Railbelt region.
In order to provide an organization capable of undertaking the needs of the Railbelt utilities, the Legislature is
considering the formation of GRETC which would become the entity charged with planning, constructing,
and operating the integrated energy and transmission system to serve the Railbelt utilities.
The corporate identity of GRETC has yet to be determined. Several organizational structures have been
evaluated and will require further study. The purpose of this study is not to identify the structure of GRETC
as an organization, but to identify its role in the Railbelt electrical system. GRETC’s role in the Railbelt
system is envisioned as follows:
Planning
GRETC will serve as the entity responsible for performing system studies, analysis, and evaluation of
transmission projects, and will be required to:
• Develop plans to repair and replace (R&R) the existing transmission system as required to maintain
the service and reliability of the existing system such that the future system will be at least no worse
than the reliability and transfer capacity that exist today.
• Develop plans to repair, replace and maintain the communication and control system required to
ensure system reliability and economic operation.
• Develop long-range transmission plans (LRTP) to identify transmission projects required over the
next 50 years to provide the same or comparable reliability and service to all Railbelt utilities.
• Develop generation and transmission plans such that at the completion of each plan, no single
contingency within the GRETC system results in the loss of firm load.
• Develop mid-range transmission plans (10-Year Plan, or TYP) to prioritize the transmission projects
identified in the LRTP and R&R plans into a single plan that is consistent with the requirements of
the Railbelt utilities and within the financing capability of GRETC.
• Develop and maintain rolling Five-Year Plans (FYP) that identify the projects to be constructed
within the next five years as outlined in the TYP. Develop project schedules, including permitting
and right-of-way (ROW) schedules for long-term projects.
• Develop design criteria for each project identified in the plan, develop the design, construction
management, construction, and close-out schedules and budgets.
• Administer design, construction management, and construction contracts associated with the projects.
Operation
• GRETC should be responsible for operation of the transmission and generation system required to
deliver power between GRETC generation or GRETC delivery points to Railbelt utilities to ensure
that each utility, over the long-term planning horizon receives comparable service in terms of
transmission reliability, access to reserves, and transmission costs.
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• GRETC should be responsible for the economic operation of the Railbelt generation system, ensuring
that power throughout the Railbelt is produced in the most economical manner possible.
• GRETC should be responsible for allocation of reserves to ensure system reliability is maintained at
no worse than existing levels.
In developing projects for the integrated operation of the Railbelt transmission system the following criteria
were adopted:
• The transmission system will be upgraded over time to remove transmission constraints that currently
prevent the coordinated operation of all the utilities as a single entity. The transmission planning
period is 50 years. The ability of GRETC to construct the transmission improvements identified in
this study within any certain time period is unknown. The prioritization of the transmission projects
and their subsequent schedule for construction cannot be completed in the scope of this study. As
such, this study attempts to identify required transmission improvements for evaluation in future
studies.
• The study includes all the utilities' assets, 69 kV and above, that are used to transmit power from a
GRETC generator to the Railbelt system or between significant load areas. These assets, over a
transition period, may flow into GRETC and form the basis for a phased upgrade of the system into a
robust, reliable transmission system that can accommodate the economic operation of the
interconnected system. Utility assets, 69 kV and above, that are not used to transmit power between
GRETC generation or between GRETC transmission delivery points may or may not be transferred to
GRETC.
• Generation assets not utilized by GRETC for power delivery, reserves or other uses may be retained
by the individual utilities for their own uses such as emergency generation, load-side generation, load
serving etc.
• The study assumes that all utilities participate in GRETC with transmission and generation planning
being conducted on a GRETC (i.e., regional) basis. The common goal would be the tight integration
of GRETC with the utilities for planning and operations as previously described.
12.3 Project Categories
The projects selected for consideration were based on the overall GRETC concept of developing a robust,
reliable transmission system that can accommodate the economic operation of the Railbelt integrated system.
Discussions were held with the utilities and a list of potential projects was developed for further
consideration. The projects were classified in the following categories:
• Transmission systems that need to be replaced because of age and condition (Category 1)
• Transmission projects required to improve grid reliability, power transfer capability, and reserve
sharing (Category 2)
• Transmission projects required to connect new generation projects to the grid (Category 3)
• Transmission projects to upgrade the grid required by a new generation project (Category 4)
In developing the system, reliability remains a significant focus. Redundancy is one way to increase
reliability, but may not be the only way to improve or maintain reliability as indicated in the analysis below.
12.4 Summary of Transmission Analysis Conducted
A transmission analysis consisting of power system load flows and N-1 analysis was conducted to determine
the deficiencies of the existing system. In the existing transmission system, constraints preclude the
economic development of large projects that are common to the entire Railbelt. Lack of transfer capacity and
single contingency interties prevent projects being developed in any one area to serve firm power to the entire
region. Improvements to the power system required to alleviate overloads, transfer limitations and address
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N-1 contingencies under the existing generation and the generation configurations developed as part of this
plan were identified as projects and evaluated in power flow studies to determine if the resulting system
satisfied the main objectives and criteria set for the RIRP. Identified projects were evaluated to determine if
the system could supply the projected load under economic generation dispatch without violating the
transmission criteria of no loss of load or voltage violations under the N-1 criteria as well as to establish a
redundant system with a 230 kV backbone through the Railbelt. Similar to the generation alternatives, this
plan has identified possible projects that are required to meet the goals and objectives of GRETC.
Prioritization and detailed development of the projects should be completed concurrent with the subsequent
generation plan to provide a comprehensive and coordinated approach to serving the Railbelt utilities.
12.4.1 Cases Reviewed
The base case for 2060 was evaluated with all the projects included, along with the load forecast for 2060 as
developed for the RIRP. The generating resources selected by the RIRP for the different scenarios were also
modeled for the respective cases. With each case developed, the generating resources were dispatched
economically and several contingencies evaluated to determine if there were any constraints on the Railbelt
transmission system. A review of the recent projects designed and constructed for the Railbelt utilities, has
revealed that many projects have been designed at a higher voltage than the existing voltage of the line. In
many cases, the circuits have been rebuilt to a higher voltage but placed back in operation at the same voltage
awaiting an opportunity to increase the capacity of these circuits when appropriate. These lines, in many
instances, have been insulated to operate at 230 kV from the existing 115 kV or 138 kV levels. To capture
the benefits of increased transmission capacity, as well as to capture the benefits of standardizing transmission
voltages at a specific level thus controlling operation and maintenance costs going forward, standardization of
the Railbelt transmission grid at 230 kV was determined by Black & Veatch, EPS, and the Railbelt utilities to
be appropriate. This key concept of developing a reliable transmission backbone for the Railbelt occasionally
results in projects that are designed and constructed at a higher voltage but operated at a lower voltage until
the transition to the higher voltage can be facilitated or justified This is particularly applicable in the repair
and replacement of existing transmission facilities. Portions of the existing Railbelt transmission system are
not recommended to be included in the 230 kV upgrade due to difficulties in obtaining ROW and other
considerations. As a result, portions of the existing 115 kV system on the Kenai, ML&P and MEA areas
would remain at 115 kV and portions of the Chugach and GVEA systems would remain at 138 kV throughout
the life of this plan.
In accordance with the ideals of GRETC, some of the existing transmission systems would not be
incorporated into the GRETC system, but would remain with the local utility to own, operate and maintain for
its own use.
Since the repair and replacement of the existing transmission facilities is scheduled over many years, it is
likely that that the initial portions of a transmission line replacement project will be operated at its existing
voltage for many years until the entire transmission line is replaced and a justification to convert any required
substations and operate the transmission line at its ultimate construction voltage is warranted.
The above analysis was based on load flow evaluations with consideration given to possible stability issues.
The development of the final transmission plan will require more detailed studies, analysis and integration
with the selected generation plan. The projects that are interrelated with generation scenarios will require
evaluation concurrent with more detailed generation scenarios. Projects that are independent of generation
scenarios can undergo detailed studies, including stability analysis and detailed evaluation prior to selection
of the preferred generation scenario. The results of these future studies may result in some changes to the
projects identified.
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Black & Veatch 12-6 February 2010
12.4.2 Results of 2060 Analysis
The transmission analysis included normal and N-1 contingency analysis of all transmission branches in the
Railbelt, with all the generating resources dispatched economically. The power flow analysis was evaluated
to determine if any overloads or voltage violations of any of the transmission lines within the Railbelt system
occur during both normal and N-1 conditions.
Limited stability studies were completed to evaluate the ability of the Railbelt system to operate for select
cases. As future studies refine transmission and generation projects, additional power flow and stability
studies will be required to evaluate the requirements of the transmission system.
12.5 Proposed Projects
Project A – Bernice Lake Power Plant to International 230 kV Transmission Line (Southern Intertie)
(New Build - Category 2)
The Bernice Lake Power Plant to International Substation 230 kV project is a new 230 kV line between the
Anchorage area and the Kenai. The project commences at the ITSS substation, crosses Turnagain Arm via
submarine cable and an overhead crossing of Fire Island and proceeds overhead along the coastline to the
Bernice Lake Substation. The project is comprised of a total of 15 miles of submarine cable and 47 miles of
overhead transmission line. The project is intended to follow the recommended route included in the
Environmental Impact Statement managed by Chugach.
The single transmission line between Anchorage and Kenai prevents the economic construction of generation
in the Railbelt, and places constraints on both the amount of power that can be exported from the Kenai area
and the amount of power that can be imported into the Kenai area.
In addition to the export and import of energy to the Kenai, the ability to utilize reserves across this single
transmission line is a severe restriction to the economic operation of the system as a whole. For instance, if
the Bradley reserves are increased to 50 MW, the ability of the northern utilities to utilize these additional
reserves is questionable since the transfer of these reserves requires transmission across the single tie-line that
is already transferring real power to the northern utilities and the transfer of these reserves is beyond the
stability limit of the transmission system.
In order to meet the planning criteria that no N-1 contingency results in the loss of load from the GRETC
system, without a second tie-line, the generation on the Kenai has to be severely constrained to limit power
transfers into the Kenai area. This constraint increases both capital and operating costs for the Railbelt,
forcing the location of new generation on the Kenai as well as new generation in the northern parts of the
system to supply reserves that are not transferable across the existing transmission line.
This project is the second intertie between the areas and is required to increase the transfer limit between the
two areas. The current transfer limit between the areas is limited due to stability considerations to 75 MW.
The steady-state limit is constrained to 105 MW (winter) due to voltage collapse while the thermal limit for
the existing 115 kV transmission line is approximately185 MW (winter) and 95 MW (summer). This project
is a Category 2 project required for reliability and increased transfer capability. Figure 12-2 presents the
proposed project. More investigation is required to determine detailed transmission characteristics and
routing.
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Black & Veatch 12-7 February 2010
Figure 12-2
Bernice Lake Power Plant to International 230 kV Transmission Line (New Build)
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ALASKA RIRP STUDY
Black & Veatch 12-8 February 2010
Project B – Soldotna to Quartz Creek 230 kV Transmission Line (Repair and
Replacement - Category 1)
This project is the upgrade of the existing 54-mile long, 115 kV transmission line between Soldotna and
Quartz Creek substations. This line was constructed in 1959 and is in very poor condition, suffering from
frost jacking and age deterioration. The transmission line is a continuation of the Anchorage – Daves Creek
line and results in the same stability and reliability constraints as the Project 1-line described above. Because
of the importance of this intertie to the integrated operation of the Railbelt system, this line is proposed to be
rebuilt for operation at 230 kV. The line would continue to operate at 115 kV until conversion to 230 kV
operation is warranted. Figure 12-3 presents the proposed upgrade.
Figure 12-3
Soldotna to Quartz Creek 230kV Transmission Line (Repair and Replacement)
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ALASKA RIRP STUDY
Black & Veatch 12-9 February 2010
Project C – Quartz Creek to University 230 kV Transmission Line (Repair and
Replacement - Category 1)
This is the section of the existing 115 kV Kenai Intertie owned by Chugach and was constructed in 1959 and
consists of two sections. The first section is from Quartz Creek to Daves Creek and is approximately
7.7 miles long. The second section is from Daves Creek to University and is approximately 68.2 miles long.
Portions of this line have been upgraded over time however approximately 65 percent of this wood pole line
is over 50 years old and is subject to avalanches and severe weather conditions. It will require significant
rebuilding to keep it in service over the life of this plan. The line is considered a critical component of the
transfer capability between the Anchorage and Kenai areas and is also required for reliability and reserve
sharing. The current transfer limit between the areas is limited due to stability considerations to 75 MW. The
steady-state limit is constrained to 105 MW due to voltage collapse while the thermal limit for the existing
115 kV transmission line is approximately185 MW in the winter and 95 MW in the summer. The line is
recommended to be upgraded to 230 kV over the life of this plan to increase the stability limit transfer
capability and reserve sharing between the areas. Figure 12-4 presents the proposed upgrade.
Figure 12-4
Quartz Creek to University 230kV Transmission Line (Repair and Replacement)
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ALASKA RIRP STUDY
Black & Veatch 12-10 February 2010
Project D – Douglas to Teeland 230 kV Transmission Line (Repair and Replacement - Category 2)
The Douglas to Teeland line was originally constructed for operation at 115 kV and currently operates at
138 kV and serves as the final line section of the Anchorage-Fairbanks Intertie.
The construction of the Lorraine-Douglas line described below and the upgrade of the Anchorage-Fairbanks
Intertie to 230 kV requires the upgrade of this line section to 230 kV to form a transmission loop between
Lorraine-Teeland and Douglas stations. The proposed loop will eliminate single contingency outages to the
southern portion of the Intertie and permits higher transfer limits between load and generation areas. The line
should be constructed following the completion of the Lorraine – Douglas line section to mitigate the impact
of the line’s construction on energy transfers between the Anchorage and Fairbanks areas. Figure 12-5
presents the proposed upgrade.
Figure 12-5
Douglas to Teeland 230 kV Transmission Line (Repair and Replacement)
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Black & Veatch 12-11 February 2010
Project E – Lake Lorraine to Douglas 230 kV Transmission Line (New Build - Category 2)
Pt. MacKenzie substation is a key component in the Railbelt transmission grid, serving as the hub of electrical
power generated at Beluga and providing interconnections to all other utilities. Teeland substation currently
serves as the sole terminus of the Anchorage-Fairbanks Intertie and also as the primary source of power for
MEA’s consumers in the Palmer-Wasilla area.
The Pt. MacKenzie–Teeland transmission line is the heaviest loaded line in the Railbelt, often carrying over
200 MW during peak months. By comparison, the Anchorage-Kenai Intertie is constrained to no more than
75 MW during its peak loading and the Anchorage-Fairbanks Intertie is restricted to less than 85 MW. Under
both summer and winter loading conditions, the loss of the Pt. MacKenzie-Teeland transmission line results
in unstable conditions in the Anchorage-Kenai transmission system during certain generation conditions.
This instability is in addition to the blackout of approximately 25 percent of the Railbelt consumers caused by
the line outage. The unstable conditions could result in widespread blackouts from Fairbanks to Homer. In
the worst case, the system will suffer a complete blackout, with a risk of damage to Railbelt generators.
The construction of a new substation at Lake Lorraine, with a new transmission line to Douglas Substation
provides a transmission loop between Pt. MacKenzie, Lake Lorraine, Teeland and Douglas substations will
eliminate the largest single contingency in the Railbelt system. Following the completion of the Lorraine-
Douglas line, the loss of any single transmission line in this loop will not result in widespread outages in the
Fairbanks and Mat-Su areas.
The construction of the Lake Lorraine-Douglas transmission line has a dramatic impact on the reliability of
service to the Railbelt consumers. The elimination of a single point of failure for the entire electrical system
in the summer conditions is achieved. In both winter and summer conditions, outages to all consumers in the
Palmer – Wasilla areas and a significant number of consumers in the Fairbanks area by the failure of a single
transmission line are eliminated. The stability margin for the winter conditions is improved, but unlike the
summer conditions, the risk of system instability is not eliminated.
This project will also require the upgrade of the existing SVCs at Teeland, Healy and Gold Hill. These SVCs
were installed in 1984 as part of the original Intertie construction. The SVC components are no longer
manufactured or available from third party vendors. Spare parts have been exhausted and replacement
components cannot be obtained. Loss of the SVCs is critical to the operation of the Intertie and the economic
transfer of both energy and capacity between Anchorage and Fairbanks. Figure 12-6 presents this proposed
project.
SECTION 12 TRANSMISSION PROJECTS
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Black & Veatch 12-12 February 2010
Figure 12-6
Lake Lorraine to Douglas 230 kV Transmission Line (New Build)
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ALASKA RIRP STUDY
Black & Veatch 12-13 February 2010
Project F – Douglas to Healy 230 kV Transmission Line (Upgrade - Category 2)
The Alaska Intertie includes a 170-mile, 345 kV transmission line between Willow and Healy and voltage
control devices at Teeland, Healy and Gold Hill Substations. The line built with State grant funds, went into
operation in 1985, and is operated at 138 kV.
The line is the state-owned portion of the 300 mile Anchorage to Fairbanks transmission system. The Intertie
allows GVEA to purchase lower cost energy from Anchorage and the Kenai generated from natural gas and
the Bradley Lake hydroelectric project. Chugach and ML&P generate revenue from the sale of economy
energy to GVEA. The line also allows reserves, both operating and non-operating to be shared between the
northern and southern areas of the system.
The ability to import power into the Fairbanks area is limited to the current stability limit of approximately 85
MW. Although stability aids could increase this power transfer capability, the amount of power transferred
over the intertie would still be limited to approximately 85 MW as this is considered the maximum allowable
import limit into the Fairbanks area to survive the N-1 contingency of the loss of the intertie.
The proposed transmission line upgrade will allow power transfers to increase from the existing limit of
approximately 85 MW and will eliminate the loss of load associated with an N-1 contingency and bring the
Fairbanks GRETC area into compliance with the planning criteria following the completion of the second
transmission line. Figure 12-7 presents the proposed transmission line.
Figure 12-7
Douglas to Healy 230 kV Transmission Line (Upgrade)
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ALASKA RIRP STUDY
Black & Veatch 12-14 February 2010
Project G – Douglas to Healy 230 kV Transmission Line (New Build - Category 2)
An additional line between the Douglas and Healy substation is required to meet the reliability criteria for no
loss of load for any N-1 condition and to increase the transfer capability between the northern and central
portions of the Railbelt. The ability to import power into the Fairbanks area is limited to the current stability
limit of approximately 85 MW over the single transmission line. Although stability aids could increase this
power transfer capability, the amount of power transferred over a single intertie would still be limited to
approximately 85 MW as this is considered the maximum allowable import limit into the Fairbanks area to
ensure survival following the N-1 contingency loss of the intertie.
The proposed transmission line will allow power transfers to increase from the existing limit of approximately
85 MW and will eliminate the loss of load associated with an N-1 contingency and bring the Fairbanks
GRETC area into compliance with the planning criteria following the completion of the second transmission
line. The proposed route would parallel the existing intertie. A significant portion, but not all of the right-of-
way, of the existing intertie will accommodate an additional line. The exact routing and characteristics of the
transmission line, along with any associated changes in compensation at the terminals of the line will be
determined in future studies. Figure 12-8 presents the proposed new line. If the preferred generation plan
includes a Susitna option, this line configuration will change depending on the selected Susitna alternative.
Figure 12-8
Douglas to Healy 230 kV Transmission Line (New Build)
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ALASKA RIRP STUDY
Black & Veatch 12-15 February 2010
Project H – Eklutna to Fossil Creek 230 kV Transmission Line (Upgrade - Category 2)
The Eklutna and Briggs substations are interconnected by a 230 kV double circuit line with one circuit used to
supply multiple MEA distribution substations at 115 kV. The other circuit is not connected to local
distribution substations and can function as a direct connection from Eklutna to Fossil Creek. From Fossil
Creek the 230 kV line currently connects to the ML&P Plant 2 230 kV substation while the 115 kV line
connects to the 115 kV substation at ML&P’s Plant 2 generation plant. The construction of a 230 kV/115 kV
substation at Fossil Creek would allow this line section to serve an express 115 kV line to Eklutna station
while the tapped line would be used to serve local load. As part of the long range goals, the express feeder
would be converted to 230 kV with a corresponding 230 kV/115 kV substation at Eklutna. This project,
along with upgrade of the MEA 115 kV system (Projects M and N), will be part of a redundant 230 kV path
from Beluga to Anchorage. This project includes the construction of a 230 kV/ 115 kV substation at Fossil
Creek and Eklutna to serve the MEA 115 kV system. Figure 12-9 presents the proposed line from Eklutna to
the Fossil Creek substation.
This project will also require the construction of a 230 kV line section from ML&P Plant 2 to University
station for N-1 contingencies at Plant 2 and to support the ML&P and Chugach 138 kV and 115 kV systems
as described in other project summaries.
The project may consist of a staged approach resulting in the 115 kV systems in the MEA area continuing to
operate at 115 kV for many years while the infrastructure continues to develop.
Figure 12-9
Eklutna to Fossil Creek 230 kV Transmission Line (Upgrade)
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ALASKA RIRP STUDY
Black & Veatch 12-16 February 2010
Project I – Healy to Gold Hill 230 kV Transmission Line (Repair and Replacement - Category 1)
The existing Healy to Gold Hill 138 kV line was constructed and placed in service in 1968. This line serves
as one of two paths between Healy and Fairbanks and delivers firm and economy power to Fairbanks from the
Healy, Anchorage, and Kenai areas. In 2007, the GVEA Long Range Planning Study recommended that this
line be rebuilt in stages between 2017 and 2021. The study further recommended that this line should be
upgraded to 230 kV although it would initially be operated at 138 kV. When the transmission plan is
completed, the existing 138 kV line becomes the weak link in the transmission system and limits the ability to
import power into Fairbanks following the N-1 loss of the Northern Intertie. This project is required to meet
the GRETC concept of providing a reliable transmission system backbone throughout the Railbelt.
Figure 12-10 presents the proposed upgrade.
Figure 12-10
Healy to Gold Hill 230 kV Transmission Line (Repair and Replacement)
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ALASKA RIRP STUDY
Black & Veatch 12-17 February 2010
Project J – Healy to Wilson 230 kV Transmission Line (Upgrade - Category 2)
The existing Healy to Wilson line was constructed in 2005 at 230 kV and presently operated at 138 kV. To
increase the power transfer capability of the transmission system above its current limits, the line is required
to be operated at 230 kV. Operation of this line along with the Healy to Gold Hill line at 230 kV is a part of
the phased development of a reliable 230 kV backbone of transmission facilities. Figure 12-11 presents the
proposed upgrade.
Figure 12-11
Healy to Wilson 230 kV Transmission Line (Upgrade)
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ALASKA RIRP STUDY
Black & Veatch 12-18 February 2010
Project K – Soldotna to Diamond Ridge 115 kV Transmission Line (Repair and
Replacement - Category 1)
The Soldotna to Diamond Ridge 115 kV line serves several distribution substations on the Kenai from Ski
Hill, Kasilof, Anchor Point, Diamond Ridge, and Fritz Creek and as part of a transmission loop from Soldotna
Substation to Bradley Lake generation facility. The older of the two lines comprising the transmission loop is
in poor condition and has a very small conductor size. The small conductor size on this line segment results
in high impedance, high losses and limited capacity transfer over the line. Outage of the express Soldotna to
Bradley Lake 115 kV line results in low voltages and line overloads in the southern Kenai and restricts the
Bradley Lake project to an output of less than 60 MW in summer months. This proposed project will rebuild
the line with larger conductor at the existing transmission line voltage. Figure 12-12 presents the proposed
upgrade.
Figure 12-12
Soldotna to Diamond Ridge 115 kV Transmission Line (Repair and Replacement)
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Black & Veatch 12-19 February 2010
Project L – Lawing to Seward 115 kV Transmission Line (Upgrade - Category 1)
The City of Seward is served by a 115 kV line from Daves Creek on the Kenai to the Lawing substation. The
voltage is then stepped down to 69 kV and the line continues into the City of Seward. Most of the 69 kV line
section was replaced and upgraded to 115 kV insulation, but left to operate at 69 kV. Some distribution
stations and the short line to Spring Creek will need to be converted from 69 kV to 115 kV. The transmission
line runs primarily through the Department of Forestry lands with sections along the Alaska Railroad. The
City of Seward is a full-requirements customer of Chugach and has a winter peak load of approximately
10 MW. Figure 12-13 presents the proposed upgrade.
Figure 12-13
Lawing to Seward 115 kV Transmission Line (Upgrade)
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ALASKA RIRP STUDY
Black & Veatch 12-20 February 2010
Project M – Eklutna to Lucas (Hospital Substation) 115 kV/ 230 kV Transmission Line (Repair and
Replacement - Category 1)
The existing Eklutna to Lucas line was originally built as part of the Eklutna Project in 1955 and needs to be
rebuilt due to the age and condition of the line. The line requires upgrading or an additional line to meet the
requirements of the system over the life of this plan. The optimal construction of this project should be
determined in conjunction with the preferred generation plan. The deficiencies of the system can be
addressed in a number of different manners. An express 115 kV line similar to the Briggs–Eklutna line
eliminates low voltage conditions and provides reliability improvements to meet the GRETC requirements.
The express feeder should be insulated to 230 kV to serve as a possible tie to the Teeland station.
Alternatively, the existing line could be rebuilt at 230 kV converting all of the MEA substations to 230 kV, or
finally the express feeder could be built and operated at 230 kV with a corresponding 230 kV/115 kV
substation in the Lucas or Hospital Sub area. The final configuration of the project should be determined in
future studies following determination of the preferred generation plan. Figure 12-14 presents the proposed
project.
Figure 12-14
Eklutna to Lucas 230 kV Transmission Line (Repair and Replacement)
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Black & Veatch 12-21 February 2010
Project N – Lucas to Teeland 230 kV (115 kV) Transmission Line (Repair and
Replacement - Category 2)
The existing 115 kV Teeland to Lucas line serves several substations in the MEA area. This section of line is
subject to low voltages and load loss with the single contingency outage of the Teeland 230 kV/ 115 kV
transformer or the Teeland – Pt. MacKenzie 230 kV transmission line. The transmission contingency is
alleviated by the construction of Project E (Lake Loraine to Douglas 230 kV line), but the construction of this
line does not mitigate the loss of load and low voltage conditions experienced following the loss of the
Teeland Transformer. There is currently a 138 kV/115 kV transformer that serves as a emergency
replacement for the 230 kV/115 kV transformer, however, this transformer will be retired when the Intertie is
converted to 230 kV. In order to alleviate low voltage conditions and loss of load in the MEA area for
contingency operations, a new transmission line is required into the Lucas/Hospital Sub area of the MEA
territory. The optimum selection of the line and its construction and operating voltage requires more detailed
study than is possible in this analysis and will require coordination with other transmission projects and
generation alternatives. This project should be evaluated as part of future transmission planning studies.
Figure 12-15 presents the proposed replacement.
Figure 12-15
Lucas to Teeland 230 kV Transmission Line (Repair and Replacement)
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ALASKA RIRP STUDY
Black & Veatch 12-22 February 2010
Project O – Fossil Creek to Plant 2 230 kV Transmission Line (Upgrade - Category 2)
This section of line consists of a double circuit 230 kV constructed line , with one circuit operated at 230 kV
and one circuit currently being operated at 115 kV. This project is required to enhance the reliability of the
Anchorage and MEA areas. Operation of both circuits at 230 kV will require the construction of a
230 kV/115 kV substation at Fossil Creek and construction of a 230 kV line section from ML&P Plant 2 to
University station. Alternatively, it may be possible to install a second transformer at ML&P Plant 2 and
increase the transfer capacity of the AML&P 115 kV system. The exact configuration should be determined
in future studies. Figure 12-16 presents the proposed upgrade.
Figure 12-16
Fossil Creek to Plant 2 230 kV Transmission Line (Upgrade)
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ALASKA RIRP STUDY
Black & Veatch 12-23 February 2010
Project P – Pt. Mackenzie (Lorraine) to Plant 2 230 kV Transmission Line (Repair and
Replacement - Category 2)
The existing Pt. Mackenzie to Plant 2 transmission line consists of two sections of 230 kV overhead
transmission line and a section of underwater cable between the East Terminal and West Terminal stations.
The overhead line is in reasonably good condition but the submarine cable is expected to be in need of
replacement and repairs by 2025. At that time, the terminus of the transmission line will be Lorraine and
AML&P Plant 2 stations. This circuit is critical to the reliability of the Railbelt system and is, therefore,
scheduled as a GRETC replacement project. The project is presented in Figure 12-17.
Figure 12-17
Pt. Mackenzie to Plant 2 230 kV Transmission Line (Repair and Replacement)
SECTION 12 TRANSMISSION PROJECTS
ALASKA RIRP STUDY
Black & Veatch 12-24 February 2010
Project Q – Bernice Lake – Soldotna 115 kV Transmission Line (Rebuild - Category 2)
The 115 kV transmission line from Bernice Lake Power Plant to Soldotna Substation serves as the critical
link between the proposed Southern Intertie, the existing Kenai intertie and the Bradley Lake power plant.
The transmission line was constructed in 1971 and is expected to require significant reconstruction over the
life of this plan. Further study should be undertaken before this line is upgraded to determine if 230 kV
operation is required or is possible over the life of this plan. 230 kV operation will require significant
permitting and environmental effort and may not be warranted. The project is presented in Figure 12-18.
Figure 12-18
Bernice Lake to Soldotna 115 kV Transmission Line (Rebuild)
SECTION 12 TRANSMISSION PROJECTS
ALASKA RIRP STUDY
Black & Veatch 12-25 February 2010
Project R – Bernice Lake–Beaver Creek - Soldotna 115 kV Transmission Line (Rebuild - Category 2)
The existing 69 kV transmission line between Bernice Lake, Beaver Creek and Soldotna stations cannot be
operated in parallel with the 115 kV transmission line between Bernice Lake and Soldotna due to the limited
transfer capacity of the line and transient stability limitations. The 69 kV line is required to be upgraded to
115 kV to eliminate the single contingency loss of the existing 115 kV transmission line between Soldotna
and Bernice Lake. HEA has rebuilt portions of the 69 kV line to 115 kV construction and Marathon Station is
constructed to 115 kV construction.
The project consists of upgrading the remaining portions of the 69 kV line to 115 kV and modifications to the
stations at Bernice Lake, Beaver Creek and Soldotna. This line should not be considered for 230 kV
operation. The project is presented in Figure 12-19.
Figure 12-19
Bernice Lake to Beaver Creek to Soldotna 115 kV Transmission Line (Rebuild)
SECTION 12 TRANSMISSION PROJECTS
ALASKA RIRP STUDY
Black & Veatch 12-26 February 2010
12.6 Susitna
Project S – Susitna Transmission Additions (New Project - Category 3)
The Susitna transmission interconnection configuration will depend on the selected generation site at Susitna.
The Watana option consists of two 230 kV transmission lines connecting the Susitna substation to the new
230 kV Gold Creek substation, one transmission line from Sustina to Healy Substation, one additional 230 kV
transmission line from the Gold Creek substation south to the Douglas 230 kV substation, and one line
230 kV transmission line from Douglas to Pt. MacKenzie Substation. The Gold Creek substation is
approximately 33 miles from the Susitna substation and is the terminating point for the two 230 kV lines from
Susitna as well as a switching station for the Douglas to Healy tie lines and the connecting point for the Gold
Creek to Douglas 230 kV line that will transport power from the Susitna plant into the southern regions of the
Railbelt. The capital cost for the Susitna substation, the two 230 kV transmission lines from Susitna to Gold
Creek, and the Gold Creek substation are included in the capital cost for the Susitna projects. The capital cost
for the Douglas to Lake Lorraine 230 kV transmission line is included as the incremental cost making the
Douglas to Lake Lorraine 230 kV transmission line described in Project E a double circuit line. The Susitna to
Gold Creek lines and the Gold Creek to Douglas line are presented in Figure 12-20. The Douglas to Lake
Lorraine 230 kV transmission line is shown in Figure 12-6. Project S is not required if the Susitna project is
not constructed.
If the Devils Canyon site is selected, three lines between Susitna and Gold Creek are required; however, the
second Intertie between Gold Creek and Healy would replace the Susitna-Healy line.
Figure 12-20
Susitna to Gold Creek 230 kV Transmission Line
SECTION 12 TRANSMISSION PROJECTS
ALASKA RIRP STUDY
Black & Veatch 12-27 February 2010
12.7 Summary of Transmission Projects
The list of transmission projects is presented in Table 12-1, and their locations are shown in Figures 12-21
and 12-22. Table 12-1 also includes preliminary cost estimates for each of the listed projects. Note that this
list does not include a description of the associated distribution substations that would need to be upgraded to
accommodate the new voltage levels of the transmission projects. The cost of these projects are however
included in the total cost for each scenario and is also shown in the table below. While the details of GRETC
are not yet developed to a point that determines whether these distribution substations would be a part of the
GRETC system or part of the individual utilities distribution systems, they are a necessary cost resulting from
the development of the GRETC system and have been included in the economic evaluations. All the
transmission projects presented in this section were evaluated by a transmission load flow analysis to
determine how the Railbelt system performed with these projects along with the economic dispatch of the
selected generating resources in the RIRP.
Table 12-1
Summary of Proposed Transmission Projects
Project
No. Transmission Projects Type Cost ($000)
A Bernice Lake – International New Build (230 kV) 227,500
B Soldotna – Quartz Creek R&R (230 kV) 126,500
C Quartz Creek – University R&R (230 kV) 165,000
D Douglas – Teeland R&R (230 kV) 62,500
E Lake Lorraine – Douglas New Build (230 kV) 80,000
F Douglas – Healy Upgrade (230 kV) 30,000
G Douglas – Healy New Build (230 kV) 252,000
H Eklutna – Fossil Creek Upgrade (230 kV) 65,000
I Healy – Gold Hill R&R (230 kV) 180,500
J Healy – Wilson Upgrade (230 kV) 32,000
K Soldotna – Diamond Ridge R&R (115 kV) 66,000
L Lawing – Seward Upgrade (115 kV) 15,450
M Eklutna – Lucas R&R(115 kV/230 kV) 12,300
N Lucas – Teeland R&R (230 kV) 51,100
O Fossil Creek – Plant 2 Upgrade (230 kV) 13,650
P Pt. Mackenzie – Plant 2 R&R (230 kV) 32,400
Q Bernice Lake – Soldotna Rebuild (115 kV) 24,000
R Bernice Lake – Beaver Creek - Soldotna Rebuild (115 kV) 24,000
S Susitna Transmission Additions New Build (230 kV) 57,000
SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Black & Veatch 12-28 February 2010 Figure 12-21 Location of Proposed Transmission Projects (Without Susitna)
SECTION 12 TRANSMISSION PROJECTS ALASKA RIRP STUDY Black & Veatch 12-29 February 2010 Figure 12-22 Location of Proposed Transmission Projects (With Susitna)
SECTION 12 TRANSMISSION PROJECTS
ALASKA RIRP STUDY
Black & Veatch 12-30 February 2010
12.8 Other Reliability Projects
In addition to the transmission lines presented in this section, other projects were considered that could
contribute to improving the reliability of the Railbelt system. These projects generally fall into one or more
of the following categories:
• Providing reactive power (static var compensators – SVCs)
• Providing or assisting with the provision of other ancillary services (regulation and/or spinning
reserves)
• Assistance in control of line flows or substation voltages
• Assistance in the transition and coordination of transmission project implementation (mobile
transformers or substations)
• Communications and control facilities
Several of these projects have been identified and discussed while others will result from the transmission
reliability assessment. Potential projects in this category include:
• Substation capacitor banks
• Series capacitors
• SVCs
• BESS
• Mobile substations that could provide construction flexibility during the implementation phase
Many of the projects listed will be proposed and reviewed during the reliability evaluation phase, while others
may be identified only when more detailed design and specification of the transmission projects are
undertaken. Where preliminary information indicates that these projects will be required as part of the
projects identified above, their estimated costs have been included in the project cost in Table 12-1. The cost
for any additional projects will be developed during the reliability analysis conducted as part of the
implementation.
The Railbelt system currently has several SVCs deployed across the system to assist in the operation of the
system and to assist in the stable transfer of power between areas. These were installed several years ago and
are considered critical to the stable operation of the system. Further analysis of the projects outlined in
Section 12.5 is expected to result in potential changes to these projects, as well as a requirement for several
more SVCs at locations to be identified by the stability analysis. Additionally, the currently deployed SVCs
are in need of repairs if they are to continue in service and provide the reliability functions they were designed
to provide. It is estimated that the repair or replacement of these existing SVCs would cost a total of
approximately $25 million.
Projects that could facilitate or complement the implementation of other projects (e.g., wind) were of
particular interest during project discussions. These projects, if implemented, could smooth the transition and
adoption by the utilities of the GRETC concept. One such project was the BESS that could provide much
needed frequency regulation and potentially some spinning reserves when non dispatchable projects, such as
wind, are considered. Specific stability and regulation studies will be required to determine the best methods
of integrating the wind generation.
A BESS was specified that could provide frequency regulation required by the system when wind projects
were selected by the RIRP. The BESS was sized in relation to the size of the non-dispatchable project to be
50 percent of the project nominal capacity for a 20-minute duration. For evaluation purposes, a 27 MW
BESS which would provide 50 percent of 54 MW Fire Island project is estimated to cost approximately
$50 million. Although the performance of the BESS has not yet been analyzed as part of the stability
SECTION 12 TRANSMISSION PROJECTS
ALASKA RIRP STUDY
Black & Veatch 12-31 February 2010
analysis, the cost for the system was included in the analysis in Section 13. Other options (e.g., fly wheel
storage technologies and compressed air energy storage) that could provide the required frequency regulation
should also be considered.
It should be noted that if the need for frequency regulation is driven in part by an IPP-sponsored renewable
project, policies will need to be adopted to allocate an appropriate portion of the regulation costs to those
projects.
The GRETC system will require upgrades to the communication and control systems of the existing facilities
in order to operate as a unified grid. Communication for pilot relaying between Anchorage and Fairbanks as
well as communication upgrades to the Anchorage – Kenai system will be required for protective relaying and
control. The individual utilities have their own communication and control systems. The alternatives and
costs for implementing the necessary communication and control systems for GRETC operation were
discussed in the REGA study. Those costs which are considered necessary administrative costs for
implementing GRETC are not included in the costs in Table 12-1.
12.9 Projects Priorities
The proposed projects presented in Section 12.5 are not presented in any specific order or priority. It was felt
that the information currently available, as well as the uncertainty which exists surrounding the selected
generation plans, did not permit a more definitive prioritization of projects. This does not mean, however, that
all the projects in the list have the same impact on the reliability of the Railbelt system, or that the projects are
equally important to each utility. In several instances the projects were in extremely poor physical condition
and were scheduled to be repaired or rebuilt to prevent the lines from literally falling to the ground. To
facilitate the immediate repairs to these lines, the projects that should be addressed within the next five years
because of their potential impact on the reliability of the system have been identified. Additionally, some of
the projects will need to be evaluated and specified further and funds have been identified to facilitate the
studies that are required to further identify and schedule the transmission improvements that will be required.
The following projects and studies have been identified for priority attention because of their immediate
impact on the reliability of the existing system. All of the projects will require detailed system feasibility
studies prior to actual implementation. Estimated costs for these studies are included as part of the project
costs estimates in Table 12-1. The following projects are estimated to be required within the next five years.
1. Soldotna to Quartz Creek Transmission Line ($126.5 million – Project B)
2. Quartz Creek to University Transmission Line ($165.0 million – Project C)
3. Douglas to Teeland Transmission Line ($62.5 million – Project D)
4. Lake Lorraine to Douglas Transmission Line ($80.0 million – Project E)
5. SVCs ($25.0 million - Other Reliability Projects)
6. Funds to undertake the study of the Southern Intertie ($1.0 million)
7. Funds to investigate the provision of regulation that will facilitate the integration of renewable energy
projects into the Railbelt system ($50.0 million, including cost of BESS – Other Reliability Projects)
The total estimate costs necessary for transmission projects during the initial five years of the RIRP is
$510 million in 2009 dollars.
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-1 February 2010
13.0 SUMMARY OF RESULTS
The purpose of this section is to summarize the results of the RIRP analysis. We begin by providing a
summary of the reference case results for each of the four Evaluation Scenarios, followed by a summary of
the results for the various sensitivity cases that were evaluated. We then provide a comparative summary of
the economic and emission results for all cases. This is followed by a summary of the results of the
transmission analysis that was completed and, finally, the results of the financial analysis.
13.1 Results of Reference Cases
In this subsection, we provide summaries of the reference case results for each of the following four
Evaluation Scenarios:
• Scenario 1A – Base Case Load Forecast – Least Cost Plan
• Scenario 1B - Base Case Load Forecast – Force 50% Renewables
• Scenario 2A – Large Growth Load Forecast – Least Cost Plan
• Scenario 2B - Large Growth Load Forecast – Force 50% Renewables
Our analysis shows that Scenarios 1A and 1B result in the same resources and, consequently, the same costs
and emissions. In other words, the cost of achieving a renewable energy target of 50 percent by 2025
(Scenario 1B) is no greater than the cost of the unconstrained solution (Scenario 1A). This result applies only
if a large hydroelectric project is built. Hereafter, we will refer to Scenarios 1A and 1B together.
We begin with a summary of the impact that DSM/EE measures have on the region’s capacity and annual
energy requirements. This is followed by summary graphics and information for each of the Evaluation
Scenarios. Additional summary information on the results of each reference case is provided at the end of this
section. Detailed model output for each of the reference cases are provided in Appendices E-G.
13.1.1 Results - DSM/EE Resources
As discussed in Section 11, Black & Veatch screened a broad array of residential and commercial DSM/EE
measures. Based on this screening, 21 residential and 51 commercial DSM/EE measures were selected for
inclusion in the RIRP models, Strategist® and PROMOD®, as potential resources to be selected.
Based upon the relative economics and savings of these screened residential and commercial DSM/EE
measures, from the utility perspective, all of the residential and commercial DSM/EE measures were selected
in each of the four Evaluation Scenarios. As discussed in Section 11, the penetration of the measures was
based on technology adoption curves for DSM/EE studies from the BASS model; additionally, as discussed,
DSM/EE measures are treated by Strategist® and PROMOD® as a reduction to the load forecast from which
the alternative supply-side options are considered for adding generation resources.
Since the maximum allowed level of DSM/EE resources were selected in each of the four Evaluation
Scenarios, we summarize the resulting impact on the Base Case Load Forecast for Scenario 1A in the
following graphic.
As can be seen in Figure 13-1, DSM/EE measures result in a significant impact on the region’s capacity and
energy requirements. After the initial program start-up years, DSM/EE measures reduce the region’s capacity
requirements by approximately 8 percent. A similar level of impact is also shown for annual energy
requirements.
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-2 February 2010
Figure 13-1
Impact of DSM/EE Resources – Base Case Load Forecast
Demand (MW)
0
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800
1,000
1,200
1,400
20112014201720202023202620292032203520382041204420472050205320562059YearDemand (MW)Without DSM/EE
With DSM/EE
Energy Requirements (MWh)
0
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8,000,000
20112014201720202023202620292032203520382041204420472050205320562059YearEnergy Requirements (MWh)Without DSM/EE
With DSM/EE
It should be noted that this study did not include an evaluation of innovative rate designs (e.g., real-time
pricing and demand response rates), nor did it consider the potential benefits of a Smart Grid and the
associated widespread implementation of smart meters. These options could result in even greater reductions
in peak demand and annual energy usage.
13.1.2 Results - Scenarios 1A/1B Reference Cases
Figure 13-2
Results – Scenarios 1A/1B Reference Cases
Capacity By Resource Type
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SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-3 February 2010
13.1.3 Results - Scenario 2A Reference Case Results
Figure 13-3
Results – Scenario 2A Reference Case
Capacity By Resource Type
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13.1.4 Results - Scenario 2B Reference Case Results
Figure 13-4
Results – Scenario 2B Reference Case
Capacity By Resource Type
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13.2 Results of Sensitivity Cases
In this subsection, we list the various sensitivity cases that were evaluated. We then provide graphics that
summarize the results for each sensitivity case. Additional summary information on the results of each
sensitivity case is provided at the end of this section.
13.2.1 Sensitivity Cases Evaluated
• Scenarios 1A/1B Without DSM/EE Measures
• Scenarios 1A/1B With Double DSM/EE Measures
• Scenarios 1A/1B With Committed Units Included
• Scenarios 1A/1B Without CO2 Costs
• Scenarios 1A/1B With Higher Gas Prices
• Scenarios 1A/1B Without Chakachamna
• Scenarios 1A/1B With Chakachamna Capital Costs Increased by 75%
• Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option) Forced
• Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option) Forced
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-4 February 2010
• Scenarios 1A/1B With Susitna (Low Watana Expandable Option) Forced
• Scenarios 1A/1B With Susitna (Low Watana Expansion Option) Forced
• Scenarios 1A/1B With Susitna (Watana Option) Forced
• Scenarios 1A/1B With Susitna (High Devil Canyon Option) Forced
• Scenarios 1A/1B With Modular Nuclear
• Scenarios 1A/1B With Tidal
• Scenarios 1A/1B With Lower Coal Capital and Fuel Costs
• Scenarios 1A/1B With Federal Tax Credits for Renewables
13.2.2 Sensitivity Results – Scenarios 1A/1B Without DSM/EE Measures
Figure 13-5
Sensitivity Results – Scenarios 1A/1B Without DSM/EE Measures
Capacity By Resource Type
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13.2.3 Sensitivity Results – Scenarios 1A/1B With Double DSM/EE Measures
Figure 13-6
Sensitivity Results – Scenarios 1A/1B With Double DSM/EE Measures
Capacity By Resource Type
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SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-5 February 2010
13.2.4 Sensitivity Results – Scenarios 1A/1B With Committed Units Included
Figure 13-7
Sensitivity Results – Scenarios 1A/1B With Committed Units Included
Capacity By Resource Type
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13.2.5 Sensitivity Results – Scenarios 1A/1B Without CO2 Costs
Figure 13-8
Sensitivity Results – Scenarios 1A/1B Without CO2 Costs
Capacity By Resource Type
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SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-6 February 2010
13.2.6 Sensitivity Results – Scenarios 1A/1B With Higher Gas Prices
Figure 13-9
Sensitivity Results – Scenarios 1A/1B With Higher Gas Prices
Capacity By Resource Type
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13.2.7 Sensitivity Results – Scenarios 1A/1B Without Chakachamna
Figure 13-10
Sensitivity Results – Scenarios 1A/1B Without Chakachamna
Capacity By Resource Type
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13.2.8 Sensitivity Results – Scenarios 1A/1B With Chakachamna Capital Costs Increased
by 75%
When Chakachamna’s capital costs are increased by 75 percent, it is no longer selected as a resource in the
resource plan. As a result, the results of this sensitivity case are the same as the Scenario 1A Without
Chakachmna Sensitivity Case above. Consequently, the resulting breakdown of capacity and energy
generated by resource type is the same as the graphs shown in Figure 13-10.
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-7 February 2010
13.2.9 Sensitivity Results – Scenarios 1A/1B With Susitna (Lower Low Watana Non-
Expandable Option) Forced
Figure 13-11
Sensitivity Results – Scenarios 1A/1B With Susitna (Lower Low Watana Non-Expandable Option)
Forced
Capacity By Resource Type
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13.2.10 Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana Non-Expandable
Option) Forced
Figure 13-12
Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana Non-Expandable Option) Forced
Capacity By Resource Type
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13.2.11 Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana Expandable
Option) Forced
In this sensitivity case, we forced the Susitna (Low Watana Expandable Option) to be selected, in a similar
manner to the Susitna (Low Watana Non-Expandable Option) Sensitivity Case immediately above.
Consequently, the resulting breakdown of capacity and energy generation by resource type is the same as the
graphs shown in Figure 13-12. However, the total cumulative prevent value, average unit cost, and total
capital requirements for this sensitivity case are higher; this results from the fact that the only difference
between this and the Susitna (Low Watana Non-Expandable Option) Sensitivity Case is that capital costs
associated with this option are $400 million higher to preserve the option of future expansion.
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-8 February 2010
13.2.12 Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana Expansion Option)
Forced
Figure 13-13
Sensitivity Results – Scenarios 1A/1B With Susitna (Low Watana Expansion Option) Forced
Capacity By Resource Type
0
500
1000
1500
2000
2500
20112014201720202023202620292032203520382041204420472050205320562059Capacity (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
1000
2000
3000
4000
5000
6000
7000
20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
13.2.13 Sensitivity Results – Scenarios 1A/1B With Susitna (Watana Option) Forced
Figure 13-14
Sensitivity Results – Scenarios 1A/1B With Susitna (Watana Option) Forced
Capacity By Resource Type
0
500
1000
1500
2000
2500
3000
20112014201720202023202620292032203520382041204420472050205320562059Capacity (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
1000
2000
3000
4000
5000
6000
7000
20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-9 February 2010
13.2.14 Sensitivity Results – Scenarios 1A/1B With Susitna (High Devil Canyon Option)
Forced
Figure 13-15
Sensitivity Results – Scenarios 1A/1B With Susitna (High Devil Canyon Option) Forced
Capacity By Resource Type
0
500
1000
1500
2000
2500
20112014201720202023202620292032203520382041204420472050205320562059Capacity (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
1000
2000
3000
4000
5000
6000
7000
20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
13.2.15 Sensitivity Results – Scenarios 1A/1B With Modular Nuclear
Figure 13-16
Sensitivity Results – Scenarios 1A/1B With Modular Nuclear
Capacity By Resource Type
0
200
400
600
800
1000
1200
1400
1600
1800
2000
20112014201720202023202620292032203520382041204420472050205320562059Capacity (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
1000
2000
3000
4000
5000
6000
7000
20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-10 February 2010
13.2.16 Sensitivity Results – Scenarios 1A/1B With Tidal
Figure 13-17
Sensitivity Results – Scenarios 1A/1B With Tidal
Capacity By Resource Type
0
200
400
600
800
1000
1200
1400
1600
1800
2000
20112014201720202023202620292032203520382041204420472050205320562059Capacity (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
1000
2000
3000
4000
5000
6000
7000
20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
13.2.17 Sensitivity Results – Scenarios 1A/1B With Lower Coal Capital and Fuel Costs
Figure 13-18
Sensitivity Results – Scenarios 1A/1B With Lower Coal Capital and Fuel Costs
Capacity By Resource Type
0
200
400
600
800
1000
1200
1400
1600
1800
2000
20112014201720202023202620292032203520382041204420472050205320562059Capacity (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
1000
2000
3000
4000
5000
6000
7000
20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
13.2.18 Sensitivity Results – Scenarios 1A/1B With Federal Tax Credits for Renewables
Figure 13-19
Sensitivity Results – Scenarios 1A/1B With Federal Tax Credits for Renewables
Capacity By Resource Type
0
200
400
600
800
1000
1200
1400
1600
1800
2000
20112014201720202023202620292032203520382041204420472050205320562059Capacity (MW)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
Energy By Resource Type
0
1000
2000
3000
4000
5000
6000
7000
20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal
Wind
Municipal Solid Waste
Geothermal
Hydro
Purchase Power
Fuel Oil
Nuclear
Coal
Natural Gas
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-11 February 2010
13.3 Summary of Results
In this subsection, we provide a comparative summary of the economic and emissions results for all of the
reference and sensitivity cases.
13.3.1 Summary of Results - Economics
Table 13-1 summarizes the economic results, including:
• Cumulative present value cost (from the utility perspective)
• Average wholesale power cost (from the utility perspective)
• Renewable energy in 2025
• Total capital investment
13.3.2 Summary of Results - Emissions
Table 13-2 summarizes the emissions-related results of all of the reference and sensitivity cases. The
following information is provided for each case:
• CO2 emissions
• NOx emissions
• SOx emissions
13.4 Results of Transmission Analysis
An important element of this RIRP was the analysis of transmission investments required to integrate the
generation resources in each resource plan, ensure reliability and enable the region to take advantage of
economy energy transfers between load areas within the region.
The fundamental objective underlying the transmission analysis was to upgrade the transmission system over
a 10-year period to remove transmission constraints that currently prevent the coordinated operation of all the
utilities as a single entity.
The study included all the utilities' assets 69 kV and above. These assets, over a transition period, may flow
into GRETC and form the basis for a phased upgrade of the system into a robust, reliable transmission system
that can accommodate the economic operation of the interconnected system. The transmission analysis also
assumed that all utilities would participate in GRETC with planning being conducted on a GRETC
(i.e., regional) basis. The common goal would be the tight integration of the system operated by GRETC.
Potential transmission investments in each of the following four categories were considered:
• Transmission systems that need to be replaced because of age and condition (Category 1)
• Transmission projects required to improve grid reliability, power transfer capability, and reserve
sharing (Category 2)
• Transmission projects required to connect new generation projects to the grid (Category 3)
• Transmission projects to upgrade the grid required by a new generation project (Category 4)
Table 13-3 lists the recommended transmission system expansions and enhancements that resulted from our
transmission analysis. Detailed information on each of the transmission projects listed in the following table is
provided in Section 12.
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-12 February 2010
Table 13-1
Summary of Results – Economics
Case
Cumulative
Present Value
Cost
($000,000)
Average
Wholesale
Power Cost
(¢ per kWh)
Renewable
Energy in
2025
(%)
Total Capital
Investment
($000,000)
Scenarios
Scenario 1A $13,625 17.26 62.32% $9,087
Scenario 1B $13,625 17.26 62.32% $9,087
Scenario 2A $20,162 19.75 42.64% $14,111
Scenario 2B $21,109 20.68 65.83% $18,805
Sensitivities
1A/1B Without DSM/EE Measures $14,507 17.40 67.10% $8,603
1A/1B With Double DSM $12,546 15.89 65.15% $8,861
1A/1B With Committed Units Included $14,109 17.87 46.84% $8,090
1A/1B Without CO2 Costs $11,206 14.20 49.07% $8,381
1A/1B With Higher Gas Prices $14,064 17.82 61.95% $9,248
1A/1B Without Chakachamna $14,332 18.16 38.06% $7,719
1A/1B With Chakachamna Capital Costs
Increased by 75%
$14,332 18.16 38.06% $7,719
1A/1B With Susitna (Lower Low Watana
Non-Expandable Option) Forced
$15,228 19.29 61.01% $12,421
1A/1B With Susitna (Low Watana Non-
Expandable Option) Forced
$15,040 19.05 63.01% $15,057
1A/1B With Susitna (Low Watana
Expandable Option) Forced
$15,346 19.44 63.01% $15,588
1A/1B With Susitna (Low Watana
Expansion Option) Forced
$14,854 18.82 66.90% $14,069
1A/1B With Susitna (Watana Option) Forced $15,683 19.87 70.97% $13,211
1A/1B With Susitna (High Devil Canyon
Option) Forced
$14,795 18.74 66.92% $11,633
1A/1B With Modular Nuclear $13,841 17.53 60.51% $9,105
1A/1B With Tidal $13,712 17.37 65.52% $9,679
1A/1B With Lower Coal Fuel and Lower
Coal Capital Costs
$13,625 17.26 62.32% $9,087
1A/1B With Tax Credits for Renewables $12,954 16.41 67.56% $9,256
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-13 February 2010
Table 13-2
Summary of Results – Emissions
Case
CO2
('000 tons)
NOx
('000 tons)
SO2
('000 tons)
Scenarios
Scenario 1A 80,259,047 124,215 21,768
Scenario 1B 80,259,047 124,215 21,768
Scenario 2A 152,318,066 133,642 24,476
Scenario 2B 125,498,202 140,897 26,348
Sensitivities
1A/1B Without DSM/EE Measures 88,181,350 139,179 30,605
1A/1B With Double DSM 69,324,920 131,299 18,994
1A/1B With Committed Units Included 91,212,598 136,946 16,482
1A/1B Without CO2 Costs 100,753,030 134,031 23,960
1A/1B With Higher Gas Prices 78,323,066 121,700 25,232
1A/1B Without Chakachamna 105,643,650 133,577 25,700
1A/1B With Chakachamna Capital Costs Increased by 75% 105,643,650 133,577 25,700
1A/1B With Susitna (Lower Low Watana Non-Expandable
Option) Forced
82,328,762 127,921 22,124
1A/1B With Susitna (Low Watana Non-Expandable Option)
Forced
69,133,553 124,640 19,620
1A/1B With Susitna (Low Watana Expandable Option) Forced 69,133,553 124,640 19,620
1A/1B With Susitna (Low Watana Expansion Option) Forced 67,724,563 136,906 23,589
1A/1B With Susitna (Watana Option) Forced 70,966,059 111,307 19,171
1A/1B With Susitna (High Devil Canyon Option) Forced 71,853,368 121,538 19,909
1A/1B With Modular Nuclear 79,664,701 126,881 22,787
1A/1B With Tidal 75,598,948 121,306 21,067
1A/1B With Lower Coal Fuel and Lower Coal Capital Costs 80,259,047 124,215 21,768
1A/1B With Tax Credits for Renewables 74,046,352 129,384 18,832
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-14 February 2010
Table 13-3
Summary of Proposed Transmission Projects
Project
No. Transmission Projects Type Cost ($000)
A Bernice Lake – International New Build (230 kV) 227,500
B Soldotna – Quartz Creek R&R (230 kV) 126,500
C Quartz Creek – University R&R (230 kV) 165,000
D Douglas – Teeland R&R (230 kV) 62,500
E Lake Lorraine – Douglas New Build (230 kV) 80,000
F Douglas – Healy Upgrade (230 kV) 30,000
G Douglas – Healy New Build (230 kV) 252,000
H Eklutna – Fossil Creek Upgrade (230 kV) 65,000
I Healy – Gold Hill R&R (230 kV) 180,500
J Healy – Wilson Upgrade (230 kV) 32,000
K Soldotna – Diamond Ridge R&R (115 kV) 66,000
L Lawing – Seward Upgrade (115 kV) 15,450
M Eklutna – Lucas R&R(115 kV/230 kV) 12,300
N Lucas – Teeland R&R (230 kV) 51,100
O Fossil Creek – Plant 2 Upgrade (230 kV) 13,650
P Pt. Mackenzie – Plant 2 R&R (230 kV) 32,400
Q Bernice Lake – Soldotna Rebuild (115 kV) 24,000
R Bernice Lake – Beaver Creek - Soldotna Rebuild (115 kV) 24,000
S Susitna Transmission Additions New Build (230 kV) 57,000
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-15 February 2010
The following issues result from our transmission analysis:
• We were unable to complete a stability analysis based upon our proposed transmission system
configuration prior to the completion of this project. This analysis is required to ensure that the
proposed transmission system expansions and enhancements result in the necessary stability to ensure
reliable electric service over the planning horizon. This analysis should be completed as part of the
future work to further define, prioritize, and design specific transmission projects.
• In addition to the transmission lines listed above, other projects were considered that could contribute
to improving the reliability of the Railbelt system. These projects generally fall into one or more of
the following categories:
o Providing reactive power (static var compensators – SVCs)
o Providing or assisting with the provision of other ancillary services (regulation and/or spinning
reserves)
o Assistance in control of line flows or substation voltages
o Assistance in the transition and coordination of transmission project implementation (mobile
transforms or substations)
o Communications and control facilities
Several of these projects have been identified and discussed while others will result from the
transmission reliability assessment. Potential projects in this category include:
o Substation capacitor banks
o Series capacitors
o SVCs
o BESS
o Mobile substations that could provide construction flexibility during the implementation phase
• Projects that could facilitate or complement the implementation of other projects (e.g., wind), were of
particular interest during project discussions. These projects, if implemented, could smooth the
transition and adoption by the utilities of the GRETC concept. One such project was the BESS that
could provide much needed frequency regulation and potentially some spinning reserves when
non-dispatchable projects, such as wind, are considered. A BESS was specified that could provide
frequency regulation required by the system when wind projects were selected by the RIRP. The
BESS was sized in relation to the size of the non-dispatchable project to be 50 percent of the project
nominal capacity for a 20-minute duration. Although the performance of the BESS has not yet been
analyzed as part of the stability analysis, the costs for each such system were included in the analysis.
Other options (e.g., fly wheel storage technologies and compressed air energy storage) that could
provide the required frequency regulation should also be considered.
• The Fire Island Wind Project is a 54 MW maximum output wind project. Each wind turbine will be
equipped with reactive power and voltage support capabilities that should facilitate interconnection
into the transmission grid. Current plans are to interconnect the project to the grid via a 34.5 kV
underground and submarine cable to the Chugach 34.5 kV Raspberry Substation. There has been
some discussions regarding the most appropriate transmission interconnection for the Fire Island
Project and detailed interconnection studies have not been completed. The timeframe for
implementing this project in order to qualify for available grants under the ARRA could preclude
more detailed transmission studies and consideration of alternatives to the currently proposed 34.5 kV
interconnection. An option to consider if Fire Island is constructed is to lay cables from Fire Island to
Anchorage insulated for 230 kV and review a transmission routing for the new transmission
connection to the Kenai peninsula that would begin at the International 230 kV Substation to Bernice
Lake Substation along the Kenai cost line then via submarine cable across the Cook Inlet to Fire
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-16 February 2010
Island. The interconnection would then use the 230 kV submarine cable previously laid over to the
Anchorage coast then into the International 230 kV Substation.
• The recommended transmission system expansions and enhancements can not be justified based
solely on economics. However, in addition to their underlying economics, these transmission projects
are required to ensure the reliable delivery of electricity throughout the region over the 50-year
planning horizon and to provide the foundation for future economic development efforts.
13.5 Results of Financial Analysis
It will be difficult for the region to obtain the necessary financing for the DSM/EE, generation and
transmission resources included in the alternative resource plans that were developed. The formation of a
regional entity with some form of State assistance will help meet this challenge.
Figure 13-20 summarizes the cumulative capital investment required for each of the reference cases.
Figure 13-20
Required Cumulative Capital Investment for Each Reference Case
Cumulative Capital Investment
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
$14,000,000
$16,000,000
$18,000,000
$20,000,000
2011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059YearCumulative Capital Investment ($000)Scenario 1A/1B
Scenario 2A
Scenario 2B
To assist in the completion of the financial analysis, the AEA contracted with SNW to:
• Provide a high-level analysis of the capital funding capacity of each of the Railbelt utilities.
• Analyze strategies to capitalize selected RIRP assets by integrating State (which could include loans,
State appropriations, Permanent Fund, State moral obligation bonds, etc.) and federal (e.g., USDA-
RUS) financing resources with debt capital market resources.
• Develop a spreadsheet model that utilizes inputs from this RIRP analysis and overlays realistic debt
capital funding to provide a total cost to ratepayers of the optimal resource plan.
The results of the financial analysis completed by SNW are provided in Appendix B.
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-17 February 2010
Important conclusions from SNW’s report include:
• The scope of the RIRP projects is too great, and for certain individual projects, it is reasonable to
conclude that there is no ability for a municipality or cooperative utility to independently secure debt
financing without committing substantial amounts of equity of cash reserves.
• Figure 13-21 helps to put into context the scope of the required RIRP capital investments relative to
the estimated combined debt capacity of the Railbelt utilities. The lines toward the bottom of the
graph represent SNW’s estimate of the bracketed range of additional debt capacity collectively for the
Railbelt utilities, adjusted for inflation and customer growth over time.
Figure 13-21
Required Cumulative Capital Investment (Scenarios 1A/1B) Relative to Railbelt Utility Debt Capacity
Source: SNW Report included in Appendix C.
• A regional entity, such as GRETC, with “all outputs” contracts migrating over time to “all
requirements” contracts will have greater access to capital than the combined capital capacity of the
individual utilities.
• There are several strategies that could be employed to lower the RIRP-related capital costs to
customers, including:
o Ratepayer Benefits Charge – A charge levied on all ratepayers within the Railbelt system that
would be used to cash fund and thereby defer borrowing for infrastructure capital.
o “Pay-Go” Versus Borrowing for Capital – A pay-go financing structure minimizes the total
cost of projects through the reduction in interest costs. A “pay-go” capital financing program is
one in which ongoing capital projects are paid for from remaining revenue after O&M expenses
and debt service are paid for. A balance of these two funding approaches appears to be the most
effective in lowering the overall cost of the RIRP, as well as spreading out the costs over a longer
period of time.
o Construction Work in Progress (CWIP) – CWIP is a rate methodology that allows for the
recovery of interest expense on project construction expenditures through the base rate during
construction, rather than capitalizing the interest until the projects are on-line and generating
power. It should be noted that this rate methodology is sometimes criticized for shifting risks
from shareholders to ratepayers; however, in the case of a public cooperative or municipal utility,
the “shareholders” are the ratepayers.
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-18 February 2010
o State Financial Assistance – State financial assistance could take a variety of forms as
previously noted; for the purposes of this project, SNW focused on State assistance structured
similarly to the Bradley Lake project. The benefits of State funding include: repayment
flexibility, credit support/risk mitigation, and potential interest cost benefit.
It should be noted that the economic comparison of resource options (using Strategist™ and
PROMOD™) does not assume any of these financing strategies, including any State grants or
loans, or federal tax credits, with the exception of the Federal Tax Credit for Renewables
Sensitivity Case.
• The overall objective of SNW’s analysis was to identify ways to overcome the funding challenges
inherent with large-scale projects, including the length of construction time before the project is
online and access to the capital markets, and to develop strategies that could be used to produce
equitable rates over the useful life of the assets being financed. With these challenges in mind, SNW
developed separate versions of its model to capture the cost of financing under a “base case” scenario
and an “alternative” scenario. The base case financing model was structured such that the list of
RIRP projects during the first 20 years would be financed through the capital markets in advance of
construction and that the cost of the financing in the form of debt service on the bonds, would
immediately be passed through to the ratepayers; the projects being financed over the balance of the
50-year period would be financed through cash flow created through normal rates and charges
(“pay-go”) capital once debt service coverage from previous years has grown to levels that create
cash flow balance amounts sufficient to pay for the projects as their construction costs come due. The
alternative model was developed with the goal of minimizing the rate shock that may otherwise occur
with such a large capital plan, and levelizing the rate over time so that the economic burden derived
from these projects can be spread more equitably over the useful life of the projects being
contemplated.
• In both the base and alternative cases, SNW transferred the excess operating cash flow that is
generated to create the debt service coverage level, and used that balance to both partially fund the
capital projects in the early years and almost fully fund the projects in the later years. In the
alternative case, SNW also included: 1) a Capital Benefits Surcharge ($0.01 per kWH) over the first
17 years, when approximately 75 percent of the capital projects will have been constructed, and
2) State assistance as an equity participant, structured in a manner similar to the Bradley Lake
financing model (SNW assumed that the State would provide a $2.4 billion zero-interest loan to
GRETC to provide the upfront funding for the Chakachamna project, only to be paid back by GRETC
out of system revenues over an extended period of time, and following the repayment of the
potentially more expensive capital markets debt).
• Under the base case, the maximum fixed charge rate on the capital portion alone is estimated to cost
$0.13 per kWH, while the average fixed charge rate over the 50-year period is $0.07 per kWh.
• In the alternative case, the maximum fixed charge rate on the capital portion alone is estimated to cost
$0.08 per kWH, while the average fixed charge rate over the 50-year period is $0.06 per kWh, not
including the $0.01 consumer benefit surcharge that is in place for the first 17 years.
• While the average rates between the two cases are essentially the same, the maximum rate in the
alternative case is much lower, showing the ability of innovative financing tools and ratemaking
methodologies to overcome the funding challenges and produce equitable rates over the 50-year
period.
• The formation of a regional entity, such as GRETC, that would combine the existing resources and
rate base of the Railbelt utilities, as well as provide an organized front in working to obtain private
financing and the necessary levels of State assistance, would be, in SNW’s opinion, a necessary next
step towards achieving the goal of reliable energy for the Railbelt region now and in the future.
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-19 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $13,624,595
2013 Anchorage 1x1 6FA
2014 Glacier Fork
2015 Anchorage MSW
2016
2017 GVEA MSW 62.32%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $9,086,710
2023
2024
2025 Chakachamna
2026
2027
2028
2029
2030 Kenai Hydro
2031
2032
2033
2034
2035
2036
2037 GVEA LMS100
2038
2039
2040
2041
2042 GVEA 1x1 6FA
2043
2044
2045
2046 Anchorage LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 GVEA LMS100
2058
2059
2060
Plan 1A/1B
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-20 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $20,162,223
2013
2014
Glacier Fork
Anchorage MSW
2015 Anchorage 1x1 6FA
2016
2017 Kenai Wind 42.64%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $14,110,777
2023
2024
2025
Anchorage 2x1 6FA
Anchorage LM6000
Chakachamna
2026
2027
2028
2029
2030
GVEA 2x1 6FA
GVEA Wind
2031
2032
2033
2034
2035
2036
2037 GVEA LMS100
2038
2039
2040
Anchorage 2x1 6FA
GVEA 1x1 6FA
GVEA 2x1 6FA
2041
2042 GVEA Wind
2043
2044
2045
2046 GVEA Wind
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 HEA LMS100
2058
2059
2060 HEA LM6000
Plan 2A
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-21 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $21,108,823
2013
2014
Glacier Fork
Anchorage MSW
2015 Anchorage 1x1 6FA
2016
2017 Kenai Wind 65.83%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $18,804,578
2023
2024
2025
Chakachamna
GVEA Wind
Low Watana (Non-Expandable)
2026
2027
2028
2029
2030 GVEA Wind
2031
2032
2033
2034
2035
2036
2037
Anchorage 2x1 6FA
Kenai Wind
2038
2039
2040
Anchorage 2x1 6FA
Kenai Wind
GVEA 2x1 6FA
2041
2042 GVEA Wind
2043
2044
2045
2046 GVEA LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 Anchorage LMS100
2058
2059
2060
Plan 2B
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-22 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $14,506,801
2013 Anchorage 1x1 6FA
2014
2015 Kenai Wind
2016
2017 GVEA MSW 67.10%
2018
Chakachamna
Glacier Fork
2019
2020 Anchorage MSW
2021 Mount Spurr
2022 Mount Spurr $9,791,215
2023
2024
2025 GVEA 1X1 NPole Retrofit
2026
2027
2028
2029
2030 Anchorage 2x1 6FA
2031
2032
2033
2034
2035
2036
2037 GVEA LM6000
2038
2039
2040
2041
2042 Anchorage LMS100
2043
2044
2045
2046 GVEA LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 GVEA 1x1 6FA
2058
2059
2060
1A/1B Without DSM/EE Measures
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-23 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $12,545,859
2013
2014 Anchorage MSW
2015 Anchorage 1x1 6FA
2016
2017 Glacier Fork 65.15%
2018 Mount Spurr
2019
2020 Mount Spurr
2021 GVEA 1X1 NPole Retrofit
2022 Anchorage LMS100 $8,860,649
2023
2024
2025
GVEA MSW
Chakachamna
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037 GVEA LMS100
2038
2039
2040
2041
2042 GVEA 1x1 6FA
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055 GVEA LMS100
2056
2057
2058
2059
2060 HEA LM6000
1A/1B With Double DSM/EE Measures
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-24 February 2010
Year Unit Additions
2011
Nikiski Wind
Seward 1
Healy Clean Coal
2012
Fire Island
MLP LM2500
Nikiski
Seward 2
$14,108,513
2013
2014
HEA Frame
South Central PP
MLP LM6000 CC
GVEA MSW
HEA Aero
2015 Eklutna Generation
2016 Kenai Wind
2017 46.84%
2018
2019 Kenai Wind
2020 Mount Spurr T
2021 Kenai Wind
2022 GVEA Wind $9,086,710
2023 Mount Spurr
2024 Kenai Wind
2025 Anchorage LMS100
2026
2027
2028
2029
2030 GVEA Wind
2031
2032
2033
2034
2035
2036 GVEA 1X1 NPole Retrofit
2037
2038
2039
2040 Anchorage 1x1 6FA
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050 Anchorage LMS100
2051
2052
2053
2054
2055
2056
2057
2058
2059 GVEA LM6000
2060
1A/1B With Committed Units Included
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-25 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 $11,205,673
2013 Anchorage 1x1 6FA
2014
GVEA MSW
Glacier Fork
Anchorage MSW
2015
2016
2017 49.07%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Anchorage LMS100
2021
2022 $8,381,277
2023
2024
2025 Chakachamna
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037 GVEA 1x1 6FA
2038
2039
2040
2041
2042 Anchorage LMS100
2043
2044
2045
2046 GVEA LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 Anchorage LMS100
2058
2059
2060 GVEA LM6000
1A/1B Without CO2 Costs
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-26 February 2010
Year Unit Additions
2011 Nikiski Wind
2012 Anchorage 1x1 6FA $14,064,201
2013
2014
Glacier Fork
GVEA MSW
2015 Anchorage MSW
2016
2017 Kenai Wind 61.95%
2018 Mount Spurr
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Anchorage LM6000 $9,248,373
2023
2024
2025
Chakachamna
Kenai Wind
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037 GVEA LMS100
2038
2039
2040
2041
2042 GVEA 1x1 6FA
2043
2044
2045
2046 Kenai Hydro
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 GVEA LMS100
2058
2059
2060 Anchorage LM6000
1A/1B With Higher Gas Prices
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-27 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $14,331,969
2013 Anchorage 1x1 6FA
2014 Glacier Fork
2015 Anchorage MSW
2016
2017 GVEA MSW 38.06%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $7,719,034
2023
2024
2025 GVEA LM6000
2026
2027
2028
2029
2030 Anchorage 2x1 6FA
2031
2032
2033
2034
2035
2036
2037 Anchorage LMS100
2038
2039
2040
2041
2042 Anchorage LMS100
2043
2044
2045
2046 HEA LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 GVEA 1x1 6FA
2058
2059
2060
1A/1B Without Chakachamna
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-28 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $14,331,969
2013 Anchorage 1x1 6FA
2014 Glacier Fork
2015 Anchorage MSW
2016
2017 GVEA MSW 38.06%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $7,719,034
2023
2024
2025 GVEA LM6000
2026
2027
2028
2029
2030 Anchorage 2x1 6FA
2031
2032
2033
2034
2035
2036
2037 Anchorage LMS100
2038
2039
2040
2041
2042 Anchorage LMS100
2043
2044
2045
2046 HEA LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 GVEA 1x1 6FA
2058
2059
2060
1A/1B With Chakachamna Capital Costs Increased by 75%
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-29 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 $15,228,141
2013
2014
Glacier Fork
Anchorage MSW
GVEA MSW
2015 Anchorage 1x1 6FA
2016
2017 61.01%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $12,420,673
2023
2024
2025 Lower Low Watana
2026
2027
2028
2029
2030 MEA Hydro
2031
2032
2033
2034
2035
2036
2037 Anchorage LM6000
2038
2039
2040
2041
2042 GVEA 1x1 6FA
2043
2044
2045
2046 Kenai Hydro
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 Anchorage 1x1 6FA
2058
2059
2060
1A/1B With Susitna (Lower Low Watana Non-Expandable Option) Forced
Cumulative Present Worth
Cost ($000)
Renewable Energy % In
2025
Total Capital Investment
($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-30 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 $15,039,926
2013
2014
Glacier Fork
Anchorage MSW
GVEA MSW
2015 Anchorage 1x1 6FA
2016
2017 63.01%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $15,056,672
2023
2024
2025 Low Watana (Non-Expandable)
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046 Chakachamna
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
1A/1B With Susitna (Low Watana Non-Expandable Option) Forced
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-31 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 $15,345,647
2013
2014
Glacier Fork
Anchorage MSW
GVEA MSW
2015 Anchorage 1x1 6FA
2016
2017 60.18%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $15,588,186
2023
2024
2025 Low Watana (Expandable)
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046 Chakachamna
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
1A/1B With Susitna (Low Watana Expandable Option) Forced
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-32 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 $14,854,377
2013
2014
Glacier Fork
Anchorage MSW
GVEA MSW
2015 Anchorage 1x1 6FA
2016
2017 66.90%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $14,068,673
2023
2024
2025 Low Watana (Expandable)
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040 Low Watana Expansion
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
1A/1B With Susitna (Low Watana Expansion Option) Forced
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-33 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $15,682,774
2013
2014
Glacier Fork
Anchorage MSW
2015 Anchorage 1x1 6FA
2016
2017 GVEA MSW 70.97%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Anchorage LM6000
2021 Anchorage 1x1 6FA
2022 GVEA LM6000 $13,210,718
2023
2024
2025 Watana
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
1A/1B With Susitna (Watana Option) Forced
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-34 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 $14,794,958
2013 Anchorage 1x1 6FA
2014 Glacier Fork; GVEA MSW
2015 Anchorage MSW
2016
2017 66.92%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 GVEA LM6000 $11,633,307
2023
2024
2025 High Devil Canyon
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057
2058
2059
2060
1A/1B With Susitna (High Devil Canyon Option) Forced
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-35 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $13,841,100
2013 Anchorage 1x1 6FA
2014 Glacier Fork
2015 Anchorage MSW
2016
2017 GVEA MSW 60.51%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $9,105,176
2023
2024
2025
Chakachamna
Kenai Wind
Anchorage Nuc
2026
2027
2028
2029
2030 Kenai Hydro
2031
2032
2033
2034
2035
2036
2037 GVEA LMS100
2038
2039
2040
2041
2042 Anchorage LMS100
2043
2044
2045
2046 Anchorage LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 Anchorage LMS100
2058
2059
2060 Anchorage LM6000
1A/1B With Modular Nuclear
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-36 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $13,712,483
2013 Anchorage 1x1 6FA
2014 Glacier Fork
2015 Anchorage MSW
2016
2017 GVEA MSW 65.52%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $9,679,006
2023
2024
2025
Chakachamna
Turnagain Tidal Arm
2026
2027
2028
2029
2030 Kenai Hydro
2031
2032
2033
2034
2035
2036
2037 GVEA LMS100
2038
2039
2040
2041
2042 GVEA 1x1 6FA
2043
2044
2045
2046 Anchorage LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 GVEA LMS100
2058
2059
2060
1A/1B With Tidal
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-37 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $13,624,595
2013 Anchorage 1x1 6FA
2014 Glacier Fork
2015 Anchorage MSW
2016
2017 GVEA MSW 62.32%
2018 GVEA 1X1 NPole Retrofit
2019
2020 Mount Spurr
2021 Anchorage 1x1 6FA
2022 Mount Spurr $9,086,710
2023
2024
2025 Chakachamna
2026
2027
2028
2029
2030 Kenai Hydro
2031
2032
2033
2034
2035
2036
2037 GVEA LMS100
2038
2039
2040
2041
2042 GVEA 1x1 6FA
2043
2044
2045
2046 Anchorage LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 GVEA LMS100
2058
2059
2060
1A/1B With Lower Coal Capital and Fuel Costs
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
SECTION 13 SUMMARY OF RESULTS
ALASKA RIRP STUDY
Black & Veatch 13-38 February 2010
Year Unit Additions
2011
Nikiski Wind
Healy Clean Coal
2012 Fire Island $12,953,856
2013 Anchorage 1x1 6FA
2014 Glacier Fork
2015 Anchorage MSW
2016
2017 Kenai Wind 67.56%
2018 Mount Spurr
2019
2020 GVEA 1X1 NPole Retrofit
2021 Anchorage 1x1 6FA
2022 Mount Spurr $9,256,012
2023
2024
2025
GVEA MSW
Chakachamna
2026
2027
2028
2029
2030 Kenai Hydro
2031
2032
2033
2034
2035
2036
2037 GVEA LMS100
2038
2039
2040
2041
2042 GVEA 1x1 6FA
2043
2044
2045
2046 Anchorage LM6000
2047
2048
2049
2050
2051
2052
2053
2054
2055
2056
2057 GVEA LMS100
2058
2059
2060 Kenai Wind
1A/1B With Federal Tax Credits for Renewables
Cumulative Present
Worth Cost ($000)
Renewable Energy %
In 2025
Total Capital
Investment ($000)
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-1 February 2010
14.0 IMPLEMENTATION RISKS AND ISSUES
In this section, Black & Veatch identifies a number of general risks and issues that must be addressed
regardless of the resource future that is chosen by stakeholders, including the utilities and State policy makers.
This is followed by a discussion of the risks and issues associated with each alternative generation resource
type including transmission, and the actions that should be taken to address these resource-specific risks and
issues.
14.1 General Risks and Issues
In this subsection, Black & Veatch identifies and discuss a number of general issues and risks that relate to
the implementation of this RIRP. These general issues and risks are grouped into the following categories:
• Organizational
• Resource
• Fuel Supply
• Transmission
• Market Development
• Financing and Rate
• Legislative and Regulatory
• Value of Optionality
14.1.1 Organizational Risks and Issues
As previously discussed, the four resource plans that have been developed as part of this project focus on the
Railbelt region as a whole. In other words, the four alternative resource plans were developed on a
comprehensive regional basis to minimize costs, while maintaining adequate reliability, rather than for the
individual utilities.
14.1.1.1 Regional Implementation
The possible formation of a new Railbelt regional generation and transmission entity (i.e., GRETC) is under
consideration. The functional responsibilities of this new regional entity would include:
• Independent, coordinated operation of the Railbelt electric transmission system
• Region-wide economic commitment and dispatch of the Railbelt’s generation facilities
• Region-wide resource and transmission expansion planning
• Joint identification, planning and development of new generation and transmission facilities for the
Railbelt region
The existing Railbelt utilities would retain the responsibility for providing traditional distribution and
customer services, such as moving power from transmission/distribution substations to individual customers,
meter reading, turn-ons/offs, billing and responding to customer inquiries.
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-2 February 2010
Taking a regional approach to economic dispatch and system operation, integrated resource planning, and
project planning and development will most likely lead to better results than the current situation of six
individual utilities working separately to meet the needs of their own residential and commercial customers
without full regard to the benefits of coordination of activities among the utilities, provided that the regional
entity has the appropriate governance structure, and financial and technical expertise. Additional benefits of a
regional entity will likely include:
• A regional entity, with rational regional planning, would enable the region to identify and prioritize
projects on a regional basis and it puts the State in a better position to evaluate, award and monitor
funding.
• A regional entity improves the opportunities to obtain the benefits of economies of scale in
generation, transmission, and DSM/EE projects and programs.
• The formation of a regional entity could lead to a reduction in the required levels of reserve margins
over time.
• A regional entity is better able to integrate non-dispatchable resources, such as wind and solar, given
the impact of these resources on system operation and reliability.
• With regard to project development, the concentration of staff within one organization will increase
the ability to make timely and effective mid-course corrections, as required.
• A regional entity is in a better position to manage risks which is particularly important given the
current circumstances in the Railbelt region.
• A regional entity could also result in other cost savings, including:
o The region would need to develop only one regional Integrated Resource Plan, as opposed to
three or more Integrated Resource Plans, every three to five years.
o Legal and consulting expenses can be reduced as more issues are addressed on a regional basis
versus on an individual utility basis.
o Total staffing levels in certain areas on a regional basis can likely be reduced.
o Better access to lower cost financing due to the overall financial strength of the regional entity
relative to the six individual utilities.
• A regional entity would be responsible for development and implementation of a single region-wide
DSM/EE program-related communications and outreach effort, thereby ensuring consistency of
message and procedures for participation, along with the attendant cost efficiencies involved. This
would help avoid confusion and facilitate use of mass marketing, while still enabling co-branding
with individual Railbelt utilities.
• A single point of contact for DSM/EE activities for the region would make program administration
and evaluation much easier. All data would be housed in a central DSM/EE tracking system for ease
of tracking progress towards the achievement of goals, reporting on individual entities or total, and
tracking performance of vendors.
• The formation of a regional entity can increase the flexibility of the region to respond to major events
(e.g., a large load increase, such as a new or expanded mine).
• A regional entity would be in a better position to work with Enstar Natural Gas Company and the gas
producers to address the region’s energy issues in a more comprehensive manner.
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This study was undertaken largely on the premise that such a regional entity would be formed to implement
the chosen RIRP. While it is not an absolute requirement that a regional entity be formed to implement the
RIRP, such implementation would be considerably more difficult if it is left up to the six individual Railbelt
utilities, as they are required under their own governance policies to focus on identifying and implementing
the best solutions for their own members and customers, as opposed to focusing on the most optimal regional
solution.
It is Black & Veatch’s belief that the formation of a regional entity is critical to implementing many of the
recommendations of this report, whether the regional entity is the proposed GRETC or a different, but similar,
regional entity. Black & Veatch also believes that the formation of this entity should occur as quickly as
possible; delay will only make the challenges greater and, if the regional entity is not formed now, decisions
will need to be made by individual utilities and these decisions will not result in optimal results from a
regional perspective. Suboptimal solutions result in higher costs, lower reliability and the inability to manage
the successful integration of DSM/EE resources and renewable resources into the Railbelt system.
14.1.1.2 Achieving Economies of Scale
The Railbelt utilities, to date, have not been able to take full advantage of economies of scale for several
reasons. First, as previously noted, the combined peak load of the six Railbelt utilities is still relatively small.
Second, the Railbelt transmission grid’s lack of redundancies and interconnections with other regions has
placed reliability-driven limits on the size of generation facilities that could be integrated into the Railbelt
region.
Third, the fact that each utility has developed their own long-term resource plans has led to less optimal
results (from a regional perspective) relative to what could be accomplished through a rational, fully
coordinated regional planning process. Finally, the existence of six separate utilities, and their small size on
an individual utility basis, has restricted their ability to take advantage of economies of scale with regards to
staffing and their skill sets. For example, the development of six separate programs to develop and deliver
DSM/EE programs is a considerably more difficult challenge than would be the case if there was one regional
entity, with the responsibility for developing and delivering DSM/EE programs to residential and commercial
customers throughout the Railbelt region.
In addition to the benefits of scale related to generation and transmission resources, there are benefits
associated with staffing, including:
• The concentration of staff would likely lead to more sophisticated generation and transmission
planning, resulting in better regional resource planning decisions.
• Better coordination is possible if all regional employees with generation and transmission
responsibilities are part of one organization.
• Depth of bench – it is easier to take advantage of the depth of everyone’s skills and expertise when
everyone works for one organization, and greater specialization can occur.
• The concentration of staff increases the ability of the regional entity to keep abreast of new
technologies (e.g., renewables) and industry trends.
• The concentration of staff also increases the ability of the Railbelt region to develop and support the
delivery of cost-effective renewables and DSM/EE programs.
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14.1.2 Resource Risks and Issues
There are a myriad of risks and issues associated with the implementation of specific resource options,
whether DSM/EE, generation, or transmission. General areas of risk are discussed below and resource
specific issues and risks are discussed in the next subsection.
14.1.3 Fuel Supply Risks and Issues
Natural gas has been the predominant source of fuel for electric generation used for the customers of
Chugach, ML&P, MEA, Homer and Seward. Additionally, customers in Fairbanks have benefited from
natural gas-generated economy energy sales in recent years.
There are a number of inherent risks whenever a utility or region is so dependent upon one fuel source
including risks related to prices, availability and deliverability. An additional risk faced by Chugach is the
fact that its current gas supply contracts are expected to expire in the 2010-2012 timeframe. An additional
problem faced by the Railbelt utilities, due to their dependence on natural gas, is the fact that existing
developed reserves in the Cook Inlet are declining as well as the current deliverability of that gas.
Consequently, the Railbelt region will not be able to continue its heavy dependence upon natural gas in the
future unless enhanced gas supplies become available. Those enhanced supplies could include additional
reserves discovered in the Cook Inlet, new reserves discovered in basins within or near the Railbelt region,
North Slope gas delivered by an interstate pipeline, or a LNG import terminal with access to LNG suppliers
outside Alaska.
Historically low prices for natural gas in the Cook Inlet region have been rationalized in some cases as a
consequence of “stranded gas” in supply that exceeds the available market outlets. But in fact the export of
LNG to Japan, where premium prices are assured, has provided the most significant market outlet and has
made the “stranded gas” argument unconvincing. Indeed, the LNG export outlet has served as much of the
financial incentive for producers to continue gas production from Cook Inlet.
Whether new gas supplies from the Cook Inlet become available or gas from the North Slope is brought to the
Railbelt region, one reality can not be escaped: future gas supply prices will be higher than in past experience.
For additional gas supplies in the Cook Inlet to become available, prices will need to increase to encourage
exploration and production, and to help offset losses if LNG exports come to an end. This results from the
fact that oil and gas producers make investment decisions based upon expected returns relative to investment
opportunities available elsewhere in the world.
In the case of North Slope gas supplies, the cost, probability and timing of potential gas flows to the Railbelt
region are unknown at this time. Nevertheless, given the construction lead times for a potential gas pipeline
to provide gas from the North Slope, gas from that region is unlikely to be available for a number of years.
Furthermore, if gas from the North Slope becomes available in the Railbelt region through either the Bullet
Line or Spur Line, prices will likely be tied to market prices since potential natural gas flows to the Railbelt
region will likely be just one of the competing demands for the available gas. Additionally, the pipeline
transmission rates that will be paid to move gas to the Railbelt region will be significantly higher than the
relatively low transportation rates that are imbedded in the delivered cost of gas from Cook Inlet suppliers
under existing contracts.
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14.1.4 Transmission Risks and Issues
As previously noted, the Railbelt electric transmission grid has been described as a long straw, as opposed to
the integrated, interconnected, and redundant grid that is in place throughout the lower-48 states. This
characterization reflects the fact that the Railbelt electric transmission grid is an isolated grid with no external
interconnections to other areas and that it is essentially a single transmission line running from Fairbanks to
the Kenai Peninsula, with limited total transfer capabilities and redundancies.
As a result of the lack of redundancies and interconnections with other regions, each Railbelt utility is
required to maintain higher generation reserve margins (reserve margins reflect the amount of extra capacity
beyond the peak load requirement that a utility needs to assure reliable system operation in the event that a
generating units fails) and higher spinning reserve requirements (spinning reserve represents the amount of
capacity that is available to serve load instantaneously if an operating generator disconnects from the grid)
than elsewhere in order to ensure reliability in the case of a generation or transmission grid outage.
Furthermore, the lack of interconnections and redundancies exacerbates a number of the other issues facing
the Railbelt region, such as:
• The requirement for larger regulating reserves (regulating reserves are extra capacity that are required
to be synchronized and on-line and are able to adjust output both up and down in real-time as load
fluctuates). This maintains stable frequency performance.
• The requirement for enough units on-line that can influence the rate of change of frequency when the
balance between real-time load and real-time generation is out of balance. The lack of other
interconnected units result in a lower system inertia and, consequently, a much more rapid fluctuation
rate for frequency. This issue assumes greater importance when high penetration of non-dispatchable
generation (e.g., wind) is being considered in the system.
• The lack of interconnection coupled with the relatively small size of the Railbelt system also results
in smaller unit sizes than would otherwise be considered. This means that the full benefit of
economies of scale will not be available and possibly more limited potential for jointly developed
larger projects.
• Benefits of more economic system operation based on the potential for diversity of operation and
wider power marketing transactions, as well as higher operation load factors for generators.
• Environmental benefits of system interconnection could result in reductions, through inter-regional
commitment and dispatch, of greenhouse gas (GHG) emissions from electricity production in thermal
plants. The value of the avoided emissions may be expressed as the total reduction in GHG times the
cost of the emissions.
14.1.5 Market Development Risks and Issues
14.1.5.1 Competitive Power Procurement
An important market development-related issue relates to the ability of IPPs, or non-utility generators of
electricity, to enter the market. To date, the level of IPP penetration is the Railbelt region has been minor.
The most significant activity is the current efforts by Cook Inlet Regional, Inc./enXco to develop the Fire
Island wind farm. Additionally, other activities include those by Ormat to develop the Mt. Spurr geothermal
project. Other IPP development activities are either for smaller projects or are not as far along in the
development process. However, none of these current activities are guaranteed to succeed. There are a
number of reasons for lower IPP activity in the Railbelt region than has occurred in other regions of the
country. Not the least of these reasons is the fact that IPPs must work with individual utilities to gain
acceptance on their projects, including the negotiation of power purchase agreements under varying terms and
conditions and dealing with various generation interconnection requirements. The region would likely benefit
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from the adoption of policies that attract IPP development of project alternatives under the resource addition
parameters established by the RIRP. One such policy would be the development of a competitive power
procurement policy that would establish a “level playing field” for IPP-proposed projects. Under competitive
procurement, IPP developers would be able to bid projects that offer economic benefits to the grid against
other economic options. This assures that the combination of resources selected would be the most economic
options for customers.
14.1.5.2 Load Growth
With regard to native load growth (e.g., normal load growth resulting from residential and commercial
customers), Railbelt utilities have experienced limited, stable growth in recent years. This stable native load
growth is expected to continue in the years ahead, absent significant economic development gains in the
region.
There are, however, a number of potential significant, discrete load additions that could result from economic
development efforts. These potential load additions could result from the development of new, or expansion
of existing, mines (e.g., Pebble and Donlin Creek), continued military base realignment, other economic
development efforts and or State policy decisions. Additionally, there will likely be a significant increase in
Railbelt population if the North Slope natural gas pipeline, and or the Spur Line or Bullet Line, is built.
Where large discreet load additions occur, there will be associated changes in both generation and
transmission infrastructure to maintain system reliability. Under a consolidated integrated resource plan the
discreet additions would be coordinated with other regional reliability projects to minimize costs and to
optimize system considerations such as the size, timing and location of new resources.
14.1.6 Financing and Rate Risks and Issues
14.1.6.1 Financing
As noted above, the Railbelt utilities face a very significant challenge in terms of their ability to finance the
future. Traditional means of financing by the Railbelt utilities going forward independently simply are
inadequate given the capital investment requirements over the next 50 years that result from each of the four
alternative resource plans. Essentially, the existing net cash flow for the individual utilities would not provide
sufficient debt coverage ratios to support investment grade debt financing for large, multi-year construction
projects. Even for a regional entity, the available net cash flow to support such projects would be difficult
without State assistance.
14.1.6.2 Rate Design
In addition to the challenge associated with securing the required financing, that capital investment will need
to be recovered through rates, thereby resulting in higher monthly bills for residential and commercial
customers. While the need to recover capital investments is a reality, innovative rate design options
(e.g., Construction-Work-in-Progress - CWIP) are available to smooth out these rate increases over time so
that they are more affordable to residential and commercial customers. CWIP also helps to address the cash
flow issues associated with financing new projects.
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14.1.7 Legislative and Regulatory Risks and Issues
14.1.7.1 State Energy Policy
The development of a RIRP is not the same as the development of a State Energy Plan; nor does it set State
policy. Setting energy-related policies is the role of the Governor’s office and State Legislature. With regard
to energy policy making, however, the RIRP does provide a foundation of information and analysis that can
be used by policy makers to develop important policies.
Having said this, the development of a State Energy Policy and or related policies could directly impact the
specific alternative resource plan chosen for the Railbelt region’s future. As such, the RIRP may need to be
readdressed as future energy-related policies are enacted.
14.1.7.2 Regulatory Commission of Alaska
While it is not within the scope of this RIRP to address the level and quality of regulation for either the
individual utilities or GRETC, the level and quality of regulation impacts current and future investment
decisions by both the electric and natural gas industries.
14.1.8 Value of Optionality
Optionality represents the ability to make other choices once an initial choice has been made. Given the large
fixed cost commitments associated with generation and transmission projects, any optionality in a resource
plan adds value. As previously discussed, the recent increases in natural gas prices highlight the dangers
inherent from an over-reliance on one fuel source or generation technology. That is, given the sunk cost of
generation from gas fired resources, there is little option for reducing costs as gas prices rise. Just as investors
rely on a portfolio of assets to manage risk, it is important for utilities to develop a portfolio of assets to
ensure safe, reliable and cost-effective service to customers. It also demonstrates the importance of
maintaining flexibility.
In this context, maintaining flexibility has two dimensions. The first dimension of flexibility relates to future
generation resources and fuel supplies. Any future resource path should be chosen only if it is likely to
enhance the region’s ability to maintain and improve the region’s resource asset portfolio flexibility.
The second dimension of flexibility relates to the ability to adjust to changing State and Federal policies,
whether they are related to a State Energy Plan, carbon emissions regulations, support of the North Slope gas
pipeline and or the Bullet or Spur Lines, and so forth. Resource decisions being made by utility managers are
increasingly driven or influenced by energy policy makers.
Fuel supply diversity inherently has value in terms of risk management. Simply stated, the greater a region’s
dependence upon one fuel source, the less flexibility the region will have to react to future price and
availability problems.
The level of uncertainty facing the Railbelt region continues to grow, as do the risks attendant to utility
operations. One important approach to risk management is to spread the risk to a greater base of investors
and consumers so that the impact of those risks on individuals is reduced. Simply stated, the ability of the
region to absorb the risks facing it is greater on a regional basis than it is on an individual utility basis.
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Additionally, maintaining flexibility is important. In that regard, even after a particular resource plan has
been adopted, it is important to pursue activities that maintain the viability of other resource options;
therefore, the region can modify it resource plan, as required, as the issues and risks associated with the
selected resource plan become better known
14.2 Resource Specific Risks and Issues
14.2.1 Introduction
The purpose of this section is to identify the primary issues and risks associated with the development of the
following resource options:
• DSM/EE
• Generation resources, including natural gas, coal and modular nuclear, as well as renewable resources
including large and small hydro, wind, geothermal, solid waste and tidal
• Transmission resources
14.2.2 Resource Specific Risks and Issues – Summary
The following table provides Black & Veatch’s assessment of the relative magnitude of various categories of
risks and issues for each resource type, including:
• Resource Potential Risks – the risk associated with the total energy and capacity that could be
economically developed for each resource option.
• Project Development and Operational Risks – the risks and issues associated with the development
of specific projects, including regulatory and permitting issues, the potential for construction costs
overruns, actual operational performance relative to planned performance, and so forth. This category
also includes non-completion risks once a project gets started, the risk that adverse operating
conditions will severely damage the facilities resulting in a shorter useful life than expected, and
project delay risks.
• Fuel Supply Risks – the risks and issues associated with the adequacy and pricing of required fuel
supplies.
• Environmental Risks – the risks of environmental-related operational concerns and the potential for
future changes in environmental regulations.
• Transmission Constraint Risks – the risk that the ability to move power from a specific generation
resources to where that power is needed, an issue that is particularly important for large generation
projects and remote renewable projects.
• Financing Risks – the risk that a regional entity or individual utility will not be able to obtain the
financing required for specific resource options under reasonable and affordable terms and conditions.
• Regulatory/Legislative Risks – the risk that regulatory and legislative issues could affect the
economic feasibility of specific resource options.
• Price Stability Risks – the risk that wholesale power costs will increase significantly as a result of
changes in fuel prices and other factors (e.g., CO2 costs).
IMPLEMENTATION SECTION 14 RISKS AND ISSUES ALASKA RIRP STUDY Black & Veatch 14-9 February 2010 Table 14-1 Resource Specific Risks and Issues - Summary Relative Magnitude of Risk/Issue Resource Resource Potential Risks Project Development and Operational Risks Fuel Supply Risks Environmental Risks Transmission Constraint Risks Financing Risks Regulatory/ Legislative Risks Price Stability Risks DSM/EE Moderate Limited N/A N/A N/A Limited - Moderate Moderate Limited Generation Resources Natural Gas Limited Limited Significant Moderate Limited Moderate Moderate Significant Coal Limited Moderate-Significant Limited Moderate - Significant Limited - Significant Moderate – Significant Moderate Moderate Modular Nuclear Limited Significant Moderate Significant Limited Significant Significant Significant Large Hydro Limited Significant Limited Significant Significant Significant Significant Limited Small Hydro Moderate Moderate Limited Moderate Moderate Limited - Moderate Limited Limited Wind Moderate Moderate N/A Limited Moderate Limited - Moderate Limited Limited - Moderate Geothermal Moderate Limited - Moderate N/A Limited - Moderate Moderate – Significant Limited – Moderate Limited Limited Solid Waste Limited Moderate-Significant N/A Significant Moderate Limited – Moderate Limited-Moderate Moderate Tidal Limited Significant N/A Significant Moderate - Significant Moderate – Significant Moderate -Significant Limited - Moderate Transmission Limited Significant N/A Moderate N/A Significant Moderate -Significant N/A
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The following provides some commentary related to the basis for these qualitative assessment of resource
specific risks and issues:
• Resource Potential Risks
Resource potential risks are deemed to be moderate for some of the renewables resource options
primarily due to the fact that enough resource potential studies have not been completed to provide a
high degree confidence in the amount of energy capacity and energy that could be provided by these
different resource options. For other renewable resource options, initial studies indicate significant
resources are available, but more detailed studies have not been conducted to ensure that these large
potential resources can actually be converted into renewable generation. Based upon the studies that
have been completed, there is a solid foundation for believing that each of these different forms of
renewable resources offers the potential for relatively significant capacity and energy within the
Railbelt region. However, additional studies must be completed to identify the most attractive
locations and to firm up the resource potential estimates for each type of renewable resource
technology.
Resource potential risks and issues are relatively lower for natural gas, coal and modular nuclear, as
well as for additional transmission resources.
Resource potential risks associated with DSM/EE programs are more commonly related to the
reliability, or lack thereof, of the resource in that it is less under the control of the utility and relies
more on mass market decision-making and/or behavior.
• Project Development and Operational Risks
Project development and operational risks and issues are significant for modular nuclear, large hydro,
tidal, and transmission. They are also fairly significant for coal and solid waste. In the case of large
hydro, these risks are significant due to the stringent environmental and permitting issues that would
need to be addressed. Additionally, the potential for significant construction cost overruns is
significant for large hydro.
Tidal power represents an option with significant potential in the Railbelt. However, this technology
has not been widely commercialized and there are significant environmental and permitting risks and
issues associated with this technology.
In the case of transmission, project development risks are deemed significant due to NIMBY concerns
and the rough terrain and difficult construction conditions that exist.
Coal, solid waste, and modular nuclear face NIMBY concerns as well as permitting and licensing
concerns.
The project development-related risks are believed to be lower, or moderate, for the other types of
renewable resources, including small hydro, wind, and geothermal; they are even lower, or minimal,
for DSM/EE resources, and generation resources that are fueled by natural gas and other fossil fuels.
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• Fuel Supply Risks
Fuel supply-related risks are very significant for natural gas generation resources. They are generally
limited for generation options that rely on other fossil fuels, and they do not apply to DSM/EE and
the various renewable resources.
• Environmental Risks
Environmental-related risks are believed moderate for natural gas generation, and moderate to
significant for other fossil fueled generation options. Future carbon restrictions represent an
important risk for all generation resources that rely on fossil fuels and are very significant in the case
of coal.
Environmental-related risks are shown as significant for modular nuclear, large hydro options, solid
waste, and tidal power due to their potential environmental impact.
They are believed to be moderate for small hydro and geothermal, and limited for wind based, in
large part, on experience with these technologies in other regions of the country and elsewhere in the
world.
• Transmission Constraint Risks
Existing transmission constraints are significant for large hydro because the current transmission
network is insufficient to move large amounts of capacity and energy throughout the region which
would be required for any large hydro project to be economic.
Transmission constraints also represent a moderate to significant issue for geothermal and tidal,
depending upon the ultimate amount of these resources developed within the region.
They are believed to be moderate with regard to small hydro, wind, and solid waste due to the typical
size of these projects and the fact that they can generally be developed throughout the Railbelt region,
thereby reducing the need to have transmission to move the related capacity and energy from one area
of the Railbelt region to another.
Transmission constraints are deemed limited for natural gas-fuel generation, again due to the typical
size of these projects and the fact that they can be located throughout the Railbelt region, and they do
not exist with regard to DSM/EE resources due to the distributed nature of these resources.
• Financing Risks
Financing risks and issues are significant for any large scale resource option including coal, modular
nuclear, large hydro, and transmission resources. They are moderate for natural gas generation.
Financing risks are limited to moderate for most of the renewable resources (e.g., including small
hydro, wind, geothermal, solid waste and tidal) depending upon the actual size of the projects
developed; likewise they are limited to moderate for DSM/EE resources.
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• Regulatory/Legislative Risks
Regulatory and legislative risks and issues are limited for smaller-scale renewable resources,
including small hydro, wind, geothermal, and solid waste.
They are moderate for DSM/EE resources, primarily due to the fact that regulatory (and potentially
legislative) changes would be required to eliminate the disincentive that exists under the current
regulatory framework for utilities to encourage customers to use less electricity. They are also
believed to be moderate for natural gas and other fossil fueled generation resources.
Regulatory and legislative risks and issues are believed to be significant for modular nuclear and large
hydro, and moderate to significant for tidal and transmission resources.
• Price Stability Risks
Price stability risks and issues are limited for DSM/EE programs, small and large hydro, and
geothermal; limited to moderate for wind and tidal. They are moderate for coal and solid waste, and
significant for natural gas and modular nuclear.
More detailed information related to the risks and issues associated with each type of resource options is
provided in the following subsection.
14.2.3 Resource Specific Risks and Issues – Detailed Discussion
This section provides more detailed information related to the risks and issues associated with each of the
following types of resource options:
• DSM/EE
• Generation
o Natural gas
o Coal
o Modular nuclear
o Large hydro
o Small hydro
o Wind
o Geothermal
o Solid waste
o Tidal
• Transmission
This section consists of a series of tables that identifies the most significant risks and issues for each type of
resource options, broken down by the major risk/issue categories discussed in the previous section. These
tables also identify the primary actions that should be taken to address these risks and issues.
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14.2.3.1 DSM/EE
Table 14-2
Resource Specific Risks and Issues – DSM/EE
Resource: DSM/EE
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • Total economic resource potential is
unknown
• General lack of Alaska-specific data to
determine economic resource potential,
including end-use saturations, measure
persistence, weather sensitive impacts,
and cost-effectiveness
• Reliability is a key concern with DSM
since utilities have less control over its
acquisition and management
• Establish Alaska-specific baseline
information through the completion
of region-wide residential and
commercial end-use saturation
surveys and customer attitudinal
surveys
• Complete comprehensive
economically achievable potential
study that includes a detailed cost-
effectiveness evaluation of all
feasible DSM/EE measures
• Complete vendor surveys to
determine availability and relative
costs of DSM/EE measures in the
Railbelt region
• Develop regional DSM/EE program
measurement and evaluation
protocols
• Focus programs on hard-wired
technology replacements rather
than behavioral based savings
• If demand reduction is a goal, focus
DSM programs on peak load
reduction program strategies that
can be dispatched or under greater
control by the utility
Project Development • Ineffectiveness and inefficiencies
associated with six individual utilities
developing their own DSM/EE
programs
• Ineffectiveness and inefficiencies
associated with lack of coordination
between the electric utilities, Enstar,
and AHFC
• Lack of customer awareness regarding
DSM/EE options and economics
• Establish a regional entity
(e.g., GRETC or independent third
party) to develop and deliver, in
coordination with the six Railbelt
utilities, DSM/EE efficiency
programs to all customers in the
Railbelt region
• Develop and implement regional
DSM/EE programs in close
coordination with Enstar and
AHFC
• Develop public outreach program
to increase awareness of DSM/EE
options
• Develop and learn from near-term
DSM/EE pilot programs throughout
the Railbelt region
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Table 14-2 (Continued)
Resource Specific Risks and Issues – DSM/EE
Resource: DSM/EE
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Fuel Supply • Not applicable • Not applicable
Environmental • Not applicable • Not applicable
Transmission Constraints • Not applicable • Not applicable
Financing • Lack of funding source for initial
activities (e.g., collect baseline
information and consumer education)
required to build a viable and successful
DSM/EE program
• Lack of stable source of long-term
financing for DSM/EE program
• Legislature should appropriate
funds for the initial development of
a regional DSM/EE program,
including 1) region-wide
residential and commercial end-use
saturation surveys, 2) customer
attitudinal survey, 3) vendor
surveys, 4) comprehensive
evaluation of economically
achievable potential, and 5) detailed
DSM/EE program design efforts
• Increase State funding of low
income weatherization and
residential and energy audit (both
residential and commercial)
program
• Aggressively pursue available
Federal funding for DSM/EE
programs
• Consider implementation of a
System Benefit Charge, or SBC,
(i.e., a surcharge on customer bills
that would be dedicated to the
funding of DSM/EE programs) to
provide for the long-term funding
of DSM/EE programs
Regulatory/Legislative • The implementation of DSM/EE
reduces energy sales and, therefore,
reduces the ability of utilities to recover
costs under current rate design
principles
• Lack of innovative rate structures in the
Railbelt region, such as time-of-use
(TOU) and demand response (DR) rates
• Lack of strict building codes and
enforcement of those codes
• Lack of State leadership related to
DSM/EE
• Implement a decoupling
mechanism so that a regional entity
and or the individual Railbelt
utilities can still recover their costs
even with lower sales
• Allow utilities to develop pilot
programs to test the effectiveness of
TOU and DR rates
• Establish more stringent residential
and commercial building codes that
lead to lower energy use in new
homes and buildings and increase
the enforcement of those building
codes
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Table 14-2 (Continued)
Resource Specific Risks and Issues – DSM/EE
Resource: DSM/EE
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Regulatory/Legislative
(Continued)
• Establish State targets for DSM/EE
savings based on the economics of
the programs
• Establish State goals for reducing
energy usage at State facilities
• Develop and implement programs
to increase energy efficiency in
State buildings and schools
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ALASKA RIRP STUDY
Black & Veatch 14-16 February 2010
14.2.3.2 Generation Resources
14.2.3.2.1 Generation Resources – Natural Gas
Table 14-3
Resource Specific Risks and Issues – Generation – Natural Gas
Resource: Generation – Natural Gas
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • See Fuel Supply • See Fuel Supply
Project Development • Development risks are well known and
understood
• Not applicable
Fuel Supply • Near-term adequacy and deliverability
of natural gas supplies appear
inadequate
• Several long-term gas supply options
exist but the relative risks and
economics of those options have not
been fully assessed
• Electric utilities need to work
closely with the State, gas
producers and Enstar to ensure the
adequacy of near-term gas supplies
• Current LNG export agreement
should not be extended and the
related gas should be used for the
needs of Railbelt gas and electric
customers, although the loss of the
LNG export outlet might require
the Cook Inlet gas price to be re-set
• Short-term imported LNG gas
supplies should be secured to serve
as transitional gas supply option
• Local gas storage capabilities
should be developed as soon as
possible
• The State should complete a
detailed risk and cost evaluation of
available long-term gas supply
options to determine the best option
• Once the most attractive long-term
supplies of natural gas have been
determined, detailed engineering
studies and permitting activities
should be undertaken
• Appropriate commercial terms and
pricing structures should be
established to provide producers the
incentive to increase exploration for
additional Cook Inlet gas supplies
• State should consider providing
incentives to encourage additional
exploration for Cook Inlet gas
supplies
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-17 February 2010
Table 14-3 (Continued)
Resource Specific Risks and Issues – Generation – Natural Gas
Resource: Generation – Natural Gas
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Environmental • Risk of accident • Continue efforts to enforce safety
and operational regulations
Transmission Constraints • Proper location of gas-fired generation
resources mitigates transmission
constraints
• Require that all proposed plant
locations also include transmission
infrastructure analyses and costs as
part of any approval process
Financing • For larger projects, financing can be
difficult given the financial strength of
the Railbelt utilities
• Formation of a regional G&T entity
(e.g., GRETC) would provide
greater financial capabilities
• Consider State assistance for new
gas-fired generation projects that
replace old, inefficient natural gas
plants
Regulatory/Legislative • Potential future environmental
regulations related to emissions,
including carbon and other emissions
• Monitor Federal legislative and
regulatory activities related to
emission regulations
• Monitor technological
developments regarding carbon
capturing technologies (e.g., carbon
sequestration)
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-18 February 2010
14.2.3.2.2 Generation Resources – Coal
Table 14-4
Resource Specific Risks and Issues – Generation – Coal
Resource: Generation – Coal
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • Not applicable • Not applicable
Project Development • Development risks are generally known
and understood
• Not applicable
Fuel Supply • Not applicable • Not applicable
Environmental • See Regulatory/Legislative • Not applicable
Transmission Constraints • Location of new facilities can add to
transmission constraints
• Expand Railbelt transmission
network
• Require that all proposed plant
locations also include transmission
infrastructure analyses and costs as
part of any approval process
Financing • For larger projects, financing can be
difficult given the financial strength of
the Railbelt utilities
• Formation of a regional G&T entity
(e.g., GRETC) would provide
greater financial capabilities
Regulatory/Legislative • Potential future environmental
regulations related to emissions,
including carbon and other emissions,
and coal mining
• Potential regulations of regarding ash
disposal
• Monitor Federal legislative and
regulatory activities related to
emission regulations and coal
mining
• Monitor technological
developments regarding carbon
capturing technologies (e.g., carbon
sequestration)
• Implement appropriate design to
mitigate environmental impacts
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-19 February 2010
14.2.3.2.3 Generation Resources – Modular Nuclear
Table 14-5
Resource Specific Risks and Issues – Generation – Modular Nuclear
Resource: Generation – Modular Nuclear
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • Resource potential would be very large,
but technology not demonstrated
• Monitor development and licensing
of technology
Project Development • Significant permitting challenges exist
for modular nuclear
• Public acceptability of modular nuclear
is unknown
• Potential for construction cost overruns
is significant
• Technology not fully developed
• Work closely with resource
agencies to identify permitting
requirements
• Develop public outreach program
to better determine public
acceptability of modular nuclear
• Implement best practices related to
management of construction costs
• Support research and development
of technology and pilot projects
Fuel Supply • Not applicable • Not applicable
Environmental • Environmental impacts of modular
nuclear may not be significant, but
public perception about environmental
impacts may be very significant
• Work closely with resource
agencies to identify environmental
issues
• Conduct necessary studies to
address resource agencies’ issues
and data requirements
Transmission Constraints • The small size of the modular nuclear
projects should not pose transmission
constraints
• Require that all proposed plant
locations also include transmission
infrastructure analyses and costs as
part of any approval process
Financing • The lack of technology demonstration
at this small size may create concerns in
the financing community
• Costs per kW may be significant
• Formation of a regional G&T entity
(e.g., GRETC) would provide
greater financial capabilities
• Consider alternative forms of State
assistance reduce resistance to
finance
• Aggressively pursue available
Federal funding
Regulatory/Legislative • NRC licensing is uncertain • Monitor NRC licensing process
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-20 February 2010
14.2.3.2.4 Generation Resources – Large Hydro
Table 14-6
Resource Specific Risks and Issues – Generation – Large Hydro
Resource: Generation – Large Hydro
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • Both Susitna and Chakachamna sites
are adequate to play a major role in
meeting the region’s future electric
capacity and energy requirements
• Not applicable
Project Development • Significant permitting challenges exist
for large hydro projects
• Public acceptability of large hydro is
unknown
• Potential for construction cost overruns
is significant
• Infrastructure needs to support project
construction are significant
• Work closely with resource agencies
to identify permitting requirements
• Develop public outreach program to
better determine public acceptability
of large hydro
• Implement best practices related to
management of construction costs
Fuel Supply • Potential impact of climate change • Monitor water flows
Environmental • Environmental impacts of large hydro
projects are potentially significant
• Work closely with resource agencies
to identify environmental issues
• Conduct necessary studies to
address resource agencies’ issues
and data requirements
Transmission Constraints • Location of new facilities can add to
transmission constraints
• Integration of large hydro facility into
Railbelt transmission grid poses
challenges
• Expand Railbelt transmission
network
• Complete required studies to ensure
the ability to integrate large hydro
projects into the transmission grid
Financing • Financing requirements of a large
hydro project are greater than the
combined financial capabilities of the
Railbelt utilities
• Formation of a regional G&T entity
(e.g., GRETC) would provide
greater financial capabilities
• Consider alternative forms of State
assistance for large hydro projects
Regulatory/Legislative • Potential future environmental
regulations related to large hydro
projects
• Regional commitment to large hydro is
uncertain
• Monitor Federal activities related to
large hydro projects
• Determine State policy regarding
the desirability of large hydro
projects
• Establish State Renewable Portfolio
Standard (RPS) targets
• Develop State policies regarding
Renewable Energy Credits (RECs)
and Green Pricing
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-21 February 2010
14.2.3.2.5 Generation Resources – Small Hydro
Table 14-7
Resource Specific Risks and Issues – Generation – Small Hydro
Resource: Generation – Small Hydro
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • Total economic resource potential is
unknown
• Resource potential may be constrained
by Railbelt regional system regulation
requirements
• Complete regional economic
potential assessment, including the
identification of the most attractive
sites
• Develop regional regulation
strategy for non-dispatchable
resources
Project Development • Ineffectiveness and inefficiencies
associated with six individual utilities
developing small hydro projects
• Lack of standard power purchase
agreements for projects developed by
IPPs
• Infrastructure needs to support
construction may be significant
• Establish a regional entity
(e.g., GRETC) or rely on IPPs to
identify and develop small hydro
projects
• Develop regional standard power
purchase agreements
• Develop regional competitive
power procurement process to
encourage IPP development of
projects
Fuel Supply • Potential impact of climate change • Monitor water flows
Environmental • Site specific environmental issues
including impact on fish
• Comprehensive evaluation of site
specific environmental impacts at
attractive sites
Transmission Constraints • Location of new facilities can add to
transmission constraints
• Integration of non-dispatchable
resources into Railbelt transmission
grid poses challenges
• Expand Railbelt transmission
network
• Require that all proposed plant
locations also include transmission
infrastructure analyses and costs as
part of any approval process
• Develop regional strategy for the
integration of non-dispatchable
resources
Financing • Cost per kW can be significant • Aggressively pursue available
Federal funding for renewable
projects
Regulatory/Legislative • Regional commitment to renewable
resources is uncertain
• Establish State RPS targets
• Develop State policies regarding
RECs and Green Pricing
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-22 February 2010
14.2.3.2.6 Generation Resources – Wind
Table 14-8
Resource Specific Risks and Issues – Generation – Wind
Resource: Generation – Wind
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • Total economic resource potential is
unknown
• Resource potential may be constrained
by Railbelt regional system regulation
requirements
• Complete regional economic
potential assessment, including the
identification of the most attractive
sites
• Develop regional regulation
strategy for non-dispatchable
resources
Project Development • Ineffectiveness and inefficiencies
associated with six individual utilities
developing wind projects
• Lack of standard power purchase
agreements for projects developed by
IPPs
• Establish a regional entity
(e.g., GRETC) or rely on IPPs to
identify and develop wind projects
• Develop regional standard power
purchase agreements
• Develop regional competitive
power procurement process to
encourage IPP development of
projects
Fuel Supply • Not applicable • Not applicable
Environmental • Site specific environmental issues • Comprehensive evaluation of site
specific environmental impacts at
attractive sites
Transmission Constraints • Location of new facilities can add to
transmission constraints
• Integration of non-dispatchable
resources into Railbelt transmission
grid poses challenges
• Expand Railbelt transmission
network
• Require that all proposed plant
locations also include transmission
infrastructure analyses and costs as
part of any approval process
• Develop regional strategy for the
integration of non-dispatchable
resources
Financing • Cost per kW can be significant • Aggressively pursue available
Federal funding for renewable
projects
Regulatory/Legislative • Regional commitment to renewable
resources is uncertain
• Establish State RPS targets
• Develop State policies regarding
RECs and Green Pricing
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-23 February 2010
14.2.3.2.7 Generation Resources – Geothermal
Table 14-9
Resource Specific Risks and Issues – Generation – Geothermal
Resource: Generation – Geothermal
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • Total economic resource potential is
unknown
• Complete regional economic
potential assessment, including the
identification of the most attractive
sites
Project Development • Ineffectiveness and inefficiencies
associated with six individual utilities
developing geothermal projects
• Lack of standard power purchase
agreements for projects developed by
IPPs
• Infrastructure needs to support
construction are likely significant
• Establish a regional entity
(e.g., GRETC) or rely on IPPs to
identify and develop geothermal
projects
• Develop regional standard power
purchase agreements
• Develop regional competitive
power procurement process to
encourage IPP development of
projects
• Explore if synergies can be
achieved for infrastructure with
hydro projects
Fuel Supply • Not applicable • Not applicable
Environmental • Site specific environmental issues • Comprehensive evaluation of site
specific environmental impacts at
attractive sites
Transmission Constraints • Location of new facilities can add to
transmission constraints
• Expand Railbelt transmission
network
• Require that all proposed plant
locations also include transmission
infrastructure analyses and costs as
part of any approval process
Financing • Cost per kW can be significant • Aggressively pursue available
Federal funding for renewable
projects
Regulatory/Legislative • Regional commitment to renewable
resources is uncertain
• Potential future environmental
regulations related to emissions,
including carbon and other emissions
• Establish State RPS targets
• Develop State policies regarding
RECs and Green Pricing
• Monitor Federal legislative and
regulatory activities related to
emission regulations
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-24 February 2010
14.2.3.2.8 Generation Resources – Solid Waste
Table 14-10
Resource Specific Risks and Issues – Generation – Solid Waste
Resource: Generation – Solid Waste
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • Total economic resource potential is
unknown
• Complete regional economic
potential assessment, including the
identification of the most attractive
sites
Project Development • Ineffectiveness and inefficiencies
associated with six individual utilities
developing solid waste projects
• Lack of standard power purchase
agreements for projects developed by
IPPs
• Establish a regional entity
(e.g., GRETC) or rely on IPPs to
identify and develop solid waste
projects
• Develop regional standard power
purchase agreements
• Develop regional competitive
power procurement process to
encourage IPP development of
projects
Fuel Supply • See Resource Potential • Not applicable
Environmental • Site specific environmental issues • Comprehensive evaluation of site
specific environmental impacts at
attractive sites
Transmission Constraints • Location of new facilities can add to
transmission constraints
• Expand Railbelt transmission
network
• Require that all proposed plant
locations also include transmission
infrastructure analyses and costs as
part of any approval process
Financing • Cost per kW is very significant • Aggressively pursue available
Federal funding for renewable
projects
Regulatory/Legislative • Regional commitment to renewable
resources is uncertain
• Potential future environmental
regulations related to emissions,
including carbon and other emissions
• Establish State RPS targets
• Develop State policies regarding
RECs and Green Pricing
• Monitor Federal legislative and
regulatory activities related to
emission regulations
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-25 February 2010
14.2.3.2.9 Generation Resources – Tidal
Table 14-11
Resource Specific Risks and Issues – Generation – Tidal
Resource: Generation – Tidal
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • Total economic resource potential is
unknown
• Resource potential may be constrained
by Railbelt regional system regulation
requirements
• Complete regional economic
potential assessment, including the
identification of the most attractive
sites
• Develop regional regulation strategy
for non-dispatchable resources
Project Development • Ineffectiveness and inefficiencies
associated with six individual utilities
developing tidal projects
• Lack of standard power purchase
agreements for projects developed by
IPPs
• Significant permitting challenges exist
for large hydro projects
• Public acceptability of tidal is unknown
• Potential for construction cost overruns
is significant
• Technology not fully developed
• Establish a regional entity
(e.g., GRETC) or rely on IPPs to
identify and develop tidal projects
• Develop regional standard power
purchase agreements
• Develop regional competitive power
procurement process to encourage
IPP development of projects
• Work closely with resource
agencies to identify permitting
requirements
• Develop public outreach program to
better determine public acceptability
of tidal
• Implement best practices related to
management of construction costs
• Support research and development
of technology and pilot projects
Fuel Supply • Not applicable • Not applicable
Environmental • Environmental impacts of tidal projects
are potentially significant
• Work closely with resource
agencies to identify environmental
issues
• Conduct necessary studies to
address resource agencies’ issues
and data requirements
Transmission Constraints • Location of new facilities can add to
transmission constraints
• Integration of large tidal facility into
Railbelt transmission grid poses
challenges
• Integration of non-dispatchable
resources into Railbelt transmission
grid poses challenges
• Expand Railbelt transmission
network
• Complete required studies to ensure
the ability to integrate large tidal
projects into the transmission grid
• Require that all proposed plant
locations also include transmission
infrastructure analyses and costs as
part of any approval process
• Develop regional strategy for the
integration of non-dispatchable
resources
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-26 February 2010
Table 14-11 (Continued)
Resource Specific Risks and Issues – Generation – Tidal
Resource: Generation – Tidal
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Financing • Financing requirements of a large tidal
project are greater than the combined
financial capabilities of the Railbelt
utilities
• Formation of a regional G&T entity
(e.g., GRETC) would provide
greater financial capabilities
• Consider alternative forms of State
assistance for large tidal projects
• Aggressively pursue available
Federal funding for renewable
projects
Regulatory/Legislative • Regional commitment to renewable
resources is uncertain
• Establish State RPS targets
• Develop State policies regarding
RECs and Green Pricing
IMPLEMENTATION
SECTION 14 RISKS AND ISSUES
ALASKA RIRP STUDY
Black & Veatch 14-27 February 2010
14.2.3.3 Transmission
Table 14-12
Resource Specific Risks and Issues – Transmission
Resource: Transmission
Risk/Issue Category Description Primary Actions to Address Risk/Issue
Resource Potential • “Resource potential” is not limited;
issue is determining the most
appropriate projects, voltage, and siting
• Implement transmission plan
included in this RIRP
Project Development • Ineffectiveness and inefficiencies
associated with six individual utilities
developing transmission projects
• Potential for construction cost overruns
is significant
• Establish a regional entity
(e.g., GRETC) to identify and
develop transmission projects
• Implement best practices related to
management of construction costs
• Centralize all siting and permitting
at the State level
Fuel Supply • Not applicable • Not applicable
Environmental • Potential for local environmental issues • Pursue statewide permitting by
GRETC
Transmission Constraints • Not applicable • Not applicable
Financing • Financing requirements of transmission
projects are significant
• Formation of a regional G&T entity
(e.g., GRETC) would provide
greater financial capabilities
• Consider alternative forms of State
assistance for transmission projects
Regulatory/Legislative • Siting and permitting issues are
potentially significant
• Develop streamlined siting and
permitting processes for
transmission projects
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-1 February 2010
15.0 CONCLUSIONS AND RECOMMENDATIONS
This section provides an overview of the conclusions and recommendations resulting from the RIRP study.
Purpose and Limitations of the RIRP
• The development of this RIRP is not the same as the development of a State Energy Plan; nor does it set
State policy. Setting energy-related policies is the role of the Governor and State Legislature. With regard
to energy policy making, however, the RIRP does provide a foundation of information and analysis that
can be used by policy makers to develop important policies.
Having said this, the development of a State Energy Policy and or related policies could directly impact
the specific alternative resource plan chosen for the Railbelt region’s future. As such, the RIRP may need
to be readdressed as future energy-related policies are enacted.
• This RIRP, consistent with all integrated resource plans, should be viewed as a “directional” plan. In this
sense, the RIRP identifies alternative resource paths that the region can take to meet the future electric
needs of Railbelt citizens and businesses; in other words, it identifies the types of resources that should be
developed in the future. The granularity of the analysis underlying the RIRP is not sufficient to identify
the optimal configuration (e.g., specific size, manufacturer, model, location, etc.) of specific resources
that should be developed. The selection of specific resources requires additional and more detailed
analysis.
• The alternative resource options considered in this study include a combination of identified projects
(e.g., Susitna and Chakachamna hydroelectric projects, Mt. Spurr geothermal project, etc.), as well as
generic resources (e.g., Generic Hydro – Kenai, Generic Wind – GVEA, generic conventional generation
alternatives, etc.). Identified projects are included, and shown as such, because they are projects that are
currently at various points in the project development lifecycle. Consequently, there is specific capital
cost and operating assumptions available on these projects. Generic resources are included to enable the
RIRP models to choose various resource types, based on capital cost and operating assumptions
developed by Black & Veatch. This approach is common in the development of integrated resource plans.
Consistent with the comment above regarding the RIRP being a “directional” plan, the actual resources
developed in the future, while consistent with the resource type identified, may be: 1) the identified
project shown in the resource plan (e.g., Chakachamna), 2) an alternative identified project of the same
resource type (e.g., Susitna); or 3) an alternative generic project of the same resource type. One reason for
this is the level of risks and uncertainties that exist regarding the ability to plan, permit, and develop each
project. Consequently, when looking at the resource plans shown in this report, it is important to focus on
the resource type of an identified resource, as opposed to the specific project.
• The capital costs and operating assumptions used in this study for alternative DSM/EE, generation and
transmission resources do not consider the actual owner or developer of these resources. Ownership could
be in the form of individual Railbelt utilities, a regional entity, or an independent power producer (IPP).
Depending upon specific circumstances, ownership and development by IPPs may be the least-cost
alternative.
• As with all integrated resource plans, this RIRP should be periodically updated (e.g., every three years) to
identify changes that should be made to the preferred resource plan to reflect changing circumstances
(e.g., resolution of uncertainties), improved cost and performance of emerging technologies (e.g., tidal),
and other developments.
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-2 February 2010
15.1 Conclusions
The primary conclusions from the RIRP study are discussed below.
1. The current situation facing the Railbelt utilities includes a number of challenging issues that place
the region at a historical crossroad regarding the mix of DSM/EE, generation, and transmission
resources that it will rely on to economically and reliably meet the future electric needs of the
region’s citizens and businesses. As a result of these issues, the Railbelt utilities are faced with the
following challenges:
o A transmission network that is isolated and has limited total transfer capabilities and
redundancies.
o The inability of the region to take full advantage of economies of scale due to its limited size.
o A heavy dependence on natural gas from the Cook Inlet for electric generation.
o Limited and declining Cook Inlet gas deliverability.
o Lack of natural gas storage capability.
o The region’s aging generation and transmission infrastructure.
o A heavy reliance on older, inefficient natural gas generation assets.
o The region’s limited financing capability, both individually and collectively among the Railbelt
utilities.
o Duplicative and diffused generation and transmission expertise among the Railbelt utilities.
2. The key factors that drive the results of Black & Veatch’s analysis include the following:
o The risks and uncertainties that exist for all alternative DSM/EE, generation, and transmission
resource options.
o The future availability and price of natural gas.
o The public acceptability and ability to permit a large hydroelectric project which is a greater
concern, based upon Black & Veatch’s discussions with numerous stakeholders, than the
acceptability and ability to permit other types of renewable projects, such as wind and
geothermal.
o Potential future CO2 prices, which would impact all fossil fuels, that may or may not result from
proposed Federal legislation.
o The region’s existing transmission network, which limits: 1) the ability to transfer power between
areas within the region to minimize power costs, and 2) places a maximum limit on the amount of
non-dispatchable resources that can be integrated into the region’s transmission grid.
o The ability of the region to raise the required financing, either by the utilities on their own or
through a regional G&T entity.
o Whether the Railbelt utilities develop a number of currently proposed projects that were selected
outside of a regional planning process.
Figures 15-1 and 15-2 graphically demonstrate how the results of the various reference and sensitivity
cases are impacted by these important uncertainties. Figure 15-1 shows the cumulative present value
cost for each year over the 50-year planning horizon; similarly, Figure 15-2 shows the annual
wholesale power cost (cents/kWh) in 2010 dollars. In both cases, we have shown selected reference
and sensitivity cases to highlight how dependent the results are to these key uncertainties.
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-3 February 2010
Figure 15-1
Cumulative Present Value Cost – Selected Reference and Sensitivity Cases
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
$14,000,000
$16,000,000
2011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059YearCumulative Present Value Cost ($000)Plan 1A/1B 1A/1B With Double DSM/EE Programs 1A/1B Without DSM/EE Programs
1A/1B With High Gas Prices 1A/1B Without CO2 Taxes 1A/1B Without Chakachamna
1A/1B With Susitna (Low Watana Expansion)1A/1B With Committed Units
Figure 15-2
Annual Wholesale Power Cost – Selected Reference and Sensitivity Cases
0.00
5.00
10.00
15.00
20.00
25.002011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059
YearWholesale Power Cost (cents/kWh) - 2010 DollarsPlan 1A/1B Plan 2A
1A/1B With Double DSM/EE Programs 1A/1B Without DSM/EE Programs
1A/1B With High Gas Prices 1A/1B Without CO2 Taxes
1A/1B Without Chakachamna 1A/1B With Susitna (Low Watana Expansion)
1A/1B With Committed Units
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-4 February 2010
As can be seen in Figures 15-1, which shows cumulative net present value costs over the 50-year
planning horizon, the 1A/1B With Susitna (Low Watana Expansion), 1A/1B With no DSM/EE
Programs, 1A/1B Without Chakachamna, 1A/1BWith Committed Units, and 1A/1B With High Gas
Prices Sensitivity Cases are all higher cost than Scenario 1A/1B, in descending order. The 1A/1B
With Double DSM/EE Programs and 1A/1B With No CO2 Taxes Sensitivity Cases are lower cost that
Scenario 1A/1B.
Figure 15-2 shows how significant the uncertainty regarding CO2 taxes is with regard to the results.
It also shows the economic value of achieving higher DSM/EE savings that were assumed in the
Scenario 1A/1B Reference Case if those savings can be achieved. Also, shown is the fact that the
other sensitivity cases are higher cost than Scenario 1A/1B.
3. The resource plans that were developed as part of this study for each Evaluation Scenario include a
diverse portfolio of resources. If implemented, the RIRP will lead to:
o The development of a resource mix resulting from a regional planning process.
o Greater reliance on DSM/EE and renewable resources and a lower dependence on natural gas.
o A more robust transmission network.
o More effective spreading of risks among all areas of the region.
o A greater ability to respond to large load growth should these load increases occur. Stated
another way, the implementation of the RIRP will provide a stronger foundation upon which to
base future economic development efforts.
4. The cost of this greater reliance on DSM/EE and renewable resources is less than the continued heavy
reliance on natural gas based upon the base case gas price forecast that was used in this analysis. This
result is achievable if the region builds a large hydroelectric project. There are uncertainties, at this
point in time, regarding the environmental and/or geotechnical conditions under which a large
hydroelectric project could be built. If a large hydroelectric facility can not be developed, or if the
cost of the large hydroelectric project significantly exceeds the current preliminary estimates, then the
costs associated with a predominately renewable future would be greater than continuing to rely on
natural gas.
5. Our analysis shows that Scenarios 1A and 1B result in the same resources and, consequently, the
same costs and emissions. In other words, the cost of achieving a renewable energy target of
50 percent by 2025 (Scenario 1B) is no greater than the cost of the unconstrained solution
(Scenario 1A). This result applies only if a large hydroelectric project is built.
6. Scenarios 2A and 2B were evaluated to determine what the impact would be if the demand in the
region was significantly greater than it is today. In fact, the per unit power costs were not less than
Scenario 1A/1B due to the cost of Susitna which was the resource chosen to meet this additional
load..
7. Additionally, the implementation of a regional plan will result in lower costs than if the individual
Railbelt utilities continue to go forward on their own. While the scope of this study did not include
the development of separate integrated resource plans for each of the six Railbelt utilities, we did
complete a sensitivity analysis to show the cost impact if the utilities develop their currently proposed
projects (referred to as committed units) that were selected outside of a regional planning process.
The Railbelt utilities are moving forward with these projects due to the existing uncertainty regarding
the formation of GRETC. While this sensitivity case does not fully capture the incremental cost of
the utilities acting independently over the 50-year planning horizon, it does provide an indication of
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-5 February 2010
the relative cost differential. Figure 15-3 shows the resulting total annual costs of the two different
resource plans. In the aggregate, the cost of the Committed Unit Sensitivity Case was approximately
5.6 percent, or $484 million on a cumulative net present value cost basis, higher than Scenario 1A/1B.
The main conclusion to draw from this graphic is that there are significant cost savings associated
with the Railbelt utilities implementing a plan that has been developed to minimize total regional
costs, while ensuring reliable service, as opposed to the individual utilities working separately to meet
the needs of their own customers.
Figure 15-3
Comparison of Results - Scenario 1A/1B Versus Committed Units Sensitivity Case
$0
$2,000,000
$4,000,000
$6,000,000
$8,000,000
$10,000,000
$12,000,000
$14,000,000
$16,000,0002011201320152017201920212023202520272029203120332035203720392041204320452047204920512053205520572059
YearCumulative Present Value Cost ($000)Plan 1A/1B 1A/1B With Committed Units
8. There are a number of risks and uncertainties regardless of the resource options chosen. For example:
1) there is a lack of Alaska-specific data upon which to build an aggressive region-wide DSM/EE
program, 2) the future availability and price of natural gas affects the viability of natural gas
generation, and 3) the total economic potential of various renewable resources is unknown at this
time. In some cases, these risks and uncertainties (e.g., the ability to permit a large hydroelectric
facility) might completely eliminate a particular resource option. Due to these risks and uncertainties,
it will be important for the region to maintain flexibility so that changes to the preferred resource plan
can be made, as necessary, as these resource-specific risks and uncertainties become more clear or get
resolved.
9. Significant investments in the region’s transmission network need to be made within the next 10 years
to ensure the reliable and economic transfer of power throughout the region. Without these
investments, providing economic and reliable electric service will be a greater challenge.
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-6 February 2010
10. The increased reliance on non-dispatchable renewable resources (e.g., wind) will require a higher
level of frequency regulation within the region to handle swings in electric output from these
resources. An increased level of regulation has been included in Black & Veatch’s transmission plan.
Even with this increased regulation, however, the challenges associated with the integration of non-
dispatchable resources will ultimately place a maximum limit on the amount of these resources that
can be developed.
11. The implementation of the RIRP does not require that a regional generation and transmission entity
(e.g., GRETC) be formed. However, the absence of a regional entity with the responsibility for
implementing the RIRP will increase the difficulty of the region’s ability to implement a regional plan
and, in fact, Black & Veatch believes that the lack of a regional entity will, as a practical matter, mean
that the RIRP will not be fully implemented. As a consequence, the favorable outcomes of the RIRP
discussed above would not be realized. The interplay between the formation of a regional entity and
the RIRP is shown in Figure 15-4.
Figure 15-4
Interplay Between GRETC and Regional Integrated Resource Plan
Current
Situation
• Limited redundancy
• Limited economies
of scale
• Dependence on
fossil fuels
• Limited Cook Inlet
gas deliverability
and storage
•Aging G&T
infrastructure
• Inefficient fuel use
• Difficult financing
• Duplicative G&T
expertise
RIRP Study
• Plan that economically
schedules what, when,
and where to build, based
on available fuel and
energy supplies
• 50-year time horizon
• Competes generation,
transmission, fuel supply
and DSM/energy
efficiency options
•Considers CO2 regulation
• Includes renewable
energy projects
• Arrives at a plan to build
future infrastructure for
minimum long-run cost to
ratepayers
•Considers fuel supply
options and risks
RIRP
Results
• Increased
DSM/energy
efficiency
• Increased
renewables
•Reduced
dependence
on natural gas
• Increased
transmission
GRETC - Enabler
REGA Study
Proposed
GRETC
Formation
Future Situation
• Robust transmission
• Diversified fuel supply
• System-wide power rates
• Spread risk
• State financial assistance
• Regional planning
• Wise resource use
• Respond to large load
growth
• Technical resources
• New technologies
10-Year Transition Period
Financing Options
• Pre-funding of capital
requirements
• Commercial bond market
• State financial assistance
(Bradley Lake model)
• Construction-work-in-progress
15.2 Recommendations
This subsection summarizes the overall recommendations arising from this study, broken down into the
following three categories:
• Recommendations – General
• Recommendations – Capital Projects
• Recommendations – Other
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-7 February 2010
15.2.1 Recommendations - General
The following general actions should be taken to ensure the timely implementation of the RIRP:
1. The State should work closely with the utilities and other stakeholders to make a decision regarding
the formation of GRETC and to develop the required governance plan, financial and capital
improvement plan, capital management plan and transmission access plan, and address other matters
related to the formation of the proposed regional entity.
2. The State should establish certain energy-related policies, including:
o The pursuit of large hydroelectric facilities
o DSM/EE program targets
o RPS (i.e., target for renewable resources), and the pursuit of wind, geothermal, and tidal (which
will become commercially mature during the 50-year planning horizon) projects in addition to
large hydroelectric projects; the passage of an RPS would be meaningful as a policy statement
even though the preferred resource plan would achieve a 50 percent renewable level by 2025.
o System benefit charge to fund DSM/EE programs and or renewable projects
3. The State should work closely with the Railbelt utilities and other stakeholders to establish the
specific preferred resource plan. In establishing the preferred resource plan, the economic results of
the various reference cases and sensitivity cases evaluated in this study should be considered, as well
as the environmental impacts discussed in Section 13 and the project-specific risks discussed in
Section 14.
4. Black & Veatch believes that the Scenario 1A/1B resource plan should be the starting point for the
selection of the preferred resource plan as discussed below. Table 15-1 provides a summary of the
specific resources that were selected, based upon economics, in the Scenario 1A/1B resource plan
during the first 10 years.
A project selected in Scenario 1A/1B after the first 10 years especially worthy of mention is the
Chakachamna Hydroelectric Project in 2025.
Another important consideration in the selection of a preferred resource plan is evaluation of the
sensitivity cases evaluated, as presented in Section 13. Issues addressed through the sensitivity cases
and considered in Black & Veatch’s selection of a preferred resource plan include the following and
are discussed in Table 15-2. Following that discussion, Table 15-3 provides a discussion regarding
specific projects currently under development and their impact on the preferred resource plan.
o What if CO2 regulation doesn’t occur?
o What is the effect if the committed units are installed?
o What if Chakachamna doesn’t get developed?
o What would be the impact of the alternative Susitna projects?
There are several projects that are significantly under development and included in the preferred
resource plan. These significantly developed projects include:
o Healy Clean Coal Project (HCCP)
o Southcentral Power Project
o Fire Island Wind Project
o Nikiski Wind Project
These projects are discussed in Table 15-3.
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-8 February 2010
Table 15-1
Resources Selected in Scenario 1A/1B Resource Plan
Project Discussion
DSM/EE Resources The full level of DSM/EE resources evaluated was selected based upon their relative
economics. Sensitivity analysis indicates that even greater levels of DSM/EE may be
cost-effective. The lack of Alaska-specific DSM/EE data causes the exact level of
cost-effective DSM/EE to remain uncertain.
Nikiski Wind The RIRP selected this project in the initial year. It is being developed as an IPP
project and is well along in the development process. The ARRA potentially offers
significant financial incentives if this project is completed by January 1, 2013. These
incentives could further improve its competitiveness. As a wind unit, it has no impact
on planning reserves, but contributes to renewable generation.
HCCP HCCP is completed and GVEA has negotiated with AIDEA for its purchase. This
project was selected in the initial year of the plan.
Fire Island Wind Project The Fire Island Wind Project is being developed as an IPP project with proposed
power purchase agreements provided to the Railbelt utilities. The project may be able
to benefit significantly from ARRA and the $25 million grant from the State for
interconnection. This project was selected in 2012.
Anchorage 1x1 6FA Combined
Cycle
The RIRP selected this unit for commercial operation in 2013. This unit is very
similar in size and performance to the Southcentral Power Project being developed as
a joint ownership project by Chugach and ML&P for 2013 commercial operation.
The project appears well under development with the combustion turbines already
under contract. The project fits well with the RIRP and the joint ownership at least
partially reflects the GRETC joint development concept.
Glacier Fork Hydroelectric
Project
The RIRP selected this project for commercial operation in 2014, the first year that it
was available for commercial operation in the models. Of the large hydroelectric
projects, Glacier Fork is by far the least developed. Glacier Fork has very limited
storage and thus does not offer the system operating flexibility of the other large
hydroelectric units. There is also significant uncertainty with respect to its capital
cost and ability to be licensed. Because it has such a minimal level of firm generation
in the winter, it does not contribute significantly to planning reserves, but does
contribute about 6 percent of the renewable energy to the Railbelt. Detailed
feasibility studies and licensing are required to advance this option.
Anchorage and GVEA MSW
Units
The RIRP selected these units in 2015 and 2017. Historically, mass burn MSW units
such as those modeled, have faced significant opposition due to emissions of
mercury, dioxin, and other pollutants. Other technologies which result in lower
emissions, such as plasma arc, are not commercially demonstrated. The units
included in the RIRP are relatively small (26 MW in total) and are not required to be
installed to meet planning reserve requirements, but their base load nature contributes
nearly 4 percent of the renewable energy. Detailed feasibility studies would be
required to advance this alternative.
GVEA North Pole Retrofit The retrofitting of GVEA’s North Pole combined cycle unit with a second train using
a LM6000 combustion turbine and heat recovery steam generator was selected in
2018 coincident with the assumption of the availability of natural gas to GVEA. The
retrofit takes advantage of capital and operating cost savings resulting from the
existing installation.
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-9 February 2010
Table 15-1 (Continued)
Resources Selected in Scenario 1A/1B Resource Plan
Project Discussion
Mt. Spurr Geothermal Project The first unit at Mt. Spurr was selected in 2020. Mt. Spurr’s developer, Ormat,
currently has commercial operation scheduled for 2017. Significant development
activity remains for the project including verifying the geothermal resource. Mt.
Spurr will also require significant infrastructure development including access roads
and transmission lines. This infrastructure may correspond to similar infrastructure
development required for Chakachamna which is selected in 2025 in the RIRP. As
the implementation of the RIRP unfolds, there will likely be the need to adjust the
timing of the resource additions following the implementation of the initial projects.
Table 15-2
Impact of Selected Issues on the Preferred Resource Plan
Issue Discussion
CO2 Regulation The sensitivity case for Scenario 1A without CO2 regulation selects
the Anchorage LMS 100 project instead of Fire Island and Mt. Spurr
in the first 10 years.
Committed Units Installation of the committed units significantly increases the cost of
Scenario 1A/1B. In addition to the committed units, this plan selects
five wind units from 2016 through 2024 in response to CO2
regulation. The plan with the committed units eliminates
Chakachamna and does not meet the 50 percent renewable target by
2025.
Chakachamna Chakachamna could fail to develop because of licensing or technical
issues. Also, if the cost of Chakachamna were to increase to be
equivalent to the alternative Susitna projects on a GWh basis, it would
not be selected. The sensitivity case without Chakachamna for the
first 10 years is identical to Scenario 1A/1B. The case does not meet
the 50 percent renewable target by 2025 and is 5.2 percent higher in
cost than the preferred resource plan.
Susitna None of the alternative Susitna projects are selected in the
Scenario 1A/1B resource plan. The least cost Susitna option, which is
Low Watana Expansion, is 15.3 percent more than the preferred
resource plan and 9.0 percent more than the case without
Chakachamna. The 50 percent renewable requirement can not be met
without Susitna if Chakachamna is not available.
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-10 February 2010
Table 15-3
Projects Significantly Under Development
Project Discussion Preferred Resource Plan Recommendation
HCCP HCCP is completed and GVEA has negotiated with
AIDEA for its purchase. The project is part of the
least cost scenario. While CO2 regulation has been
assumed in the RIRP, those regulations are not in
place and there is no absolute assurance that they
will be in place or what the costs from the
regulations will be. HCCP adds further fuel
diversity to the Railbelt, especially to GVEA who
doesn’t currently have access to natural gas. As a
steam unit, HCCP improves transmission system
stability.
Black & Veatch recommends that HCCP be
included in the preferred resource plan.
Southcentral
Power Project
The Southcentral Power Project is well under
development with the combustion turbines
purchased. The timing and technology are
generally consistent with the preferred resource
plan. The project will improve the efficiency of
natural gas generation in the Railbelt and permit the
retirement of aging units.
Black & Veatch recommends the continued
development of the Southcentral Power Project
as part of the preferred resource plan.
Fire Island
Wind Project
The Fire Island Wind Project is being developed as
an IPP project with proposed power purchase
agreements provided to the Railbelt utilities. The
project may be able to benefit significantly from
ARRA and the $25 million grant from the State for
interconnection. This project is part of the least
cost plan and provides renewable energy to the
Railbelt system. Issues with interconnection and
regulation will need to be resolved.
Subject to the successful negotiation of a
purchase power agreement and successful
negotiation of the interconnection and
regulation issues, Black & Veatch recommends
that it be part of the preferred resource plan in a
time frame that allows for the ARRA benefits
to be captured.
Nikiski Wind
Project
The Nikiski Wind Project is an IPP project like Fire
Island and has the same potential to benefit from
ARRA. It is also part of the least cost plan.
Like Fire Island, subject to successful
negotiation of a purchase power agreement and
successful negotiation of the interconnection
and regulation issues, Black & Veatch
recommends that it be part of the preferred
resource plan in a time frame that allows for the
ARRA benefits to be captured.
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-11 February 2010
In addition to these resources, Black & Veatch believes that Mt. Spurr, Glacier Fork, Chakachamna
and Susitna should be pursued further to the point that the uncertainties regarding the environmental,
geotechnical and capital cost issues become adequately resolved to determine if any of the projects
could actually be built.
In the case of the Mt. Spurr Geothermal Project, exploration should continue to determine the extent
and characteristics of the geothermal resource at the site.
In the case of Susitna, the primary focus should be on completing engineering studies to optimize the
size and minimize the costs of the project. In the case of Glacier Fork and Chakachamna, the
additional work should look for “fatal flaws”.
Additionally, further analysis needs to be completed relative to integrating wind and other non-
dispatchable renewable resources into the transmission network.
5. The State and Railbelt utilities should develop a public outreach program to inform the general public
regarding the preferred resource plan, including the costs and benefits.
6. The State Legislature should make decisions regarding the level and form of State financial assistance
that will be provided to assist the Railbelt utilities and AEA, under a unified regional G&T entity
(i.e., GRETC), develop the generation resources and transmission projects identified in the preferred
resource plan.
7. The electric utilities, various State agencies, Enstar and Cook Inlet producers need to work more
closely together to address short-term and long-term gas supply issues. Specific actions that should
be taken include:
o Development of local gas storage capabilities with open access among all market participants as
soon as possible.
o Undertake efforts to secure near-term LNG supplies to ensure adequate gas over the 10-year
transition period until additional gas supplies can be secured either in the Cook Inlet, from the
North Slope or from long-term LNG supplies.
o The State should complete a detailed cost and risk evaluation of available long-term gas supply
options to determine the best options. Once the most attractive long-term supplies of natural gas
have been identified, detailed engineering studies and permitting activities should be undertaken
to secure these resources.
o Appropriate commercial terms and pricing structures should be established through State and
regulatory actions to provide producers with the incentive to increase exploration for additional
gas supplies in the Cook Inlet or nearby basins. This action is required to provide the necessary
long-term contractual certainty to result in additional exploration and development.
15.2.2 Recommendations – Capital Projects
Efforts should be undertaken to begin the development, including detailed engineering and permitting
activities, of the following capital projects, which are included in Black & Veatch’s recommended preferred
resource plan.
1. Develop a comprehensive region-wide portfolio of DSM/EE programs.
2. Generation projects:
o Projects under development (HCCP, Southcentral Power Project, Fire Island Wind Project, and
Nikiski Wind Project)
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-12 February 2010
o Glacier Fork Hydroelectric Project
o Generic Anchorage MSW Project
o Generic GVEA MSW Project
o GVEA North Pole Retrofit Project
o Mt. Spurr Geothermal Project
o Chakachamna Hydroelectric Project
o Susitna Hydroelectric Project
3. Transmission and related substation projects, including the following projects which have been
identified for priority attention because of their immediate impact on the reliability of the existing
system. These projects are estimated to be required within the next five years.
o Soldotna to Quartz Creek Transmission Line ($84 million – Project B)
o Quartz Creek to University Transmission Line ($112.5 million – Project C)
o Douglas to Teeland Transmission Line ($37.5 million – Project D)
o Lake Lorraine to Douglas Transmission Line ($80 million – Project E)
o SVCs ($25 million - Other Reliability Projects)
o Funds to undertake the study of the Southern Intertie ($1 million)
o Funds to investigate the provision of regulation that will facilitate the integration of renewable
energy projects into the Railbelt system ($50 million, including cost of BESS – Other Reliability
Projects)
15.2.3 Recommendations - Other
Other actions, related to the implementation of the RIRP, that should be undertaken include:
1. The State Legislature should appropriate funds for the initial stages of the development of a regional
DSM/EE program, including 1) region-wide residential and commercial end-use saturation surveys,
2) residential and commercial customer attitudinal surveys, 3) vendor surveys, 4) comprehensive
evaluation of economically achievable potential, and 5) detailed DSM/EE program design efforts.
2. Develop a regional DSM/EE program measurement and evaluation protocol.
3. If GRETC is not formed, some type of a regional entity should be formed to develop and deliver
DSM/EE programs to residential and commercial customers throughout the Railbelt region, in close
coordination with the Railbelt utilities.
4. Likewise, if GRETC is not formed, some type of a regional entity should be formed to develop the
renewable resources included in the preferred resource plan.
5. Establish close coordination between the Railbelt electric utilities, Enstar and AHFC regarding the
development and delivery of DSM/EE programs.
6. Aggressively pursue available Federal funding for DSM/EE programs and renewable projects.
7. Further development of tidal power should be encouraged due to its resource potential in the Railbelt
region. Although this technology is not commercially available, in Black & Veatch’s opinion, at this
point in time, it has the potential to be economic within the planning horizon.
8. The State and Railbelt utilities should work closely with resource agencies to identify environmental
issues and permitting requirements related to large hydroelectric and tidal projects, and conduct the
necessary studies to address these issues and requirements.
9. Complete a regional economic potential assessment, including the identification of the most attractive
sites, for all renewable resources included in the preferred resource plan.
CONCLUSIONS AND
SECTION 15 RECOMMENDATIONS
ALASKA RIRP STUDY
Black & Veatch 15-13 February 2010
10. Develop streamlined siting and permitting processes for transmission projects.
11. Develop a regional frequency regulation strategy for non-dispatchable resources.
12. Develop a regional competitive power procurement process and a standard power purchase agreement
to provide IPPs an equal opportunity to submit qualified proposals to develop specific projects.
13. Federal legislative and regulatory activities, including those related to emissions regulations, should
be monitored closely and influenced to the degree possible.
14. Monitor the licensing progress of small modular nuclear units.
NEAR-TERM IMPLEMENTATION
SECTION 16 ACTION PLAN (2010-2012)
ALASKA RIRP STUDY
Black & Veatch 16-1 February 2010
16.0 NEAR-TERM IMPLEMENTATION ACTION PLAN (2010-2012)
The purpose of this section is to provide Black & Veatch’s recommended near-term implementation plan,
covering the period from 2010 to 2012. Our recommended actions are grouped into the following categories:
• General actions
• Capital projects
• Supporting studies and activities
• Other actions
In many ways, the near-term implementation plan shown in the following tables serves two objectives. First,
it identifies the steps that should be taken during the next three years regardless of the alternative resource
plan that is chosen as the preferred resource plan. Second, it is intended to maintain flexibility as the
uncertainties and risks associated with each alternative resource become more clear and or resolved.
16.1 General Actions
Table 16-1
Near-Term Implementation Action Plan – General Actions
Actions
Category Description Timeline Est. Cost
General Actions • The State should work closely with the utilities and other
stakeholders to make a decision regarding the formation of
GRETC and to develop the required governance plan,
financial and capital improvement plan, capital
management plan and transmission access plan, and
address other matters related to the formation of the
proposed regional entity
2010 $6.8 million
• Establish State energy-related policies regarding:
o The pursuit of large hydroelectric facilities
o DSM/EE program targets
o RPS (i.e., target for renewable resources), and the
pursuit of wind, geothermal, and tidal projects
o System benefit charge to fund DSM/EE programs and
or renewable projects
2010-2011 $0.2 million
• The State should work closely with the Railbelt utilities
and other stakeholders to establish the preferred resource
plan, using the Scenario 1A/1B resource plan as the
starting point
2010 Not
applicable
• Mt. Spurr, Glacier Fork, Chakachamna and Susitna should
be pursued further to the point that the uncertainties
regarding the environmental, geotechnical and capital cost
issues become adequately resolved to determine if any of
these projects could actually be built
2010-2011 To be
determined
NEAR-TERM IMPLEMENTATION
SECTION 16 ACTION PLAN (2010-2012)
ALASKA RIRP STUDY
Black & Veatch 16-2 February 2010
Table 16-1 (Continued)
Near-Term Implementation Action Plan – General Actions
Actions
Category Description Timeline Est. Cost
• Develop a public outreach program to inform the public
regarding the preferred resource plan, including the costs
and benefits
2010-2011 $0.1 million
• The State Legislature should make decisions regarding the
level and form of State financial assistance that will be
provided to assist the Railbelt utilities and AEA, under a
unified regional G&T entity (i.e., GRETC), develop the
generation resources and transmission projects identified
in the preferred resource plan
2010-2011 Not
applicable
• The electric utilities, various State agencies, Enstar and
Cook Inlet producers need to work more closely together
to address short-term and long-term gas supply issues;
specific actions that should be taken include:
o Development of local gas storage capabilities as soon
as possible
o Undertake efforts to secure near-term LNG supplies
to ensure adequate gas over the 10-year transition
period until additional gas supplies can be secured
o The State should complete a detailed cost and risk
evaluation of available long-term gas supply options
to determine the best options; once the most attractive
long-term supplies of natural gas have been identified,
detailed engineering studies and permitting activities
should be undertaken to secure these resources
o Appropriate commercial terms and pricing structures
should be established through State and regulatory
actions to provide producers with the incentive to
increase exploration for additional gas supplies in the
Cook Inlet or nearby basins
2010-2012 To be
determined
NEAR-TERM IMPLEMENTATION
SECTION 16 ACTION PLAN (2010-2012)
ALASKA RIRP STUDY
Black & Veatch 16-3 February 2010
16.2 Capital Projects
Table 16-2
Near-Term Implementation Action Plan – Capital Projects
Actions
Category Description Timeline Est. Cost
Capital Projects • Develop a comprehensive region-wide portfolio of
DSM/EE programs within first six years
2011-2016 $34 million
• Begin detailed engineering and permitting activities
associated with the generation projects identified in the
initial years of the preferred resource plan, including:
o Projects under development (HCCP, Southcentral
Power Project, Fire Island Wind Project, and Nikiski
Wind Project)
o Glacier Fork Hydroelectric Project
o Generic Anchorage MSW Project
o Generic GVEA MSW Project
o GVEA North Pole Retrofit Project
o Mt. Spurr Geothermal Project
o Chakachamna Hydroelectric Project
o Susitna Hydroelectric Project
2011-2016 Varies by
project
• Begin detailed engineering and permitting activities
associated with the transmission projects identified in the
initial years of the preferred resource plan, including:
o Soldotna to Quartz Creek Transmission Line
($84 million – Project B)
o Quartz Creek to University Transmission Line
($112.5 million – Project C)
o Douglas to Teeland Transmission Line ($37.5 million
– Project D)
o Lake Lorraine to Douglas Transmission Line
($80 million – Project E)
o SVCs ($25 million - Other Reliability Projects)
o Funds to undertake the study of the Southern Intertie
($1 million)
o Funds to investigate the provision of regulation that
will facilitate the integration of renewable energy
projects into the Railbelt system ($50 million,
including cost of BESS – Other Reliability Projects)
2011-2016 Varies by
project
NEAR-TERM IMPLEMENTATION
SECTION 16 ACTION PLAN (2010-2012)
ALASKA RIRP STUDY
Black & Veatch 16-4 February 2010
16.3 Supporting Studies and Activities
Table 16-3
Near-Term Implementation Action Plan – Supporting Studies and Activities
Actions
Category Description Timeline Est. Cost
Supporting
Studies and
Activities
• The State Legislature should appropriate funds for the
initial stages of the development of a regional DSM/EE
program, including 1) region-wide residential and
commercial end-use saturation surveys, 2) residential and
commercial customer attitudinal surveys, 3) vendor
surveys, 4) comprehensive evaluation of economically
achievable potential, and 5) detailed DSM/EE program
design efforts
2010-2011 $1.0 million
• Develop a regional DSM/EE program measurement and
evaluation protocol
2012 $0.1 million
• The State and Railbelt utilities should work closely with
resource agencies to identify environmental issues and
permitting requirements related to large hydroelectric and
tidal projects
2010-2011 $0.2 million
• Conduct necessary studies to address resource agencies’
issues and data requirements related to large hydroelectric
and tidal projects
2011-2012 To be
determined
• Complete a regional economic potential assessment,
including the identification of the most attractive sites, for
all renewable projects included in the preferred resource
plan
2010-2012 $1.5 million
• Develop a regional frequency regulation strategy for non-
dispatchable resources
2011 $0.5 million
• Develop a regional standard power purchase agreement
for IPP-developed projects
2011-2012 $0.2 million
• Develop a regional competitive power procurement
process to encourage IPP development of projects
included in the preferred resource plan
2011-2012 $0.2 million
NEAR-TERM IMPLEMENTATION
SECTION 16 ACTION PLAN (2010-2012)
ALASKA RIRP STUDY
Black & Veatch 16-5 February 2010
16.4 Other Actions
Table 16-4
Near-Term Implementation Action Plan – Other Actions
Actions
Category Description Timeline Est. Cost
Other Actions • Form a regional entity (if GRETC is not formed) to
develop and deliver DSM/EE programs to residential and
commercial customers throughout the Railbelt region, in
close coordination with the Railbelt utilities
2010-2011 Subject to
decision
regarding
formation of
GRETC
• Establish close coordination between the Railbelt electric
utilities, Enstar and AHFC regarding the development and
delivery of DSM/EE programs
2010-2011 $0.2 million
• Aggressively pursue available Federal funding for
DSM/EE programs
2010-2011 $0.2 million
• Form a regional entity (if GRETC is not formed) and
encourage IPPs to identify and develop renewable projects
that are included in the preferred resource plan
2011-2012 Subject to
decision
regarding
formation of
GRETC
• Further encourage the development of tidal power Ongoing To be
determined
• Monitor, and influence to the degree possible, Federal
legislative and regulatory activities, including those related
to emissions regulations
Ongoing Not
applicable
• Aggressively pursue available Federal funding for
renewable projects
2010-2012 $0.2 million
• Develop streamlined siting and permitting processes for
transmission projects
2010-2011 $0.5 million
• Monitor the licensing progress of small modular nuclear
units
Ongoing Not
applicable
APPENDIX A SUSITNA ANALYSIS
ALASKA RIRP STUDY
Black & Veatch A-1 February 2010
APPENDIX A
SUSITNA ANALYSIS
Susitna Hydroelectric Project
Conceptual Alternatives Design Report
Final Draft
Prepared for:
Alaska Energy Authority
813 West Northern Lights Boulevard
Anchorage, Alaska 99503
Prepared by:
HDR Alaska, Inc.
2525 C Street, Suite 305
Anchorage, AK 99503
November 23, 2009
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Contents
1 Executive Summary ........................................................................................................................... 1
2 Background ......................................................................................................................................... 5
2.1 Project Scope ............................................................................................................................. 5
3 Preliminary Energy Estimate ............................................................................................................ 6
3.1 Hydrologic Analysis .................................................................................................................. 6
3.2 Evaluation of Firm Winter Capacities and Average Annual Energy ........................................ 7
3.3 Model Assumptions and Data Sources ...................................................................................... 8
3.4 Model Operation ........................................................................................................................ 9
4 Estimates of Probable Project Development Costs ....................................................................... 13
4.1 Original Cost Estimate ............................................................................................................ 13
4.2 Expandability .......................................................................................................................... 13
4.3 Quantities ................................................................................................................................ 14
4.4 Unit Costs ................................................................................................................................ 15
4.5 Indirect Costs ........................................................................................................................... 16
4.6 Interest During Construction and Financing Costs ................................................................. 16
4.7 Changes from 1983 Design ..................................................................................................... 16
4.7.1 Camps .......................................................................................................................... 16
4.7.2 Access .......................................................................................................................... 16
4.7.3 Transmission ................................................................................................................ 17
4.8 Conclusions ............................................................................................................................. 17
5 Project Development Schedule ........................................................................................................ 19
6 Project Development Issues ............................................................................................................. 21
6.1 Engineering ............................................................................................................................. 21
6.2 Siltation ................................................................................................................................... 21
6.3 Seismicity ................................................................................................................................ 21
6.4 Climate Change ....................................................................................................................... 21
6.5 Environmental Issues .............................................................................................................. 21
6.5.1 Fisheries Impacts ......................................................................................................... 22
6.5.2 Botanical Impacts ........................................................................................................ 22
6.5.3 Wildlife Impacts .......................................................................................................... 23
6.5.4 Cultural Resource Impacts ........................................................................................... 23
6.5.5 Carbon Emissions ........................................................................................................ 23
7 References ......................................................................................................................................... 25
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Tables
Table 1 - Susitna Summary ............................................................................................................. 2
Table 2 - Summary of Susitna Project Alternatives ........................................................................ 9
Table 3 - Firm Capacity and Energy Estimates ............................................................................ 10
Table 4 - Estimated Total Fill Volumes ........................................................................................ 14
Table 5 - Watana Water Conduit and Powerhouse Size Parameters ............................................ 15
Table 6 - Alternate Project Configuration Cost Summary Table (Millions of US Dollars) ......... 18
Table 7 - Power Generation Time Estimates ................................................................................ 20
Figures
Figure 1 - Susitna River Hydrologic Variation ............................................................................... 7
Figure 2 - Firm Capacity ............................................................................................................... 11
Figure 3 - Watana Dam Configurations ........................................................................................ 13
Figure 4 - Proposed Access Route ................................................................................................ 17
Appendices
Appendix A Energy Analysis Input and Results
Appendix B Detailed Cost Estimates
Appendix C Detailed Schedules
Appendix D Climate Change Analyses
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1 Executive Summary
A hydroelectric project on the Susitna River has been studied for more than 50 years and is again
being considered by the State of Alaska as a long term source of energy. In the 1980s, the project
was studied extensively by the Alaska Power Authority (APA) and a license application was
submitted to the Federal Energy Regulatory Commission (FERC). Developing a workable
financing plan proved difficult for a project of this scale. When this existing difficulty was
combined with the relatively low cost of gas-fired electricity in the Railbelt and the declining
price of oil throughout the 1980s, and its resulting impacts upon the State budget, the APA
terminated the project in March 1986.
In 2008, the Alaska State Legislature authorized the Alaska Energy Authority (AEA) to perform
an update of the project. That authorization also included a Railbelt Integrated Resource Plan
(RIRP) to evaluate the ability of this project and other sources of energy to meet the long term
energy demand for the Railbelt region of Alaska. Renewable hydroelectric power is of particular
interest to the railbelt because of its potential to provide stable power costs for the region. Of all
the renewable resources in the railbelt region, the Susitna projects are the most advanced and
best understood.
HDR was contracted by AEA to update the cost estimate, energy estimates and the project
development schedule for a Susitna River hydroelectric project. This report summarizes the
results of that study. The initial alternatives reviewed were based upon the 1983 FERC license
application and subsequent 1985 amendment which presented several project alternatives:
Watana. This alternative consists of the construction of a large storage reservoir on the
Susitna River at the Watana site with an 885-foot-high rock fill dam and a six-unit
powerhouse with a total installed capacity of 1,200 megawatts (MW).
Low Watana Expandable. This alternative consists of the Watana dam constructed to a
lower height of 700 feet and a four-unit powerhouse with a total installed capacity of
600 MW. This alternative contains provisions that would allow for future raising of the
dam and expansion of the powerhouse.
Devil Canyon. This alternative consists of the construction of a 646-foot-high concrete
dam at the Devil Canyon site with a four-unit powerhouse with a total installed capacity
of 680 MW.
Watana/Devil Canyon. This alternative consists of the full-height Watana development
and the Devil Canyon development as presented in the 1983 FERC license application.
The two dams and powerhouses would be constructed sequentially without delays. The
combined Watana/Devil Canyon development would have a total installed capacity of
1,880 MW.
Staged Watana/Devil Canyon. This alternative consists of the Watana development
constructed in stages and the Devil Canyon development as presented in the 1985 FERC
amendment. In stage one the Watana dam would be constructed to the lower height and
the Watana powerhouse would only have 4 out of the 6 turbine generators installed, but
would be constructed to the full sized powerhouse. In stage two the Devil Canyon dam
and powerhouse would be constructed. In stage three the Watana dam would be raised to
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its full height, the existing turbines upgraded for the higher head, and the remaining 2
units installed. At completion, the project would have a total installed capacity of
1,880 MW.
As the RIRP process defined the future railbelt power requirement it became evident that lower
cost hydroelectric project alternatives, that were a closer fit to the energy needs of the railbelt,
should be sought. As such, the following single dam configurations were also evaluated:
Low Watana Non-Expandable. This alternative consists of the Watana dam constructed
to a height of 700 feet, along with a powerhouse containing 4 turbines with a total
installed capacity of 600 MW. This alternative has no provisions for future expansion.
Lower Low Watana. This alternative consists of the Watana dam constructed to a
height of 650 feet along with a powerhouse containing 3 turbines with a total installed
capacity of 390 MW. This alternative has no provisions for future expansion.
High Devil Canyon. This alternative consists of a roller-compacted concrete (RCC) dam
constructed to a height of 810 feet, along with a powerhouse containing 4 turbines with a
total installed capacity of 800 MW.
Watana RCC. This alternative consists of a RCC Watana dam constructed to a height of
885 feet, along with a powerhouse containing 6 turbines with a total installed capacity of
1,200 megawatts (MW).
The results of this study are summarized in Table 1.
Table 1 - Susitna Summary
Alternative Dam Type
Dam
Height
(feet)
Ultimate
Capacity
(MW)
Firm
Capacity,
98%
(MW)
Construction
Cost
($ Billion)
Energy
(GWh/yr)
Schedule
(years from
start of
licensing)
Lower Low
Watana Rockfill 650 390 170 $4.1 2,100 13-14
Low Watana Non-
expandable Rockfill 700 600 245 $4.5 2,600 14-15
Low Watana
Expandable Rockfill 700 600 245 $4.9 2,600 14-15
Watana Rockfill 885 1,200 380 $6.4 3,600 15-16
Watana RCC RCC 885 1,200 380 $6.6 3,600 15-16
Devil Canyon Concrete Arch 646 680 75 $3.6 2,700 14-15
High Devil Canyon RCC 810 800 345 $5.4 3,900 13-14
Watana/Devil
Canyon
Rockfill/Concrete
Arch 885/646 1,880 710 $9.6 7,200 15-20
Staged
Watana/Devil
Canyon
Rockfill/Concrete
Arch 885/646 1,880 710 $10.0 7,200 15-24
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In all cases, the ability to store water increases the firm capacity over the winter. Projects
developed with dams in series allow the water to be used twice. However, because of their
locations on the Susitna River, not all projects can be combined. The Devil Canyon site
precludes development of the High Devil Canyon site but works well with Watana. The High
Devil Canyon site precludes development of Watana but could potentially be paired with other
sites located further upstream.
Development of any of the alternatives for the Susitna River will require careful consideration of
many factors. Environmental issues, climate change and sedimentation are discussed in this
report and the risk associated with these issues is considered manageable. An updated evaluation
of seismicity has been done by others and this risk is also considered manageable.
Hydroelectric power has many economic and environmental benefits including long-term rate
stabilization. Because the cost of the water (fuel) is essentially free and maintenance costs are
minimal, the cost per kilowatt hour is driven largely by the project finance terms and is not
subject to fluctuations in fuel cost.
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2 Background
The Susitna River has its headwaters in the mountains of the Alaska Range about 90 miles south
of Fairbanks. It flows generally southwards for 317 miles before discharging into Cook Inlet just
west of Anchorage. Contained entirely within the south central Railbelt region, the Susitna River
is situated between the two largest Alaska population centers of Anchorage and Fairbanks.
The Bureau of Reclamation first studied the Susitna River’s hydroelectric potential in the early
1950s, with a subsequent review by Corps of Engineers in the 1970s. In 1980, the Alaska Power
Authority (APA; now the Alaska Energy Authority) commissioned a comprehensive analysis to
determine whether hydroelectric development on the Susitna River was viable. Based on those
studies, the APA submitted a license application to the Federal Energy Regulatory
Commission (FERC) in 1983 for the Watana/Devil Canyon project on the Susitna River. The
license application was amended in 1985 for the construction of the Staged Watana/Devil
Canyon project at an estimated cost of $5.4 billion (1985 dollars).
Developing a workable financing plan proved difficult for a project of this scale. When this
existing difficulty was combined with the relatively low cost of gas-fired electricity in the
Railbelt and the declining price of oil throughout the 1980s, and its resulting impacts upon the
State budget, the APA terminated the project in March 1986.
At that point, the State of Alaska had appropriated approximately $227 million to the project
from FY79-FY86, of which the project had expended $145 million to fund extensive field work,
biological studies, and activities to support the FERC license application. Though the APA
concluded that project impacts were manageable, the license application was withdrawn and the
project data and reports were archived to be available for reconsideration sometime in the future.
In 2008, the Alaska State Legislature, in the FY 2009 capital budget, authorized the AEA to
reevaluate the Susitna Hydro Project as it was conceived in 1985. The authorization also
included funding a Railbelt Integrated Resource Plan (RIRP) to evaluate various sources of
electrical power to satisfy the long term energy needs for the Railbelt portion of Alaska. A
Susitna River hydroelectric project could play a significant role in meeting these needs.
2.1 Project Scope
The scope of this study was to collect and review pertinent information from the original studies
and license application from the 1980’s and re-estimate the project energy, costs and
development schedule.
The initial 1982 FERC license application and subsequent 1985 amendment analyzed several
project alternatives:
Watana. This alternative consists of the construction of a large storage reservoir on the
Susitna River at the Watana site with an 885-foot-high rock fill dam and a six-unit
powerhouse with a total installed capacity of 1,200 megawatts (MW).
Low Watana Expandable. This alternative consists of the Watana dam constructed to a
lower height of 700 feet and a four-unit powerhouse with a total installed capacity of
600 MW. This alternative contains provisions that would allow for future raising of the
dam and expansion of the powerhouse.
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Devil Canyon. This alternative consists of the construction of a 646-foot-high concrete
dam at the Devil Canyon site with a four-unit powerhouse with a total installed capacity
of 680 MW.
Watana/Devil Canyon. This alternative consists of the full-height Watana development
and the Devil Canyon development as presented in the 1983 FERC license application.
The two dams and powerhouses would be constructed sequentially without delays. The
combined Watana/Devil Canyon development would have a total installed capacity of
1,880 MW.
Staged Watana/Devil Canyon. This alternative consists of the Watana development
constructed in stages and the Devil Canyon development as presented in the 1985 FERC
amendment. In stage one the Watana dam would be constructed to the lower height and
the Watana powerhouse would only have 4 out of the 6 turbine generators installed, but
would be constructed to the full sized powerhouse. In stage two the Devil Canyon dam
and powerhouse would be constructed. In stage three the Watana dam would be raised to
its full height, the existing turbines upgraded for the higher head, and the remaining 2
units installed. At completion, the project would have a total installed capacity of
1,880 MW.
As the RIRP process defined the future railbelt power requirement it became evident that lower
cost hydroelectric project alternatives, that were a closer fit to the energy needs of the railbelt,
should be sought. As such, the following single dam configurations were also evaluated:
Low Watana Non-Expandable. This alternative consists of the Watana dam constructed
to a height of 700 feet, along with a powerhouse containing 4 turbines with a total
installed capacity of 600 MW. This alternative has no provisions for future expansion.
Lower Low Watana. This alternative consists of the Watana dam constructed to a
height of 650 feet along with a powerhouse containing 3 turbines with a total installed
capacity of 390 MW. This alternative has no provisions for future expansion.
High Devil Canyon. This alternative consists of a roller-compacted concrete (RCC) dam
constructed to a height of 810 feet, along with a powerhouse containing 4 turbines with a
total installed capacity of 800 MW.
Watana RCC. This alternative consists of a RCC Watana dam constructed to a height of
885 feet, along with a powerhouse containing 6 turbines with a total installed capacity of
1,200 megawatts (MW).
Preliminary energy, cost, and schedule estimates for the analyzed alternatives are described in
the following sections.
3 Preliminary Energy Estimate
3.1 Hydrologic Analysis
At the time the original study was issued in 1983 the hydrologic record contained data from 1950
to 1981. To develop an updated energy estimate for the Susitna hydroelectric project
alternatives, a synthesized hydroelectric record for each site was created by a drainage area
proration of daily flow data from United States Geological Survey (USGS) gage 1529000 at
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Gold Creek. USGS gage 1529000 has a period of record from water year 1950-1996 and 2002-
2008.
The hydrology of the upper Susitna Basin is dominated by melt water from snow and glaciers in
the spring and summer, and substantial freezing during the winter months. As a result, a majority
of the flow occurs between mid-April and mid-October. The following figure shows the average
monthly flow at the Watana dam site for each year of record.
Figure 1 - Susitna River at Watana Hydrologic Variation
The manner in which precipitation and runoff might be affected by the impacts of either natural
variability and/or potential climate change is discussed at the end of this report.
3.2 Evaluation of Firm Winter Capacities and Average Annual Energy
The amount of energy that can be produced from hydroelectric projects is a function of the
amount of available water and in the case of storage projects, how the available water can be
regulated (systematically released). For the RIRP evaluation process, in addition to the average
annual energy, the firm capacity attainable during winter months is of particular importance. For
hydroelectric projects, the firm capacity is almost always lower than the installed generation
capacity for a project. For the purposes of this study work, firm capacity is defined as:
“The amount of power the project can generate on a continuous
basis from Nov. 1 through April 30 with 100% reliability”.
The firm capacity is always driven by low periods in the hydrologic cycle. Since the hydrologic
cycle varies, it is also desired to know at what level of reliability the project can generate at
levels higher than the firm capacity. It should be noted that this is only one manner of
regulation. The water can be regulated in a variety of different means in order to achieve other
objectives, such as peaking, spinning reserve or backup capacity.
For this study, the average annual energy and winter plant capacities for the alternatives were
estimated using a HDR proprietary energy modeling software tool customized for this particular
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purpose (Computer Hydro-Electric Operations and Planning Software or (CHEOPS)). Major
assumptions used in the modeling efforts are presented below.
3.3 Model Assumptions and Data Sources
Inflow hydrology was based upon USGS gage #1529000 located at Gold Creek on the
Susitna River and scaled by a drainage area correction factor representing each of the
dam sites.
Reservoir capacity and area curves for the Watana and Devil Canyon alternatives were
based on information presented in the 1985 FERC application. For the High Devil
Canyon project this data was derived from USGS topographical data.
Tailwater curves for the Watana and Devil Canyon projects were obtained from the 1985
FERC application and estimated for High Devil Canyon.
Operating reservoir levels were obtained from the 1985 FERC application for the
Watana, Low Watana and Devil Canyon projects, from the 1982 Acres feasibility study
for the High Devil Canyon project, and estimated for the Lower Low Watana project.
Environmental flow release constraints were as presented in the 1985 FERC application
and scaled according to drainage areas for the various sites.
Evaporation coefficients were obtained from the 1985 FERC application. Total reservoir
evaporation was estimated in the 1985 FERC application to be between one (1) and three
(3) inches per month in summer, with negligible evaporation during winter months.
Equipment performance was based on vendor data obtained in 2008 specifically for the
Watana and Devil Canyon projects and was assumed to be representative for the other
projects.
Headloss estimates were based on the water conveyance design from the 1985 FERC
application for the Watana and Devil Canyon alternatives and the 1982 Acres feasibility
study for the High Devil Canyon alternative.
The reservoir was assumed to start full at the beginning of the simulation and was
allowed to fluctuate over the remaining period of the simulation.
Generation from Nov. 1 to April 30, “winter,” was at a constant capacity level (“block
loaded”).
Generation from May 1 to Oct. 31, “summer,” was to maximize energy with the objective
of the reservoir being full on Nov. 1.
Rule curves for summer target reservoir elevations were developed for each alternative
using a mass balance approach. The ratio of the average monthly inflow volume to the
average annual inflow volume during each of the reservoir filling months were used to set
target elevations for the reservoir.
Energy losses of 1.5 percent for un-scheduled outages and 2 percent for transformer
losses were applied to the total generation.
Active storage remained constant over the simulation period. Dead storage in the
reservoirs was assumed to be sufficient to contain sedimentation loads.
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No ramping rate restrictions were imposed on either reservoir drawdown or downstream
flow.
To determine the firm capacity for the combined Watana and Devil Canyon projects, the
regulated flow from Watana was assumed to pass unregulated through Devil Canyon with the
Devil Canyon pool at maximum operating level.
Key input parameters related to energy generation are shown in Table 2 below.
Table 2 - Summary of Susitna Project Alternatives
Lower Low
Watana
Low Watana
(Both
Alternatives)
Watana
(Both
Alternatives)
Devil Canyon High Devil
Canyon
Dam Type Rockfill Rockfill Rockfill or
RCC Concrete Arch RCC
Dam Height (ft) 650 700 885 646 810
Gross Head (ft) 495 557 734 605 729
Net Head (Max Flow) (ft) 481 543 729 598 707
Maximum Plant Flow (cfs) 10,700 14,500 22,300 14,000 14,800
Number of Units 3 4 6 4 4
Nameplate Capacity (MW) 390 600 1200 680 800
Maximum Pool Elevation (ft) 1951 2014 2193 1456 1751
Minimum Pool Elevation (ft) 1850 1850 2065 1405 1605
Tailwater Elevation
(Max Flow) (ft) 1456 1457 1459 851 1022
Usable Storage
(acre-ft) 1,536,200 2,704,800 3,888,50 310,000 2,254,700
3.4 Model Operation
For each alternative, 54 years of daily inflow data was used to determine each alternative’s
ability to meet a range of winter energy production targets and maximize summer generation.
For each day from November through April the flow through the powerhouse was limited to the
amount necessary to satisfy a prescribed capacity demand given the available head,
environmental flow constraints, and reservoir operational restrictions. During the months of
May through September energy production each day was maximized if the reservoir elevation
was above the target rule curve. If the reservoir elevation was below the target rule curve then
generation was limited to the amount that would allow the downstream environmental flow
constraints to be met. The simulation was repeated at various increasing winter load demands
until the maximum firm capacity was determined.
To better quantify the effect of storage and extreme low water years on the firm winter capacity,
winter load levels in excess of the firm capacity were also evaluated. The results of this analysis
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are expressed as a capacity at a given percent exceedance level. For example, a project might
have a firm capacity of 250 MW at a 100% exceedance level and a firm capacity of 300 MW at a
98% exceedance level. This would mean that the project could provide 250 MW 100% of the
time in the winter over the simulation period or 300 MW 98% of the time over the winter. The
large change in firm capacity between the 100% exceedance level and the 98% exceedance level
for all alternatives is primarily due to a single low water year in 1970.
The resulting firm capacities and average annual energy production estimates are presented in
Figure 2 and partially summarized in Table 3. Detailed input assumptions and results of these
energy analyses are provided in Appendix A of this report. The average annual energy
production was relatively constant over the range of winter power demand levels that were
modeled.
Table 3 - Firm Capacity and Energy Estimates
Alternative Firm Winter Capacity
(MW)
98% Winter
Capacity (MW)
Average Annual Energy
Production (GWh)
Lower Low Watana 100 170 2,100
Low Watana (both alternatives) * 150 245 2,600
Watana (both alternatives) ** 250 380 3,600
Watana/Devil Canyon *** 470 710 7,200
Devil Canyon 50 75 2,700
High Devil Canyon 250 345 3,900
* Low Watana Expandable and Low Watana Non-Expandable have the same energy characteristics.
** Watana Rockfill and Watana RCC have the same energy characteristics.
*** Watana/Devil Canyon and the Staged Watana/Devil Canyon have similar energy characteristics.
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Figure 2 - Firm Capacity
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
30% 40% 50% 60% 70% 80% 90% 100%Firm Capacity (MW)% Exceedance
Watana and Devil Canyon
Watana
High Devil Canyon
Low Watana
Lower Low Watana
Devil Canyon
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4 Estimates of Probable Project Development Costs
4.1 Original Cost Estimate
In 1982 the cost for developing the complete full Watana/Devil Canyon project was estimated to
be $5.0 billion (1982 dollars). In 1985 the cost for developing the staged Watana/Devil Canyon
project was $5.4 billion (1985 dollars).
The Devil Canyon and High Devil Canyon alternatives were as envisioned in the 1980’s. The
four rockfill Watana Dam configurations considered in this evaluation are depicted in Figure 3
below.
Figure 3 - Watana Dam Configurations
The estimates for the Watana, Low Watana-Expandable, Devil Canyon and Staged Watana-
Devil Canyon alternatives were developed in depth in a March 2009 Interim report and were
revised to reflect changes primarily in transmission, access and camp costs. Using this
information as a base, new estimates were made for the development costs of the Low Watana
Non-Expandable and of the Lower Low Watana alternatives. Cost estimates of $5.4 billion for
the High Devil Canyon RCC and $6.6 billion for the Watana RCC alternatives were provided by
a separate contractor using similar assumptions and are presented here for completeness of
information. The following discussion details the basis for the cost estimates for the Watana
embankment projects, the assumptions that were used in creating those estimates, and provides a
summary of the projected construction costs.
4.2 Expandability
The Low Watana alternative, as proposed in previous studies, included provisions for eventual
expansion of the dam from 700 feet to a height of approximately 885 feet and an increase in
powerhouse capacity from 800 MW to 1200 MW. The most notable of these provisions are the
design of the dam cross section and construction of the powerhouse and water conduits to their
ultimate capacity. The two non-expandable alternatives contain no provisions for future
expansion.
885FULL WATANA
LOWER
LOW WATANA
LOW WATANA -
EXPANDABLE
LOW WATANA -
NON-EXPANDABLE
650
0
500
1000
700
(Ref.)
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For the Low Watana Expandable alternative the dam cross-section is expanded on the upstream
side to provide the opportunity to later raise the dam. This results in additional fill material due
to the wider base. The powerhouse, powerhouse equipment, and water conveyance scheme
would be built to house six units, but only four turbines would be initially installed.
For the Low Watana Non-expandable alternative the cross-section is narrower and does not
accommodate expansion of the dam at a later time. Similarly the powerhouse and water conduit
features are sized for only four turbine/generator units instead of six.
4.3 Quantities
Quantities for the construction cost estimates were based upon detailed estimates developed as
part of the 1982 Acres feasibility study for the full sized Watana project and the Devil Canyon
project. To estimate the quantities of the smaller Watana alternatives, the full sized Watana
quantities were scaled based on the size of the development. As part of a separate report,
quantities were developed for the High Devil Canyon alternative based upon a new conceptual
design using RCC construction.
Table 4 summarizes the embankment fill volumes that were used for the cost estimates. The
dam heights and fill volumes of the Watana and Low Watana Expandable configurations were
adopted directly from the 1985 FERC application. The embankment volumes for the Lower
Low Watana and Low Watana Non-Expandable alternatives were estimated assuming a 2:1 side
slope on the downstream portion of the dam and a 2.4:1 side slope on the upstream portion of the
dam as were assumed for the other alternatives. Volume changes were limited to the rock-fill
and riprap portion of the dam only. The concrete volumes for the Devil Canyon, Watana RCC,
and High Devil Canyon alternatives are shown for comparison.
Table 4 - Estimated Total Fill Volumes
Alternative Type Total Fill Volume(cy)
Watana Rockfill 61,000,000
Low Watana Expandable Rockfill 32,000,000
Low Watana Non-Expandable Rockfill 22,000,000
Lower Low Watana Rockfill 17,000,000
Devil Canyon Concrete Arch 1,300,000
Watana* RCC 15,000,000
High Devil Canyon* RCC 11,600,000
* R&M, 2009.
The quantity estimates for the water conduit layouts and powerhouses for all alternatives were
based on the 1985 layout as opposed to the 1983 layout. The 1983 arrangement used a separate
penstock for each unit with a very long conveyance scheme. The 1985 arrangement employed a
headrace for every two units bifurcating into dedicated penstocks. The total length of
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conveyance was less than half that of the 1983 design. To maintain consistency with the energy
model, and to further refine the cost estimates, the 1985 configuration was used for this study.
Table 5 summarizes the design features that were assumed in each estimate. The powerhouse
and water conveyance systems for Watana and the Low Watana Expandable alternatives were
designed to service six units as contemplated in 1983. However, the water conduit layout
reflects the 1985 arrangement with three headraces bifurcated into six penstocks and discharged
into two tailraces. Low Watana Non-Expandable was assumed to be built to accommodate a
four-unit powerhouse with two headraces, four penstocks and a single tailrace. Lower Low
Watana was designed for a three-unit powerhouse with one headrace, three penstocks, and one
tailrace. The diameters of the water conduits were sized to be consistent with the 1985 design.
The powerhouse structures were also scaled accordingly.
Table 5 - Watana Water Conduit and Powerhouse Size Parameters
Item
Lower
Low
Watana
Low Watana
Non-Exandable
Low Watana
Expandable Watana
Number of Units 3 4 4 6
Unit Size (MW) 130 150 150 200
Plant Nameplate Capacity (MW) 390 600 600 1200
# of Headraces 1 2 3 3
Headrace Diameter (ft) 24 24 24 24
# of Penstocks 3 4 6 6
Concrete Lined Penstock Diameter (ft) 18 18 18 18
Steel Penstock Diameter (ft) 15 15 15 15
# of Tailrace Tunnels 1 1 2 2
Tailrace Diameter (ft) 34 34 34 34
4.4 Unit Costs
U.S. Cost, a company specializing in creating cost estimates for large capital infrastructure
projects, developed unit prices for the materials detailed in the 1982 estimate in 2008 dollars.
This cost data was used to develop the estimates presented in the Interim Report and the same
pricing was used in this study. Lump sum items were inflated using a construction cost index.
For the water-to-wire turbine-generator equipment estimates, budget pricing for the Watana
alternative was requested directly from manufacturers. The water-to-wire equipment includes
turbines, generators, turbine shutoff valves, and other miscellaneous mechanical and electrical
equipment, including installation costs. The equipment costs for other smaller alternatives were
developed by scaling the Watana vendor quotes on a per kilowatt basis.
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4.5 Indirect Costs
A contingency of 20 percent was added to the direct construction costs to reflect level of design
and uncertainty in the project.
Project licensing, environmental studies and engineering design were estimated at 7 percent of
direct construction costs. Construction management was estimated at 4 percent of the direct
construction costs, and has been included as a separate line item.
4.6 Interest During Construction and Financing Costs
Costs associated with interest during construction and project financing are not included in the
estimates.
4.7 Changes from 1983 Design
The camps, access roads and transmission, infrastructure assumptions used in the 1983
configuration have been modified as discussed below.
4.7.1 Camps
Reductions were made in the scale of the permanent and construction camps needed to
accommodate the workers. These changes were made based on the fact that permanent town
facilities were no longer necessary due to advances in remote project operation. It was also
assumed that due to modern construction methods, the number of construction personnel could
be reduced. It was assumed that 750 people would need to be housed for the Lower Low Watana
arrangement, 825 people for Low Watana and 900 people for Watana. In 1983 it was originally
assumed that housing would be provided for 3000 people plus families. Budget pricing for the
construction camp was provided by vendors.
4.7.2 Access
For all the Watana alternatives, access is assumed to be via the Denali Highway from the north
as shown in Figure 4. The route would include the upgrade of 21 miles of the Denali Highway to
a construction grade road and the construction of approximately 40 miles of new road to the
Watana site. The price per mile of new road has been assumed at $3M/mile which is the current
budgetary estimate of the Alaska Department of Transportation and Public Facilities for the road
to Bettles and Umiat from the Dalton Highway which is similar in nature to the road that would
be required for a Susitna project. Upgrading of the Denali Highway has been assumed to be
$1M/mile and local site roads have been estimated at $750k/mile.
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Figure 4 - Proposed Access Route
For the Devil Canyon and High Devil Canyon alternatives, rail access was assumed and will
originate on the Parks Hwy near MP 156 and proceed upstream on the south side of the river.
4.7.3 Transmission
A separate study (EPS, 2009) has investigated the transmission lines and interconnection
requirements for the entire Alaska railbelt region as part of the RIRP process and the results are
incorporated here at the direction of the AEA. This study estimates that a transmission line from
the project site to the substation at Gold Creek would cost approximately $4.5M/mile.
Substation costs are estimated at $16M per location. No costs have been assumed to increase or
modify the regional transmission grid beyond the Gold Creek substation.
4.8 Conclusions
The approach, methodology and assumptions previously described resulted in the estimated
project costs detailed below in the summary table.
Parks
Highway
New
Road
Watana
Denali
Highway
Cantwell
Railroad
Gold Creek
HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 11/23/2009 18 Final Draft Table 6 - Alternate Project Configuration Cost Summary Table ($Millions) FERC Line # Line Item Name Lower Low Watana Low Watana Non-Expandable Low Watana Expandable Watana Watana RCC* Devil Canyon High Devil Canyon*Watana/ Devil Canyon Staged Watana/ Devil Canyon 71A Engineering, Env., and Regulatory (7%) $ 213 $ 236 $ 259 $ 338 $342 $191 $281 $501 $528 330 Land and Land Rights $ 121 $ 121 $ 121 $ 121 $121 $52 $121 $173 $173 331 Power Plant Structure Improvements $ 93 $ 115 $ 159 $ 159 $159 $165 $159 $324 $325 332.1-.4 Reservoir, Dams and Tunnels $ 1,415 $ 1,538 $ 1,718 $ 2,424 $2,307 $900 $1,803 $3,324 $3,485 332.5-.9 Waterways $ 590 $ 590 $ 677 $ 677 $558 $415 $552 $1,093 $1,191 333 Waterwheels, Turbines and Generators $ 213 $ 297 $ 297 $ 475 $487 $295 $487 $770 $834 334 Accessory Electrical Equipment $ 29 $ 41 $ 41 $ 72 $57 $38 $57 $110 $119 335 Misc Power Plant Equipment $ 17 $ 21 $ 32 $ 32 $32 $29 $32 $61 $61 336 Roads, Rails and Air Facilities $ 232 $ 232 $ 232 $ 280 $584 $535 $490 $388 $394 350-390 Transmission Features $ 177 $ 224 $ 224 $ 353 $322 $99 $119 $481 $481 399 Other Tangible Property $ 12 $ 16 $ 16 $ 20 $12 $16 $12 $36 $42 63 Main Construction Camp $ 150 $ 180 $ 180 $ 210 $244 $180 $189 $390 $440 71B Construction Management, 4% $ 122 $ 135 $ 148 $ 193 $195 $109 $161 $286 $302 Total Subtotal $ 3,384 $ 3,746 $ 4,104 $ 5,354 $5,420 $3,024 $4,463 $7,937 $8,375 Total Contingency $ 676 $ 749 $ 821 $ 1,071 $1,155 $605 $954 $1,587 $1,675 Total (Millions of Dollars, rounded) $ 4,100 $ 4,500 $ 4,900 $6,400 $6,600 $3,600 $5,400 $9,600 $10,000 * R&M (2009)
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5 Project Development Schedule
Updated schedules were developed for each of the project alternatives. These schedules extend
from approval, through licensing, design, construction, and commissioning. The primary purpose
of these schedules is to provide timelines for cash flow and estimated energy revenue to
determine economic feasibility. These schedules assume that:
Construction times are based on 1983 FERC license application.
The licensing process from start to FERC order is estimated at 7 to 10 or more years. We
have set a reasonable target of 8 years for the proposed project analysis, provided that the
effort is begun immediately, ambitiously, fully funded, and conducted in parallel with
environmental studies, engineering, and with active public outreach and cooperation by
stakeholders.
The FERC License Application will be based on the 1985 application, updated to reflect
more than 20 years of regulatory changes and changes in engineering and construction
methods.
Any new environmental studies will be based on data acquired during the studies in the
1980’s, updated to reflect present site conditions, public interests, wildlife, and
recreational needs.
Construction will begin immediately upon issuance of the license.
Roads and staging will be state permitted outside the FERC project and will begin several
years before FERC license, including pioneer and permanent roads, airports, bridges,
construction camps and staging areas. Building facilities in advance of the project license
is the most effective way to trim the projected timeline although there is some uncertainty
whether permits could be obtained to construct these facilities before the project license
is issued. The schedule for each of the project alternatives would be extended by one to
two years if this assumption is not valid.
Construction of diversion dams and tunnels will begin on issuance of the license, with
upstream and downstream coffer dams and tunnels to divert the Susitna River during
construction of main dams at Watana/Devil Canyon.
Spillway construction will follow diversion dam and tunnel construction, and will include
site preparation, approach channels, control structures, gates, stoplogs, chute, and
flip buckets for main and emergency spillways.
Dam construction at Watana will follow site preparation, grouting, and installation of a
pressure relief system.
The main dam construction at Devil Canyon will include a thin-arch concrete dam,
preceded by site preparation, foundations, abutments, and thrust blocks. Rock-fill saddle
dam construction will follow grouting and pressure relief system.
The powerhouse and transmission will include power intake, tunnels/penstock, surge
chamber, tailrace, powerhouse, turbine/generators, mechanical/electrical systems,
switchyard, control buildings, and transmission lines.
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Reservoir filling will be based on the latest hydrologic data for inflow and turbine data
for outflow.
Devil Canyon construction will commence immediately upon completion of Watana for
the Watana/Devil Canyon alternative.
Table 7 - Power Generation Time Estimates
Alternative Generation of first power
(years)*
Generation of full power
(years)*
Lower Low Watana 13 14
Low Watana (both alternatives) 14 15
Watana (both alternatives) 15 16
Devil Canyon 14 15
High Devil Canyon 13 14
Watana/Devil Canyon 15 20
Staged Watana/Devil Canyon 15 24
*From start of licensing
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6 Project Development Issues
Development of a hydroelectric project on the Susitna River would face a variety of issues over
their design lifetime. The design lifetime for a modern dam is greater than 100 years. The
following discussion is not intended to be all inclusive but rather highlight the likely major areas
of concern.
6.1 Engineering
The projects being contemplated for the Susitna River would be on the larger end of the scale in
the world in terms of size of the dams. Projects of this size have not been undertaken in the
United States for many decades. As such, a major engineering effort will be required.
6.2 Siltation
Rivers, by nature, transport the products of erosion to the oceans. Dams interrupt this flow of
material. Given time the effective amount of storage in the reservoir behind the dam can
diminish. The alternatives investigated here have been designed with dead storage to
accommodate bedload and it is not expected that siltation will have any detrimental affect on the
energy projected energy production of any of the projects during their design lifetime.
6.3 Seismicity
Seismic (earthquake) events have the potential to effect hydroelectric projects. The main areas
of concern are damage from ground shaking, opening of faults along the dam axis, landslides and
settlement, and the creation of large waves in the reservoir. The previous studies on seismicity
have concluded that these concerns can be designed for and therefore do not pose a significant
threat. New analytic methods are now available to evaluate more complex seismic situations and
these evaluations, along with the most stringent safety factors would be incorporated into a
modern project design (R&M, 2009).
6.4 Climate Change
There has been much discussion about climate change and what the effects of climate change
will be on river flows. Analyses of the potential affects of climate change on the Susitna River
are included in Appendix D. The annual runoff from the Susitna River basin shows remarkable
balance during very disparate climate regimes. The analyses support the consistent supply of
water from the basin precipitation to support hydro-power generation regardless of the climate
fluctuations. While global climate models suggests additional warming may impact the Arctic
and Alaska, it seems very unlikely that these impacts will cause an unbalance in the runoff
production of the basin.
Based on this, there is no conclusive evidence to suggest that runoff will be statistically different
in the next 50 years from what it has been in the last 50 years.
6.5 Environmental Issues
After the Susitna project was discontinued in 1986 a database of 3,573 documents was created.
In September 2008, the 87 most-relevant documents were scanned into HDR’s files, of which 18
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of the most relevant environmental documents were summarized. A synthesis of the 7 most-
pertinent documents was completed. Because not all of the documents were summarized, some
relevant information has likely been overlooked; however, most information was included in the
synthesis.
These documents contain information on potential impacts of the proposed project and
mitigation proposals for those impacts. Specifically, the documents deal with fisheries resources,
botanical resources, wildlife resources, and cultural resources in the potential project area. The
documents divide the Susitna River Basin into 4 geographic regions:
Impoundment zones
Middle Susitna River
Lower Susitna River
Access roads and transmission lines
The potential impacts and mitigation options are discussed for each category in each geographic
region as much as possible. It is important to note that not all categories will be impacted in all
geographic regions. Mitigation for the proposed impacts is divided into the following categories:
avoidance, minimization, rectification, reduction, and compensation. Avoidance is always the
preferred mitigation, though it is not usually feasible. Compensation is the only mitigation option
for many of the impacts.
6.5.1 Fisheries Impacts
The fisheries resources have the highest potential to be impacted by the project. Most of the
potential impacts will occur in the middle Susitna River. There will be impacts due to changes in
water quality, thermal activity, the water’s suspended sediment load, reservoir draw-down
fluctuations, impoundment zone inundation, flow regime, and lost fish habitat. Not all impacts to
fish populations will be negative. For example, the increase in winter water temperatures could
lead to the creation of more overwintering habitat and thus greater fish survival; however, the
cooler spring water temperatures will slow fish growth.
In the Watana impoundment zone, 51 river miles will be inundated and transformed into
reservoir habitat. An additional 27 miles of tributary streams and 31 lakes will be inundated.
In the Devil Canyon impoundment zone 31 miles of the main river channel will be inundated and
an additional 6 miles of tributary streams will be impacted.
Mitigation for these impacts was proposed by compensation through land acquisition, habitat
modification, and reservoir stocking.
6.5.2 Botanical Impacts
The project area contains 295 vascular plant species, 11 lichen genera, and 7 moss taxa. Low
Watana inundation will permanently remove 16,000 acres of vegetation. Devil Canyon
inundation will permanently remove 6,000 acres of vegetation. Watana inundation will
permanently remove an additional 16,000 acres of vegetation. There will be a total of 38,000
acres of vegetation permanently removed. Most of the vegetation inundated will be spruce forest.
An additional 836 acres of vegetation will be permanently removed due to access road
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construction. In the transmission corridor affect on vegetation will be minimal due to
intermittent placement of control stations, relay buildings, and towers.
There will be limited botanical impacts downstream from the reservoir(s). These involve changes
to the vegetation due to a more stable environment. Due to flow regulation there will no longer
be major flooding events, which destroy the riparian vegetation; instead; rather, there will be
succession of the riparian vegetation and colonization of new floodplains. The increase in winter
water temperatures will decrease the amount of ice scouring that occurs, which will result in
effects similar to those caused by the decrease in flooding.
Botanical resource mitigation will consist largely of compensation for permanently removed
vegetation.
6.5.3 Wildlife Impacts
Within the Susitna River Basin there are 135 bird species, 16 small-mammal species, and
18 large-mammal and furbearing species. There are currently no known listed endangered
species in the project area. There will be 5 classes of potential impacts to terrestrial vertebrates:
Permanent habitat loss, including flooding of habitat and covering with gravel pads or roads.
Temporary habitat loss and habitat alteration resulting from reclaimed and revegetated areas such
as borrow pits, temporary right of ways, transmission corridors, and from alteration of climate
and hydrology.
Barriers, impediments, and hazards to movement.
Disturbances associated with project construction and operation.
Consequences of increased human access not directly related to project activities.
Mitigation for the proposed impacts involve mostly compensation since there will be permanent
habitat loss for most species.
6.5.4 Cultural Resource Impacts
Within the proposed project area, 297 historic and prehistoric archaeological sites were located.
An additional 22 sites were already on file. Sites located within 500 feet of the reservoir’s
maximum extent may be indirectly impacted due to slumping from shoreline erosion. Indirect
impacts may also result from vandalism due to increase in access to the sites. The project has the
potential to impact 140 sites. None of these sites will occur in the proposed road corridor or
transmission lines. The majority of these sites are relatively small prehistoric sites.
Mitigation for the lost cultural resources will mostly occur through data recovery. Preservation
would also be used for some sites. Options to consider include construction of protective barriers
to minimize erosion, controlled burial, or fencing of the site to restrict access.
Currently, there are a variety of federal, state, and local land use plans that encompass the
Susitna Basin.
6.5.5 Carbon Emissions
According to the United Nations working group on carbon emissions from freshwater reservoirs
the worst case carbon emissions from a reservoir in a boreal climate is 6.7 grams per square
meter per year (United Nations, 2009). For the Watana/Devil Canyon alternative this equates to
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465,000 metric tons of carbon per year or 0.065 metric tons per MWhr. The US Department of
Energy reports the average carbon emissions due to electric generation for the State of Alaska to
be 0.6261 metric tons per MWhr. Operation of the Susitna project has the potential to eliminate
up to 4 million metric tons of carbon production per year.
1 http://www.eia.doe.gov/cneaf/electricity/st_profiles/alaska.html
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7 References
Acres 1981. Susitna Basin Development Selection. Task 6 Development Section. Subtask 6.05
Development Section Report. Appendix F Single and Multi Reservoir Simulation
Studies.
Acres 1981. Susitna Hydroelectric Project. Task 6 Development Section. Subtask 6.05
Development Section Report. Plate 6.4. High Devil Canyon Layout.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 2 Engineering and
Economic Aspects. Section 12 Watana Development.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 2 Engineering and
Economic Aspects. Section 16 Devil Canyon Development.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 2 Engineering and
Economic Aspects. Section 11 Access Plan Selection.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 2 Engineering and
Economic Aspects. Section 16 Cost Estimates.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 6. Appendix C Cost
Estimates Final Draft.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 1 Engineering and
Economic Aspects Sections 17 Development Schedules.
Entrix, 1985. Impoundment area impact assessment and mitigation plan. Susitna Hydroelectric
Project Impact Assessment and Mitigation Report No. 2. Entrix, Inc., Under contract to
Harza-Ebasco Susitna Joint Venture. Prepared for the Alaska Power Authority.
EPS 2009. Susitna Hydro Transmission Study. Report to AEA dated October 22, 2009
Harza Ebasco. 1985. Introduction to the Amendment to the License Application before the
Federal Energy Regulatory Commission. Chapter III Project Description.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 1. Exhibit
A Project Description. Sections 1- 15.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 15.
Exhibit F Project Design Plates.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 16.
Exhibit F Supporting Design Report.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 2. Exhibit
B Project Operation and resource Utilization. Section 3 Description of Project Operation.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 2. Exhibit
B Project Operation and resource Utilization. Section 4 Power and Energy Production.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Exhibit D Project
Costs and Financing. Section 1 Estimates of Cost.
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Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application Exhibit C
Proposed Construction Schedule.
Harza Ebasco. 1985a. Susitna Hydroelectric Project Draft License Application Volume 9 Exhibit
E Chapter 3 Sections 1 and 2 – Fish, Wildlife and Botanical Resources.
Harza Ebasco. 1985b. Susitna Hydroelectric Project Draft License Application Volume 10
Exhibit E Chapter 3 Section 3 – Fish, Wildlife and Botanical Resources.
Harza Ebasco. 1985c. Susitna Hydroelectric Project Introduction to the Amendment to the
License Application.
Harza Ebasco. 1985d. Susitna Hydroelectric Project Draft License Application Volume 11
Exhibit E Chapter 3 Sections 4, 5, 6 & 7 – Fish, Wildlife and Botanical Resources.
Harza Ebasco. 1985e. Susitna Hydroelectric Project Draft License Application Volume 12
Exhibit E Chapter 4, 5, and 6. – Cultural Resources, Socioeconomic Resources, and
Geological and Soil Resources.
R&M 2009. Susitna Project. Seismic Setting Review and Geologic and Geotechnical Data
Reports Review. Memo to AEA dated July 2, 2009
R&M 2009. Susitna Project. Watana and High Devil Canyon RCC Dam Cost Evaluation. Final
Report dated November 16, 2009.
United Nations Educational, Scientific and Cultural Organization. Scoping Paper: Assessment
of the GHG Status of Freshwater Reservoirs. April 2008
U.S. Cost 2008. 1982 to 2008 Cost Estimate for Susitna Hydroelectric Project.
Woodward-Clyde Consultants. 1984. Susitna Hydroelectric Project: Fish Mitigation Plan.
Prepared for the Alaska Power Authority.
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Appendix A:
Energy Analysis Input and Results
For the purposes of this submittal, the appendices have been attached as PDFs.
HDR Alaska Susitna Hydroelectric Project
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Appendix B:
Detailed Cost Estimates
For the purposes of this submittal, the appendices have been attached as PDFs.
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Appendix C:
Detailed Schedules
For the purposes of this submittal, the appendices have been attached as PDFs.
HDR Alaska Susitna Hydroelectric Project
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Appendix D:
Climate Change Analyses
For the purposes of this submittal, the appendices have been attached as PDFs.
APPENDIX B FINANCIAL ANALYSIS
ALASKA RIRP STUDY
Black & Veatch B-1 February 2010
APPENDIX B
FINANCIAL ANALYSIS
SNW 1420 Fifth Avenue, Suite 4300 Seattle, Washington 98101 Phone: (206) 628-2882 Fax: (206) 343-2103 2/3/2010 Regional Integrated Resource Plan Financial Analysis Summary Report Innovative Financing and Investment Strategies
1 Introduction The Regional Integrated Resource Plan (RIRP) is a 50-year, long-range plan tasked with identifying the optimal combination of generation and transmission capital improvement projects in the Railbelt region of Alaska. The objectives of the financial analysis portion of the plan are threefold : 1. Provide a high-level analysis of the capital funding capacity of each of the Railbelt utilities, given their current financial condition and assuming that each utility will borrow on its own, rather than utilizing a joint-powers structure or receiving assistance from the State of Alaska. 2. Analyze strategies to capitalize selected RIRP assets by integrating State and federal financing resources with debt capital market resources. Specifically, we look at ways to utilize State funding to: • mitigate construction risk, • lower capital cost prior to placing assets in service , and • extend the debt repayment term beyond terms available in the debt capital markets. 3. Develop a spreadsheet-based model that utilizes inputs from the RIRP model, including total capital requirements, demand-side management (DSM), fuel cost, CO2 cost, and operation and maintenance cost (O&M), and overlays realistic debt capital funding to provide a total cost to ratepayers of the optimal resource plan. Railbelt Utility Capital Capacity The non -profit organizational structure of generation and transmission (G&T) and distribution cooperatives makes it difficult for these entities to produce operating margins and build equity to the levels needed to access the public debt markets. Rate setting is designed to recover operating cost with moderate margins, and any capital in excess of minimal reserves is returned to coop members. Nevertheless, some coops, including Chugach Electric, are able to maintain coverage margins sufficient to secure investment grade credit ratings and utilize the debt capital market to fund asset expansion. Likewise, municipal governments face a similar rate-setting challenge in the form of political pressure to keep rates at levels just sufficient to cover operations and maintain net plant and equipment. In the following sections , we take a look at several key financial measures of coop and municipally owned utilities and utilize these measures to estimate the remaining debt capacity of each of the Railbelt utilities. To develop the framework for this analysis, we retrieved the publicly available financial reports from each utility’s website and the annual filings from the Regulatory Commission of Alaska’s website. Using these reports , we summarized each of the utilities’ current outstanding debt obligations, company equity, total assets and total plant. We used these figures to derive several important financial ratios, discussed in detail below, that are used by the investment community as well as the nationally recognized rating agencies (Moody’s, Standard & Poor’s, and Fitch) to determine the ability of each organization to manage its current and/or future debt obligations. It’s important to point out that, while no single financial ratio by itself is an accurate determinant of a utility’s ability to incur additional debt for capital projects, an analysis of a sampling of several ratios in conjunction with other non-financial metrics (e.g., demand growth, rate-setting authority,
2 political climate, etc.) helps to create some guidelines for how much debt could reasonably be considered and issued in the capital markets. Debt to Equity Ratio. The debt to equity ratio (or debt as a percentage of total capitalization) is derived by dividing a utility’s total debt by its net c apital. The rating agencies have developed median debt to equity ratios for each of the different types of utility organizational structures. For example, a G&T cooperative can expect to have a higher debt ratio percentage than a retail power distributer due to the need to finance large and relatively expensive generation and transmission assets. A summary of these utility medians for debt to equity is provided in the following table: 2008 Median Debt to Capitalization % By Utility System Type G&T Coop 82% Municipal Wholesale 93% Retail Self Generating 60% Retail Power Purchaser (Distribution) 40% Source: Fitch U.S. Public Power Peer Study, June 2009 The table below calculates the remaining debt capacity for each of the Railbelt utilities under varying debt to equity ratios to derive a total debt capacity amount given existing equity capitalization. Debt to equity capitalization for this analysis ranges from 40% to 80%. Railbelt Utility Additional Debt Capacity Based on Current Debt to Equity Ratios Existing Debt as of 12/31/20081 40% 60% 70% 80% ML&P $159,405,791 - $175,744,945 $362,920,220 730,502,349 Chugach 354,383,506 - - 9,355,443 260,137,205 MEA 89,128,488 - 48,090,737 129,409,217 277,237,086 HEA 148,257,837 - - - 99,152,015 GVEA 301,670,508 - - - 131,081,336 Seward 2 2 2 2 2 - $223,835,682 $501,684,880 $1,498,109,991 (1) 2008 Annual reports and 12/31/2008 Annual Reports to the Regulatory Commission of Alaska (2) The City of Seward was not included in this analysis due to lack of information regarding their Electric Enterprise Fund Our analysis found that the debt-to-capitalization ratio for each of the utilities is close to or higher than the median ratio for its organizational type. There does appear to be some additional bonding capacity available for each of the utilities under a G&T cooperative-type structure when compared to the Fitch median ratio of 82%. However, given the utilities’ existing debt burdens and current conditions in the financial markets, which have made it more difficult for lower rated power utilities to access capital, it is not clear that the six utilities could support debt capitalization much above 70%. Fitch Ratings specifically mentions that higher debt capitalization percentages can result in negative ratings pressure going forward1. At approximately 70% 1 Fitch Ratings, U.S. Public Power Peer Study, June 2009
3 debt capitalization, the six utilities together could support between $500 and $700 million of additional debt. At 80%, available additional debt capacity for the six utilities combined increases to approximately $1.5 billion. This analysis does not include the City of Seward’s capacity. Given its Electric Enterprise Fund asset base of $26 million (as of 2007), the overall borrowing capacity number would not change by a significant amount if the City of Seward were included. Debt to Funds Available for Debt Service. An important measure of operating leverage is the Debt to Funds Available for Debt Service ratio (Debt/FADS). This ratio measures a utility’s ability to handle its current fixed debt burden based on annual operating cash flow. A lower Debt/FADS ratio indicates either a low overall debt burden or a high operating cash flow, with the opposite being true for a higher Debt/FADS ratio. In the “A” rating category and higher, all but one G&T wholesale system rated by Fitch Ratings had a Debt/FADS ratio higher than 8.8 in 2008. For comparison purposes, the average (and median) Debt/FADS ratio for the Railbelt utilities in 2008 was approximately 8.4, with the highest being 13.66. The operating leverage of the six utilities would increase dramatically as capital spending and debt burden increase. An increase in the operating leverage ratio would cause ratings pressure for utilities maintaining a public credit rating and increased scrutiny by creditors including commercial banks and cooperative banks such as CFC or CoBank. RIRP Capital Requirements Relative to Railbelt Utility Debt Capacity. The preceding debt to equity and Debt/FADS discussions do not take into consideration several additional factors that are relevant to the collective debt capacity of the Railbelt utilities. These factors can impact debt capacity both positively and negatively and include amortiza tion of existing utility debt, the level of new debt required to maintain distribution infrastructure, and potential rate increases. While these factors are influential, they do not have sufficient positive impact to alter our opinion that the utilities individually do not have the capital capacity to fund the projects recommended by the RIRP. The scope of the RIRP projects is too great, and for certain individual projects, it is reasonable to conclude that there is no ability for a municipality or coop to independently secure debt financing without committing substantial amounts of equity or cash reserves. Specifically, these individual projects would include any that require large capital investment and have any of the following characteristics: exceptionally long construction period, significant construction risk, or significant technological risk. These types of risk are associated with equity rates of return and are rarely , if ever , borne by fixed income investors. The graphic to the right helps to put into context the scope of required RIRP capital investments relative to the estimated combined debt capacity of the Railbelt utilities. The lines toward th e bottom of the graph represent our view of the bracketed range of additional debt capacity Black & Veatch Plan 1A Capital Expenditures (Cumulative Total) $0 $2,500,000,000 $5,000,000,000 $7,500,000,000 $10,000,000,000 20112014201720202023202620292032203520382041204420472050205320562059High Debt CapacityLow Debt CapacityCapitalExpenditures
4 collectively for the Railbelt utilities, adjusted for inflation and customer growth over time . Railbelt Utility Debt Capacity Conclusions. The REGA study completed in 2008 concluded that the most cost effective approach to funding necessary Railbelt generation and transmission assets was to form a regional G&T. While SNW was not asked to validate this conclusion, we are of the opinion that a regional entity such as GRETC, with “all outputs” contracts migrating over time to “all requirements” contracts, will have greater access to capital than the combined capital capacity of the individual utilities. To be clear, our conclusion should not be interpreted to mean that a regional G&T agency would be able to execute the RIRP capital plan independent of any State or federal assistance; however , a regional G&T agency will have lower -cost access to debt capital than the utilities would have on their own. This is primarily due to two factors: (1) a regional G&T entity will eliminate the rate pressure/competition that naturally exists under the current Railbelt construct of each of the 6 utilities independently providing generation and transmission services to their customers, and (2) a regional G&T entity executing a utility-approved comprehensive RIRP plan with strong power purchase agreements will be better positioned with the rating agencies and private investors. Strategies to Lower Capital Cost of RIRP to Ratepayers As previously noted, the scope of the RIRP is significant. The complexity of the overall capital plan and the size and construction duration of various projects within the plan will necessitate some amount of “equity” capital from ratepayers and/or the State of Alaska. Furthermore, equity capital, in the form of a ratepayer benefits charge or State financial assistance through either loans or grants, is the most efficient source of funding available to GRETC for the RIRP. Capital accruing from the State in the form of grants or from existing ratepayers in any form needs to be balanced with long-term debt capital so that future rate payers who will benefit from the RIRP assets share the cost of funding these assets. The following sections discuss various sources of equity capital funding and methods for involving the State in the execution of the RIRP. Ratepayer Benefits Charge. A ratepayer benefits charge is a charge levied on all ratepayers within the Railbelt system that will be used to cash fund and thereby defer borrowing for infrastructure capital. A rate surcharge that is implemented prior to construction allows for partial “pay-go” funding of capital projects and reduces the overall cost of the projects by reducing the amount of interest paid for funding in the capital markets. For example, the potential interest cost savings that could be realized if GRETC were to fund some portion of a $2 billion project through rates rather than entirely upfront through bond proceeds are shown in the table below: $2 billion project Rate Surcharge Through Construction Funded With Bonds Interest Cost Reduction (1) $500 million $1.5 billion $1.2 billion $1.0 billion $1.0 billion $2.4 billion (1) Assumes 30-year debt to fund construction at 7.00% interest.
5 “Pay-Go” vs. Borrowing for Capital. A “pay-go” capital financing program is one in which ongoing capital projects are paid for from remaining revenue after maintenance and operations (M&O) expenses, and debt service are paid for. As will be discussed in further detail later, we have assumed that any bonds sold in the capital markets will require generation of a 1.25 times debt service coverage ratio. Covenanted coverage would likely be lower than 1.25 times. The cash generated in excess of M&O expense an d debt service expense (“coverage”) will be used to fund reasonable reserves with the balance going towards ongoing capital projects. For example, in years where debt service on outstanding bond issues is the highest, the 1.25 times debt service coverage ratio creates additional reserves in the amount of nearly $130 million above what is required to pay operating expense and debt service. There is a tradeoff between the benefits derived from a pay-go financing structure versus one for which all projects are bonded. The benefit to ratepayers and GRETC in the pay-go structure is that it minimizes the total cost of the projects through the reduction of interest costs. On the other hand, the benefit of borrowing for a portion of capital needs is that expen ses are spread out over time, and the cost of the debt can be structured to more closely match the useful life of the assets being financed. This is particularly important for some of the larger hydro-electric projects, where the useful life would likely exceed 50 years; these projects have large upfront costs that would be cost-prohibitive if funded entirely through rates. A balance of these two funding approaches appears to be most effective in lowering the overall cost of the project as well as spreading out the costs over a longer period of time. Construction Work In Progress. Construction Work In Progress (CWIP) is a rate methodology that allows for the recovery of interest expense on project construction expenditures through the rate base during construction , rather than capitalizing the interest until the projects are completed and operating . This concept is important: the overall cost of the projects is significantly reduced through the immediate payment of interest on construction borrowing, vers us the alternative of borrowing an additional sum just to pay for the interest while the project is still under construction. The benefit to ratepayers of the CWIP concept is that it significantly lowers both the overall cost of the project as well as the future revenue requirements needed to pay debt service. The use of CWIP in Alaska will most likely need to be vetted and approved by the Regulatory Commission of Alaska. Both CWIP and pay-as-you -go funding rely on ratepayers to advance dollars for capital projects and thereby convey some project risk to ratepayers. If for example, a generation project were not completed for any reason ratepayers would have paid for a portion of the project even though the asset never produced power. SNW believes that ratepayers in a typical municipal utility structure generally incur this risk regardless of rate setting policies or methodologies. The ability to shift project risk to creditors is both limited and expensive and may not be appropriate for the “System” envisioned by GRETC. Under an Investor Owned Utility (IOU) structure, shareholders are responsible for bearing some of this risk, however shifting risk to shareholders requires higher equity rates of return to those investors. GRETC is not presently contemplated to be structured as an IOU.
6 State Financial Assistance. State financial assistance could take a variety of forms, but for the purpose of this report, we will focus on State assistance structured similarly to the Bradley Lake project. State financial assistance offers GRETC a number of advantages not available through traditional utility enterprise bond funding or project finance. Similar to a ratepayer benefits charge, State funding, whether in the form of a grant or loan, can be utilized to defer higher cost conventional revenue bond funding. Obviously a grant from the State provides the cheapest form of capital to GRETC, but even when structured as a loan, State assistance can dramatically lower GRETC’s overall cost of capital. State funding in the form of a loan has three significant advantages when compared to revenue bonds or a loan from a commercial lender. The advantages of State funding include: 1. Repayment flexibility. State funding can be utilized to extend debt repayment beyond the term maturities available in the public or commercial debt capital markets. Additionally, a State loan can easily be restructured or deferred to achieve system rate objectives. 2. Credit support/risk mitigation. State funding can be used to mitigate project construction risk. This is particularly relevant for projects with extended construction timelines, such as large hydro-electric projects. Risk mitigation is also relevant in situations where permitting is an issue or a new technology is being used. Generally, fixed income investors will not accept significant construction and permitting risks inherent with the large-scale projects included in the RIRP without some form of support from the State. 3. Potential interest cost benefit. State funding can provide a lower cost source of capital. The State’s high investment grade credit rating allows it to borrow for less than even the most secure utility enterprise. Assumptions as to the form of State assistance in the financial model are discussed in greater detail below; however , the terms of any loan, agreement, or grant between the State and GRETC will need to be further researched and developed in the next stage of the GRETC formation process. RIRP Financial Model Summary Results The development of the RIRP financial model took into account several different goals and objectives. The first goal was to identify ways to overcome the funding challenges inherent with large scale projects, including the length of construction time before the project is online and access to the capital markets. A second goal was to develop strategies that could be used to meet an objective of the RIRP of producing equitable rates over the useful life of the assets being financed. Structures commonly used in the current capital markets would not meet this goal, as certain of the assets required to be financed have longer useful lives than the longest term capital markets transaction could bear. With these challenges in mind, we developed separate versions of the model that would capture the cost of financing under a “base case ” scenario and an “alternative ” scenario, both of which are described in greater detail below. Major Assumptions (Black &Veatch Inputs). The input assumptions for the RIRP financial model were developed around outputs from the Black & Veatch PROMOD/Strategist modeling analysis. The results created a detailed list of the capital costs for the projects chosen over the 50-year RIRP time horizon. The results show both generation unit costs as well as required transmission development costs associated with the
7 selected projects. Other assumptions used from the Black & Veatch PROMOD analysis include associated fuel costs, fixed and variable O&M, CO2 charges , and forecasted energy load requirements by year, including DSM energy use reductions. Major Assumptions (Financing Model Inputs). The assumptions used for capital markets transactions within the financing model are all market-accepted structures for an investment grade utility, cooperative, or joint action agency. Below is a summary of the major structuring assumptions used for both financing scenarios: • 30-year debt repayment on all bond issues sold in the capital markets • 7.00% interest rate on all bond issues sold in the capital markets • Rate generated debt service coverage of 1.25X • All energy generation developed is used or sold • Debt Service Reserve Fund (DSRF) for each bond issue funded at 10% of bond issue par amount. The DSRF balance is maintained throughout the 50-year RIRP and earns 3.00% interest, which is used to pay debt service on an annual basis. Base Case Model: Specific Assumptions . The base case financing model was structured such that the list of generation and transmission projects would be financed through the capital markets in advance of construction and that the cost of the financing in the form of debt service on the bonds would immediately be passed through to rate payers (see “Construction Work in Progress” herein). Bond issues are assumed to be sold prior to the required project funding dates, and staggered in approximately three -year intervals over the first 20-years , when the majority of the large capital projects and transmission projects are scheduled. The projects being financed over the balance of the 50-year RIRP period are financed through cash flow created through normal rates and charges (“pay-go”). The pay-go approach works once debt service coverage from previous years has grown to levels that create cash reserve balance amounts sufficient to pay for the projects as their construction costs come due. The sources of funds for the projects included in the RIRP under the base case model are as follows: RIRP Plan 1A : Base Case Sources of Funds (dollars in millions) Bonds $5,889 State Funds $0 Infrastructure Tax $0 Pay-Go $3,196 The base case model assumes that approximately $5.9 billion of bonds are sold over the RIRP time horizon through five different bond sales ranging in size from $656 million to $2.5 billion. The maximum fixed charge rate on the capital portion alone is estimated to cost $0.13 per kWh, while the average fixed charge rate over the 50-years is $0.07 per kWh. Alternative Model: Specific Assumptions . The alternative model was developed with the goal of minimizing the rate shock that may otherwise occur with such a large capital plan, and levelizing the rate over time so that the economic burden derived from these projects can be spread more equitably over the useful life of the
8 projects being contemplated. Similar to the base case scenario, the first method used was to transfer the excess operating cash flow that is generated to create the debt service coverage level, and use that balance to both partially fund the capital projects in the early years and almost fully fund the projects in the later years. The second method used was the implementation of a Capital Benefits Surcharge that is applied to rate payers starting the day GRETC is formed. For this analysis, it was assumed that a $0.01 rate surcharge would be in place for the first 17 years, during which time approximately 75% of the capital projects in the plan will have been constructed. The third method used to spread out the costs over a longer time period was the use of the State as an equity participant in the execution of the RIRP capital funding plan. In a financing structure that is similar to the Bradley Lake financing model, the State would provide the upfront funding for any large hydroelectric projects, to be paid back by GRETC out of system revenues over an extended period of time, and following the repayment of the potentially more expensive capital markets debt. This analysis assumes that a $2.4 billion hydroelectric project is financed through a zero interest loan to GRETC that is then paid back through a 30-year capital markets take-out bond issue in 2047. The sources of funds for the projects included in the RIRP under the alternative case model are as follows: RIRP Plan 1A : Alternative Case Sources of Funds (dollars in millions) Bonds $3,657 State Funds $2,409 Benefit Surcharge $883 Pay-Go $2,135 The alternative model assumes that $5.9 billion of bonds are sold over the RIRP time horizon through nine different bond sales ranging in size from $32 million to $2.4 billion, which includes the $2.4 billion take-out financing to repay the State for front-funding of hydroelectric assets. The capital costs not bonded for come from the rate surcharge that is applied from day one and cash flow generated from rates and charges after operations and debt service (pay-go capital). The maximum fixed charge rate on the capital portion alone is estimated to cost $0.08 per kWh, while the average fixed charge rate over the initial 50-year period is $0.06 per kWh, not including the $0.01 consumer benefit surcharge that is in place for the first 17 years. While the average fixed cost is not significantly different between the base case and alternative scenarios, the difference between the two maximum rates are significant. The lower maximum rate in the alternative scenario benefits the rate payers by smoothing out the rates over a period of time that more closely matches the useful life of the RIRP assets. Summary, Next Steps, Conclusion. The RIRP presents a number of funding challenges, given the size and scope of the projects being contemplated. It has become evident through the financial modeling and the individual debt capacity analyses of this process that the utilities on their own would not be able to accomplish such an ambitious capital plan. The formation of a regional entity, such as GRETC, that would combine the existing resources and rate-base of the Railbelt utilities, as well provide an organized front in working to obtain private financing and the necessary levels of State assistance would be, in our opinion, a necessary next step towards achieving the goal of reliable energy for the Railbelt now and in the future.
RIRP Plan 1A - Base Case Financial Model
Alaska Regional Integrated Resource PlanYearHydro Capital RequirementsOther Unit Cost Capital RequirementsTransmission RequirementsTotal Capital RequirementsSTATE FundingUse of coverage balance for capital projectsCapital Markets ‐ BONDSScenario Cash Flow Summarydollars in millions112/1/20111 506,496,362 ‐ 506,496,363 ‐ 886,736,593$ 212/1/2012‐ 256,773,239 ‐ 256,773,239 ‐ ‐ ‐ 312/1/2013‐ 119,476,707 3,990,284 123,466,991 ‐ ‐ ‐ 412/1/2014‐ 122,463,625 52,942,550 175,406,175 ‐ (25,000,000) 656,306,880$ 512/1/2015‐ 2,435,356 191,310,564 193,745,920 ‐ ‐ ‐ Sources of Funds612/1/201633,699,203 22,466,161 255,989,420 312,154,784 ‐ ‐ ‐ BONDS 5,889 712/1/201726,865,753 74,229,623 117,965,769 219,061,145 ‐ (105,000,000) 795,887,676$ STATE (through construction) 0 812/1/201843,273,053 174,256,113 41,630,847 259,160,013 ‐ ‐ ‐ Infrastructure Tax through 2027 0 912/1/201979,301,147 174,171,476 169,193,895 422,666,518 ‐ ‐ ‐ Other (use of coverage reserves) 3,196 1012/1/2020238,340,271 208,891,416 321,882,411 769,114,097 ‐ (190,000,000) 2,454,911,924$ Total Source of Funds 9,085 1112/1/2021481,536,897 21,500,060 282,636,456 785,673,412 ‐ ‐ ‐ 1212/1/2022652,793,164 ‐ 437,331,250 1,090,124,414 ‐ ‐ ‐ Use of Funds1312/1/2023712,137,997 ‐ 464,423,300 1,176,561,297 ‐ (320,000,000) 1,095,198,536$ Project/Construction 9,085 1412/1/2024141,426,155 ‐ 59,937,820 201,363,975 ‐ ‐ ‐ Payment of interest accrued 0 1512/1/2025‐ ‐ 18,210,430 18,210,430 ‐ ‐ ‐ Reserve Funds 0 1612/1/2026‐ ‐ 19,062,834 19,062,834 ‐ ‐ ‐ Issuance Costs 0 1712/1/2027‐ 88,657,273 ‐ 88,657,273 ‐ (485,500,231) ‐$ Capitalized Interest (through construction) 0 1812/1/2028‐ 208,125,424 ‐ 208,125,424 ‐ ‐ ‐ Total Uses of Funds 9,085 1912/1/2029‐ 188,717,535 ‐ 188,717,535 ‐ ‐ ‐ 2012/1/2030‐ ‐ ‐ ‐ ‐ ‐ Maximum Annual Debt Service Requirements2112/1/2031‐ ‐ ‐ ‐ ‐ ‐ BONDS 539 2212/1/2032‐ ‐ ‐ ‐ ‐ ‐ STATE 0 2312/1/2033‐ ‐ ‐ ‐ ‐ ‐ 2412/1/2034‐ 2,260,136 2,260,136 ‐ (239,531,757) ‐$ 2512/1/2035‐ 206,133,124 206,133,124 ‐ ‐ ‐ Ave. Annual Energy Requirement (GWhr)5,625 2612/1/2036‐ 31,138,497 31,138,497 ‐ ‐ ‐ Target Debt Service Coverage (DSC)1.25X 2712/1/2037‐ ‐ ‐ ‐ ‐ ‐ All-in Borrowing Cost7.00% 2812/1/2038‐ ‐ ‐ ‐ ‐ ‐ Escalation Factor (Inflation)2.50% 2912/1/2039‐ 127,791,596 127,791,596 ‐ (699,805,525) ‐$ Average Cost of Energy ($/per kWh)0.07 3012/1/2040‐ 299,994,339 299,994,339 ‐ ‐ ‐ 3112/1/2041‐ 272,019,589 272,019,589 ‐ ‐ ‐ 3212/1/2042‐ ‐ ‐ ‐ ‐ ‐ 3312/1/2043‐ 131,612,221 131,612,221 ‐ (720,727,822) ‐$ RIRP PLAN 1ABase Case100% Fixed Rate//,,,,(,,)$Assumptions3412/1/2044‐ 308,963,361 308,963,361 ‐ ‐ ‐ Issuance Cost = 2% of Par Amount 3512/1/2045‐ 280,152,241 280,152,241 ‐ ‐ ‐ Par coupons 3612/1/2046‐ ‐ ‐ ‐ ‐ ‐ Debt service reserve funded at 10% of Bond Par Amount 3712/1/2047‐ ‐ ‐ ‐ ‐ ‐ Bonds all assumed to be 30 years from date of issue 3812/1/2048‐ ‐ ‐ ‐ ‐ ‐ 3912/1/2049‐ ‐ ‐ ‐ ‐ ‐ 4012/1/2050‐ ‐ ‐ ‐ ‐ ‐ 4112/1/2051‐ ‐ ‐ ‐ ‐ ‐ 4212/1/2052‐ ‐ ‐ ‐ ‐ ‐ 4312/1/2053‐ ‐ ‐ ‐ ‐ ‐ 4412/1/2054‐ ‐ ‐ ‐ (410,069,419) ‐$ 4512/1/2055‐ 35,525,625 35,525,625 ‐ ‐ ‐ 4612/1/2056‐ 161,918,291 161,918,291 ‐ ‐ ‐ 4712/1/2057‐ ‐ ‐ ‐ ‐ ‐ 4812/1/2058‐ 38,257,213 38,257,213 ‐ ‐ ‐ 4912/1/2059‐ 174,368,290 174,368,290 ‐ ‐ ‐ 5012/1/2060‐ ‐ ‐ ‐ Prepared by Seattle-Northwest Securities Corporation12/1/2009
Year112/1/2011212/1/2012312/1/2013412/1/2014512/1/2015612/1/2016712/1/2017812/1/2018912/1/20191012/1/20201112/1/20211212/1/20221312/1/20231412/1/20241512/1/20251612/1/20261712/1/20271812/1/20281912/1/20292012/1/20302112/1/20312212/1/20322312/1/20332412/1/20342512/1/20352612/1/20362712/1/20372812/1/20382912/1/20393012/1/20403112/1/20413212/1/20423312/1/2043Repayment of State fundsGRETC Direct Debt Service ‐ paid to bondholdersDSRF Interest Earnings Total RequirementsEnergy per Year (GWhr) Surcharge for seed capital Fixed Rate Charge for Capital DSM Fuel Rate O&M Rate (Fixed + Variable) CO² Incremental Cost (¢ per kWh) 1.0057‐$ 35,268,100$ ‐$ 35,268,100$ 5,372 ‐ 0.01 0.000 0.048 0.013 0.0000.07 81,206,200 2,660,210 78,545,990 5,412 ‐ 0.02 0.000 0.051 0.013 0.0100.09 81,204,300 2,660,210 78,544,090 5,424 ‐ 0.02 0.001 0.048 0.014 0.0110.09 107,308,425 2,660,210 104,648,215 5,421 ‐ 0.02 0.001 0.053 0.014 0.0120.10 141,306,550 4,629,130 136,677,420 5,167 ‐ 0.03 0.002 0.067 0.013 0.0120.13 141,309,000 4,629,130 136,679,870 5,147 ‐ 0.03 0.002 0.070 0.014 0.0130.13 172,958,250 4,629,130 168,329,120 5,129 ‐ 0.04 0.002 0.066 0.014 0.0140.14 214,187,950 7,016,793 207,171,157 5,105 ‐ 0.05 0.002 0.042 0.013 0.0150.12 214,190,100 7,016,793 207,173,307 5,085 ‐ 0.05 0.002 0.045 0.013 0.0160.13 311,827,975 7,016,793 304,811,182 5,068 ‐ 0.08 0.002 0.044 0.012 0.0170.15 439,001,050 14,381,529 424,619,521 5,052 ‐ 0.11 0.002 0.046 0.013 0.0180.18 439,000,300 14,381,529 424,618,771 5,081 ‐ 0.10 0.003 0.050 0.013 0.0210.19 482,557,325 14,381,529 468,175,796 5,111 ‐ 0.11 0.001 0.053 0.012 0.0210.20 539,293,200 17,667,125 521,626,075 5,140 ‐ 0.13 0.001 0.055 0.013 0.0230.22 539,294,650 17,667,125 521,627,525 5,174 ‐ 0.13 0.001 0.037 0.016 0.0170.20 ‐ 539,289,900 17,667,125 521,622,775 5,207 0.13 0.001 0.042 0.014 0.0200.20 ‐ 539,284,300 17,667,125 521,617,175 5,241 0.12 0.002 0.044 0.014 0.0220.21 ‐ 539,290,400 17,667,125 521,623,275 5,275 0.12 0.002 0.046 0.014 0.0240.21 ‐ 539,297,250 17,667,125 521,630,125 5,309 0.12 0.003 0.049 0.015 0.0270.22 ‐ 539,296,800 17,667,125 521,629,675 5,344 0.12 0.003 0.042 0.019 0.0250.21 ‐ 539,293,550 17,667,125 521,626,425 5,378 0.12 0.003 0.042 0.019 0.0260.21 ‐ 539,293,500 17,667,125 521,626,375 5,413 0.12 0.003 0.044 0.019 0.0280.21 ‐ 539,288,800 17,667,125 521,621,675 5,447 0.12 0.003 0.046 0.019 0.0310.22 ‐ 539,293,450 17,667,125 521,626,325 5,482 0.12 0.003 0.048 0.020 0.0340.22 ‐ 539,286,550 17,667,125 521,619,425 5,517 0.12 0.003 0.052 0.020 0.0370.23 ‐ 539,289,400 17,667,125 521,622,275 5,553 0.12 0.001 0.054 0.021 0.0410.23 ‐ 539,287,350 17,667,125 521,620,225 5,588 0.12 0.001 0.062 0.022 0.0480.25 ‐ 539,291,900 17,667,125 521,624,775 5,623 0.12 0.001 0.066 0.022 0.0520.26 ‐ 539,293,600 17,667,125 521,626,475 5,659 0.12 0.002 0.069 0.023 0.0570.27 ‐ 539,288,100 17,667,125 521,620,975 5,695 0.11 0.002 0.072 0.023 0.0620.27 ‐ 539,290,450 17,667,125 521,623,325 5,731 0.11 0.004 0.075 0.024 0.0670.28 ‐ 458,083,350 17,667,125 440,416,225 5,767 0.10 0.004 0.073 0.022 0.0690.26 ‐ 458,087,900 17,667,125 440,420,775 5,803 0.09 0.004 0.077 0.022 0.0750.27 //3412/1/20443512/1/20453612/1/20463712/1/20473812/1/20483912/1/20494012/1/20504112/1/20514212/1/20524312/1/20534412/1/20544512/1/20554612/1/20564712/1/20574812/1/20584912/1/20595012/1/2060,,,,,,,‐ 458,086,400 17,667,125 440,419,275 5,839 0.09 0.004 0.080 0.033 0.0820.29 ‐ 397,988,550 17,667,125 380,321,425 5,876 0.08 0.004 0.084 0.023 0.0890.28 ‐ 397,984,050 17,667,125 380,316,925 5,912 0.08 0.004 0.078 0.031 0.0870.28 ‐ 397,982,000 17,667,125 380,314,875 5,949 0.08 0.005 0.079 0.032 0.0910.29 ‐ 325,101,750 17,667,125 307,434,625 5,986 0.06 0.005 0.083 0.032 0.1000.28 ‐ 325,102,950 17,667,125 307,435,825 6,023 0.06 0.001 0.086 0.033 0.1090.29 ‐ 325,107,400 17,667,125 307,440,275 6,060 0.06 0.002 0.089 0.034 0.1170.31 ‐ 100,294,000 17,667,125 82,626,875 6,098 0.02 0.002 0.094 0.035 0.1220.27 ‐ 100,293,100 17,667,125 82,625,975 6,135 0.02 0.002 0.097 0.035 0.1260.28 ‐ 100,291,100 17,667,125 82,623,975 6,173 0.02 0.003 0.102 0.036 0.1310.29 ‐ ‐ ‐ 6,211 ‐ 0.004 0.105 0.037 0.1350.28 ‐ ‐ ‐ 6,249 ‐ 0.005 0.108 0.038 0.1400.29 ‐ ‐ ‐ 6,287 ‐ 0.006 0.113 0.039 0.1440.30 ‐ ‐ ‐ 6,326 ‐ 0.006 0.121 0.041 0.1530.32 ‐ ‐ ‐ 6,364 ‐ 0.006 0.127 0.041 0.1610.33 ‐ ‐ ‐ 6,403 ‐ 0.006 0.133 0.042 0.1680.35 ‐ ‐ 6,442 ‐ 0.006 0.137 0.043 0.1720.36 Prepared by Seattle-Northwest Securities Corporation12/1/2009
Year112/1/2011212/1/2012312/1/2013412/1/2014512/1/2015612/1/2016712/1/2017812/1/2018912/1/20191012/1/20201112/1/20211212/1/20221312/1/20231412/1/20241512/1/20251612/1/20261712/1/20271812/1/20281912/1/20292012/1/20302112/1/20312212/1/20322312/1/20332412/1/20342512/1/20352612/1/20362712/1/20372812/1/20382912/1/20393012/1/20403112/1/20413212/1/20423312/1/2043DSM (000s) Fuel Cost (000s)Fixed O&M Cost (000s)Variable O&M Cost (000s)CO² Cost (000s) Seed CapitalSeed Capital Fund BalanceFixed Rate Charge for RevenuesRevenue available after debt serviceGRETC Direct Debt Service CoverageUse of Coverage Coverage Balance2.50% 2.50% 2.50% 2.50% 2.50% 0.00% 1.25 0.00%651 259,482 39,359 30,852 ‐ ‐ ‐ 44,085,125 8,817,025 1.25 8,817,025 1,491 271,611 38,557 32,902 54,963 ‐ ‐ 98,182,488 19,636,498 1.25 28,453,523 3,063 258,329 42,181 31,820 56,995 ‐ ‐ 98,180,113 19,636,023 1.25 48,089,545 5,878 282,641 42,195 32,212 63,421 ‐ ‐ 130,810,269 26,162,054 1.25 25,000,000 49,251,599 10,455 361,674 35,055 35,819 65,306 ‐ ‐ 170,846,774 34,169,355 1.25 83,420,954 12,759 373,704 37,978 35,083 68,216 ‐ ‐ 170,849,837 34,169,967 1.25 117,590,921 11,891 352,673 38,010 36,043 73,346 ‐ ‐ 210,411,399 42,082,280 1.25 105,000,000 54,673,201 12,241 224,380 36,088 34,170 81,543 ‐ ‐ 258,963,946 51,792,789 1.25‐ 106,465,990 12,657 244,337 34,987 35,596 86,958 ‐ ‐ 258,966,633 51,793,327 1.25 158,259,317 13,124 235,418 37,177 29,384 90,354 ‐ ‐ 381,013,977 76,202,795 1.25 190,000,000 44,462,112 13,346 247,202 39,360 30,390 97,474 ‐ ‐ 530,774,401 106,154,880 1.25 150,616,992 14,024 267,038 41,731 29,426 110,165 ‐ ‐ 530,773,463 106,154,693 1.25 256,771,685 4,166 284,104 35,897 30,380 114,805 ‐ ‐ 585,219,745 117,043,949 1.25 320,000,000 53,815,634 3,313 297,843 36,104 33,631 125,785 ‐ ‐ 652,032,594 130,406,519 1.25 184,222,153 4,222 201,105 57,389 29,739 90,619 ‐ ‐ 652,034,406 130,406,881 1.25 314,629,034 5,342 227,331 57,967 16,925 107,681 ‐ ‐ 652,028,469 130,405,694 1.25 445,034,728 8,551 238,262 58,593 17,362 118,039 ‐ ‐ 652,021,469 130,404,294 1.25 485,500,231 89,938,791 13,323 247,810 59,207 18,257 130,862 ‐ ‐ 652,029,094 130,405,819 1.25‐ 220,344,610 16,151 261,837 59,916 18,745 146,548 ‐ ‐ 652,037,656 130,407,531 1.25 350,752,141 17,064 226,648 84,248 17,865 135,367 ‐ 652,037,094 130,407,419 1.25 481,159,560 14,951 224,691 84,983 15,652 140,642 ‐ 652,033,031 130,406,606 1.25 611,566,166 15,081 234,947 86,456 16,121 152,129 ‐ 652,032,969 130,406,594 1.25 741,972,760 15,919 249,713 87,902 16,762 166,550 ‐ 652,027,094 130,405,419 1.25 872,378,179 16,747 260,041 89,276 17,408 180,198 ‐ 652,032,906 130,406,581 1.25 239,531,757 763,253,003 18,111 279,793 90,794 18,296 200,974 ‐ 652,024,281 130,404,856 1.25 893,657,859 5,493 292,296 92,408 18,814 218,387 ‐ 652,027,844 130,405,569 1.25 1,024,063,428 7,019 335,171 97,112 19,787 257,520 ‐ 652,025,281 130,405,056 1.25 1,154,468,484 6,453 352,597 98,638 20,542 281,586 ‐ 652,030,969 130,406,194 1.25 1,284,874,678 8,848 368,539 100,317 21,287 306,519 ‐ 652,033,094 130,406,619 1.25 699,805,525 715,475,772 12,284 385,523 101,920 22,049 332,326 ‐ 652,026,219 130,405,244 1.25 845,881,016 18,825 403,233 103,660 22,861 361,453 ‐ 652,029,156 130,405,831 1.25 976,286,847 21,552 394,321 95,445 21,546 371,427 ‐ 550,520,281 110,104,056 1.25 1,086,390,903 22,199 412,100 97,223 22,392 404,276 ‐ 550,525,969 110,105,194 1.25 720,727,822 475,768,275 //3412/1/20443512/1/20453612/1/20463712/1/20473812/1/20483912/1/20494012/1/20504112/1/20514212/1/20524312/1/20534412/1/20544512/1/20554612/1/20564712/1/20574812/1/20584912/1/20595012/1/2060,,,,,,,,,,,,,23,458 428,330 152,761 23,116 439,168 ‐ 550,524,094 110,104,819 1.25 585,873,094 22,134 449,075 101,037 23,977 476,267 ‐ 475,401,781 95,080,356 1.25 680,953,450 22,961 421,293 140,010 26,073 466,403 ‐ 475,396,156 95,079,231 1.25 776,032,681 24,452 424,059 142,963 26,511 490,408 ‐ 475,393,594 95,078,719 1.25 871,111,400 25,398 444,961 146,057 27,392 537,229 ‐ 384,293,281 76,858,656 1.25 947,970,056 6,909 461,902 149,291 28,395 584,308 ‐ 384,294,781 76,858,956 1.25 1,024,829,013 8,724 477,627 152,489 29,313 630,743 ‐ 384,300,344 76,860,069 1.25 1,101,689,082 11,174 503,605 155,601 30,361 656,308 ‐ 103,283,594 20,656,719 1.25 1,122,345,800 9,139 520,728 158,955 31,315 676,369 ‐ 103,282,469 20,656,494 1.25 1,143,002,294 14,889 546,462 162,470 32,477 705,371 ‐ 103,279,969 20,655,994 1.25 1,163,658,288 22,880 562,487 165,955 33,535 723,997 ‐ ‐ ‐ 0.00 410,069,419 753,588,869 27,949 579,273 169,720 34,785 749,388 ‐ ‐ ‐ 0.00 753,588,869 30,133 605,200 173,255 35,877 774,023 ‐ ‐ ‐ 0.00 753,588,869 33,288 647,750 180,086 37,668 822,050 ‐ ‐ ‐ 0.00 753,588,869 33,226 682,788 182,230 38,924 862,251 ‐ ‐ ‐ 0.00 753,588,869 31,309 716,551 186,278 40,624 900,505 ‐ ‐ ‐ 0.00 753,588,869 32,092 734,465 190,935 41,639 923,018 ‐ ‐ ‐ 0.00 753,588,869 Prepared by Seattle-Northwest Securities Corporation12/1/2009
RIRP Plan 1A - Alternative Case Financial Model
Alaska Regional Integrated Resource PlanYearHydro Capital RequirementsOther Unit Cost Capital RequirementsTransmission RequirementsTotal Capital Requirements (less large hydro)STATE Funding ‐ loan and paybackUse of coverage balance for capital projectsCapital Markets ‐ BONDSScenario Cash Flow Summarydollars in millions112/1/20111 506,496,362 ‐ 506,496,362 ‐ 833,019,182$ 212/1/2012‐ 256,773,239 ‐ 256,773,239 ‐ ‐ ‐ 312/1/2013‐ 119,476,707 3,990,284 123,466,991 ‐ ‐ ‐ 412/1/2014‐ 122,463,625 52,942,550 175,406,175 ‐ (15,000,000) 470,031,769$ 512/1/2015‐ 2,435,356 191,310,564 193,745,920 ‐ ‐ ‐ Sources of Funds612/1/201633,699,203 22,466,161 255,989,420 278,455,581 2,409,373,640 ‐ ‐ BONDS 3,657 712/1/201726,865,753 74,229,623 117,965,769 192,195,392 ‐ (75,000,000) 522,012,548$ STATE (through construction) 2,409 812/1/201843,273,053 174,256,113 41,630,847 215,886,960 ‐ ‐ ‐ Infrastructure Tax through 2027 883 912/1/201979,301,147 174,171,476 169,193,895 343,365,370 ‐ ‐ ‐ Other (Use of Coverage Reserves) 2,135 1012/1/2020238,340,271 208,891,416 321,882,411 530,773,827 ‐ (120,000,000) 999,656,778$ Total Source of Funds 9,085 1112/1/2021481,536,897 21,500,060 282,636,456 304,136,516 ‐ ‐ ‐ 1212/1/2022652,793,164 ‐ 437,331,250 437,331,250 ‐ ‐ ‐ Use of Funds1312/1/2023712,137,997 ‐ 464,423,300 464,423,300 ‐ (180,000,000) 229,188,962$ Project/Construction 9,085 1412/1/2024141,426,155 ‐ 59,937,820 59,937,820 ‐ ‐ ‐ Payment of interest accrued 0 1512/1/2025‐ ‐ 18,210,430 18,210,430 ‐ ‐ ‐ Reserve Funds 0 1612/1/2026‐ ‐ 19,062,834 19,062,834 ‐ ‐ ‐ Issuance Costs 0 1712/1/2027‐ 88,657,273 ‐ 88,657,273 ‐ (245,000,000) 32,875,895$ Capitalized Interest (through construction) 0 1812/1/2028‐ 208,125,424 ‐ 208,125,424 ‐ ‐ ‐ Total Uses of Funds 9,085 1912/1/2029‐ 188,717,535 ‐ 188,717,535 ‐ ‐ ‐ 2012/1/2030‐ ‐ ‐ ‐ ‐ ‐ Maximum Annual Debt Service Requirements2112/1/2031‐ ‐ ‐ ‐ ‐ ‐ BONDS 314 2212/1/2032‐ ‐ ‐ ‐ ‐ ‐ STATE 322 2312/1/2033‐ ‐ ‐ ‐ ‐ ‐ 2412/1/2034‐ 2,260,136 2,260,136 ‐ (239,531,757) 0$ 2512/1/2035‐ 206,133,124 206,133,124 ‐ ‐ ‐ Ave.Annual Energy Requirement (GWhr)5,625 2612/1/2036‐ 31,138,497 31,138,497 ‐ ‐ ‐ Target Debt Service Coverage (DSC)1.25X 2712/1/2037‐ ‐ ‐ ‐ ‐ ‐ All-in Borrowing Cost7.00% 2812/1/2038‐ ‐ ‐ ‐ ‐ ‐ Escalation Factor (Inflation)2.50% 2912/1/2039‐ 127,791,596 127,791,596 ‐ (600,000,000) 99,805,525$ Average Cost of Energy ($/per kWh)0.06 3012/1/2040‐ 299,994,339 299,994,339 ‐ ‐ ‐ 3112/1/2041‐ 272,019,589 272,019,589 ‐ ‐ ‐ RIRP PLAN 1AAlternative Scenario100% Fixed Rate3212/1/2042‐ ‐ ‐ ‐ ‐ ‐ 3312/1/2043‐ 131,612,221 131,612,221 ‐ (250,000,000) 470,727,822$ Assumptions3412/1/2044‐ 308,963,361 308,963,361 ‐ ‐ ‐ Issuance Cost = 2% of Par Amount 3512/1/2045‐ 280,152,241 280,152,241 ‐ ‐ ‐ Par coupons 3612/1/2046‐ ‐ ‐ ‐ ‐ ‐ Debt service reserve funded at 10% of Bond Par Amount 3712/1/2047‐ ‐ ‐ 2,409,373,640 ‐ ‐ Bonds all assumed to be 30 years from date of issue 3812/1/2048‐ ‐ ‐ ‐ ‐ ‐ 3912/1/2049‐ ‐ ‐ ‐ ‐ ‐ 4012/1/2050‐ ‐ ‐ ‐ ‐ ‐ 4112/1/2051‐ ‐ ‐ ‐ ‐ ‐ 4212/1/2052‐ ‐ ‐ ‐ ‐ ‐ 4312/1/2053‐ ‐ ‐ ‐ ‐ ‐ 4412/1/2054‐ ‐ ‐ ‐ (410,069,419) (0)$ 4512/1/2055‐ 35,525,625 35,525,625 ‐ ‐ ‐ 4612/1/2056‐ 161,918,291 161,918,291 ‐ ‐ ‐ 4712/1/2057‐ ‐ ‐ ‐ ‐ ‐ 4812/1/2058‐ 38,257,213 38,257,213 ‐ ‐ ‐ 4912/1/2059‐ 174,368,290 174,368,290 ‐ ‐ ‐ 5012/1/2060‐ ‐ ‐ ‐ Prepared by Seattle-Northwest Securities Corporation12/1/2009
Year112/1/2011212/1/2012312/1/2013412/1/2014512/1/2015612/1/2016712/1/2017812/1/2018912/1/20191012/1/20201112/1/20211212/1/20221312/1/20231412/1/20241512/1/20251612/1/20261712/1/20271812/1/20281912/1/20292012/1/20302112/1/20312212/1/20322312/1/20332412/1/20342512/1/20352612/1/20362712/1/20372812/1/20382912/1/20393012/1/20403112/1/2041Repayment of State fundsGRETC Direct Debt Service ‐ paid to bondholdersDSRF Interest Earnings Total RequirementsEnergy per Year (GWhr) Surcharge for seed capital Fixed Rate Charge for Capital DSM Fuel Rate O&M Rate (Fixed + Variable) CO² Incremental Cost (¢ per kWh) 1.00570.01 ‐$ 33,131,525$ ‐$ 33,131,525$ 5,372 0.010 0.01 0.000 0.048 0.013 0.0000.08 76,283,050 2,499,058 73,783,992 5,412 0.010 0.02 0.000 0.051 0.013 0.0100.10 76,281,650 2,499,058 73,782,592 5,424 0.010 0.02 0.001 0.048 0.014 0.0110.10 94,980,800 2,499,058 92,481,742 5,421 0.010 0.02 0.001 0.053 0.014 0.0120.11 119,327,100 3,909,153 115,417,947 5,167 0.010 0.03 0.002 0.067 0.013 0.0120.13 ‐ 119,327,000 3,909,153 115,417,847 5,147 0.010 0.03 0.002 0.070 0.014 0.0130.14 ‐ 140,091,050 3,909,153 136,181,897 5,129 0.010 0.03 0.002 0.066 0.014 0.0140.14 ‐ 167,135,950 5,475,190 161,660,760 5,105 0.010 0.04 0.002 0.042 0.013 0.0150.12 ‐ 167,133,450 5,475,190 161,658,260 5,085 0.010 0.04 0.002 0.045 0.013 0.0160.13 ‐ 206,891,825 5,475,190 201,416,635 5,068 0.010 0.05 0.002 0.044 0.012 0.0170.14 ‐ 258,677,150 8,474,161 250,202,989 5,052 0.010 0.06 0.002 0.046 0.013 0.0180.15 ‐ 258,678,050 8,474,161 250,203,889 5,081 0.010 0.06 0.003 0.050 0.013 0.0210.16 ‐ 267,790,975 8,474,161 259,316,814 5,111 0.010 0.06 0.001 0.053 0.012 0.0210.16 ‐ 279,659,600 9,161,728 270,497,872 5,140 0.010 0.07 0.001 0.055 0.013 0.0230.17 ‐ 279,668,350 9,161,728 270,506,622 5,174 0.010 0.07 0.001 0.037 0.016 0.0170.15 ‐ 279,658,100 9,161,728 270,496,372 5,207 0.010 0.06 0.001 0.042 0.014 0.0200.15 ‐ 292,456,550 9,161,728 283,294,822 5,241 0.010 0.07 0.002 0.044 0.014 0.0220.16 ‐ 305,241,850 9,260,355 295,981,495 5,275 0.07 0.002 0.046 0.014 0.0240.16 ‐ 305,240,900 9,260,355 295,980,545 5,309 0.07 0.003 0.049 0.015 0.0270.16 ‐ 305,242,800 9,260,355 295,982,445 5,344 0.07 0.003 0.042 0.019 0.0250.16 ‐ 305,244,200 9,260,355 295,983,845 5,378 0.07 0.003 0.042 0.019 0.0260.16 ‐ 305,245,000 9,260,355 295,984,645 5,413 0.07 0.003 0.044 0.019 0.0280.16 ‐ 305,243,000 9,260,355 295,982,645 5,447 0.07 0.003 0.046 0.019 0.0310.17 ‐ 305,243,900 9,260,355 295,983,545 5,482 0.07 0.003 0.048 0.020 0.0340.17 ‐ 305,240,600 9,260,355 295,980,245 5,517 0.07 0.003 0.052 0.020 0.0370.18 ‐ 305,243,900 9,260,355 295,983,545 5,553 0.07 0.001 0.054 0.021 0.0410.18 ‐ 305,236,100 9,260,355 295,975,745 5,588 0.07 0.001 0.062 0.022 0.0480.20 ‐ 305,237,750 9,260,355 295,977,395 5,623 0.07 0.001 0.066 0.022 0.0520.21 ‐ 309,204,550 9,260,355 299,944,195 5,659 0.07 0.002 0.069 0.023 0.0570.22 ‐ 314,375,350 9,559,772 304,815,578 5,695 0.07 0.002 0.072 0.023 0.0620.23 ‐ 314,385,800 9,559,772 304,826,028 5,731 0.07 0.004 0.075 0.024 0.0670.24 3212/1/20423312/1/20433412/1/20443512/1/20453612/1/20463712/1/20473812/1/20483912/1/20494012/1/20504112/1/20514212/1/20524312/1/20534412/1/20544512/1/20554612/1/20564712/1/20574812/1/20584912/1/20595012/1/2060‐ 238,098,800 9,559,772 228,539,028 5,767 0.05 0.004 0.073 0.022 0.0690.22 ‐ 256,818,500 9,559,772 247,258,728 5,803 0.05 0.004 0.077 0.022 0.0750.23 ‐ 281,213,300 10,971,955 270,241,345 5,839 0.06 0.004 0.080 0.033 0.0820.26 ‐ 238,156,850 10,971,955 227,184,895 5,876 0.05 0.004 0.084 0.023 0.0890.25 ‐ 238,159,400 10,971,955 227,187,445 5,912 0.05 0.004 0.078 0.031 0.0870.25 95,827,375 238,157,150 10,971,955 323,012,570 5,949 0.07 0.005 0.079 0.032 0.0910.27 191,654,750 190,355,650 10,971,955 371,038,445 5,986 0.08 0.005 0.083 0.032 0.1000.30 191,654,750 190,357,950 10,971,955 371,040,745 6,023 0.08 0.001 0.086 0.033 0.1090.31 191,654,750 190,355,750 10,971,955 371,038,545 6,060 0.08 0.002 0.089 0.034 0.1170.32 191,654,750 98,815,900 10,971,955 279,498,695 6,098 0.06 0.002 0.094 0.035 0.1220.31 191,654,750 98,809,900 10,971,955 279,492,695 6,135 0.06 0.002 0.097 0.035 0.1260.32 191,654,750 98,809,900 10,971,955 279,492,695 6,173 0.06 0.003 0.102 0.036 0.1310.33 191,654,750 77,824,800 10,971,955 258,507,595 6,211 0.05 0.004 0.105 0.037 0.1350.33 196,264,750 77,826,750 10,971,955 263,119,545 6,249 0.05 0.005 0.108 0.038 0.1400.34 201,172,050 77,826,500 10,971,955 268,026,595 6,287 0.05 0.006 0.113 0.039 0.1440.35 206,198,250 52,247,150 10,971,955 247,473,445 6,326 0.05 0.006 0.121 0.041 0.1530.37 211,354,400 52,246,350 10,971,955 252,628,795 6,364 0.05 0.006 0.127 0.041 0.1610.38 216,638,400 52,250,150 10,971,955 257,916,595 6,403 0.05 0.006 0.133 0.042 0.1680.40 222,055,700 52,242,250 10,971,955 263,325,995 6,442 0.05 0.006 0.137 0.043 0.1720.41 Prepared by Seattle-Northwest Securities Corporation12/1/2009
Year112/1/2011212/1/2012312/1/2013412/1/2014512/1/2015612/1/2016712/1/2017812/1/2018912/1/20191012/1/20201112/1/20211212/1/20221312/1/20231412/1/20241512/1/20251612/1/20261712/1/20271812/1/20281912/1/20292012/1/20302112/1/20312212/1/20322312/1/20332412/1/20342512/1/20352612/1/20362712/1/20372812/1/20382912/1/20393012/1/20403112/1/2041DSM (000s) Fuel Cost (000s)Fixed O&M Cost (000s)Variable O&M Cost (000s)CO² Cost (000s) Seed CapitalFixed Rate Charge for RevenuesRevenue available after debt serviceGRETC Direct Debt Service CoverageUse of Coverage Coverage Balance2.50% 2.50% 2.50% 2.50% 2.50%1.25 0.00%651 259,482 39,359 30,852 ‐ 53,717,410.47 41,414,406 8,282,881 1.25 8,282,881 1,491 271,611 38,557 32,902 54,963 54,120,733.86 92,229,991 18,445,998 1.25 26,728,879 3,063 258,329 42,181 31,820 56,995 54,241,323.99 92,228,241 18,445,648 1.25 45,174,527 5,878 282,641 42,195 32,212 63,421 54,213,850.02 115,602,178 23,120,436 1.25 15,000,000 53,294,963 10,455 361,674 35,055 35,819 65,306 51,673,819.94 144,272,434 28,854,487 1.25 82,149,450 12,759 373,704 37,978 35,083 68,216 51,473,835.41 144,272,309 28,854,462 1.25 111,003,912 11,891 352,673 38,010 36,043 73,346 51,287,518.63 170,227,371 34,045,474 1.25 75,000,000 70,049,386 12,241 224,380 36,088 34,170 81,543 51,052,273.99 202,075,949 40,415,190 1.25‐ 110,464,576 12,657 244,337 34,987 35,596 86,958 50,849,002.21 202,072,824 40,414,565 1.25 150,879,141 13,124 235,418 37,177 29,384 90,354 50,683,538.05 251,770,793 50,354,159 1.25 120,000,000 81,233,299 13,346 247,202 39,360 30,390 97,474 50,524,635.70 312,753,736 62,550,747 1.25 143,784,047 14,024 267,038 41,731 29,426 110,165 50,814,618.33 312,754,861 62,550,972 1.25 206,335,019 4,166 284,104 35,897 30,380 114,805 51,106,167.59 324,146,018 64,829,204 1.25 180,000,000 91,164,222 3,313 297,843 36,104 33,631 125,785 51,401,295.01 338,122,340 67,624,468 1.25 158,788,691 4,222 201,105 57,389 29,739 90,619 51,736,787.37 338,133,278 67,626,656 1.25 226,415,346 5,342 227,331 57,967 16,925 107,681 52,073,821.68 338,120,465 67,624,093 1.25 294,039,439 8,551 238,262 58,593 17,362 118,039 52,412,432.40 354,118,528 70,823,706 1.25 245,000,000 119,863,145 13,323 247,810 59,207 18,257 130,862 ‐ 369,976,868 73,995,374 1.25 193,858,518 16,151 261,837 59,916 18,745 146,548 ‐ 369,975,681 73,995,136 1.25 267,853,655 17,064 226,648 84,248 17,865 135,367 ‐ 369,978,056 73,995,611 1.25 341,849,266 14,951 224,691 84,983 15,652 140,642 ‐ 369,979,806 73,995,961 1.25 415,845,227 15,081 234,947 86,456 16,121 152,129 ‐ 369,980,806 73,996,161 1.25 489,841,388 15,919 249,713 87,902 16,762 166,550 ‐ 369,978,306 73,995,661 1.25 563,837,049 16,747 260,041 89,276 17,408 180,198 ‐ 369,979,431 73,995,886 1.25 239,531,757 398,301,178 18,111 279,793 90,794 18,296 200,974 ‐ 369,975,306 73,995,061 1.25‐ 472,296,239 5,493 292,296 92,408 18,814 218,387 ‐ 369,979,431 73,995,886 1.25 546,292,126 7,019 335,171 97,112 19,787 257,520 ‐ 369,969,681 73,993,936 1.25 620,286,062 6,453 352,597 98,638 20,542 281,586 ‐ 369,971,743 73,994,349 1.25 694,280,410 8,848 368,539 100,317 21,287 306,519 ‐ 374,930,243 74,986,049 1.25 600,000,000 169,266,459 12,284 385,523 101,920 22,049 332,326 ‐ 381,019,473 76,203,895 1.25 245,470,354 18,825 403,233 103,660 22,861 361,453 ‐ 381,032,535 76,206,507 1.25 321,676,861 3212/1/20423312/1/20433412/1/20443512/1/20453612/1/20463712/1/20473812/1/20483912/1/20494012/1/20504112/1/20514212/1/20524312/1/20534412/1/20544512/1/20554612/1/20564712/1/20574812/1/20584912/1/20595012/1/206021,552 394,321 95,445 21,546 371,427 ‐ 285,673,785 57,134,757 1.25 378,811,618 22,199 412,100 97,223 22,392 404,276 ‐ 309,073,410 61,814,682 1.25 250,000,000 190,626,300 23,458 428,330 152,761 23,116 439,168 ‐ 337,801,681 67,560,336 1.25‐ 258,186,636 22,134 449,075 101,037 23,977 476,267 ‐ 283,981,118 56,796,224 1.25 314,982,859 22,961 421,293 140,010 26,073 466,403 ‐ 283,984,306 56,796,861 1.25 371,779,720 24,452 424,059 142,963 26,511 490,408 ‐ 403,765,712 80,753,142 1.25 452,532,863 25,398 444,961 146,057 27,392 537,229 ‐ 463,798,056 92,759,611 1.25 545,292,474 6,909 461,902 149,291 28,395 584,308 ‐ 463,800,931 92,760,186 1.25 638,052,660 8,724 477,627 152,489 29,313 630,743 ‐ 463,798,181 92,759,636 1.25 730,812,296 11,174 503,605 155,601 30,361 656,308 ‐ 349,373,368 69,874,674 1.25 800,686,970 9,139 520,728 158,955 31,315 676,369 ‐ 349,365,868 69,873,174 1.25 870,560,144 14,889 546,462 162,470 32,477 705,371 ‐ 349,365,868 69,873,174 1.25 940,433,317 22,880 562,487 165,955 33,535 723,997 ‐ 323,134,493 64,626,899 1.25 410,069,419 594,990,797 27,949 579,273 169,720 34,785 749,388 ‐ 328,899,431 65,779,886 1.25 660,770,683 30,133 605,200 173,255 35,877 774,023 ‐ 335,033,243 67,006,649 1.25 727,777,332 33,288 647,750 180,086 37,668 822,050 ‐ 309,341,806 61,868,361 1.25 789,645,693 33,226 682,788 182,230 38,924 862,251 ‐ 315,785,993 63,157,199 1.25 852,802,891 31,309 716,551 186,278 40,624 900,505 ‐ 322,395,743 64,479,149 1.25 917,282,040 32,092 734,465 190,935 41,639 923,018 329,157,493 65,831,499 1.25 983,113,539 Prepared by Seattle-Northwest Securities Corporation12/1/2009
APPENDIX C EXISTING GENERATION UNITS
ALASKA RIRP STUDY
Black & Veatch C-1 February 2010
APPENDIX C
EXISTING GENERATION UNITS
Detailed Existing Unit TablesName Unit Primary Fuel Startup FuelWinter Rating (MW)Summer Rating (MW)Minimum Capacity (MW)Variable O&M (2009 $/MWh)Fixed O&M (2009 $/kW-yr)Full Load Net Plant Heat Rate (Btu/kWh - HHV)Forcd Outage Rate (%)Must Run (Y/N)CO2 Emission Rate (lb/mmBtu)NOx Emission Rate (lb/mmBtu)SO2 Emission Rate (lb/mmBtu) Retirement DateAnchorage ML&P – Plant 1 3 Natural Gas Natural Gas 32 29.3 1 3.72 10.87 9,780 6.0 N 114.8 0.44 0.000045 2037Anchorage ML&P – Plant 2 5 Natural Gas Natural Gas 37.4 33.8 5 3.72 11.62 14 1.1 N 114.8 0.625 0.000045 2020Anchorage ML&P – Plant 2 5/6 Natural Gas Natural Gas 49.2 44.5 10 3.72 11.62 11 1.1 N 114.8 0.625 0.000045 2020Anchorage ML&P – Plant 2 7 Natural Gas Natural Gas 81.8 74.4 10 3.72 7.79 1,193 0.1 N 114.8 0.625 0.000045 2030Anchorage ML&P – Plant 2 7/6 Natural Gas Natural Gas 109.5 99.5 10 3.72 7.79 9,030 0.1 N 114.8 0.625 0.000045 2020Anchorage ML&P – Plant 2 8 Natural Gas Natural Gas 87.6 77.3 20 3.72 7.47 11,930 1.7 N 114.8 0.08 0.000045 2030
Name UnitPrimary Fuel Startup FuelWinter Rating (MW)Summer Rating (MW)Minimum Capacity (MW)Variable O&M (2009 $/MWh)Fixed O&M (2009 $/kW-yr)Full Load Net Plant Heat Rate (Btu/kWh - HHV)Forcd Outage Rate (%)Must Run (Y/N)CO2 Emission Rate (lb/mmBtu)NOx Emission Rate (lb/mmBtu)SO2 Emission Rate (lb/mmBtu) Retirement DateBernice 2 Natural Gas Natural Gas 19 19 3 1.23 6.15 14,673 2.0 N 115 0.32 0.000045 2014Bernice 3 Natural Gas Natural Gas 25.5 25.5 13 1.23 19.48 13,409 2.0 N 115 0.13 0.000045 2014Bernice 4 Natural Gas Natural Gas 25.5 25.5 13 1.23 19.48 13,741 2.0 N 115 0.13 0.000045 2014Beluga 1 Natural Gas Natural Gas 17.5 16 3 1.23 14.35 15,198 2.0 N 115 0.32 0.0002 2011Beluga 2 Natural Gas Natural Gas 17.5 16 3 1.23 14.35 14,851 2.0 N 115 0.32 0.0002 2011Beluga 3 Natural Gas Natural Gas 66.5 56 3 1.44 12.30 12,236 2.0 N 115 0.32 0.0002 2014Beluga 5 Natural Gas Natural Gas 65 54 3 1.44 12.30 12,537 2.0 N 115 0.32 0.0002 2017Beluga 6 Natural Gas Natural Gas 82 64 3 1.64 13.33 11,528 1.0 N 115 0.2 0.001 2020Beluga 6/8 Natural Gas Natural Gas 108.5 83 48 2.56 29.73 9,329 4.0 N 115 0.2 0.001 2014Beluga 7 Natural Gas Natural Gas 82 66 3 1.64 13.33 12,184 1.0 N 115 0.34 0.006 2021Beluga 7/8 Natural Gas Natural Gas 108.5 85 48 2.56 29.73 9,086 4.0 N 115 0.34 0.006 2014International 1 Natural Gas Natural Gas 14 13 3 1.23 14.35 16,379 2.0 N 115 0.32 0.002 2011International 2 Natural Gas Natural Gas 14 12.5 3 1.23 14.35 17,425 2.0 N 115 0.32 0.002 2011International 3 Natural Gas Natural Gas 19 16 3 1.23 14.35 15,116 2.0 N 115 0.32 0.002 2012
Name Unit Primary Fuel Startup FuelWinter Rating (MW)Summer Rating (MW)Minimum Capacity (MW)Variable O&M (2009 $/MWh)Fixed O&M (2009 $/kW-yr)Full Load Net Plant Heat Rate (Btu/kWh - HHV)Forcd Outage Rate (%)Must Run(Y/N)CO2 Emission Rate (lb/mmBtu)NOx Emission Rate (lb/mmBtu)SO2 Emission Rate (lb/mmBtu)Retirement DateZehnder GT1 HAGO Distillate Fuel Oil 19.2 15.8 4 8.23 10.98 14,030 0.1 N 128 0.7 0.8 2030Zehnder GT2 HAGO Distillate Fuel Oil 19.6 15 4 8.23 10.98 14,190 0.2 N 128 0.7 0.8 2030North Pole GT1 HAGO Distillate Fuel Oil 62.6 50 10 3.91 21.41 10,010 0.6 N 128 0.7 0.7 2017North Pole GT2 HAGO Distillate Fuel Oil 60.6 48 10 3.91 21.41 9,720 0.5 N 128 0.7 0.7 2018North Pole CC NAPHTHA Distillate Fuel Oil 65 54 38 3.20 224.56 6,620 0.4 N 114.8 0.76 0.0022 2042Healy ST1 COAL Distillate Fuel Oil 27 26.5 20 3.30 208.60 13,870 0.7 Y 211 0.25 0.3 2022DPP 1 HAGO Distillate Fuel Oil 25.8 23.1 4 8.23 10.98 13,210 0.3 N 128 0.7 0.12 2030
Name UnitPrimary Fuel Startup FuelWinter Rating (MW)Summer Rating (MW)Minimum Capacity (MW)Variable O&M (2009 $/MWh)Fixed O&M (2009 $/kW-yr)Full Load Net Plant Heat Rate (Btu/kWh - HHV)Forcd Outage Rate (%)Must Run (Y/N)CO2 Emission Rate (lb/mmBtu)NOx Emission Rate (lb/mmBtu)SO2 Emission Rate (lb/mmBtu) Retirement DateNikiski 1 Natural Gas Natural Gas 42 38 3 6.63 4.82 12,170 1.0 Y 114.8 0.13 0.000045 2026
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-1 February 2010
APPENDIX D
REGIONAL LOAD FORECASTS
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-2 February 2010
Table D-1
GRETC’s Winter Peak Load Forecast for Evaluation
2011 - 2060
Winter Peak Demand (MW)
Year CEA GVEA HEA MEA ML&P SES GRETC
2010/2011 233.9 238.1 87.0 146.0 188.0 9.5 869.3
2011/2012 233.9 239.6 88.0 151.0 189.0 9.5 877.5
2012/2013 233.9 241.3 88.0 153.0 190.0 10.4 883.0
2013/2014 233.9 242.9 88.0 155.0 191.0 10.4 887.4
2014/2015 234.5 217.5 89.0 157.0 192.0 10.4 867.8
2015/2016 234.9 219.2 90.0 159.0 193.0 10.4 873.3
2016/2017 235.5 221.1 90.0 161.0 194.0 10.4 879.0
2017/2018 236.5 222.7 91.0 163.0 195.0 10.4 885.4
2018/2019 237.6 224.3 92.0 165.0 196.0 10.4 891.8
2019/2020 238.1 226.0 92.0 167.0 197.0 10.4 896.3
2020/2021 238.6 227.6 93.0 169.0 198.0 10.4 902.7
2021/2022 239.7 229.2 94.0 171.0 199.0 10.4 909.1
2022/2023 240.7 230.9 94.0 173.0 200.0 10.4 914.6
2023/2024 241.7 232.6 95.0 176.0 201.0 10.4 922.1
2024/2025 242.2 234.3 96.0 178.0 202.0 10.4 927.5
2025/2026 242.8 236.0 97.0 180.0 203.0 10.4 934.0
2026/2027 243.8 237.7 97.0 182.0 204.0 10.4 939.6
2027/2028 244.8 239.4 98.0 184.0 205.0 10.4 946.1
2028/2029 245.9 241.1 99.0 186.0 206.0 10.4 952.5
2029/2030 246.9 242.8 100.0 188.0 207.0 10.4 959.0
2030/2031 247.9 244.5 100.8 190.2 208.0 10.4 965.4
2031/2032 248.8 246.2 101.6 192.4 209.0 10.4 971.8
2032/2033 249.7 248.0 102.4 194.6 210.0 10.4 978.3
2033/2034 250.7 249.7 103.2 196.8 211.1 10.4 984.7
2034/2035 251.6 251.5 104.0 199.0 212.1 10.4 991.2
2035/2036 252.5 253.2 104.8 201.3 213.1 10.4 997.7
2036/2037 253.5 255.0 105.6 203.5 214.1 10.4 1004.3
2037/2038 254.4 256.7 106.4 205.8 215.2 10.4 1010.9
2038/2039 255.4 258.5 107.3 208.1 216.2 10.4 1017.4
2039/2040 256.3 260.3 108.1 210.4 217.2 10.4 1024.1
2040/2041 257.3 262.0 108.9 212.7 218.3 10.4 1030.7
2041/2042 258.2 263.8 109.7 215.0 219.3 10.4 1037.4
2042/2043 259.2 265.6 110.6 217.4 220.4 10.4 1044.1
2043/2044 260.1 267.4 111.4 219.7 221.4 10.4 1050.9
2044/2045 261.1 269.2 112.3 222.1 222.5 10.4 1057.7
2045/2046 262.0 271.1 113.1 224.5 223.5 10.4 1064.5
2046/2047 263.0 272.9 114.0 226.9 224.6 10.4 1071.3
2047/2048 264.0 274.7 114.8 229.3 225.6 10.4 1078.2
2048/2049 264.9 276.5 115.7 231.8 226.7 10.4 1085.0
2049/2050 265.9 278.4 116.5 234.2 227.7 10.4 1092.0
2050/2051 266.9 280.2 117.4 236.7 228.8 10.4 1098.9
2051/2052 267.8 282.1 118.3 239.2 229.9 10.4 1105.9
2052/2053 268.8 284.0 119.1 241.7 231.0 10.4 1112.9
2053/2054 269.8 285.8 120.0 244.2 232.0 10.4 1120.0
2054/2055 270.7 287.7 120.9 246.8 233.1 10.4 1127.1
2055/2056 271.7 289.6 121.8 249.3 234.2 10.4 1134.2
2056/2057 272.7 291.5 122.7 251.9 235.3 10.4 1141.4
2057/2058 273.7 293.4 123.6 254.5 236.4 10.4 1148.5
2058/2059 274.7 295.3 124.4 257.1 237.4 10.4 1155.8
2059/2060 275.7 297.3 125.4 259.7 238.5 10.4 1163.0
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-3 February 2010
Table D-2
GRETC’s Summer Peak Load Forecast for Evaluation
2011 - 2060
Summer Peak Demand (MW)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 160.6 191.4 75.1 91.1 167.2 10.0 668.0
2012 160.6 192.6 75.9 94.1 168.1 10.0 674.3
2013 160.6 193.9 75.9 95.0 169.0 11.0 678.5
2014 160.6 195.2 75.9 95.5 169.9 11.0 681.9
2015 161.3 174.8 76.8 95.5 170.8 11.0 666.8
2016 161.3 176.2 77.7 95.4 171.7 11.0 671.0
2017 162.0 177.7 77.7 95.3 172.6 11.0 675.4
2018 162.7 179.0 78.5 95.1 173.5 11.0 680.3
2019 163.4 180.3 79.4 95.0 174.3 11.0 685.3
2020 163.4 181.6 79.4 95.0 175.2 11.0 688.7
2021 164.2 182.9 80.2 94.9 176.1 11.0 693.6
2022 164.9 184.3 81.1 96.0 177.0 11.0 698.6
2023 165.6 185.6 81.1 97.1 177.9 11.0 702.8
2024 166.3 187.0 82.0 98.7 178.8 11.0 708.5
2025 166.3 188.3 82.8 99.9 179.7 11.0 712.7
2026 167.0 189.7 83.7 101.1 180.6 11.0 717.7
2027 167.7 191.1 83.7 102.3 181.5 11.0 722.0
2028 168.4 192.4 84.6 103.5 182.3 11.0 726.9
2029 169.2 193.8 85.4 104.7 183.2 11.0 731.9
2030 169.9 195.2 86.3 105.9 184.1 11.0 736.9
2031 170.5 196.5 87.0 107.2 185.0 11.0 741.8
2032 171.2 197.9 87.7 108.5 185.9 11.0 746.8
2033 171.8 199.3 88.3 109.8 186.8 11.0 751.7
2034 172.4 200.7 89.0 111.1 187.7 11.0 756.7
2035 173.1 202.1 89.7 112.5 188.7 11.0 761.6
2036 173.7 203.5 90.4 113.8 189.6 11.1 766.7
2037 174.4 204.9 91.1 115.2 190.5 11.1 771.7
2038 175.0 206.3 91.8 116.6 191.4 11.2 776.7
2039 175.7 207.8 92.6 117.9 192.3 11.2 781.8
2040 176.3 209.2 93.3 119.3 193.2 11.3 786.9
2041 177.0 210.6 94.0 120.7 194.2 11.4 792.0
2042 177.6 212.1 94.7 122.1 195.1 11.4 797.1
2043 178.3 213.5 95.4 123.5 196.0 11.5 802.3
2044 179.0 214.9 96.1 124.9 196.9 11.5 807.5
2045 179.6 216.4 96.9 126.4 197.9 11.6 812.7
2046 180.3 217.9 97.6 127.8 198.8 11.7 817.9
2047 180.9 219.3 98.3 129.3 199.8 11.7 823.2
2048 181.6 220.8 99.1 130.7 200.7 11.8 828.4
2049 182.3 222.3 99.8 132.2 201.6 11.8 833.7
2050 182.9 223.8 100.5 133.7 202.6 11.9 839.1
2051 183.6 225.3 101.3 135.2 203.5 12.0 844.4
2052 184.3 226.7 102.0 136.7 204.5 12.0 849.8
2053 184.9 228.2 102.8 138.2 205.4 12.1 855.2
2054 185.6 229.8 103.6 139.7 206.4 12.1 860.6
2055 186.3 231.3 104.3 141.3 207.3 12.2 866.0
2056 186.9 232.8 105.1 142.8 208.3 12.3 871.5
2057 187.6 234.3 105.8 144.4 209.3 12.3 877.0
2058 188.3 235.8 106.6 145.9 210.2 12.4 882.5
2059 189.0 237.4 107.4 147.5 211.2 12.4 888.1
2060 189.6 238.9 108.2 149.1 212.2 12.5 893.6
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-4 February 2010
Table D-3
GRETC’s Annual Valley Load Forecast for Evaluation
2011 - 2060
Annual Valley Demand (MW)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 95.4 88.6 44.4 53.2 91.0 4.4 413.5
2012 95.4 89.2 44.9 55.0 91.5 4.4 417.2
2013 95.4 89.8 44.9 55.8 91.9 4.8 419.7
2014 95.4 90.4 44.9 56.5 92.4 4.8 421.7
2015 95.8 81.0 45.5 57.2 92.9 4.8 413.7
2016 95.8 81.6 46.0 58.0 93.4 4.8 416.3
2017 96.3 82.3 46.0 58.7 93.9 4.8 418.9
2018 96.7 82.9 46.5 59.4 94.4 4.8 421.9
2019 97.1 83.5 47.0 60.2 94.8 4.8 424.9
2020 97.1 84.1 47.0 60.9 95.3 4.8 426.9
2021 97.5 84.7 47.5 61.6 95.8 4.8 429.9
2022 98.0 85.3 48.0 62.3 96.3 4.8 433.0
2023 98.4 86.0 48.0 63.1 96.8 4.8 435.4
2024 98.8 86.6 48.5 64.2 97.3 4.8 438.9
2025 98.8 87.2 49.0 64.9 97.7 4.8 441.4
2026 99.2 87.8 49.5 65.6 98.2 4.8 444.5
2027 99.7 88.5 49.5 66.4 98.7 4.8 447.0
2028 100.1 89.1 50.1 67.1 99.2 4.8 450.0
2029 100.5 89.7 50.6 67.8 99.7 4.8 453.1
2030 100.9 90.4 51.1 68.5 100.2 4.8 456.1
2031 101.3 91.0 51.5 69.3 100.7 4.8 459.1
2032 101.7 91.7 51.9 70.1 101.1 4.8 462.1
2033 102.1 92.3 52.3 70.9 101.6 4.8 465.1
2034 102.5 93.0 52.7 71.7 102.1 4.8 468.1
2035 102.8 93.6 53.1 72.6 102.6 4.8 471.1
2036 103.2 94.3 53.5 73.4 103.1 4.8 474.1
2037 103.6 94.9 54.0 74.2 103.6 4.8 477.2
2038 104.0 95.6 54.4 75.0 104.1 4.8 480.2
2039 104.4 96.2 54.8 75.9 104.6 4.8 483.3
2040 104.8 96.9 55.2 76.7 105.1 4.8 486.4
2041 105.2 97.5 55.6 77.5 105.6 4.8 489.5
2042 105.5 98.2 56.1 78.4 106.1 4.8 492.6
2043 105.9 98.9 56.5 79.2 106.6 4.8 495.7
2044 106.3 99.5 56.9 80.1 107.1 4.8 498.8
2045 106.7 100.2 57.3 81.0 107.6 4.8 502.0
2046 107.1 100.9 57.8 81.8 108.2 4.8 505.2
2047 107.5 101.6 58.2 82.7 108.7 4.8 508.3
2048 107.9 102.3 58.6 83.6 109.2 4.8 511.5
2049 108.3 102.9 59.1 84.5 109.7 4.8 514.7
2050 108.7 103.6 59.5 85.4 110.2 4.8 517.9
2051 109.1 104.3 60.0 86.3 110.7 4.8 521.2
2052 109.5 105.0 60.4 87.2 111.2 4.8 524.4
2053 109.9 105.7 60.9 88.1 111.8 4.8 527.7
2054 110.3 106.4 61.3 89.0 112.3 4.8 530.9
2055 110.7 107.1 61.7 90.0 112.8 4.8 534.2
2056 111.1 107.8 62.2 90.9 113.3 4.8 537.5
2057 111.5 108.5 62.7 91.8 113.8 4.8 540.8
2058 111.9 109.2 63.1 92.8 114.4 4.8 544.2
2059 112.3 109.9 63.6 93.7 114.9 4.8 547.5
2060 112.7 110.7 64.0 94.7 115.4 4.8 550.9
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-5 February 2010
Table D-4
GRETC’s Net Energy for Load Forecast for Evaluation
2011 - 2060
Utility Net Energy for Load Forecast (GWh)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 1,302.0 1,522.7 554.5 771.2 1,162.8 64.6 5,377.8
2012 1,303.2 1,532.1 557.1 801.9 1,168.3 64.8 5,427.4
2013 1,305.0 1,543.0 560.2 811.1 1,173.8 65.0 5,458.1
2014 1,307.5 1,553.2 564.0 820.9 1,179.3 65.3 5,490.3
2015 1,311.4 1,333.5 568.1 831.9 1,184.9 65.6 5,295.3
2016 1,315.6 1,344.4 572.4 842.8 1,190.4 65.9 5,331.5
2017 1,320.1 1,355.5 577.0 854.0 1,196.0 66.3 5,369.0
2018 1,324.8 1,361.5 581.7 865.4 1,201.6 66.6 5,401.6
2019 1,329.6 1,367.4 586.5 876.8 1,207.3 67.0 5,434.7
2020 1,334.5 1,373.4 591.2 888.3 1,213.0 67.4 5,467.8
2021 1,339.4 1,379.5 596.1 900.1 1,218.7 67.8 5,501.6
2022 1,344.3 1,385.5 601.0 911.7 1,224.4 68.1 5,535.0
2023 1,349.2 1,391.6 605.9 923.2 1,230.1 68.5 5,568.6
2024 1,354.3 1,397.7 610.7 934.8 1,235.9 68.9 5,602.3
2025 1,359.2 1,403.8 615.5 946.4 1,241.7 69.3 5,636.0
2026 1,364.2 1,410.0 620.4 958.0 1,247.6 69.7 5,669.9
2027 1,369.3 1,416.2 625.3 969.7 1,253.4 70.0 5,703.9
2028 1,374.4 1,422.3 630.2 981.3 1,259.3 70.4 5,738.0
2029 1,379.5 1,428.5 635.1 992.9 1,265.3 70.8 5,772.0
2030 1,384.5 1,434.7 640.0 1,004.7 1,271.2 71.2 5,806.3
2031 1,389.6 1,440.8 645.0 1,016.7 1,277.1 71.6 5,840.8
2032 1,394.7 1,447.0 650.0 1,028.7 1,283.0 72.0 5,875.4
2033 1,399.7 1,453.3 655.0 1,040.9 1,289.0 72.4 5,910.2
2034 1,404.8 1,459.5 660.0 1,053.1 1,294.9 72.7 5,945.1
2035 1,409.9 1,465.7 665.1 1,065.4 1,300.9 73.1 5,980.1
2036 1,415.0 1,472.0 670.2 1,077.8 1,306.8 73.5 6,015.3
2037 1,420.1 1,478.2 675.3 1,090.2 1,312.8 73.9 6,050.6
2038 1,425.3 1,484.5 680.4 1,102.8 1,318.8 74.3 6,086.1
2039 1,430.4 1,490.8 685.5 1,115.4 1,324.9 74.7 6,121.7
2040 1,435.5 1,497.1 690.7 1,128.1 1,330.9 75.1 6,157.4
2041 1,440.7 1,503.5 695.9 1,140.9 1,336.9 75.5 6,193.3
2042 1,445.8 1,509.8 701.1 1,153.7 1,343.0 75.9 6,229.3
2043 1,451.0 1,516.2 706.3 1,166.7 1,349.1 76.3 6,265.5
2044 1,456.2 1,522.5 711.5 1,179.7 1,355.2 76.7 6,301.9
2045 1,461.4 1,528.9 716.8 1,192.9 1,361.3 77.1 6,338.4
2046 1,466.6 1,535.3 722.1 1,206.1 1,367.4 77.5 6,375.0
2047 1,471.8 1,541.7 727.4 1,219.4 1,373.5 77.9 6,411.8
2048 1,477.0 1,548.2 732.8 1,232.8 1,379.7 78.3 6,448.8
2049 1,482.3 1,554.6 738.1 1,246.3 1,385.9 78.7 6,485.9
2050 1,487.5 1,561.1 743.5 1,259.9 1,392.1 79.1 6,523.2
2051 1,492.8 1,567.5 748.9 1,273.6 1,398.3 79.5 6,560.6
2052 1,498.0 1,574.0 754.4 1,287.4 1,404.5 79.9 6,598.2
2053 1,503.3 1,580.5 759.8 1,301.3 1,410.7 80.3 6,635.9
2054 1,508.6 1,587.1 765.3 1,315.3 1,416.9 80.7 6,673.9
2055 1,513.9 1,593.6 770.8 1,329.4 1,423.2 81.1 6,712.0
2056 1,519.2 1,600.1 776.3 1,343.6 1,429.5 81.5 6,750.2
2057 1,524.5 1,606.7 781.9 1,357.9 1,435.8 81.9 6,788.7
2058 1,529.8 1,613.3 787.5 1,372.3 1,442.1 82.3 6,827.3
2059 1,535.1 1,619.9 793.1 1,386.8 1,448.4 82.8 6,866.0
2060 1,540.5 1,626.5 798.7 1,401.4 1,454.7 83.2 6,905.0
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-6 February 2010
Table D-5
GRETC’s Winter Peak Large Load Forecast for Evaluation
2011 - 2060
Large Load Winter Peak Demand (MW)
Year GVEA Anchorage MEA Kenai GRETC
2010/2011 238.1 412.2 146.0 96.3 869.3
2011/2012 239.6 413.2 151.0 97.2 877.5
2012/2013 241.3 414.2 153.0 98.2 883.0
2013/2014 242.9 415.1 155.0 98.2 887.4
2014/2015 217.5 417.1 157.0 99.2 867.8
2015/2016 219.2 418.1 159.0 100.2 873.3
2016/2017 221.1 420.1 161.0 100.2 879.0
2017/2018 222.7 422.1 163.0 101.2 885.4
2018/2019 224.3 424.1 165.0 102.2 891.8
2019/2020 226.0 425.1 167.0 102.2 896.3
2020/2021 227.6 427.1 169.0 103.2 902.7
2021/2022 229.2 429.0 171.0 104.2 909.1
2022/2023 230.9 431.0 173.0 104.2 914.6
2023/2024 232.6 433.0 176.0 105.2 922.1
2024/2025 384.3 734.0 178.0 156.2 1398.3
2025/2026 386.0 736.0 180.0 157.2 1404.7
2026/2027 387.7 738.0 182.0 157.2 1410.2
2027/2028 389.4 740.0 184.0 158.2 1416.6
2028/2029 391.1 742.0 186.0 159.2 1423.1
2029/2030 392.8 744.0 188.0 160.1 1429.5
2030/2031 394.5 745.9 190.2 160.9 1435.8
2031/2032 396.2 747.8 192.4 161.7 1442.2
2032/2033 398.0 749.7 194.6 162.5 1448.6
2033/2034 399.7 751.6 196.8 163.3 1455.0
2034/2035 401.5 753.5 199.0 164.1 1461.4
2035/2036 403.2 755.4 201.3 165.0 1468.0
2036/2037 405.0 757.4 203.5 165.8 1474.5
2037/2038 406.7 759.3 205.8 166.7 1481.1
2038/2039 408.5 761.2 208.1 167.6 1487.7
2039/2040 560.3 1063.2 210.4 218.5 1975.7
2040/2041 562.0 1065.1 212.7 219.3 1982.3
2041/2042 563.8 1067.1 215.0 220.2 1989.0
2042/2043 565.6 1069.0 217.4 221.1 1995.7
2043/2044 567.4 1071.0 219.7 222.0 2002.5
2044/2045 569.2 1072.9 222.1 222.9 2009.3
2045/2046 571.1 1074.9 224.5 223.8 2016.1
2046/2047 572.9 1076.9 226.9 224.7 2022.9
2047/2048 574.7 1078.9 229.3 225.6 2029.8
2048/2049 576.5 1080.8 231.8 226.5 2036.7
2049/2050 578.4 1082.8 234.2 227.4 2043.6
2050/2051 580.2 1084.8 236.7 228.4 2050.6
2051/2052 582.1 1086.8 239.2 229.3 2057.6
2052/2053 584.0 1088.8 241.7 230.2 2064.6
2053/2054 585.8 1090.8 244.2 231.1 2071.7
2054/2055 587.7 1092.8 246.8 232.1 2078.8
2055/2056 589.6 1094.8 249.3 233.0 2085.9
2056/2057 591.5 1096.8 251.9 234.0 2093.0
2057/2058 593.4 1098.9 254.5 234.9 2100.2
2058/2059 595.3 1100.9 257.1 235.8 2107.5
2059/2060 597.3 1102.9 259.7 236.8 2114.7
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-7 February 2010
Table D-6
GRETC’s Large Load Net Energy for Load Forecast for Evaluation (GWh)
2011 - 2060
Large Load Net Energy for Load Forecast (GWh)
Year GVEA Anchorage MEA Kenai GRETC
2011 1,522.7 2,464.8 771.2 619.1 5,377.8
2012 1,532.1 2,471.5 801.9 621.9 5,427.4
2013 1,543.0 2,478.8 811.1 625.2 5,458.1
2014 1,553.2 2,486.9 820.9 629.3 5,490.3
2015 1,333.5 2,496.2 831.9 633.7 5,295.3
2016 1,344.4 2,506.0 842.8 638.3 5,331.5
2017 1,355.5 2,516.2 854.0 643.3 5,369.0
2018 1,361.5 2,526.4 865.4 648.3 5,401.6
2019 1,367.4 2,536.9 876.8 653.5 5,434.7
2020 1,373.4 2,547.4 888.3 658.6 5,467.8
2021 1,379.5 2,558.1 900.1 663.9 5,501.6
2022 1,385.5 2,568.7 911.7 669.1 5,535.0
2023 1,391.6 2,579.4 923.2 674.4 5,568.6
2024 1,397.7 2,590.2 934.8 679.6 5,602.3
2025 2,389.3 4,572.0 946.4 1,013.3 8,921.0
2026 2,395.5 4,582.8 958.0 1,018.6 8,954.9
2027 2,401.7 4,593.7 969.7 1,023.8 8,988.9
2028 2,410.5 4,610.1 981.3 1,030.0 9,032.0
2029 2,414.0 4,615.7 992.9 1,034.4 9,057.0
2030 2,420.2 4,626.7 1,004.7 1,039.7 9,091.3
2031 2,426.3 4,637.7 1,016.7 1,045.1 9,125.8
2032 2,435.2 4,654.1 1,028.7 1,051.3 9,169.4
2033 2,438.8 4,659.7 1,040.9 1,055.8 9,195.2
2034 2,445.0 4,670.7 1,053.1 1,061.3 9,230.1
2035 2,451.2 4,681.8 1,065.4 1,066.7 9,265.1
2036 2,460.2 4,698.3 1,077.8 1,073.1 9,309.3
2037 2,463.7 4,704.0 1,090.2 1,077.7 9,335.6
2038 2,470.0 4,715.1 1,102.8 1,083.2 9,371.1
2039 2,476.3 4,726.2 1,115.4 1,088.7 9,406.7
2040 3,473.5 6,719.2 1,128.1 1,424.6 12,745.4
2041 3,474.5 6,719.6 1,140.9 1,428.3 12,763.3
2042 3,480.8 6,730.9 1,153.7 1,433.9 12,799.3
2043 3,487.2 6,742.1 1,166.7 1,439.6 12,835.5
2044 3,498.9 6,764.2 1,179.7 1,447.0 12,889.9
2045 3,499.9 6,764.7 1,192.9 1,450.9 12,908.4
2046 3,506.3 6,776.0 1,206.1 1,456.6 12,945.0
2047 3,512.7 6,787.4 1,219.4 1,462.3 12,981.8
2048 3,524.6 6,809.5 1,232.8 1,469.8 13,036.8
2049 3,525.6 6,810.1 1,246.3 1,473.8 13,055.9
2050 3,532.1 6,821.6 1,259.9 1,479.6 13,093.2
2051 3,538.5 6,833.0 1,273.6 1,485.4 13,130.6
2052 3,550.4 6,855.3 1,287.4 1,493.0 13,186.2
2053 3,551.5 6,856.0 1,301.3 1,497.1 13,205.9
2054 3,558.1 6,867.5 1,315.3 1,503.0 13,243.9
2055 3,564.6 6,879.1 1,329.4 1,508.9 13,282.0
2056 3,576.5 6,901.5 1,343.6 1,516.6 13,338.2
2057 3,577.7 6,902.3 1,357.9 1,520.8 13,358.7
2058 3,584.3 6,913.9 1,372.3 1,526.8 13,397.3
2059 3,590.9 6,925.6 1,386.8 1,532.8 13,436.0
2060 3,602.9 6,948.0 1,401.4 1,540.7 13,493.0
APPENDIX E DETAILED RESULTS – SCENARIOS 1A / 1B
ALASKA RIRP STUDY
Black & Veatch E-1 February 2010
APPENDIX E
DETAILED RESULTS – SCENARIOS 1A / 1B
Plan 1A_1B P50 SummaryYear Additions RetirementsReserve Margin (%)Renewable Generation (%) Fuel Costs ($000)Total O&M Costs ($000) CO2 Costs ($000) DSM Costs ($000)Annual Capital Fixed Charges ($000)Total Annual Costs ($000)Present Value of Annual Costs ($000)Cumulative Present Value ($000)2011Nikiski Wind; HCCPBeluga - 1; Beluga - 2; International - 1; International - 2 55.82% 11.92% $351,806 $78,494 $1,102 $651 $12,326 $444,378 $444,378 $444,3782012Fire Island International - 3 47.47% 15.18% $359,297 $86,269 $54,767 $1,491 $40,350 $542,175 506,706 951,0842013Anchorage 1x1 6FA 62.51% 14.98% $330,019 $88,259 $57,514 $3,063 $75,558 $554,413 484,245 1,435,3292014Glacier ForkBeluga - 3; Beluga - 6/8; Beluga - 7/8; Bernice - 2; Bernice - 3 71.52% 15.94% $339,919 $90,226 $63,386 $5,878 $108,169 $607,578 495,965 1,931,2942015Anchorage MSW 55.23% 24.72% $348,659 $87,384 $62,082 $10,455 $131,358 $639,938 488,205 2,419,500201659.21% 24.60% $382,711 $89,392 $68,949 $12,759 $170,907 $724,717 516,713 2,936,2132017GVEA MSW Beluga - 5; NP1 60.91% 24.85% $357,899 $89,413 $74,393 $11,891 $199,985 $733,582 488,817 3,425,0302018GVEA 1X1 NPole Retrofit NP2 54.30% 24.83% $276,253 $83,051 $80,365 $12,241 $211,778 $663,688 413,311 3,838,341201947.96% 24.62% $295,815 $82,983 $87,105 $12,657 $211,778 $690,338 401,783 4,240,1242020Mount Spurr Beluga - 6; MLP 5; MLP 5/6; MLP 7/6 46.22% 31.89% $302,861 $102,110 $88,427 $13,124 $273,431 $779,954 424,243 4,664,3672021Anchorage 1x1 6FA Beluga - 7 55.99% 31.60% $310,824 $106,747 $93,910 $13,346 $342,861 $867,688 441,089 5,105,4562022Mount Spurr Healy - 1 51.00% 38.52% $297,025 $126,402 $96,170 $14,024 $391,772 $925,393 439,648 5,545,103202346.86% 38.33% $325,599 $123,469 $97,048 $4,166 $395,365 $945,647 419,879 5,964,982202445.69% 38.18% $340,682 $126,429 $109,073 $3,313 $433,745 $1,013,242 420,460 6,385,4412025Chakachamna:Chakachamna GVEA Aurora Purchase - Tier I 84.55% 62.32% $220,174 $138,656 $75,946 $4,222 $693,340 $1,132,337 439,140 6,824,5812026Nikiski 75.13% 62.52% $234,402 $129,355 $88,159 $5,342 $693,340 $1,150,598 417,030 7,241,611202773.98% 63.00% $227,330 $132,294 $94,512 $8,551 $695,689 $1,158,376 392,382 7,633,993202872.66% 63.06% $230,300 $135,279 $103,224 $13,323 $695,689 $1,177,815 372,866 8,006,859202971.37% 61.83% $242,192 $138,036 $118,165 $16,151 $695,689 $1,210,233 358,064 8,364,9232030Kenai Hydro DPP - 6; MLP 7; MLP 8; Zen1; Zen2 50.97% 63.97% $185,036 $139,321 $110,881 $17,064 $700,698 $1,153,000 318,814 8,683,737203142.40% 62.03% $192,346 $139,762 $120,883 $14,951 $697,301 $1,165,243 301,121 8,984,858203241.36% 62.78% $191,723 $142,989 $129,151 $15,081 $677,251 $1,156,195 279,236 9,264,095203340.32% 61.88% $199,354 $146,152 $141,847 $15,919 $677,251 $1,180,522 266,459 9,530,554203439.30% 61.50% $203,127 $149,310 $154,233 $16,747 $677,251 $1,200,668 253,277 9,783,831203538.29% 61.86% $205,017 $152,770 $165,394 $18,111 $677,251 $1,218,543 240,232 10,024,063203637.29% 61.55% $207,662 $156,125 $183,109 $5,493 $677,251 $1,229,640 226,560 10,250,6232037GVEA LMS100 MLP 3 43.27% 60.64% $217,063 $162,624 $200,100 $7,019 $703,248 $1,290,053 222,141 10,472,764203842.23% 60.94% $218,402 $166,071 $217,232 $6,453 $703,248 $1,311,404 211,045 10,683,809203941.22% 60.75% $230,127 $170,053 $235,833 $8,848 $703,248 $1,348,108 202,758 10,886,568204040.20% 60.25% $243,640 $173,619 $259,739 $12,284 $703,248 $1,392,529 195,738 11,082,305204139.21% 60.34% $253,301 $177,608 $279,986 $18,825 $694,319 $1,424,038 187,072 11,269,3772042GVEA 1x1 6FA NPCC 48.65% 59.27% $276,556 $169,650 $309,508 $21,552 $758,395 $1,535,661 188,538 11,457,915204347.60% 59.37% $288,608 $173,713 $335,805 $22,199 $723,187 $1,543,512 177,104 11,635,019204446.55% 59.21% $300,081 $231,589 $363,392 $23,458 $690,575 $1,609,095 172,551 11,807,570204545.51% 58.76% $317,604 $181,983 $395,339 $22,134 $667,387 $1,584,446 158,792 11,966,3622046Anchorage LM6000 49.40% 58.33% $337,808 $189,592 $429,301 $22,961 $643,804 $1,623,465 152,059 12,118,421204748.36% 57.93% $353,295 $194,064 $464,681 $24,452 $614,726 $1,651,218 144,540 12,262,961204847.31% 57.73% $370,037 $198,719 $505,529 $25,398 $602,933 $1,702,617 139,289 12,402,250204946.30% 57.57% $386,486 $203,794 $546,949 $6,909 $602,933 $1,747,070 133,575 12,535,825205045.26% 57.17% $405,470 $208,369 $595,985 $8,724 $541,280 $1,759,830 125,749 12,661,574205144.26% 57.05% $420,223 $213,071 $616,838 $11,174 $471,850 $1,733,156 115,741 12,777,315205243.26% 56.77% $438,398 $218,532 $632,661 $9,139 $422,939 $1,721,668 107,452 12,884,767205342.27% 56.11% $463,378 $223,819 $667,701 $14,889 $419,346 $1,789,132 104,358 12,989,124205441.28% 55.98% $481,702 $229,337 $692,040 $22,880 $380,966 $1,806,925 98,500 13,087,625205540.31% 55.65% $503,136 $235,076 $717,142 $27,949 $376,280 $1,859,584 94,739 13,182,364205639.35% 55.43% $521,505 $240,450 $745,668 $30,133 $376,280 $1,914,035 91,134 13,273,4982057GVEA LMS100 Cooper Lake 47.51% 54.83% $585,511 $250,156 $787,838 $33,288 $416,531 $2,073,323 92,260 13,365,758205844.71% 53.85% $615,490 $254,038 $829,889 $33,226 $416,531 $2,149,172 89,379 13,455,136205943.71% 53.88% $647,398 $261,068 $862,589 $31,309 $416,531 $2,218,894 86,241 13,541,378206042.73% 53.09% $677,429 $267,339 $902,580 $32,092 $411,521 $2,290,960 83,217 13,624,595Present Value of Costs 4,547,973 1,750,430 1,921,235 149,474 5,255,484 Grand Total13,624,595Scenario 1A/1B Plan - P50 Natural Gas ForecastBlack & Veatch Confidential2/18/2010Page 1
Plan 1A_1B P50 SummaryYearAnchorage InteriorMatanuska Kenai Total Railbelt201133,720 0 0 4,304 38,024201231,553 0 0 5,310 36,863201331,457 0 0 3,877 35,334201430,904 0 0 3,241 34,145201522,249 0 0 2,555 24,803201621,201 0 0 2,757 23,957201721,919 0 0 2,645 24,563201818,693 9,034 0 2,741 30,468201918,656 8,262 0 2,780 29,697202014,852 8,087 0 2,803 25,742202115,866 7,311 0 2,215 25,391202214,094 6,846 0 2,041 22,980202314,741 7,727 0 2,070 24,538202415,267 7,366 0 2,197 24,830202510,081 4,435 0 1,328 15,844202610,393 5,170 0 956 16,519202710,646 5,243 0 0 15,889202810,638 5,289 0 0 15,927202910,865 5,792 0 0 16,65720305,914 6,410 0 0 12,32420317,382 5,563 0 0 12,94520327,325 5,366 0 0 12,69020337,524 5,595 0 0 13,11820347,679 5,589 0 0 13,26820357,709 5,543 0 0 13,25320368,464 4,990 0 0 13,45420376,734 7,581 0 0 14,31520386,460 7,995 0 0 14,45520396,583 8,118 0 0 14,70120406,626 8,411 0 0 15,03720416,725 8,363 0 0 15,08820426,098 9,918 0 0 16,01520436,074 10,083 0 0 16,15720446,226 10,003 0 0 16,22920456,293 10,376 0 0 16,67020467,987 9,250 0 0 17,23720478,290 9,166 0 0 17,45620488,296 9,419 0 0 17,71520498,431 9,493 0 0 17,92420508,533 9,714 0 0 18,24720518,649 9,696 0 0 18,34520528,864 9,698 0 0 18,56320538,917 10,106 0 0 19,02320549,061 10,114 0 0 19,17520559,078 10,367 0 0 19,44520569,378 10,196 0 0 19,57320577,933 13,595 0 0 21,52820588,355 13,629 0 0 21,98420598,374 14,102 0 0 22,47620608,529 14,320 0 0 22,849Scenario 1A/1B Plan - P50 Natural Gas ForecastAnnual Natural Gas Usage (mmBtu)Black & Veatch Confidential2/18/2010Page 2
Plan 1A_1B P50 SummaryYear Nikiski Wind HCCP Fire Island Anchorage 1x1 6FA Glacier ForkAnchorage MSW GVEA MSWGVEA 1X1 NPole Retrofit Mount Spurr TAnchorage 1x1 6FA Mount SpurrChakachamna:ChakachamnaKenai Hydro GVEA LMS100 GVEA 1x1 6FAAnchorage LM6000GVEA LMS100Generating Unit Capital Cost Cash Flow ($000)201130,468 99,809 175,454 210,604 127,935 0 0 0 0 0 0 0 0 0 0 0 644,2702012132,925 116,563 40,740290,2282013119,477 95,638215,114201486,719 9,00095,719201521,127 18,08339,210201619,157 42,450 33,69995,306201738,492 72,765 26,866138,1232018170,818 76,085 43,273290,1772019154,889 178,613 68,804 79,301481,6072020161,957 161,519 238,340561,8162021146,457 481,537627,9942022652,793652,7932023712,138 247712,3852024141,426 253141,68020252602602026266266202718,56018,560202817,90517,905202918,35318,353203020312032203320342,260 2,2602035206,133 206,133203631,138 31,138203720382039127,792 127,7922040299,994 299,9942041272,020 272,02020422043204427,076 27,0762045123,405 123,4052046204720482049205020512052205320543,703 3,7032055337,773 337,773205651,024 51,0242057205820592060Total6,524,085Scenario 1A/1B Plan - P50 Natural Gas ForecastCash Flow per Generating Unit Addition Black & Veatch Confidential2/18/2010Page 3
Plan 1A_1B P50 SummaryYearTotal Generating Unit Capital Cost Cash Flow ($000)Total Transmission Project Capital Cost Cash Flow ($000)Total Capital Cost Cash Flow ($000)DSM Costs ($000)Fuel Cost ($000)Fixed O&M ($000)Variable O&M ($000)CO2 Costs ($000)Energy Requirements After DSM (GWh)2011644,270 79,848 724,118 651 351,806 43,795 34,699 1,102 5,3722012290,228 3,365 293,593 1,491 359,297 48,337 37,933 54,767 5,4122013215,114 51,272 266,387 3,063 330,019 52,191 36,068 57,514 5,424201495,719 228,409 324,128 5,878 339,919 53,317 36,909 63,386 5,421201539,210 314,097 353,307 10,455 348,659 48,327 39,057 62,082 5,167201695,306 129,804 225,111 12,759 382,711 48,775 40,617 68,949 5,1472017138,123 8,812 146,935 11,891 357,899 49,059 40,354 74,393 5,1292018290,177 97,549 387,726 12,241 276,253 47,413 35,638 80,365 5,1052019481,607 214,570 696,177 12,657 295,815 46,596 36,386 87,105 5,0852020561,816 166,433 728,249 13,124 302,861 64,626 37,485 88,427 5,0682021627,994 73,715 701,709 13,346 310,824 68,386 38,361 93,910 5,0522022652,793 195,732 848,525 14,024 297,025 86,668 39,734 96,170 5,0812023712,385 205,995 918,380 4,166 325,599 82,114 41,355 97,048 5,1112024141,680 23,643 165,323 3,313 340,682 83,658 42,770 109,073 5,1402025260 10,784 11,044 4,222 220,174 106,273 32,383 75,946 5,1742026266 11,289 11,555 5,342 234,402 108,234 21,121 88,159 5,207202718,560 18,560 8,551 227,330 110,277 22,017 94,512 5,241202817,905 17,905 13,323 230,300 112,362 22,917 103,224 5,275202918,353 18,353 16,151 242,192 114,541 23,495 118,165 5,30920300 17,064 185,036 116,065 23,256 110,881 5,34420310 14,951 192,346 117,757 22,005 120,883 5,37820320 15,081 191,723 120,236 22,754 129,151 5,41320330 15,919 199,354 122,661 23,490 141,847 5,44720342,260 2,260 16,747 203,127 125,061 24,250 154,233 5,4822035206,133 206,133 18,111 205,017 127,634 25,135 165,394 5,517203631,138 31,138 5,493 207,662 130,359 25,766 183,109 5,55320370 7,019 217,063 136,144 26,480 200,100 5,58820380 6,453 218,402 138,807 27,264 217,232 5,6232039127,792 127,792 8,848 230,127 141,651 28,402 235,833 5,6592040299,994 299,994 12,284 243,640 144,475 29,143 259,739 5,6952041272,020 272,020 18,825 253,301 147,408 30,200 279,986 5,73120420 21,552 276,556 140,448 29,202 309,508 5,76720430 22,199 288,608 143,513 30,200 335,805 5,803204427,076 27,076 23,458 300,081 200,404 31,185 363,392 5,8392045123,405 123,405 22,134 317,604 149,991 31,991 395,339 5,87620460 22,961 337,808 156,421 33,170 429,301 5,91220470 24,452 353,295 159,869 34,195 464,681 5,94920480 25,398 370,037 163,510 35,210 505,529 5,98620490 6,909 386,486 167,227 36,567 546,949 6,02320500 8,724 405,470 170,958 37,411 595,985 6,06020510 11,174 420,223 174,609 38,462 616,838 6,09820520 9,139 438,398 178,567 39,965 632,661 6,13520530 14,889 463,378 182,614 41,204 667,701 6,17320543,703 3,703 22,880 481,702 186,688 42,648 692,040 6,2112055337,773 337,773 27,949 503,136 191,057 44,020 717,142 6,249205651,024 51,024 30,133 521,505 195,250 45,200 745,668 6,28720570 33,288 585,511 202,909 47,247 787,838 6,32620580 33,226 615,490 205,703 48,334 829,889 6,36420590 31,309 647,398 210,417 50,651 862,589 6,40320600 32,092 677,429 215,317 52,022 902,580 6,442Total 6,524,085 1,815,317 Total of Cash Flows &9,086,710Scenario 1A/1B Plan - P50 Natural Gas ForecastSummary of Cash Flows and Production CostsBlack & Veatch Confidential2/18/2010Page 6
Plan 1A_1B P50 SummaryYearCapacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)20111,104 3,542 80 435 251 580 25 210 176 591 15 4920121,258 3,425 80 493 251 501 25 215 176 593 69 23120131,195 3,490 80 556 251 384 25 213 176 591 69 22620141,176 3,354 80 630 251 380 25 213 251 649 69 22720151,176 2,432 80 618 251 619 25 212 251 919 22 163 69 2272016822 2,316 80 625 251 703 25 213 251 921 22 163 69 2282017822 2,388 80 611 251 602 25 212 251 919 26 188 69 2272018821 2,441 80 554 189 591 25 212 251 919 26 195 69 2272019821 2,443 80 563 189 563 25 212 251 919 26 193 69 22620201,103 2,567 80 587 25 211 251 921 50 403 26 192 69 2282021907 2,595 80 550 25 208 251 919 50 402 26 190 69 2272022825 2,250 80 543 25 204 251 919 100 800 26 186 69 2272023743 2,450 80 364 25 205 251 919 100 802 26 187 69 2272024743 2,452 53 374 25 206 251 921 100 803 26 188 69 2272025743 1,285 53 278 25 174 581 2,528 100 651 26 107 69 2262026743 1,448 53 292581 2,519 100 680 26 119 69 2272027701 1,441 53 285581 2,518 100 708 26 140 69 2272028701 1,456 53 282581 2,525 100 734 26 132 69 2272029701 1,537 53 282581 2,517 100 688 26 136 69 2272030701 1,387 53 323586 2,537 100 797 26 154 69 2262031531 1,507 53 325586 2,538 100 719 26 139 69 2262032467 1,476 53 327586 2,544 100 765 26 152 69 2282033467 1,540 53 327586 2,537 100 746 26 147 69 2272034467 1,572 53 330586 2,538 100 739 26 153 69 2272035467 1,568 53 328586 2,538 100 783 26 151 69 2272036562 1,588 53 340586 2,544 100 768 26 163 69 2272037564 1,676 53 317586 2,537 100 752 26 153 69 2272038532 1,676 53 317586 2,537 100 783 26 162 69 2272039532 1,700 53 320586 2,537 100 808 26 147 69 2272040532 1,740 53 323586 2,544 100 771 26 164 69 2312041693 1,749 53 324586 2,537 100 813 26 161 69 2262042693 1,851 53 303586 2,537 100 764 26 165 69 2272043630 1,859 53 305586 2,537 100 787 26 169 69 2272044630 1,880 53 308586 2,544 100 792 26 168 69 2282045630 1,935 53 297586 2,537 100 789 26 171 69 2272046678 1,996 53 279586 2,537 100 780 26 174 69 2272047678 2,039 53 277586 2,537 100 785 26 166 69 2262048678 2,069 53 275586 2,544 100 781 26 170 69 2282049678 2,100 53 272586 2,537 100 812 26 158 69 2272050678 2,149 53 264586 2,537 100 793 26 172 69 2272051678 2,172 53 265586 2,537 100 792 26 187 69 2272052678 2,209 53 264586 2,544 100 813 26 162 69 2272053678 2,259 53 273586 2,537 100 786 26 175 69 2272054678 2,281 53 276586 2,537 100 796 26 176 69 2272055678 2,319 53 278586 2,537 100 796 26 175 69 2272056678 2,344 53 283586 2,544 100 774 26 197 69 2282057775 2,441 53 248586 2,537 100 813 26 146 69 2272058775 2,522 53 251567 2,496 100 783 26 172 69 2262059775 2,577 53 252567 2,496 100 823 26 154 69 2272060775 2,623 53 260567 2,502 100 775 26 160 69 228WindMunicipal Solid WasteNuclear Fuel Oil GeothermalScenario 1A/1B Plan - P50 Natural Gas Forecast: Cumulative Capacity and Energy by Resource TypeOcean TidalPurchase Power HydroNatural Gas CoalBlack & Veatch Confidential2/18/2010Page 7
APPENDIX F DETAILED RESULTS – SCENARIO 2A
ALASKA RIRP STUDY
Black & Veatch F-1 February 2010
APPENDIX F
DETAILED RESULTS – SCENARIO 2A
Plan 2A P50 SummaryYear AdditionsRetirementsReserve Margin (%)Renewable Generation (%)Fuel Costs ($000)Total O&M Costs ($000)CO2 Costs ($000)DSM Costs ($000)Annual Capital Fixed Charges ($000)Total Annual Costs ($000)Present Value of Annual Costs ($000)Cumulative Present Value ($000)2011Nikiski Wind; HCCPBeluga - 1; Beluga - 2; International - 1; International - 2 55.82% 11.92% $351,604 $78,521 $1,106 $651 $12,326 $444,208 $444,208 $444,2082012Fire Island International - 3 47.47% 15.18% $360,422 $86,221 $54,846 $1,491 $40,350 $543,330 507,785 951,993201344.98% 14.98% $363,525 $85,731 $60,377 $3,063 $40,350 $553,045 483,051 1,435,0442014Glacier Fork; Anchorage MSWBeluga - 3; Beluga - 6/8; Beluga - 7/8; Bernice - 2; Bernice - 3 56.46% 18.90% $349,083 $86,281 $66,100 $5,878 $88,695 $596,037 486,543 1,921,5872015Anchorage 1x1 6FA 55.23% 24.72% $354,267 $87,454 $62,615 $10,455 $132,747 $647,538 494,004 2,415,591201659.21% 24.60% $389,510 $89,445 $69,555 $12,759 $172,296 $733,565 523,022 2,938,6122017Kenai Wind Beluga - 5; NP1 60.42% 26.14% $372,476 $92,929 $74,394 $11,891 $216,010 $767,700 511,551 3,450,1632018GVEA 1X1 NPole Retrofit NP2 53.81% 26.11% $275,355 $86,095 $80,031 $12,241 $227,803 $681,525 424,419 3,874,583201947.47% 25.89% $296,482 $86,310 $87,228 $12,657 $227,803 $710,481 413,506 4,288,0892020Mount Spurr Beluga - 6; MLP 5; MLP 5/6; MLP 7/6 45.73% 33.16% $304,731 $105,371 $88,752 $13,124 $289,455 $801,433 435,927 4,724,0162021Anchorage 1x1 6FA Beluga - 7 55.49% 32.84% $312,537 $109,985 $94,579 $13,346 $358,886 $889,333 452,092 5,176,1072022Mount Spurr Healy - 1 50.51% 39.74% $297,344 $129,708 $96,528 $14,024 $407,797 $945,400 449,153 5,625,260202346.37% 39.54% $327,794 $126,766 $97,214 $4,166 $411,390 $967,329 429,506 6,054,766202445.20% 39.58% $343,341 $130,139 $109,253 $3,313 $449,770 $1,035,816 429,827 6,484,5932025Anchorage 2x1 6FA; Anchorage LM6000; Chakachamna:Chakachamna GVEA Aurora Purchase - Tier I 41.74% 42.64% $493,814 $190,671 $158,554 $4,222 $793,649 $1,640,909 636,373 7,120,9652026Nikiski 36.05% 42.27% $529,070 $179,677 $183,279 $5,342 $793,649 $1,691,017 612,902 7,733,868202735.49% 42.50% $520,677 $182,769 $197,038 $8,551 $795,997 $1,705,032 577,553 8,311,421202834.84% 42.34% $533,295 $187,338 $219,018 $13,323 $795,997 $1,748,972 553,680 8,865,101202934.21% 41.95% $539,569 $190,662 $241,299 $16,151 $795,997 $1,783,679 527,726 9,392,8272030GVEA 2x1 6FA; GVEA Wind DPP - 6; MLP 7; MLP 8; Zen1; Zen2 45.01% 43.53% $509,936 $198,465 $245,385 $17,064 $918,989 $1,889,839 522,556 9,915,383203139.60% 43.40% $523,101 $201,504 $270,945 $14,951 $915,592 $1,926,094 497,739 10,413,123203238.95% 43.61% $531,763 $205,894 $291,795 $15,081 $895,542 $1,940,075 468,554 10,881,676203338.30% 43.19% $541,607 $210,376 $316,985 $15,919 $895,542 $1,980,429 447,009 11,328,685203437.66% 42.72% $551,169 $214,842 $343,023 $16,747 $895,542 $2,021,323 426,392 11,755,077203537.01% 43.03% $555,584 $219,480 $368,689 $18,111 $895,542 $2,057,407 405,611 12,160,688203636.38% 42.85% $560,666 $224,269 $402,574 $5,493 $895,542 $2,088,545 384,813 12,545,5002037GVEA LMS100 MLP 3 40.23% 42.52% $548,121 $231,752 $422,523 $7,019 $904,831 $2,114,246 364,064 12,909,564203839.58% 42.47% $547,828 $236,660 $454,017 $6,453 $904,831 $2,149,789 345,966 13,255,530203938.94% 42.26% $570,844 $241,766 $490,794 $8,848 $904,831 $2,217,083 333,454 13,588,9842040Anchorage 2x1 6FA; GVEA 1x1 6FA; GVEA 2x1 6FA 43.74% 31.31% $955,710 $278,383 $819,820 $12,284 $1,190,010 $3,256,208 457,702 14,046,686204143.25% 31.09% $986,042 $283,245 $876,847 $18,825 $1,181,081 $3,346,041 439,560 14,486,2462042GVEA Wind NPCC 39.49% 32.33% $995,004 $281,841 $929,314 $21,552 $1,222,216 $3,449,927 423,558 14,909,804204339.01% 32.23% $1,034,873 $288,300 $1,005,832 $22,199 $1,222,216 $3,573,421 410,018 15,319,822204438.53% 32.09% $1,075,355 $401,879 $1,082,555 $23,458 $1,173,871 $3,757,118 402,893 15,722,716204538.05% 31.69% $1,109,371 $300,374 $1,161,219 $22,134 $1,129,819 $3,722,917 373,108 16,095,8242046GVEA Wind 37.57% 33.53% $1,151,293 $316,843 $1,258,017 $22,961 $1,144,476 $3,893,591 364,685 16,460,509204737.09% 33.00% $1,190,168 $323,306 $1,347,332 $24,452 $1,117,471 $4,002,728 350,381 16,810,890204836.62% 33.07% $1,239,185 $331,193 $1,461,949 $25,398 $1,105,678 $4,163,403 340,603 17,151,493204936.15% 33.23% $1,269,655 $338,080 $1,559,594 $6,909 $1,105,678 $4,279,915 327,229 17,478,722205035.67% 32.85% $1,313,929 $345,174 $1,673,485 $8,724 $996,132 $4,337,444 309,932 17,788,654205135.20% 32.51% $1,360,215 $352,585 $1,720,933 $11,174 $926,701 $4,371,608 291,938 18,080,591205234.73% 32.77% $1,411,933 $361,346 $1,775,167 $9,139 $877,791 $4,435,375 276,819 18,357,410205334.26% 32.61% $1,448,204 $368,777 $1,813,619 $14,889 $874,198 $4,519,685 263,627 18,621,037205433.79% 32.49% $1,498,727 $377,675 $1,868,803 $22,880 $835,817 $4,603,903 250,971 18,872,008205533.32% 32.40% $1,544,239 $386,271 $1,919,022 $27,949 $756,353 $4,633,834 236,077 19,108,085205632.86% 32.38% $1,597,860 $395,323 $1,971,742 $30,133 $756,353 $4,751,411 226,231 19,334,3172057HEA LMS100 Cooper Lake 37.07% 32.13% $1,654,506 $407,185 $2,040,275 $33,288 $796,604 $4,931,857 219,461 19,553,777205835.67% 32.04% $1,721,950 $415,039 $2,114,255 $33,226 $796,604 $5,081,073 211,309 19,765,086205935.19% 31.25% $1,775,748 $423,369 $2,170,886 $31,309 $796,604 $5,197,916 202,026 19,967,1132060HEA LM600037.02% 31.66% $1,876,300 $437,564 $2,290,856 $32,092 $734,560 $5,371,371 195,110 20,162,223Present Value of Costs 7,215,425 2,198,167 3,949,357 149,474 6,649,800 Grand Total20,162,223Scenario 2A Plan - P50 Natural Gas ForecastBlack & Veatch Confidential2/18/2010Page 1
Plan 2A P50 SummaryYearAnchorageInteriorMatanuskaKenaiTotal Railbelt201133,725 0 0 4,347 38,073201231,564 0 0 5,343 36,907201331,009 0 0 5,402 36,412201429,719 0 0 4,652 34,370201522,335 0 0 2,653 24,988201621,242 0 0 2,901 24,143201722,336 0 0 1,634 23,970201819,206 9,353 0 1,741 30,299201919,347 8,532 0 1,746 29,625202015,697 8,368 0 1,731 25,797202116,406 7,538 0 1,513 25,457202214,499 7,039 0 1,433 22,971202315,391 7,732 0 1,464 24,586202415,768 7,496 0 1,513 24,777202527,374 7,039 0 1,342 35,755202628,989 7,671 0 907 37,566202729,128 7,695 0 0 36,823202829,273 7,720 0 0 36,992202929,637 7,844 0 0 37,481203021,656 14,225 0 0 35,881203125,908 10,532 0 0 36,439203225,811 10,699 0 0 36,510203326,214 10,719 0 0 36,934203426,659 10,685 0 0 37,344203526,479 10,796 0 0 37,275203626,896 10,928 0 0 37,824203722,325 15,185 0 0 37,510203822,251 15,409 0 0 37,660203922,546 15,324 0 0 37,870204035,623 24,998 0 0 60,621204135,747 24,267 0 0 60,014204235,457 24,128 0 0 59,585204335,422 24,438 0 0 59,860204435,569 24,571 0 0 60,140204535,140 24,891 0 0 60,031204636,415 23,834 0 0 60,249204736,121 24,167 0 0 60,288204836,458 24,321 0 0 60,779204936,055 24,284 0 0 60,339205036,134 24,399 0 0 60,533205136,276 24,487 0 0 60,764205236,850 24,320 0 0 61,170205336,228 24,613 0 0 60,841205436,437 24,627 0 0 61,064205536,257 24,797 0 0 61,053205636,722 24,654 0 0 61,376205735,530 24,335 0 1,797 61,661205835,362 24,558 0 2,422 62,342205934,939 25,059 0 2,440 62,438206033,668 24,847 0 5,605 64,120Scenario 2A Plan - P50 Natural Gas ForecastAnnual Natural Gas Usage (mmBtu)Black & Veatch Confidential2/18/2010Page 2
Plan 2A P50 SummaryYearNikiski WindHCCP Fire IslandGlacier ForkAnchorage MSWAnchorage 1x1 6FAKenai Wind T LinesGVEA 1X1 NPole RetrofitMount Spurr TAnchorage 1x1 6FAMount SpurrAnchorage 2x16FAAnchorage LM6000Chakachamna:ChakachamnaGVEA 2x1 6FAGVEA Wind T LinesGVEA LMS100Anchorage 2x1 6FAGVEA 1x16FAGVEA 2x1 6FAGVEA WindGVEA WindHEA LMS100HEA LM6000Generating Unit Cash Flow ($000)201130,468 99,809 175,454 127,935 39,746 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 473,4132012116,563 93,305 65,608275,4762013119,477 84,604 154,017358,0982014139,655139,655201513,577 18,08331,6602016125,247 42,45033,699201,396201738,492 72,76526,866138,1232018170,818 76,085 43,273290,1772019154,889 178,613 68,804 79,301481,6072020161,957 161,519 238,340561,8162021146,457 481,537627,9942022197,360 652,793850,1532023393,458 16,120 712,1381,121,7162024130,159 73,474 141,426345,059202520262027223,295223,2952028445,161 32,772477,9332029147,263 302,325449,588203020312032203320342,2602,2602035206,133206,133203631,13831,1382037285,836 121,634 285,836 693,3062038569,844 285,539 569,844 1,425,2272039188,510 258,912 188,510 635,931204041,925 41,9252041386,759 386,75920422043204446,278 46,2782045426,910 426,9102046204720482049205020512052205320543,703 3,7032055337,773 337,773205651,024 51,0242057205838,257 38,2572059174,368 174,3682060Total11,548,152Scenario 2A Plan - P50 Natural Gas ForecastCash Flow per Generating Unit Addition Black & Veatch Confidential2/18/2010Page 3
Plan 2A P50 SummaryYearTotal Generating Unit Cash Flow ($000)Total Transmission Project Cash Flow ($000)Total Cash Flow ($000)DSM Costs ($000)Fuel Cost ($000)Fixed O&M ($000)Variable O&M ($000)CO2 Costs ($000)Energy Requirements After DSM (GWh)2011473,413 79,848 553,260 651 351,604 43,795 34,726 1,106 5,3722012275,476 3,365 278,841 1,491 360,422 48,337 37,885 54,846 5,4122013358,098 51,272 409,370 3,063 363,525 48,328 37,403 60,377 5,4242014139,655 228,409 368,063 5,878 349,083 49,454 36,828 66,100 5,421201531,660 314,097 345,757 10,455 354,267 48,327 39,127 62,615 5,1672016201,396 129,804 331,201 12,759 389,510 48,775 40,670 69,555 5,1472017138,123 8,812 146,935 11,891 372,476 49,059 43,870 74,394 5,1292018290,177 97,549 387,726 12,241 275,355 47,413 38,682 80,031 5,1052019481,607 214,570 696,177 12,657 296,482 46,596 39,714 87,228 5,0852020561,816 166,433 728,249 13,124 304,731 64,626 40,745 88,752 5,0682021627,994 73,715 701,709 13,346 312,537 68,386 41,599 94,579 5,0522022850,153 195,732 1,045,885 14,024 297,344 86,668 43,040 96,528 5,08120231,121,716 205,995 1,327,711 4,166 327,794 82,114 44,651 97,214 5,1112024345,059 23,643 368,702 3,313 343,341 83,658 46,481 109,253 5,140202510,784 10,784 4,222 493,814 135,630 55,041 158,554 8,459202611,289 11,289 5,342 529,070 138,121 41,556 183,279 8,4922027223,295 223,295 8,551 520,677 140,707 42,062 197,038 8,5262028477,933 477,933 13,323 533,295 143,349 43,988 219,018 8,5692029449,588 449,588 16,151 539,569 146,097 44,566 241,299 8,59420300 17,064 509,936 152,823 45,642 245,385 8,62920310 14,951 523,101 155,099 46,405 270,945 8,66320320 15,081 531,763 158,176 47,718 291,795 8,70720330 15,919 541,607 161,218 49,158 316,985 8,73220342,260 2,260 16,747 551,169 164,248 50,595 343,023 8,7672035206,133 206,133 18,111 555,584 167,467 52,013 368,689 8,802203631,138 31,138 5,493 560,666 170,851 53,418 402,574 8,8472037693,306 693,306 7,019 548,121 177,317 54,436 422,523 8,87320381,425,227 1,425,227 6,453 547,828 180,675 55,985 454,017 8,9082039635,931 635,931 8,848 570,844 184,232 57,534 490,794 8,944204041,925 41,925 12,284 955,710 202,018 76,366 819,820 12,2832041386,759 386,759 18,825 986,042 205,701 77,544 876,847 12,30120420 21,552 995,004 195,580 86,261 929,314 12,33720430 22,199 1,034,873 199,431 88,869 1,005,832 12,373204446,278 46,278 23,458 1,075,355 310,643 91,236 1,082,555 12,4272045426,910 426,910 22,134 1,109,371 207,543 92,831 1,161,219 12,44620460 22,961 1,151,293 211,768 105,075 1,258,017 12,48220470 24,452 1,190,168 216,084 107,221 1,347,332 12,51920480 25,398 1,239,185 220,612 110,581 1,461,949 12,57420490 6,909 1,269,655 225,244 112,836 1,559,594 12,59320500 8,724 1,313,929 229,911 115,263 1,673,485 12,63020510 11,174 1,360,215 234,521 118,065 1,720,933 12,66820520 9,139 1,411,933 239,458 121,888 1,775,167 12,72320530 14,889 1,448,204 244,515 124,261 1,813,619 12,74320543,703 3,703 22,880 1,498,727 249,622 128,054 1,868,803 12,7812055337,773 337,773 27,949 1,544,239 255,048 131,223 1,919,022 12,819205651,024 51,024 30,133 1,597,860 260,323 135,000 1,971,742 12,87520570 33,288 1,654,506 269,102 138,083 2,040,275 12,896205838,257 38,257 33,226 1,721,950 273,035 142,003 2,114,255 12,9342059174,368 174,368 31,309 1,775,748 278,917 144,451 2,170,886 12,97320600 32,092 1,876,300 288,064 149,500 2,290,856 13,030Total 11,548,152 1,815,317 Total of Cash Fl14,110,777Scenario 2A Plan - P50 Natural Gas ForecastSummary of Cash Flows and Production CostsBlack & Veatch Confidential2/18/2010Page 4
Plan 2A P50 SummaryYearCapacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)20111,104 3,548 80 435 251 576 25 210 176 591 15 4920121,104 3,427 80 493 251 502 25 215 176 593 69 23120131,041 3,376 80 568 251 494 25 214 176 591 69 22620141,176 3,145 80 643 251 426 25 214 251 649 22 163 69 22720151,176 2,439 80 619 251 633 25 212 251 919 22 163 69 2272016822 2,329 80 625 251 720 25 214 251 921 22 163 69 2282017822 2,299 80 616 251 656 25 212 251 919 22 159 99 3262018821 2,381 80 562 189 618 25 213 251 919 22 166 99 3262019821 2,401 80 576 189 578 25 213 251 919 22 163 99 32520201,103 2,558 80 597 25 210 251 921 50 403 22 163 99 3272021907 2,583 80 568 25 209 251 919 50 401 22 161 99 3262022825 2,241 80 559 25 205 251 919 100 798 22 156 99 3262023743 2,450 80 372 25 206 251 919 100 799 22 158 99 32620241,100 2,442 53 382 25 207 251 921 100 812 22 159 99 32620251,101 4,261 53 353 25 212 581 2,517 100 802 22 160 99 32520261,101 4,516 53 360581 2,517 100 790 22 152 99 32620271,059 4,533 53 344581 2,517 100 816 22 161 99 32620281,059 4,562 53 349581 2,524 100 806 22 169 99 32620291,384 4,624 53 340581 2,517 100 803 22 154 99 32620301,384 4,571 53 266581 2,517 100 794 22 157 149 48920311,214 4,577 53 295581 2,517 100 794 22 161 149 48920321,150 4,589 53 291581 2,524 100 812 22 172 149 49120331,150 4,640 53 295581 2,517 100 802 22 161 149 49120341,150 4,704 53 296581 2,517 100 785 22 150 149 49020351,150 4,697 53 294581 2,517 100 818 22 162 149 49020361,245 4,735 53 298581 2,524 100 813 22 162 149 49020371,247 4,812 53 258581 2,517 100 787 22 175 149 49120381,215 4,839 53 255581 2,517 100 813 22 160 149 49120392,011 4,870 53 256581 2,517 100 807 22 160 149 49120402,011 8,001 53 272581 2,524 100 805 22 163 149 49920412,011 7,943 53 278581 2,517 100 800 22 162 149 48920422,011 7,741 53 276581 2,517 100 805 22 163 199 65320431,948 7,764 53 283581 2,517 100 803 22 163 199 65520441,948 7,809 53 276581 2,524 100 804 22 152 199 65620451,948 7,778 53 277581 2,517 100 761 22 158 199 65520461,948 7,698 53 282581 2,517 100 827 22 177 249 82020471,948 7,706 53 276581 2,517 100 802 22 147 249 81720481,948 7,761 53 274581 2,524 100 804 22 163 249 82220491,948 7,724 53 259581 2,517 100 828 22 174 249 82020501,948 7,744 53 247581 2,517 100 802 22 162 249 82020511,948 7,757 53 251581 2,517 100 781 22 151 249 82020521,948 7,822 53 245581 2,524 100 814 22 163 249 82120531,948 7,765 53 250581 2,517 100 804 22 168 249 81720541,948 7,790 53 261581 2,517 100 804 22 162 249 82020551,948 7,789 53 264581 2,517 100 798 22 169 249 82020561,948 7,841 53 260581 2,524 100 812 22 162 249 82120572,046 7,748 53 280581 2,517 100 794 22 162 249 82020582,046 7,802 53 283562 2,476 100 834 22 167 249 81720592,093 7,761 53 290562 2,476 100 758 22 148 249 81720602,093 7,725 53 304562 2,482 100 806 22 163 249 821Scenario 2A Plan - P50 Natural Gas Forecast: Cumulative Capacity and Energy by Resource TypeOcean TidalFuel Oil Purchase Power Hydro Geothermal Municipal Solid Waste WindCoal NuclearNatural GasBlack & Veatch Confidential2/18/2010Page 5
APPENDIX G DETAILED RESULTS – SCENARIO 2B
ALASKA RIRP STUDY
Black & Veatch G-1 February 2010
APPENDIX G
DETAILED RESULTS – SCENARIO 2B
Plan 2B P50 SummaryYear Additions RetirementsReserve Margin (%)Renewable Generation (%)Fuel Costs ($000)Total O&M Costs ($000)CO2 Costs ($000)DSM Costs ($000)Annual Capital FixedCharges ($000)Total Annual Costs ($000)Present Value of Annual Costs ($000)Cumulative Present Value ($000)2011Nikiski Wind; HCCPBeluga - 1; Beluga - 2; International - 1International - 255.82% 11.92% $351,493 $78,517 $0 $651 $12,326 $442,987 $442,987 $442,9872012Fire IslandInternational - 347.47% 15.18% $360,816 $86,324 $54,859 $1,491 $40,350 $543,841 508,262 951,249201344.98% 14.98% $373,571 $86,176 $60,950 $3,063 $40,350 $564,109 492,714 1,443,9632014Glacier Fork; Anchorage MSWBeluga - 3; Beluga - 6/8; Beluga - 7/8;Bernice - 2; Bernice - 356.46% 18.90% $355,455 $86,614 $66,555 $5,878 $88,695 $603,197 492,389 1,936,3522015Anchorage 1x1 6FA55.23% 24.72% $355,881 $87,506 $62,699 $10,455 $132,747 $649,288 495,339 2,431,691201659.21% 24.60% $391,713 $89,457 $69,675 $12,759 $172,296 $735,900 524,686 2,956,3772017Kenai Wind Beluga - 5; NP160.42% 26.14% $357,236 $92,343 $73,636 $11,891 $216,010 $751,117 500,501 3,456,8782018GVEA 1X1 NPole RetrofitNP253.81% 26.11% $275,319 $86,055 $80,008 $12,241 $227,803 $681,426 424,358 3,881,236201947.47% 25.89% $296,301 $86,307 $87,426 $12,657 $227,803 $710,494 413,514 4,294,7502020Mount SpurrBeluga - 6; MLP 5; MLP 5/6; MLP 7/645.73% 33.15% $313,065 $104,598 $88,585 $13,124 $289,455 $808,827 439,949 4,734,6992021Anchorage 1x1 6FABeluga - 755.49% 32.84% $319,829 $107,286 $95,077 $13,346 $358,886 $894,423 454,679 5,189,3782022Mount SpurrHealy - 150.51% 39.73% $303,446 $126,760 $96,696 $14,024 $407,797 $948,722 450,731 5,640,109202346.37% 39.57% $338,009 $123,561 $101,020 $4,166 $411,390 $978,146 434,308 6,074,418202445.20% 39.43% $354,550 $125,350 $111,759 $3,313 $449,770 $1,044,742 433,531 6,507,9492025Chakachamna:Chakachamna; GVEAWind; Low Watana (Non-Expandable) GVEA Aurora Purchase - Tier I59.97% 65.83% $327,284 $177,358 $109,666 $4,222 $1,387,377 $2,005,906 777,925 7,285,8742026Nikiski54.19% 65.70% $355,930 $168,282 $129,694 $5,342 $1,387,377 $2,046,625 741,791 8,027,664202753.56% 65.52% $354,583 $171,861 $141,138 $8,551 $1,389,726 $2,065,860 699,778 8,727,443202852.82% 65.41% $362,315 $175,663 $156,239 $13,323 $1,389,726 $2,097,266 663,941 9,391,383202952.11% 65.12% $370,599 $179,717 $173,790 $16,151 $1,389,726 $2,129,983 630,185 10,021,5682030GVEA Wind DPP - 6; MLP 7; MLP 8; Zen1; Zen238.93% 66.50% $324,824 $188,512 $170,425 $17,064 $1,426,241 $2,127,066 588,151 10,609,720203133.55% 66.21% $287,389 $185,763 $167,924 $14,951 $1,422,844 $2,078,872 537,220 11,146,940203232.93% 66.42% $291,077 $190,378 $181,400 $15,081 $1,402,794 $2,080,731 502,524 11,649,463203332.30% 66.03% $294,120 $194,462 $195,275 $15,919 $1,402,794 $2,102,569 474,578 12,124,041203431.69% 65.66% $300,588 $198,861 $213,080 $16,747 $1,402,794 $2,132,070 449,754 12,573,794203531.08% 65.94% $303,932 $203,534 $228,670 $18,111 $1,402,794 $2,157,041 425,253 12,999,048203630.47% 65.48% $304,372 $207,945 $248,912 $5,493 $1,402,794 $2,169,516 399,732 13,398,7792037Anchorage 2x1 6FA; Kenai Wind MLP 349.65% 64.70% $337,305 $221,770 $284,317 $7,019 $1,512,696 $2,363,107 406,916 13,805,696203848.95% 64.92% $335,376 $226,742 $306,870 $6,453 $1,512,696 $2,388,138 384,324 14,190,020203948.26% 64.44% $355,211 $231,941 $335,719 $8,848 $1,512,696 $2,444,416 367,646 14,557,6652040Anchorage 2x1 6FA; Kenai Wind; GVEA 2x1 6FA42.24% 49.31% $726,114 $261,828 $658,141 $12,284 $1,757,343 $3,415,710 480,122 15,037,787204141.75% 49.68% $749,303 $266,953 $705,228 $18,825 $1,748,414 $3,488,723 458,303 15,496,0902042GVEA Wind NPCC38.00% 50.31% $764,582 $266,145 $750,700 $21,552 $1,789,549 $3,592,529 441,066 15,937,156204337.52% 50.68% $785,633 $272,478 $804,064 $22,199 $1,789,549 $3,673,924 421,550 16,358,706204437.04% 50.66% $815,768 $279,122 $870,100 $23,458 $1,741,204 $3,729,652 399,948 16,758,654204536.57% 50.24% $852,178 $285,535 $937,781 $22,134 $1,663,223 $3,760,851 376,910 17,135,5642046GVEA LM600038.46% 50.01% $890,057 $295,214 $1,020,949 $22,961 $1,639,640 $3,868,823 362,365 17,497,930204737.99% 50.14% $918,798 $302,026 $1,096,440 $24,452 $1,612,635 $3,954,351 346,146 17,844,075204837.51% 49.97% $957,221 $309,807 $1,185,769 $25,398 $1,600,842 $4,079,038 333,701 18,177,777204937.04% 50.05% $989,273 $316,912 $1,280,071 $6,909 $1,600,842 $4,194,007 320,661 18,498,437205036.55% 49.77% $1,024,435 $324,240 $1,376,949 $8,724 $1,502,675 $4,237,023 302,756 18,801,194205136.08% 49.82% $1,061,115 $331,990 $1,416,126 $11,174 $1,433,244 $4,253,649 284,060 19,085,254205235.61% 49.47% $1,106,193 $339,840 $1,464,813 $9,139 $1,384,333 $4,304,318 268,639 19,353,893205335.14% 49.47% $1,134,383 $347,466 $1,496,925 $14,889 $1,380,740 $4,374,402 255,153 19,609,046205434.66% 49.38% $1,177,971 $356,121 $1,545,993 $22,880 $1,342,360 $4,445,327 242,327 19,851,373205534.19% 49.25% $1,223,021 $364,747 $1,593,720 $27,949 $1,329,430 $4,538,867 231,239 20,082,612205633.72% 49.23% $1,262,068 $373,263 $1,640,623 $30,133 $1,329,430 $4,635,516 220,713 20,303,3252057Anchorage LMS100Cooper Lake37.93% 49.04% $1,322,441 $385,797 $1,701,489 $33,288 $1,343,638 $4,786,652 212,999 20,516,324205836.53% 48.61% $1,372,591 $445,852 $1,765,190 $33,226 $1,343,638 $4,960,497 206,295 20,722,619205936.04% 48.57% $1,430,714 $518,902 $1,826,864 $31,309 $1,343,638 $5,151,426 200,219 20,922,838206035.57% 48.39% $1,480,273 $412,965 $1,879,232 $32,092 $1,315,593 $5,120,155 185,985 21,108,823Present Value of Costs 6,024,495 2,107,805 3,188,181 149,474 9,638,868 Grand Total21,108,823Scenario 2B Plan - P50 Natural Gas ForecastBlack & Veatch Confidential2/18/2010Page 1
Plan 2B P50 SummaryYear Anchorage Interior Matanuska Kenai Total Railbelt201133,729 0 0 4,344 38,073201231,544 0 0 5,351 36,895201330,782 0 0 5,745 36,527201429,533 0 0 4,978 34,510201522,300 0 0 2,660 24,960201621,206 0 0 2,931 24,137201721,504 0 0 2,718 24,222201818,121 9,333 0 2,846 30,300201918,265 8,505 0 2,876 29,646202015,363 7,447 0 3,213 26,023202118,274 5,312 0 2,521 26,108202216,131 5,075 0 2,341 23,547202317,306 5,444 0 2,485 25,235202418,090 4,863 0 2,709 25,663202515,198 6,048 0 2,135 23,381202616,286 6,683 0 1,623 24,592202717,378 6,898 0 0 24,276202817,654 6,802 0 0 24,456202917,734 7,075 0 0 24,809203013,735 6,592 0 0 20,327203113,861 5,722 0 0 19,583203214,037 5,482 0 0 19,518203313,932 5,653 0 0 19,585203414,126 5,736 0 0 19,862203514,240 5,650 0 0 19,890203614,623 5,370 0 0 19,993203717,352 5,224 0 0 22,576203817,154 5,353 0 0 22,507203917,527 5,499 0 0 23,026204031,944 14,295 0 0 46,239204131,757 14,198 0 0 45,956204232,415 12,885 0 0 45,300204332,242 12,717 0 0 44,960204432,303 12,810 0 0 45,113204532,857 12,772 0 0 45,629204632,801 13,321 0 0 46,121204732,648 13,422 0 0 46,070204833,107 13,360 0 0 46,467204932,822 13,701 0 0 46,523205032,986 13,694 0 0 46,679205133,318 13,588 0 0 46,906205233,518 13,900 0 0 47,418205333,414 13,736 0 0 47,150205433,741 13,762 0 0 47,503205533,901 13,984 0 0 47,885205634,108 13,890 0 0 47,998205734,725 14,124 0 0 48,849205835,127 14,122 0 0 49,249205935,493 14,393 0 0 49,885206035,785 14,392 0 0 50,177Scenario 2B Plan - P50 Natural Gas ForecastAnnual Natural Gas Usage (mmBtu)Black & Veatch Confidential2/18/2010Page 2
Plan 2B P50 SummaryYear Nikiski Wind HCCP Fire Island Glacier ForkAnchorage MSWAnchorage 1x1 6FAKenai Wind T LinesGVEA 1X1 NPole Retrofit Mount Spurr TAnchorage 1x1 6FA Mount SpurrChakachamna:ChakachamnaGVEA Wind T LinesLow Watana (Non-Expandable) GVEA WindAnchorage 2x1 6FAKenai WindAnchorage 2x1 6FA Kenai WindGVEA 2x1 6FAGVEA WindGVEA LM6000Anchorage LMS100Generating Unit Cash Flow ($000)201130,468 99,809 175,454 127,935 39,746 0 0 0 0 0 0 48,624 0 0 0 0 0 522,0362012116,563 93,305 65,60832,371307,8472013119,477 84,604 154,01730,231388,3292014139,65541,025180,680201513,577 18,08343,10274,7612016125,247 42,450 33,699 503,963705,359201738,492 72,765 26,866 529,476667,5992018170,818 76,085 43,273 711,8781,002,0552019154,889 178,613 68,804 79,301 840,2421,321,8492020161,957 161,519 238,340 882,7791,444,5962021146,457 481,537 721,7811,349,7752022652,793 758,3211,411,1142023712,138 28,966 796,7111,537,8152024141,426 267,211 39,033447,670202520262027202831,17431,1742029287,577287,57720302031203220332034265,427265,4272035529,157 22,233551,3902036175,050 205,103380,1532037285,836 285,836 571,6722038569,844 23,943 569,844 1,163,6312039188,510 220,874 188,510 597,893204041,925 41,9252041386,759 386,75920422043204427,076 27,0762045123,405 123,4052046204720482049205020512052205320543,703 3,7032055337,773 337,773205651,024 51,0242057205820592060Total16,182,068Scenario 2B Plan - P50 Natural Gas ForecastCash Flow per Generating Unit Addition Black & Veatch Confidential2/18/2010Page 3
Plan 2B P50 SummaryYearTotal Generating Unit Cash Flow ($000)Total Transmission Project Cash Flow ($000) Total Cash Flow ($000)DSM Costs ($000)Fuel Cost ($000)Fixed O&M ($000)Variable O&M ($000)CO2 Costs ($000)Energy Requirements After DSM (GWh)2011522,036 79,848 601,884 651 351,493 43,795 34,722 5,3722012307,847 3,365 311,212 1,491 360,816 48,337 37,987 54,859 5,4122013388,329 51,272 439,601 3,063 373,571 48,328 37,848 60,950 5,4242014180,680 228,409 409,088 5,878 355,455 49,454 37,160 66,555 5,421201574,761 314,097 388,859 10,455 355,881 48,327 39,179 62,699 5,1672016705,359 129,804 835,164 12,759 391,713 48,775 40,682 69,675 5,1472017667,599 8,812 676,411 11,891 357,236 49,059 43,284 73,636 5,12920181,002,055 97,549 1,099,604 12,241 275,319 47,413 38,642 80,008 5,10520191,321,849 214,570 1,536,419 12,657 296,301 46,596 39,711 87,426 5,08520201,444,596 166,433 1,611,028 13,124 313,065 64,626 39,972 88,585 5,06820211,349,775 73,715 1,423,490 13,346 319,829 68,386 38,900 95,077 5,05220221,411,114 198,726 1,609,841 14,024 303,446 86,668 40,092 96,696 5,08120231,537,815 234,141 1,771,956 4,166 338,009 82,114 41,446 101,020 5,1112024447,670 52,388 500,059 3,313 354,550 83,658 41,692 111,759 5,140202510,784 10,784 4,222 327,284 127,467 49,890 109,666 8,459202611,289 11,289 5,342 355,930 129,959 38,323 129,694 8,49220270 0 8,551 354,583 132,545 39,316 141,138 8,526202831,174 0 31,174 13,323 362,315 135,187 40,476 156,239 8,5692029287,577 0 287,577 16,151 370,599 137,934 41,783 173,790 8,59420300 0 17,064 324,824 139,466 49,046 170,425 8,62920310 0 14,951 287,389 141,743 44,020 167,924 8,66320320 0 15,081 291,077 144,820 45,559 181,400 8,70720330 0 15,919 294,120 147,862 46,600 195,275 8,7322034265,427 0 265,427 16,747 300,588 150,891 47,970 213,080 8,7672035551,390 0 551,390 18,111 303,932 154,111 49,423 228,670 8,8022036380,153 0 380,153 5,493 304,372 157,495 50,450 248,912 8,8472037571,672 0 571,672 7,019 337,305 165,776 55,994 284,317 8,87320381,163,631 0 1,163,631 6,453 335,376 169,134 57,608 306,870 8,9082039597,893 0 597,893 8,848 355,211 172,691 59,250 335,719 8,944204041,925 0 41,925 12,284 726,114 177,577 84,251 658,141 12,2832041386,759 0 386,759 18,825 749,303 181,035 85,917 705,228 12,30120420 0 21,552 764,582 170,684 95,461 750,700 12,33720430 0 22,199 785,633 174,300 98,178 804,064 12,373204427,076 0 27,076 23,458 815,768 178,239 100,883 870,100 12,4272045123,405 0 123,405 22,134 852,178 181,923 103,612 937,781 12,44620460 0 22,961 890,057 188,926 106,288 1,020,949 12,48220470 0 24,452 918,798 192,983 109,044 1,096,440 12,51920480 0 25,398 957,221 197,244 112,564 1,185,769 12,57420490 0 6,909 989,273 201,602 115,310 1,280,071 12,59320500 0 8,724 1,024,435 205,989 118,251 1,376,949 12,63020510 0 11,174 1,061,115 210,312 121,678 1,416,126 12,66820520 0 9,139 1,106,193 214,955 124,885 1,464,813 12,72320530 0 14,889 1,134,383 219,711 127,755 1,496,925 12,74320543,703 0 3,703 22,880 1,177,971 224,508 131,614 1,545,993 12,7812055337,773 0 337,773 27,949 1,223,021 229,617 135,130 1,593,720 12,819205651,024 0 51,024 30,133 1,262,068 234,567 138,695 1,640,623 12,87520570 0 33,288 1,322,441 243,013 142,783 1,701,489 12,89620580 0 33,226 1,372,591 300,121 145,731 1,765,190 12,93420590 0 31,309 1,430,714 368,398 150,504 1,826,864 12,97320600 0 32,092 1,480,273 257,872 155,093 1,879,232 13,030Total 16,182,068 1,875,203 Total of Cash Flows & DS18,804,578Scenario 2B Plan - P50 Natural Gas ForecastSummary of Cash Flows and Production CostsBlack & Veatch Confidential2/18/2010Page 5
Plan 2B P50 SummaryYearCapacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)20111,104 3,547 80 435 251 576 25 210 176 591 15 4920121,104 3,424 80 494 251 505 25 215 176 593 69 23120131,041 3,360 80 567 251 512 25 214 176 591 69 22620141,176 3,140 80 643 251 434 25 214 251 649 22 163 69 22720151,176 2,434 80 620 251 638 25 212 251 919 22 163 69 2272016822 2,323 80 625 251 726 25 214 251 921 22 163 69 2282017822 2,355 80 615 251 602 25 212 251 919 22 159 99 3262018821 2,383 80 562 189 618 25 213 251 919 22 166 99 3262019821 2,399 80 581 189 576 25 213 251 919 22 163 99 32520201,103 2,594 80 574 25 190 251 921 50 403 22 162 99 3272021907 2,611 80 552 25 178 251 919 50 401 22 161 99 3262022825 2,274 80 542 25 175 251 919 100 797 22 157 99 3262023743 2,456 80 398 25 167 251 919 100 800 22 159 99 3262024743 2,505 53 381 25 155 251 921 100 811 22 151 99 3262025743 2,303 53 322 25 188 1,181 4,435 100 790 22 158 149 4892026743 2,485 53 3521,181 4,450 100 788 22 155 149 4912027701 2,519 53 3481,181 4,448 100 798 22 153 149 4912028701 2,546 53 3491,181 4,466 100 796 22 155 149 4912029701 2,583 53 3441,181 4,451 100 802 22 154 149 4902030701 2,416 53 3551,181 4,453 100 795 22 146 199 6532031531 2,402 53 3541,181 4,478 100 772 22 139 199 6532032467 2,401 53 3601,181 4,484 100 802 22 148 199 6562033467 2,408 53 3591,181 4,480 100 792 22 144 199 6552034467 2,446 53 3671,181 4,476 100 785 22 144 199 6552035467 2,450 53 3611,181 4,488 100 819 22 147 199 6552036777 2,455 53 3701,181 4,487 100 801 22 153 199 6542037777 2,687 53 3401,181 4,497 100 687 22 103 229 7542038745 2,689 53 3441,181 4,479 100 737 22 114 229 75420391,380 2,753 53 3461,181 4,482 100 715 22 110 229 75420401,380 5,850 53 3631,181 4,495 100 768 22 155 259 86720411,380 5,805 53 3631,181 4,496 100 834 22 161 259 85020421,380 5,732 53 3751,181 4,510 100 771 22 144 309 1,01420431,317 5,687 53 3771,181 4,513 100 816 22 158 309 1,01820441,317 5,719 53 3791,181 4,527 100 809 22 174 309 1,01920451,317 5,785 53 3761,181 4,517 100 807 22 144 309 1,01720461,364 5,822 53 3741,181 4,518 100 768 22 170 309 1,01720471,364 5,813 53 3751,181 4,531 100 801 22 164 309 1,01420481,364 5,874 53 3771,181 4,547 100 802 22 146 309 1,01920491,364 5,868 53 3741,181 4,535 100 809 22 172 309 1,01820501,364 5,890 53 3751,181 4,537 100 801 22 160 309 1,01820511,364 5,916 53 3761,181 4,541 100 827 22 157 309 1,01720521,364 5,984 53 3751,181 4,565 100 786 22 154 309 1,01920531,364 5,962 53 3771,181 4,556 100 801 22 161 309 1,01420541,364 6,012 53 3801,181 4,559 100 802 22 161 309 1,01820551,364 6,045 53 3761,181 4,561 100 801 22 161 309 1,01820561,364 6,069 53 3781,181 4,577 100 794 22 176 309 1,01920571,462 6,087 53 3791,181 4,569 100 818 22 146 309 1,01720581,462 6,145 53 3811,162 4,544 100 779 22 176 309 1,01420591,462 6,231 53 3821,162 4,547 100 803 22 161 309 1,01420601,462 6,267 53 3841,162 4,558 100 805 22 147 309 1,019Scenario 2B Plan - P50 Natural Gas Forecast: Cumulative Capacity and Energy by Resource TypeOcean TidalFuel Oil Purchase Power Hydro Geothermal Municipal Solid Waste WindCoal NuclearNatural GasBlack & Veatch Confidential2/18/2010Page 6