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SUSITNA_ HYDROELECTRIC PROJECT
ECONOMIC AND FINANCIAL
UPDATE
DRAFT REPORT
FEBRUARY 27, 1984
ALASKA POWER AUTHORITY
G
0
ECONOMIC AND FINANCIAL UPDATE
TABLE OF CONTENTS
1.0 INTRODUCTION ...... 1-1
1.1 Background and Purpose of Update ......... 1-1
.1.2 Contents of this Update .................. 1-4
1.3 Summary of Observations and Conclusions .. 1-6
2.0 UPDATE OF ELECTRIC DEMAND STUDIES .............
2-1
2.1 Introduction ..............................
271
2.2 Methodology For Electrical Demand
Forecasting ..............................
2-2
2.2.1
Petroleum Revenue Forecasting
System............................
2-3
2.2.2
The Man -in -the -Arctic Program (MAP)
Economic Model .....................
2-4
2.2.3
The Railbelt Electricity Demand
(RED) Model .......................
2-5
2.2.4
The Optimized Generation Planning
(OGP) Model .......................
2-6
2.3 Future
oil Prices ........................
2-7
2.3.1
Sherman H. Clark Associates -
No Supply Distribution (May 1983)..
2-7
2.3.2
Alaska Department of Revenue
(DOR) Forecast (December 1983).....
2-10
2.3.3
Data Resources Incorporated
(DRI) Forecast (Summer 1983).......
2-12
2.3.4
U.S. Department of Energy (DOE)
Forecast (First quarter 1983)......
2-12
2.3.5
Other oil Price Forecasts .........
2-12
- i -
UNIVERSITY OF ALAS
KA ANCHORgOF ---
2.4 Electrical Demand ........................
2-13
2.4.1 Projections Underlying Electric
Demand............................
2-14
2.4.1.1 Petroleum Revenues .......
2-14
2.4.1.2 Population and
Employment ...............
2-14
2.4.1.3 Domestic Use of
Electricity ..............
2-15
2.4.1.4 Commercial, Government,
and Small Business Use
of Electricity ...........
2-16
2.4.2 Total Electric Demand Projections
2-18
2.5 Comparison with Utility Forecasts ........
2-19
2.6 Summary ............ ...................
2-20
3.0 UPDATE OF THE SUSITRA PROJECT .................
3-1
3.1
Introduction .............................
3-1
3.2
Description of the Susitna Project as
Filed at FERC ............................
3-2
3.2.1 Watana Development ................
3-2
3.2.2 Devil Canyon Development ..........
3-4
3.3
Alternative Susitna Development Schemes ..
3-5
3.4
Potential Design Refinements .............
3-6
3.5
Cost Estimates ...........................
3-7
3.5.1 Construction Cost Estimate of
Project as filed at FERC ..........
3-7
3.5.2 Construction Cost Estimates with
Refinements .......................
3-8
3.5.3 Operation and Maintenance Costs ...
3-8
3.6 Reservoir Operation Studies ..............
3-8
3.6.1
Simulation Model ..................
3-9
3.6.2
Hydrology .........................
3-9
3.6.3
Reservoir Data ....................
3-10
3.6.4
Turbine and Generator Data ........
3-10
3.6.5
Reservoir Operation Constraints ...
3-11
3.6.6
Power and Energy Production .......
3-12
3.7 Environmental
Status Update ..............
3-13
3.7.1
Aquatic Programs ..................
3-14
3.7.2
Terrestrial Programs ..............
3-15
3.7.3
Social Sciences Programs ..........
3-18
3.7.3.1 Cultural Resources .......
3-16
3.7.3.2 Socioeconomics ...........
3-17
3.7.3.3 Recreation ................
3-17
4.0' NON-SUSITNA GENERATION ALTERNATIVES ........... 4-1
4.1 Introduction .............................
4-1
4.2 Natural Gas -Fired Options ................
4-2
4.2.1 Natural
Gas Availability and
Cost..............................
4-2
4.2.1.1
Cook Inlet Gas
Availability .............
4-2
4.2.1.2
Cook Inlet Gas
Consumption ..............
4-4
4.2.1.3
Cook Inlet Gas Price .....
4-9
4.2.1.4
North Slope Gas ..........
4-11
4.2.2 Natural
Gas -Fired Powerplants .....
4-15
4.2.2.1
Simple Cycle Combustion
Turbines .................
4-15
4.2.2.2
Combined Cycle Combustion
Turbines .................
4-16
4.3 Coal -Fired Options
........................
4-16
4.3.1 Coal Availability
and Cost in
Alaska
............................
4-17
4.3.2 Coal -Fired
Powerplants .............
4-21
4.4 Chakachamna Hydroelectric
Project
Development ..............................
4-22
4.5 Environmental
Considerations of
Alternatives .............................
4-23
4.5.1 Natural
Gas -Fired Facilities ......
4-24
4.5.1.1
Beluga Region ............
4-25.
4.5.1.2
Kenai Region .............
4-26
4.5.1.3
North Slope ..............
4-28
4.5.1.4
Fairbanks ................
4-30
4.5.2 Coal -Fired
Facilities .............
4-32
4.5.2.1
Beluga ...................
4-33
4.5.2.2
Nenana ...................
4-35
4.5.3 Chakachamna
Hydroelectric
Development
.......................
4-36
4.5.3.1
Water Resources ..........
4-37
4.5.3.2
Aquatic Communities.......
4-38
4.5.3.3
Terrestrial Communities ..
4-40
4.5.3.4
Socioeconomic Factors ....
4-41
4.5.3.-5
Aesthetic Factors ........
4-41
- iv -
5.0 SYSTEM EXPANSION PROGRAMS .....................
5-1
5.1
Introduction
.............................
5-1
5.2
The Existing
Railbelt Systems ............
5-2
5.2.1
Anchorage -Cook Inlet Area .........
5-3.
5.2.2
Fairbanks -Tanana Valley Area ......
5-4
5.2.3
Total Present System ..............
5-5
5.3
Generation Expansion Before 1993..........
5-5
5.4
Formulation of Expansion Plans After 1993.
5-7
5.4.1
Reliability Evaluation ............
5-8
5.4.2
Hydro Scheduling ........ I.........
5-9
5.4.3
Thermal Unit Commitment ...........
5-9
5.4.4
OGP Optimization Procedure ........
5-10
5.5
1993 -
2020 System Expansion ..............
5-11
5.5.1
Transmission System Expansion .....
5-11
5.5.2
Generation Expansion ..............
5-11
5.6
Review
of Expansion Plans .................
5-14
5.6.1
With-Susitna Expansion Plan........
5-14
5.6.2
Non-Susitna Expansion Plan.........
5-15
6.0 ECONOMIC FEASIBILITY .......................... 6-1
6.1 Introduction ............................. 6-1
6.2 Methodology .............................. 6-1
6.3 Results of the Economic Analysis ......... 6-4
6.4 Threshold Values of Susitna Justification. 6-5-
6.4.1 World Oil Price forecast 6-5
- v -
6.4.2
Discount Rate .....................
6-6
6.4.3
Construction Cost Estimate for
Watana Development .....:..........
6-6
6.4.4
Real Interest During Construction..
6-7
6.5 Sensitivity
Analysis .....................
6-7
6.5.1
Cook Inlet Gas Supply ..............
6-8
6.5.2
Real Escalation of Fuel Costs .....
6-8
6.6.3
Utilities' Forecast ...............
6-10
6.6 Conclusions
..............................
6-12
7.0 FINANCIAL OPTIONS .............................. 7-1
7.1
Introduction ..........................
7-1
7.2
General Approach and Procedures ..........
7-3
7.3
Potential Funding Sources ................
7-4
7..3.1 State Equity Contributions ........
7-5
7.3.2 Alaska Permanent Fund .............
7-6
7.3.3 Rate Stabilization Fund ...........
7-8
7.3.4 Tax -Exempt Debt ...................
7-10
7.3.5 REA Guaranteed Loan Program .......
7-19
7.3.6 Other Sources of Funding ..........
7-23
7.4
Impact of WPPSS Default on Susitna
Financing .................................
7-25
7.5
Financing Options Selected for Analysis...
7-28
7.6
Analysis of Financing Options .............
7-30
7.6.1 Comparison of Options ..............
7-30
7.6.2 Sensitivity Analyses ...............
7-33
7.6.2.1 Revenue Bonds .............
7-33
7.6.2.2 Willingness to Pay........
7-35
- vi -
7.7 Conclusions ............................... 7-36
8.0 FUTURE ACTIONS ................................
8-1
8.1
Introduction .............................
8-1
8.2
Power Sales Agreements ...................
8-1
8.3
Final Finance Plan ........................
8-2
8.4
Legislative Authorization ................
8-4
8.5
FERC License and Other Major Perm its .....
8-4
8.5.1 FERC License ...................
8-4
8.5.2 Other.Major Permits ............
8-5
8.6
Design Completion for Initial Contracts ..
8-6
8.7
Exte.rnal Review Board Concurrence ........
8-7
8.8
Acceptable Labor Agreement ...............
8-7
8.9
Acquisition of Project Lands .............
8-8
8.10
Power Authority Decision to Construct ....
8-9
ECONOMIC AND FINANCIAL UPDATE
LIST OF TABLES
Number
Title
Page
2.1
SHCA-NSD World Oil Price Projections.....
2-10
3.1
Cumulative Present Worth of Alternative
Susitna Development Plans ................
3-5
3.2
Summary and Cost Estimate ................
3-7
3.3
Potential Minimum Flows at Gold Creek....
3-12
4.1
Estimated Beluga Field Coal Costs
Without Exports ..........................
4-19
6.1
Results of Economic Analysis ... :.........
6-4
6.2
Sensitivity Analysis Using Zero Percent
Coal Escalation ..........................
6-9
6.3
Sensitivity Analysis of Real Escalation
of Fuel Costs Beyond. 2020................
6-10
6.4
Economic Analysis Using Utilities'
Forecast.................................
6-11
7.1
Comparison of State Equity and
RSF Contributions ........................
7-31
7.2
Disbursement of State Equity and
RSF Contributions.; ......................
7-32
7.3
Sensitivity of Analysis to Exemption
and Dedicated Revenues ...................
7-34
7.4
Sensitivity Analysis Disbursement of
Equity and RSF Contributions .............
7-35
7.5
Sensitivity Analysis of 120 Percent
Willingness to Pay ....................... 7-36
- v i 1 i -
ECONOMIC AND FINANCIAL UPDATE
LIST OF EXHIBITS
Number Title
1.1 Checklist of Key Variables
2.1 Relationship of Planning Models and Input Data
2.2 MAP Model System
2.3 RED Information Flow
2.4 Oil Price Forecasts
2.5 SHCA-NSD and DOR Mean Oil Price Projections
2.6 Alternative Oil Price Projections
2.7 Summary of Input and Output Data from the Computer Models
2.8 State General Fund Expenditure Forecast .
2.9 Railbelt Population Forecast
2.10 Railbelt Households Forecast
2.11 Electric Energy Demand Forecast
2.12 Electric Peak Demand Forecast
2.13 State Petroleum Revenues
2.14 State and Government Expenditures
2.15 Population
2.16 Employment
2.17 Households
2.18 Residential Electric Energy Use Per Household
2.19 Business Electric Energy Use Per Employee
2.20 Projection of Electricity Requirements
249/164
Number Title
2.21 Projected Peak and Energy Demand
2.22 Railbelt Utilities Forecast
2.23 Chugach Electric Association, Inc. Projections of
of Total System Energy Generation
2.24 Summary of Energy and Peak Generation Projections made.
by Power Authority and Utilities
3.1 Susitna Hydroelectric Project - Operation and Maintenance
Cost Estimates
3.2 Area and Volume Versus Elevation - Watana Reservoir
3.3 Area and Volume Versus Elevation - Devil Canyon Reservoir
3.4 Powerplant Data
3.5 Susitna Energy Generation
3.6 Power and Energy Production - Year 2020 Demand Level
4.1 Estimated Cumulative Consumption of Cook Inlet Natural
Gas Reserves
4.2 SHCA-NSD Scenario Fuel Costs
4.3 Thermal Plant Operating Parameters and Costs
4.4 Chakachamna Hydroelectric Project Data
4.5 Summary of Environmental Impacts Caused by Alaska Rail -
belt Electric Power Alternatives
5.1 Location Map Showing Transmission Systems
5.2 Total Generating Capacity within the Railbelt System
5.3 Existing and Planned Railbelt Hydroelectric Generation
5.4 Railbelt Installed Capacity
e
249/164
Number Title
5.5 Optimized Generation Planning (OGP) Program Information
Flows
5.6 Expansion Plan Yearly MW Additions with Susitna
Alternatives
5.7 Expansion Plan Yearly MW Additions - Non Susitna
Alternatives I _
5.8 Summary of Railbelt System Generation Mix in Year 2020,
Economic Cast of Energy, and Cumulative Present Worth
5.9 With-Susitna Alternative - Energy Demand & Deliveries
5.10 Non-Susitna Alternative - Energy Demand & Deliveries
6.1 Principal Economic Parameters
6.2 Results of the Economic Analysis of System Expansion
Plans
7.1 Assumptions Used in Financial Analysis
7.2 Funding Requirements - Base Case
7.3 Financing Option A - Annual Disbursements
7.4 Financing Option B - Annual Disbursements
7.5 Energy Cost Comparison
7.6 Annual State Contributions for Financing
Options A and B
7.7 Annual State Contributions for Option A
Sensitivity Cases
7.8 Annual State Contributions for Option B
Sensitivity Cases
249/164
1.0 INTRODUCTION
1.1 BACKGROUND AND PURPOSE OF UPDATE
The Susitna Hydroelectric Project is one of the largest hydroelectric
projects ever brought before the Federal Energy Regulatory Commission
(FERC,) for issuance of a license. Pursuant to legislative authori-
zation, the Alaska Power Authority (Power Authority) has filed for a
license to construct and operate the Susitna Project in furtherance of
its statutory duty "to promote, develop, and advance the general pros-
perity and economic welfare of the people of Alaska by providing a means
of constructing, acquiring, financing, and operating power projects,"
including hydroelectric projects (ALASKA STAT. § 44.83.070.). The
Project is designed to play a major role in meeting the future elec-
trical demand of the Alaskan Railbelt, where over 70 percent of the
State's population currently resides.
Proceeding with Susitna has not been undertaken lightly or without
careful consideration of its feasibility. Beginning in 1980, a detailed
study of the economic, engineering, environmental, and financial fea-
sibility of the Project was undertaken for the Power Authority by Acres .
American, Inc. (Acres). Acres completed the Feasibility Report in
April, 1982. With regard to the economic feasibility of the Susitna
Project, the Acres' study concluded "that there is a high probability
that development of the hydroelectric potential of the Susitna basin
194/169 1-1
would provide significant cost advantages when compared to alternative
means of meeting projected Railbelt power demands. . ."
To ensure an independent and objective evaluation of alternatives, the
1980 State Legislature determined that an independent consultant should
prepare .a study of Railbelt electrical power alternatives. The Office
of the Governor contracted with Battelle Pacific Northwest Laboratories,
Inc. (Battelle) to analyze and prepare a series of reports an alterna-
tive means of meeting anticipated. Railbelt electric. power demand,
including a forecast of electrical power demand in the Railbelt through
the year 2010. In its December 1982 report, Battelle considered various
Railbelt energy plans and concluded that the plan which included con-
struction of the Susitna Project would provide the lowest cost of power
over an extended time period and be the most resistant to inflation.
In an "Addendum to Executive Summary," issued in December, 1982,
Battelle noted that there had been a decline in world oil prices during
the period January through March, 1982. The report concluded that,
although these lower world oil prices would make the Susitna Project
less attractive economically, it still was the best means of meeting the
Railbelt's long-term power requirements.
The Susitna Hydroelectric Project License Application was prepared based
on data developed in the feasibility and project alternatives studies
and, with Legislative authorization, was filed with the PERC on
February 28, 1983. Noting the sensitivity of the Project's economic
feasibility to world oil prices, the FERC directed the Power Authority
194/169 1-2
to refine the relevant studies in the Application to reflect up-to-date
projections of, among other things, world oil prices. The Joint Venture
of Harza Engineering Company and Ebasco Services, Inc. (Harza-Ebasco),
which had been retained by the Power Authority for the design phase of
the Susitna Project, performed these analyses.
On' July 11, 1983, the Power Authority complied with the FERC directive
and supplied supplemental data and electric power demand forecasts based
on several, revised world oil price forecasts, including a "Reference
Case" developed by Sherman H. Clark Associates (SHCA). As with most
world oil price forecasts evaluated, the electrical demand estimates
derived from the SHCA world oil prices supported the economic feasi-
bility of the Project. The License Application, as supplemented, was
accepted by FERC on July 29, 1983.
Considering the 1983 drop in world oil prices and the sensitivity of
Susitna's feasibility to such prices, the Power Authority Board of
Directors has instructed that an "update" report be prepared on the
economic and financial feasibility of the Project. The report is to
take into account the most current data on the key economic variables
affecting the Project's feasibility, including world oil prices and the
pricing and availability of alternative fuels. It is also to provide
options for financing the Susitna Project. This report is supplied in
response to the Board's request.
194/169 1-3
Beyond the general purpose of providing updated economic and financial
data relating to the Susitna Project, this Update has several specific
functions. They are:
1. To provide a status report on Project engineering, environ-
mental, and planning studies;
2. To provide an assessment of the economic and,financial feasi-
bility of the Project using current data for key variables,
including world oil prices and the cost of alternative sources
of power. A summary of current values for the key variables
and of threshold values for those variables is presented in
the "Checklist of Key Variables" included at the end of this
chapter as Exhibit 1.1;
3. To identify environmental. consequences associated with alter-
native generation modes; and
4. To identify options for financing the Project.
1.2 CONTENTS OF THIS UPDATE
This Update is organized into eight chapters which follow the methodol=
ogy used.to assess the feasibility of the Project. Chapter 2 provides a
description of the electrical demand forecasts. It describes the.
194/169 1-4
computer models and the methodology used in linking the oil price
forecasts to economic analysis, electrical demand forecast, and optimal
system planning. This chapter relies largely upon the work performed in
connection with the July 1983 License Application filing.
Chapter 3 provides a description of the Project as contained in the FERC
License Application. As a status report, Chapter 3 then describes the
various design refinements which are under'consideration. It also dis-
cusses the status of environmental programs relating to the Watana
Development.
Chapter 4 reviews the Non-Susitna generation alternatives. The costs
and performance characteristics of these generation alternatives are
updated to reflect the latest available information. The chapter also
discusses the availability and cost of natural gas and coal for use in
the thermal plant alternatives.
Chapter 5 describes the means by which the demands of the future elec-
trical system can be met, with and without the Susitna Project. The
sizes, types, and number of power plants and the installation schedules
are developed by a computer model. The annual costs of constructing,
operating, and maintaining each supply alternative are presented.
Chapter 6 presents conclusions, based upon the preceding chapters,
regarding the economic feasibility of the Susitna Project. Benefit/cost
ratios are developed for the Susitna Project by comparing the "present
194/169 1-5
worth" of the With-Susitna expansion plan with the Nan-Susitna expansion
plan.
Chapter 7 discusses. potential sources of financing, and. reviews two
potential finance plans with differing levels of State capital Involve-
ment.
Chapter 8 presents further actions which need to be. taken prior to
construction. These include: 1) completion of power sales agreements;
2) resolution of finance issues; 3) obtaining legislative authorization;
4) issuance of the FERC license and other permits; 5) completion of
design; 6) concurrence of final design by the External Review Board;
7) execution of an acceptable labor agreement; 8) acquisition of Project
lands; and 9) final approval by the Board of Directors
1.3 SUMMARY OF OBSERVATIONS AND CONCLUSIONS
From the economic and financial studies presented in this Update, the
following observations and conclusions can be made:
Assuming world oil prices as forecast in the SHCA-NSD case,
the Susitna Project is economically more attractive than
thermal alternative plans. The construction of the Susitna
Project would result in a net benefit of $1.06 billion (in
1983 dollars) over the first 50 years of operation.
194/169 1-6
° The 1983 construction cost estimates for the Watana and Devil
Canyon projects as submitted to the FERC are $3.8 and $1.6
billion, respectively. . Engineering design refinements could
reduce Watana construction costs by approximately eight
percent.
° The electric energy demand forecast for the Railbelt is
sufficient to absorb the output of the Watana.project as early
as 1993.
° Based on either" of two recommended financing options, will
require about $2 billion (1983 dollars) in State equity and
rate stabilization fund contributions in order for the initial
cost of energy from Susitna to be competitive with the cost of
energy from the least -cost thermal alternative.
Major changes in economics and in load projections could
change the expected net benefits of the .Susitna Project.
Events such as substantially lower world oil prices, higher
construction costs and higher interest rates than those
assumed in the Update, could reduce the net benefits. On the
other hand, higher world ail prices, lower interest rates or
lower Susitna construction costs would increase the net
benefits of the Susitna Project.
194/169 1-7
EXHIBIT 1.1
Page l of
CHECKLIST OF KEY VARIABLES
(January 1983 prices)
FERC
Feasibility License
Study Application Update Threshold(a)
Oil Price Forecast - $/bbl (b)
1983
38 (0)
28.95
28.95
28.95
1993
46 (a)
30.49
30.49
25.13
2010
65 (c)
50.39
50.39
33.35
2020
65 (a)
64.48
64.48
37.62
Long Term Oil Price Growth - %/yr
1983-1993
2.0
0.5
0.5
-1.4
1983-2010
2.0
2.0
2.0
0.5
1983-2020
1.5
2.2
2.2
0.7
Projection of Energy Generation - GWh/yr
1983
3,402
3,027
3,088
-
1993
5,126
4,321
4,397
(a)
2010
8,414(d)
6,280
6,444
(a)
2020
---
8,039(d)
B,312(d)
(a)
Long Term Load Growth Rate - %/yr
1983-1993
4.2
3.6-
3.6
(a)
1983-2010
3.4
2.7
2.7
(6)
1983-2020.
--
2.7
2.7
(a)
Cook Inlet Gas Price Forecast - $/MMBtu (b)
1993
3.2
3.02
3.02
2.45(g)
2010
6.2
5.00
6.97(F)
2.97(g)
2020
6.2
_
6.39
6.92(f)
4.85(g)
2050
6.2
9.05
12.62(f)
7.58(g)
Cook Inlet Gas Price Growth - %
Linked with
oil price growth
Cook Inlet Gas Availability
Assumed
Assumed
Price
Forecast
unlimited
unlimited
dependent
(h)
North Slope Gas Price Forecast - $/MMBtu (i)
1993
NA
4.22
4.22
4.00(g)
2010
NA
6.97
6.97
4.18(g)
2020
NA
8.92
8.92
4.85(g)
2050
NA
U.62
12.62
7.58(g)
North Slope Gas Availability Forecast
NA
Assumed
Available
unlimited
in 2007
Q)
CHECKLIST OF KEY VARIABLES
(January 1983 prices)
FERC
Feasibility License
Study Application
Nenana Coal Price Forecast $/MMOtu (b)
1983
1.9
1993
L 4
2010
3.1
2020
---
None- Coal Price Growth - %/yr
1983-1993
2.4
1983-2010
1.8
1983-2020
--
Nenana Coal Availability Forecast
(k)
Beluga Coal Price Forecast $/MMBtu (b)
(1)
1933
1.5
1993
2.0
2010
2.7
2020
---
Beluga Coal Price Growth -- m/yr
1983-1993
2.9
19B3-2010
2.2
1983-2020
--
Beluga Coal Availability Forecast
Unlimited
Real Discount Rate (%)
3.0
Real Interest Rate fA)
3.0
General Inflation Rate (%)
7.0
Susitna Construction Cost - $ x I06
Watana
3,005 (o)
Devil Canyon
1,535 (o)
Capital Cost Escalation Rate - A 1982
to
1985 : 1.1
19B6
to
1992 : 1.0
1993
on
: 2.0
EXHIBIT 1.1
Page 2 of 4
Update Thrashold(s)
1.72
1.72
1.72
2.17
2.17
1.72
7.57
2.57
1.72
2.84
-2.84
1.72
2.3
2.3
0.0
1.3
1.3
0.0
1.2
1.2
0.0
(k)
(k)
(m)
1.86
1.86
1.86
2.17
2.17
1.86
2.57
2.57
1.B6
2.84
2.84
1.86
1.6
1.6
0.0
1.3
1.3
0.0
1.2
1.2
0.0
Unlimited
Unlimited
(m)
3.0
3.5
5.3
3.0
3_5
7.4
7.0
6.5
N/A
3,75n (o)
3,750
+M
1,620 (o)
1,620
(n)
0.0
0.0
(n)
0.0
0.0
(n)
0.0
0.0
(n)
EXHIBIT 1.1
Page 3 of 4
CHECKLIST OF KEY VARIABLES
(January 1983 prices)
FERC
Feasibility
License
Study
Application
Update
Threshold(a)
Project Timing
Watana
1993
1993
1993
NA Devil Canyon
2002
2002
2002
NA
Benefit/Cost Ratio
1.17
1.33
1.19
NA
State Equity Contribution (1983 $ billions)
1:9 (p)(q)
_ 1.9 (p)(q)
1.9/2.1
(r) NA
Wholesale Cost of Energy (cents per kWh)
14.7 (q)
13.6 (q)
11.2 (r)
NA
NA: Not Applicable
(a) The threshold point is that point for each variable at which the Suaitna Project has a benefit/cast
ratio close to 1:00, holding all other variables constant.
In determining the threshold points for prices of oil and natural gas, the values under the June
1983 DDR Mean scenario are used, since the benefit -cost ratio for that scenario is close to 1.00.
(b) 1982 Feasibility Study fuel costs were inflated to January 1983 price level using the U.S. GNP
index of 6.0%.
(c) Based on 2.0% average annual growth rate until 2010, and 0% thereafter
as reported in February 1983 Exhibit D p. D-4-22.
(d) Last year of generation expansion planning studies.
(a) A large decrease of this variable would be required to arrive at the threshold value.
(f) Economically recoverable Cook Inlet reserves are assumed to be depleted in 2007. Analysis assumes
further Cook Inlet reserves will be priced equivalent to North Slope gas.
(g) Approximate. The threshold value would be lower.
(h) No threshold value, because of substitution possibilities.
(i) Forecast also represents prices of gas from some other sources such as Cook Inlet after year 2007
to reflect increased prices due to higher exploration and development costs, and associated risks
EXHIBIT 1.1
Page 4 of 4
CHECKLIST OF KEY VARIABLES
(j) Unavailability of North Slope gas, when Cook Inlet gas is depleted, could
cause major supply problems to the thermal alternatives. No threshold value
is available.
(k) 1982 Feasibility Study up to 200 MW of coal-fired steam plant.` Revised FERC
License and 1983 Update. up to 400 Md of coal-fired. steam plant.
(1) Assume Beluga field developed for export market, but prices sold for local
.needs independent of opportunity price.
(m) Unavailability of Nenana or Beluga coal could cause major supply disruption to the
thermal alternatives.
(n) A large increase would be required to arrive at the threshold value.
(a) January 1982 costs escalated to January 1983 using a 4.3 percent factor.
(p) Inflated from 1982 to 1983 using U.S. GNP index of 6.0%.
(q) Nominal cost of energy in 1993 based on coal expansion plan.
(r) Nominal cost of energy in 1996 based on gas and coal expansion plan.
2.0 UPDATE OF ELECTRIC DEMAND STUDIES
2.1 INTRODUCTION
The first step in assessing the economic and financial feasibility of
the Susitna Project is to forecast future electrical demand in the
Railbelt. This chapter uses the same methodology used in the July 1983
FERC License filing to re-examine predictions of Railbelt electrical
demand. Essentially, the methodology involves using a series of inter-
active models to project electrical demand based on population, employ-
ment, number of households and electricity end use data. These economic
factors are, in turn, based on a series of assumptions and forecasts,
the most important of which is the projected world oil price.
This Update incorporates the most current data regarding key variables
in the modeling process, including world oil prices, the relative cost
of alternative fuels, expected electric power prices and energy conser-
vation data. The conclusion of the analyses is that electric energy
requirements in the Railbelt will increase from 2,808 gigawatts hours
(GWh) in 1983 to 3,737 GWh in 1990, 4,542 GWh in 2000, and 5,858 GWh in
2010.
There are means of predicting electrical demand other than by econo-
metric modeling. For example, most Railbelt utilities forecast elec-
trical demand on their systems by analyzing past trends in conjunction
with anticipated commercial and industrial development and population
195/169 2-1
growth. The Power Authority has also considered the recent forecasts of
the Railbelt utilities in this Update for purposes of comparison.
The following sections describe the Railbelt market, the basic approach
used to develop the demand forecast and the principal variables and
assumptions used in the forecast. The electrical demand forecast
produced by the models is given and the forecasts of the Railbelt utili-
ties are reviewed. The forecast developed by the econometric models is
used to develop the system expansion programs described in Chapter 5.
2.2 METHODOLOGY FOR ELECTRICAL DEMAND FORECASTING
The electrical demand forecast used in this Update is based upon a broad
econometric, end -use approach. As in the July FERC License filing, four
computer models were used in developing the updated power market fore-
cast and the assessment of alternatives. These models are: a petroleum
revenue forecasting model operated by Alaska Department of Revenue
(DOR); the Man -in -the -Arctic Program (MAP) model operated by the Insti-
tute of Social and Economic Research (ISER); the Railbelt Electricity
Demand (RED) model operated by Battelle, and the Optimized Generation
Planning (OGP) model, owned and operated by General Electric Company.
The relationship between the models and their principal input and output
data are shown on Exhibit 2.1. A brief description of the interactive
relationship of the models follows.
195/169 2-2
The petroleum revenue model produces State revenue forecasts based upon
petroleum price forecasts. MAP converts these revenue projections into
projections of State-wide economic conditions, including population,
housing, and employment. The RED model then uses MAP model output,
along with additional data, to produce an electrical energy and peak
demand forecast for the Railbelt. Results of the RED model analysis,
plus generating plant cost data, are then used by OGP to produce least
cost generation expansion plans. OGP is provided different sets of
input to calculate the best plan with and without Susitna. A complete
description of these models is presented in Exhibit 8 of the FERC July
1983 filing. A condensed description is presented below.
2.2.1 Petroleum Revenue Forecasting System
Petroleum royalty payments and taxes constitute approximately 85 percent
of the revenue of the State of Alaska. For this reason, projections of
State oil revenues are generated by a special model system. The system
generates 17-year State revenue forecasts based upon world oil price
projections and other factors.
The principal model in the DOR forecasting system,-PETREV, is an econo-
mic accounting model that examines factors that affect State petroleum
revenues in order to produce a range of possible State royalties and
production taxes. The principal factors influencing the level of
petroleum revenues are North Slope petroleum production rates, the world
market price of petroleum, and tax and royalty rates applicable to the
wellhead value of petroleum.
195/169 2-3
In preparation of the July 1983 FERC License filing, a sub -model of the
PETREV model (MJSENSO) was used to project petroleum revenues based on
alternative world oil prices. Similarly in this Update, the oil reve-
nues which would be available to the State of Alaska, assuming world oil
prices as forecast in the SHCA-NSD case, were derived from the MJSENSO
sub -model.
2.2.2 The Man -in -the -Arctic Program (MAP) Economic Model
The forecast State revenues derived from the 14JSENSO sub -model, along
with other key economic financial and demographic data, are placed into
the MAP model. MAP is a computer -based economic modeling system that
simulates the behavior of the economy and the population of the State of
Alaska in each of 26 regions of the State. The Railbelt consists of six
of these regions. The MAP model projects Railbelt economic activity to
the year 2010, including factors affecting population, employment and
number of households.
The MAP model functions as three separate but linked sub -models: the
scenario generator sub -model, the economic sub -model, and the regional-
ization sub -model, as illustrated on Exhibit 2.2. The scenario gene-
rator sub -model enables the user to define scenarios of development in
activities that are basic to the economy rather than supportive.
Examples of such activities are petroleum production and other mining,
Federal government operations, and tourism. The scenario generator
sub -model also enables the user to enter into the model assumptions
concerning State petroleum revenues, as developed by the MJSENSO model.
195/169 2-4
The economic sub -model produces Statewide projections of economic and
demographic data, based on relationships between such factors as employ-
ment in industries, State revenues and spending, wages and salaries,
gross product, the Alaskan consumer price index, and population. The
regionalization sub -model enables the user to break -down the Statewide
projections to specific regions of the State, including the six that
make up the Railbelt.
2.2.3 The Railbelt Electricity Demand (RED) Model
The projections of population, employment and households generated by
the MAP model are entered into the Railbelt Electricity Demand (RED)
model to project Railbelt electrical demand. RED is a partial end -use,
econometric model that projects both annual electric energy and peak
load demand in Railbelt load centers over the period 1983 through 2010.
The RED model forecasts annual consumption of electricity for the
residential, commercial, small industrial, government, large industrial,
and miscellaneous end -use sectors of the two load centers of the Rail -
belt (Anchorage -Cook Inlet and Fairbanks -Tanana Valley). The model is
made up of seven separate but interrelated modules; the uncertainty,
housing, residential consumption, business consumption, program -induced
conservation, miscellaneous consumption, and peak demand modules.
Exhibit 2.3 shows the basic relationship among the seven modules.
The model may be operated in a probability mode to produce a distri-
bution of projections, each based on a different,.randomly selected set
of input parameters. The model may also be operated in a deterministic
196/169 2-5
mode in which only one forecast is developed based on one set of input
values. The latter mode is used in the Susitna analysis to accommodate
input derived from the other models and to accept certain assumptions.
The RED model produces projections of electricity consumption by load
centers and sectors at five-year intervals. Yearly data are obtained by
linear interpolation between the five-year points.
2.2.4 The Optimized Generation Planning (OGP) Model
The Optimized Generation Planning (OGP) model uses the output from the
RED model, plus data regarding the existing electrical generating system
and planned new power plants, to determine the most cost-effective
electrical generation system over future time periods.
In conjunction with inputting electric demand data into OGP, an impor-
tant step in determining the generating capacity that should be instal-
led in a future year is to provide the model with the required reliabil-
ity of the system expressed •in terms of the loss -of -load probability
(LOLP). LOLP is the maximum acceptable unplanned outage rate on a
system. The OGP model then determines how•much capacity i.s required and
when increments should be installed. Production cost is simulated to
compute the operating costs of the generating system with the.given unit
additions. Finally, the annual investment cost is analyzed considering
service lives of equipment and a real interest rate of 3.5 percent. The -
operating and investment cost analyses enable OGP to project the kind of
generation which should be added to the system.
195/169 2-6
2.3 FUTURE OIL PRICES
An important premise of the economic analyses presented in the FERC
License Application and this Update is that the State's economy and
electrical power demand in the Railbelt are linked to the world price of
oil. _In addition to driving the general economy, oil prices directly
affect the State's ability to finance the Project. Accordingly, the
necessary starting point for the Update analysis is selection of the
world oil price projections.
In analyzing the feasibility of the Susitna Project, the Power Authority
reviewed several world oil price forecasts. The Power Authority has
based its analysis in this Update upon the SHCA-NSD case (the Reference
Case in the July 11, 1983 License Application filing). The December
1983 forecast of DOR, which is very similar to the SHCA-NSD case, is
also analyzed. For purposes of this review, the Summer 1983 Data
Resources Incorporated (DRI) forecast, the U.S. Department of Energy
(DOE) forecast contained in the 1983 National Energy Policy Plan (NEPP),
and oil price forecasts by several other nationally known organizations
are also reviewed. These forecasts are summarized on Exhibit 2.4 and
graphically displayed on Exhibit 2.6.
2.3.1 Sherman H. Clark Associates - No Supply Disruption (May 1983)
SHCA specializes in energy and resources economics. Clients include
major oil companies, independent oil producers, independent refineries
and tanker companies, state, federal and foreign governments, coal
195/169 2-7
companies, and electric utilities. SHCA's experience in evaluating and
projecting world economics and energy developments has resulted in the
development of an extensive and detailed energy data base which is
continuously updated.
SHCA annually prepares a detailed 25 to 30 year forecast of the world
supply and demand for all types of energy and estimated pricing, titled
Evaluation of World Energy Developments and Their Economic Significance.
In June 1983, SHCA also prepared an analysis' for the Power Authority
titled Long Term Outlook for Crude Oil and Fuel Oil Prices, which
extended the oil pricing projections in the annual report from year 2010
to year 2040.
The most recent SHCA forecast of world oil prices to 2010 contains three
pricing cases based on three different political -economic scenarios:
Supply Disruption Case, Zero Economic Growth Case and No Supply Disrup-
tion Case.
SHCA's "Supply Disruption Case" assumes a severe supply disruption in
the world oil market in the late 1980's, followed by production -limiting
decisions by several key producing countries. These factors result in
forecast world oil prices of $40.00 in 1990, $53.76 in 2000 and $87.80
•in 2040. The "Zero. Economic Growth" scenario assumes no severe supply
disruption, combined with zero economic growth in the United States and
0.4 percent growth per year in the free world through 1990. Economic
growth after 1990 rises at a rate no greater than 4 percent per year.
The forecast oil prices under this scenario are $17.00 in 1990 and
195/169 2-8
$45.11 in 2010. Falling between these two scenarios is the "No Supply
Disruption" (NSD) case.
SHCA's NSD case is similar to the Supply Disruption case but it assumes
that there is no supply disruption in the late 1980s. Economic growth
after 1988 is assumed to be at an annual rate of 3 percent in the United
States, slowing gradually to an annual rate of 2.5 percent. Economic
growth in the free world is assumed to be 3.6 percent annually.
For the years 1983-1988, forecast oil prices are the same for both the
NSD and Supply Disruption case scenarios. From 1988 to 2010, prices -
increase under the NSD Case at a 3.0 percent annual rate because of the
relatively high rate of world economic growth. The rate of price
escalation is then assumed to taper off as the oil price approaches the
price that will bring forth supplies of alternative fuels. This market
condition occurs between the years 2035 and 2040.
The SHCA-NSD case was selected as the Reference Case in the July 11,
1983 FERC License filing because its assumptions were consistent with
observable events. The NSD case assumes that OPEC will continue operat-
ing as a viable entity and will successfully support its benchmark
pricing system. It also assumes that economic growth in the United
States and the free world will continue at reasonable rates. In addi-
tion, the NSD case falls in the middle range of forecasts examined by
the Power Authority and, therefore, was determined to be an appropriate-
ly conservative forecast for.the economic feasibility analysis presented
to the FERC. Similar reasoning, and the fact that the NSD scenario now
195/169 2-9
corresponds closely to DOR's world oil' price figures, supports. the
appropriateness of using the SHCA-NSD case in this Update.
Under the SHCA-NSD scenario presented on Exhibit 2.4, the real price of
oil is expected to remain at $26.30 until 1988. From 1988 to 2010,
prices increase 3.0 percent annually. Although price projections for
the period 2010 through 2040 are not utilized directly in the modeling
process, other than to provide escalation rates, they are presented in
Table 2.1. As can be seen, the rate of price escalation is projected to
taper off after 2010.
Table 2.1
SHCA-NSD WORLD OIL PRICE PROJECTIONS
2010-2040
Annual
Year
(1983 $/bbl)
Growth Rate
2010
$ 50.39
2.5%
2020
64.48
1.5%
2030
74.84
1.0%
2040
82.66
2.3.2 Alaska Department of Revenue (DOR) Forecast (December, 1983)
DOR forecasts future petroleum revenues over a 17-year period to assist
in the preparation of State budgets. These forecasts are updated on a
quarterly basis. To develop the revenue forecast, a number of employees
of the State's Office of Management and Budget (OMB), Alaska Department
of Natural Resources (DNR), and the Department of Revenue (DOR) each
develop one to ten scenarios of future world oil prices, and assign a
subjective probability to each scenario. DOR then aggregates these
individuals' forecasts and develops a composite probability distribution
of future world oil prices.
195/169 2-10
DOR's forecasts of oil prices are on a monthly basis for the first two
years and quarterly for the next three years. Beyond the first five
years, DOR forecasts a fixed escalation rate in oil prices for each
probability point. The mean oil price for each period is determined
from the composite frequency distribution.
Among the oil prices analyzed in the July 1983 FERC filing were those
projected in March 1983 by the DOR. DOR's estimates of future revenues
are made on a quarterly basis and are used by the OMB in developing and
managing the State's budget. A review of the oil prices used in DOR's
most recent (December 1983 Quarterly Report) petroleum revenue forecast
indicates that the recent mean DOR forecast and the SHCA-NSD case are
almost identical.
The'17-year projections developed by DOR are presented in Exhibit 2.4.
Under the mean scenario, the crude oil real price is expected to de-
crease until 1986 to $25.43 per barrel; then, the real price would
increase to $36.57/per barrel in year 2000. A graphic comparison of the
SHCA-NSD and DOR mean world oil prices is presented in Exhibit 2.5.
To simplify the process -and to maintain continuity with the analyses in
the FERC License Application, the world oil prices utilized throughout
this Update are those developed by SHCA as the NSD case. This approach
seems reasonable in light of the similarity of the SHCA-NSD and the most
recent DOR forecasts.
195/169 2-11
2.3.3 Data Resources Incorporated (DRI) Forecast (Summer 1983)
The projections of crude oil price developed by DRI for 1983 through
2005, are also presented on Exhibit 2.4- Crude oil prices are expected
to begin escalating rapidly in the Tatter half of the 1980's. DRI
projects averages of real price increase of about 3.0 percent in the
1990's, and 1.6 percent for the period 2000 through 2005. The 2005 real
price is expected to be $49.47 per barrel.
2.3.4 U.S. Department of Energy (DOE) Forecast (First Quarter 1983)
The policy group of the U.S. Department of Energy has developed projec-
tions of crude ail price for inclusion in the 1983 National Energy
Policy Plan. These projections are presented in Exhibit 2.4. Real
prices are expected to decrease until the mid 1980's, and increase
rapidly after 1990. The 2010 real price would vary between $54.60 and
$111.46 per barrel.
2.3.5 Other Oil Price Forecasts
In addition to the oil price forecasts discussed above, the Power
Authority solicited 'forecasts from 17 other sources. These sources
included research organizations, universities and oil companies. Ten of
the 17 sources contacted had no forecast available or did not supply oil
price data. The forecasts obtained from the remaining seven sources are
presented on Exhibit 2.6, along with the SHCA-NSD, DOR and DOE fore-
casts.
195/169 2-12
Inspection of Exhibit 2.6, which portrays the various forecasts graph-
ically, shows that in the early years (1983-1990) of the projections,
the SHCA-NSD forecast is in the low range. ' In the later years
(1995-2010) the SHCA-NSD forecast is in the middle of the range of
forecasts illustrated.
2.4 ELECTRICAL DEMAND
Exhibit 2.7 summarizes the input and output data generated by the
MJSENSO, MAP and RED models using the SHCA-NSD world oil price forecast
for the period 1983 through 2010, the forecast period for the MAP and
RED models.
To establish a starting point for analysis, historical data and projec-
tions of general fund expenditures, population, household, energy
demand, and peak demand are displayed in graphic form in Exhibits 2.8
through 2.12.
In summary, the exhibits show that Railbelt population is expected to
increase from about 320,000 in 1983 to approximately 530,000 by the year
2010. The corresponding number of households would increase from
approximately 110,000 in 1983 to 196,000 in 2010. The electric energy
consumption predicted is approximately 5,900 GWh in 2010. The corres-
ponding average annual growth rate over the period 1983 through 2010 is
2.8 percent. The peak demand is expected to increase from about 580 MW
in 1983 to approximately 1,200 MW in the year 2010.
195/169 2-13
2.4.1 Projections Underlying Electric Demand
Detailed projections of State revenues, economic conditions, and elec-
tric energy demand are presented on Exhibits 2.13 through 2.21.
2.4.1.1 Petroleum Revenues
Exhibit 2.13 presents projections of State petroleum revenues from each
of the primary revenue sources through the year 2010. The first two
columns of this Exhibit contain projected royalties and severance taxes,
respectively. These projections are in nominal dollars, reflecting an
annual change in the consumer price index of 6.5 percent. The projec-
tions of royalties and severance taxes through the year 1999 were
produced by the DOR's PETREV forecasting model system, adjusted for
minor differences in the assumed future rate of inflation. These
projections are similar to the DOR mean projections presented in the DOR
December 1983 report. Exhibit 2.13 also presents projections of State
petroleum revenues derived from corporate income taxes, property taxes,
lease bonuses, and Federal shared royalties: Future revenues from these
sources, estimated by ISER, were used along with the projections of
royalties and severance taxes as input to MAP.
2.4.1.2 Population and Employment
Exhibit 2.15 presents population projections for the State, Railbelt,
Anchorage -Cook Inlet area, and Fairbanks -Tanana Valley area. Railbelt
population is projected to grow by approximately 67 percent between 1983
195/169 2-14
and 2010 from 320,000 to 533,000. Within the Railbelt, the Anchorage
area is projected to grow by 69 percent, compared to projected growth in
the Fairbanks area of 57 percent.
The growth of employment, shown on Exhibit 2.16, is uniformly lower than
that of population. While Statewide non-agricultural wage and salary
employment is projected to grow by 61 percent during the next 27 years,
total State employment is forecast to increase by only,51 percent. The
Railbelt is projected to experience a higher employment increase; rising
by 61 percent, with the Anchorage area growing by 63 percent, compared
to.52 percent growth in the Fairbanks area.
2.4.1.3 Domestic Use of Electricity
Exhibit 2.17 presents projections of households by the following cate-
gories: State total, the Railbelt, the Anchorage area, Fairbanks area,
and Statewide by age of head of household. In contrast to projected
employment, households are projected to increase faster than population.
Statewide, households are projected to increase by 72 percent by the
year 2010, compared to a 75 percent increase in the Railbelt, a 78
percent rise in the Anchorage area, and a 67 percent increase in the
Fairbanks area.
The effects of demand elasticity are shown on Exhibit 2.18 by adjusting
the average consumption per household for conservation and fuel sub-
stitution. .In the Anchorage area, the average consumption per household
is expected to decrease from about 13,700 kWh in 1980 to 12,560 kWh in
195/169 2-15
1990, due mainly to the real increase in the price of electricity which
will continue to cause some conversion from electric space heating to
substitute fuels. After 1990, consumption is expected to slowly in-
crease to about 13,200 kWh in 2010, at an average annual growth rate of
0.25 percent. In the Fairbanks area, the average household consumption
is expected to increase from 11,500 kWh in 1980 to 15,200 kWh in 2010,
an average annual growth ,rate of about 0.9 percent. This increase is
due to the stabilization of electricity prices, combined with increasing
prices'of substitute fuels. -The projected consumption in year 2000 is
similar to the 1975 average consumption.
2.4.1.4 Commercial, Government and Small Business Use of Electricity
The employment forecasts obtained from MAP are used in the RED Business
Consumption module to derive the electric demand in the commercial -
government -small industrial sector. Exhibit 2.19 summarizes the "bus-
iness use per employee" projections. The consumption projections were
obtained from a forecast of floor space per employee and electricity
consumption per square foot, which was then adjusted for price impacts.
Floor space per employee is expected to increase b._y 10 percent in
Anchorage and 15 percent in Fairbanks by the year 2010 to approach the
current national average. As a result, in the Anchorage .area the
average consumption per employee is expected to increase from about
8,400 kWh in 1980 to 11,500 kWh in 2010, an average annual increase of
1.0 percent. In the Fairbanks area consumption per employee is expected
to increase from 7,500 kWh in 1980 to 9,900 kWh in 2010, at an average
annual growth rate of 0.9 percent.
195/169 2-16
A breakdown of electric energy demand projections by customer cate-
gories, based on the underlying projections of average consumption per
household and per employee set forth .in the previous paragraphs,. is
presented on Exhibit 2.20. Exhibit 2.20 also shows miscellaneous sector
usage which includes street lighting, second (recreation) homes, and
vacant houses. That sector's usage corresponds to about one percent of
the total energy demand. The estimates of industrial loads, including
the large industrial customers which are located in the Homer Electric
Association, Inc.. service area, and the estimate of the amount of
electricity that could be provided by utilities to the military instal-
lations, are provided as inputs to the RED model. These loads are
projected to increase from about 108 GWh in 1983 to 315 GWh in 2010 for
the Anchorage -Cook Inlet area, and from 0 to 50 GWh in the Fairbanks -
Tanana Valley area.
As most of the large industrial customers are located in the Homer
Electric Association service area, the projections of growth in large
industrial customers is based on a 1983 power requirements study by
Burns & McDonnell for that utility. Those projections indicate that
electrical demand is expected to increase from 100 GWh in 1982 to
142 GWh in 1990 and 158 GWh in 1995. An annual growth rate of
3.5 percent was assumed after 1995.
Discussions with representatives of the two military installations (Fort
Richardson and Elmendorf Air Force Base) in the Anchorage -Cook Inlet
Region, and the three military installations (Fort Wainwright, Fort
Greely, and Pelson Air Force Base) in the Fairbanks -Tanana Valley
195/169 2-17
Region, provided information on their historical and projected electri-
city consumption. Continuation of the annual military electricity
demand of 150 GWh is expected in each area. Existing power contracts
and exchanges with the utilities were reviewed and estimates of the
amount of electrical capacity and energy that could be provided by the
utilities were discussed. For load forecasting, it was assumed that
one-third of the total. military electrical demand in each of the two
regions, or 50 GWh annually per region, would.be provided by the utili-
ties. The military demand is, therefore, assumed to increase in a linear
fashion from 0 GWh in 1985 to 50 GWh in 1990 in each region, and remain
at 50 GWh thereafter.
2.4.2 Total Electrical Demand Projections
Exhibit 2.21 summarizes the annual peak and energy sales projections for
each load center and for the total system. This single load forecast
was used for all system expansion alternatives described in Chapter 5.
A single load forecast for different expansion plans is appropriate
because the RED model evaluates consumer conservation of electricity
based on price and assumed that the sales price of electricity from the
Susitna plan would not be higher than the price of the thermal alter-
native. In effect, this assumption may understate the load forecast for
the Susitna expansion plan, since electricity prices would not be as
high over the long run for Susitna generated power and conservation
would accordingly be less.
195/169 2-18
2.5 COMPARISON WITH UTILITY FORECASTS
The Railbelt utilities annually produce forecasts of electrical demand
for their own respective markets. Exhibit 2.22 summarizes projections
made for the period 1983 through 2001 by the utilities in early 1983, in
response to a request from the Alaska Power Administration (APAd). As
that Exhibit indicates, the utilities expect the average annual growth
rate to be about 6.0 percent for the period 1983 through 1990, de-
creasing to 4.5 percent for the period 1991 through 2001. The total
energy generation is expected to be 7,662 GWh in the year 2001, which is
about 50 percent greater than the model -derived projections.
A recent power requirements -study done by Burns & McDonnell for Chugach
Electric Association, Inc. (CEA) confirms the growth predicted in the
APAd survey. The results are summarized in Exhibit 2.23. Three fore-
casts of economic activity -- low, moderate, and high -- were developed
for the period 1983 through 1997. Under the Burns & McDonnell moderate
forecast, CEA's energy generation projection for the year 1997 is 3,467
GWh, while the utility itself projected 3,428 GWh. The average annual
growth rate of electric energy demand projections made by Burns &
McDonnell is expected to vary between 3.9 and 6.2 percent for the period
1983 through 1997.
Exhibit 2.24 compares the model -derived electrical demand forecast with
the current forecasts of the Railbelt utilities. The Exhibit shows that
the Power Authority's forecasts are substantially lower. For example,
195/169 2-19
the Railbelt utilities' 1990 energy demand is 4,678 GWh; the Authority's
is 4,111 GWh, approximately 12% less.
2,6 SUMMARY
Exhibit 2.7 provides the basic data upon which the economic and finan-
cial.feasibility of the Susitna Project and alternatives are analyzed.
Utilizing. the world oil price forecast by the SHCA-NSQ case (line 1 of
Exhibit 2.7), the PETREV/MJSENSO model calculates the petroleum revenues
available to the State (lines 5-7). The MAP model utilizes this data as
its primary input and calculates State economic conditions over the
forecast period (lines 8-13). Using these economic data and other
inputs, the RED model predicts electric demand in the Railbelt for the
period 1984-2010. The result of the models' analysis is a forecast of
total Railbelt electric energy sales of 3,737 GWh in 1990 and 5,858 GWh
in 2010.
195/169 2-20
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SCENARIO
GENERATOR
MODEL
ECONOMIC
SCENARIO
STATEWIDE
-ECONOMIC MODEL
-ECONOMIC MODULE
-FISCAL MODULE
-POPULATION MODULE
STATE
ECONOMIC
REGIONALIZATION
MODULE
REGIONAL
ECONOMIC
'ROJECTION
OUTPUT
TO RED
MODEL
oarA
BASE
INPUT VARIABLE S:
INDUSTRIAL CASE
FILES
• PETROLEUM
REVENUE
• FORECASTS
INPUT VARIABLES:
• U.S. INFLATION RATE
• U.S. UNEMPLOYMENT
RATE
• OTHERS
PARAMETERS:
•STATEFISCAL POLIO
PARAMETERS
• ST0CHA5 1 IC
PARAMETERS
• NGNSTCCI--ASTIC
PARALIETERS
iOPIS T.�.�; �.•�^"IC
EXHIBIT 2.2
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
MAP MVUEL SY5 1 tM
FEBRUARY 1984
EXHIBIT 2.3
ECONOMIC
FORECAST
HOUSING
STOCK
RESIDENTIAL
BUSINESS
PROGRAM INDUCED
CONSERVATION
UNCERTAINTY
MODULE
LARGE
IPIDUSTRIAL "'SCELLa"E "S
ANNUAL SALES
PEAK DEMAND
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
RED I( FORM TION FLOWS
FEBRUARY 1984
EXHIBIT 2.4
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CHASE CHASE ECONOMETRICS
DOE DEPT. OF ENERGY
DOR DEPT. OF REVENUE
/
DRI DATA RESEARCH INSTITUTE
/
RAND RAND CORPORATION
/
STAN STANDARD OIL OF CALIFORNIA
/
SRI STANFORD RESEARCH INSTITUTE
W B WORLD HANK
/
DOR MEAN
STAN LOW
RAND
\
____
____
BAR LOW
l�
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0
19831985
1990 1996 2000
YEAR
EXHIBIT 2.6
2005 2010
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
ALTERNATIVE OIL
PRICE PROJECTIONS
FEBRUARY 1984
EXHIBIT 2.7
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2 HISTORICAL
PROJECTION
EXHIBIT 2.8
1995 YEAR 2000 2005 A 2010
1960 1965 1970YEAR 1975 1980 1985
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
STATE ATE ur.1mERAL FUND
EXPENDITURE FORECAST
11 11 f11 1 A M W a^ n A
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EXHIBIT 2.9
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1960
HISTORICAL
10
1965 1970 1975 1980 1985
YEARS
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
RAILBELT POPULATION FORECAST
FEBRUARY 1984
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EXH[BIT 2.13
STATE PETROLEUM REVENUES
(MILLION $)
Total to
Total
General
Including
Fund (Net
Severance
Corporate
Property
Bonuses
of
Year
Royalties
Taxes
Income
Taxes
and
Permanent
Taxes
Federal
Fund
Shared
Contri-
Royalties
bution)
1982
1530.000
1590.000
668.899
142.700
3960.199
3570.549
1983
1456.661
1473.507
233.969
148.600
3361.836
2985.396
1984
1450.305
1474.080
328.647
153.200
3441.298
3069.956
1985
1555.117
1560.529
365.362
158.000
3668.700
3272.498
1986
1724.811
1705.298
398.724
163.456
4020.278
3582.078
1987
1896.215
1857.760
438.776
169.101
4389.691
3908.677
1988
1997.731
1647.607
396.949
174.940
4245.582
3739.060
1989
2251.456
1855.795
520.004
180.981
4837.387
4267.234
1990
2480.380
2031.695
591.983
187,231
5321.348
4693.734
1991
2352.500
1857.126
668.435
193.697
5102.781
4506.898
1992
2530.291
1929.692
794.871
200.385
5487.250
4846.672
1993
2657.006
1986.190
906.959
207.305
5790.461
5117.957
1994
2742.898
2006.949
*998.581
214.464
5996.891
5302.664
1995
2651.116
1868.193
1084.124
221.870
5860.301
5188.770
1996
2599.817
1737.659
1185.670
229.532
5788.676
5129.719
1997
2755.836
1856.672
1326.406
237.458
6213.367
5515.156
1998
2865.556
1887.844
1474.798
245.658
6511.852
5785.961
1999
2950.992
1865.044
1649.613
254.141
6758.785
6011.285
2000
3077.885
1909.805
1841.891
262.917
7132.496
6353.023
2001
3210.235
1955.641
2056.580
271.996
7535.449
6722.641
2002
3348.276
2002.576
2296.294
281.389
7970.531
7122.961
2003
3492.252
2050.638
2563.949
291.106
8440.941
7557.125
2004
3642.420
2099.854
2862.802
301.158
8950.230
8028.625
2005
3799.644
2150.251
3196.489
311.558
9502.340
8541.328
2006
3962.404
2201.857
3569.072
322.317
10101.640
9099.540
2007
4132.781
2254.702
3985.082
333.447
10753.010
9708.060
2008
4310.492
2308.815
4449.578
344.962
11461.840
10372.220
2009
4495.844
2364.227
4968.219
356.874
12234.160
11097.950
2010
4689.164
2420.969
5547.316
369.198
13076.640
11891.850
SOURCE: MAP MODEL OUTPUT
EXHIBIT2,14
STATE AND
GOVERMENT
EXPENDITURES
(MILLIONS
Unre-
stricted
Percent of
General
General
Permanent
State State
Permanent
Fund
Fund
Fund
Personal Subsidy
Fund
Year Expeudi-
Balance
Dividends
Income Tax Programs
. Earnings
tares
I
Reinvested
1982
4601.891
399.200
425.000
0.000
634.000
0.000
1983
3287.977
478.004
152.608
0.000
500..0.00
0..500
1984
3389.729
616.992
196.738
0.000
350.000
0.500
1985
3699.507
700.539
223.721
0.000
350.000
0.500
1986
4031.094
821.113
253.168
0.000
350.000
0.500
1987
4375.941
987.922
286.008
0.000
350.000
0.500
1988
4731.574
699.973
322.441
0.000
695.501
0.500
1989
5118.008
588.465
361.817
0.000
0.000
0.500
1990
5576.836
506.125
406.085
0.000
0.000
0.500
1991
5386.480
506.141
455.185
0.000
0.000
0.500
1992
5786.504
506.152
505.111
0.000
0.060
0.500
1993
6528.020
139.531
0.000
0.000
0.000
0.500
1994
6729.594
139.543
0.000
338.049
0.000
0.500
1995
7729.250
139.563
0.000
680.847
DAN
0.000
1996
7822.879
139.586
0.000
748.723
0.000
0.000
1997
8361.188
139.609
0.000
809.145
0.000
0.000
1998
8794.711
139.633
0.000
873.359
0.000
0.000
1999
9190.000
139.652
0.000
941.928
0.000
0.000
2000
9713.740
139.668
0.000
1017.188
0.000
0.000
2001
10278.270
139.691
0.000
1098.944
0.000
0.000
2002
.10886.180
139.711
0.000
1188.241'
0.000
0.000
2003
11545.180
139.734
0.000
1287.516
0.000
0.000
2004
12261.640
139.766
0.000
1396.169
0.000
0.000
2005
13034.660
139.789
0.000
1513.479
0.000
0.000
2006
13871.350
139.820
0.000
1640.603
0.000
0.ObO
2007
14777.160
139.852
0.000
1778.121
0.000
0.000
2008
15758.890
139.891
0.000
1926.802
0.000
0.000
2009
16822.770
139.934
0.000
2085.652
0.000
0.000
2010
17975.270
139.980
0.000
2257.400
0.000
0.000
SOURCE: MAP MODEL OUTPUT
EXHIBIT2.15
POPULATION
(THOUSANDS)
Greater
Greater
Year
State
Railbelt
Anchorage
Fairbanks
1982
437.175
307.105
239.830
67.277
1983
457.836
319.767
251.057
68.711
1984
473.752
330.202
259.679
70.523
1985
490.146
341.613
269.300
72.313
1986
505.884
352.187
278.082
74.105
1987
517.431
359-.054
283.333
75.723
1988
526.823
364.583
287.969
76.615
1989
538.532
375.007
296.794
78.213
1990
554.634
389.026
308.196
80.831
1991
560.786
393.296
311.585.
81.712
1992
581.846
405.991
322.865
83.127
1993
594.848
413.788
328.521
85.268
1994
602.027
420.130
332.694
87.436
1995
608.810
423.460
335.464
87.997
1996
616.422
428.574
339.629
88.945
1997
623.782
434.617
344.561
90.057
1998
630.352
440.001
348.981
91.021
1999
636.928
445.519
353.531
91.988
2000
644.111
451.561
358.441
93.120
2001
651.362
457.835
363.501
94.335
2002
658.994
464.362
368.801
95.561
2003
667.660
471.437
374.626
96.811
2004
676.878
478.925
380.769
98.156
2005
686.663
486.851
387.267
99.584
2006
697,022
495.287
394.168
101.119
2007
707.990
504.091
401.364
102.727
2008
719.644
513.431
408.995
104.436
2009
731.592
522.970
416.755
L06.216
2010
, 744.418
533.218
425.115
108.104
SOURCE: MAP MODEL OUTPUT
EXHIBIT 2.16
EMPLOYMENT
(THOUSANDS)
State
Non-Ag
State
Railbelt
Greater
Greater
Year
Wage and
Total
Total
Anchorage
Fairbanks
Salary
Total
Total
1982
192.903
231.984
154.033
120.533
33.500
1983
202.237
243.067
159.147
125.221
33.927
1984
205.903
246.984
162.259
127.853
34.406
1985
216.612
258.396
169.197
133.668
35.528
1986
225.515
267.895
174.818
138.324
36.494
1987
230.833
273.581
177.412
140.345
37.067
1988
234.657
277.669
179.422
142.065
37.357
1989
240.213
283.619
184.211
146.124
38.088
1990
249.654
293.689
190.883
151.685
39.198
1991
247.908
291.844
191.360
151.958
39.402
1992
264.012
309.031
199.404
158.995
40.409
1993
266.941
312.180
202.842
161.351
41.492
1994
267.220
312.511
203.630
161.669
41.861
1995
268.534
313.954
204.668
162.466
42.202
1996
270.783
916.404
206.258
163.772
42.486
1997
272.935
318.765
208.212
165.401
42.811
1998
274.346
320.353
210.041
166.916
43.125
1999
276.144
322.374
212.025
168.580
43.445
2000
278.729
325.186
214.541
170.645
43.897
2001
281.498
328.141
217.283
172.875
44.408
2002
284.643
331.499
220.293
175.333
44.960
2003.
288.727
335.859
223.703
178.156
45.546
2004
293.137
340.569
227.487
181.265
46.222
2005
297.941
345.701
231.584
184.625
46.959
2006
303.062
351.172
235.985
188.226
47.759
2007
308.504
356.989
240.639
192.025
48.614
2008
314.317
363.203
245.561
196.044
49.517
2'009
•320.082
369.368
250.621
200.146
50.475
2010
326.440
376.169
255.974
204.512
51.462
SOUP^E: MAP MODEL OUTPUT
EXHIBIT2.17
HOUSEHOLDS
(THOUSANDS)
Greater Greater
Year State Ra.ilbelt Anchorage Fairbanks
1982
145.453
106.572
83.678
22.894
1983
153.141
111.549
88.038
23.511
1984
159.154
115.671
91.425
24.246
1985
165.299
120.140
95.165
24.974
1986
171.192
124.275
98.580
25.695
1987
175.620.
12?.053
100.709
26.344
1988
179.287
129.415
102.669
26.746
1989
183.738
133.365
105.994
27.311
1990
189.696
138.640
110.267
28.373
1991
192.234
140.401
111.662
28.739
1992
199.886
145.348
116.024
29.324
1993
204.788
148.405
118.253
30.152
1994 _
207.695
150.964
119.963
31.002
1995
210.461
152.463
121.197
31.267
1996
213.508
154.590
122.921
31.669
1997
216.470
157.052
124.921
32.131
1998
219.161
159.242
126.710
32.532
1999
221.854
161.483
128.549
32.934
2000
224.751
163.913
130.515
33.398
2001
227.670
166.423
132.532
33.891
2002
230.716
169.023
134.636
34.388
2003
234.112
171.820
136.928
34.892
2004
.237.695
174.758
139.329
35.429
2005
241.468
177.849
141.853
35.996
2006
245.436
181.121
144.520
36.601
2007
249.609
184.516
147.285
37.231
2008
254.014
188.100
150.203
37.896
2009
258.519
191.748
153.162
38.586
2010
263.323
195.652
156.336
39.316
SOURCE: MAP MODEL OUTPUT
EXHIBIT 2.18
RESIDENTIAL ELECTRIC ENERGY USE PER HOUSEHOLD
After
Before Conservation Adjustment and Fuel Substitution Adjustment
Year Small Appliances Large Appliances Space Heat Total. Total
(kWh) (kWh) (kWh) kWh) kWh).
Anchorage —Cook Inlet Area
1980
2110
6500
5089
13699
13699
L985
21.60.
6151
4812
13133
12829
1990
2210
6020
4584
12814
12561
1995
2260
5959
4516
12735
12644
2000
2310
5989
4454
12753
12736
2005
2360
6059
4420
12839
12938
2010
2410
6124
4444
12977
13198
Fairbanks -Tanana
Valley Area
1980
2466
5740
3314
11519
11519
1985
2536
6179
3606
12321
12136
1990
2606
6453
3873
12932
12736
1995
2676
6667
4050
13393
13329
2000
2746
6795
4310
13852
14009
2005
2816
6839
4536
14191
14626
2010.
2886
6888
4656
14430
15180
EXHIBIT 2.19
N h N 00 00 .--i
O\ fl � 01 Ht h
h o0 a0 00 m m
ro
m
S4
6
u
U1 00- io O �l
�r O a0 ul .+ .•� O\ F1
H x 't
co D` O O .--1 N N
,Y
u
ro co co O O
N o. o. rn rn O o O
.4 N N
EXHIBIT 2.20
PROJECTION OF ELECTRICITY REQUIREMENTS
RED Model Computations
Residential Business Miscellaneous Indust/Military* Total
Year Requirements Requirements Requirements Requirements Requirements
(GWh) (GWh) (GWh) '(GWh) (GWh)
Anchorage —Cook Inlet Area
1985
1180
1231
26
124
2561
1990
1345
1479
30
192
3045
1995
1492
1637
34
208
3371
2000
1621
1766
36
238
3662
2005
1794
1999
41
273
4107
2010
2021
2352
47
315
4735
Fairbanks -Tanana
Valley
Area
1985
248
281
7
0
535
1990
310
325
7
50
691
1995
376
366
8
50
800
2000
426
396
9
50
880
2005
482
444
10
50
986
2010
551
511
11
50
1123
* Input to the RED Model
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EXHIBIT 2,23
CHUGACH ELECTRIC ASSOCIATION, INC.
PROJECTIONS OF TOTAL SYSTEM ENERGY GENERATION*
Low
Moderate
High
Year
Energy
Peak
Energy
Peak
Energy
Peak
{GWh)
(MW)
(GWh)
(MW)
'(GWh)
(MW)
1983
1,817
412
1,868
426
1,879
429
19.84-
1,942
432
2,050
463
2,081
469
1985
2,059
451
2,263
501
2,299
510
1986
2,189
470
2,473
533
2,614
575
1987
2,281
491
2,642
568
2,935
654
1988
2,365
513
2,803
606
3,283
745
1989
2,445
535
2,962
646
3,664
850
1980
2,523
559
3,121
689
4,087
974
1991
2,582
575
3,167
699
4.,150
978
1992
2,651
591
3,207
706
4,164
969
1993
2,725
606
3,251
713
4,187
961
1994
2,802
623
3,299
721
4,220
954
1995
2,884
639
3,350
729
4,261
946
1996
2,982
660
3,406
738
4,315
938
1997
3,103
680
3,467
747
4,381
931
* Includes Matanuska Electric Association, Homer Electric Association,
and Seward Electric System.
Source: Power Requirements Study, 1983, by Burns & McDonnell
EXHIBIT 2.24
SUMMARY OF ENERGY AND PEAK GENERATION PROJECTIONS
MADE BY POWER AUTHORITY AND UTILITIES
1990 2000
Power Authority
Annual Energy 41111 4,996
Peak Demand (MW) 855 1,040
Utilities
Annual Energy 41678 7,678
Peak Demand (MW) 940 1,419
2010
6,444
1,339
9,649
1,854
3.0 UPDATE OF THE SUSITNA PROJECT
3.1 INTRODUCTION
Evaluating the economic feasibility of the Susitna Project and its
alternatives requires that an estimate be prepared of the construc-
tion/operating costs and energy production capabilities of the Project.
This Chapter provides an update of (1) the costs and power generation
capacity of the Project as currently designed and set forth in the FERC
License Application, and (2) the impact on the economics of the Project
of certain cost -reducing design refinements.
u
The Power Authority Board of Directors has given conditional approval Lo
proceeding with certain cost -saving design refinements to the Project so
long as implementing those refinements will have no adverse effect on
the FERC licensing schedule. On the assumption that these engineering
refinements may be accommodated within the existing FERC licensing
schedule, the estimated Project costs would be less, as discussed more
fully in this Chapter. It should be clearly understood, however, that
the Power Authority has evaluated the economic and financial feasibility
of the Project in this Update based on the estimated costs as filed with
the FERC. As shown below, implementation of the design refinements
would improve the economics of Susitna.
The results of the assessments in this Chapter are incorporated in the
studies of alternative expansion plans to•meet future Railbelt elec-
196/174 3-1
trical demand (Chapter 5), economic analyses (Chapter 6) and financial
analyses (Chapter 7).
3.2 DESCRIPTION OF THE SUSITNA PROJECT AS FILED AT FERC
The Susitna Hydroelectric Project as proposed in the License Application
will consist of two major developments on the Susitna River approxi-
mately 180 miles north-east of Anchorage. The Project will consist of
two dams, Watana and Devil Canyon, with a combined maximum generating
capacity of 1,620 MW. Watana, which will be built first, provides a
major storage reservoir to control the flow of the river, and is planned
to consist of an earth and rockfill dam together with associated diver-
sion, spillway, low-level outlet.and transmission facilities. Devil
Canyon will consist of a concrete arch dam with associated diversion,
spillway, low-level outlet and transmission facilities.
3.2.1 Watana Development
Watana Dam will create a reservoir approximately 54 miles long, with a
surface area of 38,000 acres, and a gross storage capacity of 9,600,000
acre-feet at elevation (El.) 2185, the normal maximum operating level.
The minimum -operating level of the reservoir is proposed to be El. 2065,
providing active storage volume of 3,700,000 acre-feet for normal oper-
ation.
196/174 3-2
The dam will be an embankment structure with a central impervious core.
The nominal crest elevation of the dam will be El. 2205, with maximum
height 885 feet above the foundation and a crest length of 4,100 feet.
The power intake will be located on the north bank at the end of an
approach channel excavated in rock. From the intake structure, concrete
and steel -lined penstocks will lead to an underground powerstation
housing six 170-MW generating units. The maximum generating capacity of
Watana, therefore, will be 1,020 MW.
Low level outlet facilities will be provided so that downstream flow
requirements can be met when power releases are insufficient to meet
environmental requirements and to provide flood discharge capacity.
The main spillway is a safety structure to discharge inflows to the
i
reservoir that exceed the capacities of the other outlet works. The
spillway will consist of a gated control structure with an inclined
concrete chute leading to a flip bucket. The flip bucket is intended to
reduce river bed erosion when the spillway is used. The spillway could
discharge up to 120,000 cubic feet per second (cfs) at reservoir eleva-
tion 2193.5. The spillway will have sufficient capacity for the Pro-
bable Maximum Flood (PMF) with the reservoir level raised to El. 2201
(four feet below the nominal crest), assuming the low-level outlet
facilities and powerhouse are operated concurrently.
196/174 3-3
3.2.2 Devil Canvon Development
Devil Canyon dam will form a reservoir approximately 26 miles long with
a surface area of 7,800 acres and gross storage capacity of 1,100,000
acre-feet at El. 1455, the normal maximum operating level. The opera-
ting level of the Devil Canyon reservoir controls the tailwater level of
the Watana Development. The minimum operating level of the reservoir
will be E1; 1405, providing active storage volume of 350,000 acre-feet
for normal reservoir operation.
The dam will be a thin concrete arch with a crest level of El. 1463 and
maximum height of 646 feet above foundation. It will be supported by
mass concrete thrust blocks on each abutment. Adjacent to the southern
thrust block, an earth and rockfill dam will extend across a saddle to
the south bank.
The power intake will be on the north bank and will consist of an ap-
proach channel excavated in rock leading to a reinforced concrete gate
structure. Concrete and steel -lined penstock tunnels will lead from the
intake structure to an underground powerstation housing four 150-MW
units. The maximum generating capacity of Devil Canyon is 600 MW.
Low-level outlet facilities will be located in the lower part of the
main dam to assure that downstream flow requirements can be met when
power releases are insufficient to meet in -stream flow requirements and
to provide flood discharge capacity. The spillway is a safety facility
designed to pass 123,000 cfs with the reservoir at normal maximum
196/174 3-4
elevation of 1455. The reservoir will surcharge to El. 1466 during the
PMF if the spillway, powerhouse, and low-level outlet works are opera-
ting concurrently.
3.3 ALTERNATIVE SUSITNA DEVELOPMENT SCHEMES
The License Application as filed found that the optimum development for
Watana corresponded to maximum reservoir elevation 2185, and the Power
Authority Board directed that this configuration be used in re-evalua-
ting the economic and financial feasibility of the Project. Subsequent
studies prepared in connection with this Update have verified the
finding in the License Application. Table 3.1 presents the cumulative
present worth of costs of alternative Susitna development plans with
Watana at various elevations. As can be seen, the maximum net benefit
(least cost) is obtained from a Susitna Project with Watana Development
at El. 2185.
Table 3.1
CUMULATIVE PRESENT WORTH
OF ALTERNATIVE SUSITNA DEVELOPMENT PLANS
(1983 $ million)
Cumulative
Present Worth of Costs
Case inoj Onun
Watana Elevation 2185,
Devil Canyon, and
Thermal Generation
Watana Elevation 2100,
Devil Canyon, and
Thermal Generation
Watana Elevation 2000,
Devil Canyon, and
Thermal Generation
Watana Elevation 1900,
Devil Canyon, and
Thermal Generation
196/174
5730
5877
5931
6636'
3-5
Net ,Increase
In Costs Over
Elevation 2185
147
201
906
3.4 POTENTIAL DESIGN REFINEMENTS
Engineering review of the FERC License Application .and additional
geotechnical investigation at the Watana site have led to certain design
refinements which could reduce Project costs without impairing safety.
The following list identifies the major design features that have been
considered and proposed as refinements:
WATANA:
1. Reduction in dam foundation excavation and treatment requirements;
2. Change in dam configuration and composition to reflect available
materials;
3. Resizing and relocation of cofferdam and diversion tunnels;
4. Combining of power intake and spillway approach channel;
5. Reorientation of underground caverns;
6. Shortening and reduction in number of power conduits;
7. Elimination of fuseplug spillway;
8. Reduction in transmission voltage of north line;
9. Positive cutoff treatment of relict channel;
10. Elimination of outdoor switchyard and utilization of different
switchgear equipment; and
11. Increase in unit speed of generating equipment.
DEVIL CANYON:
1. Elimination of fuseplug spillway.
196/174 3-6
3.5 COST ESTIMATES
3.5.1 Construction Cost Estimate of Project as Filed at FERC
Table D.1 of the FERC License Application detailed the construction cost
estimates for the Watana and Devil Canyon developments in 1982 dollars.
As adjusted by an inflation factor of 1.043, the cost estimate (in 1983
dollars) is as stated in Table 3.2.
Table 3.2 shows the current estimate of the construction cost of the
Watana Development as contained in the FERC License Application as $3.75
billion; the corresponding estimate for the Devil Canyon Development is
$1.62 billion in 1983 dollars.
Table 3.2
SUMMARY OF COST ESTIMATE
January
1983 Dollars ($ million)
Category
Watana
Devil Canyon
Total
Production Plant
$ 2,391
$ 1,111
$ 3,502
Transmission Plant
476
109
585
General Plant
5
5
10
Indirect
461
215
676
Total Construction
3,333
1,440 -
4,773
Construction Overhead
417.
180
597
TOTAL PROJECT
CONSTRUCTION COST
$ 3,750
$ 1,620
$ 5,370
196/174 3.4
3.5.2 Construction Cost Estimates with Refinements
As a result of the potential design refinements listed in Section 3.4,
the construction cost estimate for Watana can be reduced by about
8 percent ($300 million) to approximately $3.45 billion. The Devil
Canyon costs would not be changed by the design refinement.
3.5.3 Operation and Maintenance Costs.
Operation and maintenance costs (0&Mj account for the personnel, equip-
ment, materials, and facilities required to operate the generating plant
and to maintain all of the structures and machinery. Under changing
Project conditions the annual 0&M costs would vary over time. During
the first four years of Watana operation, the annual 0&M costs are
estimated at $8.5 million (1983 dollars). Annual O&M costs are expected
to decrease to $7.3 million until Devil Canyon comes on line. During
the first four years of Devil Canyon operation, the annual 0&M costs for
both dams would increase to a total of $9.8 million. 0&M costs are then
expected to decrease to approximately $7.3 million annually.
Exhibit 3.1 presents the components of the first four year costs of each
development and the total Project 0&M costs.
3.6 RESERVOIR OPERATION STUDIES
The economic feasibility of the .Project depends partially upon the
amount of generating capacity and energy that will be available for
196/174 3-8
sale. To evaluate this aspect of the Project; operation studies were
performed to estimate the power and energy production capability of
Susitna under the operating assumptions set forth in the July 1983 FERC
License filing, which provides for the Watana Development to initially
operate as a base load facility. Additional studies are now being
conducted to determine if the economic benefits of Watana can be in-
creased by more closely matching its operation with that of the Railbelt
utilities, while still operating within environmental constraints.
Regardless of the outcome of these studies, when Devil Canyon comes on
line, Watana will operate to follow load while Devil Canyon will operate
as a base load facility. At that time the variation in flows from
Watana would be controlled by the Devil Canyon dam.
3.6.1 Simulation Model
A dual -reservoir computer simulation program was developed during the
1982 Susitna Project Feasibility Study. This program has subsequently
been modified to i-ncorporate use of a variable tailwater rating. and
variable turbine capacity and efficiency to study the impacts of various
reservoir operation scenarios. Minor changes in data input requirements
and output format were also implemented. The model is used in per-
forming the power and energy studies presented in this Chapter.
3.6.2 Hydrology
Tho initial step in simulating reservoir
operation is
to assess the
natural water flow
conditions (hydrology)
of the river.
Thirty-three
196/174 3-9
years of streamflow data from 1960 to 1982 are available and Project
operation was simulated on a monthly basis for the entire historical
period.
3.6.3 Reservoir Data
The relationship of area and volume of reservoirs to the elevation of
the Watana and•Devil Canyon dams is set forth in Exhibits 3.2 and 3.3.
At the Watana Development's normal maximum pool elevation of 2185, the
reservoir surface area is about 38,000 acres, and the gross storage
volume is 9.6 million acre-feet. At the Devil Canyon normal maximum
pool elevation of 1455, the reservoir surface area is about 7,800 acres,
with a gross storage volume of 1.1 million .acre-feet. The .active
storage volumes are 3,700,000 acre-feet for Watana, and 350,000 acre-
feet for Devil Canyon.
3.6.4 Turbine and Generator Data
The i-nstall-ed capacity of the WatanaDevelopmentis 1020 MW-, provided in
six units, each rated at 170 MW. The fifth and sixth units provide no
additional energy production in the early years but are available for
peaking use and reserve to the degree such operation would conform to
stream flow requirements.
The operating characteristics for the Watana and Devil Canyon power -
plants are summarized on Exhibit 3.4 based on the rated net head at each
site. In all cases, generator and transformer efficiencies of 98 and 99
percent, respectively, were used to compute the overall plant effi-
196/174 3-10
ciency. The head loss incurred in flow of water through the intake,
penstocks, and discharge passages of the Watana and Devil Canyon power -
plants is assumed to be 1.5 percent of the gross head.
3.6.5 Reservoir Operation Constraints
During the early years of operation, energy generation from the Susitna
Project would be limited by Raiibelt electrical demand. Operation
simulations were made for a wide range of Railbelt system demand levels
(4000-8000 GWh/year) to establish the relation of system demand to
energy production from the Project.
Analysis of the Project's economics has assumed operation designed to
meet certain energy requirements along with some minimum monthly in -
stream flow requirements for the months of July, August, and September.
These flows were delineated at the mouth of Gold Creek (denoted as "Case
C" in the FERC License Application) are shown in Table 3.3.
A reservoir rule curve is a list of monthly target reservoir elevations
which control reservoir operation to achieve a desired result with
respect to use of a water resource. A preliminary Watana rule curve has
been developed to maximize average energy generation, maintain a high
level of dependable energy and meet .environmental requirements' as
defined by the "Case C" minimum flows. The Devil Canyon reservoir rule
curve is designed to keep the reservoir as full as possible in all
cases.
196/174 3-11
Table 3.3
POTENTIAL MINIMUM FLOWS AT GOLD CREEK (cfs)
Month
Flow
Month
Flow
October
5000
April
5000
November
5000
May
6000
December
5000
June
6000
January
5000
July
6480
February
5000
August
12000
March
5000
September
9300
3.6.6 power and Energy Production
Energy production (GWh) and Project capacity (MW) have been estimated
from the reservoir operation studies described above. The studies
considered the energy demands for the period 1993 through 2020 for the
load forecasts developed in Chapter 2. Exhibit 3.5 sets forth the
annual energy production from the Watana and Devil Canyon developments,
as compared with annual demand figures for the forecast demand.
Exhibit 3.6. summarizes the power and energy production for Watana and
Devil Canyon under the 2020 load forecast. The power and energy esti-
As discussed in the FERC License Application, this flow scenario
was selected as the Project operation flow regime considering both
Project and in -stream flow uses.
** The flow changes by 1000 cfs per day from 6000 on July 25 to 12,000
on August I and from 12,000 on September 14 to 6000 on September 21.
196/174 3-12
mates are based on the modes of operation and constraints previously
discussed.
3.7 ENVIRONMENTAL STATUS UPDATE
This section presents an update of the status of the principal environ-
mental aspects of the Susitna Project•, and the activities being con-
ducted with regard thereto. As previous sections have noted, environ-
mental restrictions (e.g., prescribed minimum downstream flows) can
limit the maximum energy production which would otherwise be possible
from the Susitna Project.
Environmental studies have continued since the 1982 Feasibility Report
and the initial filing of the FERC License Application in February 1983.
The objectives of the most recent studies have been to prepare specific
information required for State, local and Federal permit applications
and to assist in the licensing process by responding to FERC Staff
inquiries. As of this time, responses have been prepared and provided
to FERC on approximately 350 requests for clarification and supplemen-
tary information. In addition, the Power Authority has responded to
over 1,000 comments on the License Application in connection with the
Environmental Impact Statement process. A list of issues and questions
has also been compiled from a comprehensive review of all State, local
and Federal agency comments received by the Power Authority during the
past four years. Most of these issues have been addressed in submis-
sions to FERC; work on others is continuing.
196/174 3-13
In addition to answering written requests for information and responding
to comments, the Power Authority has provided many recent studies to
FERC, Federal and State agencies in responding to their comments on the
License Application. The Power Authority also conducted a tour of the
Susitna basin and related areas for FERC personnel during the week of
August 21-27, 1983, so that they could better evaluate the Project using
first-hand information.
-Continuing environmental activities focus on the evaluation of impacts
and the refinement of mitigation programs tailored to specific Project
needs. These activities cover all aspects of potential Project impacts
and are briefly discussed below under the major headings of aquatic,
terrestrial and social sciences programs.
3.7.1 Aquatic Programs
Potential Project impacts include the possible effects of altered
seasonal flow regime on the ecosystem of the Susitna River, including
possibly altered water temperature regimes, turbidity and other water
quality parameters' (e.g., dissolved gas and suspended solids concentra-
tions downstream from the reservoirs). .
The effect of the altered flows on anadromous and resident fish habitats
and their associated populations is the major focus of present studies.
Five major habitats have been identified which are important to fish and
will be affected by the altered flows. These are the mainstream of the
Susitna River, side channels, side sloughs, upland sloughs and tributary
196/174 3-14
mouths. The principal concerns of potential alterations to spawning
habitats of salmon, access to the spawning habitats, and juvenile
rearing habitats are addressed through a series of mathematical models
relating potential changes in flow to fish habitats. Physical and bio-
logical data calibrate the predictive models and relate the physical
changes in habitats to the biological impacts.
To address the potential effects of the altered temperature regime, it
'is necessary to estimate what changes will occur. This is accomplished
through a series of mathematical models which address water temperature
in the reservoirs and in the river downstream. As a part of this
analysis, a mathematical model is also being used to analyze ice pro-
cesses in the reservoirs and river.
Changed turbidity, sediment transport and other water quality parameters
are analyzed through comparisons of predicted changes with observed
changes at other comparable hydroelectric projects.
The Power Authority's environmental analysis also includes effects of
changes in discharge from the Project during a single day should Watana
be operated under some variation of a load -following scenario in sup-
plying the power needs of the Railbelt system.
3.7.2 Terrestrial Programs
Project impact assessments and proposed mitigation plans regarding
terrestial ecosystems continue to be evaluated as discussed in the FERC
196/174 3-15
License Application. Models have been designed to evaluate potential
loss of habitat (lost moose carrying capacity and changes in moose
population due to changes in carrying capacity), predator -prey ratios,
hunting pressure, and other factors. Modeling components also include
browse inventories, plant phenol ogy studies, refined vegetation and
wetlands mapping, moose censuses, moose movements, and predation by
wolves and bears in controlling moose numbers. This information facil-
itates the development of mitigation programs commensurate with Project
impacts.
The Power Authority continues to monitor movements and habitat use by
moose in the riparian zone downstream of Devil Canyon; monitor the
movements and herd size of caribou in the Project area; analyze the use
of the Jay Creek mineral lick by Dall sheep; monitor bear and wolf
movements and habitat use; monitor raptors, particularly golden and bald
eagles; and monitor beavers in the riparian zone from Devil Canyon to
Talkeetna.
3.7.3 Social Sciences Programs
Included within the social sciences programs are cultural resources,
socioeconomics and recreation.
3.7.3.1 Cultural Resou
Regarding cultural resources, field work in 1983 included continued
reconnaissance surveying of the proposed dam sites, impoundment areas,
196/174 3-16
and borrow sites (for the purpose of identifying potential historic and
archeological sites). In addition, testing of certain identified sites
was conducted. A sensitivity mapping of archeological potential was
completed for the proposed railroad, access road, transmission line, and
Phase I Recreation Plan.
3.7.3.2 Socioeconomics
The Power Authority also continues to refine appropriate mitigation
plans. Socioeconomic analyses are being refined and updated based upon.
survey information from adjacent communities.
3.7.3.3 Recreation
A Recreation Plan Implementation Report will outline the steps required
to implement Phase I of the Recreation Plan as identified in Chapter 7,
Exhibit E of the FERC License Application. This report will include a
plan of action for resolving necessary policy and management issues,
such as: what Project areas and facilities will be open to the public;
policies regarding access and use of recreation resources; and control
by landowners and landmanagers.
196/174 3-17
EXHIBIT 3.1
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EXHIBIT 3.2
AREA AND VOLUME VERSUS ELEVATION
WATANA RESERVOIR
Elevation
Volume
Area
(ft, msl)
(acre-feet)
(acres)
1460.0
0.
0.
1500.0
3000.
150.
1550.0
34000.
1100.
1600.0
127000.
2620.
1650.0
292000.
3990.
1700.0
532000.
5620.
1750.0
870000.
7860.
1800.0
1318000.
10010.
1850.0
1877000.
12270.
1900.0
2546000.
14490.
1950.0
3330000.
16880.
2000.0
4248000.
19850..
2050.0
5341000.
23870.
2100.0
6645000.
28290,
2150.0
8189000.
33940.
2200.0
10017000.
39730.
2250.0
12212000.
48030.
EXHIBIT 3.3
AREA AND VOLUME VERSUS ELEVATION
DEVIL CANYON RESERVOIR
Elevation Volume Area
(ft, m81) (acre-feet) (acres)
900.0
0.
0.
950.0
2000.
70.
1000.0
7000.
190.
1050.0
25000.
400.
1100.0
49000.
654.
1150.0
65000.
955.
1200.0
132000.
1360.
1250.0
195000.
1860.
1300.0
292000.
2490.
1350.0
456000.
3565.
1400.0
707000.
5480.
1450.0
1048600.
7600.
1500.0
1484000.
9560.
EXHIBIT 3.4
POWERPLANT DATA
Reservoir
Net Head Elevation Plant Capacity_ Efficiency
(%Rated) (Feet) (Feet) (M) (%Rated) Turbine Plant
Watana Development
0.850
578.0
2045.1
834.4
76.9
0.894
0.867
0.900
612.0
2079.8
915.8
84.4
0.900
0.873
0.950
646.0
2114.4
499.4
92.1
0.905
0.878
1.000
680.0
2149.0
1085.1
100.0
0.910
0.883
1.030
700.4
2169.8
1131.7
104.3
0.908
0.881
1.060
720.8
2190.6
1178.4
108.6
0.906
0.879
Devil
Canyon Development
0.850
501.5
1360.5
521.1
76.9
0.894
0.867
0.900
531.0
1390.7
571.7
84.4
0.900
0.873
0.950
560.5
1420.7
623.5
92.1
0.905
0.878
1.000
590.0
1450.8
677.2
100.0
0.910
0.883
1.030
607.7
1468.8
706.3
104.3
0.908
0.881
EXHIBIT 3.5
SUSITNA ENERGY
GENERATION
Sus itna
Total
Generation
Devil
Year
Demand
Total
Watana
Canyon
(GWh.)
(GWh)
(GWh)
(GWh)
1993
4399
2905
2905
—
1994
4492
2940
2940
—
1995
4588
2970
2970
—
1996
4676
2995
2995
—
1997
4751
3024
3024
s-
1998
4833
3060
3060
—
1999
4915
3100
3100
—
2000
4996
3105
3105
—
2001
5177
3153
3153
—
2002
5238
4670
2396
2274
2003
5359
4791
2458
2333
2004
5481
4913
2520
2393
2005
5602
5034
2582
2452
2006
5771
5203
2669
2534
2007
5939
5371
2755
2616
2008
6107
5539
2842
2697
2009
6276
5708
292E
2780
2010
6444
5876
3014
2862
2011
6610
5994
3033
2961
2012
6780
6144
3109
3035
2013
6955
6285
3180
3105
2014
7135
6356
3216
3140
2015
7318
633E
3207
3131
2016
7507
6329
3202
3127
2017
7701
6496
3286
3210
2018
7899
6661
3370
3291
2019
8103
6736
3408
3328
2020
8312
6766
3423
3343
EXHIBIT 3.6
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4.0 NON-SUSITNA GENERATION ALTERNATIVES
4.1 INTRODUCTION
Several alternative technologies exist that could be used to generate
electricity for the Railbelt, either as substitutes for, or as comple-
ments to the Susitna Project. The alternatives include natural gas -
fired combustion turbines, gas -fired combined cycle power plants and
coal-fired steam turbines. In addition, the Chakachamna Hydroelectric
Project could be a component of a Non-Susitna generating system. These
alternatives are analyzed in this Update to evaluate the economic feasi-
bility of the Susitna Project.
The ability of any alternative to meet Railbelt demand depends on elec-
trical demand, the availability and price of fuels for thermal power -
plants, and the capacity and flow regimes of hydroelectric plants.
These were analyzed most recently in the July 11, 1983 FERC License
Application filing. This Chapter provides a summary description of the
studies contained in that document. In addition, recently completed
studies by the Power Authority regarding the Chakachamna Hydroelectric
Project (Bechtel 1983) and the use of North Slope gas, (Ebasco 1983) for
the Railbelt are also evaluated.
The generation alternatives discussed in this Chapter are used in the
formulation of system expansion plans described in Chapter 5.
200/174 4-1
4.2 NATURAL GAS -FIRED OPTIONS
Natural gas currently fuels generation which serves about 75 percent of
Railbelt electric energy demand. Assessments of thermal alternatives
should, therefore, logically begin with an analysis of gas -fired
options.
4.2.1 Natural Gas Availabilitv and Cost -
4.2.1:1 Cook Inlet Gas Availability. The two major known gas resources
in Alaska are located at Cook Inlet and the North Slope. Estimates of
natural gas resources in the Cook Inlet area have been made by the
Alaska Department of Natural Resources (DNR 1983), the Alaska Oil and
Gas Conservation Commission (OGCC 1982) and the United States Geological
Survey (USGS 1980).
Estimates of natural gas are divided into proven and undiscovered re-
serves. Proven gas reserves are those reserves whose location is known
from wells drilled and whose quantity is estimated from flow rates and
specific geologic data. Undiscovered gas reserves are reserves that are
located outside of known fields, the volume of which is estimated using
geological information.
OGCC estimates proven gas reserves by field on an annual basis. Gas
volume is estimated using initial wellhead pressure, changes in well-
200/174 4-2
head pressure during production, analyses of drill cores, and field size
obtained from seismic data. The OGCC's estimate of proven Cook Inlet
gas reserves as of January 1983 is 3.5 trillion cubic feet (TCF), the
figure utilized in this Update. OGCC does not estimate undiscovered
reserves.
There is some uncertainty as to the amount of undiscovered gas in Cook
Inlet. In 1983, DNR developed an estimate of undiscovered gas resources
in the Cook Inlet area using a "Play Approach", which determines the
amount of hydrocarbons in a "play", or prospect, through use of reser-
voir engineering equations which take probability and risk factors into
account. Estimates for various reservoirs are aggregated to create an
estimate of the reserves. DNR estimated undiscovered gas resources for
both total gas in place and economically recoverable gas. The expected
amount of total gas in place was estimated to be 3.36 TCF and the ex-
pected economically recoverable gas was estimated to be 2.04 TCF.
The USGS estimated Cook Inlet undiscovered reserves using a subjective
method in which gas resources were estimated by a team of experts.
Geological information and results from other methods were reviewed and
weighted by the experts. The weighted average quantity of economically
recoverable gas was estimated to be 5.72 TCF.
The lower DNR estimates of undiscovered reserves are used in this Update
for three reasons. First, the USGS estimate was made using data
available in 1980. While no exploration for non -associated gas (gas not
discovered in connection with oil) occurred during the 1980-82 period,
200/174 4-3
oil exploration continued and the DNR had access to additional explor-
ation information in preparing its 1983 report that was not available to
the USGS in 1980. Second, the Cook Inlet area analyzed by the USGS was
larger than the Cook Inlet basin analyzed in the DNR estimate. The
larger estimate consists mostly of additional on -shore areas on the
Kenai Peninsula and to the west and north of Cook Inlet. Finally, the
play methodology (used by DNR) is more subjective than USGS methodology.
In any event, the difference between DNR and USGS estimates of undiscov-
ered Cook'Inlet gas has a relatively minor effect on the economic analy-
sis. As shown in a sensitivity analysis presented in Chapter 6, even if
the Cook Inlet reserves are unlimited, the With-Susitna expansion plan
would still have a net economic benefit over the Nan-Susitna plan devel-
oped with such a gas supply.
4.2.1.2 Cook Inlet Gas Consumption. Cook Inlet gas is used for house-
hold heating, commercial applications, LNG and ammonia/urea production,
and electricity generation as shown in Exhibit 4.1. Of the 3.5 TCF of
proven reserves, some 1.9 TCF are committed by contract to existing
users, and about 1.7 TCF remain uncommitted. As previously noted, in
addition to the 3.5 TCF of proven reserves, there are estimated to be
2.0 TCF of undiscovered reserves which are economically recoverable.
The pattern of future consumption of Cook Inlet gas depends on the gas
needs of the major users and their ability to contract for needed sup-
plies. Since'there is a limited quantity of proven gas and the esti-
mates of undiscovered reserves in the Cook Inlet area have yet to be
proven, gas reserves may be exhausted by the late 1990's, as shown on
200/174 4-4
Exhibit 4.1. In addition, there probably is a limit to allowable gas
consumption by electric utilities because other uses will be accorded
higher priorities either through contract or by order of regulatory
agencies. A restriction on such use of gas might be appropriate since
coal could be made available for electric generation. To estimate the
quantity of Cook Inlet gas available for electrical generation, there-
fore, it is necessary to assess the requirements of the major users.
These are summarized on Exhibit 4.1 and discussed in greater detail
below.
Phillips/Marathon LNG currently has 360 billion cubic feet (8CF) of gas
under contract and Collier Chemical has 377 BCF. It is highly probable
that both entities will obtain enough of the uncommitted gas resources
to meet their needs through 2010 because both Phillips/Marathon LNG and
Collier operate established facilities. They are also owned by Cook
Inlet gas producers who control part of the uncommitted reserves.
Phillips/Marathon LNG and Collier are therefore estimated to consume 62
BCF and 55 BCF, respectively, per year from 1983 through 2010.
At present, Enstar has enough gas under contract to serve its retail
customers until after the year 2000, but since Enstar also sells gas to
the military, Chugach Electric Association, and Anchorage Municipal
Light and Power for electric generation, it may have to seek additional
reserves to meet the needs of its larger customers. It is assumed,
however, that Enstar will be able to acquire sufficient gas to meet the
needs of its retail customers (including new Matanuska Valley custo-
mers). Further, it is reasonable to assume that its retail customers'
200/174 4-5
needs will have priority over its wholesale sales of gas for electrical
generation. Accordingly, retail use is estimated in Exhibit 4.1 to in-
crease from about 19 BCF in 1983 to 52 BCF in 2010. Gas used in field
operations and the residual, "Other Sales", vary from year to year but
together are estimated, based on historical use, to average approxi-
mately 25 BCF per year over the period 1983 through 2010.
After satisfying all of the above needs, there is still a considerable
amount of gas in the near term that could be used for electrical gene-
ration. Chugach Electric Association has 285 BCF committed through
contract and Enstar has 759 BCF contracted, some of which will be sold
to Anchorage Municipal Power and Light and Chugach Electrical Assoc-
iation for electrical generation. Assuming that the Anchorage -Fairbanks
Intertie is completed in 1984-85, it is possible that electrical genera-
tion using Cook Inlet gas would increase to provide less costly energy
to Fairbanks. This would, of course, increase the rate at which Cook
Inlet reserves are depleted.
An estimate of the quantities of Cook Inlet gas required to meet all
Railbelt electrical requirements was made using the estimated load and
energy forecast for the Railbelt area. Forecast generation from the
existing Eklutna and Cooper Lake hydroelectric units, the proposed Grant'
Lake and Bradley Lake projects, as well as, generation from the existing
Healy coal-fired unit, was subtracted from the forecast electrical re-
quirements. The estimated annual gas consumption for power generation
under this scenario increases from 27 BCF in 1983 to 36 BCF in 2010.
200/174 4-6
The forecast annual and cumulative use of gas for each of the major
users, and the total use of gas for the Railbelt, is shown in Exhibit
4.1. The remaining proven and undiscovered gas resources are also
shown. As can be seen, proven reserves (3.5 TCF) will be exhausted by
1998, and proven plus economically recoverable undiscovered resources
will be exhausted by about 2007. Inspection of the Total Cumulative Gas
Use column in Exhibit 4.1 shows that currently. committed reserves (1.9
TCF) could be exhausted in 1992 under this scenario.
The data indicates that -relying on gas -fired electrical generation to
provide the Railbelt's needs is problematic in that it depends on the
future availability of uncommitted proven and undiscovered reserves of
natural gas for electrical generation. This is especially true since
uncommitted proven reserves and any undiscovered resources could also be
acquired by established entities or entities not shown in Exhibit 4.1,
further reducing the availability of Cook Inlet gas for electric gene-
ration. Known potential purchasers for the uncommitted recoverable and
undiscovered Cook Inlet gas reserves include Pacific Alaska LNG Assoc-
iates (PALNG) and the operators of the proposed Trans -Alaska Gas System
(TAGS).
The proposed PALNG project could have a significant impact upon the•
future availability of gas. The project was initiated about ten years
ago, but has been repeatedly delayed by difficulties in obtaining final
regulatory approval for a terminal in California. At one time, PALNG
had 980 BCF of recoverable reserves under contract. The contracts ex-
pired in 1980, but producers have not given written notice of termi-
200/174 4-7
nation, so the contracts have been held in abeyance. Recently, however,
Shell Oil Company sold 220 BCF of gas formerly committed to PALNG to
Enstar. This reduced reserves committed to the PALNG project to 760
BCF.
Implementation of the PALNG project would depend primarily on the avail-
ability and price of alternative sources of natural gas for the Lower 48
market, and particularly for the California market. When all factors
are considered, it does not appear that the PALNG project will be imple-
mented prior to 1995. The remaining reserves originally committed to
PALNG may therefore become available to other purchasers such as Chugach
Electric Association or Enstar, if the project's sponsors conclude that
the potential markets for this supply are too uncertain.
The proposed TAGS project would build a natural gas transmission line
from Prudhoe Bay on the North Slope to the Kenai Peninsula (near
Nikishka). The gas from the North Slope would be liquefied and sold to
Japan and other Asian countries. The proposed project is an alternative
method of bringing North Slope gas to market.
If the project were implemented, Cook Inlet gas producers might be able
to sell their gas to TAGS for liquefaction and sale to Asia, further
reducing available supplies for in -State purchase and consumption. Such
sale would depend on the ability of the liquefaction facilities to
handle greater gas quantities and on whether the market for LNG would
require such additional quantities. The price paid by TAGS to Cook
Inlet producers might be high enough to outbid competing purchasers,
200/174 4-8
since the Cook Inlet gas would not be burdened with the costs of the
transmission line from Prudhoe Bay, although some new transmission and
gathering lines would probably be required in Cook Inlet.
4.2.1.3 Cook Inlet Gas Price. If current and future Railbelt electrical
requirements are to be met with gas generation, new purchases of uncom-
mitted Cook Inlet gas and future purchases of undiscovered resources
will be required. The price that will have to be paid for these addi-
tional gas resources is important in the evaluation of thermal alterna-
tives to the Susitna Project.
J
The actual price that would be agreed upon for uncommitted gas between
producers and the utilities is difficult to predict, but an indication
is provided by the recent Enstar/Shell and Enstar/Marathon contracts for
uncommitted gas resources. Under these agreements, the wellhead price
is $2.32/MMBtu with an additional demand charge of $0.35/MMBtu beginning
in 1986. Severance tax is estimated at $0.15/MMBtu. An additional
fixed pipeline charge of about $0.30/MMBtu would be incurred for
pipeline delivery to Anchorage.
The prices established under these contracts could be a reasonable fore-
cast of future Cook Inlet prices if there is no additional competition
for Cook Inlet gas from entities who are not current users. Although
the possibility of uncommitted Cook Inlet reserves being purchased for
LNG export seems to be remote at the present time, conditions may change ,
in the future. The price that producers might be able to obtain if LNG
export opportunities exist might then become important. A method that
200/174 4-9
can be used to estimate wellhead prices for LNG export is to begin with
the market price for delivered LNG and then subtract shipping, lique-
faction, conditioning, and transmission costs to arrive at the maximum
wellhead price. The wellhead price of Cook Inlet gas for LNG export
calculated in this manner varies depending on the average price of oil
delivered to Japan.
Based on an oil price of $29/bbl (1983 OPEC Benchmark price), the max-
imum price that could be paid to Cook Inlet producers for LNG is cur-
rently about $3/MCF. This price is higher than the estimated prices
where no LNG export opportunities exist. Therefore, as LNG oppor-
tunities increased, the price of Cook Inlet gas for electrical gene-
ration would probably be higher than assumed above, since the utilities
would have to outbid potential LNG exporters to acquire supplies.
For purposes of this Update, the Enstar contracts have been used as the
basis for future Cook Inlet gas prices because they reflect recent nego-
tiations for the purchase of that gas. It should be recognized, how-
ever, that the Enstar contracts were negotiated when oil prices were
softening and there did not appear to be other markets for Cook Inlet
gas. The gas price situation could change in the future for the pur-
chase of additional gas. Uncommitted proven reserves will be exhausted
by 1998 and undiscovered economically recoverable reserves will have to
be brought into production through exploration and development that will
involve substantially higher costs. The demand for gas could also in-
crease, resulting in greater competition for available supplies. With
time, it is possible that natural gas prices might move closer to oil
200/174 4-10
prices than the approximate 40 percent relationship established under
the current Enstar contracts. Therefore, the Enstar contracts are a
conservative means of estimating Cook Inlet gas prices.
The method used to escalate natural gas prices over the forecast period
was to correlate the increase in gas prices with the projected rate of
increase in world oil prices. This method was selected in recognition
of the general substitutability of the two fuels. The recent Enstar
contracts are evidence of this pricing correlation, as they provide for
the escalation of the gas price based upon the price of No. 2 fuel oil
on the Kenai Peninsula. Projected natural gas prices were therefore
based on the escalation rate for the SHCA-NSD oil price scenario shown
in Exhibit 4.2.
In summary, based upon the limited remaining quantities of Cook Inlet
natural gas, reliance on such electric power generation past the year
2000 would seem to entail a considerable amount of risk.
4.2.1.4 North Slope Gas. The vast reserves of natural gas on the North
Slope could be moved closer to the Railbelt if either ANGTS or TAGS is
built. The ANGTS project would deliver North Slope gas to the Lower 48
states by means of a large diameter pipeline traversing central Alaska
and Canada. The ANGTS route is such that it would be possible to
construct a lateral line to Fairbanks. The proposed TAGS project would
deliver gas to the Kenai Peninsula for liquefaction and export as LNG,
principally to Japan. The development -of either ANGTS or TAGS depends
on the future prices of world oil and natural gas prices and
200/174 4-11
availability in the Lower 48 states.
Even with development of ANGTS or TAGS, it should be recognized that .
natural gas from the North Slope would be expensive if sold in either
Fairbanks or on the Kenai Peninsula because the purchase price of such
natural gas would include the costs of conditioning and transporting it
to the point of end use. As estimated by Battelle, the cost of ANGTS
gas in the Fairbanks area would be between $4.03 - $6:32/MMBtu in 1983
dollars in the first year of pipeline operation, assuming the wellhead
price -of gas was between $0.00 per MMBtu and $2.30 per MMBtu, respec-
tively. The General Accounting Office (GAO) recently estimated the
delivered price to Fairbanks to be between $2.80 and $5.10/MMBtu in 1983
dollars assuming wellhead prices of between $0.00 per MMBtu and $2.30
per MMBtu, respectively.
If the TAGS line were constructed, prices would range from $3.03 -
$4.19/MMBtu in 1983 dollars for delivery to the Kenai Peninsula.* At
$3.03/MMBtu the TAGS net -back calculated wellhead price would be a
negative $1.34/MMBtu. Obviously, at a negative price, the Project would
not be undertaken.
The various estimates of North Slope gas projects converge to a price of
about $4.00/MMBtu for North Slope gas delivered to the Railbelt and this
value would be realistic if either TAGS or ANGTS were to be constructed.
* Use of North Slope Gas for Heat and Electricity in the Railbelt,
prepared by Ebasco Services, Inc. for the Power Authority, September,
1983. (Hereafter, Ebasco, 1983).
200/174 4-12
In the absence of ANGTS and TAGS, two energy development proposals util-
izing North Slope gas have been analyzed in a report recently completed
for the Power Authority (Ebasco, 1983). The first development involves
power generation at the North Slope via simple cycle combustion turbines
with attendant electrical transmission from the North Slope to Fairbanks
and Anchorage. The second involves electric power generation at
Fairbanks using combined cycle plants with transmission lines from
Fairbanks to Anchorage. The first alternative would require the con-
struction of two 450-mile 500-kV transmission lines from the North Slope
to Fairbanks. The second alternative would require transportation of
gas to Fairbanks from the North Slope by means of a 22-inch diameter,
high pressure pipeline and a gas conditioning facility on the North
Slope.
The North Slope power generation scenario is not economically attractive
and its reliability would be questionable. The study determined that
approximately $4.4 billion (1983 dollars) would be required to construct
the 1400 MW of new generating capacity and transmission lines necessary
to satisfy the Railbelt's electrical demand in the year 2010. Total
operation and maintenance costs for the system would amount to a total
of $1.1 billion for the years 1993 through 2010. In addition, the pro-
posal is subject to some serious technical uncertainties which would
require much more detailed study to determine the project's feasibility.
North Slope gas could also be made available at Fairbanks via a 22-inch
diameter gas pipeline from the gas field. The pipeline design flow of
383 million cubic feet per day would transport sufficient gas to produce
200/174 4-13
approximately 1400 MW of electrical power and satisfy the projected
residential and commercial natural gas demand in the Fairbanks area to
the year 2010.
It is estimated that the capital investment for the Fairbanks pipeline
and its associated gas conditioning facilities would be about
$5.8 billion, and that if capital and 0&M costs increase at the rate of
inflation, a levelized price for the gas would be about $9.90/MMBtu.
Other assumptions in this analysis include: 1) private ownership; 2) a
wellhead price of $1.00/MMBtu, subject to a 12.5 percent royalty; 3) a
real discount rate of 10..0 percent and capital cost escalation rate of
3.5 percent; and 4) a pipeline and conditioning plant life of 30 years.
If ownership and financing of the pipeline by the State of Alaska is
assumed, the real discount rate would be 3.5 percent and the levelized
delivered price of the gas would be about $7.20/MMBtu. Neither deliver-
ed price of gas would be competitive, however, making the scenario of
the pipeline to Fairbanks uneconomical.
In summary, for North Slope gas to enter the marketplace by ANGTS,
natural gas prices in the Lower 48 will have to rise considerably.
Implementation of the TAGS project would require a demand for LNG in
Asian markets at a price in excess of the current $4.80 to $5.20 per
MMBtu. The alternative plans for bringing North Slope gas to the mar-
ketplace involve substantial capital investments in pipeline and gas
conditioning facilities and potential technical risks which would make
electricity generated under such plans substantially more expensive and
uncertain than Susitna-generated power.
200/174 4-14
4.2.2 Natural Gas -Fired Powerplants
Natural gas can be used in the following types of thermal powerplants:
simple cycle combustion turbines (SCCT), combined cycle combustion tur-
bines (CCCT), and steam turbines. The SCCT and CCCT alternatives are
preferred because natural gas -fired steam turbine plants are economical
only at very large unit sizes (i.e., substantially larger than 200 MW).
In the sizes appropriate for the Railbelt needs, SCCTs and steam turbine
are more costly and less efficient than the CCCT.
4.2.2.1 Simple Cycle Combustion Turbines. The SCCT is a well proven
system for electricity generation that can be used to meet both baseload
and peak demand requirements. Natural gas and air under pressure are
burned in the turbine, and the resulting products of combustion are
expanded across the turbine. The unit is characterized by rapid start-
up capability with no need for a cooling system.
The combustion turbine is factory manufactured and supplied in major
components that are assembled at the site. These characteristics result
in economies of mass production and quick installation. The 75 MW unit
size, with a full load heat rate of 11,755 Btu/kWh, was chosen for.anal-
ysis because it can be utilized effectively in the interconnected Rail -
belt system and is less costly on a per kilowatt basis than smaller
units.
The data demonstrate that the large combustion turbine is,a reasonably
efficient machine when operating at or near full load. Its efficiency
200/174 4-15
suffers substantially, however, when it is operated at less than 80
percent of capacity, and when load varies over a large percentage range.
Capital and operation and maintenance costs of combustion turbines are
summarized on Exhibit 4.3.
4.2.2.2 Combined Cycle Combustion Turbines. The CCCT makes use of the
high -temperature (1000°F) combustion turbine exhaust. In the CCCT sys-
tem, the exhaust is ducted to a waste heat boiler or heat recovery steam
generator. The steam pressure is then raised and the steam is expanded
in a conventional steam turbine to produce additional power. Because of
both technical and economic gains from scale available at the 237 M14
size and because of size of the Railbelt system load, this unit (with a
heat rate of 8,280 BTU/kWh) was chosen for analysis.*
The CCCT has a thermal efficiency of 41 percent when operating at full
load, compared to the SCOT efficiency of 29 percent (11,650 BTU/Kwh)
under the same conditions. Efficiency of both types of units drops
rapidly at partial loads. Capital and 0&M cost estimates for a 237 MW
unit are summarized on Exhibit 4.3.
4.3 COAL-FIRED OPTIONS
Coal-fired generation is another viable alternative for the Railbelt
Region. Coal currently supports 8.3 percent of utility capacity, and is
used to generate 13.5 of the electrical energy supplied to consumers in
the Railbelt.
* The 237 MW figure represents a 220 MW standard unit rated for Cook
Inlet conditions.
200/174 4-16
4.3.1 Coal Availability and Cost in Alaska
There are three major deposits of coal in Alaska: the Nenana Field, the
Beluga Field and the Kuparuk Field. There are additional smaller de-
posits in the vicinity of Nome, in the Matanuska Valley, and on the
Kenai Peninsula. These fields contain 130 billion tons of coal
resources and 6 billion tons of coal reserves. The Nenana and Beluga
fields are the most important deposits, as the others have problems that
preclude effective large scale exploitation in the near future.
The Nenana Field, located near Healy, has a total resource of 7 billion
tons and a mineable base of 457 million tons. The Beluga Field, about
75 miles west of Anchorage across Cook Inlet, has identified resources
of 1.8 to 2.4 billion tons of coal. Both fields are characterized by
thick seams (i.e., thicker than 10 ft.), quantities close to the sur-
face, and modest quality coal of 7500 - 7800 Btu/lb.
Coal production in the Nenana field is at the Usibelli Coal Company mine
at Healy and current production is 830,000 tons/yr. Currently the coal
produced at this mine is sold to the Fairbanks Municipal Utility System,
the Golden Valley Electric Association, the University of Alaska at
Fairbanks, and the U.S. Department of Defense. This production will
increase to 1.7 million tons annually when the Suneel exports to Korea
begin in 1984. The mine could be expanded further to about 4.0 million
tons annually to support electric power generation. The current
Usibelli mine uses a dragline and front-end loader -based production
200/174 4-17
system. Present production capacity is about 1.7-2.0 million tons an-
nually. The existing system would have to be duplicated to achieve
doubled capacity.
The Beluga Field has not been developed. However, Beluga deposits are
in reasonable proximity to tidewater and could therefore have access to
Pacific Rim markets. The Beluga Field represents an export opportunity,
and both Diamond Alaska Coal Company and Placer Amex -are studying the
potential for such development. The Diamond Alaska design would produce
10 million tons of coal annually while the Placer Amex project is sized
at 5 million tons annually. These facilities are designed to serve the
growing market of Japan, Korea, Taiwan, and other Asian nations.
Production from the Beluga Field could begin as early as 1988, and could
also serve domestic markets.
Beluga Field production costs, for 5 to 10 million tons per year
export -based project, are estimated to be $1.70/MMBtu, and the market
value of the coal (FOB 1983$ at Granite Point) is estimated to be
$1.86/MMBtu. Both costs include the cost of developing an
infrastructure to serve an export market.
While the Pacific Rim market is growing, the lack of infrastructure
creates major risks in predicting the development of a large Beluga
mine. If export mines do not develop, a small scale coal mine could be
developed for the domestic market alone. Such a development would in-
volve altering production technologies to meet the reduced capacity re-
quirements. If the Beluga Field were developed to serve domestic needs,
200/174 4-18
the estimated initial cost of Beluga coal would be as shown in Table
4.1.
Mine Produc-
tion Rate
tons/yr
1,000,000
3,000,000
Table 4.1
ESTIMATED BELUGA FIELD COAL
COSTS WITHOUT EXPORTS
Power Plant
Capacity Served
MW
200
600
Initial
Coal Cost
(1983 MMBtu)
3.20
2.23
These costs include the expenditures required for development of infra-
structure at the Beluga Field. The cost of coal is substantially higher
than the $1.70 to $1.86/MMBtu cost associated with export market
production of 10 million tons per year because of the smaller size mine
development.
For the purposes of the planning analysis, it is assumed that up to 400
MW of coal-fired steam units would be located near the community of
Nenana. The plant would not be located at the Healy coal field because
of potential environmental impacts on the Denali National Park. A mine -
mouth price of $1.40/MMBtu in 1983 dollars is estimated for Nenana coal
based on current contracts with Golden Valley Electric Association and
Fairbanks Municipal Utility System, adjusted for changes in production
levels and new land reclamation regulations. Transportation costs to
Nenana are estimated to be $0.32/MMBtu ($5.00 per ton) in 1983 dollars.
Therefore, the total cost of the coal delivered in Nenana would be
200/174 4-19
$1.72/MMBtu. The coal has an average heat content of about 7800 Btu/lb.
Other .than this 400 MW unit installed at Nenana, it is assumed that all
other coal-fired units would be minemouth units installed at Beluga.
Agreements between coal suppliers and electric utilities for the
sale/purchase of coal are usually under long-term contracts which in-
clude a base price for the coal with an escalation clause. Several real
escalation rates have been estimated for the base price of utility coal
in Alaska and in the Lower 48, and they range from 2.0-2.7 percent per
year. The coal escalation rates used in this Update are identical to
those utilized in the July 11, 1983, FERC License Application. Those
rates include a 2.3 percent real increase in the minemouth price of
Nenana coal used for domestic purposes through 1993. A 1.6 percent per
year real escalation rate was assumed for Beluga coal through 1993 on
the assumption that coal from this field would follow the price of coal
in the Pacific Rim Market.
As in the July 1983 License Application filing, both Nenana and Beluga
coal prices are assumed in this Update to escalate until the date a
given generating unit enters operation. At that time, the coal price
for the unit is assumed to remain constant in real terms until the unit
is replaced. In the expansion plan studies, Beluga and Nenana coal
prices were escalated at their stated rates until 1993, the first year
of coal plant operation. In 1993 the cost from either source is
estimated to be $2.17/MMBtu (1983 $). For the remainder of the study
horizon (1993-2050), a coal price escalation rate of one percent per
year is used. This escalation rate is the result on the total coal
200/174 4--20
price forecast of the assumption that coal plants "lock -up" a supply of
coal at the time they enter operation. An examination of timing and
size of projected coal plant additions as produced by the GOP model
indicates that a straightline escalation rate of one percent from 1993
to 2020 would approximate this "lock -up" effect of the individual
plants.
While these escalation rates are an adequate basis upon which to esti-
mate future coal prices for purposes of determining the economic feasi-
bility of the Project, for the reason noted below, the Power Authority
intends to engage in further studies to refine these escalation rates
before commencement of the Susitna licensing hearings. To place these
further studies in perspective, it should be noted that a sensitivity
analysis of coal escalation rates indicates that coal escalation is not
a critical variable in the Project's economic feasibility. As addressed
in greater detail in Chapter 6, the Susitna Project is economically
viable even if a zero percent real coal escalation is assumed.
4.3.2 Coal -Fired Powerplants
There are several technologies potentially available for converting coal
into electricity. The most favorable of these alternatives is the steam
turbine system, which involves burning coal under a boiler to raise high
pressure steam. This steam is expanded in a high pressure turbine and,
in larger systems, exhausted from the turbine at an intermediate pres-
sure and temperature to be reheated in the boiler to 1005°F.
200/174 4-21
Technical and capital cost studies indicate that a 200 MW coal-fired
steam turbine is an appropriate size for an interconnected Railbelt
system. Further, the 200 MW size. is about the minimum size for using
the most energy efficient technologies. The coal steam turbine system
is reasonably efficient; with a fully loaded heat rate of 9,750 Btu/kWh,
representing a station thermal efficiency of 35 percent. Partial load
efficiencies are somewhat lower.
Capital, operational, and maintenance cost estimates for a coal plant
are summarized in Exhibit 4.3. The capital costs are from the July 1983
FERC License Application filing, updated to January 1983 price levels.
4.4 CHAKACHAMNA HYDROELECTRIC PROJECT DEVELOPMENT
a
Chakachamna Lake is located on the west side of Cook Inlet; about 85
miles west of Anchorage. The project as currently conceived would in-
volve diversion of water from Chakachamna Lake via a tunnel to a power -
plant on the McArthur River. A Power Authority report titled,
"Chakachamna Hydroelectric Project - Interim Feasibility Assessment
Report" dated March 1983, assesses the merits of developing the site's
power potential by diversion of water southeasterly to the McArthur
River via a tunnel about 10 miles long, or easterly down the Chakachatna
Valley either by a tunnel about 12 miles long or by a dam and tunnel
development.
200/174 4-22
The recommended scheme, designated Alternative E, includes a dam and
provisions for fish passage at the Chakachamna Lake outlet, an intake on
the lake and 10 miles of power tunnel to provide water to a powerplant
on the McArthur River. The project would have an installed capacity of
330 MW, average annual energy generation'of 1,590 GW and is estimated to
cost $1,438 billion in 1983 dollars. The project costs and power and
energy capabilities are shown on Exhibit 4.4. .
4.5 ENVIRONMENTAL CONSIDERATIONS OF ALTERNATIVES
The environmental and socioeconomic effects of thealternatives to
Susitna are substantial and extremely varied. Exhibit 4.5 presents a
summary of some of the environment -related characteristics of these
alternatives, as compared with the Susitna Project. Although most of
the environmental impacts associated with the alternatives can be
mitigated, the cost of such mitigation could affect the economic
viability of some plants at specific sites.
The purpose of this review is to ensure that the Susitna Project with
its attendant environmental impacts is compared with alternative
projects on equal bases, that is, that the environmental consequences of
Susitna alternatives are taken into account in any comparative economic
analysis.
200/174 4-23
This section reviews environmental concerns related to the following
Non-Susitna alternatives:
° Natural gas -fired facilities
° Coal-fired facilities
° Chakachamna Hydroelectric Project
4.5.1 Natural Gas -Fired Facilities
Cook Inlet fields are already developed. Proven and economically
recoverable reserves are expected to be depleted by the mid-1990's.
North Slope gas is not yet utilized and would likely require a major
pipeline to transport gas to areas of use.
In broad terms, -environmental and socioeconomic concerns with gas alter-
natives are related to four factors:
1. Development of gas fields and required infrastructure;
2. Gas pipeline from the gas field to the power plant;
3. Construction and operation of the power plant; and
4. Transmission lines from the power plant to load centers.
If Cook Inlet gas is utilized, a power plant would be located in the
Beluga Region., If North Slope gas is developed, a power plant could be
located in the North Slope, Fairbanks, or the Kenai region. Environ-
200/174 4-24
mental and socioeconomic concerns are discussed below for the four
possible plant locations! Beluga, Kenai, the North Slope, and
Fairbanks.
4.5.1.1 Beluga Region. Development of natural gas -fired facilities in
the Beluga Region would involve two 237 MW combined cycle power plants
and a 75-mile transmission line from Beluga to the Railbelt grid at
Willow. Depending upon plant location, additional support facilities
would include access roads, construction water supply, construction
plant, airstrip, marine landing facility, and a construction camp. The
natural gas would be supplied from the Beluga River, Lewis River and
Ivan River fields. Potential concerns include impacts on air resources,
water resources, aquatic communities, terrestrial communities, adjacent
Native communities, and aesthetics.
The power plant would emit significant quantities of carbon monoxide,
nitrogen oxides and water vapor and could degrade local air quality.
A supply of cooling water (200-400 gallons per minute) would be required
for plant operation. The source would likely be groundwater, since
surface supplies are minimal. The plant itself would likely discharge
minimal wastewater to the environment, and consequently have insignifi-
cant impacts to water quality and aquatic ecology. However, if water
injection were necessary to control nitrogen oxides emissions, the
required supply of water would double, creating the potential for ad-
verse impact on groundwater reserves.
200/174 4-25
Construction of the transmission line might impact water quality and
aquatic communities. Clearing of the right-of-way for the transmission
corridor and movement of construction equipment across watercourses
could increase sediment in these streams. The additional sediment in
the streams could delay hatching, reduce hatching success, preventing
swim -up, and resulting in weaker fry.
The major terrestrial impact would be loss and disturbance of natural
habitat in the vicinity of the power plant and along the 75-mile trans-
mission corridor. Habitat for moose, bear, small game, and trumpeter
swan would be affected.
The peak construction work force would be several hundred, while per-
manent operations personnel would number about 150. The largest village
in the area has a population of approximately 250. Consequently, an
impact on the local population and its lifestyle would be expected.
The power plant and transmission facilities would have adverse visual
impacts. Moderate noise would also result from facility operations.
4.5.1.2
Kenai Region.
Development of
natural
gas -fired
facilities in
the Kenai
Region
would
likely include
one or
several
combined cycle
power plants, a 94-mile transmission line from Kenai to Anchorage, and
associated facilities such as access roads, construction water and power
supply, and a marine landing facility. The facility would use natural
gas from the North Slope and would require development of the proposed
TAGS pipeline.
200/174 4-26
Environmental and socioeconomic impacts would be slightly less than
those discussed above for the Beluga Region. Air quality impacts would
be substantially the same. Water would be derived from ample ground-
water supplies. Water pollutants would not be discharged from the
plant, thereby preserving water quality and the aquatic ecosystem.
Salmon are present in many streams in the area. Clearing of the trans-
mission corridor and construction of the transmission line could in-
crease sediment in these streams and affect fisheries.
The transmission line crossing of Turnagain Arm would be by buried sub-
marine cables. Installation of the buried cables would temporarily
disrupt the sea floor and increase local turbidity.
Impacts of the power plant on terrestrial communities would not be as
significant as the Beluga location. The power plant would be located in
an area already experiencing development, thus the wildlife populations
are less, due to avoidance, therefore, little habitat degradation would
occur.
The transmission corridor would pass through various vegetation types
but mainly spruce woodlands. The corridor includes habitat for caribou
and moose but clearing of the vegetative cover should not affect these
animals. The power plant and transmission line would have some adverse
visual impacts.
200/174 4-27
Socioeconomic impacts in the Kenai would be less severe than those at
the Beluga location. There already is a relatively large population in
the area, which is not likely to be adversely affected by a large con-
struction work force. The creation of over 100 permanent jobs for oper-
ations may be considered a positive impact; however, the demand for
housing in the vicinity could possibly exceed supply.
4.5.1.3 North Slope. .Development of natural gas -fired facilities on
the North Slope probably would include a large simple cycle plant, a
360-mile electric transmission line from the North Slope to Fairbanks,
and an upgrading of the Fairbanks -Anchorage Intertie. Associated
facilities would include access roads, construction water supply, con-
struction transmission lines, and a construction camp.
The power plant would be located within the existing Prudhoe Bay indus-
trial complex and have moderate environmental and socioeconomic impacts.
The new transmission line from the North Slope to Fairbanks, on the
other hand, could entail significant impacts to water quality, aquatic
and terrestial communities and aesthetics.
Air quality in the vicinity of the power plant would be a concern, inas-
much as there are several gas -fired units already in operation on the
North Slope to support petroleum production. The plant would emit nit-
rogen oxides, which are normally controlled by water injection systems.
However, water injection systems cause undesirable levels of ice fog in
cold climates and are very costly in the Prudhoe Bay area because fresh
water is in short supply.
200/174 4-28
Water supply for other power plant uses (approximately 50 gallons per
minute) would be supplied from a freshwater lake through the existing
water treatment system in the Prudhoe Bay industrial complex.
Fishery resources could be affected by, construction and operation of a
Water supply intake, pipeline development (water or gas), access road
construction, and gravel mining (for construction materials) in rivers.
Construction of the power plant, switchyard, and camp would directly
disturb about 66 acres of land. Since the powerplant would be located
within the Prudhoe Bay industrial complex, the impact would be less than
if the area was undeveloped. Some caribou rangeland would be directly
affected.
The transmission line from the North Slope to Fairbanks and an upgrade
of the Intertie to Anchorage crosses hundreds of lakes and streams that
are used for fish migration, rearing, spawning and wintering. Clearing
of the right-of-way and movement of construction equipment could
increase sediment in these streams and lakes and adversely affect
fisheries.
The transmission line corridor would also pass through a wide variety of
terrestrial ecosystems and would be adjacent to several major federal
land areas which are protected, in part, for their wildlife values. The
transmission line would have to be routed to avoid peregrine falcon nest
sites. The routing would also have to avoid important Dal] sheep habi-
200/174 4-29
tat, caribou migration areas and bird migration routes.
Socioeconomic impacts of the power. plant would not be significant. The
additional labor requirements for construction of the power plant would
not appreciably affect the existing large, transient work force.
Socioeconomic impacts related to the construction and operation of
transmission facilities between Prudhoe Bay and Fairbanks would have to
be strictly controlled as the peak work force would exceed 2,300. The
line would be constructed within a designated utility corridor. Con-
struction workers'would be housed at pump stations or permanent camp
facilities constructed for the Trans -Alaska oil pipeline. Existing
facilities would be used where possible. Permanent facilities for
transmission line operation and maintenance would be consolidated at
several carefully selected locations.
The aesthetic impacts of the Prudhoe Bay to Fairbanks transmission line
would be significant. The lines would significantly degrade the pris-
tine nature of the wilderness landscapes.
4.5.1.4 Fairbanks. Development of natural gas fired facilities in the
Fairbanks area, using natural gas from the North Slope, would probably
include several combined cycle plants and an upgrading of the Anchorage -
Fairbanks Intertie. Since the Fairbanks area is already developed, only
minimal associated, facilities such as access roads and construction
facilities would be required. The 360-mile gas supply line would, how-
ever, constitute a significant impact on aquatic and terrestial com-
200/174 4-30
muni ties.
A major environmental concern would be impact on air quality in the
Fairbanks area. The power plant would emit nitrogen oxides. The use of
a water injection system to control emission of nitrogen oxides, would
worsen the ice fog problem and increase carbon monoxide emissions. The
area is presently subjected to extended periods of wintertime ice fogs.
The power plant would require about 200 gallons per minute for boiler
makeup water, potable supplies and other uses. Ample groundwater sup-
plies are available in the Fairbanks area.
The potential impact on aquatic ecosystems is significant. The pipeline
from Prudhoe Bay to Fairbanks would cross numerous streams that are used '
for fish migration, rearing, spawning, and wintering. Clearing of a
50-foot wide right-of-way, burying the pipeline, and other construction
activities could introduce additional sediment into the streams. The
additional sediment could delay hatching, reduce hatching success, pre-
vent upstream migration, and produce weaker fry. The construction of
additional electric transmission lines may have similar impacts on
watercourses along the Fairbanks to Anchorage corridor.
A power pl.ant in the Fairbanks area would not have significant ter-
restrial impacts as the area is already developed. However, there are
potential impacts associated with transmission and pipeline con-
struction. Long term terrestrial impacts would result primarily from
habitat elimination. Pipeline construction would require clearing of a
200/174 4-31
50-foot wide right-of-way. The pipeline compressor and metering
stations would require 100 to 150 acres of land. Assuming that two
additional transmission lines would be built and the Intertie extended,
about 8,700 acres would be cleared, of which 80 percent is forested.
Habitat for moose, caribou, grizzly and black bears, Dall sheep, and
migratory waterfowl could be significantly affected.
Socioeconomic impacts in the Fairbanks area would the insignificant
because of the existing large population base. There would be potential
socioeconomic impacts in the area between Fairbanks and the North Slope
associated with construction and operation of the gas pipeline and
transmission line. Temporary camps would be required along the corri-
dors. To minimize impacts to local villages, existing facilities would
be utilized and temporary camps would be located far from the com-
munities.
The power plant would not have significant visual impacts in the
Fairbanks area, as the area is already developed. However, the
transmission and pipeline corridors would have significant aesthetic
impacts on the pristine wilderness landscapes.
4.5.2 Coal -Fired Facilities
As discussed earlier in this Chapter, there are two potential locations
for development, of a coal-fired facility, the Beluga Region or the
Nenana Region. In broad terms, environmental and socioeconomic concerns
would be related to five factors:
200/174 4-32
1. Development of the coal mine;
2. Transportation and storage of coal;
3. Construction and operation of the power plant;
4. Construction and operation of the transmission line from
the power plant to the load center; and
5. Restoration of mined areas.
Development of coal would have significant environmental effects. For
instance, an open pit mine operation would occupy about 6,000 acres and
would consume habitat at a rate of 250 acres/year. Water quality could
be affected by runoff from the mine, coal pile and other construction
areas. Underground water supply and quality would be affected. Pit
blasting and dragline operations create significant noise, dust, and
aesthetic impacts.
The environmental and socioeconomic concerns of constructing and opera-
ting a coal-fired facility also depend on plant location. The two po-
tential plant locations are near the Beluga coal field and near the
Nenana coal field. The Nenana plant is assumed to be located near the
town of Nenana, rather than.Healy, due to Healy's proximity to Denali
National Park.
4.5.2.1 Beluga. Development of a coal-fired power plant in the Beluga
Region would probably involve the construction of several power plants
and a 75-mile transmission line from Beluga to the Railbelt grid. Asso-
ciated facilities would include access roads, construction water supply,
200/174 4-33
construction transmissions lines, airstrip, marine landing facility, and
construction camp. Surface coal mining would be a major activity.
Potential concerns include impacts to air quality, water resources,
noise, earth vibration, geologic stability, aquatic communities, ter-
restrial communities, socioeconomics, and aesthetics.
Coal, in contrast to natural. gas, is not a high quality fuel and can
generate unacceptable levels of air pollution in the absence of sophis-
ticated control equipment.• The determination of air pollution control
requirements must be made on a case -by -case basis taking into account
environmental, economic, and energy factors; however, it is quite cer-
tain that air pollution controls will significantly impact design, con-
struction, operation, and maintenance costs of a coal-fired power plant.
In areas of high terrain, such as found in most of Alaska, controlling
sulfur dioxide to the level necessary to meet the short-term Prevention
of Significant Deterioration (POS) standards may preclude construction
of economically viable facilities. Other pollutants which require anal-
ysis and control techniques include particulate matter, hydrocarbons,
nitrogen oxides, and a host of pollutants defined as hazardous under the
federal Clean Air Act.
The plant would require up to 4,000•gallons per minute of fresh water
for cooling, boiler makeup, and other uses. Potential sources include
the Beluga River or groundwater. Water withdrawals could impact local
water resources.
The plant would be designed to have a zero pollutant discharge configur-
200/174 4-34
ation and would not significantly affect water quality or aquatic eco-
systems. Construction of the transmission corridor and clearing of the
right-of-way could affect water quality and aquatic .communities as des-
cribed previously.
A major terrestrial impact would be loss and disturbance of natural
habitat in the vicinity of the power plant and along the 75-mile trans-
mission corridor. Habitat for moose, caribou, bear,�small game, and
trumpeter swan would be affected.
Socioeconomic impacts would be significant. The only village in the
area is Tyonek, with a population of about 250. Construction activities
could bring a peak work force of over 500 into the area. Operation of
the mine and power plant would require 100 to 200 permanent employees,
most of whom would probably live near the site in either a private hous-
ing development or permanent camp facilities. The large work force and
improved access to the area would have a significant impact on the local
population and its lifestyle.
The area is presently undeveloped. Development of the power plant and
attendant transmission facilities would have adverse aesthetic impacts.
4.5.2.2 Nenana. Development of a coal-fired facility in the Nenana
area would probably involve a 400 MW power plant and a 160-mile trans-
mission line from the plant to Willow. Associated facilities would
include access roads, construction water supply, construction trans-
mission line, airstrip, railroad spur, and construction camp. The power
200/174 4-35
plant would be located near the town of Nenana and receive coal via
railroad from the existing Usibelli Coal Mine at Healy. The Usibelli
Coal Mine currently produces coal from the Nenana field at a rate of
830,000 tons per year. The field furnishes coal to existing plants at
Healy, Fairbanks, University of Alaska, and several military installa-
tions. The mine would have to be expanded to supply coal to a new plant
at Nenana.
The concerns for the Nenana plant would be similar to those discussed'
previously for the Beluga area (Section 4.5.2.1). However, water with-
drawal considerations are not a significant issue at Nenana, since ade-
quate surface sources exist in the area. The air pollution concerns for
this siting area are substantially the same as at Beluga with the addi-
tional concern -that Denali National Park's status as a federal Class I
PSD area requires that this area be protected. Such protection could
involve additional control refinements for sulfur dioxide and particu-
late matter. Since the coal mine is already operating, impacts of
Nenana mine expansion could be less than those in an undeveloped field.
The Nenana site would be near Fairbanks and much of the labor force
would live in Fairbanks. Therefore, the socioeconomic effects would be
minimal. Aesthetic impacts 'would not be as severe as those in the
Beluga area but have the potential to affect more people.
4.5.3 Chakachamna _Hydroelectric Development
The Chakachamna Hydroelectric Development would include dam and fish
passage facilities at the Chakachamna Lake outlet, a lake tap, a 10-mile
200/174 4-36
long power tunnel, and a 330 MW power plant discharging to the McArthur
River. Associated facilities include a 115-mile transmission line from
the site to Anchorage and 40 miles of access. road. Potential concerns
include impacts to water resources, aquatic communities, terrestrial
communities and socioeconomic impacts on the Village of Tyonek.
4.5.3.1 Water Resources. The water resources of Chakachamna Lake,
Chakachatna River and McArthur River would be impacted. Construction
activities, such as clearing, excavating, spoiling, stockpiling of
materials, and movement of equipment, may increase erosion and sediment
in the streams and lakes. Streams along the 115-mile transmission cor-
ridor could also be affected, as described previously in this Section.
Water supply for construction would be pumped from the local streams.
During project operation, Chakachamna Lake would be affected by an
annual 72-ft water level fluctuation. The maximum reservoir level would
be at El. 1155, which is near the historical high lake level. The min-
imum reservoir level would be at El. 1083, about 45 feet below the his-
torical low lake level. This drawdown would expose lake shoreline and
stream deltas that are normally inundated. Additionally, at low lake
levels, the tributary mouths would be altered resulting in erosion and
sediment deposition in the lake.
The development would maintain some flow into the Chakachatna River.
The releases, however, would be significantly less than occur under
natural conditions. Under natural conditions, the mean annual flow is
3,645 cubic feet per second (cfs). With the development, the mean
200/174 4-37
annual flow would be 685 cfs.
The McArthur River would receive power plant discharges ranging from a
minimum of 4,600 cfs in July to a maximum of 7,500 cfs in December.
Current flows in the upper reaches of the McArthur River average about
600 cfs in July and 30 cfs in December. The increased flows on the
upper reaches of the McArthur River could cause significant overbank
flooding. The higher flows would initially erode the stream bed and
banks, and carry large quantities of sediment downstream. Release of
lake water into the McArthur River would also alter the chemical com-
position (water quality) of the river.
The ice -formation process on McArthur River would be affected by project
operations. Ice formation would be reduced or possibly eliminated by
the increased quantity of flow and the higher temperature of the water
originating in the lake.
4.5.3.2 Aquatic Communities. Construction and operation of the devel-
opment would greatly affect the aquatic habitat and associated fishery
resources.in the McArthur and Chakachatna Rivers, Lake Chakachamna and
lake tributaries, and the system of sloughs that connect the lower
reaches of the Chakachatna River and the McArthur River. Construction
activities probably would result in increased sedimentation in the lake
and the streams, which could adversely affect eggs and larval fish.
The operation of the reservoir would affect the fish rearing habitat
200/174 4-38
within the lake. During open water, juvenile sockeye, lake trout, round
whitefish, and Dolly Varden are found throughout the lake, with many
fish found offshore along steep drop-offs and just under the ice in
winter.
At high reservoir levels (during October and November) lakeshore areas
may be used as spawning habitat by lake trout and sockeye. After reser-
voir levels drop, incubating eggs and fry would be exposed to freezing
or dessication. Relatively immobile invertebrates which reproduce in
shoreline areas may also be affected.
The development would include a fish passage facility which is designed
to permit upstream migrants to ascend from the Chakachatna River to the
lake and allow downstream migrants to pass from the lake to the
Chakachatna River. Sockeye salmon and Dolly Varden are expected to use
this facility, as both have been observed to spawn above the lake.
Based on 1982 data, it is estimated that over 41,000 sockeye would need
to successfully pass through the facility to migrate upstream. Ten to
more than 100 times as many sockeye smolt and a smaller number of Dolly
Varden can be expected to migrate downstream.
The effectiveness' of the fish passage facility, however, cannot be
assured. If the facility did not successfully allow the migration of
sockeye both upstream as adults and downstream as juveniles, some part
of the estimated adult spawning population would be lost, as well as a
portion of their contribution to the Cook Inlet fishery.
200/174 4-39
The fisheries of the McArthur and Chakachatna Rivers would also be
affected, mainly from the changes in flow regimes. The water quality in
the McArthur River would be changed, possibly altering fish production.
Juvenile salmon imprint on the waters of their origin. As smolt they
out migrate to the ocean for the marine stage of their life cycle.
Returning adults seek out their natal waters on which to spawn. The
diversion of Lake Chakachamna water into the McArthur River may disrupt
the homing patterns of salmon, principally sockeye, returning to
tributary streams above Lake Chakachamna. If sockeye salmon were
attracted by Chakachamna waters into the McArthur River they would not
find adequate spawning habitat, and there would be no rearing habitat.
It is necessary to maintain the 41,000 fish escapement of sockeye into
Lake Chakachamna in order to assure the viability of this run.
4.5.3.3 Terrestrial Communities. Construction of the Chakachamna Proj-
ect would involve removal of vegetation over a relatively small area.
The fluctuation in lake levels and increased flow areas in the McArthur
River would affect terrestrial habitat that is used by moose in winter
and by waterfowl in spring, summer and fall. Development of disposal
areas in both the McArthur and Chakachatna flood plains would result in
the largest habitat loss, and greatest disturbance to birds and mammals.
Moose, ptarmigan, small mammals, and passerine birds could be affected.'
Clearing of the 115-mile transmission corridor and construction of a
40-mile access road would eliminate a large area of wildlife habitat.
Habitat for moose, bear, and small mammals could be affected.
200/174 4-40
4.5.3.4 Socioeconomic Factors. Socioeconomic impacts would likely be
significant. The development would be located in an undeveloped area,
near the Village of Tyonek. A construction work force of over 250 would
be required This influx .of construction personnel could impact the
social and economic structure of these communities. Additionally, the
improved access to the area could impact the communities. The Native
community of Tyonek may seek to maintain its remote condition in order
to maintain its Native cultural identity, and it may not welcome
persistent high levels of construction and operation work forces.
4.5.3.5 Aesthetic Factors. The potential aesthetic impacts of the
proposed Chakachamna Project are significant, particularly from a visual
standpoint. Potential fluctuations in Lake Chakachamna levels would
leave exposed lakeshore at certain periods. Significant reduction in,
outflows would result in the loss of much of the white water reach of
the Chakachatna River canyon, as well as noticeable alterations to the
floodplain. Disposal areas in McArthur valley would be noticeable, and
together with support facilities (roads, transmission line, etc.) will
result in degradation of the aesthetic character of wilderness land-
scapes.
200/174 4-41
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EXHIBIT 4.3
THERMAL PLANT OPERATING PARAMETERS AND COSTS (a)
Combined Combustion
Characteristics Coal-fired Cycle Turbine
Nameplate Capacity - MW 200 237 . 84
Heat Rate - Btu/kWh 9,750 8,280 11,650
Outage Rates, Percent of Time
Scheduled (Immature)
Scheduled (Mature)
Forced (Immature)
Forced (Mature)
Immature Period - yrs
Construction Period, yrs
Unit Construction Costs - $/kW
Unit Investment Cost (b) - $/kW
Operation and Maintenance Costs
Variable 0&M costs - mills/kWh
Fixed 0&M Costs - $/kW/yr
.Economic Life - Years
12.0
8.8
3.2
8.0
7.0
3.2
8.6
.10.0
8'0
5.7
8.0
8.0
3
2
1
5
2
1
2,175
604
500
2,370
625
510
0.6 1.69 4.90
17.00 7.25 2.70
30 30 20
(a) January 1983 price level
(b)'Includes interest during construction at 3.5 percent interest,
escalation not included.
CHAKACHAMNA HYDROELECTRIC PROJECT DATA(a)
Installed Capacity - MW
Total Capital Cost Including
Transmission (a) - $ million
IDC - $ million
Total Capital Cost - $ million ,
Total. Capital Cost - $/kW
Annual Operation and Maintenance Cost - $ million
Monthly Power and Energy Production:
330
1,307
131.
1,438 _
4,358 .
2.0
EXHIBIT 4.4
N
Minimum
Maximum
Average
Firm
Plant
Plant
Month
En y
_gy
Rating
Rating
GWh
GWh
MW
MW
i
January
133
133
177
179
February
114
114
168
170
March
113
113
150
153
April
98
98
135
137
May
94
92
124
231
June
96
86
120
330
July
138
88
118
330
August
228
92
124
330
September
179
98
136
330
October
126
115
155
275
November
128
128
177
179
December
144
144
193
195
Total
1,591
1,301
(a) Chakachamna Hydroelectric Project Interim Feasibility Assessment
Report, Bechtel Civil & Minerals, Inc., Alternative E, March 1983.
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5.0 SYSTEM EXPANSION PROGRAMS
5.1 INTRODUCTION
The objective of the system expansion studies is to develop long-term
power supply plans to meet the forecast Railbelt electrical demand,
using system configurations with and without the Susi-tna Hydroelectric
Project.
The system expansion studies are performed using the OGP computer
program and utilize a great deal of information relating to alternative
means of electric generation, including fuel prices for thermal alterna-
tives, developed in Chapter 4. The forecast of electrical demand is
generated from the MJSENSO/MAP/P.ED models sequence discussed in Chapter
2, using the NSD world oil price forecast developed by SHCA.
The OGP program uses economic planning criteria that are described in
detail in Chapter 6. The resultant analyses also provide annual and
present worth costs of alternative expansion plans. These results are
used in Chapter 6 to draw conclusions as to the economic benefit of the
Project using a life cycle cost approach.
In this Chapter, the existing Railbelt system is first described. Next,
system expansion from 1983 to 1992 is addressed. Since 1993 was pre-
sented in the FERC License Application as the earliest date that the
Susitna Project would be available for operation, the criteria for
201/174 5-1
system expansion after 1992 are discussed. The OGP computer model is
described briefly, followed by a discussion of alternative expansion
plans produced by the study.
5.2 THE EXISTING RAILBELT SYSTEMS
The two major load centers of the Railbelt region are the Anchorage -Cook
Inlet area and the Fairbanks -Tanana Valley area, which at present
operate independently. These two load centers will become the intercon-
nected Railbelt market when the Intertie, currently under construction
by the Power Authority, is completed. The Glennallen-Valdez load center
is not planned to be interconnected with the Railbelt nor to be served
by the Susitna Project.
The existing transmission system of the Anchorage -Cook Inlet area
extends north to Willow and consists of a network of 115-kV and 138-kV
lines with interconnection to Palmer. The Fairbanks -Tanana Valley
system extends south to Healy over a 138-0 .line. The Intertie which is
being built by the Power Authority to connect Willow and Healy will
operate initially at 138-kV. The transmission system is illustrated in
Exhibit 5.1. -
201/174 5-2
5.2.1 Anchorage -Cook Inlet Area
The Anchorage -Cook Inlet area has the following major electric utilities
and power producers:
° Municipal Utilities
-- Municipality of Anchorage -Municipal Light & Power
Department (AMLP)
-- Seward Electric System (SES)
Rural Electrification Cooperatives (REAs)
-- Chugach Electric Association, Inc. (CEA)
-- Homer Electric Association, Inc. (HEA)
-- Matanuska Electric Association, Inc. (MEA)
Federal Power Marketing Agency
-- Alaska Power Administration (APAd)
° Military Installations
-- Elmendorf Air Force Base
Fort Richardson
AMLP and CEA are the two principal utilities serving the Anchorage -Cook
Inlet area. All of these organizations, with the exception of MEA, have
electrical generating facilities. MEA buys its power from CEA. HEA and
SES have relatively small generating facilities that are used for
standby operation. They also purchase power from CEA.
The Anchorage -Cook Inlet area is almost entirely dependent on natural
gas to generate electricity. About 92 percent of the total capacity is
201/174 5-3
provided by gas -fired units. The remainder is provided by hydroelectric
units and oil -fired diesel units.
In 1982, the electricity generated by the Anchorage -Cook Inlet utilities
was 2,446 GWh, with a peak demand of about 472 MW. Between 1976 and
1982, the demand increased at an average annual growth rate of 7.1
percent, according to figures supplied by the utilities.
5.2.2 Fairbanks -Tanana Valley Area
The Fairbanks -Tanana Valley area is currently served by the following
utilities and power producers:
° Municipal Utility
-- Fairbanks Municipal Utilities System (FMUS)
Rural Electrification Cooperatives (REAs)
-- Golden Valley Electric Association, Inc. (GVEA)
° Military Installations
-- Eielson Air Force Base
-- Fort Greeley
-- Fort Wainwright
University of Alaska, Fairbanks
GVEA & FMUS own and operate generation, transmission, and distribution
facilities. The University and military bases maintain their own
generation and distribution facilities. Fort Wainwright is
201/174 5-4
interconnected with GVEA and FMUS and provides both utilities with
secondary energy. A large portion of the total installed capacity
consists of oil -fired combustion turbines (57 percent) and coal-fired
steam turbines (30 percent). The remaining capacity is provided by
diesel units.
In 1982, the total energy generation, including purchases, of the
Fairbanks utilities was 491 GWh, with a peak demand of 94 MW. The
growth in peak -demand in the past six years has averaged less than one
percent.
5.2.3 Total Present Svstem
Exhibit 5.2 summarizes the total generating capacity within the Railbelt
system in 1983. The total Railbelt installed capacity amounts to 1123
MW, excluding installations not available for public service at military
bases. The 11.23 MW consists of 1077 MW of thermal generation fired.by
oil, gas, or coal, plus 45 MW from the Eklutna and Cooper Lake hydro-
electric plants. Average and firm monthly energy estimates for the
Eklutna and Cooper Lake hydroelectric projects are shown on Exhibit 5.3,
5.3 GEN€RATION EXPANSION BEFORE 1993
The Power Authority has begun the construction of an Intertie connecting
the Anchorage and Fairbanks load centers with a single circuit
201/174 5-5
transmission line between Willow and Healy. The line, scheduled for
completion in 1984, will initially be energized at 138 kV, but can be
operated at 345 kV as loads grow in Anchorage and. Fairbanks. The
completion of the Intertie will improve the reliability of service for
both load centers and provide opportunities for economy exchanges of
energy.
Because of their advanced planning status, two proposed hydroelectric
plants are assumed to be added to the Railbelt system prior to 1993.
These are the Bradley Lake Hydroelectric Project, with 90 MW of generat—
ing capacity and 347 GWh of average annual energy, and the Grant Lake
Project, with 7 MW of generating capacity and 25 GWh of average annual
energy. The average and firm monthly energy estimates for the Bradley
Lake and Grant Lake projects are shown on Exhibit 5.3.
FMUS. is considering the addition of a 25-30 MW cogeneration unit to
replace Chena Units 1, 2 and 3, and Chugach Electric Association is
studying the feasibil"ity of a 34 MW combustion turbine at Bernice Lake
and an 80 MW combustion turbine at Beluga. Although plans for these
units appear to be moving forward, they have not been finalized and the
units are therefore not included in the Railbelt system for purposes of
the Update analysis.
201/174 5-6
5.4' FORMULATION OF EXPANSION PLANS AFTER 1993
Capacity expansion studies, such as those undertaken for the Susitna
Project, serve three major functions: (1) reliability (or reserve)
evaluation; (2) electricity production simulation; and, (3) capacity
expansion optimization. Expansion optimization analyses provide a
systematic means of evaluating the timing, type, and system costs of new
power facilities, thus permitting analysis of the relative costs of
different means of meeting an estimated electrical demand.
This Update uses the Optimized Generation Plan (OGP) model to develop
expansion plans for the Railbelt. The OGP model was also used in the
earlier feasibility studies and in the FERC License Application.
Exhibit SA outlines the procedure used by OGP to determine an optimum.
generation expansion plan. The OGP analysis conducted for this Update
assumes that the Railbelt utilities are fully interconnected, share
reserves, and optimize plant operation.
In developing an -optimal capacity expansion plan, the program considers
the existing and committed units (planned and under construction)
available to the system and the operating characteristics of these
units. The program then factors in given load forecast and system
operation criteria in determining the need for additional future capaci-
ty to attain the specified degree of reliability. The program quan-
tifies the amount and installation date of needed additional capacity as
load increases over time.
201/174 5-7
If additional capacity is needed, the program considers additions from
available alternatives and selects the available unit best fitting the
System's needs. Unit selection Is -made by computing production costs
for the system with each alternative unit included and comparing the
results. The unit providing the lowest system production costs is
selected and added to the system. The OGP modeling procedure contains
several key elements which are discussed below.
5.4.1 Reliability Evaluation
The Loss of Load Probability (LOLP) method is used in the OGP program to
determine when additional capacity is needed. The LOLP approach recog-
nizes that forced outages of .generating units would cause a deficiency
in the capacity available to meet the system load unless adequate
capacity had been installed. In developing an adequate reserve margin
for the Railbelt three LOLPs were studied, one day in ten years, one day
in five years and one day in three years. With LOLP of one day in five
years, the reserve margin would normally be in the range of 30 to 50
percent, which is considered appropriate for a system such as the
Railbelt, and is the reliability criteria used in the Update.
Exhibit 5.1 illustrates the reserve margin for the_ Non-Susitna and
With-Susitna expansion plans. A spinning reserve of 150 MW is included
within the reserve margin for all alternative expansion plans. Spinning
reserve is available thermal capacity which can quickly be brought into
full production to off -set any forced shut -down of operating units. The
costs associated with this spinning reserve are included in al.l plans.
201/174
- - 5-0
5.4.2 Hydro Schedulin
In the OGP simulation, the size and timing of hydroelectric units are
provided as input around which thermal units are added. For purposes of
the OGP runs done.for this Update, the Watana Development initially
operates on base load in order to maintain nearly uniform discharge from
the nnwernlant. When Devil Canyon begins operation, Watana. operates as
load -following while Devil Canyon operates an base load. The operating
made of the Watana Development will be subject to more detailed analysis
by the utiTities, environmental agencies, and the Power Authority as
planning proceeds.
5.4.3 Thermal Unit Commitment
After deducting hydroelectric plant output and thermal unit maintenance,
the remaining loads are served by the thermal units available to the
system. The units are added to the system to minimize operating costs,
which consist of fuel costs and variable Operating and Maintenance (0&M)
costs for each unit. Fixed 0&M costs do not affect the order in which
units are committed.
The unit operation logic determines how many units will be on-line each
hour and which units are selected, with the least expensive increment
being added first.
201/174 5-9
5.4.4 OGP Optimization Procedure
For each year under study, OGP evaluates system reliability to determine
the need for installing additional generating capacity. If the capacity
is sufficient to maintain the desired LOLP of one day in five years, the
program calculates the annual production and investment costs and pro-
ceeds to the next year.
If additional capacity is needed, OGP adds units from the list of
suitable additions until the gdven reliability level is met. Among the
Issues considered in determining suitability is the size of a potential
unit relative to the size of system load and cost. For a combination of
units the program calculates annual costs for a 10-year "look -ahead"
period and selects the most economical installation.
The OGP logic utilizes ah "overbuild" feature that develops annual costs
over a 10-year period for combinations of units to determine if addi-
tions of new units larger than those needed to meet reliability require-
ments would reduce system costs. If a generating unit is found to
reduce system costs, it is selected and the cost calculations for that
unit become part of the present worth of the expansion plan.
201/174 5-10
5.5 1993-2020 SYSTEM EXPANSION
5.5.1 Transmission System Expansion
Transmission system expansion for the With-Susitna expansion plan has
been studied in detail, and the costs have been estimated and included
as part of the Project.
Transmission system expansion costs associated with Non-Susitna expan-
sion plans are added as a separate item to those alternatives. To
simplify the transmission system analysis, $220 million in transmission
costs is assumed to be necessary for coal-fired and/or combined cycle
plants at Beluga, while $117 million is assumed to be required for a
coal-fired plant at Healy. These costs provide for new lines to the
existing transmission system and for increased capacity within the
present transmission system.
A preliminary review of the year -by -year transmission requirements for
several specific Non-Susitna alternative expansion programs indicates
that the cost estimates for the Non-Susitna transmission system are
reasonably in line with, but slightly lower than, detailed year -by -year
estimates.
5.5.2 Generation Expansion
Using OGP, alternative expansion programs were developed for the period
from January 1993 to December 2020 to establish the least -cost system
201/174 5-11
for that period with and without the Susitna Project. In the With-
Susitna case, it was assumed that Watana would start operation in 1993
and Devil Canyon in 2002. This assumption was placed as input into the
OGP model. All of the Susitna Project's energy would be absorbed in the
system by about the year 2020.
In the Non-Susitna alternative plans, coal-fired and gas -fired thermal
generation and the Chakachamna Hydroelectric Project are added to the
existing units. 'Four basic Non-Susitna alternatives were developed to
meet the forecast electrical demand. The plans are as follows:
Plan A includes natural gas -fired combined cycle plants,
coal-fired steam plants, and combustion turbines.
P1an.6 includes only natural gas -fired combined cycle plants
and combustion turbines.
Plan C includes coal=fired steam plants and natural gas -fired
combustion turbines.
Plan 0 includes the Chakachamna Hydroelectric Project, coal-
fired steam plants, natural gas -fired combined cycle and
combustion turbines..
For the four plans, proven and economically -recoverable, undiscovered
reserves of natural gas from Cook Inlet are assumed to be depleted by
about 2007. At that time higher -priced natural gas for generation of
201/174 5-12
electricity is considered to be available from undiscovered Cook Inlet
reserves or from the North Slope via ANGTS or TAGS, for reasons more
fully discussed in Chapter 4.
The total costs for the Non-Susitna alternatives include all costs of
fuel and the 0&M costs of the generating units. In addition, the
production cost includes the annualized investment costs of any plants
and transmission facilities added during the period.. Costs common to
all the alternatives, such as investment costs of facilities in service
prior to 1993, and administrative and customer services costs of the
utilities, are excluded.
The annual costs from 1993 through'2020 are developed by the OOP model
and are converted to a 1983 present worth. The long-term system costs
(2021-2050) are estimated from the 2020 annual costs, with adjustments
for fuel escalation, for the 30-year period. The With-Susitna and
Non-Susitna expansion plans are then compared on the basis of the sum of
present worths from 1993 to 2050.
As discussed more fully in Chapter 6, present worth analysis is a means
of comparing the value of benefits realized and costs incurred -over
different timeframes, discounted to the same base year. Such analyses
recognize the fact that, at any given point in time, money that must be
spent immediately has a "cost" greater than the same amount of money
that must be spent later, since the funds to meet the future commitment
can be -invested and earn interest until the time they must be spent.
201/174 5-13
5.6 REVIEW OF EXPANSION PLANS
5.6.1 With-Susitna Expansion Plan
Exhibit 5.6 shows the yearly additions for the With-Susitna expansion
plan. When Watana begins operation in 1993, it is assumed that all
Railbelt utilities will be interconnected and will share reserves. It
is further assumed that the Bradley Lake and Grant Lake hydroelectric
projects will be in operation by 1990, and scheduled retirements of
existing plants will be delayed so that sufficient reserve will be
available to meet the system demand prior to 1993. After 1993, a LQLP
of one day in five years is used. As shown in Exhibit 5.6, before Devil
Canyon starts operation, three combustion turbines will be required to
meet the reserve criteria. Ten years after Devil Canyon starts opera-
tion, additional combustion turbines and one combined cycle plant will
be required to replace retired units and to meet the load demand and.
reserve criteria.
Based upon recent analyses, indicating that 1996 might be a more realis-
tic date for commencement of full operation, an OGP analysis was done of
the expansion plan which would be necessary under those circumstances.
In that case, it is estimated that the reserve capacity prior to 1996
would become inadequate without additions of new capacity. To meet a
LQLP of one day in five years, five combustion turbines would need to be
added prior to 1996. The OGP program adds four combustion turbines in
1993, although in practical terms, these units would be added during the
period 1984-1993. Eleven years after Devil Canyon starts operation,
201/174 5-14
additional combustion turbines and one combined cycle plant would be
required to replace retired units and to meet the load demand and
reserve criteria.
5.6.2 Non-Susitna Expansion Plans
Exhibit 5.7 shows the four Non-Susitna alternative plans. As the OGP
program begins in 1993 with only the existing Railbelt capacity (plus
Bradley and Grant Lakes), its first action, in order to meet the pro-
jected load growth and maintain reliability criteria, is to add a large
amount of capacity in 1993. Exhibit 5.7 shows Plan A beginning with a
two -unit combined cycle plant in 1993. In a "real world" situation it
could be expected that these two combined cycle units or a combination
of three combustion turbines and one combined cycle would be added by
utilities over the 1984-1993 time period. After 2000, coal-fired plants
are added and additional combustion turbines are brought on-line in
Plan A to replace those added in earlier years. This Plan was developed
by the OGP process of comparing the economic advantages of various mixes
including combined cycle, combustion turbine and coal-fired alterna-
tives. The OGP program was also run with the forced addition of a
coal-fired plant in 1993 and no combined cycle plants (Plan C), and with
the use of only gas -fired generation (Plan B). Those expansion plans
were found to be less economical since they resulted in higher cumula-
tive present worths than Plan A for the period 1993-2050.
As can be seen in Exhibit 5.8, which presents a summary of the alterna-
tive expansion plans, Plans A and D are very close in having the lowest
201/174 5-16
1983 present worth costs, with Plan D being slightly less costly than
Plan A. However, the environmental impacts associated with the
Chakachamna Project suggest that Plan D is less likely of being imple-
mented as an alternative to Susitna than Plan A. The latter plan, which
relies upon both gas and coal units for future Railbelt generation is,
therefore, selected as the.least cost, practical Non-Susitna alternative
for comparison with the With-Susitna expansion plan.
Exhibits 5.9 and 5.10 compare the contribution of energy production
between the With-Susitna pl-an and Non-Susitna plan. As shown- by these
two exhibits, the Railbelt system will continue to be dominated by oil
and gas -fired generation over the next 10 years. By 1993 a very large
share of the gas and oil -fired generation can be replaced, if Susitna is
in operation. Otherwise, natural gas will continue to be the principal
source of fuel for the Railbelt through the end of this century. Beyond
year 2000, coal-fired generation becomes more significant in the
Non-Susitna plan. The economic conclusions which can be drawn from
these expansion plans are presented in the following chapter.
201/174 5-16
04 6c
LOCATION MAP
LEGEND
PROPOSED
DAM, SITES
PROPOSED IM KV LINE
EXISTING LINES
13B KV
69 KV
EXHIBIT
I W 0 wwm
KV
vJq
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- 138 KV
ILLOW
IISKV-
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APA, MEA, C5A,AMLF!
VALDEZ
AG/
-115YAA:A-
SES
138 KV
NX)
EXHIBIT 5.2
TOTAL GENERATING CAPACITY WITHIN THE RAILBELT SYSTEM
in Megawatts
Abbreviations
Railbelt Utility Installed Capacity (a)
AMLP
Anchorage Municipal Light
311.6
& Power Department
CEA
Chugach Electric Association
463,5
GVEA
Golden Valley Electric Association
221.6
FMUS
Fairbanks Municipal Utility System
68.5
MEA
Matanuska Electric Association
0.9
SES
Seward Electric System
5.5
APA
Alaska Power Administration
30.0
U of A
University of Alaska
18.6
TOTAL
1122.8 (b)
(a) Installed capacity as of 1982 at 0°F
(b) Excludes National Defense installed capacity of 101.3 MW
EXHIBIT 5.3
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LOAD GENERATION7F STUDY DATA
FORECAST - SYSTEM
HOURLY BASED EXISTING UNITS & FUTURE ECONOMICS &
PEAKS & ENERGIES ALLOWABLE OPERATING GUIDELINES
TECHNOLOGIES
OPTIMIZED GENERATION PLANNING (OGP)
I EVALUATE RELIABILITY I
EVALUATE SELECT UNIT SIZES & TYPES
ALL CHOICES
WITH 'LOOK -AHEAD' STUDY
CALCULATE OPERATING & INVESTMENT COSTS ALL YEARS
USING 'LOOK -AHEAD'
CHOOSE LOWEST COST ADDITIONS
& CALCULATE CURRENT YEAR'SCOSTS
RESULTANT OPTIMUM EXPANSION PATTERN OUTPUT
& DOCUMENTATION OF NEAR -OPTIMUM PLANS
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
OPTIMIZED GENERATION PLANNING (OGP)
lanuummm Ivirvnmik1IVIV rLVYYo
FEBRUARY 1984
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`` OTHER HYDRO
1980 2000 2020
YEAR
LEGEND
® OIL AND GAS -FIRED
COAL-FIRED
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
WITH - SUSITNA ALTERNATIVE - ENERGY
DEMAND & DELIVERIES
I FEBRUARY 1984
6.0 ECONOMIC FEASIBILITY
6.1 LNTRODUCTION
Based upon the preceding five chapters, this Chapter summarizes the
methodology and key variables used to analyze the economic feasibility
of the Susitna Project. The conclusions as to the economic feasibility
of the Project are then presented. Specifically, Section 6.2 contains a
discussion of the methodology used in the economic analysis. Section
6.3 contains the results of the economic analysis expressed in terms of
benefit -cost ratios and net benefits. The remaining two sections
contain information on the threshold and sensitivity analyses performed
to measure the impact on economic feasibility of changing key variables.
6.2 METHODOLOGY
The economic analysis compares the costs of alternatives during the
planning period 1993-2050. The year 1993 was presented in the FERC
License Application as the earliest date of Watana operation. Recent
analyses of the licensing and construction schedule, however indicate
that a 1996 date for Watana might be more appropriate for planning
purposes. The results of the analyses indicate that the difference in
the cumulative present cost worth of the project between a 1993 and 1996
Watana on-line date is approximately $5 million. This difference is
within the range of error of the modeling process and, therefore, no
202/169 6-1
disti-nction is drawn in the economic section of this Update between a
Watana on-line date of 1993 and 1996. As noted in Chapter 7, a 1996
date has been assumed for purposes of developing finance plans.
Exhibit 6.1 summarizes the principal economic parameters that were used
in the economic analysis. The economic life of each generating plant
type used in the economic analysis is based on 20 years for combustion
turbines, 30 years for combined cycle and steam turbines, and 50 years
for hydroelectric plants. Transmission lines have an economic life of
40 years.
The With-Susitna and Non-Susitna alternative expansion plans discussed
in detail in Chapter 5 are utilized here to assess the economic benefits
of the Susitna Project. Benefits are based on the difference between
the costs of the least -cost Non-Susitna alternative and the With-Susitna
alternative ("net benefits"). For the Susitna Project to be considered
economically feasible, the benefit/cost ratio of the With-Susitna
alternative over the Won-Susitna alternative must be greater than one.
The-Benefit/Cost (B/C) ratio is determined using the following formula:
Total Present Worth of System Expansion
B / C = Plan Without Susitna (benefits)
Total Present Worth of System Expansion
Plan With Susitna (costs)
Costs for each expansion alternative include three main items: invest-
ment, fuel, and 0&M costs. Investment costs include construction costs
(described in Chapter 3), and interest on funds used during construc-
tion. A real interest rate (adjusted for inflation) of 3.5 percent was
202/169 6-2
used in estimating interest during construction. Fuel costs are for the
coal or gas used yearly in the thermal plants (as described in Chapter
4). 0&h1 costs also are expended each year.
To determine the benefit/cost ratio and net benefits, all costs (or
benefits) must be adjusted to a comparable present worth. Costs are
adjusted to their present worth by discounting, which gives costs in
earlier years more weight than costs in later years. PThis concept is
based on the theory that money, until it is needed to pay costs, can be
invested profitably.
The 3.5 percent discount rate used in this economic analysis was provid-
ed by a survey of financial experts and economists. The total present
worth of each expansion plan was obtained by calculating the present
worths of each future annual cost. It is important to note that costs
are being evaluated; hence, the alternative having the lowest present
worth is the most economically attractive.
202/169 6-3
6.3 RESULTS OF THE ECONOMIC ANALYSIS
The results of the economic analysis of alternate system expansions are
presented in Exhibit 6.1 and summarized in Table 6.1. As reflected in
Table 6.1, the total present worth of the With-Susitna expansion plan is
$5.73 billion for the period 1993 to 2050. The total present worth of
the Non-Susitna system expansion plan is $6.79 billion for the same
period. Thus, the With-Susitna expansion plan has a' net benefit of
$1.06 billion and a benefit/cost ratio of 1.19.
Table 6.1
RESULTS OF ECONOMIC ANALYSIS
(1983 $ billion)
With-Susitna Non-Susitna
Expansion Plan Expansion Plan
Total Present Worth 5.73 6.79
Net Benefits 1.06 N/A
Benefit/Cost Ratio 1.19 N/A
(N/A indicates not applicable)
As shown on Exhibit 6.2, the annual costs of the With-Susitna plan are
less than the annual costs of the Non-Susitna plan after -year 2003.
That year represents the "cross -over" point from which time the With-
Susitna plan's annual costs drop below those of the Non-Susitna plan.
Thus, in year 2020, the With-Susitna annual costs are about $162 million
(1983 $) less than the Non-Susitna costs. The total cumulative present
worth of the With-Susitna plan is less than the Non-Susitna plan after
year 2010.
202/169 6-4
With the potential design refinements described in Chapter 3, the
construction costs of the Susitna Project could be reduced by about 8
percent. These construction cost savings would reduce the total present
worth costs of the With-Susitna alternative by about six percent, and
the net benefits would increase from $1.06 billion to about
$1.36 billion if such design refinements are ultimately implemented.
6.4 THRESHOLD VALUES OF SUSITNA JUSTIFICATION
A threshold value is that value of a parameter at which the total
present worth of the With-Susitna expansion plan is equal to that of a
Non-Susitna plan. That is, the benefit/cost ratio is equal to one and
there are zero net benefits. Under such circumstances the Susitna
Project could not be deemed to be more economically feasible than a
Non-Susitna alternative, although there might be other reasons justify-
ing its construction. A threshold value was computed for the following
four key parameters:
• Oil Price Forecasts
° Discount Rate
° Construction Cost Estimate for Watana Development
• Real Interest During Construction
6.4.1 World Oil Price Foreca
World oil price forecasts greatly influence the economics of the With-
Susitna alternative; therefore it is necessary to identify the threshold
202/169 6-5
value of forecast oil prices. The threshold forecast oil price is very
near the mean oil price forecast by DOR in June, 1983. As noted previ-
ously, DOR has substantially raised its oil price forecasts since that
time and use of this approximation of a threshold case is not intended
to tie DOR to outdated forecasts; it is used because it approximates a
threshold oil price only.
It is important to recognize that the threshold oil price forecast is a
price line rather than a single value, and the line does not have a
constant rate of change. The critical oil price is, however, $27.45 per
barrel (in 1983 $) in 1999. This price was assumed to escalate at 1.5
percent for the years beyond 1999. Should all reliable oil price
forecasts drop to this level, serious questions might be raised as to
the economic viability of the Project.
6.4.2 Discount Rate
The discount rate at which the present worth of the With-Susitna expan-
sion plan becomes equal, to that of the least -cost Non-Susitna expansion
plan is 5.3 percent. That is, should the non -inflationary value of
money be greater than 5.3 percent, there might be no economic advantage
to the With-Susitna expansion plan.
6.4.3 Construction Cost Estimate for Watana Development
The estimated construction cost of the Watana Development is
$3.75 billion (January 1983 prices). The threshold value for Watana
202/169 6-6
construction cost, using a 3.5 percent discount rate, is $5.0 billion.
Hence, if the construction cost of the Watana Development were to
increase by 33 percent, the cumulative present worths of the With-
Susitna and Non-Susitna expansion plans would be equal.
6.4.4 Real Interest During Construction
A real (adjusted for inflation) interest rate of 3.5 percent was used to
calculate interest during construction- in the economic analysis. The
threshold value for real interest was estimated to be 7.4 percent. That
is, the real interest rate for Watana construction funds would have to
increase to 7.4 percent in order for the With-Susitna present worth to
be equal to the Non-Susitna alternative's present worth costs.
6.5 SENSITIVITY ANALYSI-S
Economic analyses require numerous assumptions. Typically, a single
value (i.e., a best estimate) for a key parameter is used in the compu-
tations, yet that single value lies within a range of possibilities. To
evaluate the effects on project economics of such a selection, economic
analyses are often performed using a range of possible values for each
of several key parameters. This analysis is termed "sensitivity analy-
sis," as its objective is to determine the sensitivity of the results of
economic analyses to assumed changes in one or more key variables.
Sensitivity analyses were performed in preparing this Update for Cook
202/169 6-7
Inlet gas supplies, real escalation rates of fuel costs and utilities'
demand forecasts.
6.5.1 Cook Inlet Gas Supply
As explained in Chapter 4, the ONR forecast of Cook Inlet gas supply was
used in the economic analysis, However, if an unlimited supply of Cook
Inlet gas is assumed and it is further assumed that' its price will
follow world oil prices, the cumulative present worth of Non-Susitna
Plan A would decrease from $6791 to $6510 million. The resulting bene-
fit/cost ratio of the With-Susitna plan would decrease from 1.19 to
1.14. Hence, the exact estimate of undiscovered Cook Inlet reserves
does not materi.ally effect the economic analysis.
6.5.2 Real Escalation of fuel Costs
The sensitivity of the Non-Susitna expansion plan to coal price esca-
lation was analyzed using the January 1983 coal prices of $1.8fi per
MMBtu for Beluga and $1.72 per MMBtu for Nenana. A scenario of zero
escalation on the price of coal for the entire planning period of 1983
through 2050 was analyzed, and the results are presented in Table 6.2.
As indicated there, the With-Susitna plan still has a positive bene-
fit/cost ratio.
202/169 6-8
Table 6.2
SENSITIVITY ANALYSIS USING
ZERO PERCENT COAL ESCALATION
(1983 $ x billion)
With-Susitna Non-Susitna
Expansion Plan ELansion_Plan
Total Present Worth 6.73 5.84
Net Benefits 0.11 --
Benefit-Cost Ratio 1.02 --
The Susitna Project would supply about 80 percent of the Railbelt areas
electricity requirements by the year 2020. Therefore, long-term fore-
casts of fuel prices and escalation rates critically influence Project
economics. A special analysis of long-term oil prices was prepared by
SHCA during the preparation of the License Application to support the
estimation of long-term system costs (2021 - 2050). A real annual
escalation rate of 1.5 percent was estimated for the period 2021 through
2030 and 1.0 percent for the period 2030 - 2050. Escalation of the
natural gas price was assumed to follow that of oil.
A sensitivity analysis was conducted to compare the net benefits of the
With-Susitna expansion plan against the least -cost Non-Susitna expansion
plan with no allowance for real escalation of fuel costs after 2020.
The results of that analysis are summarized in Table 6.3.
202/169 6-9
Table 6.3
SENSITIVITY ANALYSIS OF
REAL ESCALATION OF FUEL COSTS BEYOND 2020
Present Worth of
System
Costs
(1983 - $
billion)
Wit Fuel
Without Fuel
Escalation
Escalation
System 1993-
2021- 1993- Net
2021-
1993- Net
Expansion 2020
2050 2050 Benefit
2050
2050 Benefit
Non-Susitna 3.87
2.91 6.79 -
2.72
6.59 -
With- 3.65 2.07 5.73 1.06 1.�99 5.65 .94
Susitna
As indicated, without fuel escalation, the net benefits of the With-
Susitna plan would decrease from $1.06 billion to $940 million.
6.5.3 Utilities' Forecast
The Railbelt utilities annually produce 20 year forecasts for their
respective .markets. As shown on Exhibit 2.22, the forecasts indicate
that energy generation is expected to increase from 3105 GWh in 1983 to
7662 GWh in 2001. For purposes of a sensitivity analysis, the utili-
ties' forecasts were extended to 2020 using the same annual rate of
electrical demand increase after 2001 as obtained from the Power Author-
ity forecast. All other parameters were kept constant to those used in
the Power Authority analysis. Table 6.4 presents the results of the
economic analysis using the utilities' forecasts.
The OGP analysis of the systems necessary to meet the utilities' fore-
cast demand shows that construction of Susitna would replace a signifi-
cant amount of thermal generation capacity. Under the Non-Susitna
202/169 6-10
expansion plan, two combined cycle plants (237 MW each) are constructed
in 1993. Gas turbines are then added until 1998. After year 2000 a
total of 10 coal-fired plants are constructed. With Susitna, the
combined cycle plants are delayed (until 1995 and 2000) with only three
coal-fired plants installed between 2012 and 2017. Calculating the
cumulative present worth costs of the expansion plans indicates that the
With-Susitna expansion plan would have a net benefit of $2.96 billion
assuming load growth as predicted by the utilities. That figure is
$1.90 billion greater than that for th€ With-Susitna expansion plan
using the Power. Authority estimate of electrical demand. The Susitna
benefit -cost ratio using the utilities forecast would increase to 1.45.
Table 6.4
ECONOMIC ANALYSIS USING UTILITIES' FORECAST
(1983 $ x billion)
With-Susitna Non-Susitna
Expansion Plan Expansion Plan
Present Worth of
Annual Costs 6.57 9.54
Net Benefits 2.96 -
Benefit/Cost Ratio 1.45 -
The conclusion which can be drawn from this analysis is that if elec-
trical demand is greater than the forecast produced by the models used
in this Update, .the economic benefits of the Susitna Project increase
202/169 6-11
accordingly. Conversely, if electrical demand is lower than the Update
forecast, a reevaluation would be necessary as to the appropriate timing
of the Watana Development.
6.6 CONCLUSIONS
Although stated in various terms throughout this Chapter, the conclusion
of the OGP analysis of Railbelt expansion plans, comparing the With-
Susitna plan (which includes some thermal generation) against Non-
Susitna alternative plans (which includes minor amounts of hydroelectric
power), is that the Susitna Project would have a positive benefit/cost .
ratio (a ratio greater than 1.0) over the planning period of 1993-2050.
Stated simply, using the most current data, it is the conclusion of this
Update that the Project remains economically viable.
202/169 6-12
1
2
3
4
5
6
h
EXHIBIT 6.1
PRINCIPAL ECONOMIC PARAMETERS
All Costs in January 1983 Dollars
Base Year for Present Worth Analysis: 1983
Electrical Load Forecast: 1983 to 2020
Discount Rate: 3.5 percent
Inflation Rate: 0 percent
Economic Life of Projects:
Combustion Turbines: 20 years
Combined Cycle Turbines: 30 years
Steam Turbines 30 years .
Hydroelectric Projects 50 years
Transmission Lines 40 years
Annual Fixed Carrying Charges
20-year 30-year 40-year 50-year
Life Life Life Life
Cost of Money 3.50
3.50
3.50
3.50
Amortization 3.54
1.94
1.18
0.70
Insurance 0.25
0.25
0.25
0.10
Total 7.29
5.69
4.93
4.36
0
EXHIBIT 6.2
RESULTS OF THE ECONOMIC ANALYSIS
OF SYSTEM EXPANSION PLANS
(1983 $ million)
Annual
Cost
Cumulative
Present Worth
YEAR
Non-Susitna
With-Susitna
Non-Susitna
With-Susitna
1993
156.0
215.0
110.6
152.4
1994
165.3
216.9
223.8
300.9
1995
172.1
221.7
337.7
447.6
1996
184.7
228.7
455.8
593.9
1997'
194.6
233.5
576.0
738.1
1998
201.5
237.3
696.3
879.8
1999
208.7
243.6
816.7
1020.2
2000
229.3
248.1
944.4
1158.5
2001
237.3
252.9
1072.2
1294.6
2002
261.5
267.7
1208.2
1433.8
2003
267.1
267.7
1342.4
1568.4
2004
275.5
267.7
1476.2
1698.3
2005
282.8
267.3
1608.9
1823.7
2006
314.2
265.3
1751.3
1944.0
2007
351.9
265.3
1905.4
2060.2
2008
368.8
265.3
2061.4
2172.4
2009
377.1 _
268.1
2215.6
2382.1
2010
387.7
265.3
2368.7
2386.9
2011
406.3
267.4
2523.8
2488.9
2012
415.7
277.7
2677.0
2591.3
2013
425.8
281.9
2828.7
2691.8
2014
437.4
298.9
2979.3-
2794.6
2015
455.9
304.0
3130.9
2895.8
2016
464.7
322.4
3280.2
2999.3
2017
479.0
328.8
3429.0
3101.4
2018
492.0
332.2
3576.5
3201.1
2019
512.1
346.1
3725.0
3301.4
2020
529.2
367.3
3873.1
3404.3
2050
619.4
420.0
6790.7
5730.1
7.0 FINANCING OPTIONS
7.1 INTRODUCTION
The purpose of this Chapter is to explore the relative merits of various
funding sources and develop financing options for the Susitna Project.
Implementing financing options for the Project will require certain
policy decisions and commitments by Alaska decision -makers, including
the Legislature. One purpose of this assessment, therefore, is to bring
these necessary decisions to the attention of the Legislative and
Executive branches of the State of Alaska.
Based upon continuing review and analysis conducted by the Power Author-
ity since the filing of the July 11, 1983 FERC License Application,
several potential. funding sources have been identified. In this Chap-
ter, these funding sources are reviewed on the basis of legal, practical
and cost of energy considerations. The legal review examines the
existing requirements, apparent constraints and legislative action that
should be taken into account to utilize each of these sources. The
practical considerations address the marketability and similar factors
associated with each source. The cost of energy analysis is utilized to
determine the size and mix of the proposed funding sources in order to
give assurance that the projected wholesale cost of Susitna energy under
the selected financing options is competitive with the cost of energy
from the least -cost thermal alternative in the first years of operation.
161/169 7-1
After a review of the above considerations., two financing options are
selected for detailed analysis as the most feasible approaches to the
financing of the Project. These options are:
Option A: Tax -Exempt Revenue Bonds combined with State Equity and Rate
Stabilization Fund.
Option B: REA Guaranteed Loan and Tax -Exempt Bonds (50/50) combined with
State Equity and Rate Stabilization Fund. .
During the past several months the Power Authority has been conducting
extensive negotiations with the intended purchasers of power to be
generated by the "Four Dam Pool" which is comprised of the following
hydroelectric projects in various stages of completion: (1) Lake Tyee
near Petersburg and Wrangell, (2) Solomon Gulch near Valdez, (3) Swan
Lake near Ketchikan, and (4) Terror Lake near 'Kodiak. These negotia-
tions and related hearings on necessary legislative changes are in
process as the first maturity date of interim construction notes becomes
imminent. It should be noted that the State's ability to deal with the
Four Dam Pool situation will largely determine investor willingness to
participate in the Susitna bond financing program. Future investors
will respond favorably to a coordinated response by the Power Authority,
the utilities and the Legislature to the need to refund the short-term
indebtedness for the Four Dam Pool. By the same token, potential
Susitna bond purchasers will long remember any failure by these Alaskan
entities to solve the problem and avoid delays in retiring the short-
term notes.
161/169 7-2
7.2 GENERAL APPROACH AND PROCEDURES
A fundamental assumption in the.analysis of Susitna financing options is
that the wholesale cost of energy from the Project must be competitive
with the wholesale cost of energy from the least -cost Nan-Susitna
Alternative in the first years of operation. Generally, the Railbelt
utilities are not expected to enter into contracts to purchase Susitna
generated power if the rates are significantly higher than the rate that
would be available from alternative generation sources. Therefore, each
of the options examined below is constrained to give assurance that the
wholesale cost of Susitna energy is competitive with the least -cost
thermal alternative during its first years of operation.
Because of the projected long-term benefits of the Susitna Project, it
has been suggested that the Railbelt utilities might be willing to pay a
premium price for Susitna energy over a short period of time. While no
definitive analysis has been made, the hypothesis of the "willingness to
pay" of the Railbelt utilities suggests that Susitna energy might con-
ceivably be priced at a wholesale rate as much as 20 percent greater
than the least -cost thermal alternative during the early years of
operation and still be marketable in the Railbelt. It is estimated that
the resulting retail cost of energy would be approximately 10 percent
greater, after considering costs of distribution, administration, trans-
mission and other costs. Therefore, a sensitivity analysis was run for
both of the financing options examined herein to allow wholesale Susitna
costs to be 20 percent greater than the thermal alternative cost during
the first years of Susitna operation. Should such premium rates be
16.1/169 7-3
agreed upon with the utilities, it would allow a significant reduction
in the necessary amount of State assistance (see Table 7.5)..
Before the allowable wholesale cost of Susitna energy can be determined,
it is first necessary to develop, the cost of energy for the least -cost
thermal alternative. The cost of energy of various thermal alternatives
was computed from Optimum Generation Planning ("OGP") output summaries.
The least -cost thermal generation- scenario described in Chapter 5
results in an average cost of energy in the Railbelt of 11.2¢ per kWh in
the first year of operation of Watana (1996). This figure assumes that
the thermal alternatives would be financed by the individual utilities
using 75 percent REA loans and 25 percent tax-exempt revenue bonds on
the assumption that the State will not provide equity funding or loan
subsidies for thermal generation alternatives.
7.3 POTENTIAL FUNDING SOURCES
There are several different sources of funds potentially available to
finance the Susitna Project. Because of the large size of the financing
requirements of Susitna, however, one source may not be able to provide
all necessary funding. The financing options presented in Section 7.5,
therefore, draw on several funding sources. This Section discusses in
general terms the types of funding sources potentially available to
Susitna.
161/169 7-4
7.3.1 State Equity Contributions
The State Legislature could appropriate money from the State's General
Fund to be utilized in the construction of the Susitna Project. The
appropriation could take the form of a direct grant or a loan to the
Power Authority or some combination of the foregoing. All financing
options which have seemed feasible or possibly feasible over the course
of the on -going review of Susitna have involved large levels of State
assistance. It is clear that Susitna will have to be one of the State's
highest capital funding priorities in order to achieve the required
equity contribution.
Precise estimates of the required amount of State funds vary among the
financing options analyzed. A continuing commitment to provide State
funds in the form of grants or loans over a period of several years to
the Susitna Project would be required. A legal constraint in making
this commitment is Section 7, Article IX, of the Alaska Constitution,
which prohibits one Legislature from making binding commitments on
future Legislatures through a prohibition against dedicating funds.
Thus, although State monies might be provided by one Legislature, there
is no assurance that continued funding would be approved by subsequent
Legislatures. This lack of legislative authority to make long-term
commitment of grants or loans would impose considerable financial risk
on the Project, a risk which would probably be perceived by other
potential investors as too great, thus rendering necessary non -State
funding more expensive, if not impossible.
161/169 7-5
A means of reducing the investor's risk and establishing long-term State
funding for the Susitna Project would be the proposed Major Projects
Fund. As proposed, this fund would operate in a manner similar to the
current Permanent Fund.An amendment to the Alaska Constitution would
provide for setting aside 10 percent of the State's mineral revenues
into a special account which would be available for energy development
projects in the State. In broad philosophical terms, it would be the
goal of this fund to.utilize a portion of the State's wealth derived
from non-renewable energy sources to fund energy projects (either
through equity contributions, rate stabilization. funds or both) which
utilize renewable energy, such as hydroelectric, geothermal,.and solar
projects. Grants or loans from the Major Projects Fund to construct the
Susitna Project would be consistent with this stated philosophical goal.
One advantage of this approach is that it would provide non -State
investors in the Susitna Project with assurance that, to the extent of
available pledged resources ("a dedicated revenue source"), the State
would fulfill its funding obligations to the Project, thus eliminating
the fear that future Legislatures would not authorize sufficient funds.
Exhibit 7.6 indicates the portion of this special account which would be
required for Susitna under both financing options analyzed.
7.3.P Alaska Permanent Fund
Another possible financing option is the utilization of the investment
capacity of the Alaska Permanent Fund, which was created by a 1976
amendment to the State Constitution. It is a separate fund composed of
the revenues from at least 25 percent of all annual mineral .lease ren-
161/169 7-6
tals, royalties, royalty sale proceeds and federal mineral payments
received by the State, plus earnings on these payments. An Alaska
Permanent Fund Corporation was established in 1980 to provide a means of
conserving this portion of the State's revenues, derived from mineral
resources, to benefit future generations of Alaskans. The Corporation
is a public corporation organized within the Department of Revenue whose
primary purpose is to manage and invest the Permanent Fund assets. A
Board of Trustees appointed by the Governor has the responsibility of.
ensuring that judgment and care are applied in investment of these
assets, considering the "probable safety of capital as well as probable
income." The statutory obligations for management and investment of the
Fund's assets are specific, as are the types of investments and the
designated percentage of the Permanent Fund which may be invested in
each type of investment.
The Permanent Fund has been suggested by some as a potential source of
financing for the construction of the Susitna Project, either as a
source of loans through purchase of bonds or as a means of guaranteeing
other forms of financing with the view that the construction of the
Susitna Project is a means of preserving the State's mineral resource
base. If Susitna is not constructed, natural gas, diesel fuel and other
fossil fuels will probably be used for generation which otherwise would
have been provided by Susitna to meet electric power demand within the
State. In this context, use of the Permanent Fund as a financing source
for Susitna could be viewed as consistent with the purpose of the Fund,
i.e., "conservation of the State's revenues from mineral resources to
benefit generations of Alaskans."
161/169 7-7
Pursuant to Articles IX and XV of Alaska's Constitution, the Permanent
Fund's principal may be used only for "income -providing investments
specifically designated by law. The. assets may thus presently be
invested only in specific types of government securities, corporate
stocks and bonds and real estate, all at market rates. Investment in
below -market yield or no -income investments with Fund assets (even
though long-term benefits could be argued) would probably require a
Constitutional amendment in light of the conservative view typically
given to the types of permissible investments in such a Fund. Further
consideration of this funding source has not been given because:
(1) for this source to be competitive with Option A for the financing of
Watana, an interest rate of approximately 10 percent per annum would be
required assuming the same approximate level of State,equity; current
yields available to the Permanent Fund are approximately 3 percent.per
annum greater for similar maturities and credit risks inasmuch as the
Permanent Fund has no incentive to acquire tax-exempt debt instruments,
and (2) in order to fully fund the financing of Watana by loans from the
Permanent Fund (without any State equity), an interest rate of approxi-
mately 3 percent per annum would be required, which is approximately
10 percent per annum below yields otherwise available to the Permanent
Fund.
7.3.3 Rate Stabilization Fund
Although not a form of financing in and of itself, a Rate Stabilization
Fund (RSF) is a means of allowing other sources of financing for Susitna
to be used more effectively by holding down energy costs during
161/169 7-8
Susitna's early years of operation when it is most difficult for hydro
costs to be competitive with thermal alternatives. A RSF could be
funded by either the issuance of additional bonds, by State appropria-
tions, or from a dedicated revenue source such as the proposed Major
Projects Fund. Bond proceeds are commonly used for this purpose, often
in the form of capitalized interest. The RSF concept was developed by
the Power Authority for the Four Dam Pool financing plan.
The RSF is a. rate subsidy during the early years of operation. The cost
of energy from the Susitna Project, based on a given financing plan,
would be offset by transfers made to the accounts of the Railbelt
utilities by the bond Trustee. This would result in a projected net
cost of Susitna energy equivalent to the projected Nan-Susitna Alterna-
tive in the early years. The cost of Susitna energy after the RSF
period would be expected to be less than the least -cost thermal energy
alternative during Susitna's latter years of operation, because of the
high level of fixed costs associated with hydro.
Because the RSF provides State assistance in. the time period most
needed, it reduces the level of permanent commitment of State funds
required in the form of equity. The RSF concept is included in the base.
case of each financing option.
As in the equity contribution approach, the RSF could present problems
of continuity. Although one Legislature may agree to an RSF program,
there is no assurance that subsequent Legislatures would provide further
appropriations to an RSF which would be necessary over a period of years
161/169 7-9
if the initial appropriation was not adequate. For purposes of analysis
of the financing options, it is assumed that RSF funds would be provided
as needed by a dedicated revenue source not subject to Legislative
approval. A sensitivity analysis was made assuming that the under-
writing standards of any debt market would require that the full amount
of rate stabilization funds needed over a period of years be provided
"up front" before the bonds could be sold.
7.3.4 Tax -Exempt Debt
Public power projects are commonly financed with tax-exempt debt. This
type of debt can be an obligation of a state, or political subdivision
of a state, the interest on which is generally exempt from Federal
income taxes. This tax exemption enables states and their political
subdivisions to issue debt at lower interest rates than would otherwise
be the case. For example, long-term municipal bonds for public power
projects were marketed in January 1984 at interest rates of 10 percent
to 10.5 percent, whereas taxable corporate bonds of the same maturity
and credit rating were being sold at interest rates of approximately
13 percent to 13.5 percent.
Public power projects are -generally financed on a tax-exempt basis with
revenue bonds, as distinguished from general obligation ("G.O.") bonds.
In the case of the Susitna Project, revenue bond financing would mean
that the first and primary source of payment for the principal and
interest on those bonds would be the revenues derived from the Susitna
Project itself. G.O. bonds, on the other hand, are backed by the full
161/169 7-10
faith and Credit, including the taxing power, of the issuing govern-
mental entity. Revenue bonds have two principal advantages over G.O.
bonds; one being fewer procedural steps prior to'bond issuance, and the
other that revenue bonds do not directly affect the G.O. rating of a
state.
However, under the Internal Revenue Code (the "Code"), not all obliga-
tions of.states and their political subdivisions are exempt from Federal
income taxes. If the proceeds of otherwise tax-exempt bonds are made
available to "non-exempt persons" (entities other than states, their
political subdivisions and charitable organizations described in Section
501(c)(3) of the Code), those bonds could be classified as Industrial
Development Bonds ("IDBO ). The Internal Revenue Service considers
bonds to be IDBs if the bond proceeds are expected to be used in the
trade or business of a non-exempt person and to be secured by payments
made by such non-exempt person. Interest on IDBs is not exempt from
Federal income taxes unless the size of the bond issue is below a
certain level (far smaller than the needs of the Susitna Project) or
unless the bond proceeds are used to fund certain types of exempt
facilities (which in the case of hydroelectric projects include only
projects for which the output is used in no more than two counties or
their political equivalent). in other words, since Susitna does not
meet the two -county rule test, if a portion of the bonds issued to
finance the Susitna Project met the definitional test and were classi-
fied as IDBs, under current Federal laws, the interest on that portion
of the bonds deemed to be IDBs would not be exempt from Federal income
taxes and the cost of financing the Project would be correspondingly
higher.
It is expected that roughly 75 percent of the energy from the Susitna
Project will be sold to REA cooperatives. These cooperatives, while
generally exempt from Federal income taxes, are not included in the
definition of "exempt persons" under Section 501(c)(3) of the Code. The
REA cooperatives would accordingly be classified as "n6n-exempt per-
sons."
The Treasury Regulations and IRS rulings dealing with.power generating
facilities contain detailed rules for determining whether the sale of
energy to "non-exempt persons" will cause bonds issued to finance those
facilities to be classified as IDBs. In very general terms, such bonds
would be IDBs if "non-exempt persons" entered into power sales agree-
ments covering more than 25 percent of the capacity of the power gene-
rating facilities, and those contracts required the "non-exempt persons"
to make payments covering a pro rata portion of debt service regardless
of whether any power was in fact delivered. This type of power sales
contract (known as a "take -or -pay" contract) is the standard in the
utility finance industry, whether in the tax-exempt or corporate market
and will probably be necessary for the financing of Susitna.
Because of the desirability of take -or -pay power sales contracts with
the REA cooperatives as well as the exempt users, tax-exempt financing
for the Susitna Project in its entirety might not be available under
existing law. For several years, this issue of the availability of tax-
exempt financing has been the subject of on -going research and analysis
by the Power Authority and its advisors, as well as by the Governor's
Office in Washington, D.C. and the Congressional delegation. The
161/169 7-12
problem has become even more significant with the introduction in
October 1983 of H.R. 4170, the Tax Reform Act of 1983, which is dis-
cussed below. Three possible solutions to this problem which would
enable the Susitna Project to be financed on a tax-exempt basis would be
to either change existing State law, modify existing Federal law or
modify the planned sales to REA cooperatives.
The concept of amending State law was first introduced, to the Board of
the Power Authority on April 18, 1983 as a possible financing option for
the Anchorage -Fairbanks Intertie Project, which also involves a heavy
concentration of non-exempt users. The concept, known as "direct
billing", is that a Legislative amendment would allow the Power Author-
ity to pass -through its debt service for various projects directly to
utility consumers. The utilities could contractually serve as collec-
tion agents utilizing a separate line item category in their monthly
billing statements to their customers. With such a broad rate base, no
power sales contracts would be necessary to market the bonds. Since the
ultimate power consumers would not constitute "trades or businesses"
under the Internal Revenue Code, bonds issued for projects utilizing
this concept should not be deemed to be IDBs. While legal advisors to
the Power Authority have expressed some level of comfort with this
methodology of achieving tax -exemption, no decision has been made as to
the necessity of obtaining a Revenue Ruling from the Internal Revenue
Service. The Power Authority plans to introduce a bill to the current
Alaska Legislature to provide for the "direct billing" concept. The
bill is entitled "An Act relating to the direct sale of power by the
Alaska Power Authority to retail customers".
161/169 7-13
Existing Federal law could be amended in any number of ways; either
narrowly, to limit tax-exempt status solely to Susitna, or more broadly,
allowing other power generation facilities to qualify for tax-exempt
status. Three examples of narrow changes to existing law would be:
(1) to amend current Federal law to provide that bonds issued for the
construction and operation of the Susitna Hydroelectric Project would be
tax-exempt; (2) to amend current Federal law to exclude bonds issued for
purposes of constructing Susitna from the definition of IDBs by expand-
ing the Section 103 definition of "exempt persons" to include REA
cooperatives or specifically the purchasers of power from Susitna and
(3) to amend Section 103 to broaden the definition of "qual.ified hydro-
electric projects" which are tax-exempt to include Susitna.
A less -narrow approach involves broadening an existing list of bonds
that, although IDBs, are tax-exempt. Tax-exempt IDBs include bonds
issued for purposes relating to "the local furnishing of electric energy
or gas." (26 U.S.C. Section 103(b)(4)(E)). As currently defined by the
IRS, "local furnishing" exists only where two or fewer contiguous
counties are involved (hence the term "two -county rule" evolved as a
synonym of "local furnishing exemption"). Since the Susitna Project
would serve several Alaska boroughs, it appears that it would not fall
within the current definition of "local furnishing." This could be
altered by amending Section 103 of the Code to define "local furnishing"
for purposes of Alaska as involving the entire State.
It is important to note that although it may be simple to identify.the
sections of Federal law to be amended and to draft the necessary lang-
161/169 7-14
uage, it is never easy to pass amendments benefiting a single project.
A further possible constraint on tax-exempt status for Susitna bonds is
the aforementioned Tax Reform Act of 1983, which would place a state -by -
state limit on the amount of IDBs each state could issue. The limit
currently proposed would be a $150 per person per year "cap" on tax-
exempt IDBs (and student loans) allowed to be issued by each state. The
pendency of this legislation, with its January 1,. 1984 effective date,
has created a practical moratorium on issuance of IDBs which would
otherwise be classified as tax-exempt.
Because of its small population, the State of Alaska would be authorized
to issue a relatively small amount of tax-exempt IDBs if the Tax Reform
Act,of 1983 passes as currently written. There would not be sufficient
IDB capacity under the cap to fund the Susitna Project along with other
projects seeking similar tax-exempt funding in the State. At the time
of this writing, it is expected that a compromise will be reached
between those forces in Congress seeking to "cap" tax-exempt IDBs and
local government forces attempting to maintain this method of financing
projects beneficial to the public; however, public power projects have
not yet been included in the list of exclusions from the cap.
The approach of modifying the contemplated sales to REA cooperatives so
as to obtain tax-exempt status for the revenue bonds might require
restructuring the Railbelt electric system. One approach would be for
the municipal electric systems in the Railbelt to purchase the non-
exempt utilities in the Railbelt. There are a number of legal, politi-
cal and practical difficulties with this re -organizational approach.
161/169 7-15
Inasmuch as the Power Authority does not currently control the assets or
activities of any Railbelt utility and has no statutory authority to
become a public utility, it is unlikely that changes could be 'made in
the Railbelt electric system in the necessary timeframe to allow Susitna
bonds to be classified as tax-exempt under current law.
A. practical consideration of tax-exempt financing is that debt service
coverage is often required to market bonds. For example, the Power
Authority might be required to maintain revenues from the Susitna
Project equal to some percentage (possibly 10 to 25 percent) in excess
of the current year's debt service. However, mitigating any coverage
requirement is the probability that the coverage will be retained in the
flow of funds on the Project and thereby be made available for funding
of reserves, improvements to the system or early retirement of debt.
For purposes of analysis, it is assumed the excess coverage, after
required reserves are established, is held and invested along with
required reserves at a rate of 11 percent. This treatment produces a
result essentially the same as retiring debt. Another treatment of
coverage would be to assume the market will accept a "rolling -coverage'
concept whereby certain reserve fund balances, exclusive of debt service
reserves and other special purpose funds, may be included as available
revenues in the setting of power rates and thus the net effect is to
eliminate the coverage factor from the. cost of power. Because of the
use of coverage within the system or the possible elimination of cover-
age as described above, coverage in and of itself does not appear to be
a major detriment to tax-exempt financing.
161/169 7-16
Of more concern in the tax-exempt area is the likelihood that a market
saturation scenario could develop with regard to the sale of bonds fora
project the size of Susitna. In such a case, bonds of succeeding series
might command increasingly higher yields by comparison to similarly
rated competing issues of the same type' and. maturity range but which do
not have an overexposure to the market. For this reason, it is impor-
tant to develop several financing options and to explore combinations of
options to help prevent the risk of market saturation.
Another concern relative to the marketing of revenue bonds (whether
tax-exempt or not) is the considerable magnitude of the obligations
assumed under the power sales agreements by the Railbelt utilities as
compared to their financial strength. Also their ability to perform
might be jeopardized in the event of a prolonged Project outage or if
the financial disability of one of the participating utilities shifts
the burden to other participants. This problem has been dealt with in
the Four Dam Pool negotiations, mentioned in the introduction to this
Chapter, by modifications to standard take -or -pay language. The modi-
fications shift certain risks, not covered by insurance proceeds or
other available funds, from the utilities. to the State's "moral obli-
gation The term "moral obligation" refers to- the ' procedure of at
least annually notifying the Legislature and Administration if a de-
ficiency exists in the required Capital Reserve Fund (generally one
year's debt service) associated with a bond issue. After such notifi-
cation the Legislature may, at its option, restore such deficiency.
161/169 7-17
While the literal wording of this moral obligation language does not
give any assurance of assistance from the State, a view generally held
by investors is that a state could not in good conscience, or by using
prudent business judgement acting in its own best interest, allow one of
its agencies to default on a debt obligation. There are, of course,
investors who do not share this view, or -at least not to the extent that
they would purchase bonds secured to any 'significant degree in .this
fashion. There are many investors, however, who would place reliance on
the .moral obligation to cover the risk of extraordinary and highly
remote "doomsday scenarios". In summary, the State's willingness to
assume a contingent responsibility for certain catastrophic events could
be a meaningful credit enhancement for the debt portion of the financing
for the Project because the State's resources appear to be commensurate
with the financial obligations. The moral obligation availability would
also be helpful in power sales agreement negotiations with utilities.
However, it must be emphasized that the resolution of the Four Dam Pool
situation is essential to any investor reliance in the future on the
moral'obligation of the State of Alaska.
Because of the uncertainty regarding, the tax-exempt status of a portion
of Susitna revenue bonds, the financing options involving tax-exempt
bonds will include sensitivity analysis assessing the impact of financ-
ing a portion of the Project with taxable bonds.
161/169 7-18
7.3.5 REA Guaranteed Loan Program
A potential source of federally guaranteed financing has recently
received a great deal of attention within the State. The Rural Electri-
fication Administration (REA) is an agency within the U.S. Department of
Agriculture which, under the Rural Electrification Act (7 U.S.C.
section 901), has the authority to loan monies to state agencies and
non-profit cooperatives, for the purpose of providing electric service
to rural areas. The REA has a guaranteed loan program which has been in
existence for 10 years that could be a source of funding for a portion
of Susitna. REA can guarantee loans made by any established lending
institutions for generation and transmission projects to service rural
areas not receiving central station service.
Under the Federal Financing Bank Act of 1973, REA borrowers are entitled
to receive their loan through the Federal Financing Bank (FFB), if they
choose. FFB is an arm of the U.S. Treasury. Its loans are provided at
interest rates of 0.125 percent (1/8th of one percent) above prevailing
Treasury bond rates. Because these terms are so favorable, most guaran-
teed loans are made through the FFB. In fiscal year 1984, FFB has
available $3.3 billion for REA's guaranteed loan program. Short-term
construction loans, available for a term of three to seven years, can be
negotiated based on interest rates for short-term Treasury bills. The
REA has guaranteed approximately $30 billion, in loans since 1973.
Of this amount, only about $800,000 has been lent by institutions other
than FFB.
161/169 7-19
short-term loan may be rolled over to a long-term arrangement with a
maximum term of 35 years. These rates would be based on long-term
Treasury bond yields.
The REA will only finance projects which are designed to serve rural
needs and, therefore, Susitna's total financial needs cannot be met by
REA financing. Where a proposed project is intended to serve both rural
and urban areas, as is the case with Susitna, REA will serve only "Act
beneficiaries", i.e., customers in areas which the Act defines as rural.
The present REA cooperatives of Chugach, Matanuska, Homer and Golden
Valley are deemed "Act beneficiaries", since they qualified when first
formed. Having once qualified, they may continue to qualify despite
population changes.
The Power Authority may be an applicant under the REA loan guarantee
program. However, it should be noted that the REA guarantee program
cannot be utilized in combination with tax-exempt bonds for the REA
guaranteed portion of the project financing. Although REA loans are
typically made to generating and transmission cooperatives (G&Ts) or REA
distribution cooperatives, the Alaska Railbelt does not have an estab-
lished G&T cooperative. Generally, "G&T cooperatives are formed by the
initiation and concerted effort of rural cooperatives for the purposes
In the past 10 years of the Guaranteed Loan Program, there have
been approximately 923 loans to cooperatives either in their own right,
or through a G&T cooperative, 40 to public utility districts, and 4 to
investor -owned or municipal utilities for service outside city bound-
aries.
161/169 7-20
of financing the construction of needed generation and transmission
systems in the REA's service territories. Lacking such a G&T coopera-
tive, the preferable entity in the Railbelt for receiving an REA loan
for Susitna would be the Power Authority.
One key reason for this approach to REA financing is the FERC licensing
procedure. If the Power Authority were to assist the rural cooperatives
in establishing a G&T to act as Applicant for the loan guarantee pro-
gram, it would need to transfer ownership of Susitna to the cooperative.
This would necessitate a change in the Power Authority's FERC License
Application, with a possible regulatory delay.
Financing a portion of the Susitna Project through the REA loan guaran-
tee program could provide real benefits to the State as developed in
greater detail in the finance plan discussed below. These benefits flow
from the relatively low interest rates associated with such financing as
compared to other taxable financing options. The interest rate for REA
loans in January 1984 was approximately 11.75 percent, as compared to
approximately 13.0 percent for taxable bonds and approximately 10.0
percent for tax-exempt bonds. Furthermore, the possible alleviation of
the market saturation scenario described above could be very beneficial.
A very real drawback to the use of REA guaranteed loans is the likeli-
hood that the REA program will continue to receive decreasing amounts of
U.S. Congressional approval. The REA's guarantee program ceiling of
$3.3 billion for fiscal year 1984 represents a reduction of $1.3 billion
in nominal dollars from fiscal year 1983. The currently proposed
161/169 7-21
Administration budget for fiscal year 1985 is approximately
$1.3 billion, again in nominal dollars. The Susitna Project would be
the REA's largest single commitment if guaranteed to the maximum pos-
sible extent.
In the current political environment in Washington, the probability of
gaining sufficient support for financing all of the participation of
cooperatives in Susitna appears to be low. However,, participation of
the REA to the extent legally and practically feasible is a financing
option which deserves considerable attention. This option has never
been ruled out by the Power Authority but has not been pursued actively
in recent years because of the size of the Project and the more attrac-
tive interest rates available if tax -exemption is achieved. Also, while
the REA staff has indicated a willingness to explore more "risk -taking"
on their part than would be the case in the tax-exempt bond market (such
as possibly accepting yearly appropriations of the RSF rather than
having dedicated stream of revenue), this would indeed be a departure
from their usual policy of having binding commitments on all the ele-
ments of a financing package. The likelihood of a variance of basic
policy on their largest single project exposure seems somewhat remote.
It would seem more probable that the risk of non -appropriation would
have to be borne by the utilities, and ultimately the consumer, as is
the case on present REA loans to cooperatives within the State who now
receive power rate assistance funds.
161/169 7-22
7.3.6 Other Sources of Funding
In addition to the possible funding sources reviewed above, taxable
bonds or private equity financing could also provide financing for the
Susitna Project. Generally, however, these sources are not attractive
to the State because investors in those markets demand a higher rate of
return than*can be accommodated and still achieve a marketable power
rate. Although a Rate Stabilization Fund or State equity could be used
in conjunction with some of these markets to reduce the ultimate cost of
power in the early years of operation, even that mechanism has limita-
tions. In anticipation that other forms of financing may be considered.
before a final finance plan is decided upon, this section examines
taxable bonds and private equity financing as sources of financing for
the Project. .In addition, G.O. bonds are considered.
Taxable bonds may be issued as either fixed-rate or floating interest
rate obligations, as may tax-exempt bonds. Fixed-rate taxable bonds
which are rated "A" by Moody's or Standard & Poor's are currently
carrying an interest rate of approximately 13.0 percent or more. At
this level, the wholesale cost of energy from Susitna would be quite
high: Floating rate bonds carry interest rates generally tied to the
movement of the prime rate or some other index rate. Because the
interest rate varies over time, the cost of energy from the Susitna
Project would also vary without the establishment of a variable amount
RSF. •Such fluctuation in the cost of energy without any ceiling would
probably be unacceptable to the Railbelt utilities and their customers.
A variable amount RSF would probably be unacceptable to the State as
well.
Private equity, if it could be found, would enable parties other than
the State of Alaska and its political subdivisions to acquire an owner-
sh.ip interest in Susitna. There are two major drawbacks to private
equity financing for Susitna. First, the rate of return demanded by -
providers of private equity is quite high, with the probable result of
making this the most expensive means of financing the Project. Second,
allowing private equity financing of the Susitna Project would cause the
State of Alaska, acting through the Power Authority, to lose consider-
able control over the Project, including control over its method of
operation, rates and management. This would be inconsistent with the
current statutory purposes of the Power Authority.
Another alternative source of financing is the use of G.O. bonds. These
bonds are issued by a state relying on its general credit rating and do
not depend on a dedicated stream of revenue from a project for repay-
ment. Payments on the bonds are usually made from the general fund of a
state and the bonds can be used for any legal purpose. Because these
bonds are the obligations of states they are tax-exempt. The use of
G.O. bonds was not considered an attractive source of financing for
several reasons. First, through the credit rating process, debt markets
limit the amount of G.O. bonds available.to a state. The amount of G.O.
bonds needed for Susitna would greatly exceed Alaska's G.D. bond capa-
city assuming an investment rating downgrade is unacceptable. Second,
the State of Alaska has traditionally followed a prudent policy of
repaying its G.O. bonds over a relatively short term while projected oil
revenues are reliable, providing excellent coverage. Such financing,
repayable over a short-term, would be unacceptable for purposes of
161/169 7-24
Susitna. Accordingly, although G.O. bonds are a possible but limited
source of financing, it appears the State would prefer to make other
uses of this financing tool; therefore, this option has not been con-
sidered in any detail in connection with the Project financing.
Another extremely important element of utilizing G.O. debt for Susitna
is the probable effect of a potential downgrade in the State's G.O. debt
rating resulting from issuing excessive G.O: debt. In the opinion of
the financial advisor and investment bankers to the Power Authority, a
bond rating of "A" or better on the Susitna revenue bonds is essential
to its financing due to the sheer size of the total debt required. A
downgrade in the State's G.O. rating could impact the Power Authority's
ability to achieve an "A" rating on its bonds.
7.4 IMPACT OF WPPSS DEFAULT ON SUSITNA FINANCING
The effects of the recent default by the Washington Public Power Supply
System ("WPPSS") on its debt relating to Units 4 and 5 and the resulting
possible impact on the Power Authority, particularly the Susitna Proj-
ect, must be reviewed in connection with the Susitna Update. This
$2.25 billion WPPSS default is the largest municipal bond failure of
record.
The implications of the WPPSS experience in the public power finance
markets are broad, especially for projects in the Pacific Northwest.
Hopefully, the Alaska Railbelt will not automatically be considered part
of the Pacific Northwest- Region by investors. In addition, Susitna is
161/169 7-25
not a nuclear project as were WPPSS Units 4 and 5, nor is the Power
Authority authorized to pursue nuclear projects. The financing of
Susitna will be enhanced by the following facts; that it is a hydro-
electric project, it has and will continue to benefit from substantial
State investment and it is a project of a State agency.
The principal concerns of investors, financial analysts and the rating
agencies with large power projects are -illustrated perfectly by the
WPPSS case. They are as follows;
(1) Economic and financial viability of the project,
(a) Need for..power (accurate load forecasts),
(b) Acceptable power rates (competitive with alternatives),
(c) Public support for project (environmental concerns and
willingness to pay),
(d) Executive and Legislative commitment,
(e) Consistency in dealing with energy policy;
(2) Risks associated with the project,
(a) Risk of completion,
(b) Risk of cost overruns,
(c) Risk of construction delays;
(3) Market access for subsequent series of bond issues (market
saturation);
(4) Validity of power sales contracts relating to the provision of
necessary revenues to service the debt.
... .. I., , . I
As a case in point, Standard & Poor's, one of the two principal bond
rating agencies, has written many, if not all, public power entities
with rated debt outstanding and requested them to obtain new legal
opinions from bond counsel to the effect that, even in light of the
WPPSS decisions by the Supreme Courts of Washington and Idaho, the
existing power sales agreements applicable to their project are legal,
binding and enforceable in accordance with their terms. Presumably, the
inability to produce such opinions could result in the reduction, if not
withdrawal, of the bond rating.
Another case in point is that some large institutional investors have
now .established policies of not buying electric revenue bonds where
power sales agreements have not been validated by litigation (test case
or otherwise). And, to the extreme, some investors are shying away from
all power bonds, at least for the present. It seems that load forecasts
are the subject of far more review than ever before and that the invest-
ment community is striving to be certain, to the degree possible, that a
given project makes economic sense, regardless of the existence of power
sales agreements or the validity thereof. Nevertheless, the existence
of legally binding power sales agreements will be essential and a test
case may be necessary or advisable before marketing any longterm Power
Authority bonds for Susitna.
The financial advisor and investment bankers of the Power Authority have
in the past and continue to advise that State contributions of equity to
the Project should be made.in_the early years and in substantial amounts
with bonds issued at a later date. The WPPSS lessons learned from the
161/169 7-2.7
default make it clear that this earlier recommendation is appropriate.
It is important not only to reduce the risk of completion but also to
make the cost of energy economically feasible. It also demonstrates the
State's commitment to the Project, which was missing in the WPPSS
situation. Despite the favorable differences between the Power Author-
ity.and WPPSS, the sheer size of the Susitna financing, even with large
State equity contributions, will cause Susitna financing to be carefully
scrutinized by the investment community.
7.5 FINANCING OPTIONS SELECTED FOR ANALYSIS
Based upon a review of the relative advantages and disadvantages of the
various funding sources discussed in Section 7.3, two specific financing
options have been identified for further analysis and discussion herein:
Option A: Tax -Exempt Revenue Bonds combined with State Equity and Rate
Stabilization Fund
Option B: REA Guaranteed Loan and Tax -Exempt Revenue Bonds (50/50)
combined with State Equity and Rate Stabilization Fund
In Section 7.6, Options A and B will be analyzed assuming that the Devil
Canyon Phase in each instance will be financed from proceeds of revenue
bonds or other debt instruments bearing the same interest rate as was
assumed for Watana tax-exempt revenue bonds. Relatively small amounts
of RSF funds will also be required in the first few years of operation
of Devil Canyon. The exact means of financing Devil Canyon is not
161/169 7-28
critical to the financing of the Watana Phase which must stand on its
own in the financial market.
In Option B, a 50/50 split of the debt portion between REA guaranteed
loans and tax-exempt revenue bonds is assumed because: (1) the avail-
ability of a share larger than 50 percent from the REA program is highly
improbable; (2) the interest rate benefit of tax-exempt financing of
approximately 1.75 percent per annum is clearly the least expensive form
of long-term debt presently available, regardless of debt service
coverage considerations; and (3) the 50/50 split may have a beneficial
effect on the potential market saturation problem relating to the
tax-exempt bond market; however, it should be noted that the Federal
government could also experience market saturation problems if present
levels .of budget deficits continue. The actual split of the debt
portion of the financing between REA guaranteed loans and tax-exempt
revenue bonds would be determined based upon market conditions and
availability of REA guaranteed loans at the time debt is marketed.
Both financing options employ a combination of funding sources and both
utilize the Rate Stabilization Fund concept for reasons stated in
Section 7.3.3, principally to lower State equity requirements (on a
present worth basis) and to spread the State assistance payments over a
longer period of years. The base case (or recommended approach) for
each option assumes the State equity and RSF will be paid in as needed
by means of a revenue source such as the proposed Major Project Fund
which further assists in spreading the State's assistance over a greater
period of time. In Option B, to the extent tax-exempt financing is
161/169 7-29
assumed for more than the presently available 25 percent (estimated) of
the Project to be utilized by "exempt persons", the base case assumes
the tax-exempt question will be resolved in favor of the State.
Sensitivity analyses have been performed on: (1) the effect of the RSF
being required "up -front" at the time of debt financings in the event a
dedicated• revenue stream has not been approved by the ,electorate;
(2) the effect of no tax -exemption for Project financing in excess of
the 25 percent estimated to be utilized by "exempt persons"; and (3) the
effect on the financing and equity requirements if a 120 percent
"willingness to pay" exists during the first years of operation.
7.6 ANALYSIS OF FINANCING OPTIONS
The two financing options presented in Section 7.5 were analyzed using a
financial model. The model computes the annual disbursements required
during the construction and operation periods of the Susitna Project.
The basic assumptions used in the'analysis are presented in Exhibit 7.1.
7.6.1 Comparison of Options
The amounts required from each funding source under the base case of
each option are shown on Exhibit 7.2. Amounts are given on Exhibit 7.2
for both Watana and Devil Canyon; however as stated earlier, Devil
Canyon is financed by revenue bonds and RSF, if necessary, under each
option. For that reason the discussion that follows applies only to the
Watana Development.
161/169 7-30
The annual disbursements required during the construction and operation
periods for Options A and B are shown on Exhibits 7.3 and 7.4, respec-
tively. These Exhibits also present the wholesale cost of energy for
each option. Exhibit 7.5 shows the wholesale cost of energy of the two
options compared to that of the least -cost thermal alternative.
A comparison of the State funds required for equity contributions and
RSF under each option is shown on Table 7.1. The total equity plus RSF
required in each of the options, expressed in 1983 dollars, is
$1,915 million in Option A and $2,054 million in Option B, a difference
of about 7 percent.
Table 7.1
COMPARISON OF STATE EQUITY
AND RSF CONTRIBUTIONS *
(In Million Dollars)
--0��t—ion —AA
Option B
(Bon
shy, RSF)
(Bonds, REA, Equity, RSF)
In Nominal Dollars
Equity
2,4QO
2,700
RSF
1,013
888
TOTAL
3,417
3,588
In 1983 Dollars
Equity
1,519
1,707
RSF
396
347
TOTAL
11915
2,054
* Assumes reinvestment
earnings on all
State equity including rate
stabilization accumulated
for the benefit
of the Project.
161/169 7-31
Table 7.2 shows the annual disbursement of equity and RSF contributions
required for each option. Exhibit 7.6 shows the nominal disbursements
in each year compared to 10 percent of forecast oil and gas revenues in
each year. As can be seen from Exhibit 7.6, Watana's requirements are
well below the 10 percent limit under both options, allowing funds to be
used for other capital projects.
Table 7.2
DISBURSEMENT OF STATE. EQUITY
AND
RSF CONTRIBUTIONS
(In
Million
Dollars)
Option
A
Option B
(Bonds, E unit
RSF)
(Bonds, REA
Equity RSF)
Nomina'
168
83
Nom'lnai
igh
Year
Dollars
Dollars
Dollars
Dollars
1985
177
151
199
170
1986
196
157
220
176
1987
210
159
236
178
1988
227
161
254
180
1989
247
164
276
183
1990
246
153
276
172
1991
238
140
266
156
1992
237
130
265
146
1993
239
123
268'
138
1994
233
113
261
126
1995
150
68
179
82
1996
256
109
200
86
1997
277
111
253
102
1998
247
93
228
86
1999
214
76
198
70
2000
19
7
9
3
TOTALS
3,413
1,915
3,588
2,054
161/169 7-32
7.6.2 Sensitivity Analyses
7.6.2.1 Revenue Bonds Two key assumptions regarding the revenue bonds
used in the options are: (1) that the bonds are tax-exempt status and
(2) the passage of a constitutional amendment establishing a fairly
uniform dedicated stream of revenues for Watana before and during its
construction and during its initial. years of operation. It is assumed
that taxable revenue bonds bearing an interest rate of 13 percent could
be used to finance the project if exemption is not obtained: If a dedi-
cated stream of revenues is not allocated to Watana, bond underwriters
and prospective investors will probably require that all equity and RSF
funds are allocated "up front" before the revenue bonds are issued.
Sensitivity analyses for these two assumptions were performed. The
amounts required from each financing source are given on Table 7.3 for
each option.
161/169 7-33
Table 7.3
SENSITIVITY OF ANALYSIS TO
EXEMPTION AND DEDICATED REVENUES
(In Million Nominal Dollars)
Option A
Base Case
Sensitivity
Tax -Exemption
Exempt
Non Exempt
Revenue Bonds
6,075
3,324
Equity
2,400
3,800
RSF
1,013
145
TOTAL
7,269
Base Case
Sensitivity
Dedicated Revenues
Dedicated
Up Front
Revenue Bonds
6,075
1 ,181
Equity
2,400
--
RSF
1,013
3,
1 910*
TOTAL
87
1-3,W
Option B
Base Case
Sensitivity
Tax -Exemption
Exempt
Non -Exempt
Revenue Bonds
2,736
2,337
REA Loan
2,332
1,884
Equity
2,700
3,200
RSF
888
607
TOTAL
8,656
8,028
Dedicated Revenues
Revenue Bonds
REA Loan
Equity
RSF
TOTAL
Base Case
Dedicated
2,736
2,332
2,700
888
8,656
Sensitivity
Uo Front
5,606
4,964
2,280**
12,850
* Amount set aside during 1985-88 equals $4,314 million in 1996 with
interest accruals.
** Amount set aside during 1985-88 equals $5,152 million in 1996 with
interest accruals.
161/169 7-34
The annual disbursements required for the "up front" equity and RSF
contributions are given on Table 7.4.
Table 7.4
SENSITIVITY ANALYSIS DISBURSEMENT
OF EQUITY AND RSF CONTRIBUTIONS
(In Million Dollars)
Option
A
I Option
B
(Bonds, Equity,
RSF)
(Bonds, REA, Equity,
RSF)
Nominal
1983
Nominal
1983
Year
Dollars
Dollars
Dollars
Dollars
1985
419
357
501
428
1986
463
371
555
445
1987
497
374
595
448
1988
531
375
629
445
TOTALS
1,910
1,477
2,280
1,766
7.6.2.2 Willingness to Pay The concept of "willingness to pay" was
discussed in Section 7.2. If a 120 percent willingness to pay is
assumed for the options, the amount of financing required from each
source for each option would be as indicated on Table 7.5.
The annual disbursements of State funds to the sensitivity cases are
shown on Exhibits 7.7 and 7.8, respectively, for Options A and B.
161/169 7-35
Option A
Tax -Exempt Bonds
Equity
RSF
TOTAL
Option B
Tax -Exempt Bonds
REA Loans
Equity
RSF
TOTAL
7.7 CONCLUSIONS
Table 7.5
SENSITIVITY OF ANALYSIS TO
120 PERCENT WILLINGNESS TO PAY
(In Million Nominal Dollars)
Base Case Sensitivity
100%
120%
6,075
8.,090
2,400
1,500
1,013
1,373
9-488
10,963
2,736
3,608
2,332
3,088
2,700
1,900
888
1,177
8,656
9,773
The conclusions which can be drawn from the analysis are:
° There is a relatively minor difference (about 7 percent) in the
amount of State contributions required under either financing
option base case, as shown on Table 7.1. Approximately $2 billion
in 1983 dollars is required in each instance;
161/169 7-36
The cost of energy is approximately the same under each financing
option base case as reflected on Exhibit 7.5; and
° Both proposed financing options have potential for financing the
Project and should be pursued iri tandem.
The sensitivity analyses demonstrate that the assumptions regarding
tax -exemption, the constitutional amendment establishing the dedicated
stream of revenues for the Susitna Project, and willingness to pay each
have a significant effect on the financing options. If tax -exemption is
not obtained, the State's contribution will have to be substantially
increased. Requiring State equity and RSF funds up -front will increase
the debt associated with the Project and the required annual State
contribution, although the State's total contribution will decrease.
The State's contribution will be substantially decreased if'a portion of
the financial burden of the Project is passed on to consumers in the
form of a willingness to pay premium.
Five issues need to be resolved before any plan of finance for the
Susitna Project can be finalized. The Power Authority will pursue each
of these issues with appropriate entities, keeping- the Legislature and
Administration apprised of progress.. The five issues are:
° Tax-exempt status of the Susitna revenue bonds;
° Ability and willingness of the REA to guarantee debt in meaningful
amounts;
° Establishment of a dedicated stream of revenues;
161/169 7-37
° Willingness of utilities to contract for the purchase of Susitna
power; and
° Willingness of the State to allow the use of its "moral obligation"
to support Project funding.
161/169 7-38
Page 1 of 2
EXHIBIT 7.1
ASSUMPTIONS USED IN FINANCIAL ANALYSIS
Financing Terms: Interest Repayment
Rate, Period,
Source Percent Years
Revenue Bonds,Tax Exempt 10.0�
Revenue Bonds, Taxable 13.00 35
REA Loan; 11.75 35
Interest Rates on Invested Funds: Equity and Short Term *: 9%/yr
Long Term: 11%/yr
Rate Stabilization Fund: 5%/yr
Inflation and Deflation Rate: 6.5%/yr
Willingness to Pay: 20% above thermal cost of energy when applicable.
Project Construction Cost (1983): (License Application)
1983 Dollars Nominal Dollars
Watana $3,75�9-6 n $7,200_ million
Devil Canyon 1,620 million 4,638 million
TOTAL 5,3 million $ 1, 38 million
First Year of Construction:
Watana 1989
Devil Canyon 1995
First Year of Operation:
Watana 1996
Devil'Canyon 2002
Equity Contribution Limit:
1 of Oil and Gas Revenues
and Gas
r Year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
Less than one year.
.evenues in miiiion
_
(Nominal Dollars)
3, 5 .
3,381.5
3,629.5
3,910.5
4,252.5
4,242.0
4,097.5
4,083.5
4,124.5
4,015.5
3,798.5
3,818.5
161/169
4
Page 2 of 2
EXHIBIT 7.1
ASSUMPTIONS USED IN FINANCIAL ANALYSIS
Power Market Forecast (SHCA-NSD):
Railbelt
Net Energy
Year Generation Re uirements, GWh
1995 4, 5
2000 4,846
- 2020 8,063
Thermal System Energy Coin Nominal Dollars:
1996 Target Cost. 11. sts W
Capital Renewals (as percent of escalated investment cost):
Thermo 3.0.
Hydro: 0.3%
Revenue Bond Characteristics:
Maximum Bond Size:
No limit, determined by annual requirements.
Interest During Construction:
Each succeeding bond funds prior years) bond(s) interest
Debt Service:
Debt service begins in first year of operation
Debt Service Coverage: 10%
Financing Expense:
Equal to 3 percent of principal amount
Debt Service Reserve:
One years levelized debt service based on 35-year repayment period
Reserve and Contingency Fund (hydro):
One years capital renewals plus one year's operation and main-
tenance cost (established at start of bond issue
Working Capital Fund:
Fifteen percent of first year's operation and maintenance cost plus
10 percent of first year's total annual system cost
161/169
EXHIBIT 7.2
FUNDING REQUIREMENTS - BASE CASE
(In Million Nominal Dollars)
4latana
Devil Canyon
Total
Option_..A
Tax-exempt
Bonds
6;075
7,049
13,124
Equity
2,400
--
2,400
RSF
1,013
463
1,476
TOTAL
9
7,512
17,000
Option B
Tax-exempt
Bonds
2,736
7,049
9,785
REA Loans
2,332
--
2,332
Equity
2,700
--
2,700
RSF
888
463
1,351
TOTAL
8,656
7,512
16;-1-68
161/169
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45 EXHIBIT 7.5
LEAST-C/THERMAL,
40
35
FULL FUNDING WITH
TAX-EXEMPT
REVENUE BONDS
30
s
_
i
OPTION 8
z 25
C7
®i
w
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z
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LL 20
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U
w 15
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S
'
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10
5
® RATE STABILIZATION
FUND
0
1996 2000 2005 2010
YEAR
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
ENERGY COST CO
FEBRUARY 1984
EXHIBIT 7.6
450
10% OF OIL AND GAS REVENUES
400
350
STATE CONTRIBUTION REQUIRED
300
FOR WATANA
OPTION B
250-
r-�
O-
(" OPTION A
J
Z 200
I 1 i
-J L-
O
Z
-
Z
O
150
100
50
L_
1985 1990 YEAR 1995 2000
ALASKA POWER AUTHORITY
BUBITNA HYDROELECTRIC PROJECT UPDATE
ANNUAL. STATE CONTRIBUTIONS
FOR FINANCING OPTIONS A AND B
FEBRUARY 1984
EXHIBIT 7.7
550
500 FUNDS REQUIRED UP FRONT
FOR RATE STABILIZATION
450 10% OF OIL AND
GAS REVENUES
400 - -
�
350 � f
rJ I I
i
300
z 250
Z -z�r
f'J OPTION A
200 r I (BASE) II
150 -j-.� L
100
120% WILLINGNESS TO PAY �
r=�
50 75% OF REVENUE �i
BONDS TAXABLE.O k� i
1985 1990 1995 2000-
YEAR
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
ANNUAL STATE CONTRIBUTIONS
FOR OPTION A SENSITIVITY CASES
PEBRUARY 1984_
EXHIBIT 7.8
650
FUNDS REQUIRED UP FRONT
FOR RATE STABILIZATION
600
550
10% OF OIL AND GAS REVENUES
500
450
c[
350
O _
300 r-- OPTION
r"� CBASE) 1
z
z0 250 r r� r-- 1 I
rJ 120% WILLINGNESS J —'
200 J TO PAY
150 i
I
L.
100
50% OF REVENUE
50, BONDS TAXABLE
1588 199bYEAR 99 000
ALASKA POWER AUTHORITY
SUSITNA HYDROELECTRIC PROJECT UPDATE
ANNUAL STATE CONTRIBUTIONS
FOR OPTION B SENSITIVITY CASES
FEBRUARY 1984
8.0 FUTURE ACTIONS
8.1 INTRODUCTION
Chapters 1 through 7 of this Report have provided an Update of the
economic and financial feasibility of the Susitna Hydroelectric Project.
The purpose of this Chapter is to outline the major future actions to be
accomplished prior to construction of the Project. The Power Authority
has identified 9 such major actions and these are reviewed below.
8.2 POWER SALES AGREEMENTS
Power sales agreements need to be signed and in place before the start
of engineering design for the Project. The Railbelt utilities have been
contacted to provide letters of support for the Project. To date, three
utilities have provided such letters and others are expected. Although
these letters do not obligate the utilities to enter into power sales
agreements, they will be used in support of the FERC License Applica-
tion.
The preparation of utility profiles has been initiated. These profiles,
to be developed in cooperation with the utilities, will serve as a basis
for cost of energy and Project feasibility analyses. These analyses
will provide the analytical tool for the Railbelt utilities and the
Power Authority to evaluate the merits of the Project as a basis for
signing Letters of Intent. Continued update of these profiles and
economic and financial assumptions based on the current estimated cost
219/169 8-1
of the Project will enable the utilities and the Power Authority to
enter into power sales agreements.
8.3 FINAL FINANCE PLAN
Before a final finance plan for Susitna can be devised, a number of
issues need to be resolved. First, the tax-exempt status of Susitna
revenue bonds must be determined. As noted in Chapter 7, if Susitna is
financed using revenue bonds on which interest is taxable, the higher
interest rate of those bonds will require the State's equity and RSF
contribution in the Project to increase. Determining the tax-exempt
status will depend upon possible changes to existing law (either Federal
or State) or possible restructuring of the Railbelt electric system. As
discussed in Chapter 7, all possible changes contain considerable uncer-
tainty. It is also possible that only a request for a Revenue Ruling
from the Internal Revenue Service will resolve the question; however,
such a request can only be made when the final form of the power sales
contracts has been determined and the relative participation of Railbelt
utilities is known.
A second issue to be resolved is the ability and willingness of REA to
guarantee debt in meaningful amounts. Specific matters to be pursued
with REA include the availability of REA funds for Susitna, the quan-
tities expected to be available in the key financing years, and the
decision of REA to make necessary commitments. If REA is unwilling to
make commitments for funds or if tax-exempt interest rates continue to
219/169 8-2
be more favorable than REA interest rates, Option B would have to be
revised.
The third finance issue which needs to be resolved is the willingness of
the State to establish a dedicated revenue source to support the Proj-
ect's financing. As noted in Chapter 7, one means of providing the
necessary equity contributions and RSF payments would be the proposed
Major Projects Fund. A measure now pending before the' Alaska Legisla-
ture would place a proposed constitutional amendment creating such a
fund on the ballot in November 1984. Careful attention to the funding
mechanism provided for in such legislation is necessary to assure that
such mechanism is consistent with assumptions made herein.
Fourth, the willingness of Railbelt utilities (and ultimately Railbelt
consumers) to pay a premium price for Susitna. energy needs to be ex-
plored and validated. As noted in Chapter 7, if there was a willingness
to pay 20 percent more for wholesale Susitna energy, it would reduce the
State's necessary equity and RSF contribution in the Project. However,
there is no assurance that such willingness to pay exists. .
Finally, the willingness of the State to allow the use of its "moral
obligation" to support Project funding needs to be assessed. The
completion of Four Dam Pool power sales agreement negotiations embodying
moral obligation features will be an indication of the State's willing-
ness to consider such an arrangement for its projects.
219/169 8-3
8.4 LEGISLATIVE AUTHORIZATION
As with all new projects of the Power Authority, the Legislature must
approve the Susitna Project by enacting law that authorizes the Project
at an approved construction cost. Prior to such Legislative approval,
ALASKA STAT. § 44.83.183 requires that the Power Authority submit a
feasibility study and plan of finance to the Office of Management and
Budget (OMB) for review. OMB must then submit a report of their find-
ings along with a recommendation of approval or disapproval to the
Governor and Legislature within -60 days. Existing law ALASKA
STAT. § 44.83.185 further requires that the feasibility study, plan of
finance, an independent cost estimate, and the report from OMB be
submitted to the Legislature for consideration.
8.5 FERC LICENSE AND OTHER MAJOR PERMITS
A number of regulatory approvals must be obtained before construction of
the Susitna Project can commence. Although the most important of these
is issuance of a license to construct and operate the Project by the
FERC, a number of permits from oth.er Federal and State agencies must
also be obtained.
8.5.1 FERC License
The FERC licensing process is currently underway and proceeding toward
the target license issuance date of March 18, 1987. The Susitna License
Application was accepted for processing by the FERC on July 29, 1983,
219/169 8-4
Since that time the Power Authority has responded to numerous FERC Staff
requests for additional information and has begun preparation for the
two-phase hearings tentatively planned for the case. The current
schedule calls for "Need for Power" hearings to be held in the Summer of
1984 and for hearings on environmental and dam safety issues to begin in
the Spring of 1985. The second •phase hearings may be shortened through 1
settlements; if so, it is possible that a FERC License could be issued
earlier than the March 1987 target date. As with most regulatory
actions, however, there is the possibility of future legal challenges
which could delay the effective date of the FERC License.
8.5.2 Other Major Permits
In addition to the FERC License, several Federal, State and local
permits will be required to construct the Project. A listing of the
major permits, and the agencies involved, follows:
Federal Permits
1. U.S. Army Corps of Engineers, Obstructions of Navigable
Waterway Permit
2. U.S. Army Corps of Engineers, Wetlands Fill Permit
3. Bureau of Land Management, Right -of -Way Grant, Land and Gravel
Permits
4. Environmental Protection Agency, National Pollution Discharge
Elimination System Permit
5. Environmental Protection Agency, New Source Performance
Statements
219/169 8-5
State Permits
1. Department of Environmental Conservation, Water Quality
Certificate of Reasonable Assurance, Air Quality Permits to
Operate
2. Office of Management and Budget, Coastal Zone Consistency
Determination
3. Department of Fish and Game, Fisheries Protection Permits
4. Department of Natural Resources, Water Right, Permit to
Construct a Dam, Material Sales, Right -of -Way
Local
1. Matanuska-Susitna Borough, Talkeetna Mountains Special Use
District Variance
The Power Authority has been coordinating with permitting agencies for
the .past two years to insure that timely acquisition of permits will be
achieved. Applications have already been submitted for several permits.
It is anticipated that, in most instances, the information and analyses
being prepared to support the FERC licensing process will also support
the processing of necessary Federal, State and local permits.
8.6 DESIGN COMPLETION FOR INITIAL CONTRACTS
Before award of initial construction contracts the Power Authority will
require completion of detailed design. This policy will reduce the
tendency for construction cost over -runs that has been experienced as a
219/169 8-6
result of the common industry practice of inviting bids on preliminary
design documents and then completing design during construction.
8.7 EXTERNAL REVIEW BOARD CONCURRENCE
As will be required .by the FERC, the Power Authority has retained a
board of qualified, independent engineering consultants to review the
design, specifications and construction of the Susitna Project for
safety and adequacy. The consultants on this External Review Board have
been involved in reviewing the Project's design for the past several
years, and will be required to submit a final statement to the FERC
indicating their satisfaction with the construction, safety and adequacy
of the Project's structures when built. In addition, the Power Authori-
ty will require the External Review Board's concurrence on final Project
design before proceeding with construction. These measures provide an
.extra layer of review which ensures that the Project will be built to
the highest engineering standards.
8.8 ACCEPTABLE LABOR AGREEMENT
A Project Labor Agreement will be necessary to provide uniformity,
stability and continuity during construction and to avoid potentially
costly labor disputes. The labor agreement will include standardized
working hours, strong work stoppage - no strike clauses, progressive
grievance and arbitration procedu'res, jurisdictional delineation of
crafts, and training programs and employment opportunities for Native
Alaskans and other minorities.
219/169 8-7
Since it would not be practical to negotiate wage rates for the length
of the job, provisions will be negotiated providing that in the event of
a strike by a local bargaining unit, work would continue on the Susitna
Project and the wage scale eventually agreed upon would be paid retroac-
tively to those Susitna craftsmen represented by the local unit.
8.9 ACQUISITION OF PROJECT LANDS
Approximately 71,000 acres of land are required for the Susitna Project.
The current ownerships of that acreage is distributed as follows:
1. 6,944 acres, State of Alaska
2. 33,350 acres, Native (CIRI and CIRI Villages)
3. 31,105 acres Federal (29,600 of these are State and Native
Selected)
4. 270 acres Municipal Lands (Mat -Su Borough and Municipality of
Anchorage)
The following methods will be used to obtain the use or title to each
land ownership category:
1. State of Alaska lands, easements, classifications
2. Native Land, purchase or land trade, use provisions of Sec-
tion 24 of Federal Power Act
3. Federal Land, State selection under Statehood Entitlement,
Land Use Permits, and Grants of Right -of -Way
_. 4. Municipal, purchase or grant of Right -of -Way
219/169 8-8
Although land acquisition planning is underway, no land will be acquired
until the construction of the Project has been legislatively approved.
8.10 POWER AUTHORITY DECISION TO CONSTRUCT
Before construction of the Susitna Project commences a final decision
will be required by the Board of Directors of the Power Authority. The
Board will not authorize construction unless it has been shown that the
Project is economically and financially feasible and all actions dis-
cussed in this Chapter have been completed to the extent necessary.
219/169 8-9