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Susitna-Watana Hydroelectric Project Document
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Susitna Hydroelectric Project conceptual alternatives design report
SuWa 199
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Susitna-Watana Hydroelectric Project document number 199
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[Anchorage, Alaska : Alaska Energy Authority, 2010]
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Susitna Hydroelectric Project
Conceptual Alternatives Design Report
Final Draft
Prepared for:
Alaska Energy Authority
813 West Northern Lights Boulevard
Anchorage, Alaska 99503
Prepared by:
HDR Alaska, Inc.
2525 C Street, Suite 305
Anchorage, AK 99503
November 23, 2009
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Contents
1 Executive Summary ........................................................................................................................... 1
2 Background ......................................................................................................................................... 5
2.1 Project Scope ............................................................................................................................. 5
3 Preliminary Energy Estimate ............................................................................................................ 6
3.1 Hydrologic Analysis .................................................................................................................. 6
3.2 Evaluation of Firm Winter Capacities and Average Annual Energy ........................................ 7
3.3 Model Assumptions and Data Sources ...................................................................................... 8
3.4 Model Operation ........................................................................................................................ 9
4 Estimates of Probable Project Development Costs ....................................................................... 13
4.1 Original Cost Estimate ............................................................................................................ 13
4.2 Expandability .......................................................................................................................... 13
4.3 Quantities ................................................................................................................................ 14
4.4 Unit Costs ................................................................................................................................ 15
4.5 Indirect Costs ........................................................................................................................... 16
4.6 Interest During Construction and Financing Costs ................................................................. 16
4.7 Changes from 1983 Design ..................................................................................................... 16
4.7.1 Camps .......................................................................................................................... 16
4.7.2 Access .......................................................................................................................... 16
4.7.3 Transmission ................................................................................................................ 17
4.8 Conclusions ............................................................................................................................. 17
5 Project Development Schedule ........................................................................................................ 19
6 Project Development Issues ............................................................................................................. 21
6.1 Engineering ............................................................................................................................. 21
6.2 Siltation ................................................................................................................................... 21
6.3 Seismicity ................................................................................................................................ 21
6.4 Climate Change ....................................................................................................................... 21
6.5 Environmental Issues .............................................................................................................. 21
6.5.1 Fisheries Impacts ......................................................................................................... 22
6.5.2 Botanical Impacts ........................................................................................................ 22
6.5.3 Wildlife Impacts .......................................................................................................... 23
6.5.4 Cultural Resource Impacts ........................................................................................... 23
6.5.5 Carbon Emissions ........................................................................................................ 23
7 References ......................................................................................................................................... 25
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Tables
Table 1 - Susitna Summary ............................................................................................................. 2
Table 2 - Summary of Susitna Project Alternatives ........................................................................ 9
Table 3 - Firm Capacity and Energy Estimates ............................................................................ 10
Table 4 - Estimated Total Fill Volumes ........................................................................................ 14
Table 5 - Watana Water Conduit and Powerhouse Size Parameters ............................................ 15
Table 6 - Alternate Project Configuration Cost Summary Table (Millions of US Dollars) ......... 18
Table 7 - Power Generation Time Estimates ................................................................................ 20
Figures
Figure 1 - Susitna River Hydrologic Variation ............................................................................... 7
Figure 2 - Firm Capacity ............................................................................................................... 11
Figure 3 - Watana Dam Configurations ........................................................................................ 13
Figure 4 - Proposed Access Route ................................................................................................ 17
Appendices
Appendix A Energy Analysis Input and Results
Appendix B Detailed Cost Estimates
Appendix C Detailed Schedules
Appendix D Climate Change Analyses
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1 Executive Summary
A hydroelectric project on the Susitna River has been studied for more than 50 years and is again
being considered by the State of Alaska as a long term source of energy. In the 1980s, the project
was studied extensively by the Alaska Power Authority (APA) and a license application was
submitted to the Federal Energy Regulatory Commission (FERC). Developing a workable
financing plan proved difficult for a project of this scale. When this existing difficulty was
combined with the relatively low cost of gas-fired electricity in the Railbelt and the declining
price of oil throughout the 1980s, and its resulting impacts upon the State budget, the APA
terminated the project in March 1986.
In 2008, the Alaska State Legislature authorized the Alaska Energy Authority (AEA) to perform
an update of the project. That authorization also included a Railbelt Integrated Resource Plan
(RIRP) to evaluate the ability of this project and other sources of energy to meet the long term
energy demand for the Railbelt region of Alaska. Renewable hydroelectric power is of particular
interest to the railbelt because of its potential to provide stable power costs for the region. Of all
the renewable resources in the railbelt region, the Susitna projects are the most advanced and
best understood.
HDR was contracted by AEA to update the cost estimate, energy estimates and the project
development schedule for a Susitna River hydroelectric project. This report summarizes the
results of that study. The initial alternatives reviewed were based upon the 1983 FERC license
application and subsequent 1985 amendment which presented several project alternatives:
Watana. This alternative consists of the construction of a large storage reservoir on the
Susitna River at the Watana site with an 885-foot-high rock fill dam and a six-unit
powerhouse with a total installed capacity of 1,200 megawatts (MW).
Low Watana Expandable. This alternative consists of the Watana dam constructed to a
lower height of 700 feet and a four-unit powerhouse with a total installed capacity of
600 MW. This alternative contains provisions that would allow for future raising of the
dam and expansion of the powerhouse.
Devil Canyon. This alternative consists of the construction of a 646-foot-high concrete
dam at the Devil Canyon site with a four-unit powerhouse with a total installed capacity
of 680 MW.
Watana/Devil Canyon. This alternative consists of the full-height Watana development
and the Devil Canyon development as presented in the 1983 FERC license application.
The two dams and powerhouses would be constructed sequentially without delays. The
combined Watana/Devil Canyon development would have a total installed capacity of
1,880 MW.
Staged Watana/Devil Canyon. This alternative consists of the Watana development
constructed in stages and the Devil Canyon development as presented in the 1985 FERC
amendment. In stage one the Watana dam would be constructed to the lower height and
the Watana powerhouse would only have 4 out of the 6 turbine generators installed, but
would be constructed to the full sized powerhouse. In stage two the Devil Canyon dam
and powerhouse would be constructed. In stage three the Watana dam would be raised to
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its full height, the existing turbines upgraded for the higher head, and the remaining 2
units installed. At completion, the project would have a total installed capacity of
1,880 MW.
As the RIRP process defined the future railbelt power requirement it became evident that lower
cost hydroelectric project alternatives, that were a closer fit to the energy needs of the railbelt,
should be sought. As such, the following single dam configurations were also evaluated:
Low Watana Non-Expandable. This alternative consists of the Watana dam constructed
to a height of 700 feet, along with a powerhouse containing 4 turbines with a total
installed capacity of 600 MW. This alternative has no provisions for future expansion.
Lower Low Watana. This alternative consists of the Watana dam constructed to a
height of 650 feet along with a powerhouse containing 3 turbines with a total installed
capacity of 390 MW. This alternative has no provisions for future expansion.
High Devil Canyon. This alternative consists of a roller-compacted concrete (RCC) dam
constructed to a height of 810 feet, along with a powerhouse containing 4 turbines with a
total installed capacity of 800 MW.
Watana RCC. This alternative consists of a RCC Watana dam constructed to a height of
885 feet, along with a powerhouse containing 6 turbines with a total installed capacity of
1,200 megawatts (MW).
The results of this study are summarized in Table 1.
Table 1 - Susitna Summary
Alternative Dam Type
Dam
Height
(feet)
Ultimate
Capacity
(MW)
Firm
Capacity,
98%
(MW)
Construction
Cost
($ Billion)
Energy
(GWh/yr)
Schedule
(years from
start of
licensing)
Lower Low
Watana Rockfill 650 390 170 $4.1 2,100 13-14
Low Watana Non-
expandable Rockfill 700 600 245 $4.5 2,600 14-15
Low Watana
Expandable Rockfill 700 600 245 $4.9 2,600 14-15
Watana Rockfill 885 1,200 380 $6.4 3,600 15-16
Watana RCC RCC 885 1,200 380 $6.6 3,600 15-16
Devil Canyon Concrete Arch 646 680 75 $3.6 2,700 14-15
High Devil Canyon RCC 810 800 345 $5.4 3,900 13-14
Watana/Devil
Canyon
Rockfill/Concrete
Arch 885/646 1,880 710 $9.6 7,200 15-20
Staged
Watana/Devil
Canyon
Rockfill/Concrete
Arch 885/646 1,880 710 $10.0 7,200 15-24
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In all cases, the ability to store water increases the firm capacity over the winter. Projects
developed with dams in series allow the water to be used twice. However, because of their
locations on the Susitna River, not all projects can be combined. The Devil Canyon site
precludes development of the High Devil Canyon site but works well with Watana. The High
Devil Canyon site precludes development of Watana but could potentially be paired with other
sites located further upstream.
Development of any of the alternatives for the Susitna River will require careful consideration of
many factors. Environmental issues, climate change and sedimentation are discussed in this
report and the risk associated with these issues is considered manageable. An updated evaluation
of seismicity has been done by others and this risk is also considered manageable.
Hydroelectric power has many economic and environmental benefits including long-term rate
stabilization. Because the cost of the water (fuel) is essentially free and maintenance costs are
minimal, the cost per kilowatt hour is driven largely by the project finance terms and is not
subject to fluctuations in fuel cost.
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2 Background
The Susitna River has its headwaters in the mountains of the Alaska Range about 90 miles south
of Fairbanks. It flows generally southwards for 317 miles before discharging into Cook Inlet just
west of Anchorage. Contained entirely within the south central Railbelt region, the Susitna River
is situated between the two largest Alaska population centers of Anchorage and Fairbanks.
The Bureau of Reclamation first studied the Susitna River’s hydroelectric potential in the early
1950s, with a subsequent review by Corps of Engineers in the 1970s. In 1980, the Alaska Power
Authority (APA; now the Alaska Energy Authority) commissioned a comprehensive analysis to
determine whether hydroelectric development on the Susitna River was viable. Based on those
studies, the APA submitted a license application to the Federal Energy Regulatory
Commission (FERC) in 1983 for the Watana/Devil Canyon project on the Susitna River. The
license application was amended in 1985 for the construction of the Staged Watana/Devil
Canyon project at an estimated cost of $5.4 billion (1985 dollars).
Developing a workable financing plan proved difficult for a project of this scale. When this
existing difficulty was combined with the relatively low cost of gas-fired electricity in the
Railbelt and the declining price of oil throughout the 1980s, and its resulting impacts upon the
State budget, the APA terminated the project in March 1986.
At that point, the State of Alaska had appropriated approximately $227 million to the project
from FY79-FY86, of which the project had expended $145 million to fund extensive field work,
biological studies, and activities to support the FERC license application. Though the APA
concluded that project impacts were manageable, the license application was withdrawn and the
project data and reports were archived to be available for reconsideration sometime in the future.
In 2008, the Alaska State Legislature, in the FY 2009 capital budget, authorized the AEA to
reevaluate the Susitna Hydro Project as it was conceived in 1985. The authorization also
included funding a Railbelt Integrated Resource Plan (RIRP) to evaluate various sources of
electrical power to satisfy the long term energy needs for the Railbelt portion of Alaska. A
Susitna River hydroelectric project could play a significant role in meeting these needs.
2.1 Project Scope
The scope of this study was to collect and review pertinent information from the original studies
and license application from the 1980’s and re-estimate the project energy, costs and
development schedule.
The initial 1982 FERC license application and subsequent 1985 amendment analyzed several
project alternatives:
Watana. This alternative consists of the construction of a large storage reservoir on the
Susitna River at the Watana site with an 885-foot-high rock fill dam and a six-unit
powerhouse with a total installed capacity of 1,200 megawatts (MW).
Low Watana Expandable. This alternative consists of the Watana dam constructed to a
lower height of 700 feet and a four-unit powerhouse with a total installed capacity of
600 MW. This alternative contains provisions that would allow for future raising of the
dam and expansion of the powerhouse.
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Devil Canyon. This alternative consists of the construction of a 646-foot-high concrete
dam at the Devil Canyon site with a four-unit powerhouse with a total installed capacity
of 680 MW.
Watana/Devil Canyon. This alternative consists of the full-height Watana development
and the Devil Canyon development as presented in the 1983 FERC license application.
The two dams and powerhouses would be constructed sequentially without delays. The
combined Watana/Devil Canyon development would have a total installed capacity of
1,880 MW.
Staged Watana/Devil Canyon. This alternative consists of the Watana development
constructed in stages and the Devil Canyon development as presented in the 1985 FERC
amendment. In stage one the Watana dam would be constructed to the lower height and
the Watana powerhouse would only have 4 out of the 6 turbine generators installed, but
would be constructed to the full sized powerhouse. In stage two the Devil Canyon dam
and powerhouse would be constructed. In stage three the Watana dam would be raised to
its full height, the existing turbines upgraded for the higher head, and the remaining 2
units installed. At completion, the project would have a total installed capacity of
1,880 MW.
As the RIRP process defined the future railbelt power requirement it became evident that lower
cost hydroelectric project alternatives, that were a closer fit to the energy needs of the railbelt,
should be sought. As such, the following single dam configurations were also evaluated:
Low Watana Non-Expandable. This alternative consists of the Watana dam constructed
to a height of 700 feet, along with a powerhouse containing 4 turbines with a total
installed capacity of 600 MW. This alternative has no provisions for future expansion.
Lower Low Watana. This alternative consists of the Watana dam constructed to a
height of 650 feet along with a powerhouse containing 3 turbines with a total installed
capacity of 390 MW. This alternative has no provisions for future expansion.
High Devil Canyon. This alternative consists of a roller-compacted concrete (RCC) dam
constructed to a height of 810 feet, along with a powerhouse containing 4 turbines with a
total installed capacity of 800 MW.
Watana RCC. This alternative consists of a RCC Watana dam constructed to a height of
885 feet, along with a powerhouse containing 6 turbines with a total installed capacity of
1,200 megawatts (MW).
Preliminary energy, cost, and schedule estimates for the analyzed alternatives are described in
the following sections.
3 Preliminary Energy Estimate
3.1 Hydrologic Analysis
At the time the original study was issued in 1983 the hydrologic record contained data from 1950
to 1981. To develop an updated energy estimate for the Susitna hydroelectric project
alternatives, a synthesized hydroelectric record for each site was created by a drainage area
proration of daily flow data from United States Geological Survey (USGS) gage 1529000 at
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Gold Creek. USGS gage 1529000 has a period of record from water year 1950-1996 and 2002-
2008.
The hydrology of the upper Susitna Basin is dominated by melt water from snow and glaciers in
the spring and summer, and substantial freezing during the winter months. As a result, a majority
of the flow occurs between mid-April and mid-October. The following figure shows the average
monthly flow at the Watana dam site for each year of record.
Figure 1 - Susitna River at Watana Hydrologic Variation
The manner in which precipitation and runoff might be affected by the impacts of either natural
variability and/or potential climate change is discussed at the end of this report.
3.2 Evaluation of Firm Winter Capacities and Average Annual Energy
The amount of energy that can be produced from hydroelectric projects is a function of the
amount of available water and in the case of storage projects, how the available water can be
regulated (systematically released). For the RIRP evaluation process, in addition to the average
annual energy, the firm capacity attainable during winter months is of particular importance. For
hydroelectric projects, the firm capacity is almost always lower than the installed generation
capacity for a project. For the purposes of this study work, firm capacity is defined as:
“The amount of power the project can generate on a continuous
basis from Nov. 1 through April 30 with 100% reliability”.
The firm capacity is always driven by low periods in the hydrologic cycle. Since the hydrologic
cycle varies, it is also desired to know at what level of reliability the project can generate at
levels higher than the firm capacity. It should be noted that this is only one manner of
regulation. The water can be regulated in a variety of different means in order to achieve other
objectives, such as peaking, spinning reserve or backup capacity.
For this study, the average annual energy and winter plant capacities for the alternatives were
estimated using a HDR proprietary energy modeling software tool customized for this particular
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purpose (Computer Hydro-Electric Operations and Planning Software or (CHEOPS)). Major
assumptions used in the modeling efforts are presented below.
3.3 Model Assumptions and Data Sources
Inflow hydrology was based upon USGS gage #1529000 located at Gold Creek on the
Susitna River and scaled by a drainage area correction factor representing each of the
dam sites.
Reservoir capacity and area curves for the Watana and Devil Canyon alternatives were
based on information presented in the 1985 FERC application. For the High Devil
Canyon project this data was derived from USGS topographical data.
Tailwater curves for the Watana and Devil Canyon projects were obtained from the 1985
FERC application and estimated for High Devil Canyon.
Operating reservoir levels were obtained from the 1985 FERC application for the
Watana, Low Watana and Devil Canyon projects, from the 1982 Acres feasibility study
for the High Devil Canyon project, and estimated for the Lower Low Watana project.
Environmental flow release constraints were as presented in the 1985 FERC application
and scaled according to drainage areas for the various sites.
Evaporation coefficients were obtained from the 1985 FERC application. Total reservoir
evaporation was estimated in the 1985 FERC application to be between one (1) and three
(3) inches per month in summer, with negligible evaporation during winter months.
Equipment performance was based on vendor data obtained in 2008 specifically for the
Watana and Devil Canyon projects and was assumed to be representative for the other
projects.
Headloss estimates were based on the water conveyance design from the 1985 FERC
application for the Watana and Devil Canyon alternatives and the 1982 Acres feasibility
study for the High Devil Canyon alternative.
The reservoir was assumed to start full at the beginning of the simulation and was
allowed to fluctuate over the remaining period of the simulation.
Generation from Nov. 1 to April 30, “winter,” was at a constant capacity level (“block
loaded”).
Generation from May 1 to Oct. 31, “summer,” was to maximize energy with the objective
of the reservoir being full on Nov. 1.
Rule curves for summer target reservoir elevations were developed for each alternative
using a mass balance approach. The ratio of the average monthly inflow volume to the
average annual inflow volume during each of the reservoir filling months were used to set
target elevations for the reservoir.
Energy losses of 1.5 percent for un-scheduled outages and 2 percent for transformer
losses were applied to the total generation.
Active storage remained constant over the simulation period. Dead storage in the
reservoirs was assumed to be sufficient to contain sedimentation loads.
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No ramping rate restrictions were imposed on either reservoir drawdown or downstream
flow.
To determine the firm capacity for the combined Watana and Devil Canyon projects, the
regulated flow from Watana was assumed to pass unregulated through Devil Canyon with the
Devil Canyon pool at maximum operating level.
Key input parameters related to energy generation are shown in Table 2 below.
Table 2 - Summary of Susitna Project Alternatives
Lower Low
Watana
Low Watana
(Both
Alternatives)
Watana
(Both
Alternatives)
Devil Canyon High Devil
Canyon
Dam Type Rockfill Rockfill Rockfill or
RCC Concrete Arch RCC
Dam Height (ft) 650 700 885 646 810
Gross Head (ft) 495 557 734 605 729
Net Head (Max Flow) (ft) 481 543 729 598 707
Maximum Plant Flow (cfs) 10,700 14,500 22,300 14,000 14,800
Number of Units 3 4 6 4 4
Nameplate Capacity (MW) 390 600 1200 680 800
Maximum Pool Elevation (ft) 1951 2014 2193 1456 1751
Minimum Pool Elevation (ft) 1850 1850 2065 1405 1605
Tailwater Elevation
(Max Flow) (ft) 1456 1457 1459 851 1022
Usable Storage
(acre-ft) 1,536,200 2,704,800 3,888,50 310,000 2,254,700
3.4 Model Operation
For each alternative, 54 years of daily inflow data was used to determine each alternative’s
ability to meet a range of winter energy production targets and maximize summer generation.
For each day from November through April the flow through the powerhouse was limited to the
amount necessary to satisfy a prescribed capacity demand given the available head,
environmental flow constraints, and reservoir operational restrictions. During the months of
May through September energy production each day was maximized if the reservoir elevation
was above the target rule curve. If the reservoir elevation was below the target rule curve then
generation was limited to the amount that would allow the downstream environmental flow
constraints to be met. The simulation was repeated at various increasing winter load demands
until the maximum firm capacity was determined.
To better quantify the effect of storage and extreme low water years on the firm winter capacity,
winter load levels in excess of the firm capacity were also evaluated. The results of this analysis
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are expressed as a capacity at a given percent exceedance level. For example, a project might
have a firm capacity of 250 MW at a 100% exceedance level and a firm capacity of 300 MW at a
98% exceedance level. This would mean that the project could provide 250 MW 100% of the
time in the winter over the simulation period or 300 MW 98% of the time over the winter. The
large change in firm capacity between the 100% exceedance level and the 98% exceedance level
for all alternatives is primarily due to a single low water year in 1970.
The resulting firm capacities and average annual energy production estimates are presented in
Figure 2 and partially summarized in Table 3. Detailed input assumptions and results of these
energy analyses are provided in Appendix A of this report. The average annual energy
production was relatively constant over the range of winter power demand levels that were
modeled.
Table 3 - Firm Capacity and Energy Estimates
Alternative Firm Winter Capacity
(MW)
98% Winter
Capacity (MW)
Average Annual Energy
Production (GWh)
Lower Low Watana 100 170 2,100
Low Watana (both alternatives) * 150 245 2,600
Watana (both alternatives) ** 250 380 3,600
Watana/Devil Canyon *** 470 710 7,200
Devil Canyon 50 75 2,700
High Devil Canyon 250 345 3,900
* Low Watana Expandable and Low Watana Non-Expandable have the same energy characteristics.
** Watana Rockfill and Watana RCC have the same energy characteristics.
*** Watana/Devil Canyon and the Staged Watana/Devil Canyon have similar energy characteristics.
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Figure 2 - Firm Capacity
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
30% 40% 50% 60% 70% 80% 90% 100%Firm Capacity (MW)% Exceedance
Watana and Devil Canyon
Watana
High Devil Canyon
Low Watana
Lower Low Watana
Devil Canyon
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4 Estimates of Probable Project Development Costs
4.1 Original Cost Estimate
In 1982 the cost for developing the complete full Watana/Devil Canyon project was estimated to
be $5.0 billion (1982 dollars). In 1985 the cost for developing the staged Watana/Devil Canyon
project was $5.4 billion (1985 dollars).
The Devil Canyon and High Devil Canyon alternatives were as envisioned in the 1980’s. The
four rockfill Watana Dam configurations considered in this evaluation are depicted in Figure 3
below.
Figure 3 - Watana Dam Configurations
The estimates for the Watana, Low Watana-Expandable, Devil Canyon and Staged Watana-
Devil Canyon alternatives were developed in depth in a March 2009 Interim report and were
revised to reflect changes primarily in transmission, access and camp costs. Using this
information as a base, new estimates were made for the development costs of the Low Watana
Non-Expandable and of the Lower Low Watana alternatives. Cost estimates of $5.4 billion for
the High Devil Canyon RCC and $6.6 billion for the Watana RCC alternatives were provided by
a separate contractor using similar assumptions and are presented here for completeness of
information. The following discussion details the basis for the cost estimates for the Watana
embankment projects, the assumptions that were used in creating those estimates, and provides a
summary of the projected construction costs.
4.2 Expandability
The Low Watana alternative, as proposed in previous studies, included provisions for eventual
expansion of the dam from 700 feet to a height of approximately 885 feet and an increase in
powerhouse capacity from 800 MW to 1200 MW. The most notable of these provisions are the
design of the dam cross section and construction of the powerhouse and water conduits to their
ultimate capacity. The two non-expandable alternatives contain no provisions for future
expansion.
885FULL WATANA
LOWER
LOW WATANA
LOW WATANA -
EXPANDABLE
LOW WATANA -
NON-EXPANDABLE
650
0
500
1000
700
(Ref.)
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For the Low Watana Expandable alternative the dam cross-section is expanded on the upstream
side to provide the opportunity to later raise the dam. This results in additional fill material due
to the wider base. The powerhouse, powerhouse equipment, and water conveyance scheme
would be built to house six units, but only four turbines would be initially installed.
For the Low Watana Non-expandable alternative the cross-section is narrower and does not
accommodate expansion of the dam at a later time. Similarly the powerhouse and water conduit
features are sized for only four turbine/generator units instead of six.
4.3 Quantities
Quantities for the construction cost estimates were based upon detailed estimates developed as
part of the 1982 Acres feasibility study for the full sized Watana project and the Devil Canyon
project. To estimate the quantities of the smaller Watana alternatives, the full sized Watana
quantities were scaled based on the size of the development. As part of a separate report,
quantities were developed for the High Devil Canyon alternative based upon a new conceptual
design using RCC construction.
Table 4 summarizes the embankment fill volumes that were used for the cost estimates. The
dam heights and fill volumes of the Watana and Low Watana Expandable configurations were
adopted directly from the 1985 FERC application. The embankment volumes for the Lower
Low Watana and Low Watana Non-Expandable alternatives were estimated assuming a 2:1 side
slope on the downstream portion of the dam and a 2.4:1 side slope on the upstream portion of the
dam as were assumed for the other alternatives. Volume changes were limited to the rock-fill
and riprap portion of the dam only. The concrete volumes for the Devil Canyon, Watana RCC,
and High Devil Canyon alternatives are shown for comparison.
Table 4 - Estimated Total Fill Volumes
Alternative Type Total Fill Volume(cy)
Watana Rockfill 61,000,000
Low Watana Expandable Rockfill 32,000,000
Low Watana Non-Expandable Rockfill 22,000,000
Lower Low Watana Rockfill 17,000,000
Devil Canyon Concrete Arch 1,300,000
Watana* RCC 15,000,000
High Devil Canyon* RCC 11,600,000
* R&M, 2009.
The quantity estimates for the water conduit layouts and powerhouses for all alternatives were
based on the 1985 layout as opposed to the 1983 layout. The 1983 arrangement used a separate
penstock for each unit with a very long conveyance scheme. The 1985 arrangement employed a
headrace for every two units bifurcating into dedicated penstocks. The total length of
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conveyance was less than half that of the 1983 design. To maintain consistency with the energy
model, and to further refine the cost estimates, the 1985 configuration was used for this study.
Table 5 summarizes the design features that were assumed in each estimate. The powerhouse
and water conveyance systems for Watana and the Low Watana Expandable alternatives were
designed to service six units as contemplated in 1983. However, the water conduit layout
reflects the 1985 arrangement with three headraces bifurcated into six penstocks and discharged
into two tailraces. Low Watana Non-Expandable was assumed to be built to accommodate a
four-unit powerhouse with two headraces, four penstocks and a single tailrace. Lower Low
Watana was designed for a three-unit powerhouse with one headrace, three penstocks, and one
tailrace. The diameters of the water conduits were sized to be consistent with the 1985 design.
The powerhouse structures were also scaled accordingly.
Table 5 - Watana Water Conduit and Powerhouse Size Parameters
Item
Lower
Low
Watana
Low Watana
Non-Exandable
Low Watana
Expandable Watana
Number of Units 3 4 4 6
Unit Size (MW) 130 150 150 200
Plant Nameplate Capacity (MW) 390 600 600 1200
# of Headraces 1 2 3 3
Headrace Diameter (ft) 24 24 24 24
# of Penstocks 3 4 6 6
Concrete Lined Penstock Diameter (ft) 18 18 18 18
Steel Penstock Diameter (ft) 15 15 15 15
# of Tailrace Tunnels 1 1 2 2
Tailrace Diameter (ft) 34 34 34 34
4.4 Unit Costs
U.S. Cost, a company specializing in creating cost estimates for large capital infrastructure
projects, developed unit prices for the materials detailed in the 1982 estimate in 2008 dollars.
This cost data was used to develop the estimates presented in the Interim Report and the same
pricing was used in this study. Lump sum items were inflated using a construction cost index.
For the water-to-wire turbine-generator equipment estimates, budget pricing for the Watana
alternative was requested directly from manufacturers. The water-to-wire equipment includes
turbines, generators, turbine shutoff valves, and other miscellaneous mechanical and electrical
equipment, including installation costs. The equipment costs for other smaller alternatives were
developed by scaling the Watana vendor quotes on a per kilowatt basis.
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4.5 Indirect Costs
A contingency of 20 percent was added to the direct construction costs to reflect level of design
and uncertainty in the project.
Project licensing, environmental studies and engineering design were estimated at 7 percent of
direct construction costs. Construction management was estimated at 4 percent of the direct
construction costs, and has been included as a separate line item.
4.6 Interest During Construction and Financing Costs
Costs associated with interest during construction and project financing are not included in the
estimates.
4.7 Changes from 1983 Design
The camps, access roads and transmission, infrastructure assumptions used in the 1983
configuration have been modified as discussed below.
4.7.1 Camps
Reductions were made in the scale of the permanent and construction camps needed to
accommodate the workers. These changes were made based on the fact that permanent town
facilities were no longer necessary due to advances in remote project operation. It was also
assumed that due to modern construction methods, the number of construction personnel could
be reduced. It was assumed that 750 people would need to be housed for the Lower Low Watana
arrangement, 825 people for Low Watana and 900 people for Watana. In 1983 it was originally
assumed that housing would be provided for 3000 people plus families. Budget pricing for the
construction camp was provided by vendors.
4.7.2 Access
For all the Watana alternatives, access is assumed to be via the Denali Highway from the north
as shown in Figure 4. The route would include the upgrade of 21 miles of the Denali Highway to
a construction grade road and the construction of approximately 40 miles of new road to the
Watana site. The price per mile of new road has been assumed at $3M/mile which is the current
budgetary estimate of the Alaska Department of Transportation and Public Facilities for the road
to Bettles and Umiat from the Dalton Highway which is similar in nature to the road that would
be required for a Susitna project. Upgrading of the Denali Highway has been assumed to be
$1M/mile and local site roads have been estimated at $750k/mile.
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Figure 4 - Proposed Access Route
For the Devil Canyon and High Devil Canyon alternatives, rail access was assumed and will
originate on the Parks Hwy near MP 156 and proceed upstream on the south side of the river.
4.7.3 Transmission
A separate study (EPS, 2009) has investigated the transmission lines and interconnection
requirements for the entire Alaska railbelt region as part of the RIRP process and the results are
incorporated here at the direction of the AEA. This study estimates that a transmission line from
the project site to the substation at Gold Creek would cost approximately $4.5M/mile.
Substation costs are estimated at $16M per location. No costs have been assumed to increase or
modify the regional transmission grid beyond the Gold Creek substation.
4.8 Conclusions
The approach, methodology and assumptions previously described resulted in the estimated
project costs detailed below in the summary table.
Parks
Highway
New
Road
Watana
Denali
Highway
Cantwell
Railroad
Gold Creek
HDR Alaska Susitna Hydroelectric Project Conceptual Alternatives Design Report 11/23/2009 18 Final Draft Table 6 - Alternate Project Configuration Cost Summary Table ($Millions) FERC Line # Line Item Name Lower Low Watana Low Watana Non-Expandable Low Watana Expandable Watana Watana RCC* Devil Canyon High Devil Canyon*Watana/ Devil Canyon Staged Watana/ Devil Canyon 71A Engineering, Env., and Regulatory (7%) $ 213 $ 236 $ 259 $ 338 $342 $191 $281 $501 $528 330 Land and Land Rights $ 121 $ 121 $ 121 $ 121 $121 $52 $121 $173 $173 331 Power Plant Structure Improvements $ 93 $ 115 $ 159 $ 159 $159 $165 $159 $324 $325 332.1-.4 Reservoir, Dams and Tunnels $ 1,415 $ 1,538 $ 1,718 $ 2,424 $2,307 $900 $1,803 $3,324 $3,485 332.5-.9 Waterways $ 590 $ 590 $ 677 $ 677 $558 $415 $552 $1,093 $1,191 333 Waterwheels, Turbines and Generators $ 213 $ 297 $ 297 $ 475 $487 $295 $487 $770 $834 334 Accessory Electrical Equipment $ 29 $ 41 $ 41 $ 72 $57 $38 $57 $110 $119 335 Misc Power Plant Equipment $ 17 $ 21 $ 32 $ 32 $32 $29 $32 $61 $61 336 Roads, Rails and Air Facilities $ 232 $ 232 $ 232 $ 280 $584 $535 $490 $388 $394 350-390 Transmission Features $ 177 $ 224 $ 224 $ 353 $322 $99 $119 $481 $481 399 Other Tangible Property $ 12 $ 16 $ 16 $ 20 $12 $16 $12 $36 $42 63 Main Construction Camp $ 150 $ 180 $ 180 $ 210 $244 $180 $189 $390 $440 71B Construction Management, 4% $ 122 $ 135 $ 148 $ 193 $195 $109 $161 $286 $302 Total Subtotal $ 3,384 $ 3,746 $ 4,104 $ 5,354 $5,420 $3,024 $4,463 $7,937 $8,375 Total Contingency $ 676 $ 749 $ 821 $ 1,071 $1,155 $605 $954 $1,587 $1,675 Total (Millions of Dollars, rounded) $ 4,100 $ 4,500 $ 4,900 $6,400 $6,600 $3,600 $5,400 $9,600 $10,000 * R&M (2009)
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5 Project Development Schedule
Updated schedules were developed for each of the project alternatives. These schedules extend
from approval, through licensing, design, construction, and commissioning. The primary purpose
of these schedules is to provide timelines for cash flow and estimated energy revenue to
determine economic feasibility. These schedules assume that:
Construction times are based on 1983 FERC license application.
The licensing process from start to FERC order is estimated at 7 to 10 or more years. We
have set a reasonable target of 8 years for the proposed project analysis, provided that the
effort is begun immediately, ambitiously, fully funded, and conducted in parallel with
environmental studies, engineering, and with active public outreach and cooperation by
stakeholders.
The FERC License Application will be based on the 1985 application, updated to reflect
more than 20 years of regulatory changes and changes in engineering and construction
methods.
Any new environmental studies will be based on data acquired during the studies in the
1980’s, updated to reflect present site conditions, public interests, wildlife, and
recreational needs.
Construction will begin immediately upon issuance of the license.
Roads and staging will be state permitted outside the FERC project and will begin several
years before FERC license, including pioneer and permanent roads, airports, bridges,
construction camps and staging areas. Building facilities in advance of the project license
is the most effective way to trim the projected timeline although there is some uncertainty
whether permits could be obtained to construct these facilities before the project license
is issued. The schedule for each of the project alternatives would be extended by one to
two years if this assumption is not valid.
Construction of diversion dams and tunnels will begin on issuance of the license, with
upstream and downstream coffer dams and tunnels to divert the Susitna River during
construction of main dams at Watana/Devil Canyon.
Spillway construction will follow diversion dam and tunnel construction, and will include
site preparation, approach channels, control structures, gates, stoplogs, chute, and
flip buckets for main and emergency spillways.
Dam construction at Watana will follow site preparation, grouting, and installation of a
pressure relief system.
The main dam construction at Devil Canyon will include a thin-arch concrete dam,
preceded by site preparation, foundations, abutments, and thrust blocks. Rock-fill saddle
dam construction will follow grouting and pressure relief system.
The powerhouse and transmission will include power intake, tunnels/penstock, surge
chamber, tailrace, powerhouse, turbine/generators, mechanical/electrical systems,
switchyard, control buildings, and transmission lines.
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Reservoir filling will be based on the latest hydrologic data for inflow and turbine data
for outflow.
Devil Canyon construction will commence immediately upon completion of Watana for
the Watana/Devil Canyon alternative.
Table 7 - Power Generation Time Estimates
Alternative Generation of first power
(years)*
Generation of full power
(years)*
Lower Low Watana 13 14
Low Watana (both alternatives) 14 15
Watana (both alternatives) 15 16
Devil Canyon 14 15
High Devil Canyon 13 14
Watana/Devil Canyon 15 20
Staged Watana/Devil Canyon 15 24
*From start of licensing
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6 Project Development Issues
Development of a hydroelectric project on the Susitna River would face a variety of issues over
their design lifetime. The design lifetime for a modern dam is greater than 100 years. The
following discussion is not intended to be all inclusive but rather highlight the likely major areas
of concern.
6.1 Engineering
The projects being contemplated for the Susitna River would be on the larger end of the scale in
the world in terms of size of the dams. Projects of this size have not been undertaken in the
United States for many decades. As such, a major engineering effort will be required.
6.2 Siltation
Rivers, by nature, transport the products of erosion to the oceans. Dams interrupt this flow of
material. Given time the effective amount of storage in the reservoir behind the dam can
diminish. The alternatives investigated here have been designed with dead storage to
accommodate bedload and it is not expected that siltation will have any detrimental affect on the
energy projected energy production of any of the projects during their design lifetime.
6.3 Seismicity
Seismic (earthquake) events have the potential to effect hydroelectric projects. The main areas
of concern are damage from ground shaking, opening of faults along the dam axis, landslides and
settlement, and the creation of large waves in the reservoir. The previous studies on seismicity
have concluded that these concerns can be designed for and therefore do not pose a significant
threat. New analytic methods are now available to evaluate more complex seismic situations and
these evaluations, along with the most stringent safety factors would be incorporated into a
modern project design (R&M, 2009).
6.4 Climate Change
There has been much discussion about climate change and what the effects of climate change
will be on river flows. Analyses of the potential affects of climate change on the Susitna River
are included in Appendix D. The annual runoff from the Susitna River basin shows remarkable
balance during very disparate climate regimes. The analyses support the consistent supply of
water from the basin precipitation to support hydro-power generation regardless of the climate
fluctuations. While global climate models suggests additional warming may impact the Arctic
and Alaska, it seems very unlikely that these impacts will cause an unbalance in the runoff
production of the basin.
Based on this, there is no conclusive evidence to suggest that runoff will be statistically different
in the next 50 years from what it has been in the last 50 years.
6.5 Environmental Issues
After the Susitna project was discontinued in 1986 a database of 3,573 documents was created.
In September 2008, the 87 most-relevant documents were scanned into HDR’s files, of which 18
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of the most relevant environmental documents were summarized. A synthesis of the 7 most-
pertinent documents was completed. Because not all of the documents were summarized, some
relevant information has likely been overlooked; however, most information was included in the
synthesis.
These documents contain information on potential impacts of the proposed project and
mitigation proposals for those impacts. Specifically, the documents deal with fisheries resources,
botanical resources, wildlife resources, and cultural resources in the potential project area. The
documents divide the Susitna River Basin into 4 geographic regions:
Impoundment zones
Middle Susitna River
Lower Susitna River
Access roads and transmission lines
The potential impacts and mitigation options are discussed for each category in each geographic
region as much as possible. It is important to note that not all categories will be impacted in all
geographic regions. Mitigation for the proposed impacts is divided into the following categories:
avoidance, minimization, rectification, reduction, and compensation. Avoidance is always the
preferred mitigation, though it is not usually feasible. Compensation is the only mitigation option
for many of the impacts.
6.5.1 Fisheries Impacts
The fisheries resources have the highest potential to be impacted by the project. Most of the
potential impacts will occur in the middle Susitna River. There will be impacts due to changes in
water quality, thermal activity, the water’s suspended sediment load, reservoir draw-down
fluctuations, impoundment zone inundation, flow regime, and lost fish habitat. Not all impacts to
fish populations will be negative. For example, the increase in winter water temperatures could
lead to the creation of more overwintering habitat and thus greater fish survival; however, the
cooler spring water temperatures will slow fish growth.
In the Watana impoundment zone, 51 river miles will be inundated and transformed into
reservoir habitat. An additional 27 miles of tributary streams and 31 lakes will be inundated.
In the Devil Canyon impoundment zone 31 miles of the main river channel will be inundated and
an additional 6 miles of tributary streams will be impacted.
Mitigation for these impacts was proposed by compensation through land acquisition, habitat
modification, and reservoir stocking.
6.5.2 Botanical Impacts
The project area contains 295 vascular plant species, 11 lichen genera, and 7 moss taxa. Low
Watana inundation will permanently remove 16,000 acres of vegetation. Devil Canyon
inundation will permanently remove 6,000 acres of vegetation. Watana inundation will
permanently remove an additional 16,000 acres of vegetation. There will be a total of 38,000
acres of vegetation permanently removed. Most of the vegetation inundated will be spruce forest.
An additional 836 acres of vegetation will be permanently removed due to access road
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construction. In the transmission corridor affect on vegetation will be minimal due to
intermittent placement of control stations, relay buildings, and towers.
There will be limited botanical impacts downstream from the reservoir(s). These involve changes
to the vegetation due to a more stable environment. Due to flow regulation there will no longer
be major flooding events, which destroy the riparian vegetation; instead; rather, there will be
succession of the riparian vegetation and colonization of new floodplains. The increase in winter
water temperatures will decrease the amount of ice scouring that occurs, which will result in
effects similar to those caused by the decrease in flooding.
Botanical resource mitigation will consist largely of compensation for permanently removed
vegetation.
6.5.3 Wildlife Impacts
Within the Susitna River Basin there are 135 bird species, 16 small-mammal species, and
18 large-mammal and furbearing species. There are currently no known listed endangered
species in the project area. There will be 5 classes of potential impacts to terrestrial vertebrates:
Permanent habitat loss, including flooding of habitat and covering with gravel pads or roads.
Temporary habitat loss and habitat alteration resulting from reclaimed and revegetated areas such
as borrow pits, temporary right of ways, transmission corridors, and from alteration of climate
and hydrology.
Barriers, impediments, and hazards to movement.
Disturbances associated with project construction and operation.
Consequences of increased human access not directly related to project activities.
Mitigation for the proposed impacts involve mostly compensation since there will be permanent
habitat loss for most species.
6.5.4 Cultural Resource Impacts
Within the proposed project area, 297 historic and prehistoric archaeological sites were located.
An additional 22 sites were already on file. Sites located within 500 feet of the reservoir’s
maximum extent may be indirectly impacted due to slumping from shoreline erosion. Indirect
impacts may also result from vandalism due to increase in access to the sites. The project has the
potential to impact 140 sites. None of these sites will occur in the proposed road corridor or
transmission lines. The majority of these sites are relatively small prehistoric sites.
Mitigation for the lost cultural resources will mostly occur through data recovery. Preservation
would also be used for some sites. Options to consider include construction of protective barriers
to minimize erosion, controlled burial, or fencing of the site to restrict access.
Currently, there are a variety of federal, state, and local land use plans that encompass the
Susitna Basin.
6.5.5 Carbon Emissions
According to the United Nations working group on carbon emissions from freshwater reservoirs
the worst case carbon emissions from a reservoir in a boreal climate is 6.7 grams per square
meter per year (United Nations, 2009). For the Watana/Devil Canyon alternative this equates to
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465,000 metric tons of carbon per year or 0.065 metric tons per MWhr. The US Department of
Energy reports the average carbon emissions due to electric generation for the State of Alaska to
be 0.6261 metric tons per MWhr. Operation of the Susitna project has the potential to eliminate
up to 4 million metric tons of carbon production per year.
1 http://www.eia.doe.gov/cneaf/electricity/st_profiles/alaska.html
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7 References
Acres 1981. Susitna Basin Development Selection. Task 6 Development Section. Subtask 6.05
Development Section Report. Appendix F Single and Multi Reservoir Simulation
Studies.
Acres 1981. Susitna Hydroelectric Project. Task 6 Development Section. Subtask 6.05
Development Section Report. Plate 6.4. High Devil Canyon Layout.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 2 Engineering and
Economic Aspects. Section 12 Watana Development.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 2 Engineering and
Economic Aspects. Section 16 Devil Canyon Development.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 2 Engineering and
Economic Aspects. Section 11 Access Plan Selection.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 2 Engineering and
Economic Aspects. Section 16 Cost Estimates.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 6. Appendix C Cost
Estimates Final Draft.
Acres 1982. Susitna Hydroelectric Project Feasibility Report. Volume 1 Engineering and
Economic Aspects Sections 17 Development Schedules.
Entrix, 1985. Impoundment area impact assessment and mitigation plan. Susitna Hydroelectric
Project Impact Assessment and Mitigation Report No. 2. Entrix, Inc., Under contract to
Harza-Ebasco Susitna Joint Venture. Prepared for the Alaska Power Authority.
EPS 2009. Susitna Hydro Transmission Study. Report to AEA dated October 22, 2009
Harza Ebasco. 1985. Introduction to the Amendment to the License Application before the
Federal Energy Regulatory Commission. Chapter III Project Description.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 1. Exhibit
A Project Description. Sections 1- 15.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 15.
Exhibit F Project Design Plates.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 16.
Exhibit F Supporting Design Report.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 2. Exhibit
B Project Operation and resource Utilization. Section 3 Description of Project Operation.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Volume 2. Exhibit
B Project Operation and resource Utilization. Section 4 Power and Energy Production.
Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application. Exhibit D Project
Costs and Financing. Section 1 Estimates of Cost.
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Harza Ebasco. 1985. Susitna Hydroelectric Project Draft License Application Exhibit C
Proposed Construction Schedule.
Harza Ebasco. 1985a. Susitna Hydroelectric Project Draft License Application Volume 9 Exhibit
E Chapter 3 Sections 1 and 2 – Fish, Wildlife and Botanical Resources.
Harza Ebasco. 1985b. Susitna Hydroelectric Project Draft License Application Volume 10
Exhibit E Chapter 3 Section 3 – Fish, Wildlife and Botanical Resources.
Harza Ebasco. 1985c. Susitna Hydroelectric Project Introduction to the Amendment to the
License Application.
Harza Ebasco. 1985d. Susitna Hydroelectric Project Draft License Application Volume 11
Exhibit E Chapter 3 Sections 4, 5, 6 & 7 – Fish, Wildlife and Botanical Resources.
Harza Ebasco. 1985e. Susitna Hydroelectric Project Draft License Application Volume 12
Exhibit E Chapter 4, 5, and 6. – Cultural Resources, Socioeconomic Resources, and
Geological and Soil Resources.
R&M 2009. Susitna Project. Seismic Setting Review and Geologic and Geotechnical Data
Reports Review. Memo to AEA dated July 2, 2009
R&M 2009. Susitna Project. Watana and High Devil Canyon RCC Dam Cost Evaluation. Final
Report dated November 16, 2009.
United Nations Educational, Scientific and Cultural Organization. Scoping Paper: Assessment
of the GHG Status of Freshwater Reservoirs. April 2008
U.S. Cost 2008. 1982 to 2008 Cost Estimate for Susitna Hydroelectric Project.
Woodward-Clyde Consultants. 1984. Susitna Hydroelectric Project: Fish Mitigation Plan.
Prepared for the Alaska Power Authority.
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Appendix A:
Energy Analysis Input and Results
For the purposes of this submittal, the appendices have been attached as PDFs.
HDR Alaska Susitna Hydroelectric Project
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Appendix B:
Detailed Cost Estimates
For the purposes of this submittal, the appendices have been attached as PDFs.
HDR Alaska Susitna Hydroelectric Project
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Appendix C:
Detailed Schedules
For the purposes of this submittal, the appendices have been attached as PDFs.
HDR Alaska Susitna Hydroelectric Project
Conceptual Alternatives Design Report
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Appendix D:
Climate Change Analyses
For the purposes of this submittal, the appendices have been attached as PDFs.
APPENDIX B FINANCIAL ANALYSIS
ALASKA RIRP STUDY
Black & Veatch B-1 February 2010
APPENDIX B
FINANCIAL ANALYSIS
SNW 1420 Fifth Avenue, Suite 4300 Seattle, Washington 98101 Phone: (206) 628-2882 Fax: (206) 343-2103 2/3/2010 Regional Integrated Resource Plan Financial Analysis Summary Report Innovative Financing and Investment Strategies
1 Introduction The Regional Integrated Resource Plan (RIRP) is a 50-year, long-range plan tasked with identifying the optimal combination of generation and transmission capital improvement projects in the Railbelt region of Alaska. The objectives of the financial analysis portion of the plan are threefold : 1. Provide a high-level analysis of the capital funding capacity of each of the Railbelt utilities, given their current financial condition and assuming that each utility will borrow on its own, rather than utilizing a joint-powers structure or receiving assistance from the State of Alaska. 2. Analyze strategies to capitalize selected RIRP assets by integrating State and federal financing resources with debt capital market resources. Specifically, we look at ways to utilize State funding to: • mitigate construction risk, • lower capital cost prior to placing assets in service , and • extend the debt repayment term beyond terms available in the debt capital markets. 3. Develop a spreadsheet-based model that utilizes inputs from the RIRP model, including total capital requirements, demand-side management (DSM), fuel cost, CO2 cost, and operation and maintenance cost (O&M), and overlays realistic debt capital funding to provide a total cost to ratepayers of the optimal resource plan. Railbelt Utility Capital Capacity The non -profit organizational structure of generation and transmission (G&T) and distribution cooperatives makes it difficult for these entities to produce operating margins and build equity to the levels needed to access the public debt markets. Rate setting is designed to recover operating cost with moderate margins, and any capital in excess of minimal reserves is returned to coop members. Nevertheless, some coops, including Chugach Electric, are able to maintain coverage margins sufficient to secure investment grade credit ratings and utilize the debt capital market to fund asset expansion. Likewise, municipal governments face a similar rate-setting challenge in the form of political pressure to keep rates at levels just sufficient to cover operations and maintain net plant and equipment. In the following sections , we take a look at several key financial measures of coop and municipally owned utilities and utilize these measures to estimate the remaining debt capacity of each of the Railbelt utilities. To develop the framework for this analysis, we retrieved the publicly available financial reports from each utility’s website and the annual filings from the Regulatory Commission of Alaska’s website. Using these reports , we summarized each of the utilities’ current outstanding debt obligations, company equity, total assets and total plant. We used these figures to derive several important financial ratios, discussed in detail below, that are used by the investment community as well as the nationally recognized rating agencies (Moody’s, Standard & Poor’s, and Fitch) to determine the ability of each organization to manage its current and/or future debt obligations. It’s important to point out that, while no single financial ratio by itself is an accurate determinant of a utility’s ability to incur additional debt for capital projects, an analysis of a sampling of several ratios in conjunction with other non-financial metrics (e.g., demand growth, rate-setting authority,
2 political climate, etc.) helps to create some guidelines for how much debt could reasonably be considered and issued in the capital markets. Debt to Equity Ratio. The debt to equity ratio (or debt as a percentage of total capitalization) is derived by dividing a utility’s total debt by its net c apital. The rating agencies have developed median debt to equity ratios for each of the different types of utility organizational structures. For example, a G&T cooperative can expect to have a higher debt ratio percentage than a retail power distributer due to the need to finance large and relatively expensive generation and transmission assets. A summary of these utility medians for debt to equity is provided in the following table: 2008 Median Debt to Capitalization % By Utility System Type G&T Coop 82% Municipal Wholesale 93% Retail Self Generating 60% Retail Power Purchaser (Distribution) 40% Source: Fitch U.S. Public Power Peer Study, June 2009 The table below calculates the remaining debt capacity for each of the Railbelt utilities under varying debt to equity ratios to derive a total debt capacity amount given existing equity capitalization. Debt to equity capitalization for this analysis ranges from 40% to 80%. Railbelt Utility Additional Debt Capacity Based on Current Debt to Equity Ratios Existing Debt as of 12/31/20081 40% 60% 70% 80% ML&P $159,405,791 - $175,744,945 $362,920,220 730,502,349 Chugach 354,383,506 - - 9,355,443 260,137,205 MEA 89,128,488 - 48,090,737 129,409,217 277,237,086 HEA 148,257,837 - - - 99,152,015 GVEA 301,670,508 - - - 131,081,336 Seward 2 2 2 2 2 - $223,835,682 $501,684,880 $1,498,109,991 (1) 2008 Annual reports and 12/31/2008 Annual Reports to the Regulatory Commission of Alaska (2) The City of Seward was not included in this analysis due to lack of information regarding their Electric Enterprise Fund Our analysis found that the debt-to-capitalization ratio for each of the utilities is close to or higher than the median ratio for its organizational type. There does appear to be some additional bonding capacity available for each of the utilities under a G&T cooperative-type structure when compared to the Fitch median ratio of 82%. However, given the utilities’ existing debt burdens and current conditions in the financial markets, which have made it more difficult for lower rated power utilities to access capital, it is not clear that the six utilities could support debt capitalization much above 70%. Fitch Ratings specifically mentions that higher debt capitalization percentages can result in negative ratings pressure going forward1. At approximately 70% 1 Fitch Ratings, U.S. Public Power Peer Study, June 2009
3 debt capitalization, the six utilities together could support between $500 and $700 million of additional debt. At 80%, available additional debt capacity for the six utilities combined increases to approximately $1.5 billion. This analysis does not include the City of Seward’s capacity. Given its Electric Enterprise Fund asset base of $26 million (as of 2007), the overall borrowing capacity number would not change by a significant amount if the City of Seward were included. Debt to Funds Available for Debt Service. An important measure of operating leverage is the Debt to Funds Available for Debt Service ratio (Debt/FADS). This ratio measures a utility’s ability to handle its current fixed debt burden based on annual operating cash flow. A lower Debt/FADS ratio indicates either a low overall debt burden or a high operating cash flow, with the opposite being true for a higher Debt/FADS ratio. In the “A” rating category and higher, all but one G&T wholesale system rated by Fitch Ratings had a Debt/FADS ratio higher than 8.8 in 2008. For comparison purposes, the average (and median) Debt/FADS ratio for the Railbelt utilities in 2008 was approximately 8.4, with the highest being 13.66. The operating leverage of the six utilities would increase dramatically as capital spending and debt burden increase. An increase in the operating leverage ratio would cause ratings pressure for utilities maintaining a public credit rating and increased scrutiny by creditors including commercial banks and cooperative banks such as CFC or CoBank. RIRP Capital Requirements Relative to Railbelt Utility Debt Capacity. The preceding debt to equity and Debt/FADS discussions do not take into consideration several additional factors that are relevant to the collective debt capacity of the Railbelt utilities. These factors can impact debt capacity both positively and negatively and include amortiza tion of existing utility debt, the level of new debt required to maintain distribution infrastructure, and potential rate increases. While these factors are influential, they do not have sufficient positive impact to alter our opinion that the utilities individually do not have the capital capacity to fund the projects recommended by the RIRP. The scope of the RIRP projects is too great, and for certain individual projects, it is reasonable to conclude that there is no ability for a municipality or coop to independently secure debt financing without committing substantial amounts of equity or cash reserves. Specifically, these individual projects would include any that require large capital investment and have any of the following characteristics: exceptionally long construction period, significant construction risk, or significant technological risk. These types of risk are associated with equity rates of return and are rarely , if ever , borne by fixed income investors. The graphic to the right helps to put into context the scope of required RIRP capital investments relative to the estimated combined debt capacity of the Railbelt utilities. The lines toward th e bottom of the graph represent our view of the bracketed range of additional debt capacity Black & Veatch Plan 1A Capital Expenditures (Cumulative Total) $0 $2,500,000,000 $5,000,000,000 $7,500,000,000 $10,000,000,000 20112014201720202023202620292032203520382041204420472050205320562059High Debt CapacityLow Debt CapacityCapitalExpenditures
4 collectively for the Railbelt utilities, adjusted for inflation and customer growth over time . Railbelt Utility Debt Capacity Conclusions. The REGA study completed in 2008 concluded that the most cost effective approach to funding necessary Railbelt generation and transmission assets was to form a regional G&T. While SNW was not asked to validate this conclusion, we are of the opinion that a regional entity such as GRETC, with “all outputs” contracts migrating over time to “all requirements” contracts, will have greater access to capital than the combined capital capacity of the individual utilities. To be clear, our conclusion should not be interpreted to mean that a regional G&T agency would be able to execute the RIRP capital plan independent of any State or federal assistance; however , a regional G&T agency will have lower -cost access to debt capital than the utilities would have on their own. This is primarily due to two factors: (1) a regional G&T entity will eliminate the rate pressure/competition that naturally exists under the current Railbelt construct of each of the 6 utilities independently providing generation and transmission services to their customers, and (2) a regional G&T entity executing a utility-approved comprehensive RIRP plan with strong power purchase agreements will be better positioned with the rating agencies and private investors. Strategies to Lower Capital Cost of RIRP to Ratepayers As previously noted, the scope of the RIRP is significant. The complexity of the overall capital plan and the size and construction duration of various projects within the plan will necessitate some amount of “equity” capital from ratepayers and/or the State of Alaska. Furthermore, equity capital, in the form of a ratepayer benefits charge or State financial assistance through either loans or grants, is the most efficient source of funding available to GRETC for the RIRP. Capital accruing from the State in the form of grants or from existing ratepayers in any form needs to be balanced with long-term debt capital so that future rate payers who will benefit from the RIRP assets share the cost of funding these assets. The following sections discuss various sources of equity capital funding and methods for involving the State in the execution of the RIRP. Ratepayer Benefits Charge. A ratepayer benefits charge is a charge levied on all ratepayers within the Railbelt system that will be used to cash fund and thereby defer borrowing for infrastructure capital. A rate surcharge that is implemented prior to construction allows for partial “pay-go” funding of capital projects and reduces the overall cost of the projects by reducing the amount of interest paid for funding in the capital markets. For example, the potential interest cost savings that could be realized if GRETC were to fund some portion of a $2 billion project through rates rather than entirely upfront through bond proceeds are shown in the table below: $2 billion project Rate Surcharge Through Construction Funded With Bonds Interest Cost Reduction (1) $500 million $1.5 billion $1.2 billion $1.0 billion $1.0 billion $2.4 billion (1) Assumes 30-year debt to fund construction at 7.00% interest.
5 “Pay-Go” vs. Borrowing for Capital. A “pay-go” capital financing program is one in which ongoing capital projects are paid for from remaining revenue after maintenance and operations (M&O) expenses, and debt service are paid for. As will be discussed in further detail later, we have assumed that any bonds sold in the capital markets will require generation of a 1.25 times debt service coverage ratio. Covenanted coverage would likely be lower than 1.25 times. The cash generated in excess of M&O expense an d debt service expense (“coverage”) will be used to fund reasonable reserves with the balance going towards ongoing capital projects. For example, in years where debt service on outstanding bond issues is the highest, the 1.25 times debt service coverage ratio creates additional reserves in the amount of nearly $130 million above what is required to pay operating expense and debt service. There is a tradeoff between the benefits derived from a pay-go financing structure versus one for which all projects are bonded. The benefit to ratepayers and GRETC in the pay-go structure is that it minimizes the total cost of the projects through the reduction of interest costs. On the other hand, the benefit of borrowing for a portion of capital needs is that expen ses are spread out over time, and the cost of the debt can be structured to more closely match the useful life of the assets being financed. This is particularly important for some of the larger hydro-electric projects, where the useful life would likely exceed 50 years; these projects have large upfront costs that would be cost-prohibitive if funded entirely through rates. A balance of these two funding approaches appears to be most effective in lowering the overall cost of the project as well as spreading out the costs over a longer period of time. Construction Work In Progress. Construction Work In Progress (CWIP) is a rate methodology that allows for the recovery of interest expense on project construction expenditures through the rate base during construction , rather than capitalizing the interest until the projects are completed and operating . This concept is important: the overall cost of the projects is significantly reduced through the immediate payment of interest on construction borrowing, vers us the alternative of borrowing an additional sum just to pay for the interest while the project is still under construction. The benefit to ratepayers of the CWIP concept is that it significantly lowers both the overall cost of the project as well as the future revenue requirements needed to pay debt service. The use of CWIP in Alaska will most likely need to be vetted and approved by the Regulatory Commission of Alaska. Both CWIP and pay-as-you -go funding rely on ratepayers to advance dollars for capital projects and thereby convey some project risk to ratepayers. If for example, a generation project were not completed for any reason ratepayers would have paid for a portion of the project even though the asset never produced power. SNW believes that ratepayers in a typical municipal utility structure generally incur this risk regardless of rate setting policies or methodologies. The ability to shift project risk to creditors is both limited and expensive and may not be appropriate for the “System” envisioned by GRETC. Under an Investor Owned Utility (IOU) structure, shareholders are responsible for bearing some of this risk, however shifting risk to shareholders requires higher equity rates of return to those investors. GRETC is not presently contemplated to be structured as an IOU.
6 State Financial Assistance. State financial assistance could take a variety of forms, but for the purpose of this report, we will focus on State assistance structured similarly to the Bradley Lake project. State financial assistance offers GRETC a number of advantages not available through traditional utility enterprise bond funding or project finance. Similar to a ratepayer benefits charge, State funding, whether in the form of a grant or loan, can be utilized to defer higher cost conventional revenue bond funding. Obviously a grant from the State provides the cheapest form of capital to GRETC, but even when structured as a loan, State assistance can dramatically lower GRETC’s overall cost of capital. State funding in the form of a loan has three significant advantages when compared to revenue bonds or a loan from a commercial lender. The advantages of State funding include: 1. Repayment flexibility. State funding can be utilized to extend debt repayment beyond the term maturities available in the public or commercial debt capital markets. Additionally, a State loan can easily be restructured or deferred to achieve system rate objectives. 2. Credit support/risk mitigation. State funding can be used to mitigate project construction risk. This is particularly relevant for projects with extended construction timelines, such as large hydro-electric projects. Risk mitigation is also relevant in situations where permitting is an issue or a new technology is being used. Generally, fixed income investors will not accept significant construction and permitting risks inherent with the large-scale projects included in the RIRP without some form of support from the State. 3. Potential interest cost benefit. State funding can provide a lower cost source of capital. The State’s high investment grade credit rating allows it to borrow for less than even the most secure utility enterprise. Assumptions as to the form of State assistance in the financial model are discussed in greater detail below; however , the terms of any loan, agreement, or grant between the State and GRETC will need to be further researched and developed in the next stage of the GRETC formation process. RIRP Financial Model Summary Results The development of the RIRP financial model took into account several different goals and objectives. The first goal was to identify ways to overcome the funding challenges inherent with large scale projects, including the length of construction time before the project is online and access to the capital markets. A second goal was to develop strategies that could be used to meet an objective of the RIRP of producing equitable rates over the useful life of the assets being financed. Structures commonly used in the current capital markets would not meet this goal, as certain of the assets required to be financed have longer useful lives than the longest term capital markets transaction could bear. With these challenges in mind, we developed separate versions of the model that would capture the cost of financing under a “base case ” scenario and an “alternative ” scenario, both of which are described in greater detail below. Major Assumptions (Black &Veatch Inputs). The input assumptions for the RIRP financial model were developed around outputs from the Black & Veatch PROMOD/Strategist modeling analysis. The results created a detailed list of the capital costs for the projects chosen over the 50-year RIRP time horizon. The results show both generation unit costs as well as required transmission development costs associated with the
7 selected projects. Other assumptions used from the Black & Veatch PROMOD analysis include associated fuel costs, fixed and variable O&M, CO2 charges , and forecasted energy load requirements by year, including DSM energy use reductions. Major Assumptions (Financing Model Inputs). The assumptions used for capital markets transactions within the financing model are all market-accepted structures for an investment grade utility, cooperative, or joint action agency. Below is a summary of the major structuring assumptions used for both financing scenarios: • 30-year debt repayment on all bond issues sold in the capital markets • 7.00% interest rate on all bond issues sold in the capital markets • Rate generated debt service coverage of 1.25X • All energy generation developed is used or sold • Debt Service Reserve Fund (DSRF) for each bond issue funded at 10% of bond issue par amount. The DSRF balance is maintained throughout the 50-year RIRP and earns 3.00% interest, which is used to pay debt service on an annual basis. Base Case Model: Specific Assumptions . The base case financing model was structured such that the list of generation and transmission projects would be financed through the capital markets in advance of construction and that the cost of the financing in the form of debt service on the bonds would immediately be passed through to rate payers (see “Construction Work in Progress” herein). Bond issues are assumed to be sold prior to the required project funding dates, and staggered in approximately three -year intervals over the first 20-years , when the majority of the large capital projects and transmission projects are scheduled. The projects being financed over the balance of the 50-year RIRP period are financed through cash flow created through normal rates and charges (“pay-go”). The pay-go approach works once debt service coverage from previous years has grown to levels that create cash reserve balance amounts sufficient to pay for the projects as their construction costs come due. The sources of funds for the projects included in the RIRP under the base case model are as follows: RIRP Plan 1A : Base Case Sources of Funds (dollars in millions) Bonds $5,889 State Funds $0 Infrastructure Tax $0 Pay-Go $3,196 The base case model assumes that approximately $5.9 billion of bonds are sold over the RIRP time horizon through five different bond sales ranging in size from $656 million to $2.5 billion. The maximum fixed charge rate on the capital portion alone is estimated to cost $0.13 per kWh, while the average fixed charge rate over the 50-years is $0.07 per kWh. Alternative Model: Specific Assumptions . The alternative model was developed with the goal of minimizing the rate shock that may otherwise occur with such a large capital plan, and levelizing the rate over time so that the economic burden derived from these projects can be spread more equitably over the useful life of the
8 projects being contemplated. Similar to the base case scenario, the first method used was to transfer the excess operating cash flow that is generated to create the debt service coverage level, and use that balance to both partially fund the capital projects in the early years and almost fully fund the projects in the later years. The second method used was the implementation of a Capital Benefits Surcharge that is applied to rate payers starting the day GRETC is formed. For this analysis, it was assumed that a $0.01 rate surcharge would be in place for the first 17 years, during which time approximately 75% of the capital projects in the plan will have been constructed. The third method used to spread out the costs over a longer time period was the use of the State as an equity participant in the execution of the RIRP capital funding plan. In a financing structure that is similar to the Bradley Lake financing model, the State would provide the upfront funding for any large hydroelectric projects, to be paid back by GRETC out of system revenues over an extended period of time, and following the repayment of the potentially more expensive capital markets debt. This analysis assumes that a $2.4 billion hydroelectric project is financed through a zero interest loan to GRETC that is then paid back through a 30-year capital markets take-out bond issue in 2047. The sources of funds for the projects included in the RIRP under the alternative case model are as follows: RIRP Plan 1A : Alternative Case Sources of Funds (dollars in millions) Bonds $3,657 State Funds $2,409 Benefit Surcharge $883 Pay-Go $2,135 The alternative model assumes that $5.9 billion of bonds are sold over the RIRP time horizon through nine different bond sales ranging in size from $32 million to $2.4 billion, which includes the $2.4 billion take-out financing to repay the State for front-funding of hydroelectric assets. The capital costs not bonded for come from the rate surcharge that is applied from day one and cash flow generated from rates and charges after operations and debt service (pay-go capital). The maximum fixed charge rate on the capital portion alone is estimated to cost $0.08 per kWh, while the average fixed charge rate over the initial 50-year period is $0.06 per kWh, not including the $0.01 consumer benefit surcharge that is in place for the first 17 years. While the average fixed cost is not significantly different between the base case and alternative scenarios, the difference between the two maximum rates are significant. The lower maximum rate in the alternative scenario benefits the rate payers by smoothing out the rates over a period of time that more closely matches the useful life of the RIRP assets. Summary, Next Steps, Conclusion. The RIRP presents a number of funding challenges, given the size and scope of the projects being contemplated. It has become evident through the financial modeling and the individual debt capacity analyses of this process that the utilities on their own would not be able to accomplish such an ambitious capital plan. The formation of a regional entity, such as GRETC, that would combine the existing resources and rate-base of the Railbelt utilities, as well provide an organized front in working to obtain private financing and the necessary levels of State assistance would be, in our opinion, a necessary next step towards achieving the goal of reliable energy for the Railbelt now and in the future.
RIRP Plan 1A - Base Case Financial Model
Alaska Regional Integrated Resource PlanYearHydro Capital RequirementsOther Unit Cost Capital RequirementsTransmission RequirementsTotal Capital RequirementsSTATE FundingUse of coverage balance for capital projectsCapital Markets ‐ BONDSScenario Cash Flow Summarydollars in millions112/1/20111 506,496,362 ‐ 506,496,363 ‐ 886,736,593$ 212/1/2012‐ 256,773,239 ‐ 256,773,239 ‐ ‐ ‐ 312/1/2013‐ 119,476,707 3,990,284 123,466,991 ‐ ‐ ‐ 412/1/2014‐ 122,463,625 52,942,550 175,406,175 ‐ (25,000,000) 656,306,880$ 512/1/2015‐ 2,435,356 191,310,564 193,745,920 ‐ ‐ ‐ Sources of Funds612/1/201633,699,203 22,466,161 255,989,420 312,154,784 ‐ ‐ ‐ BONDS5,889712/1/201726,865,753 74,229,623 117,965,769 219,061,145 ‐ (105,000,000) 795,887,676$ STATE (through construction)0812/1/201843,273,053 174,256,113 41,630,847 259,160,013 ‐ ‐ ‐ Infrastructure Tax through 20270912/1/201979,301,147 174,171,476 169,193,895 422,666,518 ‐ ‐ ‐ Other (use of coverage reserves)3,1961012/1/2020238,340,271 208,891,416 321,882,411 769,114,097 ‐ (190,000,000) 2,454,911,924$ Total Source of Funds9,0851112/1/2021481,536,897 21,500,060 282,636,456 785,673,412 ‐ ‐ ‐ 1212/1/2022652,793,164 ‐ 437,331,250 1,090,124,414 ‐ ‐ ‐ Use of Funds1312/1/2023712,137,997 ‐ 464,423,300 1,176,561,297 ‐ (320,000,000) 1,095,198,536$ Project/Construction9,0851412/1/2024141,426,155 ‐ 59,937,820 201,363,975 ‐ ‐ ‐ Payment of interest accrued01512/1/2025‐ ‐ 18,210,430 18,210,430 ‐ ‐ ‐ Reserve Funds01612/1/2026‐ ‐ 19,062,834 19,062,834 ‐ ‐ ‐ Issuance Costs01712/1/2027‐ 88,657,273 ‐ 88,657,273 ‐ (485,500,231) ‐$ Capitalized Interest (through construction)01812/1/2028‐ 208,125,424 ‐ 208,125,424 ‐ ‐ ‐ Total Uses of Funds9,0851912/1/2029‐ 188,717,535 ‐ 188,717,535 ‐ ‐ ‐ 2012/1/2030‐ ‐ ‐ ‐ ‐ ‐ Maximum Annual Debt Service Requirements2112/1/2031‐ ‐ ‐ ‐ ‐ ‐ BONDS5392212/1/2032‐ ‐ ‐ ‐ ‐ ‐ STATE02312/1/2033‐ ‐ ‐ ‐ ‐ ‐ 2412/1/2034‐ 2,260,136 2,260,136 ‐ (239,531,757) ‐$ 2512/1/2035‐ 206,133,124 206,133,124 ‐ ‐ ‐ Ave. Annual Energy Requirement (GWhr)5,625 2612/1/2036‐ 31,138,497 31,138,497 ‐ ‐ ‐ Target Debt Service Coverage (DSC)1.25X 2712/1/2037‐ ‐ ‐ ‐ ‐ ‐ All-in Borrowing Cost7.00% 2812/1/2038‐ ‐ ‐ ‐ ‐ ‐ Escalation Factor (Inflation)2.50% 2912/1/2039‐ 127,791,596 127,791,596 ‐ (699,805,525) ‐$ Average Cost of Energy ($/per kWh)0.07 3012/1/2040‐ 299,994,339 299,994,339 ‐ ‐ ‐ 3112/1/2041‐ 272,019,589 272,019,589 ‐ ‐ ‐ 3212/1/2042‐ ‐ ‐ ‐ ‐ ‐ 3312/1/2043‐ 131,612,221 131,612,221 ‐ (720,727,822) ‐$ RIRP PLAN 1ABase Case100% Fixed Rate//,,,,(,,)$Assumptions3412/1/2044‐ 308,963,361 308,963,361 ‐ ‐ ‐ Issuance Cost = 2% of Par Amount3512/1/2045‐ 280,152,241 280,152,241 ‐ ‐ ‐ Par coupons3612/1/2046‐ ‐ ‐ ‐ ‐ ‐ Debt service reserve funded at 10% of Bond Par Amount3712/1/2047‐ ‐ ‐ ‐ ‐ ‐ Bonds all assumed to be 30 years from date of issue3812/1/2048‐ ‐ ‐ ‐ ‐ ‐ 3912/1/2049‐ ‐ ‐ ‐ ‐ ‐ 4012/1/2050‐ ‐ ‐ ‐ ‐ ‐ 4112/1/2051‐ ‐ ‐ ‐ ‐ ‐ 4212/1/2052‐ ‐ ‐ ‐ ‐ ‐ 4312/1/2053‐ ‐ ‐ ‐ ‐ ‐ 4412/1/2054‐ ‐ ‐ ‐ (410,069,419) ‐$ 4512/1/2055‐ 35,525,625 35,525,625 ‐ ‐ ‐ 4612/1/2056‐ 161,918,291 161,918,291 ‐ ‐ ‐ 4712/1/2057‐ ‐ ‐ ‐ ‐ ‐ 4812/1/2058‐ 38,257,213 38,257,213 ‐ ‐ ‐ 4912/1/2059‐ 174,368,290 174,368,290 ‐ ‐ ‐ 5012/1/2060‐ ‐ ‐ ‐ Prepared by Seattle-Northwest Securities Corporation12/1/2009
Year112/1/2011212/1/2012312/1/2013412/1/2014512/1/2015612/1/2016712/1/2017812/1/2018912/1/20191012/1/20201112/1/20211212/1/20221312/1/20231412/1/20241512/1/20251612/1/20261712/1/20271812/1/20281912/1/20292012/1/20302112/1/20312212/1/20322312/1/20332412/1/20342512/1/20352612/1/20362712/1/20372812/1/20382912/1/20393012/1/20403112/1/20413212/1/20423312/1/2043Repayment of State fundsGRETC Direct Debt Service ‐ paid to bondholdersDSRF Interest Earnings Total RequirementsEnergy per Year (GWhr) Surcharge for seed capital Fixed Rate Charge for Capital DSM Fuel Rate O&M Rate (Fixed + Variable) CO² Incremental Cost (¢ per kWh) 1.0057‐$ 35,268,100$ ‐$ 35,268,100$ 5,372 ‐ 0.01 0.000 0.048 0.013 0.0000.07 81,206,200 2,660,210 78,545,990 5,412 ‐ 0.02 0.000 0.051 0.013 0.0100.09 81,204,300 2,660,210 78,544,090 5,424 ‐ 0.02 0.001 0.048 0.014 0.0110.09 107,308,425 2,660,210 104,648,215 5,421 ‐ 0.02 0.001 0.053 0.014 0.0120.10 141,306,550 4,629,130 136,677,420 5,167 ‐ 0.03 0.002 0.067 0.013 0.0120.13 141,309,000 4,629,130 136,679,870 5,147 ‐ 0.03 0.002 0.070 0.014 0.0130.13 172,958,250 4,629,130 168,329,120 5,129 ‐ 0.04 0.002 0.066 0.014 0.0140.14 214,187,950 7,016,793 207,171,157 5,105 ‐ 0.05 0.002 0.042 0.013 0.0150.12 214,190,100 7,016,793 207,173,307 5,085 ‐ 0.05 0.002 0.045 0.013 0.0160.13 311,827,975 7,016,793 304,811,182 5,068 ‐ 0.08 0.002 0.044 0.012 0.0170.15 439,001,050 14,381,529 424,619,521 5,052 ‐ 0.11 0.002 0.046 0.013 0.0180.18 439,000,300 14,381,529 424,618,771 5,081 ‐ 0.10 0.003 0.050 0.013 0.0210.19 482,557,325 14,381,529 468,175,796 5,111 ‐ 0.11 0.001 0.053 0.012 0.0210.20 539,293,200 17,667,125 521,626,075 5,140 ‐ 0.13 0.001 0.055 0.013 0.0230.22 539,294,650 17,667,125 521,627,525 5,174 ‐ 0.13 0.001 0.037 0.016 0.0170.20 ‐ 539,289,900 17,667,125 521,622,775 5,207 0.13 0.001 0.042 0.014 0.0200.20 ‐ 539,284,300 17,667,125 521,617,175 5,241 0.12 0.002 0.044 0.014 0.0220.21 ‐ 539,290,400 17,667,125 521,623,275 5,275 0.12 0.002 0.046 0.014 0.0240.21 ‐ 539,297,250 17,667,125 521,630,125 5,309 0.12 0.003 0.049 0.015 0.0270.22 ‐ 539,296,800 17,667,125 521,629,675 5,344 0.12 0.003 0.042 0.019 0.0250.21 ‐ 539,293,550 17,667,125 521,626,425 5,378 0.12 0.003 0.042 0.019 0.0260.21 ‐ 539,293,500 17,667,125 521,626,375 5,413 0.12 0.003 0.044 0.019 0.0280.21 ‐ 539,288,800 17,667,125 521,621,675 5,447 0.12 0.003 0.046 0.019 0.0310.22 ‐ 539,293,450 17,667,125 521,626,325 5,482 0.12 0.003 0.048 0.020 0.0340.22 ‐ 539,286,550 17,667,125 521,619,425 5,517 0.12 0.003 0.052 0.020 0.0370.23 ‐ 539,289,400 17,667,125 521,622,275 5,553 0.12 0.001 0.054 0.021 0.0410.23 ‐ 539,287,350 17,667,125 521,620,225 5,588 0.12 0.001 0.062 0.022 0.0480.25 ‐ 539,291,900 17,667,125 521,624,775 5,623 0.12 0.001 0.066 0.022 0.0520.26 ‐ 539,293,600 17,667,125 521,626,475 5,659 0.12 0.002 0.069 0.023 0.0570.27 ‐ 539,288,100 17,667,125 521,620,975 5,695 0.11 0.002 0.072 0.023 0.0620.27 ‐ 539,290,450 17,667,125 521,623,325 5,731 0.11 0.004 0.075 0.024 0.0670.28 ‐ 458,083,350 17,667,125 440,416,225 5,767 0.10 0.004 0.073 0.022 0.0690.26 ‐ 458,087,900 17,667,125 440,420,775 5,803 0.09 0.004 0.077 0.022 0.0750.27 //3412/1/20443512/1/20453612/1/20463712/1/20473812/1/20483912/1/20494012/1/20504112/1/20514212/1/20524312/1/20534412/1/20544512/1/20554612/1/20564712/1/20574812/1/20584912/1/20595012/1/2060,,,,,,,‐ 458,086,400 17,667,125 440,419,275 5,839 0.09 0.004 0.080 0.033 0.0820.29 ‐ 397,988,550 17,667,125 380,321,425 5,876 0.08 0.004 0.084 0.023 0.0890.28 ‐ 397,984,050 17,667,125 380,316,925 5,912 0.08 0.004 0.078 0.031 0.0870.28 ‐ 397,982,000 17,667,125 380,314,875 5,949 0.08 0.005 0.079 0.032 0.0910.29 ‐ 325,101,750 17,667,125 307,434,625 5,986 0.06 0.005 0.083 0.032 0.1000.28 ‐ 325,102,950 17,667,125 307,435,825 6,023 0.06 0.001 0.086 0.033 0.1090.29 ‐ 325,107,400 17,667,125 307,440,275 6,060 0.06 0.002 0.089 0.034 0.1170.31 ‐ 100,294,000 17,667,125 82,626,875 6,098 0.02 0.002 0.094 0.035 0.1220.27 ‐ 100,293,100 17,667,125 82,625,975 6,135 0.02 0.002 0.097 0.035 0.1260.28 ‐ 100,291,100 17,667,125 82,623,975 6,173 0.02 0.003 0.102 0.036 0.1310.29 ‐ ‐ ‐ 6,211 ‐ 0.004 0.105 0.037 0.1350.28 ‐ ‐ ‐ 6,249 ‐ 0.005 0.108 0.038 0.1400.29 ‐ ‐ ‐ 6,287 ‐ 0.006 0.113 0.039 0.1440.30 ‐ ‐ ‐ 6,326 ‐ 0.006 0.121 0.041 0.1530.32 ‐ ‐ ‐ 6,364 ‐ 0.006 0.127 0.041 0.1610.33 ‐ ‐ ‐ 6,403 ‐ 0.006 0.133 0.042 0.1680.35 ‐ ‐ 6,442 ‐ 0.006 0.137 0.043 0.1720.36 Prepared by Seattle-Northwest Securities Corporation12/1/2009
Year112/1/2011212/1/2012312/1/2013412/1/2014512/1/2015612/1/2016712/1/2017812/1/2018912/1/20191012/1/20201112/1/20211212/1/20221312/1/20231412/1/20241512/1/20251612/1/20261712/1/20271812/1/20281912/1/20292012/1/20302112/1/20312212/1/20322312/1/20332412/1/20342512/1/20352612/1/20362712/1/20372812/1/20382912/1/20393012/1/20403112/1/20413212/1/20423312/1/2043DSM (000s) Fuel Cost (000s)Fixed O&M Cost (000s)Variable O&M Cost (000s)CO² Cost (000s) Seed CapitalSeed Capital Fund BalanceFixed Rate Charge for RevenuesRevenue available after debt serviceGRETC Direct Debt Service CoverageUse of Coverage Coverage Balance2.50% 2.50% 2.50% 2.50% 2.50% 0.00% 1.25 0.00%651 259,482 39,359 30,852 ‐ ‐ ‐ 44,085,125 8,817,025 1.25 8,817,025 1,491 271,611 38,557 32,902 54,963 ‐ ‐ 98,182,488 19,636,498 1.2528,453,523 3,063 258,329 42,181 31,820 56,995 ‐ ‐ 98,180,113 19,636,023 1.2548,089,545 5,878 282,641 42,195 32,212 63,421 ‐ ‐ 130,810,269 26,162,054 1.25 25,000,000 49,251,599 10,455 361,674 35,055 35,819 65,306 ‐ ‐ 170,846,774 34,169,355 1.2583,420,954 12,759 373,704 37,978 35,083 68,216 ‐ ‐ 170,849,837 34,169,967 1.25117,590,921 11,891 352,673 38,010 36,043 73,346 ‐ ‐ 210,411,399 42,082,280 1.25 105,000,000 54,673,201 12,241 224,380 36,088 34,170 81,543 ‐ ‐ 258,963,946 51,792,789 1.25‐ 106,465,990 12,657 244,337 34,987 35,596 86,958 ‐ ‐ 258,966,633 51,793,327 1.25158,259,317 13,124 235,418 37,177 29,384 90,354 ‐ ‐ 381,013,977 76,202,795 1.25 190,000,000 44,462,112 13,346 247,202 39,360 30,390 97,474 ‐ ‐ 530,774,401 106,154,880 1.25150,616,992 14,024 267,038 41,731 29,426 110,165 ‐ ‐ 530,773,463 106,154,693 1.25256,771,685 4,166 284,104 35,897 30,380 114,805 ‐ ‐ 585,219,745 117,043,949 1.25 320,000,000 53,815,634 3,313 297,843 36,104 33,631 125,785 ‐ ‐ 652,032,594 130,406,519 1.25184,222,153 4,222 201,105 57,389 29,739 90,619 ‐ ‐ 652,034,406 130,406,881 1.25314,629,034 5,342 227,331 57,967 16,925 107,681 ‐ ‐ 652,028,469 130,405,694 1.25445,034,728 8,551 238,262 58,593 17,362 118,039 ‐ ‐ 652,021,469 130,404,294 1.25 485,500,231 89,938,791 13,323 247,810 59,207 18,257 130,862 ‐ ‐ 652,029,094 130,405,819 1.25‐ 220,344,610 16,151 261,837 59,916 18,745 146,548 ‐ ‐ 652,037,656 130,407,531 1.25350,752,141 17,064 226,648 84,248 17,865 135,367 ‐ 652,037,094 130,407,419 1.25481,159,560 14,951 224,691 84,983 15,652 140,642 ‐ 652,033,031 130,406,606 1.25611,566,166 15,081 234,947 86,456 16,121 152,129 ‐ 652,032,969 130,406,594 1.25741,972,760 15,919 249,713 87,902 16,762 166,550 ‐ 652,027,094 130,405,419 1.25872,378,179 16,747 260,041 89,276 17,408 180,198 ‐ 652,032,906 130,406,581 1.25239,531,757 763,253,003 18,111 279,793 90,794 18,296 200,974 ‐ 652,024,281 130,404,856 1.25893,657,859 5,493 292,296 92,408 18,814 218,387 ‐ 652,027,844 130,405,569 1.251,024,063,428 7,019 335,171 97,112 19,787 257,520 ‐ 652,025,281 130,405,056 1.251,154,468,484 6,453 352,597 98,638 20,542 281,586 ‐ 652,030,969 130,406,194 1.251,284,874,678 8,848 368,539 100,317 21,287 306,519 ‐ 652,033,094 130,406,619 1.25 699,805,525 715,475,772 12,284 385,523 101,920 22,049 332,326 ‐ 652,026,219 130,405,244 1.25845,881,016 18,825 403,233 103,660 22,861 361,453 ‐ 652,029,156 130,405,831 1.25976,286,847 21,552 394,321 95,445 21,546 371,427 ‐ 550,520,281 110,104,056 1.251,086,390,903 22,199 412,100 97,223 22,392 404,276 ‐ 550,525,969 110,105,194 1.25 720,727,822 475,768,275 //3412/1/20443512/1/20453612/1/20463712/1/20473812/1/20483912/1/20494012/1/20504112/1/20514212/1/20524312/1/20534412/1/20544512/1/20554612/1/20564712/1/20574812/1/20584912/1/20595012/1/2060,,,,,,,,,,,,,23,458 428,330 152,761 23,116 439,168 ‐ 550,524,094 110,104,819 1.25 585,873,094 22,134 449,075 101,037 23,977 476,267 ‐ 475,401,781 95,080,356 1.25 680,953,450 22,961 421,293 140,010 26,073 466,403 ‐ 475,396,156 95,079,231 1.25 776,032,681 24,452 424,059 142,963 26,511 490,408 ‐ 475,393,594 95,078,719 1.25 871,111,400 25,398 444,961 146,057 27,392 537,229 ‐ 384,293,281 76,858,656 1.25 947,970,056 6,909 461,902 149,291 28,395 584,308 ‐ 384,294,781 76,858,956 1.25 1,024,829,013 8,724 477,627 152,489 29,313 630,743 ‐ 384,300,344 76,860,069 1.251,101,689,082 11,174 503,605 155,601 30,361 656,308 ‐ 103,283,594 20,656,719 1.251,122,345,800 9,139 520,728 158,955 31,315 676,369 ‐ 103,282,469 20,656,494 1.251,143,002,294 14,889 546,462 162,470 32,477 705,371 ‐ 103,279,969 20,655,994 1.251,163,658,288 22,880 562,487 165,955 33,535 723,997 ‐ ‐ ‐ 0.00 410,069,419 753,588,869 27,949 579,273 169,720 34,785 749,388 ‐ ‐ ‐ 0.00753,588,869 30,133 605,200 173,255 35,877 774,023 ‐ ‐ ‐ 0.00753,588,869 33,288 647,750 180,086 37,668 822,050 ‐ ‐ ‐ 0.00753,588,869 33,226 682,788 182,230 38,924 862,251 ‐ ‐ ‐ 0.00753,588,869 31,309 716,551 186,278 40,624 900,505 ‐ ‐ ‐ 0.00753,588,869 32,092 734,465 190,935 41,639 923,018 ‐ ‐ ‐ 0.00753,588,869 Prepared by Seattle-Northwest Securities Corporation12/1/2009
RIRP Plan 1A - Alternative Case Financial Model
Alaska Regional Integrated Resource PlanYearHydro Capital RequirementsOther Unit Cost Capital RequirementsTransmission RequirementsTotal Capital Requirements (less large hydro)STATE Funding ‐ loan and paybackUse of coverage balance for capital projectsCapital Markets ‐ BONDSScenario Cash Flow Summarydollars in millions112/1/20111 506,496,362 ‐ 506,496,362 ‐ 833,019,182$ 212/1/2012‐ 256,773,239 ‐ 256,773,239 ‐ ‐ ‐ 312/1/2013‐ 119,476,707 3,990,284 123,466,991 ‐ ‐ ‐ 412/1/2014‐ 122,463,625 52,942,550 175,406,175 ‐ (15,000,000) 470,031,769$ 512/1/2015‐ 2,435,356 191,310,564 193,745,920 ‐ ‐ ‐ Sources of Funds612/1/201633,699,203 22,466,161 255,989,420 278,455,581 2,409,373,640 ‐ ‐ BONDS3,657712/1/201726,865,753 74,229,623 117,965,769 192,195,392 ‐ (75,000,000) 522,012,548$ STATE (through construction)2,409812/1/201843,273,053 174,256,113 41,630,847 215,886,960 ‐ ‐ ‐ Infrastructure Tax through 2027883912/1/201979,301,147 174,171,476 169,193,895 343,365,370 ‐ ‐ ‐ Other (Use of Coverage Reserves)2,1351012/1/2020238,340,271 208,891,416 321,882,411 530,773,827 ‐ (120,000,000) 999,656,778$ Total Source of Funds9,0851112/1/2021481,536,897 21,500,060 282,636,456 304,136,516 ‐ ‐ ‐ 1212/1/2022652,793,164 ‐ 437,331,250 437,331,250 ‐ ‐ ‐ Use of Funds1312/1/2023712,137,997 ‐ 464,423,300 464,423,300 ‐ (180,000,000) 229,188,962$ Project/Construction9,0851412/1/2024141,426,155 ‐ 59,937,820 59,937,820 ‐ ‐ ‐ Payment of interest accrued01512/1/2025‐ ‐ 18,210,430 18,210,430 ‐ ‐ ‐ Reserve Funds01612/1/2026‐ ‐ 19,062,834 19,062,834 ‐ ‐ ‐ Issuance Costs01712/1/2027‐ 88,657,273 ‐ 88,657,273 ‐ (245,000,000) 32,875,895$ Capitalized Interest (through construction)01812/1/2028‐ 208,125,424 ‐ 208,125,424 ‐ ‐ ‐ Total Uses of Funds9,0851912/1/2029‐ 188,717,535 ‐ 188,717,535 ‐ ‐ ‐ 2012/1/2030‐ ‐ ‐ ‐ ‐ ‐ Maximum Annual Debt Service Requirements2112/1/2031‐ ‐ ‐ ‐ ‐ ‐ BONDS3142212/1/2032‐ ‐ ‐ ‐ ‐ ‐ STATE3222312/1/2033‐ ‐ ‐ ‐ ‐ ‐ 2412/1/2034‐ 2,260,136 2,260,136 ‐ (239,531,757) 0$ 2512/1/2035‐ 206,133,124 206,133,124 ‐ ‐ ‐ Ave.Annual Energy Requirement (GWhr)5,625 2612/1/2036‐ 31,138,497 31,138,497 ‐ ‐ ‐ Target Debt Service Coverage (DSC)1.25X 2712/1/2037‐ ‐ ‐ ‐ ‐ ‐ All-in Borrowing Cost7.00% 2812/1/2038‐ ‐ ‐ ‐ ‐ ‐ Escalation Factor (Inflation)2.50% 2912/1/2039‐ 127,791,596 127,791,596 ‐ (600,000,000) 99,805,525$ Average Cost of Energy ($/per kWh)0.06 3012/1/2040‐ 299,994,339 299,994,339 ‐ ‐ ‐ 3112/1/2041‐ 272,019,589 272,019,589 ‐ ‐ ‐ RIRP PLAN 1AAlternative Scenario100% Fixed Rate3212/1/2042‐ ‐ ‐ ‐ ‐ ‐ 3312/1/2043‐ 131,612,221 131,612,221 ‐ (250,000,000) 470,727,822$ Assumptions3412/1/2044‐ 308,963,361 308,963,361 ‐ ‐ ‐ Issuance Cost = 2% of Par Amount3512/1/2045‐ 280,152,241 280,152,241 ‐ ‐ ‐ Par coupons3612/1/2046‐ ‐ ‐ ‐ ‐ ‐ Debt service reserve funded at 10% of Bond Par Amount3712/1/2047‐ ‐ ‐ 2,409,373,640 ‐ ‐ Bonds all assumed to be 30 years from date of issue3812/1/2048‐ ‐ ‐ ‐ ‐ ‐ 3912/1/2049‐ ‐ ‐ ‐ ‐ ‐ 4012/1/2050‐ ‐ ‐ ‐ ‐ ‐ 4112/1/2051‐ ‐ ‐ ‐ ‐ ‐ 4212/1/2052‐ ‐ ‐ ‐ ‐ ‐ 4312/1/2053‐ ‐ ‐ ‐ ‐ ‐ 4412/1/2054‐ ‐ ‐ ‐ (410,069,419) (0)$ 4512/1/2055‐ 35,525,625 35,525,625 ‐ ‐ ‐ 4612/1/2056‐ 161,918,291 161,918,291 ‐ ‐ ‐ 4712/1/2057‐ ‐ ‐ ‐ ‐ ‐ 4812/1/2058‐ 38,257,213 38,257,213 ‐ ‐ ‐ 4912/1/2059‐ 174,368,290 174,368,290 ‐ ‐ ‐ 5012/1/2060‐ ‐ ‐ ‐ Prepared by Seattle-Northwest Securities Corporation12/1/2009
Year112/1/2011212/1/2012312/1/2013412/1/2014512/1/2015612/1/2016712/1/2017812/1/2018912/1/20191012/1/20201112/1/20211212/1/20221312/1/20231412/1/20241512/1/20251612/1/20261712/1/20271812/1/20281912/1/20292012/1/20302112/1/20312212/1/20322312/1/20332412/1/20342512/1/20352612/1/20362712/1/20372812/1/20382912/1/20393012/1/20403112/1/2041Repayment of State fundsGRETC Direct Debt Service ‐ paid to bondholdersDSRF Interest Earnings Total RequirementsEnergy per Year (GWhr) Surcharge for seed capital Fixed Rate Charge for Capital DSM Fuel Rate O&M Rate (Fixed + Variable) CO² Incremental Cost (¢ per kWh) 1.00570.01 ‐$ 33,131,525$ ‐$ 33,131,525$ 5,372 0.010 0.01 0.000 0.048 0.013 0.0000.08 76,283,050 2,499,058 73,783,992 5,412 0.010 0.02 0.000 0.051 0.013 0.0100.10 76,281,650 2,499,058 73,782,592 5,424 0.010 0.02 0.001 0.048 0.014 0.0110.10 94,980,800 2,499,058 92,481,742 5,421 0.010 0.02 0.001 0.053 0.014 0.0120.11 119,327,100 3,909,153 115,417,947 5,167 0.010 0.03 0.002 0.067 0.013 0.0120.13 ‐ 119,327,000 3,909,153 115,417,847 5,147 0.010 0.03 0.002 0.070 0.014 0.0130.14 ‐ 140,091,050 3,909,153 136,181,897 5,129 0.010 0.03 0.002 0.066 0.014 0.0140.14 ‐ 167,135,950 5,475,190 161,660,760 5,105 0.010 0.04 0.002 0.042 0.013 0.0150.12 ‐ 167,133,450 5,475,190 161,658,260 5,085 0.010 0.04 0.002 0.045 0.013 0.0160.13 ‐ 206,891,825 5,475,190 201,416,635 5,068 0.010 0.05 0.002 0.044 0.012 0.0170.14 ‐ 258,677,150 8,474,161 250,202,989 5,052 0.010 0.06 0.002 0.046 0.013 0.0180.15 ‐ 258,678,050 8,474,161 250,203,889 5,081 0.010 0.06 0.003 0.050 0.013 0.0210.16 ‐ 267,790,975 8,474,161 259,316,814 5,111 0.010 0.06 0.001 0.053 0.012 0.0210.16 ‐ 279,659,600 9,161,728 270,497,872 5,140 0.010 0.07 0.001 0.055 0.013 0.0230.17 ‐ 279,668,350 9,161,728 270,506,622 5,174 0.010 0.07 0.001 0.037 0.016 0.0170.15 ‐ 279,658,100 9,161,728 270,496,372 5,207 0.010 0.06 0.001 0.042 0.014 0.0200.15 ‐ 292,456,550 9,161,728 283,294,822 5,241 0.010 0.07 0.002 0.044 0.014 0.0220.16 ‐ 305,241,850 9,260,355 295,981,495 5,275 0.07 0.002 0.046 0.014 0.0240.16 ‐ 305,240,900 9,260,355 295,980,545 5,309 0.07 0.003 0.049 0.015 0.0270.16 ‐ 305,242,800 9,260,355 295,982,445 5,344 0.07 0.003 0.042 0.019 0.0250.16 ‐ 305,244,200 9,260,355 295,983,845 5,378 0.07 0.003 0.042 0.019 0.0260.16 ‐ 305,245,000 9,260,355 295,984,645 5,413 0.07 0.003 0.044 0.019 0.0280.16 ‐ 305,243,000 9,260,355 295,982,645 5,447 0.07 0.003 0.046 0.019 0.0310.17 ‐ 305,243,900 9,260,355 295,983,545 5,482 0.07 0.003 0.048 0.020 0.0340.17 ‐ 305,240,600 9,260,355 295,980,245 5,517 0.07 0.003 0.052 0.020 0.0370.18 ‐ 305,243,900 9,260,355 295,983,545 5,553 0.07 0.001 0.054 0.021 0.0410.18 ‐ 305,236,100 9,260,355 295,975,745 5,588 0.07 0.001 0.062 0.022 0.0480.20 ‐ 305,237,750 9,260,355 295,977,395 5,623 0.07 0.001 0.066 0.022 0.0520.21 ‐ 309,204,550 9,260,355 299,944,195 5,659 0.07 0.002 0.069 0.023 0.0570.22 ‐ 314,375,350 9,559,772 304,815,578 5,695 0.07 0.002 0.072 0.023 0.0620.23 ‐ 314,385,800 9,559,772 304,826,028 5,731 0.07 0.004 0.075 0.024 0.0670.24 3212/1/20423312/1/20433412/1/20443512/1/20453612/1/20463712/1/20473812/1/20483912/1/20494012/1/20504112/1/20514212/1/20524312/1/20534412/1/20544512/1/20554612/1/20564712/1/20574812/1/20584912/1/20595012/1/2060‐ 238,098,800 9,559,772 228,539,028 5,767 0.05 0.004 0.073 0.022 0.0690.22 ‐ 256,818,500 9,559,772 247,258,728 5,803 0.05 0.004 0.077 0.022 0.0750.23 ‐ 281,213,300 10,971,955 270,241,345 5,839 0.06 0.004 0.080 0.033 0.0820.26 ‐ 238,156,850 10,971,955 227,184,895 5,876 0.05 0.004 0.084 0.023 0.0890.25 ‐ 238,159,400 10,971,955 227,187,445 5,912 0.05 0.004 0.078 0.031 0.0870.25 95,827,375 238,157,150 10,971,955 323,012,570 5,949 0.07 0.005 0.079 0.032 0.0910.27 191,654,750 190,355,650 10,971,955 371,038,445 5,986 0.08 0.005 0.083 0.032 0.1000.30 191,654,750 190,357,950 10,971,955 371,040,745 6,023 0.08 0.001 0.086 0.033 0.1090.31 191,654,750 190,355,750 10,971,955 371,038,545 6,060 0.08 0.002 0.089 0.034 0.1170.32 191,654,750 98,815,900 10,971,955 279,498,695 6,098 0.06 0.002 0.094 0.035 0.1220.31 191,654,750 98,809,900 10,971,955 279,492,695 6,135 0.06 0.002 0.097 0.035 0.1260.32 191,654,750 98,809,900 10,971,955 279,492,695 6,173 0.06 0.003 0.102 0.036 0.1310.33 191,654,750 77,824,800 10,971,955 258,507,595 6,211 0.05 0.004 0.105 0.037 0.1350.33 196,264,750 77,826,750 10,971,955 263,119,545 6,249 0.05 0.005 0.108 0.038 0.1400.34 201,172,050 77,826,500 10,971,955 268,026,595 6,287 0.05 0.006 0.113 0.039 0.1440.35 206,198,250 52,247,150 10,971,955 247,473,445 6,326 0.05 0.006 0.121 0.041 0.1530.37 211,354,400 52,246,350 10,971,955 252,628,795 6,364 0.05 0.006 0.127 0.041 0.1610.38 216,638,400 52,250,150 10,971,955 257,916,595 6,403 0.05 0.006 0.133 0.042 0.1680.40 222,055,700 52,242,250 10,971,955 263,325,995 6,442 0.05 0.006 0.137 0.043 0.1720.41 Prepared by Seattle-Northwest Securities Corporation12/1/2009
Year112/1/2011212/1/2012312/1/2013412/1/2014512/1/2015612/1/2016712/1/2017812/1/2018912/1/20191012/1/20201112/1/20211212/1/20221312/1/20231412/1/20241512/1/20251612/1/20261712/1/20271812/1/20281912/1/20292012/1/20302112/1/20312212/1/20322312/1/20332412/1/20342512/1/20352612/1/20362712/1/20372812/1/20382912/1/20393012/1/20403112/1/2041DSM (000s) Fuel Cost (000s)Fixed O&M Cost (000s)Variable O&M Cost (000s)CO² Cost (000s) Seed CapitalFixed Rate Charge for RevenuesRevenue available after debt serviceGRETC Direct Debt Service CoverageUse of Coverage Coverage Balance2.50% 2.50% 2.50% 2.50% 2.50%1.25 0.00%651 259,482 39,359 30,852 ‐ 53,717,410.47 41,414,406 8,282,881 1.25 8,282,881 1,491 271,611 38,557 32,902 54,963 54,120,733.86 92,229,991 18,445,998 1.25 26,728,879 3,063 258,329 42,181 31,820 56,995 54,241,323.99 92,228,241 18,445,648 1.2545,174,527 5,878 282,641 42,195 32,212 63,421 54,213,850.02 115,602,178 23,120,436 1.25 15,000,000 53,294,963 10,455 361,674 35,055 35,819 65,306 51,673,819.94 144,272,434 28,854,487 1.2582,149,450 12,759 373,704 37,978 35,083 68,216 51,473,835.41 144,272,309 28,854,462 1.25111,003,912 11,891 352,673 38,010 36,043 73,346 51,287,518.63 170,227,371 34,045,474 1.25 75,000,000 70,049,386 12,241 224,380 36,088 34,170 81,543 51,052,273.99 202,075,949 40,415,190 1.25‐ 110,464,576 12,657 244,337 34,987 35,596 86,958 50,849,002.21 202,072,824 40,414,565 1.25150,879,141 13,124 235,418 37,177 29,384 90,354 50,683,538.05 251,770,793 50,354,159 1.25 120,000,000 81,233,299 13,346 247,202 39,360 30,390 97,474 50,524,635.70 312,753,736 62,550,747 1.25143,784,047 14,024 267,038 41,731 29,426 110,165 50,814,618.33 312,754,861 62,550,972 1.25206,335,019 4,166 284,104 35,897 30,380 114,805 51,106,167.59 324,146,018 64,829,204 1.25 180,000,000 91,164,222 3,313 297,843 36,104 33,631 125,785 51,401,295.01 338,122,340 67,624,468 1.25158,788,691 4,222 201,105 57,389 29,739 90,619 51,736,787.37 338,133,278 67,626,656 1.25226,415,346 5,342 227,331 57,967 16,925 107,681 52,073,821.68 338,120,465 67,624,093 1.25294,039,439 8,551 238,262 58,593 17,362 118,039 52,412,432.40 354,118,528 70,823,706 1.25 245,000,000 119,863,145 13,323 247,810 59,207 18,257 130,862 ‐ 369,976,868 73,995,374 1.25193,858,518 16,151 261,837 59,916 18,745 146,548 ‐ 369,975,681 73,995,136 1.25267,853,655 17,064 226,648 84,248 17,865 135,367 ‐ 369,978,056 73,995,611 1.25341,849,266 14,951 224,691 84,983 15,652 140,642 ‐ 369,979,806 73,995,961 1.25415,845,227 15,081 234,947 86,456 16,121 152,129 ‐ 369,980,806 73,996,161 1.25489,841,388 15,919 249,713 87,902 16,762 166,550 ‐ 369,978,306 73,995,661 1.25563,837,049 16,747 260,041 89,276 17,408 180,198 ‐ 369,979,431 73,995,886 1.25 239,531,757 398,301,178 18,111 279,793 90,794 18,296 200,974 ‐ 369,975,306 73,995,061 1.25‐ 472,296,239 5,493 292,296 92,408 18,814 218,387 ‐ 369,979,431 73,995,886 1.25546,292,126 7,019 335,171 97,112 19,787 257,520 ‐ 369,969,681 73,993,936 1.25620,286,062 6,453 352,597 98,638 20,542 281,586 ‐ 369,971,743 73,994,349 1.25694,280,410 8,848 368,539 100,317 21,287 306,519 ‐ 374,930,243 74,986,049 1.25 600,000,000 169,266,459 12,284 385,523 101,920 22,049 332,326 ‐ 381,019,473 76,203,895 1.25245,470,354 18,825 403,233 103,660 22,861 361,453 ‐ 381,032,535 76,206,507 1.25321,676,861 3212/1/20423312/1/20433412/1/20443512/1/20453612/1/20463712/1/20473812/1/20483912/1/20494012/1/20504112/1/20514212/1/20524312/1/20534412/1/20544512/1/20554612/1/20564712/1/20574812/1/20584912/1/20595012/1/206021,552 394,321 95,445 21,546 371,427 ‐ 285,673,785 57,134,757 1.25 378,811,618 22,199 412,100 97,223 22,392 404,276 ‐ 309,073,410 61,814,682 1.25 250,000,000 190,626,300 23,458 428,330 152,761 23,116 439,168 ‐ 337,801,681 67,560,336 1.25‐ 258,186,636 22,134 449,075 101,037 23,977 476,267 ‐ 283,981,118 56,796,224 1.25 314,982,859 22,961 421,293 140,010 26,073 466,403 ‐ 283,984,306 56,796,861 1.25 371,779,720 24,452 424,059 142,963 26,511 490,408 ‐ 403,765,712 80,753,142 1.25452,532,863 25,398 444,961 146,057 27,392 537,229 ‐ 463,798,056 92,759,611 1.25545,292,474 6,909 461,902 149,291 28,395 584,308 ‐ 463,800,931 92,760,186 1.25638,052,660 8,724 477,627 152,489 29,313 630,743 ‐ 463,798,181 92,759,636 1.25730,812,296 11,174 503,605 155,601 30,361 656,308 ‐ 349,373,368 69,874,674 1.25800,686,970 9,139 520,728 158,955 31,315 676,369 ‐ 349,365,868 69,873,174 1.25870,560,144 14,889 546,462 162,470 32,477 705,371 ‐ 349,365,868 69,873,174 1.25940,433,317 22,880 562,487 165,955 33,535 723,997 ‐ 323,134,493 64,626,899 1.25 410,069,419 594,990,797 27,949 579,273 169,720 34,785 749,388 ‐ 328,899,431 65,779,886 1.25660,770,683 30,133 605,200 173,255 35,877 774,023 ‐ 335,033,243 67,006,649 1.25727,777,332 33,288 647,750 180,086 37,668 822,050 ‐ 309,341,806 61,868,361 1.25789,645,693 33,226 682,788 182,230 38,924 862,251 ‐ 315,785,993 63,157,199 1.25852,802,891 31,309 716,551 186,278 40,624 900,505 ‐ 322,395,743 64,479,149 1.25917,282,040 32,092 734,465 190,935 41,639 923,018 329,157,493 65,831,499 1.25983,113,539 Prepared by Seattle-Northwest Securities Corporation12/1/2009
APPENDIX C EXISTING GENERATION UNITS
ALASKA RIRP STUDY
Black & Veatch C-1 February 2010
APPENDIX C
EXISTING GENERATION UNITS
Detailed Existing Unit TablesNameUnit Primary Fuel Startup FuelWinter Rating (MW)Summer Rating (MW)Minimum Capacity (MW)Variable O&M (2009 $/MWh)Fixed O&M (2009 $/kW-yr)Full Load Net Plant Heat Rate (Btu/kWh - HHV)Forcd Outage Rate (%)Must Run (Y/N)CO2 Emission Rate (lb/mmBtu)NOx Emission Rate (lb/mmBtu)SO2 Emission Rate (lb/mmBtu) Retirement DateAnchorage ML&P – Plant 13 Natural Gas Natural Gas 32 29.3 13.7210.879,7806.0 N 114.80.44 0.000045 2037Anchorage ML&P – Plant 25 Natural Gas Natural Gas 37.4 33.8 53.7211.62141.1 N 114.80.625 0.000045 2020Anchorage ML&P – Plant 2 5/6 Natural Gas Natural Gas 49.2 44.5 103.7211.62111.1 N 114.80.625 0.000045 2020Anchorage ML&P – Plant 27 Natural Gas Natural Gas 81.8 74.4 103.727.791,1930.1 N 114.80.625 0.000045 2030Anchorage ML&P – Plant 2 7/6 Natural Gas Natural Gas 109.5 99.5 103.727.799,0300.1 N 114.80.625 0.000045 2020Anchorage ML&P – Plant 28 Natural Gas Natural Gas 87.6 77.3 203.727.4711,9301.7 N 114.80.08 0.000045 2030
Name UnitPrimary Fuel Startup FuelWinter Rating (MW)Summer Rating (MW)Minimum Capacity (MW)Variable O&M (2009 $/MWh)Fixed O&M (2009 $/kW-yr)Full Load Net Plant Heat Rate (Btu/kWh - HHV)Forcd Outage Rate (%)Must Run (Y/N)CO2 Emission Rate (lb/mmBtu)NOx Emission Rate (lb/mmBtu)SO2 Emission Rate (lb/mmBtu) Retirement DateBernice 2 Natural Gas Natural Gas 19 19 3 1.23 6.15 14,673 2.0 N 115 0.32 0.000045 2014Bernice 3 Natural Gas Natural Gas 25.5 25.5 13 1.23 19.48 13,409 2.0 N 115 0.13 0.000045 2014Bernice 4 Natural Gas Natural Gas 25.5 25.5 13 1.23 19.48 13,741 2.0 N 115 0.13 0.000045 2014Beluga 1 Natural Gas Natural Gas 17.5 16 3 1.23 14.35 15,198 2.0 N 115 0.32 0.0002 2011Beluga 2 Natural Gas Natural Gas 17.5 16 3 1.23 14.35 14,851 2.0 N 115 0.32 0.0002 2011Beluga 3 Natural Gas Natural Gas 66.5 56 3 1.44 12.30 12,236 2.0 N 115 0.32 0.0002 2014Beluga 5 Natural Gas Natural Gas 65 54 3 1.44 12.30 12,537 2.0 N 115 0.32 0.0002 2017Beluga 6 Natural Gas Natural Gas 82 64 3 1.64 13.33 11,528 1.0 N 115 0.2 0.001 2020Beluga 6/8 Natural Gas Natural Gas 108.5 83 48 2.56 29.73 9,329 4.0 N 115 0.2 0.001 2014Beluga 7 Natural Gas Natural Gas 82 66 3 1.64 13.33 12,184 1.0 N 115 0.34 0.006 2021Beluga 7/8 Natural Gas Natural Gas 108.5 85 48 2.56 29.73 9,086 4.0 N 115 0.34 0.006 2014International 1 Natural Gas Natural Gas 14 13 3 1.23 14.35 16,379 2.0 N 115 0.32 0.002 2011International 2 Natural Gas Natural Gas 14 12.5 3 1.23 14.35 17,425 2.0 N 115 0.32 0.002 2011International 3 Natural Gas Natural Gas 19 16 3 1.23 14.35 15,116 2.0 N 115 0.32 0.002 2012
Name Unit Primary Fuel Startup FuelWinter Rating (MW)Summer Rating (MW)Minimum Capacity (MW)Variable O&M (2009 $/MWh)Fixed O&M (2009 $/kW-yr)Full Load Net Plant Heat Rate (Btu/kWh - HHV)Forcd Outage Rate (%)Must Run(Y/N)CO2 Emission Rate (lb/mmBtu)NOx Emission Rate (lb/mmBtu)SO2 Emission Rate (lb/mmBtu)Retirement DateZehnder GT1 HAGO Distillate Fuel Oil 19.2 15.8 4 8.23 10.98 14,030 0.1 N 128 0.7 0.8 2030Zehnder GT2 HAGO Distillate Fuel Oil 19.6 15 4 8.23 10.98 14,190 0.2 N 128 0.7 0.8 2030North Pole GT1 HAGO Distillate Fuel Oil 62.6 50 10 3.91 21.41 10,010 0.6 N 128 0.7 0.7 2017North Pole GT2 HAGO Distillate Fuel Oil 60.6 48 10 3.91 21.41 9,720 0.5 N 128 0.7 0.7 2018North Pole CC NAPHTHA Distillate Fuel Oil 65 54 38 3.20 224.56 6,620 0.4 N 114.8 0.76 0.0022 2042Healy ST1 COAL Distillate Fuel Oil 27 26.5 20 3.30 208.60 13,870 0.7 Y 211 0.25 0.3 2022DPP 1 HAGO Distillate Fuel Oil 25.8 23.1 4 8.23 10.98 13,210 0.3 N 128 0.7 0.12 2030
Name UnitPrimary Fuel Startup FuelWinter Rating (MW)Summer Rating (MW)Minimum Capacity (MW)Variable O&M (2009 $/MWh)Fixed O&M (2009 $/kW-yr)Full Load Net Plant Heat Rate (Btu/kWh - HHV)Forcd Outage Rate (%)Must Run (Y/N)CO2 Emission Rate (lb/mmBtu)NOx Emission Rate (lb/mmBtu)SO2 Emission Rate (lb/mmBtu) Retirement DateNikiski 1 Natural Gas Natural Gas 42 38 3 6.63 4.82 12,170 1.0 Y 114.8 0.13 0.000045 2026
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-1 February 2010
APPENDIX D
REGIONAL LOAD FORECASTS
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-2 February 2010
Table D-1
GRETC’s Winter Peak Load Forecast for Evaluation
2011 - 2060
Winter Peak Demand (MW)
Year CEA GVEA HEA MEA ML&P SES GRETC
2010/2011 233.9 238.1 87.0 146.0 188.0 9.5 869.3
2011/2012 233.9 239.6 88.0 151.0 189.0 9.5 877.5
2012/2013 233.9 241.3 88.0 153.0 190.0 10.4 883.0
2013/2014 233.9 242.9 88.0 155.0 191.0 10.4 887.4
2014/2015 234.5 217.5 89.0 157.0 192.0 10.4 867.8
2015/2016 234.9 219.2 90.0 159.0 193.0 10.4 873.3
2016/2017 235.5 221.1 90.0 161.0 194.0 10.4 879.0
2017/2018 236.5 222.7 91.0 163.0 195.0 10.4 885.4
2018/2019 237.6 224.3 92.0 165.0 196.0 10.4 891.8
2019/2020 238.1 226.0 92.0 167.0 197.0 10.4 896.3
2020/2021 238.6 227.6 93.0 169.0 198.0 10.4 902.7
2021/2022 239.7 229.2 94.0 171.0 199.0 10.4 909.1
2022/2023 240.7 230.9 94.0 173.0 200.0 10.4 914.6
2023/2024 241.7 232.6 95.0 176.0 201.0 10.4 922.1
2024/2025 242.2 234.3 96.0 178.0 202.0 10.4 927.5
2025/2026 242.8 236.0 97.0 180.0 203.0 10.4 934.0
2026/2027 243.8 237.7 97.0 182.0 204.0 10.4 939.6
2027/2028 244.8 239.4 98.0 184.0 205.0 10.4 946.1
2028/2029 245.9 241.1 99.0 186.0 206.0 10.4 952.5
2029/2030 246.9 242.8 100.0 188.0 207.0 10.4 959.0
2030/2031 247.9 244.5 100.8 190.2 208.0 10.4 965.4
2031/2032 248.8 246.2 101.6 192.4 209.0 10.4 971.8
2032/2033 249.7 248.0 102.4 194.6 210.0 10.4 978.3
2033/2034 250.7 249.7 103.2 196.8 211.1 10.4 984.7
2034/2035 251.6 251.5 104.0 199.0 212.1 10.4 991.2
2035/2036 252.5 253.2 104.8 201.3 213.1 10.4 997.7
2036/2037 253.5 255.0 105.6 203.5 214.1 10.4 1004.3
2037/2038 254.4 256.7 106.4 205.8 215.2 10.4 1010.9
2038/2039 255.4 258.5 107.3 208.1 216.2 10.4 1017.4
2039/2040 256.3 260.3 108.1 210.4 217.2 10.4 1024.1
2040/2041 257.3 262.0 108.9 212.7 218.3 10.4 1030.7
2041/2042 258.2 263.8 109.7 215.0 219.3 10.4 1037.4
2042/2043 259.2 265.6 110.6 217.4 220.4 10.4 1044.1
2043/2044 260.1 267.4 111.4 219.7 221.4 10.4 1050.9
2044/2045 261.1 269.2 112.3 222.1 222.5 10.4 1057.7
2045/2046 262.0 271.1 113.1 224.5 223.5 10.4 1064.5
2046/2047 263.0 272.9 114.0 226.9 224.6 10.4 1071.3
2047/2048 264.0 274.7 114.8 229.3 225.6 10.4 1078.2
2048/2049 264.9 276.5 115.7 231.8 226.7 10.4 1085.0
2049/2050 265.9 278.4 116.5 234.2 227.7 10.4 1092.0
2050/2051 266.9 280.2 117.4 236.7 228.8 10.4 1098.9
2051/2052 267.8 282.1 118.3 239.2 229.9 10.4 1105.9
2052/2053 268.8 284.0 119.1 241.7 231.0 10.4 1112.9
2053/2054 269.8 285.8 120.0 244.2 232.0 10.4 1120.0
2054/2055 270.7 287.7 120.9 246.8 233.1 10.4 1127.1
2055/2056 271.7 289.6 121.8 249.3 234.2 10.4 1134.2
2056/2057 272.7 291.5 122.7 251.9 235.3 10.4 1141.4
2057/2058 273.7 293.4 123.6 254.5 236.4 10.4 1148.5
2058/2059 274.7 295.3 124.4 257.1 237.4 10.4 1155.8
2059/2060 275.7 297.3 125.4 259.7 238.5 10.4 1163.0
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-3 February 2010
Table D-2
GRETC’s Summer Peak Load Forecast for Evaluation
2011 - 2060
Summer Peak Demand (MW)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 160.6 191.4 75.1 91.1 167.2 10.0 668.0
2012 160.6 192.6 75.9 94.1 168.1 10.0 674.3
2013 160.6 193.9 75.9 95.0 169.0 11.0 678.5
2014 160.6 195.2 75.9 95.5 169.9 11.0 681.9
2015 161.3 174.8 76.8 95.5 170.8 11.0 666.8
2016 161.3 176.2 77.7 95.4 171.7 11.0 671.0
2017 162.0 177.7 77.7 95.3 172.6 11.0 675.4
2018 162.7 179.0 78.5 95.1 173.5 11.0 680.3
2019 163.4 180.3 79.4 95.0 174.3 11.0 685.3
2020 163.4 181.6 79.4 95.0 175.2 11.0 688.7
2021 164.2 182.9 80.2 94.9 176.1 11.0 693.6
2022 164.9 184.3 81.1 96.0 177.0 11.0 698.6
2023 165.6 185.6 81.1 97.1 177.9 11.0 702.8
2024 166.3 187.0 82.0 98.7 178.8 11.0 708.5
2025 166.3 188.3 82.8 99.9 179.7 11.0 712.7
2026 167.0 189.7 83.7 101.1 180.6 11.0 717.7
2027 167.7 191.1 83.7 102.3 181.5 11.0 722.0
2028 168.4 192.4 84.6 103.5 182.3 11.0 726.9
2029 169.2 193.8 85.4 104.7 183.2 11.0 731.9
2030 169.9 195.2 86.3 105.9 184.1 11.0 736.9
2031 170.5 196.5 87.0 107.2 185.0 11.0 741.8
2032 171.2 197.9 87.7 108.5 185.9 11.0 746.8
2033 171.8 199.3 88.3 109.8 186.8 11.0 751.7
2034 172.4 200.7 89.0 111.1 187.7 11.0 756.7
2035 173.1 202.1 89.7 112.5 188.7 11.0 761.6
2036 173.7 203.5 90.4 113.8 189.6 11.1 766.7
2037 174.4 204.9 91.1 115.2 190.5 11.1 771.7
2038 175.0 206.3 91.8 116.6 191.4 11.2 776.7
2039 175.7 207.8 92.6 117.9 192.3 11.2 781.8
2040 176.3 209.2 93.3 119.3 193.2 11.3 786.9
2041 177.0 210.6 94.0 120.7 194.2 11.4 792.0
2042 177.6 212.1 94.7 122.1 195.1 11.4 797.1
2043 178.3 213.5 95.4 123.5 196.0 11.5 802.3
2044 179.0 214.9 96.1 124.9 196.9 11.5 807.5
2045 179.6 216.4 96.9 126.4 197.9 11.6 812.7
2046 180.3 217.9 97.6 127.8 198.8 11.7 817.9
2047 180.9 219.3 98.3 129.3 199.8 11.7 823.2
2048 181.6 220.8 99.1 130.7 200.7 11.8 828.4
2049 182.3 222.3 99.8 132.2 201.6 11.8 833.7
2050 182.9 223.8 100.5 133.7 202.6 11.9 839.1
2051 183.6 225.3 101.3 135.2 203.5 12.0 844.4
2052 184.3 226.7 102.0 136.7 204.5 12.0 849.8
2053 184.9 228.2 102.8 138.2 205.4 12.1 855.2
2054 185.6 229.8 103.6 139.7 206.4 12.1 860.6
2055 186.3 231.3 104.3 141.3 207.3 12.2 866.0
2056 186.9 232.8 105.1 142.8 208.3 12.3 871.5
2057 187.6 234.3 105.8 144.4 209.3 12.3 877.0
2058 188.3 235.8 106.6 145.9 210.2 12.4 882.5
2059 189.0 237.4 107.4 147.5 211.2 12.4 888.1
2060 189.6 238.9 108.2 149.1 212.2 12.5 893.6
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-4 February 2010
Table D-3
GRETC’s Annual Valley Load Forecast for Evaluation
2011 - 2060
Annual Valley Demand (MW)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 95.4 88.6 44.4 53.2 91.0 4.4 413.5
2012 95.4 89.2 44.9 55.0 91.5 4.4 417.2
2013 95.4 89.8 44.9 55.8 91.9 4.8 419.7
2014 95.4 90.4 44.9 56.5 92.4 4.8 421.7
2015 95.8 81.0 45.5 57.2 92.9 4.8 413.7
2016 95.8 81.6 46.0 58.0 93.4 4.8 416.3
2017 96.3 82.3 46.0 58.7 93.9 4.8 418.9
2018 96.7 82.9 46.5 59.4 94.4 4.8 421.9
2019 97.1 83.5 47.0 60.2 94.8 4.8 424.9
2020 97.1 84.1 47.0 60.9 95.3 4.8 426.9
2021 97.5 84.7 47.5 61.6 95.8 4.8 429.9
2022 98.0 85.3 48.0 62.3 96.3 4.8 433.0
2023 98.4 86.0 48.0 63.1 96.8 4.8 435.4
2024 98.8 86.6 48.5 64.2 97.3 4.8 438.9
2025 98.8 87.2 49.0 64.9 97.7 4.8 441.4
2026 99.2 87.8 49.5 65.6 98.2 4.8 444.5
2027 99.7 88.5 49.5 66.4 98.7 4.8 447.0
2028 100.1 89.1 50.1 67.1 99.2 4.8 450.0
2029 100.5 89.7 50.6 67.8 99.7 4.8 453.1
2030 100.9 90.4 51.1 68.5 100.2 4.8 456.1
2031 101.3 91.0 51.5 69.3 100.7 4.8 459.1
2032 101.7 91.7 51.9 70.1 101.1 4.8 462.1
2033 102.1 92.3 52.3 70.9 101.6 4.8 465.1
2034 102.5 93.0 52.7 71.7 102.1 4.8 468.1
2035 102.8 93.6 53.1 72.6 102.6 4.8 471.1
2036 103.2 94.3 53.5 73.4 103.1 4.8 474.1
2037 103.6 94.9 54.0 74.2 103.6 4.8 477.2
2038 104.0 95.6 54.4 75.0 104.1 4.8 480.2
2039 104.4 96.2 54.8 75.9 104.6 4.8 483.3
2040 104.8 96.9 55.2 76.7 105.1 4.8 486.4
2041 105.2 97.5 55.6 77.5 105.6 4.8 489.5
2042 105.5 98.2 56.1 78.4 106.1 4.8 492.6
2043 105.9 98.9 56.5 79.2 106.6 4.8 495.7
2044 106.3 99.5 56.9 80.1 107.1 4.8 498.8
2045 106.7 100.2 57.3 81.0 107.6 4.8 502.0
2046 107.1 100.9 57.8 81.8 108.2 4.8 505.2
2047 107.5 101.6 58.2 82.7 108.7 4.8 508.3
2048 107.9 102.3 58.6 83.6 109.2 4.8 511.5
2049 108.3 102.9 59.1 84.5 109.7 4.8 514.7
2050 108.7 103.6 59.5 85.4 110.2 4.8 517.9
2051 109.1 104.3 60.0 86.3 110.7 4.8 521.2
2052 109.5 105.0 60.4 87.2 111.2 4.8 524.4
2053 109.9 105.7 60.9 88.1 111.8 4.8 527.7
2054 110.3 106.4 61.3 89.0 112.3 4.8 530.9
2055 110.7 107.1 61.7 90.0 112.8 4.8 534.2
2056 111.1 107.8 62.2 90.9 113.3 4.8 537.5
2057 111.5 108.5 62.7 91.8 113.8 4.8 540.8
2058 111.9 109.2 63.1 92.8 114.4 4.8 544.2
2059 112.3 109.9 63.6 93.7 114.9 4.8 547.5
2060 112.7 110.7 64.0 94.7 115.4 4.8 550.9
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-5 February 2010
Table D-4
GRETC’s Net Energy for Load Forecast for Evaluation
2011 - 2060
Utility Net Energy for Load Forecast (GWh)
Year CEA GVEA HEA MEA ML&P SES GRETC
2011 1,302.0 1,522.7 554.5 771.2 1,162.8 64.6 5,377.8
2012 1,303.2 1,532.1 557.1 801.9 1,168.3 64.8 5,427.4
2013 1,305.0 1,543.0 560.2 811.1 1,173.8 65.0 5,458.1
2014 1,307.5 1,553.2 564.0 820.9 1,179.3 65.3 5,490.3
2015 1,311.4 1,333.5 568.1 831.9 1,184.9 65.6 5,295.3
2016 1,315.6 1,344.4 572.4 842.8 1,190.4 65.9 5,331.5
2017 1,320.1 1,355.5 577.0 854.0 1,196.0 66.3 5,369.0
2018 1,324.8 1,361.5 581.7 865.4 1,201.6 66.6 5,401.6
2019 1,329.6 1,367.4 586.5 876.8 1,207.3 67.0 5,434.7
2020 1,334.5 1,373.4 591.2 888.3 1,213.0 67.4 5,467.8
2021 1,339.4 1,379.5 596.1 900.1 1,218.7 67.8 5,501.6
2022 1,344.3 1,385.5 601.0 911.7 1,224.4 68.1 5,535.0
2023 1,349.2 1,391.6 605.9 923.2 1,230.1 68.5 5,568.6
2024 1,354.3 1,397.7 610.7 934.8 1,235.9 68.9 5,602.3
2025 1,359.2 1,403.8 615.5 946.4 1,241.7 69.3 5,636.0
2026 1,364.2 1,410.0 620.4 958.0 1,247.6 69.7 5,669.9
2027 1,369.3 1,416.2 625.3 969.7 1,253.4 70.0 5,703.9
2028 1,374.4 1,422.3 630.2 981.3 1,259.3 70.4 5,738.0
2029 1,379.5 1,428.5 635.1 992.9 1,265.3 70.8 5,772.0
2030 1,384.5 1,434.7 640.0 1,004.7 1,271.2 71.2 5,806.3
2031 1,389.6 1,440.8 645.0 1,016.7 1,277.1 71.6 5,840.8
2032 1,394.7 1,447.0 650.0 1,028.7 1,283.0 72.0 5,875.4
2033 1,399.7 1,453.3 655.0 1,040.9 1,289.0 72.4 5,910.2
2034 1,404.8 1,459.5 660.0 1,053.1 1,294.9 72.7 5,945.1
2035 1,409.9 1,465.7 665.1 1,065.4 1,300.9 73.1 5,980.1
2036 1,415.0 1,472.0 670.2 1,077.8 1,306.8 73.5 6,015.3
2037 1,420.1 1,478.2 675.3 1,090.2 1,312.8 73.9 6,050.6
2038 1,425.3 1,484.5 680.4 1,102.8 1,318.8 74.3 6,086.1
2039 1,430.4 1,490.8 685.5 1,115.4 1,324.9 74.7 6,121.7
2040 1,435.5 1,497.1 690.7 1,128.1 1,330.9 75.1 6,157.4
2041 1,440.7 1,503.5 695.9 1,140.9 1,336.9 75.5 6,193.3
2042 1,445.8 1,509.8 701.1 1,153.7 1,343.0 75.9 6,229.3
2043 1,451.0 1,516.2 706.3 1,166.7 1,349.1 76.3 6,265.5
2044 1,456.2 1,522.5 711.5 1,179.7 1,355.2 76.7 6,301.9
2045 1,461.4 1,528.9 716.8 1,192.9 1,361.3 77.1 6,338.4
2046 1,466.6 1,535.3 722.1 1,206.1 1,367.4 77.5 6,375.0
2047 1,471.8 1,541.7 727.4 1,219.4 1,373.5 77.9 6,411.8
2048 1,477.0 1,548.2 732.8 1,232.8 1,379.7 78.3 6,448.8
2049 1,482.3 1,554.6 738.1 1,246.3 1,385.9 78.7 6,485.9
2050 1,487.5 1,561.1 743.5 1,259.9 1,392.1 79.1 6,523.2
2051 1,492.8 1,567.5 748.9 1,273.6 1,398.3 79.5 6,560.6
2052 1,498.0 1,574.0 754.4 1,287.4 1,404.5 79.9 6,598.2
2053 1,503.3 1,580.5 759.8 1,301.3 1,410.7 80.3 6,635.9
2054 1,508.6 1,587.1 765.3 1,315.3 1,416.9 80.7 6,673.9
2055 1,513.9 1,593.6 770.8 1,329.4 1,423.2 81.1 6,712.0
2056 1,519.2 1,600.1 776.3 1,343.6 1,429.5 81.5 6,750.2
2057 1,524.5 1,606.7 781.9 1,357.9 1,435.8 81.9 6,788.7
2058 1,529.8 1,613.3 787.5 1,372.3 1,442.1 82.3 6,827.3
2059 1,535.1 1,619.9 793.1 1,386.8 1,448.4 82.8 6,866.0
2060 1,540.5 1,626.5 798.7 1,401.4 1,454.7 83.2 6,905.0
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-6 February 2010
Table D-5
GRETC’s Winter Peak Large Load Forecast for Evaluation
2011 - 2060
Large Load Winter Peak Demand (MW)
Year GVEA Anchorage MEA Kenai GRETC
2010/2011 238.1 412.2 146.0 96.3 869.3
2011/2012 239.6 413.2 151.0 97.2 877.5
2012/2013 241.3 414.2 153.0 98.2 883.0
2013/2014 242.9 415.1 155.0 98.2 887.4
2014/2015 217.5 417.1 157.0 99.2 867.8
2015/2016 219.2 418.1 159.0 100.2 873.3
2016/2017 221.1 420.1 161.0 100.2 879.0
2017/2018 222.7 422.1 163.0 101.2 885.4
2018/2019 224.3 424.1 165.0 102.2 891.8
2019/2020 226.0 425.1 167.0 102.2 896.3
2020/2021 227.6 427.1 169.0 103.2 902.7
2021/2022 229.2 429.0 171.0 104.2 909.1
2022/2023 230.9 431.0 173.0 104.2 914.6
2023/2024 232.6 433.0 176.0 105.2 922.1
2024/2025 384.3 734.0 178.0 156.2 1398.3
2025/2026 386.0 736.0 180.0 157.2 1404.7
2026/2027 387.7 738.0 182.0 157.2 1410.2
2027/2028 389.4 740.0 184.0 158.2 1416.6
2028/2029 391.1 742.0 186.0 159.2 1423.1
2029/2030 392.8 744.0 188.0 160.1 1429.5
2030/2031 394.5 745.9 190.2 160.9 1435.8
2031/2032 396.2 747.8 192.4 161.7 1442.2
2032/2033 398.0 749.7 194.6 162.5 1448.6
2033/2034 399.7 751.6 196.8 163.3 1455.0
2034/2035 401.5 753.5 199.0 164.1 1461.4
2035/2036 403.2 755.4 201.3 165.0 1468.0
2036/2037 405.0 757.4 203.5 165.8 1474.5
2037/2038 406.7 759.3 205.8 166.7 1481.1
2038/2039 408.5 761.2 208.1 167.6 1487.7
2039/2040 560.3 1063.2 210.4 218.5 1975.7
2040/2041 562.0 1065.1 212.7 219.3 1982.3
2041/2042 563.8 1067.1 215.0 220.2 1989.0
2042/2043 565.6 1069.0 217.4 221.1 1995.7
2043/2044 567.4 1071.0 219.7 222.0 2002.5
2044/2045 569.2 1072.9 222.1 222.9 2009.3
2045/2046 571.1 1074.9 224.5 223.8 2016.1
2046/2047 572.9 1076.9 226.9 224.7 2022.9
2047/2048 574.7 1078.9 229.3 225.6 2029.8
2048/2049 576.5 1080.8 231.8 226.5 2036.7
2049/2050 578.4 1082.8 234.2 227.4 2043.6
2050/2051 580.2 1084.8 236.7 228.4 2050.6
2051/2052 582.1 1086.8 239.2 229.3 2057.6
2052/2053 584.0 1088.8 241.7 230.2 2064.6
2053/2054 585.8 1090.8 244.2 231.1 2071.7
2054/2055 587.7 1092.8 246.8 232.1 2078.8
2055/2056 589.6 1094.8 249.3 233.0 2085.9
2056/2057 591.5 1096.8 251.9 234.0 2093.0
2057/2058 593.4 1098.9 254.5 234.9 2100.2
2058/2059 595.3 1100.9 257.1 235.8 2107.5
2059/2060 597.3 1102.9 259.7 236.8 2114.7
APPENDIX D REGIONAL LOAD FORECASTS
ALASKA RIRP STUDY
Black & Veatch D-7 February 2010
Table D-6
GRETC’s Large Load Net Energy for Load Forecast for Evaluation (GWh)
2011 - 2060
Large Load Net Energy for Load Forecast (GWh)
Year GVEA Anchorage MEA Kenai GRETC
2011 1,522.7 2,464.8 771.2 619.1 5,377.8
2012 1,532.1 2,471.5 801.9 621.9 5,427.4
2013 1,543.0 2,478.8 811.1 625.2 5,458.1
2014 1,553.2 2,486.9 820.9 629.3 5,490.3
2015 1,333.5 2,496.2 831.9 633.7 5,295.3
2016 1,344.4 2,506.0 842.8 638.3 5,331.5
2017 1,355.5 2,516.2 854.0 643.3 5,369.0
2018 1,361.5 2,526.4 865.4 648.3 5,401.6
2019 1,367.4 2,536.9 876.8 653.5 5,434.7
2020 1,373.4 2,547.4 888.3 658.6 5,467.8
2021 1,379.5 2,558.1 900.1 663.9 5,501.6
2022 1,385.5 2,568.7 911.7 669.1 5,535.0
2023 1,391.6 2,579.4 923.2 674.4 5,568.6
2024 1,397.7 2,590.2 934.8 679.6 5,602.3
2025 2,389.3 4,572.0 946.4 1,013.3 8,921.0
2026 2,395.5 4,582.8 958.0 1,018.6 8,954.9
2027 2,401.7 4,593.7 969.7 1,023.8 8,988.9
2028 2,410.5 4,610.1 981.3 1,030.0 9,032.0
2029 2,414.0 4,615.7 992.9 1,034.4 9,057.0
2030 2,420.2 4,626.7 1,004.7 1,039.7 9,091.3
2031 2,426.3 4,637.7 1,016.7 1,045.1 9,125.8
2032 2,435.2 4,654.1 1,028.7 1,051.3 9,169.4
2033 2,438.8 4,659.7 1,040.9 1,055.8 9,195.2
2034 2,445.0 4,670.7 1,053.1 1,061.3 9,230.1
2035 2,451.2 4,681.8 1,065.4 1,066.7 9,265.1
2036 2,460.2 4,698.3 1,077.8 1,073.1 9,309.3
2037 2,463.7 4,704.0 1,090.2 1,077.7 9,335.6
2038 2,470.0 4,715.1 1,102.8 1,083.2 9,371.1
2039 2,476.3 4,726.2 1,115.4 1,088.7 9,406.7
2040 3,473.5 6,719.2 1,128.1 1,424.6 12,745.4
2041 3,474.5 6,719.6 1,140.9 1,428.3 12,763.3
2042 3,480.8 6,730.9 1,153.7 1,433.9 12,799.3
2043 3,487.2 6,742.1 1,166.7 1,439.6 12,835.5
2044 3,498.9 6,764.2 1,179.7 1,447.0 12,889.9
2045 3,499.9 6,764.7 1,192.9 1,450.9 12,908.4
2046 3,506.3 6,776.0 1,206.1 1,456.6 12,945.0
2047 3,512.7 6,787.4 1,219.4 1,462.3 12,981.8
2048 3,524.6 6,809.5 1,232.8 1,469.8 13,036.8
2049 3,525.6 6,810.1 1,246.3 1,473.8 13,055.9
2050 3,532.1 6,821.6 1,259.9 1,479.6 13,093.2
2051 3,538.5 6,833.0 1,273.6 1,485.4 13,130.6
2052 3,550.4 6,855.3 1,287.4 1,493.0 13,186.2
2053 3,551.5 6,856.0 1,301.3 1,497.1 13,205.9
2054 3,558.1 6,867.5 1,315.3 1,503.0 13,243.9
2055 3,564.6 6,879.1 1,329.4 1,508.9 13,282.0
2056 3,576.5 6,901.5 1,343.6 1,516.6 13,338.2
2057 3,577.7 6,902.3 1,357.9 1,520.8 13,358.7
2058 3,584.3 6,913.9 1,372.3 1,526.8 13,397.3
2059 3,590.9 6,925.6 1,386.8 1,532.8 13,436.0
2060 3,602.9 6,948.0 1,401.4 1,540.7 13,493.0
APPENDIX E DETAILED RESULTS – SCENARIOS 1A / 1B
ALASKA RIRP STUDY
Black & Veatch E-1 February 2010
APPENDIX E
DETAILED RESULTS – SCENARIOS 1A / 1B
Plan 1A_1B P50 SummaryYear Additions RetirementsReserve Margin (%)Renewable Generation (%) Fuel Costs ($000)Total O&M Costs ($000) CO2 Costs ($000) DSM Costs ($000)Annual Capital Fixed Charges ($000)Total Annual Costs ($000)Present Value of Annual Costs ($000)Cumulative Present Value ($000)2011Nikiski Wind; HCCPBeluga - 1; Beluga - 2; International - 1; International - 2 55.82% 11.92% $351,806 $78,494 $1,102 $651 $12,326 $444,378 $444,378 $444,3782012Fire Island International - 3 47.47% 15.18% $359,297 $86,269 $54,767 $1,491 $40,350 $542,175 506,706 951,0842013Anchorage 1x1 6FA 62.51% 14.98% $330,019 $88,259 $57,514 $3,063 $75,558 $554,413 484,245 1,435,3292014Glacier ForkBeluga - 3; Beluga - 6/8; Beluga - 7/8; Bernice - 2; Bernice - 3 71.52% 15.94% $339,919 $90,226 $63,386 $5,878 $108,169 $607,578 495,965 1,931,2942015Anchorage MSW 55.23% 24.72% $348,659 $87,384 $62,082 $10,455 $131,358 $639,938 488,205 2,419,500201659.21% 24.60% $382,711 $89,392 $68,949 $12,759 $170,907 $724,717 516,713 2,936,2132017GVEA MSW Beluga - 5; NP1 60.91% 24.85% $357,899 $89,413 $74,393 $11,891 $199,985 $733,582 488,817 3,425,0302018GVEA 1X1 NPole Retrofit NP2 54.30% 24.83% $276,253 $83,051 $80,365 $12,241 $211,778 $663,688 413,311 3,838,341201947.96% 24.62% $295,815 $82,983 $87,105 $12,657 $211,778 $690,338 401,783 4,240,1242020Mount Spurr Beluga - 6; MLP 5; MLP 5/6; MLP 7/6 46.22% 31.89% $302,861 $102,110 $88,427 $13,124 $273,431 $779,954 424,243 4,664,3672021Anchorage 1x1 6FA Beluga - 7 55.99% 31.60% $310,824 $106,747 $93,910 $13,346 $342,861 $867,688 441,089 5,105,4562022Mount Spurr Healy - 1 51.00% 38.52% $297,025 $126,402 $96,170 $14,024 $391,772 $925,393 439,648 5,545,103202346.86% 38.33% $325,599 $123,469 $97,048 $4,166 $395,365 $945,647 419,879 5,964,982202445.69% 38.18% $340,682 $126,429 $109,073 $3,313 $433,745 $1,013,242 420,460 6,385,4412025Chakachamna:Chakachamna GVEA Aurora Purchase - Tier I 84.55% 62.32% $220,174 $138,656 $75,946 $4,222 $693,340 $1,132,337 439,140 6,824,5812026Nikiski 75.13% 62.52% $234,402 $129,355 $88,159 $5,342 $693,340 $1,150,598 417,030 7,241,611202773.98% 63.00% $227,330 $132,294 $94,512 $8,551 $695,689 $1,158,376 392,382 7,633,993202872.66% 63.06% $230,300 $135,279 $103,224 $13,323 $695,689 $1,177,815 372,866 8,006,859202971.37% 61.83% $242,192 $138,036 $118,165 $16,151 $695,689 $1,210,233 358,064 8,364,9232030Kenai Hydro DPP - 6; MLP 7; MLP 8; Zen1; Zen2 50.97% 63.97% $185,036 $139,321 $110,881 $17,064 $700,698 $1,153,000 318,814 8,683,737203142.40% 62.03% $192,346 $139,762 $120,883 $14,951 $697,301 $1,165,243 301,121 8,984,858203241.36% 62.78% $191,723 $142,989 $129,151 $15,081 $677,251 $1,156,195 279,236 9,264,095203340.32% 61.88% $199,354 $146,152 $141,847 $15,919 $677,251 $1,180,522 266,459 9,530,554203439.30% 61.50% $203,127 $149,310 $154,233 $16,747 $677,251 $1,200,668 253,277 9,783,831203538.29% 61.86% $205,017 $152,770 $165,394 $18,111 $677,251 $1,218,543 240,232 10,024,063203637.29% 61.55% $207,662 $156,125 $183,109 $5,493 $677,251 $1,229,640 226,560 10,250,6232037GVEA LMS100 MLP 3 43.27% 60.64% $217,063 $162,624 $200,100 $7,019 $703,248 $1,290,053 222,141 10,472,764203842.23% 60.94% $218,402 $166,071 $217,232 $6,453 $703,248 $1,311,404 211,045 10,683,809203941.22% 60.75% $230,127 $170,053 $235,833 $8,848 $703,248 $1,348,108 202,758 10,886,568204040.20% 60.25% $243,640 $173,619 $259,739 $12,284 $703,248 $1,392,529 195,738 11,082,305204139.21% 60.34% $253,301 $177,608 $279,986 $18,825 $694,319 $1,424,038 187,072 11,269,3772042GVEA 1x1 6FA NPCC 48.65% 59.27% $276,556 $169,650 $309,508 $21,552 $758,395 $1,535,661 188,538 11,457,915204347.60% 59.37% $288,608 $173,713 $335,805 $22,199 $723,187 $1,543,512 177,104 11,635,019204446.55% 59.21% $300,081 $231,589 $363,392 $23,458 $690,575 $1,609,095 172,551 11,807,570204545.51% 58.76% $317,604 $181,983 $395,339 $22,134 $667,387 $1,584,446 158,792 11,966,3622046Anchorage LM6000 49.40% 58.33% $337,808 $189,592 $429,301 $22,961 $643,804 $1,623,465 152,059 12,118,421204748.36% 57.93% $353,295 $194,064 $464,681 $24,452 $614,726 $1,651,218 144,540 12,262,961204847.31% 57.73% $370,037 $198,719 $505,529 $25,398 $602,933 $1,702,617 139,289 12,402,250204946.30% 57.57% $386,486 $203,794 $546,949 $6,909 $602,933 $1,747,070 133,575 12,535,825205045.26% 57.17% $405,470 $208,369 $595,985 $8,724 $541,280 $1,759,830 125,749 12,661,574205144.26% 57.05% $420,223 $213,071 $616,838 $11,174 $471,850 $1,733,156 115,741 12,777,315205243.26% 56.77% $438,398 $218,532 $632,661 $9,139 $422,939 $1,721,668 107,452 12,884,767205342.27% 56.11% $463,378 $223,819 $667,701 $14,889 $419,346 $1,789,132 104,358 12,989,124205441.28% 55.98% $481,702 $229,337 $692,040 $22,880 $380,966 $1,806,925 98,500 13,087,625205540.31% 55.65% $503,136 $235,076 $717,142 $27,949 $376,280 $1,859,584 94,739 13,182,364205639.35% 55.43% $521,505 $240,450 $745,668 $30,133 $376,280 $1,914,035 91,134 13,273,4982057GVEA LMS100 Cooper Lake 47.51% 54.83% $585,511 $250,156 $787,838 $33,288 $416,531 $2,073,323 92,260 13,365,758205844.71% 53.85% $615,490 $254,038 $829,889 $33,226 $416,531 $2,149,172 89,379 13,455,136205943.71%53.88%$647,398$261,068$862,589$31,309$416,531 $2,218,894 86,24113,541,378206042.73% 53.09%$677,429$267,339$902,580$32,092$411,521 $2,290,960 83,21713,624,595Present Value of Costs4,547,9731,750,4301,921,235149,4745,255,484Grand Total13,624,595Scenario 1A/1B Plan - P50 Natural Gas ForecastBlack & Veatch Confidential2/18/2010Page 1
Plan 1A_1B P50 SummaryYearAnchorage InteriorMatanuska Kenai Total Railbelt201133,720 0 0 4,304 38,024201231,553 0 0 5,310 36,863201331,457 0 0 3,877 35,334201430,904 0 0 3,241 34,145201522,249 0 0 2,555 24,803201621,201 0 0 2,757 23,957201721,919 0 0 2,645 24,563201818,693 9,034 0 2,741 30,468201918,656 8,262 0 2,780 29,697202014,852 8,087 0 2,803 25,742202115,866 7,311 0 2,215 25,391202214,094 6,846 0 2,041 22,980202314,741 7,727 0 2,070 24,538202415,267 7,366 0 2,197 24,830202510,081 4,435 0 1,328 15,844202610,393 5,170 0 956 16,519202710,646 5,243 0 0 15,889202810,638 5,289 0 0 15,927202910,865 5,792 0 0 16,65720305,914 6,410 0 0 12,32420317,382 5,563 0 0 12,94520327,325 5,366 0 0 12,69020337,524 5,595 0 0 13,11820347,679 5,589 0 0 13,26820357,709 5,543 0 0 13,25320368,464 4,990 0 0 13,45420376,734 7,581 0 0 14,31520386,460 7,995 0 0 14,45520396,583 8,118 0 0 14,70120406,626 8,411 0 0 15,03720416,725 8,363 0 0 15,08820426,098 9,918 0 0 16,01520436,074 10,083 0 0 16,15720446,226 10,003 0 0 16,22920456,293 10,376 0 0 16,67020467,987 9,250 0 0 17,23720478,290 9,166 0 0 17,45620488,296 9,419 0 0 17,71520498,431 9,493 0 0 17,92420508,533 9,714 0 0 18,24720518,649 9,696 0 0 18,34520528,864 9,698 0 0 18,56320538,917 10,106 0 0 19,02320549,061 10,114 0 0 19,17520559,078 10,367 0 0 19,44520569,378 10,196 0 0 19,57320577,933 13,595 0 0 21,52820588,355 13,629 0 0 21,98420598,374 14,102 0 0 22,47620608,529 14,320 0 0 22,849Scenario 1A/1B Plan - P50 Natural Gas ForecastAnnual Natural Gas Usage (mmBtu)Black & Veatch Confidential2/18/2010Page 2
Plan 1A_1B P50 SummaryYear Nikiski Wind HCCP Fire Island Anchorage 1x1 6FA Glacier ForkAnchorage MSW GVEA MSWGVEA 1X1 NPole Retrofit Mount Spurr TAnchorage 1x1 6FA Mount SpurrChakachamna:ChakachamnaKenai Hydro GVEA LMS100 GVEA 1x1 6FAAnchorage LM6000GVEA LMS100Generating Unit Capital Cost Cash Flow ($000)201130,468 99,809 175,454 210,604 127,935 0 0 0 0 0 0 0 0 0 0 0 644,2702012132,925 116,563 40,740290,2282013119,477 95,638215,114201486,719 9,00095,719201521,127 18,08339,210201619,157 42,450 33,69995,306201738,492 72,765 26,866138,1232018170,818 76,085 43,273290,1772019154,889 178,613 68,804 79,301481,6072020161,957 161,519 238,340561,8162021146,457 481,537627,9942022652,793652,7932023712,138 247712,3852024141,426 253141,68020252602602026266266202718,56018,560202817,90517,905202918,35318,353203020312032203320342,260 2,2602035206,133 206,133203631,138 31,138203720382039127,792 127,7922040299,994 299,9942041272,020 272,02020422043204427,076 27,0762045123,405 123,4052046204720482049205020512052205320543,703 3,7032055337,773 337,773205651,024 51,0242057205820592060Total6,524,085Scenario 1A/1B Plan - P50 Natural Gas ForecastCash Flow per Generating Unit Addition Black & Veatch Confidential2/18/2010Page 3
Plan 1A_1B P50 SummaryYearTotal Generating Unit Capital Cost Cash Flow ($000)Total Transmission Project Capital Cost Cash Flow ($000)Total Capital Cost Cash Flow ($000)DSM Costs ($000)Fuel Cost ($000)Fixed O&M ($000)Variable O&M ($000)CO2 Costs ($000)Energy Requirements After DSM (GWh)2011644,270 79,848 724,118 651 351,806 43,795 34,699 1,102 5,3722012290,228 3,365 293,593 1,491 359,297 48,337 37,933 54,767 5,4122013215,114 51,272 266,387 3,063 330,019 52,191 36,068 57,514 5,424201495,719 228,409 324,128 5,878 339,919 53,317 36,909 63,386 5,421201539,210 314,097 353,307 10,455 348,659 48,327 39,057 62,082 5,167201695,306 129,804 225,111 12,759 382,711 48,775 40,617 68,949 5,1472017138,123 8,812 146,935 11,891 357,899 49,059 40,354 74,393 5,1292018290,177 97,549 387,726 12,241 276,253 47,413 35,638 80,365 5,1052019481,607 214,570 696,177 12,657 295,815 46,596 36,386 87,105 5,0852020561,816 166,433 728,249 13,124 302,861 64,626 37,485 88,427 5,0682021627,994 73,715 701,709 13,346 310,824 68,386 38,361 93,910 5,0522022652,793 195,732 848,525 14,024 297,025 86,668 39,734 96,170 5,0812023712,385 205,995 918,380 4,166 325,599 82,114 41,355 97,048 5,1112024141,680 23,643 165,323 3,313 340,682 83,658 42,770 109,073 5,1402025260 10,784 11,044 4,222 220,174 106,273 32,383 75,946 5,1742026266 11,289 11,555 5,342 234,402 108,234 21,121 88,159 5,207202718,560 18,560 8,551 227,330 110,277 22,017 94,512 5,241202817,905 17,905 13,323 230,300 112,362 22,917 103,224 5,275202918,353 18,353 16,151 242,192 114,541 23,495 118,165 5,30920300 17,064 185,036 116,065 23,256 110,881 5,34420310 14,951 192,346 117,757 22,005 120,883 5,37820320 15,081 191,723 120,236 22,754 129,151 5,41320330 15,919 199,354 122,661 23,490 141,847 5,44720342,260 2,260 16,747 203,127 125,061 24,250 154,233 5,4822035206,133 206,133 18,111 205,017 127,634 25,135 165,394 5,517203631,138 31,138 5,493 207,662 130,359 25,766 183,109 5,55320370 7,019 217,063 136,144 26,480 200,100 5,58820380 6,453 218,402 138,807 27,264 217,232 5,6232039127,792 127,792 8,848 230,127 141,651 28,402 235,833 5,6592040299,994 299,994 12,284 243,640 144,475 29,143 259,739 5,6952041272,020 272,020 18,825 253,301 147,408 30,200 279,986 5,73120420 21,552 276,556 140,448 29,202 309,508 5,76720430 22,199 288,608 143,513 30,200 335,805 5,803204427,076 27,076 23,458 300,081 200,404 31,185 363,392 5,8392045123,405 123,405 22,134 317,604 149,991 31,991 395,339 5,87620460 22,961 337,808 156,421 33,170 429,301 5,91220470 24,452 353,295 159,869 34,195 464,681 5,94920480 25,398 370,037 163,510 35,210 505,529 5,98620490 6,909 386,486 167,227 36,567 546,949 6,023205008,724 405,470 170,958 37,411 595,9856,06020510 11,174 420,223 174,609 38,462 616,8386,098205209,139 438,398 178,567 39,965 632,6616,13520530 14,889 463,378 182,614 41,204 667,7016,17320543,7033,703 22,880 481,702 186,688 42,648 692,0406,2112055337,773337,773 27,949 503,136 191,057 44,020 717,1426,249205651,02451,024 30,133 521,505 195,250 45,200 745,6686,28720570 33,288 585,511 202,909 47,247 787,8386,32620580 33,226 615,490 205,703 48,334 829,8896,36420590 31,309 647,398 210,417 50,651 862,5896,40320600 32,092 677,429 215,317 52,022 902,5806,442Total6,524,0851,815,317 Total of Cash Flows &9,086,710Scenario 1A/1B Plan - P50 Natural Gas ForecastSummary of Cash Flows and Production CostsBlack & Veatch Confidential2/18/2010Page 6
Plan 1A_1B P50 SummaryYearCapacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)20111,104 3,542 80 435 251 580 25 210 176 591 15 4920121,258 3,425 80 493 251 501 25 215 176 593 69 23120131,195 3,490 80 556 251 384 25 213 176 591 69 22620141,176 3,354 80 630 251 380 25 213 251 649 69 22720151,176 2,432 80 618 251 619 25 212 251 919 22 163 69 2272016822 2,316 80 625 251 703 25 213 251 921 22 163 69 2282017822 2,388 80 611 251 602 25 212 251 919 26 188 69 2272018821 2,441 80 554 189 591 25 212 251 919 26 195 69 2272019821 2,443 80 563 189 563 25 212 251 919 26 193 69 22620201,103 2,567 80 587 25 211 251 921 50 403 26 192 69 2282021907 2,595 80 550 25 208 251 919 50 402 26 190 69 2272022825 2,250 80 543 25 204 251 919 100 800 26 186 69 2272023743 2,450 80 364 25 205 251 919 100 802 26 187 69 2272024743 2,452 53 374 25 206 251 921 100 803 26 188 69 2272025743 1,285 53 278 25 174 581 2,528 100 651 26 107 69 2262026743 1,448 53 292581 2,519 100 680 26 119 69 2272027701 1,441 53 285581 2,518 100 708 26 140 69 2272028701 1,456 53 282581 2,525 100 734 26 132 69 2272029701 1,537 53 282581 2,517 100 688 26 136 69 2272030701 1,387 53 323586 2,537 100 797 26 154 69 2262031531 1,507 53 325586 2,538 100 719 26 139 69 2262032467 1,476 53 327586 2,544 100 765 26 152 69 2282033467 1,540 53 327586 2,537 100 746 26 147 69 2272034467 1,572 53 330586 2,538 100 739 26 153 69 2272035467 1,568 53 328586 2,538 100 783 26 151 69 22720365621,588 53 340586 2,544 100 768 26 163 69 2272037564 1,676 53 317586 2,537 100 752 26 153 69 2272038532 1,676 53 317586 2,537 100 783 26 162 69 2272039532 1,700 53 320586 2,537 100 808 26 147 69 2272040532 1,740 53 323586 2,544 100 771 26 164 69 2312041693 1,749 53 324586 2,537 100 813 26 161 69 2262042693 1,851 53 303586 2,537 100 764 26 165 69 2272043630 1,859 53 305586 2,537 100 787 26 169 69 2272044630 1,880 53 308586 2,544 100 792 26 168 69 2282045630 1,935 53 297586 2,537 100 789 26 171 69 2272046678 1,996 53 279586 2,537 100 780 26 174 69 2272047678 2,039 53 277586 2,537 100 785 26 166 69 2262048678 2,069 53 275586 2,544 100 781 26 170 69 2282049678 2,100 53 272586 2,537 100 812 26 158 69 2272050678 2,149 53 264586 2,537 100 793 26 172 69 2272051678 2,172 53 265586 2,537 100 792 26 187 69 2272052678 2,209 53 264586 2,544 100 813 26 162 69 2272053678 2,259 53 273586 2,537 100 786 26 175 69 2272054678 2,281 53 276586 2,537 100 796 26 176 69 2272055678 2,319 53 278586 2,537 100 796 26 175 69 2272056678 2,344 53 283586 2,544 100 774 26 197 69 2282057775 2,441 53 248586 2,537 100 813 26 146 69 2272058775 2,522 53 251567 2,496 100 783 26 172 69 2262059775 2,577 53 252567 2,496 100 823 26 154 69 2272060775 2,623 53 260567 2,502 100 775 26 160 69 228WindMunicipal Solid WasteNuclear Fuel Oil GeothermalScenario 1A/1B Plan - P50 Natural Gas Forecast: Cumulative Capacity and Energy by Resource TypeOcean TidalPurchase Power HydroNatural Gas CoalBlack & Veatch Confidential2/18/2010Page 7
APPENDIX F DETAILED RESULTS – SCENARIO 2A
ALASKA RIRP STUDY
Black & Veatch F-1 February 2010
APPENDIX F
DETAILED RESULTS – SCENARIO 2A
Plan 2A P50 SummaryYear AdditionsRetirementsReserve Margin (%)Renewable Generation (%)Fuel Costs ($000)Total O&M Costs ($000)CO2 Costs ($000)DSM Costs ($000)Annual Capital Fixed Charges ($000)Total Annual Costs ($000)Present Value of Annual Costs ($000)Cumulative Present Value ($000)2011Nikiski Wind; HCCPBeluga - 1; Beluga - 2; International - 1; International - 2 55.82% 11.92% $351,604 $78,521 $1,106 $651 $12,326 $444,208 $444,208 $444,2082012Fire Island International - 3 47.47% 15.18% $360,422 $86,221 $54,846 $1,491 $40,350 $543,330 507,785 951,993201344.98% 14.98% $363,525 $85,731 $60,377 $3,063 $40,350 $553,045 483,051 1,435,0442014Glacier Fork; Anchorage MSWBeluga - 3; Beluga - 6/8; Beluga - 7/8; Bernice - 2; Bernice - 3 56.46% 18.90% $349,083 $86,281 $66,100 $5,878 $88,695 $596,037 486,543 1,921,5872015Anchorage 1x1 6FA 55.23% 24.72% $354,267 $87,454 $62,615 $10,455 $132,747 $647,538 494,004 2,415,591201659.21% 24.60% $389,510 $89,445 $69,555 $12,759 $172,296 $733,565 523,022 2,938,6122017Kenai Wind Beluga - 5; NP1 60.42% 26.14% $372,476 $92,929 $74,394 $11,891 $216,010 $767,700 511,551 3,450,1632018GVEA 1X1 NPole Retrofit NP2 53.81% 26.11% $275,355 $86,095 $80,031 $12,241 $227,803 $681,525 424,419 3,874,583201947.47% 25.89% $296,482 $86,310 $87,228 $12,657 $227,803 $710,481 413,506 4,288,0892020Mount Spurr Beluga - 6; MLP 5; MLP 5/6; MLP 7/6 45.73% 33.16% $304,731 $105,371 $88,752 $13,124 $289,455 $801,433 435,927 4,724,0162021Anchorage 1x1 6FA Beluga - 7 55.49% 32.84% $312,537 $109,985 $94,579 $13,346 $358,886 $889,333 452,092 5,176,1072022Mount Spurr Healy - 1 50.51% 39.74% $297,344 $129,708 $96,528 $14,024 $407,797 $945,400 449,153 5,625,260202346.37% 39.54% $327,794 $126,766 $97,214 $4,166 $411,390 $967,329 429,506 6,054,766202445.20% 39.58% $343,341 $130,139 $109,253 $3,313 $449,770 $1,035,816 429,827 6,484,5932025Anchorage 2x1 6FA; Anchorage LM6000; Chakachamna:Chakachamna GVEA Aurora Purchase - Tier I 41.74% 42.64% $493,814 $190,671 $158,554 $4,222 $793,649 $1,640,909 636,373 7,120,9652026Nikiski 36.05% 42.27% $529,070 $179,677 $183,279 $5,342 $793,649 $1,691,017 612,902 7,733,868202735.49% 42.50% $520,677 $182,769 $197,038 $8,551 $795,997 $1,705,032 577,553 8,311,421202834.84% 42.34% $533,295 $187,338 $219,018 $13,323 $795,997 $1,748,972 553,680 8,865,101202934.21% 41.95% $539,569 $190,662 $241,299 $16,151 $795,997 $1,783,679 527,726 9,392,8272030GVEA 2x1 6FA; GVEA Wind DPP - 6; MLP 7; MLP 8; Zen1; Zen2 45.01% 43.53% $509,936 $198,465 $245,385 $17,064 $918,989 $1,889,839 522,556 9,915,383203139.60% 43.40% $523,101 $201,504 $270,945 $14,951 $915,592 $1,926,094 497,739 10,413,123203238.95% 43.61% $531,763 $205,894 $291,795 $15,081 $895,542 $1,940,075 468,554 10,881,676203338.30% 43.19% $541,607 $210,376 $316,985 $15,919 $895,542 $1,980,429 447,009 11,328,685203437.66% 42.72% $551,169 $214,842 $343,023 $16,747 $895,542 $2,021,323 426,392 11,755,077203537.01% 43.03% $555,584 $219,480 $368,689 $18,111 $895,542 $2,057,407 405,611 12,160,688203636.38% 42.85% $560,666 $224,269 $402,574 $5,493 $895,542 $2,088,545 384,813 12,545,5002037GVEA LMS100 MLP 3 40.23% 42.52% $548,121 $231,752 $422,523 $7,019 $904,831 $2,114,246 364,064 12,909,564203839.58% 42.47% $547,828 $236,660 $454,017 $6,453 $904,831 $2,149,789 345,966 13,255,530203938.94% 42.26% $570,844 $241,766 $490,794 $8,848 $904,831 $2,217,083 333,454 13,588,9842040Anchorage 2x1 6FA; GVEA 1x1 6FA; GVEA 2x1 6FA 43.74% 31.31% $955,710 $278,383 $819,820 $12,284 $1,190,010 $3,256,208 457,702 14,046,686204143.25% 31.09% $986,042 $283,245 $876,847 $18,825 $1,181,081 $3,346,041 439,560 14,486,2462042GVEA Wind NPCC 39.49% 32.33% $995,004 $281,841 $929,314 $21,552 $1,222,216 $3,449,927 423,558 14,909,804204339.01% 32.23% $1,034,873 $288,300 $1,005,832 $22,199 $1,222,216 $3,573,421 410,018 15,319,822204438.53% 32.09% $1,075,355 $401,879 $1,082,555 $23,458 $1,173,871 $3,757,118 402,893 15,722,716204538.05% 31.69% $1,109,371 $300,374 $1,161,219 $22,134 $1,129,819 $3,722,917 373,108 16,095,8242046GVEA Wind 37.57% 33.53% $1,151,293 $316,843 $1,258,017 $22,961 $1,144,476 $3,893,591 364,685 16,460,509204737.09% 33.00% $1,190,168 $323,306 $1,347,332 $24,452 $1,117,471 $4,002,728 350,381 16,810,890204836.62% 33.07% $1,239,185 $331,193 $1,461,949 $25,398 $1,105,678 $4,163,403 340,603 17,151,493204936.15% 33.23% $1,269,655 $338,080 $1,559,594 $6,909 $1,105,678 $4,279,915 327,229 17,478,722205035.67% 32.85% $1,313,929 $345,174 $1,673,485 $8,724 $996,132 $4,337,444 309,932 17,788,654205135.20% 32.51% $1,360,215 $352,585 $1,720,933 $11,174 $926,701 $4,371,608 291,938 18,080,591205234.73% 32.77% $1,411,933 $361,346 $1,775,167 $9,139 $877,791 $4,435,375 276,819 18,357,410205334.26% 32.61% $1,448,204 $368,777 $1,813,619 $14,889 $874,198 $4,519,685 263,627 18,621,037205433.79% 32.49% $1,498,727 $377,675 $1,868,803 $22,880 $835,817 $4,603,903 250,971 18,872,008205533.32% 32.40% $1,544,239 $386,271 $1,919,022 $27,949 $756,353 $4,633,834 236,077 19,108,085205632.86%32.38% $1,597,860 $395,323 $1,971,742 $30,133 $756,353 $4,751,411 226,231 19,334,3172057HEA LMS100Cooper Lake37.07% 32.13% $1,654,506 $407,185 $2,040,275 $33,288 $796,604 $4,931,857 219,461 19,553,777205835.67% 32.04% $1,721,950 $415,039 $2,114,255 $33,226 $796,604 $5,081,073 211,309 19,765,086205935.19% 31.25% $1,775,748 $423,369 $2,170,886 $31,309 $796,604 $5,197,916 202,026 19,967,1132060HEA LM600037.02% 31.66% $1,876,300 $437,564 $2,290,856 $32,092 $734,560 $5,371,371 195,110 20,162,223Present Value of Costs7,215,425 2,198,167 3,949,357 149,474 6,649,800Grand Total20,162,223Scenario 2A Plan - P50 Natural Gas ForecastBlack & Veatch Confidential2/18/2010Page 1
Plan 2A P50 SummaryYearAnchorageInteriorMatanuskaKenaiTotal Railbelt201133,725 0 0 4,347 38,073201231,564 00 5,343 36,907201331,009 00 5,402 36,412201429,719 00 4,652 34,370201522,335 00 2,653 24,988201621,242 00 2,901 24,143201722,336 00 1,634 23,970201819,206 9,3530 1,741 30,299201919,347 8,5320 1,746 29,625202015,697 8,3680 1,731 25,797202116,406 7,5380 1,513 25,457202214,499 7,0390 1,433 22,971202315,391 7,7320 1,464 24,586202415,768 7,4960 1,513 24,777202527,374 7,0390 1,342 35,755202628,989 7,6710 907 37,566202729,128 7,6950 0 36,823202829,273 7,7200 0 36,992202929,637 7,8440 0 37,481203021,656 14,2250 0 35,881203125,908 10,5320 0 36,439203225,811 10,6990 0 36,510203326,214 10,7190 0 36,934203426,659 10,6850 0 37,344203526,479 10,7960 0 37,275203626,896 10,9280 0 37,824203722,325 15,1850 0 37,510203822,251 15,4090 0 37,660203922,546 15,3240 0 37,870204035,623 24,9980 0 60,621204135,747 24,2670 0 60,014204235,457 24,1280 0 59,585204335,422 24,4380 0 59,860204435,569 24,5710 0 60,140204535,140 24,8910 0 60,031204636,415 23,8340 0 60,249204736,121 24,1670 0 60,288204836,458 24,3210 0 60,779204936,055 24,2840 0 60,339205036,134 24,3990 0 60,533205136,276 24,4870 0 60,764205236,850 24,3200 0 61,170205336,228 24,6130 0 60,841205436,437 24,6270 0 61,064205536,257 24,7970 0 61,053205636,722 24,6540 0 61,376205735,530 24,3350 1,797 61,661205835,362 24,5580 2,422 62,342205934,939 25,0590 2,440 62,438206033,668 24,8470 5,605 64,120Scenario 2A Plan - P50 Natural Gas ForecastAnnual Natural Gas Usage (mmBtu)Black & Veatch Confidential2/18/2010Page 2
Plan 2A P50 SummaryYearNikiski WindHCCP Fire IslandGlacier ForkAnchorage MSWAnchorage 1x1 6FAKenai Wind T LinesGVEA 1X1 NPole RetrofitMount Spurr TAnchorage 1x1 6FAMount SpurrAnchorage 2x16FAAnchorage LM6000Chakachamna:ChakachamnaGVEA 2x1 6FAGVEA Wind T LinesGVEA LMS100Anchorage 2x1 6FAGVEA 1x16FAGVEA 2x1 6FAGVEA WindGVEA WindHEA LMS100HEA LM6000Generating Unit Cash Flow ($000)201130,468 99,809 175,454 127,935 39,746 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 473,4132012116,563 93,305 65,608275,4762013119,477 84,604 154,017358,0982014139,655139,655201513,577 18,08331,6602016125,247 42,45033,699201,396201738,492 72,76526,866138,1232018170,818 76,085 43,273290,1772019154,889 178,613 68,804 79,301481,6072020161,957 161,519 238,340561,8162021146,457 481,537627,9942022197,360 652,793850,1532023393,458 16,120 712,1381,121,7162024130,159 73,474 141,426345,059202520262027223,295223,2952028445,161 32,772477,9332029147,263 302,325449,588203020312032203320342,2602,2602035206,133206,133203631,13831,1382037285,836 121,634 285,836 693,3062038569,844 285,539 569,844 1,425,2272039188,510 258,912 188,510 635,931204041,925 41,9252041386,759 386,75920422043204446,278 46,2782045426,910 426,9102046204720482049205020512052205320543,703 3,7032055337,773 337,773205651,024 51,0242057205838,257 38,2572059174,368 174,3682060Total11,548,152Scenario 2A Plan - P50 Natural Gas ForecastCash Flow per Generating Unit Addition Black & Veatch Confidential2/18/2010Page 3
Plan 2A P50 SummaryYearTotal Generating Unit Cash Flow ($000)Total Transmission Project Cash Flow ($000)Total Cash Flow ($000)DSM Costs ($000)Fuel Cost ($000)Fixed O&M ($000)Variable O&M ($000)CO2 Costs ($000)Energy Requirements After DSM (GWh)2011473,413 79,848 553,260 651 351,604 43,795 34,726 1,106 5,3722012275,4763,365 278,841 1,491 360,422 48,337 37,885 54,8465,4122013358,09851,272 409,370 3,063 363,525 48,328 37,403 60,3775,4242014139,655228,409 368,063 5,878 349,083 49,454 36,828 66,1005,421201531,660314,097 345,757 10,455 354,267 48,327 39,127 62,6155,1672016201,396129,804 331,201 12,759 389,510 48,775 40,670 69,5555,1472017138,1238,812 146,935 11,891 372,476 49,059 43,870 74,3945,1292018290,17797,549 387,726 12,241 275,355 47,413 38,682 80,0315,1052019481,607214,570 696,177 12,657 296,482 46,596 39,714 87,2285,0852020561,816166,433 728,249 13,124 304,731 64,626 40,745 88,7525,0682021627,99473,715 701,709 13,346 312,537 68,386 41,599 94,5795,0522022850,153195,732 1,045,885 14,024 297,344 86,668 43,040 96,5285,08120231,121,716205,995 1,327,711 4,166 327,794 82,114 44,651 97,2145,1112024345,05923,643 368,702 3,313 343,341 83,658 46,481 109,2535,140202510,784 10,784 4,222 493,814 135,630 55,041 158,5548,459202611,289 11,289 5,342 529,070 138,121 41,556 183,2798,4922027223,295223,295 8,551 520,677 140,707 42,062 197,0388,5262028477,933477,933 13,323 533,295 143,349 43,988 219,0188,5692029449,588449,588 16,151 539,569 146,097 44,566 241,2998,59420300 17,064 509,936 152,823 45,642 245,3858,62920310 14,951 523,101 155,099 46,405 270,9458,66320320 15,081 531,763 158,176 47,718 291,7958,70720330 15,919 541,607 161,218 49,158 316,9858,73220342,2602,260 16,747 551,169 164,248 50,595 343,0238,7672035206,133206,133 18,111 555,584 167,467 52,013 368,6898,802203631,13831,138 5,493 560,666 170,851 53,418 402,5748,8472037693,306693,306 7,019 548,121 177,317 54,436 422,5238,87320381,425,2271,425,227 6,453 547,828 180,675 55,985 454,0178,9082039635,931635,931 8,848 570,844 184,232 57,534 490,7948,944204041,92541,925 12,284 955,710 202,018 76,366 819,82012,2832041386,759386,759 18,825 986,042 205,701 77,544 876,84712,30120420 21,552 995,004 195,580 86,261 929,31412,33720430 22,199 1,034,873 199,431 88,869 1,005,83212,373204446,27846,278 23,458 1,075,355 310,643 91,236 1,082,55512,4272045426,910426,910 22,134 1,109,371 207,543 92,831 1,161,21912,44620460 22,961 1,151,293 211,768 105,075 1,258,01712,48220470 24,452 1,190,168 216,084 107,221 1,347,33212,51920480 25,398 1,239,185 220,612 110,581 1,461,94912,57420490 6,909 1,269,655 225,244 112,836 1,559,59412,59320500 8,724 1,313,929 229,911 115,263 1,673,48512,63020510 11,174 1,360,215 234,521 118,065 1,720,93312,66820520 9,139 1,411,933 239,458 121,888 1,775,16712,72320530 14,889 1,448,204 244,515 124,261 1,813,61912,74320543,7033,703 22,880 1,498,727 249,622 128,054 1,868,80312,7812055337,773337,773 27,949 1,544,239 255,048 131,223 1,919,02212,819205651,02451,024 30,133 1,597,860 260,323 135,000 1,971,74212,87520570 33,288 1,654,506 269,102 138,083 2,040,27512,896205838,25738,257 33,226 1,721,950 273,035 142,003 2,114,25512,9342059174,368174,368 31,309 1,775,748 278,917 144,451 2,170,88612,97320600 32,092 1,876,300 288,064 149,500 2,290,85613,030Total11,548,152 1,815,317 Total of Cash Fl14,110,777Scenario 2A Plan - P50 Natural Gas ForecastSummary of Cash Flows and Production CostsBlack & Veatch Confidential2/18/2010Page 4
Plan 2A P50 SummaryYearCapacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)20111,104 3,548 80 435 251 576 25 210 176 591 15 4920121,104 3,427 80 493 251 502 25 215 176 593 69 23120131,041 3,376 80 568 251 494 25 214 176 591 69 22620141,176 3,145 80 643 251 426 25 214 251 649 22 163 69 22720151,176 2,439 80 619 251 633 25 212 251 919 22 163 69 2272016822 2,329 80 625 251 720 25 214 251 921 22 163 69 2282017822 2,299 80 616 251 656 25 212 251 919 22 159 99 3262018821 2,381 80 562 189 618 25 213 251 919 22 166 99 3262019821 2,401 80 576 189 578 25 213 251 919 22 163 99 32520201,103 2,558 80 597 25 210 251 921 50 403 22 163 99 3272021907 2,583 80 568 25 209 251 919 50 401 22 161 99 3262022825 2,241 80 559 25 205 251 919 100 798 22 156 99 3262023743 2,450 80 372 25 206 251 919 100 799 22 158 99 32620241,100 2,442 53 382 25 207 251 921 100 812 22 159 99 32620251,101 4,261 53 353 25 212 581 2,517 100 802 22 160 99 32520261,101 4,516 53 360581 2,517 100 790 22 152 99 32620271,059 4,533 53 344581 2,517 100 816 22 161 99 32620281,059 4,562 53 349581 2,524 100 806 22 169 99 32620291,384 4,624 53 340581 2,517 100 803 22 154 99 32620301,384 4,571 53 266581 2,517 100 794 22 157 149 48920311,214 4,577 53 295581 2,517 100 794 22 161 149 48920321,150 4,589 53 291581 2,524 100 812 22 172 149 49120331,150 4,640 53 295581 2,517 100 802 22 161 149 49120341,150 4,704 53 296581 2,517 100 785 22 150 149 49020351,150 4,697 53 294581 2,517 100 818 22 162 149 49020361,2454,735 53 298581 2,524 100 813 22 162 149 49020371,247 4,812 53 258581 2,517 100 787 22 175 149 49120381,215 4,839 53 255581 2,517 100 813 22 160 149 49120392,011 4,870 53 256581 2,517 100 807 22 160 149 49120402,011 8,001 53 272581 2,524 100 805 22 163 149 49920412,011 7,943 53 278581 2,517 100 800 22 162 149 48920422,011 7,741 53 276581 2,517 100 805 22 163 199 65320431,948 7,764 53 283581 2,517 100 803 22 163 199 65520441,948 7,809 53 276581 2,524 100 804 22 152 199 65620451,948 7,778 53 277581 2,517 100 761 22 158 199 65520461,948 7,698 53 282581 2,517 100 827 22 177 249 82020471,948 7,706 53 276581 2,517 100 802 22 147 249 81720481,948 7,761 53 274581 2,524 100 804 22 163 249 82220491,948 7,724 53 259581 2,517 100 828 22 174 249 82020501,948 7,744 53 247581 2,517 100 802 22 162 249 82020511,948 7,757 53 251581 2,517 100 781 22 151 249 82020521,948 7,822 53 245581 2,524 100 814 22 163 249 82120531,948 7,765 53 250581 2,517 100 804 22 168 249 81720541,948 7,790 53 261581 2,517 100 804 22 162 249 82020551,948 7,789 53 264581 2,517 100 798 22 169 249 82020561,948 7,841 53 260581 2,524 100 812 22 162 249 82120572,046 7,748 53 280581 2,517 100 794 22 162 249 82020582,046 7,802 53 283562 2,476 100 834 22 167 249 81720592,093 7,761 53 290562 2,476 100 758 22 148 249 81720602,093 7,725 53 304562 2,482 100 806 22 163 249 821Scenario 2A Plan - P50 Natural Gas Forecast: Cumulative Capacity and Energy by Resource TypeOcean TidalFuel Oil Purchase Power Hydro Geothermal Municipal Solid Waste WindCoal NuclearNatural GasBlack & Veatch Confidential2/18/2010Page 5
APPENDIX G DETAILED RESULTS – SCENARIO 2B
ALASKA RIRP STUDY
Black & Veatch G-1 February 2010
APPENDIX G
DETAILED RESULTS – SCENARIO 2B
Plan 2B P50 SummaryYear Additions RetirementsReserve Margin (%)Renewable Generation (%)Fuel Costs ($000)Total O&M Costs ($000)CO2 Costs ($000)DSM Costs ($000)Annual Capital FixedCharges ($000)Total Annual Costs ($000)Present Value of Annual Costs ($000)Cumulative Present Value ($000)2011Nikiski Wind; HCCPBeluga - 1; Beluga - 2; International - 1International - 255.82% 11.92% $351,493 $78,517 $0 $651 $12,326 $442,987 $442,987 $442,9872012Fire IslandInternational - 347.47% 15.18% $360,816 $86,324 $54,859 $1,491 $40,350 $543,841 508,262951,249201344.98% 14.98% $373,571 $86,176 $60,950 $3,063 $40,350 $564,109 492,714 1,443,9632014Glacier Fork; Anchorage MSWBeluga - 3; Beluga - 6/8; Beluga - 7/8;Bernice - 2; Bernice - 356.46% 18.90% $355,455 $86,614 $66,555 $5,878 $88,695 $603,197 492,389 1,936,3522015Anchorage 1x1 6FA55.23% 24.72% $355,881 $87,506 $62,699 $10,455 $132,747 $649,288 495,339 2,431,691201659.21% 24.60% $391,713 $89,457 $69,675 $12,759 $172,296 $735,900 524,686 2,956,3772017Kenai Wind Beluga - 5; NP160.42% 26.14% $357,236 $92,343 $73,636 $11,891 $216,010 $751,117 500,501 3,456,8782018GVEA 1X1 NPole RetrofitNP253.81% 26.11% $275,319 $86,055 $80,008 $12,241 $227,803 $681,426 424,358 3,881,236201947.47% 25.89% $296,301 $86,307 $87,426 $12,657 $227,803 $710,494 413,514 4,294,7502020Mount SpurrBeluga - 6; MLP 5; MLP 5/6; MLP 7/645.73% 33.15% $313,065 $104,598 $88,585 $13,124 $289,455 $808,827 439,949 4,734,6992021Anchorage 1x1 6FABeluga - 755.49% 32.84% $319,829 $107,286 $95,077 $13,346 $358,886 $894,423 454,679 5,189,3782022Mount SpurrHealy - 150.51% 39.73% $303,446 $126,760 $96,696 $14,024 $407,797 $948,722 450,731 5,640,109202346.37% 39.57% $338,009 $123,561 $101,020 $4,166 $411,390 $978,146 434,308 6,074,418202445.20% 39.43% $354,550 $125,350 $111,759 $3,313 $449,770 $1,044,742 433,531 6,507,9492025Chakachamna:Chakachamna; GVEAWind; Low Watana (Non-Expandable) GVEA Aurora Purchase - Tier I59.97% 65.83% $327,284 $177,358 $109,666 $4,222 $1,387,377 $2,005,906 777,925 7,285,8742026Nikiski54.19% 65.70% $355,930 $168,282 $129,694 $5,342 $1,387,377 $2,046,625 741,791 8,027,664202753.56% 65.52% $354,583 $171,861 $141,138 $8,551 $1,389,726 $2,065,860 699,778 8,727,443202852.82% 65.41% $362,315 $175,663 $156,239 $13,323 $1,389,726 $2,097,266 663,941 9,391,383202952.11% 65.12% $370,599 $179,717 $173,790 $16,151 $1,389,726 $2,129,983 630,185 10,021,5682030GVEA Wind DPP - 6; MLP 7; MLP 8; Zen1; Zen238.93% 66.50% $324,824 $188,512 $170,425 $17,064 $1,426,241 $2,127,066 588,151 10,609,720203133.55% 66.21% $287,389 $185,763 $167,924 $14,951 $1,422,844 $2,078,872 537,220 11,146,940203232.93% 66.42% $291,077 $190,378 $181,400 $15,081 $1,402,794 $2,080,731 502,524 11,649,463203332.30% 66.03% $294,120 $194,462 $195,275 $15,919 $1,402,794 $2,102,569 474,578 12,124,041203431.69% 65.66% $300,588 $198,861 $213,080 $16,747 $1,402,794 $2,132,070 449,754 12,573,794203531.08% 65.94% $303,932 $203,534 $228,670 $18,111 $1,402,794 $2,157,041 425,253 12,999,048203630.47% 65.48% $304,372 $207,945 $248,912 $5,493 $1,402,794 $2,169,516 399,732 13,398,7792037Anchorage 2x1 6FA; Kenai Wind MLP 349.65% 64.70% $337,305 $221,770 $284,317 $7,019 $1,512,696 $2,363,107 406,916 13,805,696203848.95% 64.92% $335,376 $226,742 $306,870 $6,453 $1,512,696 $2,388,138 384,324 14,190,020203948.26% 64.44% $355,211 $231,941 $335,719 $8,848 $1,512,696 $2,444,416 367,646 14,557,6652040Anchorage 2x1 6FA; Kenai Wind; GVEA 2x1 6FA42.24% 49.31% $726,114 $261,828 $658,141 $12,284 $1,757,343 $3,415,710 480,122 15,037,787204141.75% 49.68% $749,303 $266,953 $705,228 $18,825 $1,748,414 $3,488,723 458,303 15,496,0902042GVEA Wind NPCC38.00% 50.31% $764,582 $266,145 $750,700 $21,552 $1,789,549 $3,592,529 441,066 15,937,156204337.52% 50.68% $785,633 $272,478 $804,064 $22,199 $1,789,549 $3,673,924 421,550 16,358,706204437.04% 50.66% $815,768 $279,122 $870,100 $23,458 $1,741,204 $3,729,652 399,948 16,758,654204536.57% 50.24% $852,178 $285,535 $937,781 $22,134 $1,663,223 $3,760,851 376,910 17,135,5642046GVEA LM600038.46% 50.01% $890,057 $295,214 $1,020,949 $22,961 $1,639,640 $3,868,823 362,365 17,497,930204737.99% 50.14% $918,798 $302,026 $1,096,440 $24,452 $1,612,635 $3,954,351 346,146 17,844,075204837.51% 49.97% $957,221 $309,807 $1,185,769 $25,398 $1,600,842 $4,079,038 333,701 18,177,777204937.04% 50.05% $989,273 $316,912 $1,280,071 $6,909 $1,600,842 $4,194,007 320,661 18,498,437205036.55% 49.77% $1,024,435 $324,240 $1,376,949 $8,724 $1,502,675 $4,237,023 302,756 18,801,194205136.08% 49.82% $1,061,115 $331,990 $1,416,126 $11,174 $1,433,244 $4,253,649 284,060 19,085,254205235.61% 49.47% $1,106,193 $339,840 $1,464,813 $9,139 $1,384,333 $4,304,318 268,639 19,353,893205335.14% 49.47% $1,134,383 $347,466 $1,496,925 $14,889 $1,380,740 $4,374,402 255,153 19,609,046205434.66% 49.38% $1,177,971 $356,121 $1,545,993 $22,880 $1,342,360 $4,445,327 242,327 19,851,373205534.19% 49.25% $1,223,021 $364,747 $1,593,720 $27,949 $1,329,430 $4,538,867 231,239 20,082,612205633.72% 49.23% $1,262,068 $373,263 $1,640,623 $30,133 $1,329,430 $4,635,516 220,713 20,303,3252057Anchorage LMS100Cooper Lake37.93% 49.04% $1,322,441 $385,797 $1,701,489 $33,288 $1,343,638 $4,786,652 212,999 20,516,324205836.53% 48.61% $1,372,591 $445,852 $1,765,190 $33,226 $1,343,638 $4,960,497 206,295 20,722,619205936.04% 48.57% $1,430,714 $518,902 $1,826,864 $31,309 $1,343,638 $5,151,426 200,219 20,922,838206035.57% 48.39% $1,480,273 $412,965 $1,879,232 $32,092 $1,315,593 $5,120,155 185,985 21,108,823Present Value of Costs 6,024,495 2,107,805 3,188,181 149,474 9,638,868 Grand Total21,108,823Scenario 2B Plan - P50 Natural Gas ForecastBlack & Veatch Confidential2/18/2010Page 1
Plan 2B P50 SummaryYear Anchorage Interior Matanuska Kenai Total Railbelt201133,729 0 0 4,344 38,073201231,544 0 0 5,351 36,895201330,782 0 0 5,745 36,527201429,533 0 0 4,978 34,510201522,300 0 0 2,660 24,960201621,206 0 0 2,931 24,137201721,504 0 0 2,718 24,222201818,121 9,333 0 2,846 30,300201918,265 8,505 0 2,876 29,646202015,363 7,447 0 3,213 26,023202118,274 5,312 0 2,521 26,108202216,131 5,075 0 2,341 23,547202317,306 5,444 0 2,485 25,235202418,090 4,863 0 2,709 25,663202515,198 6,048 0 2,135 23,381202616,286 6,683 0 1,623 24,592202717,378 6,898 0 0 24,276202817,654 6,802 0 0 24,456202917,734 7,075 0 0 24,809203013,735 6,592 0 0 20,327203113,861 5,722 0 0 19,583203214,037 5,482 0 0 19,518203313,932 5,653 0 0 19,585203414,126 5,736 0 0 19,862203514,240 5,650 0 0 19,890203614,623 5,370 0 0 19,993203717,352 5,224 0 0 22,576203817,154 5,353 0 0 22,507203917,527 5,499 0 0 23,026204031,944 14,295 0 0 46,239204131,757 14,198 0 0 45,956204232,415 12,885 0 0 45,300204332,242 12,717 0 0 44,960204432,303 12,810 0 0 45,113204532,857 12,772 0 0 45,629204632,801 13,321 0 0 46,121204732,648 13,422 0 0 46,070204833,107 13,360 0 0 46,467204932,822 13,701 0 0 46,523205032,986 13,694 0 0 46,679205133,318 13,588 0 0 46,906205233,518 13,900 0 0 47,418205333,414 13,736 0 0 47,150205433,741 13,762 0 0 47,503205533,901 13,984 0 0 47,885205634,108 13,890 0 0 47,998205734,725 14,124 0 0 48,849205835,127 14,122 0 0 49,249205935,493 14,393 0 0 49,885206035,785 14,3920 0 50,177Scenario 2B Plan - P50 Natural Gas ForecastAnnual Natural Gas Usage (mmBtu)Black & Veatch Confidential2/18/2010Page 2
Plan 2B P50 SummaryYear Nikiski Wind HCCP Fire Island Glacier ForkAnchorage MSWAnchorage 1x1 6FAKenai Wind T LinesGVEA 1X1 NPole Retrofit Mount Spurr TAnchorage 1x1 6FA Mount SpurrChakachamna:ChakachamnaGVEA Wind T LinesLow Watana (Non-Expandable) GVEA WindAnchorage 2x1 6FAKenai WindAnchorage 2x1 6FA Kenai WindGVEA 2x1 6FAGVEA WindGVEA LM6000Anchorage LMS100Generating Unit Cash Flow ($000)201130,468 99,809 175,454 127,935 39,746 0 0 0 0 0 0 48,624 0 0 0 0 0 522,0362012116,563 93,305 65,60832,371307,8472013119,477 84,604 154,01730,231388,3292014139,65541,025180,680201513,577 18,08343,10274,7612016125,247 42,450 33,699 503,963705,359201738,492 72,765 26,866 529,476667,5992018170,818 76,085 43,273 711,8781,002,0552019154,889 178,613 68,804 79,301 840,2421,321,8492020161,957 161,519 238,340 882,7791,444,5962021146,457 481,537 721,7811,349,7752022652,793 758,3211,411,1142023712,138 28,966 796,7111,537,8152024141,426 267,211 39,033447,670202520262027202831,17431,1742029287,577287,57720302031203220332034265,427265,4272035529,157 22,233551,3902036175,050 205,103380,1532037285,836 285,836 571,6722038569,844 23,943 569,844 1,163,6312039188,510 220,874 188,510 597,893204041,925 41,9252041386,759 386,75920422043204427,076 27,0762045123,405123,4052046204720482049205020512052205320543,7033,7032055337,773 337,773205651,024 51,0242057205820592060Total16,182,068Scenario 2B Plan - P50 Natural Gas ForecastCash Flow per Generating Unit Addition Black & Veatch Confidential2/18/2010Page 3
Plan 2B P50 SummaryYearTotal Generating Unit Cash Flow ($000)Total Transmission Project Cash Flow ($000) Total Cash Flow ($000)DSM Costs ($000)Fuel Cost ($000)Fixed O&M ($000)Variable O&M ($000)CO2 Costs ($000)Energy Requirements After DSM (GWh)2011522,036 79,848 601,884 651 351,493 43,795 34,722 5,3722012307,847 3,365 311,212 1,491 360,816 48,337 37,987 54,859 5,4122013388,329 51,272 439,601 3,063 373,571 48,328 37,848 60,950 5,4242014180,680 228,409 409,088 5,878 355,455 49,454 37,160 66,555 5,421201574,761 314,097 388,859 10,455 355,881 48,327 39,179 62,699 5,1672016705,359 129,804 835,164 12,759 391,713 48,775 40,682 69,675 5,1472017667,599 8,812 676,411 11,891 357,236 49,059 43,284 73,636 5,12920181,002,055 97,549 1,099,604 12,241 275,319 47,413 38,642 80,008 5,10520191,321,849 214,570 1,536,419 12,657 296,301 46,596 39,711 87,426 5,08520201,444,596 166,433 1,611,028 13,124 313,065 64,626 39,972 88,585 5,06820211,349,775 73,715 1,423,490 13,346 319,829 68,386 38,900 95,077 5,05220221,411,114 198,726 1,609,841 14,024 303,446 86,668 40,092 96,696 5,08120231,537,815 234,141 1,771,956 4,166 338,009 82,114 41,446 101,020 5,1112024447,670 52,388 500,059 3,313 354,550 83,658 41,692 111,759 5,140202510,784 10,784 4,222 327,284 127,467 49,890 109,666 8,459202611,289 11,289 5,342 355,930 129,959 38,323 129,694 8,49220270 0 8,551 354,583 132,545 39,316 141,138 8,526202831,174 0 31,174 13,323 362,315 135,187 40,476 156,239 8,5692029287,577 0 287,577 16,151 370,599 137,934 41,783 173,790 8,59420300 0 17,064 324,824 139,466 49,046 170,425 8,62920310 0 14,951 287,389 141,743 44,020 167,924 8,66320320 0 15,081 291,077 144,820 45,559 181,400 8,70720330 0 15,919 294,120 147,862 46,600 195,275 8,7322034265,427 0 265,427 16,747 300,588 150,891 47,970 213,080 8,7672035551,390 0 551,390 18,111 303,932 154,111 49,423 228,670 8,8022036380,153 0 380,153 5,493 304,372 157,495 50,450 248,912 8,8472037571,672 0 571,672 7,019 337,305 165,776 55,994 284,317 8,87320381,163,631 0 1,163,631 6,453 335,376 169,134 57,608 306,870 8,9082039597,893 0 597,893 8,848 355,211 172,691 59,250 335,719 8,944204041,925 0 41,925 12,284 726,114 177,577 84,251 658,141 12,2832041386,759 0 386,759 18,825 749,303 181,035 85,917 705,228 12,30120420 0 21,552 764,582 170,684 95,461 750,700 12,33720430 0 22,199 785,633 174,300 98,178 804,064 12,373204427,076 0 27,076 23,458 815,768 178,239 100,883 870,100 12,4272045123,405 0 123,405 22,134 852,178 181,923 103,612 937,781 12,44620460 0 22,961 890,057 188,926 106,288 1,020,949 12,48220470 0 24,452 918,798 192,983 109,044 1,096,440 12,51920480 0 25,398 957,221 197,244 112,564 1,185,769 12,574204900 6,909 989,273 201,602 115,310 1,280,07112,593205000 8,724 1,024,435 205,989 118,251 1,376,94912,630205100 11,174 1,061,115 210,312 121,678 1,416,12612,668205200 9,139 1,106,193 214,955 124,885 1,464,81312,723205300 14,889 1,134,383 219,711 127,755 1,496,92512,74320543,70303,703 22,880 1,177,971 224,508 131,614 1,545,99312,7812055337,7730337,773 27,949 1,223,021 229,617 135,130 1,593,72012,819205651,024051,024 30,133 1,262,068 234,567 138,695 1,640,62312,875205700 33,288 1,322,441 243,013 142,783 1,701,48912,896205800 33,226 1,372,591 300,121 145,731 1,765,19012,934205900 31,309 1,430,714 368,398 150,504 1,826,86412,973206000 32,092 1,480,273 257,872 155,093 1,879,23213,030Total16,182,068 1,875,203 Total of Cash Flows & DS18,804,578Scenario 2B Plan - P50 Natural Gas ForecastSummary of Cash Flows and Production CostsBlack & Veatch Confidential2/18/2010Page 5
Plan 2B P50 SummaryYearCapacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)Capacity (MW)Energy (GWh)20111,104 3,547 80 435 251 576 25 210 176 591 15 4920121,104 3,424 80 494 251 505 25 215 176 593 69 23120131,041 3,360 80 567 251 512 25 214 176 591 69 22620141,176 3,140 80 643 251 434 25 214 251 649 22 163 69 22720151,176 2,434 80 620 251 638 25 212 251 919 22 163 69 2272016822 2,323 80 625 251 726 25 214 251 921 22 163 69 2282017822 2,355 80 615 251 602 25 212 251 919 22 159 99 3262018821 2,383 80 562 189 618 25 213 251 919 22 166 99 3262019821 2,399 80 581 189 576 25 213 251 919 22 163 99 32520201,103 2,594 80 574 25 190 251 921 50 403 22 162 99 3272021907 2,611 80 552 25 178 251 919 50 401 22 161 99 3262022825 2,274 80 542 25 175 251 919 100 797 22 157 99 3262023743 2,456 80 398 25 167 251 919 100 800 22 159 99 3262024743 2,505 53 381 25 155 251 921 100 811 22 151 99 3262025743 2,303 53 322 25 188 1,181 4,435 100 790 22 158 149 4892026743 2,485 53 3521,181 4,450 100 788 22 155 149 4912027701 2,519 53 3481,181 4,448 100 798 22 153 149 4912028701 2,546 53 3491,181 4,466 100 796 22 155 149 4912029701 2,583 53 3441,181 4,451 100 802 22 154 149 4902030701 2,416 53 3551,181 4,453 100 795 22 146 199 6532031531 2,402 53 3541,181 4,478 100 772 22 139 199 6532032467 2,401 53 3601,181 4,484 100 802 22 148 199 6562033467 2,408 53 3591,181 4,480 100 792 22 144 199 6552034467 2,446 53 3671,181 4,476 100 785 22 144 199 6552035467 2,450 53 3611,181 4,488 100 819 22 147 199 65520367772,455 53 3701,181 4,487 100 801 22 153 199 6542037777 2,687 53 3401,181 4,497 100 687 22 103 229 7542038745 2,689 53 3441,181 4,479 100 737 22 114 229 75420391,380 2,753 53 3461,181 4,482 100 715 22 110 229 75420401,380 5,850 53 3631,181 4,495 100 768 22 155 259 86720411,380 5,805 53 3631,181 4,496 100 834 22 161 259 85020421,380 5,732 53 3751,181 4,510 100 771 22 144 309 1,01420431,317 5,687 53 3771,181 4,513 100 816 22 158 309 1,01820441,317 5,719 53 3791,181 4,527 100 809 22 174 309 1,01920451,317 5,785 53 3761,181 4,517 100 807 22 144 309 1,01720461,364 5,822 53 3741,181 4,518 100 768 22 170 309 1,01720471,364 5,813 53 3751,181 4,531 100 801 22 164 309 1,01420481,364 5,874 53 3771,181 4,547 100 802 22 146 309 1,01920491,364 5,868 53 3741,181 4,535 100 809 22 172 309 1,01820501,364 5,890 53 3751,181 4,537 100 801 22 160 309 1,01820511,364 5,916 53 3761,181 4,541 100 827 22 157 309 1,01720521,364 5,984 53 3751,181 4,565 100 786 22 154 309 1,01920531,364 5,962 53 3771,181 4,556 100 801 22 161 309 1,01420541,364 6,012 53 3801,181 4,559 100 802 22 161 309 1,01820551,364 6,045 53 3761,181 4,561 100 801 22 161 309 1,01820561,364 6,069 53 3781,181 4,577 100 794 22 176 309 1,01920571,462 6,087 53 3791,181 4,569 100 818 22 146 309 1,01720581,462 6,145 53 3811,162 4,544 100 779 22 176 309 1,01420591,462 6,231 53 3821,162 4,547 100 803 22 161 309 1,01420601,462 6,267 53 3841,162 4,558 100 805 22 147 309 1,019Scenario 2B Plan - P50 Natural Gas Forecast: Cumulative Capacity and Energy by Resource TypeOcean TidalFuel Oil Purchase Power Hydro Geothermal Municipal Solid Waste WindCoal NuclearNatural GasBlack & Veatch Confidential2/18/2010Page 6