200304302003 IRP Appendices.pdf

2003 IRP
Technical
ppendices

Table of Appendices

Appendix A. Resource & Contract Details............................................................................A-1
Utility-Owned Resources .......................................................................................................A-1
Power Purchase and Sale Contracts .......................................................................................A-3
Appendix B. Retail Load Forecast..........................................................................................B-1
Economic Growth...................................................................................................................B-1
Electric Retail Sales................................................................................................................B-4
Energy Load and Peak Load Forecasts ..................................................................................B-6
Enhancements to Forecasting Process....................................................................................B-6
Appendix C. Modeling Details ................................................................................................C-1
Selection of the AURORA Model..........................................................................................C-1
Cost of Capital for New Resources ........................................................................................C-2
Portfolio Optimization Using Linear Programming (LP) Module.........................................C-2
Capacity Expansion................................................................................................................C-5
Modeling Process Diagram ....................................................................................................C-6
Appendix D. Risk Details.........................................................................................................D-1
Resource Risk Profiles ...........................................................................................................D-1
Resource Characteristics ........................................................................................................D-2
Load Correlations...................................................................................................................D-3
Market Uncertainty.................................................................................................................D-4
Industry Restructuring............................................................................................................D-5
Appendix E. Detailed Results..................................................................................................E-1
Details of Preferred Resource Strategy.................................................................................. E-1
Details of Strategy Results ..................................................................................................... E-2
Details of Scenario Results..................................................................................................... E-7
Appendix F. Load and Resource Tables ................................................................................ F-1
Appendix G. TAC Meeting Agendas......................................................................................G-1
Appendix H. Wind Studies......................................................................................................H-1
Wind Energy...........................................................................................................................H-1
Appendix I. Capacity Expansion Process Details...................................................................I-1
Appendix J. Results of Capacity Expansion...........................................................................J-1
Appendix K. Spokane River Relicensing ...............................................................................K-1
Appendix L. Transmission Planning......................................................................................L-1
Relationship to Resource Planning......................................................................................... L-1
Current Issues......................................................................................................................... L-1
Expansion Possibilities & System Reconfiguration............................................................... L-2
Reliability............................................................................................................................... L-2
Appendix M. Distributed Generation....................................................................................M-1
Appendix N. Historic Data ......................................................................................................N-1
Hydroelectric Plants ...............................................................................................................N-1
Coal-Fired Plants....................................................................................................................N-4
Other Resources .....................................................................................................................N-6
PURPA Hydroelectric Plants .................................................................................................N-7
PURPA Thermal Plants........................................................................................................N-12
Appendix O. Avoided Cost Details .........................................................................................O-1
Appendix P. NWPPC Assumptions........................................................................................ P-1
Natural Gas Simple-Cycle Gas Turbine Power Plants........................................................... P-1
Coal-Fired Power Plants......................................................................................................... P-5
Natural Gas Combined-Cycle Gas Turbine Power Plants...................................................... P-9
Wind Power Plants............................................................................................................... P-18
Appendix Q. DSM Modeling Details......................................................................................Q-1

Appendix A Page A-1 Utility Resources & Contracts
Appendix

Resource & Contract Details

Utility-Owned Resources

The Company owns and operates hydroelectric projects on both the Spokane and Clark Fork
Rivers. It owns a portion of two coal-fired units located in Montana and operates three natural
gas-fired projects within its service territory. The Company has a 50 percent share in a new gas-
fired project located in Oregon. Finally, the Company owns and operates a large wood waste
generating plant near Kettle Falls, Washington. These resources are described in further detail
below.

Spokane River

The Company owns and operates six hydroelectric dams on the Spokane River. FERC licenses
for the projects expire on July 31, 2007 (except for Little Falls, which is licensed by the state of
Washington). A short description of each Spokane River project is provided below.

• Monroe Street

Monroe Street was the Company’s first generating plant, built on the Spokane River in
Spokane in 1890. The plant was rebuilt in 1992 and presently has a maximum capacity
of 15,000 kW and a nameplate of 14,800 kW for its single unit.

• Post Falls

Post Falls, completed in 1906 in Post Falls, Idaho; was the Company’s second
hydroelectric plant. The original plant consisted of five units with a sixth added on
December 16, 1980. The plant presently has a maximum capacity of 18,000 kW and a
nameplate rating of 14,750 kW.

• Nine Mile

Nine Mile, located near Nine Mile Falls, Washington; was built in 1908 by a private
developer. The Company acquired the project in 1925. The four units at the facility have
a combined maximum capacity of 24,500 kW and nameplate rating of 26,400 kW.

• Little Falls

Little Falls was completed in 1910. Located on the Spokane River near Ford,
Washington; the project has four units that total to a maximum capacity of 36,000 kW
and a nameplate rating of 32,000 kW.

Appendix A Page A-2 Utility Resources & Contracts
• Long Lake

Long Lake, located just above Little Falls, was built in 1915. New runners were installed
in 1999, increasing the total maximum capacity of its four units to 88,000 kW and a
nameplate rating of 70,000 kW.

• Upper Falls

Upper Falls is located in Spokane, and was completed in 1922. Its single unit has a
maximum capacity of 10,200 kW and a nameplate rating of 10,000 kW.

Clark Fork River

The Clark Fork River Project consists of two large hydroelectric projects located in Clark Fork,
Idaho, and Noxon, Montana. The two plants operate under a recently renewed FERC license that
expires on March 1, 2046.

• Cabinet Gorge

Cabinet Gorge began generating electricity for the Company in 1952. Two additional
units were added in 1953, bringing the total to four. Two of the units have since been
upgraded, increasing the maximum capacity of the plant to 246,000 kW and the
nameplate rating to 245,100 kW.

• Noxon Rapids

Noxon Rapids consists of four hydro units installed between September of 1959 and
April of 1960. A fifth unit was installed in December of 1977. The plant presently has a
maximum capacity of 527,000 kW and a nameplate rating of 466,200 kW.

Colstrip

Colstrip, located near Colstrip, Montana consists of four coal-fired steam plants. A consortium
of utilities owns the project, which is operated by PPL Global. The Company owns fifteen-
percent of Units 3 and 4. Unit 3 was completed in January 1984 and Unit 4 in April 1986. The
Company’s share of each Colstrip unit has a maximum capacity of 111,000 kW with a nameplate
rating of 116,700 kW.

Rathdrum

Rathdrum is a two-unit simple-cycle gas-fired plant located near Rathdrum, Idaho; built in 1995.
The plant has a maximum capacity of 176,000 kW and a nameplate rating of 166,500 kW.

Appendix A Page A-3 Utility Resources & Contracts
Northeast

Constructed in late 1978, Northeast is a two-unit aero-derivative simple-cycle plant located in
Spokane. The plant has bi-fuel capability and may burn either natural gas or fuel oil. The two
generators have a combined maximum capacity of 66,800 kW and a nameplate rating of 61,800
kW.

Boulder Park

Boulder Park, located in Spokane Valley, became operational on August 1, 2002. The site has
six internal combustion engines fired by natural gas. The maximum capacity and nameplate
rating are 24,600 kW.

Coyote Springs 2

Coyote Springs 2 is a natural gas-fired combined-cycle combustion turbine located near
Boardman, Oregon. The Company’s 50 percent share equals a maximum capacity of 143,500
kW. The plant is expected to be operational in 2003.

Kettle Falls

The Kettle Falls project began operation in December 1983. The steam plant is fueled by hog
fuel. It has a maximum capacity of 50,000 kW and a nameplate rating of 46,000 kW. It is
located near Kettle Falls, Washington.

Kettle Falls CT

The Kettle Falls CT is a natural gas-fired combustion turbine that entered commercial service on
May 31, 2002. It has a maximum capacity rating of 6,870 kW. Exhaust heat from the plant is
routed through a heat recovery boiler. The steam output is then used to increase the efficiency of
Kettle Falls.

Power Purchase and Sale Contracts

The Company is currently involved in several medium- to long-term power supply purchase and
sale arrangements. This section provides a brief description of the various contracts in effect
during the IRP timeframe. For more detailed contract information, provided on a monthly basis
over the IRP timeframe, refer to Appendix F.

Appendix A Page A-4 Utility Resources & Contracts
Bonneville Power Administration – Residential Exchange

The Company entered into a settlement agreement of the Residential Exchange Program that
became effective on October 1, 2001. Over the first five-year period of the ten-year settlement
the Company is receiving financial benefits intended to be the equivalent of purchasing 90 aMW
at Bonneville’s lowest cost-based rates. For the subsequent five-year period (beginning October
1, 2006) the Company’s benefit level increases to 149 aMW. At Bonneville’s option, the 149
aMW may be provided in whole or in part as financial benefits or as a physical power sale.

Bonneville Power Administration – WNP-3 Settlement

On September 17, 1985 the Company signed settlement agreements with BPA and Energy
Northwest (formerly the Washington Public Power Supply System), ending its construction
delay claims against both parties. The settlement provides for an exchange of energy, an
agreement to reimburse the Company for certain WNP No. 3 preservation costs, and an
irrevocable offer of WNP No. 3 capability for acquisition under the Regional Power Act.

The energy exchange portion of the settlement contains two basic provisions. The first provides
the Company with approximately 42 aMW from BPA through 2019, subject to a contract
minimum of 5.8 million MWh. The Company is obligated to pay BPA operating and
maintenance costs associated with the energy exchange, determined by a formula in an amount
not less than $16 per MWh or more than $29 per MWh, expressed in 1987 dollars.

The second provision of the exchange provides BPA approximately 36 aMW of return energy at
a cost equal to the actual operating cost of the Company's highest-cost resource. A further
discussion of this obligation, and how the Company plans to account for it, is covered under
Planning Reserves below.

Mid-Columbia Contracts

During the 1950s and 1960s, various public utility districts (PUDs) in Central Washington began
developing hydroelectric sites on the Columbia River. Each of these plants was very large when
compared to the loads then served by the PUDs. To assist in financing these large plants, and to
ensure a market for the surplus power, long-term contracts were signed with other public,
municipal, and investor-owned utilities in the Northwest.

The Company entered into long-term contracts for the output from four of these projects “at
cost.” The contracts provide not only for electrical energy, but also for capacity and reserve
capabilities. The contracts today provide approximately 190 MW of capacity and 100 aMW of
average annual energy. Over the next twenty years, the Wells and Rocky Reach the contracts
will expire. While the Company may be able to extend these contracts, it has no assurance today
that extensions will be offered. The 2003 IRP therefore does not include energy or capacity
beyond their expirations.

Appendix A Page A-5 Utility Resources & Contracts
The Company was successful in renewing its contract with Grant PUD for power from the Priest
Rapids project. The new contract term will be equal to the license term issued by FERC and will
cover both the Priest Rapids and Wanapum dams. The license term is expected to be between 30
and 50 years. As part of the all-party settlement over Priest Rapids, the Company acquired an
additional quantity of displacement power. Displacement power, available through September
30, 2011, is project output available due to displacement resources being used to serve Grant
PUD's load,

A description of the Mid-Columbia contracts is presented in the following table.

Table A.1
Mid-Columbia Contract Quantities Summary

2004 2009 2014 2019 2023
Project Expires MW aMW MW aMW MW aMW MW aMW MW aMW
Rocky Reach 10/31/11 37.7 20.5 37.7 20.5 0.0 0.0 0.0 0.0 0.0 0.0
Wells 08/31/18 28.6 9.9 28.6 9.9 28.6 9.9 0.0 0.0 0.0 0.0
Priest Rapids1 N/A 129.3 71.0 84.9 46.6 35.0 19.2 24.6 13.5 15.7 8.6
Total 195.6 101.5 151.2 74.0 63.6 29.1 24.6 13.5 15.7 8.6

PacifiCorp Exchange

The Company and PacifiCorp entered into a fifteen-year, 50 MW exchange contract that expires
on March 31, 2004. The delivery obligation of the contract will be completed in 2003, and the
Company has rights for 17,200 MWh of energy to be delivered prior to contract expiration.

Medium-Term Market Purchases

The Company has purchased 100 MW of flat (7x24) power for the period 2004 through 2010.
These purchases were completed during 2001 and 2002.

Nichols Pumping Station

The Company provides energy at Colstrip to operate its share of the Nichols Pumping Station,
which supplies water for the Colstrip plant. The Company’s share of the Nichols Pumping
Station load is approximately one aMW.

Portland General Electric

The Company provides PGE 150 MW of firm capacity under a contract expiring December 31,
2016. PGE may schedule deliveries up to its capacity limit during any ten hours of each
weekday. Within 168 hours PGE returns all energy delivered under the contract.

1 This includes the existing contracts for Priest Rapids and Wanapum, which expire in 2005 and 2009, respectively.
Thereafter, the contracts are combined as the Priest Rapids Project (PRP).

Appendix B Page B-1 Retail Load Forecast
Appendix

Retail Load Forecast

Economic Growth

A significant regional trend over the past 20 years has been the shift from an economy largely
based on natural resource-based manufacturing to one based on light manufacturing and services.
The decline in manufacturing employment has been driven by, among other factors, the
depletion of mining reserves and timber harvests. These factors have led to the closure of
several mines and sawmills throughout the region, and have had a significant impact on the
forecast of retail loads.

The Company purchases employment and population forecasts from Global Insight, Inc.
(formerly Data Resources, Inc.) for the following three counties, which comprise over 80 percent
of the service territory:

• Spokane County, Washington
• Kootenai County, Idaho
• Bonner County, Idaho

These forecasts are the basis for the Company’s electric customer forecasts. The national
forecast, from which these regional forecasts are based, was prepared in March 2002. The
county-level estimates were completed in May 2002. With regard to growth in the Company’s
primary counties, the following characterizations can be made:

• Spokane County is expected to exhibit moderate, steady growth for the next twenty years.
• Kootenai County, which is the third-fasted growing county in the U.S., is expected to
continue growing rapidly going forward.
• Bonner County is expected to have modest growth, although the other counties dwarf it
in size.

The following chart depicts historic and forecast growth patterns for employment in the above
listed counties.

Appendix B Page B-2 Retail Load Forecast
Chart B.1
County Employment Growth Forecast (thousands)

Population growth is the key component of forecasting customer growth. Though there is not a
perfect correlation, population provides the fundamental demand for housing. Over the last
several years, the region has seen considerable absorption of a housing surplus that was
generated after the population boom of the early 1990’s. Favorable low interest rates during
2002 sparked a 26.5 percent annual increase in residential permits in Spokane and Kootenai
Counties, with many of those homes being connected to the Company's system. The following
chart depicts historic and forecast population growth patterns in the above listed counties.
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Appendix B Page B-3 Retail Load Forecast
Chart B.2
County Population Growth Forecast (thousands)

Housing is also the fundamental driver of commercial customer expansion, as more retail stores,
schools, and other “population-serving” business are attracted to these new markets. Over the
twenty-year horizon, customer growth is estimated to average 1.8 percent per year, slightly
higher than the 1.5 percent experienced over the past five years. The following chart shows the
Company’s customer forecast.

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Appendix B Page B-4 Retail Load Forecast
Chart B.3
Customer Forecast (thousands)

Electric Retail Sales

The energy crisis of 2001 included the implementation of widespread conservation efforts by our
customers. In 2002, higher retail electric prices reinforced customer conservation efforts
modestly. Due to the economic recession during 2001 and 2002, several large industrial
facilities served by the Company were permanently closed, including a major employer in the
aluminum industry. The forecast includes what the Company believes to be a conservative
assumption—these closures will be permanent. If these facilities are purchased by new operators
or restarted by existing owners, the forecast will need to be adjusted.

The twenty-year forecast assumes no additional plant closures, relative stable future retail
electric prices that increase slightly below the prevailing rate of inflation, and a modestly healthy
economy. Conservation acquisitions are expected to continue throughout the forecast horizon
and energy efficient equipment will be installed in new construction and replace retired
equipment in residences and businesses. Refer to the following chart for a depiction of the retail
electric sales forecast through 2023, as well as actual sales for 1997 to 2002.

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Average Compound Growth Rate
1997-2002 = 1.5%
2002-2022 = 1.8%

Appendix B Page B-5 Retail Load Forecast
Chart B.4
Annual Retail Electric Sales
1997-2023 (in GWh)

NOTE: 1997-2002 are based on actual retail sales (not weather adjusted).

DSM in the Forecast

The system forecast used in the IRP process is the Company’s expectation of the aggregate
demand at the customer meter. Since DSM resource acquisition impacts the metered demand of
our customers, this resource is implicitly incorporated within the forecast.

The Company can very accurately identify and separate the impact of “programmic” DSM
within the forecast. Programmic DSM would include efficiency measures that the utility is
directly involved in, usually those involving cash incentives grants to the customer. The
Company can then disaggregate programmic DSM from the remainder of the forecast and
represent that impact as a separate line item within the IRP.

The Company’s DSM programs do influence usage beyond that which can be immediately
identified through customer program participation. This includes our participation in regional
market transformation efforts, local technology transformations, research and development
activities, and general market impacts. These influences are difficult to identify and will
consequently not be disaggregated from the overall forecast. Thus to some extent there will
continue to be some DSM within the forecast.

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Residential-WA Commercial-WA Industrial-WA
Street Lights-WA Residential-ID Commercial-ID
Industrial-ID Street Lights-ID
Average Compound Growth Rate
1997-2002 = -0.6%
2002-2022 = 3.2%

Appendix B Page B-6 Retail Load Forecast
Energy Load and Peak Load Forecasts

The retail sales forecast detailed above is converted into monthly energy and peak load forecasts.
The peak load forecast is the expected (or average) peak demand during the respective month.
Depending on weather variation, we would expect actual peak loads to exceed this estimate 50
percent of the time.

Enhancements to Forecasting Process

Consistent with the Company’s two-year action plan, the forecasting models have been updated
with the latest energy consumption profiles. An additional enhancement was made with the
inclusion of cooling degree-days. In previous years, attempts were made to include hot weather
impacts on summertime loads, but they were unsuccessful. Our customers appear to have met a
threshold for usage during the air-conditioning season. The model coefficients were checked for
price elasticity impacts, and the new values were incorporated into the forecast; they have not
changed greatly during the last twenty years.

Appendix C Page C-1 Modeling Details
Appendix

Modeling Details

Selection of the AURORA Model

In the past, the Company has utilized PROSYM, an hourly dispatching program developed by
Henwood Energy Services for intra-month resource dispatch analyses. The Company’s first
official use of PROSYM was in support of the Clark Fork River relicensing effort in 1994.
PROSYM was also used in the Company’s 2001 General Rate Case in Washington. PROSYM
is a resource dispatch program that relies upon inputs including retail loads, fuel prices, and
wholesale electricity prices.

In late 2001, the Company decided to take a significant step forward in resource modeling and
elected to obtain a new chronological dispatch model with the ability to provide an electric
market price forecast based on marketplace fundamentals. To this end the Company reviewed
products offered by several leading purveyors of such tools.

Early in the process, the Company determined that five basic capabilities were necessary:

1. GUI and Usability
Each of the evaluated models relies upon a very large database containing all of the
generation facilities, utility loads, fuel prices, and other details pertaining to the Western
Electricity Coordinating Council (WECC). A graphical user interface (GUI) provides a
much more efficient means to work with these large data sets.

2. Deterministic
The deterministic capability of a model is signified by its ability to accurately represent
resource capabilities and loads. For example, certain models are able only to allow one heat
rate and capacity output for a given plant. Other models were not chronological and
therefore had the potential to violate the minimum up and down requirements of some base
load resources and dispatch them on an hourly basis.

3. Scenarios
IRPs and other regular analyses performed by the Company necessitate the ability for
developing scenarios. All of the evaluated models had some means whereby scenarios could
be managed.

4. Stochastic
Recent events, where market prices for natural gas and electricity have risen to points many
times above their historical levels, have emphasized the necessity of being able to evaluate
the risks inherent in any resource strategy.

Appendix C Page C-2 Modeling Details
5. Capacity Expansion
Over time the west coast will require a growing pool of new resources. The ideal model was
to include the capability to serve regional load growth by selecting least-cost resource
alternatives from a list of hypothetical future generation facilities.

AURORA, by EPIS Inc., best met the Company’s criteria. In April of 2002, Company staff,
along with staff from the Idaho and Washington Commissions, began training on AURORA at
EPIS headquarters in West Linn, Oregon. Evaluation and testing of AURORA continued
throughout the summer of 2002. The Company also provided its state regulators with licenses to
operate AURORA later in that year.

Cost of Capital for New Resources

An important assumption underlying AURORA that was not detailed in Section 5 is the cost of
capital for new resources. Depending on who backs the financing of new generation resources,
capital carrying costs vary. Generally, independent power producers (IPPs) have higher capital
carrying costs reflective of their riskier position in the marketplace. IPPs do not benefit, as
utilities do, from an allowed rate of return on their investments. As a result, utilities generally
have lower capital carrying costs. The following table provides the assumed cost of capital as
input into AURORA.

Table C.1
AURORA Cost of Capital

Municipal IOU IPP Weighted
Participation 20.0% 60.0% 20.0%
Debt Cost (After-Tax) 6.5% 5.4% 5.7% 5.7%
Debt Finance Level 100.0% 50.0% 60.0% 62.0%
Cost of Equity N/A 10.0% 16.0% 9.2%
Weighted Cost of
Capital 6.5% 8.2% 10.2% 10.0%
Weighted Average After-Tax Cost of Capital 7.0%

The weighted average after-tax cost of capital in AURORA was assumed to be seven percent
based on municipal utilities, investor owned utilities (IOUs), and IPPs constructing twenty, 60,
and twenty percent of the future resource additions, respectively.

Portfolio Optimization Using Linear Programming (LP) Module

One of the major challenges of the planning process is selecting an optimal portfolio of resource
alternatives. Portfolio optimization for the 2003 IRP is developed using a Linear Programming
Module that selects the optimal level of options and the specific timing of each option. For
example, over a twenty-year horizon the optimal set of resources to meet a given set of future
load requirements might be a combination of a new combustion turbine and a coal plant. The LP
Module is capable of assisting in the selection of the best mix of resources, and the specific
timing (i.e., year of installation) of each new resource.

Appendix C Page C-3 Modeling Details

As a further step, the LP Module is capable of comparing the optimal solution to other
alternatives that decision-makers might consider better for more qualitative reasons (e.g., wind
integration). This capability proved valuable given that a range of portfolios was found to
provide a similar lowest cost solution. The LP Module is also capable of adjusting the optimal
decision based on specific attributes such as lowest cost, level of risk, impact on the
environmental, etc. Finally, the LP Module can ensure a specific minimum or maximum level of
future resources generating capability is met (e.g., renewable portfolio standards).

Inputs to LP Module

The LP Module is dependent on various information derived from AURORA, and assumed fixed
costs associated with each portfolio decision. For each Monte Carlo iteration, AURORA records
three key statistics: the operating margin of the Company’s existing generation portfolio
assuming no incremental changes occur; the cost of serving its retail load assuming it was met
entirely from the wholesale marketplace; and the operating margin of the various new resource
alternatives. This data is then summed by calendar year and input into the LP Module.

In addition to AURORA output, the LP Module considers the annual fixed-cost payment stream
associated with each incremental resource decision. For example, fixed costs for a new CCCT
include not only capital, but also such items as fixed O&M, transmission integration,
depreciation, taxes, and miscellaneous charges.

The LP Module reviews the benefit derived from each new resource and then optimizes the
selection of resources given a level of future requirements. Where a new resource is selected its
operating margin, as determined by AURORA, is combined with its associated fixed costs to
derive the expected net impact to the Company.

Linear Programming Theory - by Robert Fourer

A Linear Program (LP) is a problem that can be expressed as follows (the so-called Standard
Form):

Minimize cx
subject to Ax = b
x >= 0

where x is the vector of variables to be solved for, A is a matrix of known coefficients, and c and
b are vectors of known coefficients. The expression "cx" is called the objective function, and the
equations "Ax=b" are called the constraints. All these entities must have consistent dimensions,
of course, and you can add "transpose" symbols to taste. The matrix A is generally not square,
hence you don't solve an LP by just inverting A. Usually A has more columns than rows, and
Ax=b is therefore quite likely to be under-determined, leaving great latitude in the choice of x
with which to minimize cx.

Appendix C Page C-4 Modeling Details
The word "Programming" is used here in the sense of "planning"; the necessary relationship to
computer programming was incidental to the choice of name. Hence the phrase "LP program" to
refer to a piece of software is not a redundancy, although I tend to use the term "code" instead of
"program" to avoid the possible ambiguity.

Although all linear programs can be put into the Standard Form, in practice it may not be
necessary to do so. For example, although the Standard Form requires all variables to be non-
negative, most good LP software allows general bounds l <= x <= u, where l and u are vectors of
known lower and upper bounds. Individual elements of these bounds vectors can even be infinity
and/or minus-infinity. This allows a variable to be without an explicit upper or lower bound,
although of course the constraints in the A-matrix will need to put implied limits on the variable
or else the problem may have no finite solution. Similarly, good software allows b1 <= Ax <= b2
for arbitrary b1, b2; the user need not hide inequality constraints by the inclusion of explicit
"slack" variables, nor write Ax >= b1 and Ax <= b2 as two separate constraints. Also, LP
software can handle maximization problems just as easily as minimization (in effect, the vector c
is just multiplied by -1).

The importance of linear programming derives in part from its many applications (see further
below) and in part from the existence of good general-purpose techniques for finding optimal
solutions. These techniques take as input only an LP in the above Standard Form, and determine
a solution without reference to any information concerning the LP's origins or special structure.
They are fast and reliable over a substantial range of problem sizes and applications.

Two families of solution techniques are in wide use today. Both visit a progressively improving
series of trial solutions, until a solution is reached that satisfies the conditions for an optimum.
Simplex methods, introduced by Dantzig about 50 years ago, visit "basic" solutions computed by
fixing enough of the variables at their bounds to reduce the constraints Ax = b to a square
system, which can be solved for unique values of the remaining variables. Basic solutions
represent extreme boundary points of the feasible region defined by Ax = b, x >= 0, and the
simplex method can be viewed as moving from one such point to another along the edges of the
boundary. Barrier or interior-point methods, by contrast, visit points within the interior of the
feasible region. These methods derive from techniques for nonlinear programming that were
developed and popularized in the 1960s by Fiacco and McCormick, but their application to linear
programming dates back only to Karmarkar's innovative analysis in 1984.

The related problem of integer programming (or integer linear programming, strictly speaking)
requires some or all of the variables to take integer (whole number) values. Integer programs
(IPs) often have the advantage of being more realistic than LPs, but the disadvantage of being
much harder to solve. The most widely used general-purpose techniques for solving IPs use the
solutions to a series of LPs to manage the search for integer solutions and to prove optimality.
Thus most IP software is built upon LP software, and this FAQ applies to problems of both
kinds.

Appendix C Page C-5 Modeling Details
Linear and integer programming have proved valuable for modeling many and diverse types of
problems in planning, routing, scheduling, assignment, and design. Industries that make use of
LP and its extensions include transportation, energy, telecommunications, and manufacturing of
many kinds. A sampling of applications can be found in many LP textbooks, in books on LP
modeling systems, and among the application cases in the journal Interfaces.

Source: Robert Fourer ([e-mail]), "Linear Programming Frequently Asked Questions," Optimization
Technology Center of Northwestern University and Argonne National Laboratory, http://www-
unix.mcs.anl.gov/otc/Guide/faq/ linear-programming-faq.html (2000).

Capacity Expansion

AURORA simulates the entire WECC and develops an hourly price forecast based on user
inputs. One sophisticated feature of AURORA is its ability to add new resources in a least-cost
manner to serve load growth over time, referred to as “capacity expansion.” AURORA develops
the capacity expansion plan using a list of user-defined new resources, detailed further in Section
4. Older, less-efficient units are retired and new resources are added through an iterative process
that identifies the optimal least-cost mix through the term of the study. Once the capacity
expansion plan is complete, hourly market prices can be estimated. The Company included a
$250 (in 2004 dollars) electricity price cap over the study period, which is intended to represent
the continuation of price caps imposed by FERC.

The overwhelming resource preference of the capacity expansion exercise is combined-cycle
combustion turbines (CCCTs). This result is consistent across the WECC. Wind plants are the
second-most selected alternative, accounting for nearly seventeen percent of installed capacity by
the end of the twenty-year study. Modest amounts of coal, and simple-cycle combustion turbines
(SCCTs) are also selected. The following table illustrates the resource retirements and additions
over various years of the IRP study. More detailed results from the study may be found in
Appendix J.

Table C.2
Cumulative IRP Capacity Expansion Resource Summary (GW)

Year CCCT Coal SCCT Wind Retire Net
2004 0.00 0.00 0.00 0.00 (0.50) (0.50)
2008 0.28 0.00 0.00 1.10 (7.48) (6.09)
2013 16.06 2.00 0.00 11.10 (25.74) 3.43
2018 40.70 2.00 0.09 13.90 (25.81) 30.90
2023 67.30 2.00 0.83 14.00 (25.81) 58.34
80.0% 2.4% 1.0% 16.6%

Overall, AURORA selects 67.3 GW of new CCCT generation capacity. This equates to 80
percent of the total. Nearly 26 GW of older resources are retired over the term of the study, with
a majority leaving service by 2013. Most of the resource retirements are older, inefficient
natural gas- and oil-fired plants. A list of specific plants retired in the capacity expansion run
may be found in Appendix J.

Appendix C Page C-6 Modeling Details
EPIS, the developers of AURORA, provided the Company with a detailed document regarding
the capacity expansion process. This document has been included as Appendix I.

Modeling Process Diagram

Figure C.1 depicts the entire modeling process. This process utilized three spreadsheet-based
models, as well as AURORA, to develop, execute, and evaluate 200 distinct iterations of Monte
Carlo simulation.

The process represented in Figure C.1 includes the following stages of analysis:

1. Stochastic Analysis
The initial stage was dedicated to the development of inputs for AURORA that incorporate
varying natural gas prices, WECC loads, and northwest hydroelectric generation. It utilized a
spreadsheet-based model to generate 200 distinct input data sets based on random variables,
and upload each data set to an Oracle database.

2. Capacity Expansion
The second stage in the process was capacity expansion, where AURORA matched twenty
years of WECC load growth with the construction of hypothetical new generation. Capacity
expansion utilized average values for natural gas prices, WECC loads, and northwest
hydroelectric generation; as well as resource assumptions from the NWPPC.

3. Monte Carlo
The next stage incorporated the results of the stochastic analysis and capacity expansion. It
used a spreadsheet-based model to select a specific input data set, run AURORA, and write
the outputs to an Oracle database. This process was repeated for each of the 200 iterations,
and resulted in 200 distinct output data sets.

4. Resource Optimization
The final stage made use of a spreadsheet-based optimization model that incorporated an LP
Module to select an optimum set of resources based on Company-specific needs. This stage
evaluated numerous resource strategies under several distinct scenarios to develop and assess the
Preferred Resource Strategy.

Appendix C Page C-7 Modeling Details
Figure C.1
Modeling Process Diagram

Stochastic Analysis
Gas based on 2003 Gas inversely correlated
Prices IRP (DRI-WEFA) to hydro
WECC based on actual all regions
Loads WECC load data correlated to OWI
Northwest based on 60 years all river systems
Hydro of historic data correlated to OWI
generates 200 Randomization uploads data sets
input data sets Model to Oracle DB
Capacity Expansion
based on average Long-Term forecasts WECC load
gas, load, and hydro Study growth for 20 years
utilizes NWPPC builds resources
resource assumptions to meet WECC load
Monte Carlo
pulls unique inputs Monte Carlo writes custom
into Aurora Model outputs to Oracle
marks to market creates distinct
loads and resources market forecast
marks to market writes outputs to
potential resources Oracle DB
Resource Optimization
market cost to Query Data market value of
serve Avista load from Oracle DB potential resources
accounts for capital resource selection
costs of potential and timing based on
resources Avista load
evaluates potential analyses potential
resources based on resource strategies
risk and cost (NPV) and distinct scenarios
Aurora
nd The
Answer Is?
Optimization Model
1
3
4
2

Appendix D Page D-1 Risk Details
Appendix

Risk Details

Resource Risk Profiles

There are many risk factors that must be considered when evaluating prospective new resources.
The most significant risk factors associated with different resources are detailed below.

Fuel Supply Risk

Some resources do not have consistent access to fuel. The best example of this may be hydro,
where fuel is determined by precipitation and runoff. As a result, fuel availability can vary
significantly from year to year. Fuel supply risk can be substantial, particularly when the fuel is
essentially free or very low cost, as is the case with hydro. When evaluated on an hourly or daily
basis, wind resources cannot be counted on to have any fuel supply. Long-term market
purchases have fuel supply risk due to reduced assurance that the supplier will exist to perform
over the contract term.

Fuel Price Risk

Resources that don’t have long-term fixed price fuel contracts often have significant fuel cost
risk. Natural gas-fired resources have the most fuel price risk, since the gas price can be volatile
and is typically not fixed over a long period. Coal resources typically have a fixed price long-
term supply contract with little fuel price risk. Hydro and wind resources have free fuel, so there
is no fuel price risk.

Forced Outage Risk

Forced outage rates vary between resources. Resources with low operating costs present the
most risk from forced outages. While hydro and wind plants generally have very low forced
outage rates, coal plants have the highest forced outage rates. Forced outage risk can be
significant with coal plants because the operating cost is usually low and outages, while usually
short, can be much longer. Longer-term (several month) outages at a coal plant can have a
significant impact on power supply costs. Forced outages at natural gas fired plants do not
represent as large of a risk because the operating cost is typically high, so purchasing
replacement power may not constitute a large incremental expense.

Environmental Risk

All resources contain some environmental risk. Regulation, licensing, and permitting conditions
may change over time and adversely impact the cost of a resource. Examples of environmental
risk include potential future carbon tax on fossil fuel-fired resources, permitting and construction
delay risks for most resources, and relicensing issues with hydroelectric facilities.

Appendix D Page D-2 Risk Details
Resource Characteristics

Each type of resource has its own unique characteristics. Included below are the prominent
resource types and corresponding characteristics.

Combustion Turbines

Short-term dispatch capability reduces risk in that the Company can shut down a plant when its
costs are higher than equivalent market purchases. High fuel cost that is correlated to electric
prices increases risk. Low capital cost reduces present value cost and initial rate pressure.

Coal

Low fuel cost that is typically not correlated to electric prices is good for risk mitigation. High
capital cost increases present value cost and initial rate pressure. Construction and
environmental risks may be significant, but are hard to quantify.

Wind

Very low operating cost and output that is not correlated to electric prices is good for risk
mitigation. High capital cost increases present value cost and initial rate pressure. There are
significant concerns with system integration (i.e., control area services). Wind would be
beneficial if renewable portfolio requirements were adopted. It also appears to have significant
public appeal.

Market Purchases

The Company is always in the market, balancing loads and resources on an hourly, daily,
monthly, and quarterly basis. The Company also, on occasion, makes medium-term (up to five
year) purchases when prices appear to be lower than marketplace fundamentals. Short-term
purchases (one year or less) can be low cost in surplus market conditions, but come with higher
risk.

Utilizing medium-term purchases can be a low cost strategy when markets are favorable, but can
have somewhat higher risk due to counter party credit issues and the need to roll the contracts
over in potentially high-cost market conditions. Long-term (beyond five year) fixed price
purchases are good for risk mitigation to the extent the counter party exists into the future to
make deliveries. However, the risk associated with issues including credit, margin calls, and
supplier reliability generally increases as the term extends. The current lack of market liquidity
makes the execution of even medium term purchases difficult, and makes long-term purchases
unlikely.

Cogeneration

Cogeneration resources may provide risk mitigation depending on the fuel source and contractual
arrangements. Typically the Company purchases cogeneration under long-term fixed price

Appendix D Page D-3 Risk Details
contracts. In this case cogeneration has the same risk mitigation characteristics as a fixed price
market purchase. The purchase is unit contingent so there is also supply risk. Cogeneration is an
opportunity resource, meaning that if a host proposes a viable project the Company will consider
it. Since the Company does not control the host sites, it is difficult to plan for the addition of
cogeneration resources.

Demand-Side Management (DSM)

DSM resources are typically characterized by all capital cost and no operating cost. Because of
this they have the risk mitigation properties similar to other high fixed, low variable cost
resources. DSM can increase risk in other ways due to the difficulty in verifying energy savings.

The Company has focused its analytical efforts on understanding the impacts of commercially
available and relatively low cost supply-side resource options. To this end, only those resources
with a reasonable likelihood of benefiting customers were included in the analyses. The benefits
and risks expected from these resources, as detailed above, were supported by the analyses
performed for the IRP.

Load Correlations

The following table contains load correlations between the WECC load areas modeled in
AURORA and OWI (Oregon, Washington, and North Idaho). A load area representing the
Company’s service territory was also included in the model, but is not included in the table
below. This load area (AVA) was assumed to be 100 percent correlated to OWI.

Table D.1
Load Correlations to OWI
(Average of Weekdays)

Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
AB 0.659 NotSig 0.481 NotSig Mix 0.635 0.668 Mix Mix 0.479 NotSig NotSig
AZ 0.440 0.664 NotSig Mix (0.289) 0.666 NotSig NotSig NotSig NotSig Mix NotSig
BC 0.918 0.838 0.825 0.733 0.617 NotSig 0.560 NotSig 0.638 0.809 0.525 0.890
CANo NotSig 0.734 NotSig NotSig NotSig 0.771 Mix 0.757 0.789 NotSig Mix NotSig
CASo NotSig Mix NotSig NotSig Mix 0.680 Mix 0.500 0.778 NotSig NotSig NotSig
CO 0.623 NotSig 0.567 Mix Mix NotSig NotSig NotSig NotSig 0.655 0.629 0.571
IDSo 0.673 0.747 0.882 NotSig NotSig 0.758 Mix 0.789 0.733 0.561 0.587 0.813
MT 0.894 0.773 0.755 0.651 0.405 0.599 0.786 0.648 0.752 NotSig 0.856 0.898
NVNo Mix NotSig NotSig NotSig NotSig NotSig NotSig NotSig NotSig Mix 0.476 NotSig
NVSo NotSig 0.641 0.513 Mix NotSig 0.729 Mix NotSig Mix NotSig 0.461 Mix
NM 0.384 Mix Mix NotSig NotSig Mix NotSig Mix NotSig NotSig Mix Mix
UT 0.816 NotSig 0.669 0.697 0.610 0.698 0.703 0.604 0.611 NotSig 0.561 0.837
WY 0.765 Mix 0.641 NotSig Mix Mix NotSig NotSig 0.483 NotSig 0.522 0.633

NOTE: "NotSig" represents that relationship was not statistically significant; "Mix" represents
that the relationship was not a consistent across time.

Appendix D Page D-4 Risk Details
Market Uncertainty

The northwest electricity marketplace has historically been characterized by a general
cooperation among participants. Various past and present consortiums of utilities, such as the
NWPP, PNUCC, the inter-company pool, stand as a testament to this coordination. Unlike some
other parts of the country where a lack of transmission access prevented vibrant wholesale
markets, the northwest benefited from a transmission system owned substantially by BPA. This
provided a means for utilities to buy and sell electricity as their needs warranted. This type of
cooperation remained into the mid-1990s.

Beginning in the mid-1990s, regional cooperation was replaced with competition. Beginning
with the Energy Policy Act of 1992, utilities were pushed into wholesale and, later through state
deregulation attempts, retail competition. Utilities witnessed the entrance of marketing
companies whose primary purpose was not to serve retail customers, but instead was to generate
profits from energy trading. Many utilities responded to this competition by spinning off their
own unregulated marketing arms. In 1996 the inter-company pool was abandoned and
cooperation was restricted significantly due to "competitive interests."

In 1996 California passed Assembly Bill 1890 opening their electricity marketplace to retail
competition. The industry was abuzz with excitement. Then-Governor Pete Wilson probably
summed up the general consensus of that period by stating as he signed the bill into law, "[that]
this landmark legislation is a major step in our efforts to lower rates, provide consumer choice
and offer reliable service, so that no one literally is left in the dark." For various reasons the
results of AB1890 as implemented could not have been further from expectations.

Adding to marketplace uncertainty was a rapid erosion of the capacity surplus responsible for the
more than a decade of low-cost wholesale market prices that helped drive the train of electricity
deregulation. Many northwest utilities, including this Company, began to rely on the wholesale
marketplace to serve their load requirements. The logic of this strategy was clear at the time and
was supported by regulatory bodies through rate cases and IRPs: new resources could not be
built except at twice the cost of market purchases.

Federal deregulation efforts, California's deregulation, load growth and the reliance of utilities on
the marketplace to serve their retail requirements, the entrance of for-profit marketing entities,
and low hydroelectric conditions came together in 2000 to create unprecedented market
conditions. Wholesale prices rose from historical levels of twenty dollars per MWh to more than
five hundred dollars. Utilities across the West approached or went bankrupt as they purchased
power at costs as much as ten times what they were recovering from sales to their customers.
Power marketers who also were planning to serve sales obligations from the spot market went
out of business. Enron, the largest player in the marketplace and the entity responsible for a
majority of market liquidity, declared bankruptcy and stopped trading. Customer rates were
increased by tens of percentage points.

By mid-2001 electricity prices returned to historical levels in response to new generation
construction and FERC-imposed price caps. The run-up and fall of electricity prices can be seen
in the following chart of Mid-C average monthly prices.

Appendix D Page D-5 Risk Details
Chart D.1
Mid-Columbia Market Prices 1999-2002

Wholesale market prices in 1998 and 1999 averaged $23.19 dollars per MWh. The averages in
both 2000 and 2001 were more than $120 per MWh. 2002 averaged $22.38 per MWh, modestly
lower than the 2000/01 period.

Liquidity, the essential ability to buy and sell in a competitive marketplace, has always
challenged the west coast electricity markets. Until the energy crisis occurred, liquidity was
expanding; the number of counter parties the Company could do business with was increasing.
This afforded the Company greater opportunities for portfolio optimization. Since the energy
crisis, the Company has witnessed a rapid decline in the number of counter parties available to it
due to many marketers leaving the industry and the increasingly difficult task of acquiring the
credit necessary to do business. However, the risk of price volatility remains. Utility planning
must now re-double its efforts to address market price fluctuations such as those witnessed
during 2000 and 2001.

Industry Restructuring

Industry restructuring to open the electric wholesale energy market to competition was initially
promoted by federal legislation. The Energy Policy Act of 1992 amended provisions of the
Public Utility Holding Company Act of 1935 and the Federal Power Act to remove certain
barriers to a competitive wholesale market. The Energy Act expanded the authority of the FERC
to issue orders requiring electric utilities to transmit power and energy to or for wholesale
purchasers and sellers, and to require electric utilities to enlarge or construct additional
transmission capacity for the purpose of providing these services. It also created “exempt
wholesale generators,” a new class of independent power plant owners that are able to sell
generation only at the wholesale level. This permits public utilities and other entities to
participate through subsidiaries in the development of independent electric generating plants for
sales to wholesale customers without being required to register under the PUHCA.
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Appendix D Page D-6 Risk Details

FERC Order No. 888, issued in April 1996, requires public utilities operating under the Federal
Power Act to provide access to their transmission systems to third parties pursuant to the terms
and conditions of the FERC’s pro-forma open access transmission tariff. FERC Order No. 889,
the companion rule to Order No. 888, requires public utilities to establish an Open Access Same-
Time Information System (OASIS) to provide transmission customers with information about
available transmission capacity and other information by electronic means. It also requires each
public utility subject to the rule to functionally separate its transmission and wholesale power
merchant functions. The FERC issued its initial order accepting the non-rate terms and
conditions of the Company’s open access transmission tariff in November 1996. The Company
filed its “Procedures for Implementing Standards of Conduct under FERC Order No. 889” with
the FERC in December 1996 and adopted these Procedures effective January 1997. FERC
Orders No. 888 and No. 889 have not had a material effect on the Company's operating results.

The Company is participating with nine other utilities in the western United States in the possible
formation of a Regional Transmission Organization (RTO), RTO West, a non-profit
organization. The potential formation of RTO West is in response to a FERC order requiring all
utilities subject to FERC regulation to file a proposal to form a RTO, or a description of efforts
to participate in a RTO, and any existing obstacles to RTO participation. RTO West filed its
Stage 2 proposal with the FERC in March 2002 and received limited approval from the FERC of
this initial plan in September 2002. Depending on regional support, RTO West could be
operational in late 2005 or early 2006.

The Company and two other utilities have also taken steps toward the formation of a for-profit
Independent Transmission Company, TransConnect, which would be a member of RTO West,
serve portions of five states and own or lease the high voltage transmission facilities of the
participating utilities. TransConnect filed its proposal with the FERC in November 2001 and
received limited approval from the FERC in September 2002.

The final proposals must be approved by the FERC, the boards of directors of the filing
companies and regulators in various states. The companies’ decision to move forward with the
formation of TransConnect or RTO West will ultimately depend on the conditions related to the
formation of the entities, as well as the economics and conditions imposed in the regulatory
approval process. If TransConnect were formed, it could result in the Company divesting its
electric transmission assets. The formation of RTO West or TransConnect could have an impact
on the Company’s transmission costs. However, the Company believes that any changes to
transmission costs would be reflected as an adjustment to retail rates.

On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking proposing a Standard
Market Design (SMD) that would significantly alter the markets for wholesale electricity and
transmission and ancillary services in the United States. The new SMD would establish a
generation adequacy requirement for “load-serving entities” and a standard platform for the sale
of electricity and transmission services. Under the new SMD, Independent Transmission
Providers would administer spot markets for wholesale power, ancillary services and
transmission congestion rights, and electric utilities, including the Company, would be required
to transfer control over transmission facilities to the applicable Independent Transmission

Appendix D Page D-7 Risk Details
Provider. There have been significant state-level and regional concerns raised with the FERC
with respect to the SMD, particularly in the western and southeastern United States. Public
meetings were held during the second half of 2002 and early 2003 with an updated SMD
expected to be issued during the first half of 2003. Once the final SMD is issued, a phased
compliance schedule will begin. The Company is currently in the process of determining the
impact the proposed SMD would have on its operations as well as how the SMD would impact
the RTO West and TransConnect proposals. The Company is subject to state regulation in each
of the states it operates in. State regulatory agencies are actively involved in the SMD
rulemaking process.

The North American Electric Reliability Council and the WECC have undertaken initiatives to
establish a series of security coordinators to oversee the reliable operation of the regional
transmission system. Accordingly, the Company, in cooperation with other utilities in the
Pacific Northwest, established the Pacific Northwest Security Coordinator (PNSC), which
oversees daily and short-term operations of the Northwest sub-regional transmission grid and has
limited authority to direct certain actions of control area operators in the case of a pending
transmission system emergency. The Company executed its service agreement with the PNSC in
September 1998.

Appendix D Page D-8 Risk Details
DRAFT

Interoffice Memorandum
Energy Resources

DATE: April 11, 2003

TO: Clint Kalich

FROM: Ed Groce

SUBJECT: SMD Resource Adequacy

The reserve margin and planning horizon sections of FERC’s SMD NOPR are summarized below at your
request.

• In order to operate a transmission system reliably, adequate generation must be available to
meet load. Some lead time is needed to develop adequate infrastructure for the future.

• Resource adequacy must be assessed at the regional level. Because all customers in an
interconnected region are interdependent, a shortage of resources for some customers in the
region can lead to a shortage for the entire region, which threatens reliable grid operations
and risks sustained shortages with attendant high prices for the region.

• A requirement to assure adequate long-term resources is currently needed because spot
market prices do not consistently signal the need for new infrastructure in the electric power
industry. Most resources take years to develop and spot market prices alone may not signal
the need to begin development of new resources in time to avert a shortage.

• Each region should take its own characteristics into account when determining the
appropriate level, subject to a minimum level of resource adequacy for all regions. This
determination has historically been made by load-serving entities under the oversight of the
states, and FERC wants this state oversight to continue. FERC proposes that the level should
be set by a Regional State Advisory Committee. States in the region should have this strong
role in determining the level of resource adequacy because a higher level provides greater
reliability and also incurs higher costs that affect most retail customers. State representatives
are in the best position to determine on behalf of retail customers the trade-off between the

Appendix D Page D-9 Risk Details
cost to the customers of extra generation and demand response reserves and the difficult-to-
quantify benefits to the customers of increased reliability and reduced exposure of the region
to the effects of a power shortage.

• Resource adequacy reserves are often called planning reserves and are not the same as 5 and
7 percent operating reserves.

• Once the future level of supply and demand resources is determined, the region must assess
whether this level is adequate. This requires a regional determination of the appropriate level
of resources, for example, whether the reserve margin (if reserve margin is the region’s
measure of resource adequacy) should be 12, 15, 18 percent, or another level.

• FERC is concerned that the requirement be set so that the RTO can operate the system
reliably and that inadequate resources could lead to poor market liquidity and even shortages
with sustained high wholesale power prices. For these reasons, FERC proposes to adopt a 12
percent reserve margin as a minimum regional level for all regions with the understanding
that this is low by traditional generation adequacy standards and that the Regional State
Advisory Committee in each region may set this number higher for the region. FERC
selected a 12 percent margin as a minimum in that it is two-thirds of the typical historical
reserve margin target of 18 percent for large utilities. FERC emphasizes that most utilities
historically used a reserve margin well above 12 percent.

• The traditional state-required planning horizon was 10-12 years. The horizons were
established when the industry relied on new large hydroelectric, coal, or nuclear facilities
which could take 10 or more years to site and construct. Today, most new resources are
planned and developed over a much shorter time frame. Because the planning horizon
should be no less than the time frame for developing new resources and development times
vary from region to region, the planning horizon can depend on that region’s reliance on
coal, gas, wind, hydropower or new demand-response technology for new supply. This
argues for allowing each region to determine it’s own appropriate planning horizon.

• FERC proposes to have the Regional State Advisory Committee determine the planning
horizon for the region.

• FERC defines reserve margin as: The reserve for a period is the amount of resources
expected to be available during the period less the forecasted peak load. The reserve margin
is the ratio of the reserves to the forecasted peak load. A region may use another measure of
adequacy as long as the minimum level is the arithmetic equivalent of a 12 percent reserve
margin. For example, many use capacity margin, which is the ratio of the reserves to the
amount of resources expected to be available during the period. A capacity margin of 10.7
percent is the same as a reserve margin of 12 percent. Some may measure adequacy with a
loss-of-load probability, called LOLP, which is a statistical measure of the expected total
time during a period that generation will be unavailable to meet load. The common US
standard is one day in ten years, which means that the sum of the hours during a ten year
period when generation is expected to be short is 24 hours. Reserve margin cannot be
translated directly into LOLP without studying a particular system. For example, an area

Appendix D Page D-10 Risk Details
served by a few large generators is more vulnerable to a shortage caused by an outage of one
or two large generators than a similar area served by many smaller generators. The area with
a few large generators may need a larger reserve margin to achieve the same LOLP. A
general rule-of-thumb for a large US utility system is that an LOLP of one-day-in-ten-years
is achieved with a reserve margin of about 18 percent.

Appendix E Page E-1 Detailed Results
Appendix

Detailed Results

Details of Preferred Resource Strategy

As discussed in Section 7, the Preferred Resource Strategy selects a mix of natural gas-fired,
coal-fired, and wind generation. During the first ten years (2004-2013), varying amounts of each
of these resources is selected. During the second ten years (2014-2023) of the IRP term, only
coal-fired generation is constructed. Refer to the following chart for a depiction of resource
selections under the PRS. Since no resources are added until 2008, the chart represents only
2008-2023.

Chart E.1
Preferred Resource Mix (in aMW)
2008-2023

Possibly the largest surprise in the study is the significant reliance on coal-fired generation.
This is especially unexpected since AURORA selected only a modest amount of coal-fired
generation during WECC capacity expansion (see Appendix C). Instead, AURORA relied on
CCCTs for 80 percent of its new resources.

If the Preferred Resource Strategy had been based entirely on achieving the lowest cost, the LP
Module would also have selected CCCTs instead of coal plants. The primary driver behind the
construction of coal plants is the consideration of risk. Coal plants have low variable operating
costs, making their level of fuel price risk much lower than CCCTs, for which two-thirds of the
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CCCT Peakers
Wind Coal

Appendix E Page E-2 Detailed Results
generation cost is fuel. Coal plants cost only a modest amount more than CCCTs, especially in
the out years, yet the variability of net power supply expenses is significantly lower. This result
is very intriguing, and the further study of coal plant economics has been identified as an action
item. See Section 8 for more detail.

Details of Strategy Results

As discussed in Section 5, the Company analyzed several strategies in addition to the Preferred
Resource Strategy. These strategies include No Additions, Lowest Cost/CCCT, Lowest Risk, All
Coal, and Wind Strategy. The PRS was compared to each strategy on a cost, risk, capital
expenditure, rate impact, market reliance, and qualitative basis. The result, as detailed below,
was that the PRS performed very well across those criteria.

Average Expected Cost

Average expected costs across the strategies are not substantially different. During the first ten
years, No Additions has a 0.9 percent lower average cost than the other strategies, even the
Lowest Cost strategy. This is due to the fact that all of the strategies, with the exception of No
Additions, must build something. Considering the Company’s position in the early years of the
study, it is less expensive to do nothing. Ignoring risk and focusing exclusively on lowest cost
provides a modest savings of 2.5 percent over the Preferred Resource Strategy. Other strategies
have higher costs than the PRS in the first ten years.

On a twenty-year basis, the Preferred Resource Strategy has higher costs than the Lowest Cost
strategy. The Lowest Risk and Wind Strategy also provide a modest reduction in cost over the
PRS over twenty years. Both No Additions and All Coal would increase costs modestly over the
Preferred Resource Strategy. The following chart provides a comparison of costs for the various
strategies.

Appendix E Page E-3 Detailed Results
Chart E.2
Comparison of Net Power Supply Expense
2004-13 and 2004-23 Net Present Values
(in 2004 dollars)

Risk Assessment

Unlike average net power supply expense, the risk profiles for the various strategies vary
substantially. To illustrate these differences, the average annual variation over the 200 iterations
was evaluated for the 2004-2013 and 2004-2023 timeframes, as shown in the chart below.

Chart E.3
Comparison of Strategy Risk Profiles
2004-13 and 2004-23 Average Annual Variation

1.0
1.2
1.4
1.6
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No Additions Preferred Lowest
Cost/CCCT
Lowest Risk All Coal Wind Strategy
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20-year NPV
8%
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16%
17%
No Additions Preferred Lowest
Cost/CCCT
Lowest Risk All Coal Wind Strategy
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Appendix E Page E-4 Detailed Results
All strategies provide a significant reduction in risk when compared to No Additions. Besides No
Additions, the Lowest Cost/CCCT strategy is the riskiest over the first ten years. Over twenty
years, the Preferred Resource Strategy reduces risk substantially when compared to the No
Additions, Lowest Cost/CCCT, and Wind Strategy strategies. The Lowest Risk and All Coal
strategies are only slightly less risky than the PRS.

Viewing risk over the timeframe of the IRP provides a more robust understanding of the impact
of selecting a portfolio of resources. The following chart depicts each strategy over time.

Chart E.4
Comparison of Strategy Risk Profiles
2004-2023

Capital Expenditures

The following chart depicts the capital costs of each strategy in 2004 dollars. Over the first ten
years the varying strategies would require between $390 million and $1.02 billion in capital
investments. The PRS requires $725 million, less than the All Coal and Lowest Risk strategies,
but more than the Lowest Cost/CCCT strategies. The Wind Strategy is similar in cost to the PRS.
Over 20 years the Preferred Resource Strategy will require $2.37 billion of capital.

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Preferred
Lowest Cost/CCCT
Lowest Risk
All Coal
Wind Strategy

Appendix E Page E-5 Detailed Results
Chart E.5
Capital Costs of Strategies (in 2004 dollars)
2004-2023

The Lowest Cost/CCCT strategy requires the smallest initial investment in new resources. The
trade-off is higher future expenses for natural gas.

Rate Impacts

The following chart depicts the rate impact of each strategy due to changes in power supply
costs. During the first ten years, all strategies besides Lowest Cost/CCCT increase rates very
modestly when compared to the current embedded power supply cost of approximately $32 per
MWh. In the case of the Preferred Resource Strategy, the increase is less than one dollar per
MWh. With the exception of constructing new CCCT plants, buying from the wholesale
marketplace for the first ten years of the IRP study could produce the lowest cost to customers.

0.0
0.5
1.0
1.5
2.0
2.5
Preferred Lowest
Cost/CCCT
Lowest Risk All Coal Wind Strategy
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10-year
average
20-year
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Appendix E Page E-6 Detailed Results
Chart E.6
Rate Impacts (as Compared to No Additions)
2004-13 and 2004-23 Averages

Over twenty years, all strategies besides All Coal are expected to reduce rate pressure when
compared to a No Additions strategy. The PRS lowers costs by about $0.2 per MWh. The
Lowest Risk and Wind Strategy reduce costs by between $0.2 and $0.5 dollars per MWh over
twenty years compared to the PRS.

Reliance On the Wholesale Electricity Marketplace

As discussed earlier in this section, the Company relies on the wholesale marketplace to support
surplus energy sales or meet load obligations. During any given calendar year, the Company
expects that it would be selling and buying in different months, days, and hours. With the
exception of No Additions and the Wind Strategy, all of the strategies rely on the market for
fewer than seven percent of retail load over twenty years. The only strategy that contains a
surplus of energy that must be sold into the wholesale marketplace is Lowest Risk. Its significant
level of wind generation forces many sales, since the resource cannot be dispatched. The Wind
Strategy does not have a substantial amount of surplus sales due to the large amount of peaking
units that are oftentimes displaced. The other strategies include net purchases of electricity,
primarily due to periods where it is less expensive to buy from the market than to generate. The
following chart displays the market reliance of all strategies.

(0.8)
(0.6)
(0.4)
(0.2)
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Preferred Lowest
Cost/CCCT
Lowest Risk All Coal Wind Strategy
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20-year
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Appendix E Page E-7 Detailed Results
Chart E.7
Market Reliance
2004-13 and 2004-2023 Averages

Details of Scenario Results

As discussed in Section 5, the Company utilized several scenarios to evaluate the Preferred
Resource Strategy and other strategies. Most of the discussion so far has been about strategies
(e.g, PRS, No Additions, All Coal, etc.), and how they stack up under the Base Case. While the
Base Case scenario incorporates the results of 200 iterations of Monte Carlo simulation, eight
other scenarios were evaluated utilizing normal loads, hydroelectric generation, and natural gas
prices (unless the scenario specifically designates a departure from average). These scenarios
include Average, Critical Water, High Gas, High Load, Load Loss, New Trans, Coal Build, and
Carbon Tax. The following chart compares average annual Northwest electricity prices under
the Base Case with those resulting from the scenarios described above. The chart does not
include the Load Loss scenario, as this scenario has no impact on market prices.

-5%
0%
5%
10%
15%
20%
25%
30%
No Additions Preferred Lowest
Cost/CCCT
Lowest Risk All Coal Wind Strategy
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Appendix E Page E-8 Detailed Results
Chart E.8
Northwest Electricity Market Prices by Scenario
2004-2023

High Gas and High Load create the highest average market prices. Critical Water also drives
prices up relative to many of the other scenarios, but to a much lesser extent. The impact of
Critical Water is less significant in the later years, as hydro represents a smaller portion of total
generation in the WECC.

An interesting result is the difference between the Average scenario and the Base Case. The
average of load, hydroelectric generation, and natural gas prices in the 200 iterations that
developed Base Case prices were used in creating the Average scenario, yet the average price
under 200 iterations is higher than the single run using average loads, hydro, and natural gas
prices.

The difference between Base Case and Average substantiates the Company’s position that
averages understate the true cost of serving customer loads and the value of generating resources.
There are a number of reasons for this result. For example, revenues when the Company
experiences above-average hydro are not adequate to compensate for when hydro generation is
below average. Additionally, the Company’s net position is correlated to the region, forcing it to
buy at inopportune times.

Each of the scenarios, and their impacts on each portfolio strategy, is detailed below.

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Hi Load New Trans
Coal Build Carbon Tax

Appendix E Page E-9 Detailed Results
Critical Water

The Critical Water scenario assumes Northwest hydroelectric conditions equal the 1936-1937
water year. This scenario provides an estimate of how prices might change due to adverse
hydroelectric generation, creating a situation where the WECC must rely more heavily on
thermal generation. The table below shows the NPV of each resource strategy under Critical
Water scenario. It also shows the difference between each resource strategy and the Preferred
Resource Strategy.

Table E.1
Net Present Value of Resource Strategies
Critical Water Scenario

PRS No Additions
Lowest
Cost/CCCT Lowest Risk All Coal
Wind
Strategy
Period Value Value Diff Value Diff Value Diff Value Diff Value Diff
2004-13 1.44 1.40 -2.4% 1.41 -2.2% 1.45 1.1% 1.46 1.5% 1.46 1.5%
2004-23 3.19 3.12 -2.0% 3.05 -4.4% 3.14 -1.4% 3.26 2.3% 3.18 -0.1%

Results under Critical Water are similar to the Base Case. The No Additions strategy cost is two
percent lower than the Preferred Resource Strategy over twenty years. This differs from the
Base Case where No Additions increases costs by 1.6 percent.

High Gas

For the High Gas scenario, natural gas prices were doubled. Instead of increasing from $3.95
per decatherm in 2004 to $6.75 in 2023, prices begin at $7.88 per decatherm and increase to
$13.53. Table E.2 compares the Preferred Resource Strategy to other considered strategies
under the High Gas scenario.

Table E.2
Net Present Value of Strategies
High Gas Scenario

PRS No Additions
Lowest
Cost/CCCT Lowest Risk All Coal
Wind
Strategy
Period Value Value Diff Value Diff Value Diff Value Diff Value Diff
2004-13 1.40 1.40 0.3% 1.44 3.0% 1.34 -4.1% 1.33 -5.3% 1.43 2.1%
2004-23 3.23 3.45 6.8% 3.59 11.0% 2.96 -8.5% 3.05 -5.5% 3.42 5.9%

High gas prices disadvantage gas-fired resources, relative to those using other fuels. The
Preferred Resource Strategy relies on 189 aMW of gas-fired resources, while choosing coal and
wind to account for 790 aMW of energy. As a result, its NPV does not change substantially
from the Base Case. The Lowest Cost/CCCT strategy relies exclusively on natural gas-fired
CCCTs and has costs much greater than the PRS.

Appendix E Page E-10 Detailed Results
High Load

For the High Load scenario, loads were increased by two standard deviations, or 12.5 percent
through time. Natural gas prices are assumed to remain constant, which might not always hold
true and would disadvantage gas-fired generation. WECC loads begin at 108,771 aMW in 2004,
compared to 96,712 aMW in the Base Case. In 2023, loads are 167,371 aMW instead of
148,837 aMW. Table E.3 compares the Preferred Resource Strategy to other considered
strategies under the High Load scenario.

Table E.3
Net Present Value of Strategies
High Load Scenario

PRS No Additions
Lowest
Cost/CCCT Lowest Risk All Coal
Wind
Strategy
Period Value Value Diff Value Diff Value Diff Value Diff Value Diff
2004-13 1.28 1.54 20.8% 1.26 -1.7% 1.25 -2.1% 1.30 1.7% 1.28 0.5%
2004-23 3.08 4.58 48.6% 2.99 -3.0% 2.78 -9.8% 3.15 2.3% 3.01 -2.4%

The Preferred Resource Strategy is modestly out-performed by the Lowest Cost/CCCT and
Lowest Risk strategies during the first ten years of the IRP study. Over twenty years, the Wind
Strategy also provides a modest benefit when compared to the PRS. The No Additions strategy is
substantially higher in cost than the other strategies because the High Load scenario drives up the
cost of serving load from the wholesale marketplace. The PRS provides a significant level of
protection against higher loads because the portfolio contains resources that are capable of
generating approximately fifteen percent more energy than in the Base Case, and it can therefore
provide for increased customer requirements. On the other hand, because the PRS relies heavily
on coal plants in the later years, the costs are higher. Coal plants are not as attractive as gas-fired
plants in a high load scenario, as economic dispatch is limited due to higher fixed costs and
lower variable costs.

Load Loss

Losing 300 aMW of system load will lower the Company’s net power supply expense by 70
percent on a NPV basis between 2004 and 2013 under the Preferred Resource Strategy. The
reduction over twenty years is 49 percent. Costs are reduced substantially due to the Company
selling significant amounts of low-cost generation into the wholesale marketplace. With reduced
loads, the Company does not require new resources until 2012, a full four years further out than
in the Base Case. The following chart shows the reduction in required additions of generation
under the Load Loss scenario.

Appendix E Page E-11 Detailed Results
Table E.4
Resource Build
Base Case and Load Loss Scenarios

Period Scenario CCCT SCCT Wind Coal Total
Base Case 149 40 25 197 411 First 10
Years Load Loss 111 0 0 0 111
Base Case 149 40 25 763 977 Full 20
Years Load Loss 111 0 25 541 677

By reducing load, the Company’s position changes substantially over the IRP timeframe as
shown in the energy and capacity charts below. Capacity obligations were reduced on a
percentage basis equivalent to the 300 aMW load reduction.

Table E.5
Loads and Resources Energy Forecast (aMW)
Load Loss Scenario
2004-2008, 2013, 2018, 2023

2004 2005 2006 2007 2008 2013 2018 2023
Obligations
Retail Load 985 1,014 1,051 1,083 1,120 1,326 1,569 1,860
80% Conf. Interval 189 189 189 189 189 189 189 153
Total Obligations 1,174 1,203 1,240 1,272 1,309 1,515 1,758 2,013
Existing Resources
Hydro 550 545 530 530 529 477 471 458
Net Contracts 156 157 175 177 177 58 59 12
Base Thermal 223 230 223 223 230 230 230 230
Gas Dispatch 158 156 158 158 156 158 158 156
Gas Peaking Units 181 181 181 181 181 181 181 181
Total Existing Resources 1,268 1,269 1,267 1,269 1,273 1,104 1,099 1,037
PRS Resource Additions
Wind 0 0 0 0 0 (0) 25 25
Base Thermal 0 0 0 0 0 0 224 541
Gas Dispatch 0 0 0 0 0 111 111 111
Gas Peaking Units 0 0 0 0 0 0 0 0
Total PRS Resources 0 0 0 0 0 111 360 677
Net Position 394 366 327 297 264 0 1 1

Appendix E Page E-12 Detailed Results
Table E.6
Loads and Resources Capacity Forecast (MW)
Load Loss Scenario
2004-2008, 2013, 2018, 2023

2004 2005 2006 2007 2008 2013 2018 2023
Obligations
Retail Load 1,022 1,067 1,122 1,169 1,224 1,534 1,900 2,332
Operating Reserves 107 107 105 105 105 108 126 150
Total Obligations 1,129 1,174 1,226 1,274 1,329 1,642 2,026 2,482
Existing Resources
Hydro 1,177 1,177 1,135 1,134 1,133 1,043 1,035 998
Net Contracts 70 19 43 45 45 -73 78 -2
Base Thermal 272 272 272 272 272 272 272 272
Gas Dispatch 176 176 176 176 176 176 176 176
Gas Peaking Units 236 236 236 236 236 236 236 236
Total Existing Resources 1,931 1,880 1,862 1,863 1,862 1,654 1,797 1,680
PRS Resource Additions
Wind 0 0 0 0 0 0 0 0
Base Thermal 0 0 0 0 0 0 260 628
Gas Dispatch 0 0 0 0 0 117 117 117
Gas Peaking Units 0 0 0 0 0 0 0 0
Total PRS Resources 0 0 0 0 0 117 376 745
Net Position 802 706 636 589 533 129 148 -57
Reserve Margin 88.9% 76.2% 66.0% 59.4% 52.1% 15.5% 14.4% 4.0%

The loss of 300 aMW of retail load exposes the Company to a similar level of annual power
supply risk on a total cost basis. The comparison can be found in Chart E.9.

Appendix E Page E-13 Detailed Results
Chart E.9
Variation of Power Supply Expense From Expected Value Over 200 Iterations
2004-2023

Table E.7
Net Present Value of Strategies
Load Loss Scenario

PRS No Additions
Lowest
Cost/CCCT Lowest Risk All Coal Wind Strategy
Period Value Value Diff Value Diff Value Diff Value Diff Value Diff
2004-13 0.37 0.38 2.5% 0.37 0.0% 0.38 0.9% 0.40 6.7% 0.38 1.6%
2004-23 1.35 1.72 27.2% 1.28 -5.0% 1.36 0.3% 1.46 7.9% 1.33 -1.4%

Besides No Additions, only the All Coal strategy would be substantially more expensive between
2004 and 2013 than the PRS. Over twenty years the Lowest Cost/CCCT and Wind Strategy are
modestly better than the PRS.

New Transmission

A lack of coal development is often attributed to a lack of transmission. Coal plants included in
the various strategies all included an investment in transmission to approximate the development
of new lines to move energy from their remote locations. The New Transmission scenario
assumed four new 3,000 MW transmission lines were built as follows:
• Montana to the Northwest
• Wyoming to Southern Idaho
• Wyoming to Utah
• Utah to Southern California
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Appendix E Page E-14 Detailed Results
The following table details the capacity expansion build in AURORA with the additional transfer
capabilities.

Table E.8
Capacity Expansion Resource Summary (GW)
New Trans Scenario

Year CCCT Coal SCCT Wind Retire Net
2004 0.00 0.00 0.00 0.00 (0.51) (0.50)
2008 0.00 3.20 0.00 0.30 (7.52) (4.01)
2013 5.60 14.40 0.00 8.50 (27.06) 1.45
2018 40.98 16.00 0.09 11.30 (35.70) 32.68
2023 68.14 16.40 0.18 13.00 (35.80) 61.94
69.7% 16.8% 0.2% 13.3%

The significant difference in the study is that 14.4 GW of additional coal-fired generation plants
are constructed once the transmission lines are built to retire an additional 10 GW of less-
efficient gas- and oil-fired plants. The impact on market prices with the new capacity expansion
run was surprisingly modest; market prices in the Northwest were on average about 4.5 percent
lower.

Table E.9 compares the Preferred Resource Strategy to other considered strategies.

Table E.9
Net Present Value of Strategies
New Trans Scenario

PRS No Additions
Lowest
Cost/CCCT Lowest Risk All Coal
Wind
Strategy
Period Value Value Diff Value Diff Value Diff Value Diff Value Diff
2004-13 1.11 1.01 -9.1% 1.08 -2.8% 1.14 2.7% 1.14 2.4% 1.12 1.1%
2004-23 2.63 2.21 -15.9% 2.49 -5.6% 2.66 1.0% 2.72 3.2% 2.58 -1.9%

Where significant additional transmission capability is constructed out of Montana and
Wyoming to the Northwest, Southern Idaho, and Southern California, the Company’s Preferred
Resources Strategy out-performs the Lowest Risk and All Coal strategies modestly. The No
Additions strategy provides the greatest savings as spot market prices are held down in many
periods by lower-cost coal-fired plants.

Coal Build

In the Coal Build scenario, all of the CCCT plants constructed in the AURORA capacity
expansion run were replaced by coal plants. Northwest market prices were modestly lower when
coal plants were used in lieu of CCCTs. The following table presents the net present value of the
various strategies under the Coal Build scenario.

Appendix E Page E-15 Detailed Results
Table E.10
Net Present Value of Strategies
Coal Build Scenario

PRS No Additions
Lowest
Cost/CCCT Lowest Risk All Coal
Wind
Strategy
Period Value Value Diff Value Diff Value Diff Value Diff Value Diff
2004-13 1.11 1.02 -8.1% 1.08 -2.8% 1.13 2.5% 1.13 2.3% 1.12 1.3%
2004-23 2.62 2.29 -12.7% 2.48 -5.5% 2.63 0.4% 2.70 3.1% 2.59 -1.4%

Because coal plants have low variable costs, the price volatility under a coal-build scenario is
much lower than under the Base Case. Under such conditions, strategies based on building no
additional resources or focusing on investments with low capital costs (CCCTs) tend to
outperform the Preferred Resource Strategy.

Carbon Tax

CO2 taxes disadvantage carbon-emitting resources, such as CCCT and coal plants. For the IRP,
Northwest Power Planning Council (NWPPC) carbon tax assumptions were used, with prices
increasing from $1.32 in 2004 to about $11 in 2023. The Company applied these charges to all
CO2 emissions in the WECC. Coal plants, with their higher carbon emission levels per MWh,
are disadvantaged when compared to CCCT plants, which emit significant levels of carbon, but
about half of coal plants. This can best be seen by reviewing the differences between the Lowest
Cost/CCCT and the All Coal strategies in the following table.

Table E.11
Net Present Value of Strategies
Carbon Tax Scenario

PRS No Additions
Lowest
Cost/CCCT Lowest Risk All Coal
Wind
Strategy
Period Value Value Diff Value Diff Value Diff Value Diff Value Diff
2004-13 1.14 1.04 -8.2% 1.10 -3.3% 1.16 1.8% 1.17 3.2% 1.15 0.8%
2004-23 2.78 2.39 -14.2% 2.55 -8.5% 2.69 -3.3% 2.91 4.6% 2.67 -4.0%

The Lowest Cost/CCCT build, relying entirely on CCCT plants, is 3.3 percent lower in cost than
the PRS over the first ten years of the IRP timeframe. Over twenty years, the gap increases to
8.5 percent. This cost savings stems from the reliance of the PRS on coal plants. A comparison
of the Lowest Cost/CCCT strategy to the All Coal strategy further illustrates this difference, with
a spread of 6.5 percent during the first ten years and 13.1 percent over twenty years.

Appendix F Page F-1 Loads and Resources Tables
Appendix

Load and Resource Tables

This appendix contains the following tables and charts depicting loads and resources for energy
and capacity:

• Table F.1 – Annual Loads and Resources Energy Forecast – 2004-2023
• Tables F.2-F.21 – Monthly Loads and Resources Energy Forecast – 2004-2023
• Charts F.1-F.5 – Loads and Resources Monthly Energy Position – 2004, 2008, 2013,
2018, and 2023
• Table F.1 – Annual Loads and Resources Capacity Forecast – 2004-2023
• Tables F.2-F.21 – Monthly Loads and Resources Capacity Forecast – 2004-2023
• Chart F.6 – 2002 Hourly System Load Shapes by Quarter

Appendix F Page F-2 Loads and Resources Tables
Table F.1
Annual Loads & Resources Energy Forecast
2004-2023 (in aMW)
Last Updated 12/12/2002 Notes 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
REQUIREMENTS
System Load 1 (985) (1,014) (1,051) (1,083) (1,120) (1,165) (1,207) (1,248) (1,285) (1,326) (1,364) (1,414) (1,465) (1,517) (1,569) (1,620) (1,671)
Contracts Out 2 (7) (7) (6) (6) (6) (5) (4) (4) (3) (3) (3) (3) (3) (3) (2) (2) (2)
Total Requirements (992) (1,021) (1,057) (1,089) (1,126) (1,171) (1,211) (1,251) (1,288) (1,329) (1,367) (1,417) (1,468) (1,520) (1,572) (1,622) (1,672)
RESOURCES
Hydro 3 550 545 530 530 529 524 499 496 477 477 476 475 474 473 471 462 461
Contracts In 4 163 164 181 183 183 183 182 76 61 61 61 61 61 61 61 42 13
Base Load Thermals 5 223 230 223 223 230 230 230 230 230 230 230 230 230 230 230 230 230
Gas Dispatch Units 6 158 156 158 158 156 158 158 156 158 158 156 158 158 156 158 158 156
Total Resources 1,094 1,095 1,092 1,094 1,098 1,095 1,069 958 926 926 922 924 923 920 920 892 860
Surplus (Deficit) 102 74 35 5 (28) (75) (142) (294) (361) (403) (444) (493) (544) (600) (652) (730) (813)
CONTINGENCY PLANNING
Confidence Interval 7 (153) (153) (153) (153) (153) (153) (153) (153) (153) (153) (153) (153) (153) (153) (153) (153) (153)
WNP-3 Obligation 8 (36) (36) (36) (36) (36) (36) (36) (36) (36) (36) (36) (36) (36) (36) (36) (20) -
Peaking Units 9 181 181 181 181 181 181 181 181 181 181 181 181 181 181 181 181 181
Surplus (Deficit) net position 94 66 27 (3) (36) (83) (149) (302) (369) (411) (452) (501) (552) (608) (660) (722) (785)
Notes:
1. Load estimates are from the 2003 load forecast (08-27-2002) including the forecast for net Potlatch load.
2. Includes PacifiCorp Exchange Delivery, Nichols Pumping, and Canadian Entitlement Return contracts. Does not include WNP-3 Obligation.
3. Average (60-year) hydro generation for system hydro (Clark Fork and Spokane River projects) and contract hydro (mid-Columbia) based on NWPP 2000-01 Headwater Benefits Study.
Contract hydro numbers reflect the Priest Rapids and Wanapum contract extensions beginning in 2005.
4. Includes small power contracts, Upriver, Black Creek, market purchases of 100 MW flat for 2004-2010. PacifiCorp Exchange Return, and WNP-3 Receipt. BPA Residential Exchange is zero, assumes contract monetization.
5. Includes Colstrip and Kettle Falls.
6. Includes Coyote Springs, Boulder Park, and Kettle Falls CT.
7. The confidence interval represents the 12-month average of reserve energy necessary to ensure nomore than a 10 percent probability of loads exceeding, and/or hydro underperforming, during a given month.
8. Represents highest level of potential obligation to BPA generally exercised under low hydro conditions.
9. Includes Northeast and Rathdrum, numbers reflect "full availability" adjusted for forced outage and maintenance.
2021 2022 2023
(1,731) (1,793) (1,860)
(2) (1) (1)
(1,732) (1,795) (1,862)
460 459 458
13 13 13
230 230 230
158 158 156
862 861 857
(871) (934) (1,005)
(153) (153) (153)
- - -
181 181 181
(843) (906) (977)

Appendix F Page F-3 Loads and Resources Tables
Table F.2
Monthly Loads & Resources Energy Forecast – 2004 (in aMW)
December 12, 2002 Version
Year 2004 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 939 1,052 1,026 1,001 889 848 845 909 901 834 879 1,001 1,077
Potlatch Load 46 46 46 46 46 46 46 46 46 46 46 46 46
TOTAL LOADS 985 1,098 1,072 1,047 936 895 891 955 947 880 925 1,047 1,123
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Market Purchases 100 100 100 100 100 100 100 100 100 100 100 100 100
Pacificorp Exchange Return 2 12 13 0 0 0 0 0 0 0 0 0 0
PGE Capacity Return 48 48 47 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 12 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 112 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 211 291 287 223 222 165 164 157 166 149 158 275 274
CONTRACT OBLIGATIONS
Canadian Entitlement 6 6 6 6 6 6 6 6 6 6 6 6 6
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 47 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 55 56 55 56 55 58 55 54 58 51 58 55 52
NET CONTRACT POSITION 156 236 233 167 167 108 108 103 109 98 100 219 223
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 101 143 119 99 83 91 112 98 103 84 85 85 114
Sub-Total 550 518 529 482 599 853 906 593 460 306 329 454 570
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,195 1,175 1,184 1,133 1,245 1,495 1,543 1,224 1,091 945 975 1,107 1,227
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 42 31 31 31 31 120 72 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 84 61 61 64 63 263 131 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions 282 252 283 189 414 446 629 313 193 104 91 218 266
80% Confidence Interval 129 61 109 21 238 277 445 45 92 28 3 106 137
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position 94 13 61 (26) 191 277 397 45 92 (20) (45) 58 89

Appendix F Page F-4 Loads and Resources Tables
Table F.3
Monthly Loads & Resources Energy Forecast – 2005 (in aMW)
December 12, 2002 Version
Year 2005 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 969 1,088 1,059 1,033 919 875 872 936 929 863 906 1,030 1,115
Potlatch Load 46 46 46 46 46 46 46 46 46 46 46 46 46
TOTAL LOADS 1,014 1,134 1,105 1,079 965 921 918 982 975 909 952 1,076 1,161
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Grant Displacement 3 0 0 0 0 0 0 0 0 0 0 20 20
Market Purchases 100 100 100 100 100 100 100 100 100 100 100 100 100
PGE Capacity Return 48 48 49 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 212 280 281 223 222 165 164 157 166 149 158 295 295
CONTRACT OBLIGATIONS
Canadian Entitlement 6 6 6 6 6 6 6 6 6 6 6 4 4
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 49 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 55 56 56 56 55 58 55 54 58 51 58 53 50
NET CONTRACT POSITION 157 224 224 167 167 108 108 103 109 98 100 241 245
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 97 143 119 99 83 91 112 98 103 84 85 61 82
Sub-Total 545 518 529 482 599 853 906 593 460 306 329 429 539
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,191 1,175 1,184 1,133 1,245 1,495 1,543 1,224 1,091 945 975 1,082 1,195
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 14 7 102 7 7 7 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 8 1 1 1 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 79 61 163 64 63 156 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions 254 204 140 158 385 526 643 286 165 75 63 187 218
80% Confidence Interval 101 13 (35) (10) 209 357 460 18 63 (1) (25) 75 89
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position 66 (34) (82) (58) 162 357 412 18 63 (49) (72) 27 41

Appendix F Page F-5 Loads and Resources Tables
Table F.4
Monthly Loads & Resources Energy Forecast – 2006 (in aMW)
December 12, 2002 Version
Year 2006 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,006 1,132 1,100 1,072 955 908 905 969 964 898 940 1,065 1,162
Potlatch Load 46 46 46 46 46 46 46 46 46 46 46 46 46
TOTAL LOADS 1,051 1,178 1,146 1,118 1,000 954 951 1,015 1,010 944 986 1,111 1,207
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Grant Displacement 20 20 20 20 20 20 20 20 20 20 20 20 20
Market Purchases 100 100 100 100 100 100 100 100 100 100 100 100 100
PGE Capacity Return 48 48 49 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 229 300 301 243 243 186 184 177 187 170 178 295 295
CONTRACT OBLIGATIONS
Canadian Entitlement 5 5 5 5 5 5 5 5 5 5 5 5 5
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 49 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 54 54 55 54 54 56 54 52 56 49 56 54 50
NET CONTRACT POSITION 176 246 246 189 189 130 130 125 131 120 122 241 245
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 82 110 91 75 77 85 97 81 85 63 64 64 87
Sub-Total 530 485 501 458 593 847 892 575 442 286 308 433 543
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,175 1,143 1,156 1,109 1,239 1,488 1,529 1,206 1,073 925 954 1,086 1,200
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 42 31 31 31 31 126 66 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 84 61 61 64 63 269 125 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions 216 150 195 116 365 395 583 257 134 41 30 155 176
80% Confidence Interval 63 (41) 21 (51) 190 227 399 (11) 33 (35) (58) 43 47
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position 27 (89) (27) (99) 142 227 352 (11) 33 (83) (105) (4) (1)

Appendix F Page F-6 Loads and Resources Tables
Table F.5
Monthly Loads & Resources Energy Forecast – 2007 (in aMW)
December 12, 2002 Version
Year 2007 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,035 1,167 1,133 1,103 983 934 931 996 992 927 967 1,094 1,200
Potlatch Load 48 48 48 48 48 48 48 48 48 48 48 48 48
TOTAL LOADS 1,083 1,215 1,180 1,151 1,031 982 979 1,043 1,040 975 1,015 1,142 1,248
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Grant Displacement 22 22 22 22 22 22 22 22 22 22 22 22 22
Market Purchases 100 100 100 100 100 100 100 100 100 100 100 100 100
PGE Capacity Return 48 48 49 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 231 302 303 245 245 188 186 179 189 172 180 297 297
CONTRACT OBLIGATIONS
Canadian Entitlement 5 5 5 5 5 5 5 5 5 5 5 5 5
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 49 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 54 54 55 54 54 56 54 52 56 49 56 54 50
NET CONTRACT POSITION 178 248 248 191 191 132 132 127 133 122 124 243 247
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 81 109 90 75 77 85 97 80 84 63 64 64 86
Sub-Total 530 484 500 457 593 847 892 575 441 285 308 432 542
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,175 1,142 1,155 1,108 1,239 1,488 1,528 1,205 1,072 924 954 1,085 1,199
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 42 31 31 31 31 108 85 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 84 61 61 64 63 250 144 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions 186 113 162 85 336 387 537 230 106 12 3 126 137
80% Confidence Interval 33 (77) (13) (83) 161 219 354 (38) 4 (64) (85) 14 8
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (3)(125) (61) (131) 113 219 306 (38) 4 (112) (133) (33) (40)

Appendix F Page F-7 Loads and Resources Tables
Table F.6
Monthly Loads & Resources Energy Forecast – 2008 (in aMW)
December 12, 2002 Version
Year 2008 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,072 1,211 1,173 1,142 1,019 967 964 1,029 1,027 962 1,001 1,129 1,241
Potlatch Load 48 48 48 48 48 48 48 48 48 48 48 48 48
TOTAL LOADS 1,120 1,259 1,221 1,190 1,067 1,015 1,012 1,077 1,075 1,010 1,049 1,177 1,289
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Grant Displacement 22 22 22 22 22 22 22 22 22 22 22 22 22
Market Purchases 100 100 100 100 100 100 100 100 100 100 100 100 100
PGE Capacity Return 48 48 47 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 12 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 112 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 231 302 297 245 245 188 186 179 189 172 180 297 297
CONTRACT OBLIGATIONS
Canadian Entitlement 5 5 5 5 5 5 5 5 5 5 5 5 5
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 47 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 53 54 53 54 54 56 53 52 56 49 56 53 50
NET CONTRACT POSITION 177 248 244 191 191 132 132 127 133 122 124 243 247
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 80 108 89 74 76 84 97 79 84 62 63 63 85
Sub-Total 529 483 499 456 592 846 891 574 441 284 307 431 541
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,174 1,141 1,154 1,107 1,239 1,488 1,528 1,205 1,072 924 953 1,084 1,198
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 14 7 99 7 7 7 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 7 1 1 1 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 79 61 160 64 63 156 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions 153 69 17 45 300 449 558 196 71 (24) (32) 90 95
80% Confidence Interval (0) (122) (158) (123) 125 280 374 (72) (31) (100) (120) (22) (34)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (36)(170) (205) (171) 77 280 327 (72) (31) (148) (167) (69) (82)

Appendix F Page F-8 Loads and Resources Tables
Table F.7
Monthly Loads & Resources Energy Forecast – 2009 (in aMW)
December 12, 2002 Version
Year 2009 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,115 1,263 1,222 1,188 1,062 1,006 1,003 1,068 1,068 1,004 1,041 1,171 1,290
Potlatch Load 50 50 50 50 50 50 50 50 50 50 50 50 50
TOTAL LOADS 1,165 1,313 1,272 1,238 1,112 1,056 1,053 1,118 1,118 1,054 1,091 1,221 1,340
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Grant Displacement 22 22 22 22 22 22 22 22 22 22 22 22 22
Market Purchases 100 100 100 100 100 100 100 100 100 100 100 100 100
PGE Capacity Return 48 48 49 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 231 302 303 245 245 188 186 179 189 172 180 297 297
CONTRACT OBLIGATIONS
Canadian Entitlement 4 5 5 5 5 5 5 5 5 5 5 3 3
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 49 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 53 54 55 54 53 56 53 52 56 49 56 52 48
NET CONTRACT POSITION 178 248 248 191 191 132 132 127 133 122 124 245 248
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 75 107 88 73 76 84 96 79 83 61 62 39 53
Sub-Total 524 482 498 456 592 846 891 574 440 284 306 407 509
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,169 1,140 1,153 1,107 1,239 1,488 1,527 1,204 1,071 923 953 1,060 1,166
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions 105 13 69 (4) 256 347 516 154 27 (69) (74) 23 13
80% Confidence Interval (48) (177) (106) (172) 80 178 333 (114) (75) (145) (163) (88) (116)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (83)(225) (153) (220) 32 178 285 (114) (75) (193) (210) (136) (163)

Appendix F Page F-9 Loads and Resources Tables
Table F.8
Monthly Loads & Resources Energy Forecast – 2010 (in aMW)
December 12, 2002 Version
Year 2010 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,157 1,313 1,268 1,232 1,102 1,043 1,041 1,106 1,108 1,045 1,080 1,211 1,337
Potlatch Load 50 50 50 50 50 50 50 50 50 50 50 50 50
TOTAL LOADS 1,207 1,363 1,318 1,282 1,152 1,093 1,091 1,156 1,158 1,094 1,129 1,261 1,387
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Grant Displacement 21 21 21 21 21 21 21 21 21 21 21 21 21
Market Purchases 100 100 100 100 100 100 100 100 100 100 100 100 100
PGE Capacity Return 48 48 49 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 230 300 301 243 243 186 184 177 187 170 179 295 295
CONTRACT OBLIGATIONS
Canadian Entitlement 3 3 3 3 3 3 3 3 3 3 3 3 3
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 49 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 52 52 53 52 52 54 52 50 54 48 54 52 48
NET CONTRACT POSITION 178 248 248 191 191 131 132 127 132 122 124 243 247
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 51 71 57 46 47 52 63 51 54 38 39 39 53
Sub-Total 499 445 467 429 564 814 857 546 411 261 283 407 509
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,145 1,103 1,122 1,080 1,210 1,455 1,494 1,176 1,043 900 929 1,060 1,166
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions 39 (73) (9) (76) 186 277 445 88 (42) (132) (136) (18) (35)
80% Confidence Interval (114) (264) (184) (243) 10 108 262 (179) (144) (209) (224) (130) (164)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (149)(312) (231) (291) (37) 108 214 (179) (144) (257) (272) (178) (212)

Appendix F Page F-10 Loads and Resources Tables
Table F.9
Monthly Loads & Resources Energy Forecast – 2011 (in aMW)
December 12, 2002 Version
Year 2011 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,196 1,360 1,311 1,274 1,141 1,078 1,076 1,141 1,145 1,082 1,116 1,248 1,381
Potlatch Load 52 52 52 52 52 52 52 52 52 52 52 52 52
TOTAL LOADS 1,248 1,411 1,363 1,326 1,193 1,130 1,128 1,193 1,197 1,134 1,167 1,300 1,433
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Grant Displacement 15 21 21 21 21 21 21 21 21 21 0 0 0
PGE Capacity Return 48 48 49 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 124 200 201 143 143 86 84 77 87 70 58 175 174
CONTRACT OBLIGATIONS
Canadian Entitlement 3 3 3 3 3 3 3 3 3 3 3 2 2
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 49 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 52 52 53 52 52 54 52 50 54 48 54 51 47
NET CONTRACT POSITION 73 148 148 91 91 32 32 27 33 22 4 124 127
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 47 70 56 45 47 51 62 50 54 37 38 23 33
Sub-Total 496 444 466 428 563 813 856 545 411 260 282 392 489
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,141 1,102 1,121 1,079 1,209 1,455 1,493 1,175 1,042 899 929 1,045 1,146
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 14 7 102 7 7 7 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 8 1 1 1 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 79 61 163 64 63 156 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (113) (223) (257) (220) 45 200 308 (49) (181) (273) (296) (193) (221)
80% Confidence Interval (266) (414) (432) (387) (130) 32 124 (317) (283) (349) (384) (304) (350)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (302)(461) (480) (435) (178) 32 76 (317) (283) (397) (431) (352) (397)

Appendix F Page F-11 Loads and Resources Tables
Table F.10
Monthly Loads & Resources Energy Forecast – 2012 (in aMW)
December 12, 2002 Version
Year 2012 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,233 1,404 1,352 1,313 1,177 1,111 1,109 1,174 1,180 1,118 1,150 1,284 1,422
Potlatch Load 52 52 52 52 52 52 52 52 52 52 52 52 52
TOTAL LOADS 1,285 1,456 1,404 1,365 1,229 1,163 1,161 1,226 1,232 1,170 1,201 1,336 1,474
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
PGE Capacity Return 48 48 47 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 12 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 112 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 109 180 175 123 122 65 64 57 66 49 58 175 174
CONTRACT OBLIGATIONS
Canadian Entitlement 2 2 2 2 2 2 2 2 2 2 2 2 2
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 47 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 51 51 50 51 51 53 51 49 53 47 53 51 47
NET CONTRACT POSITION 58 128 124 71 72 12 13 8 13 3 5 124 127
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 29 42 34 27 24 28 34 28 30 22 23 23 32
Sub-Total 477 416 444 410 540 790 828 523 387 245 267 391 488
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,123 1,074 1,099 1,061 1,187 1,431 1,465 1,153 1,018 884 913 1,044 1,145
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (180) (315) (242) (296) (33) 64 227 (124) (260) (343) (344) (229) (263)
80% Confidence Interval (333) (505) (417) (464) (208) (105) 43 (392) (362) (420) (432) (340) (392)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (369)(553) (464) (512) (256) (105) (4) (392) (362) (467) (480) (388) (440)

Appendix F Page F-12 Loads and Resources Tables
Table F.11
Monthly Loads & Resources Energy Forecast – 2013 (in aMW)
December 12, 2002 Version
Year 2013 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,272 1,451 1,396 1,356 1,216 1,147 1,145 1,210 1,218 1,157 1,186 1,322 1,467
Potlatch Load 54 54 54 54 54 54 54 54 54 54 54 54 54
TOTAL LOADS 1,326 1,505 1,450 1,409 1,270 1,201 1,199 1,264 1,272 1,211 1,240 1,376 1,521
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
PGE Capacity Return 48 48 49 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 109 180 181 123 122 65 64 57 66 49 58 175 174
CONTRACT OBLIGATIONS
Canadian Entitlement 2 2 2 2 2 2 2 2 2 2 2 2 2
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 49 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 51 51 52 51 51 53 51 49 53 47 53 51 47
NET CONTRACT POSITION 58 128 129 71 72 12 13 8 13 3 5 124 127
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 28 40 33 26 24 27 33 28 29 21 22 22 31
Sub-Total 477 415 443 409 540 789 828 522 386 244 266 390 487
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,122 1,073 1,098 1,060 1,186 1,431 1,464 1,153 1,017 883 912 1,043 1,144
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (222) (365) (285) (342) (74) 25 188 (163) (300) (384) (383) (270) (311)
80% Confidence Interval (375) (556) (459) (509) (250) (143) 5 (431) (402) (461) (471) (381) (440)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (411)(604) (507) (557) (298) (143) (43) (431) (402) (509) (519) (429) (487)

Appendix F Page F-13 Loads and Resources Tables
Table F.12
Monthly Loads & Resources Energy Forecast – 2014 (in aMW)
December 12, 2002 Version
Year 2014 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,310 1,496 1,438 1,396 1,253 1,181 1,179 1,244 1,254 1,193 1,221 1,359 1,509
Potlatch Load 54 54 54 54 54 54 54 54 54 54 54 54 54
TOTAL LOADS 1,364 1,550 1,492 1,450 1,307 1,235 1,232 1,298 1,307 1,247 1,275 1,412 1,563
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
PGE Capacity Return 48 48 49 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 109 180 181 123 122 65 64 57 66 49 58 175 174
CONTRACT OBLIGATIONS
Canadian Entitlement 2 2 2 2 2 2 2 2 2 2 2 2 2
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 49 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 51 51 52 51 51 53 51 49 53 47 53 51 47
NET CONTRACT POSITION 58 128 129 71 72 12 13 8 13 3 5 124 127
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 27 39 32 25 23 26 32 27 28 21 21 21 30
Sub-Total 476 414 442 408 539 788 827 521 385 243 265 390 486
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,121 1,072 1,097 1,059 1,186 1,430 1,463 1,152 1,017 882 912 1,043 1,143
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 14 7 102 7 7 7 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 8 1 1 1 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 79 61 163 64 63 156 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (263) (412) (430) (383) (112) 52 154 (198) (337) (421) (419) (307) (354)
80% Confidence Interval (416) (602) (604) (550) (287) (117) (30) (466) (439) (498) (507) (418) (483)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (452)(650) (652) (598) (335) (117) (77) (466) (439) (546) (555) (466) (531)

Appendix F Page F-14 Loads and Resources Tables
Table F.13
Monthly Loads & Resources Energy Forecast – 2015 (in aMW)
December 12, 2002 Version
Year 2015 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,358 1,555 1,492 1,447 1,300 1,225 1,222 1,288 1,300 1,240 1,266 1,405 1,564
Potlatch Load 56 56 56 56 56 56 56 56 56 56 56 56 56
TOTAL LOADS 1,414 1,611 1,548 1,503 1,356 1,280 1,278 1,344 1,356 1,296 1,322 1,461 1,620
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
PGE Capacity Return 48 48 49 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 109 180 181 123 122 65 64 57 66 49 58 175 174
CONTRACT OBLIGATIONS
Canadian Entitlement 2 2 2 2 2 2 2 2 2 2 2 2 2
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 49 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 51 51 52 51 51 53 51 49 53 46 53 51 47
NET CONTRACT POSITION 58 128 129 72 72 12 13 8 13 3 5 124 127
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 26 38 31 25 23 26 31 26 27 20 20 20 29
Sub-Total 475 413 441 407 539 788 826 521 384 243 265 389 485
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,120 1,070 1,096 1,058 1,185 1,429 1,462 1,151 1,016 882 911 1,042 1,142
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (312) (473) (385) (437) (162) (55) 107 (244) (386) (471) (466) (356) (412)
80% Confidence Interval (465) (664) (559) (605) (337) (224) (76) (512) (488) (548) (554) (468) (541)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (501)(711) (607) (652) (385) (224) (124) (512) (488) (596) (602) (516) (588)

Appendix F Page F-15 Loads and Resources Tables
Table F.14
Monthly Loads & Resources Energy Forecast – 2016 (in aMW)
December 12, 2002 Version
Year 2016 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,409 1,615 1,548 1,501 1,350 1,270 1,268 1,334 1,348 1,289 1,313 1,454 1,621
Potlatch Load 56 56 56 56 56 56 56 56 56 56 56 56 56
TOTAL LOADS 1,465 1,671 1,604 1,557 1,405 1,326 1,323 1,390 1,404 1,345 1,368 1,510 1,677
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
PGE Capacity Return 48 48 47 48 48 50 48 46 50 44 50 48 44
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 12 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 112 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 109 180 175 123 122 65 64 57 66 49 58 175 174
CONTRACT OBLIGATIONS
Canadian Entitlement 2 2 2 2 2 2 2 2 2 2 2 2 2
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
PGE Capacity 48 48 47 48 48 50 48 46 50 44 50 48 44
TOTAL CONTRACT OBLIGATIONS 51 51 50 51 51 53 51 49 53 46 53 51 47
NET CONTRACT POSITION 58 128 124 72 72 12 13 8 13 3 5 124 127
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 26 37 30 24 22 25 31 25 27 19 20 20 28
Sub-Total 474 411 440 406 538 787 825 520 384 242 264 388 484
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,119 1,069 1,095 1,057 1,185 1,429 1,462 1,150 1,015 881 910 1,041 1,141
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (364) (534) (446) (491) (212) (101) 61 (291) (434) (521) (514) (405) (469)
80% Confidence Interval (517) (725) (621) (659) (387) (270) (122) (559) (536) (597) (602) (517) (598)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (552)(773) (668) (707) (435) (270) (170) (559) (536) (645) (649) (565) (646)

Appendix F Page F-16 Loads and Resources Tables
Table F.15
Monthly Loads & Resources Energy Forecast – 2017 (in aMW)
December 12, 2002 Version
Year 2017 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,459 1,676 1,605 1,555 1,399 1,315 1,313 1,380 1,396 1,338 1,359 1,503 1,678
Potlatch Load 58 58 58 58 58 58 58 58 58 58 58 58 58
TOTAL LOADS 1,517 1,734 1,663 1,613 1,457 1,373 1,371 1,438 1,454 1,396 1,417 1,561 1,736
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 61 131 132 74 75 15 16 10 16 6 8 127 130
CONTRACT OBLIGATIONS
Canadian Entitlement 2 2 2 2 2 2 2 2 2 2 2 2 2
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
TOTAL CONTRACT OBLIGATIONS 3 3 3 3 3 3 3 3 3 3 3 3 3
NET CONTRACT POSITION 58 129 129 72 72 12 13 8 13 3 5 124 127
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 25 36 29 23 22 25 30 24 26 18 19 19 27
Sub-Total 473 410 439 405 538 787 824 519 383 241 263 387 483
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,119 1,068 1,094 1,056 1,184 1,428 1,461 1,150 1,014 880 909 1,040 1,140
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 14 7 102 7 7 7 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 8 1 1 1 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 79 61 163 64 63 156 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (419) (598) (603) (548) (264) (88) 13 (339) (485) (573) (563) (457) (530)
80% Confidence Interval (572) (789) (778) (716) (440) (257) (171) (607) (587) (649) (651) (569) (659)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (608)(837) (826) (764) (487) (257) (218) (607) (587) (697) (699) (617) (706)

Appendix F Page F-17 Loads and Resources Tables
Table F.16
Monthly Loads & Resources Energy Forecast – 2018 (in aMW)
December 12, 2002 Version
Year 2018 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,512 1,738 1,663 1,611 1,450 1,362 1,360 1,427 1,446 1,389 1,408 1,553 1,737
Potlatch Load 58 58 58 58 58 58 58 58 58 58 58 58 58
TOTAL LOADS 1,569 1,796 1,721 1,669 1,508 1,420 1,418 1,485 1,503 1,447 1,466 1,611 1,795
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 48 116 116 57 57 0 0 0 0 0 0 116 116
TOTAL CONTRACT RIGHTS 61 131 132 74 75 15 16 10 16 6 8 127 130
CONTRACT OBLIGATIONS
Canadian Entitlement 1 2 2 2 2 2 2 2 2 2 1 1 1
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
TOTAL CONTRACT OBLIGATIONS 2 3 3 3 3 3 3 3 3 3 2 2 2
NET CONTRACT POSITION 59 129 129 72 72 12 13 8 13 3 6 125 128
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 22 34 28 22 21 24 29 24 25 18 13 13 17
Sub-Total 471 409 438 405 537 786 824 518 382 240 257 381 473
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,116 1,067 1,093 1,056 1,183 1,427 1,460 1,149 1,013 879 903 1,034 1,130
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (471) (662) (560) (605) (316) (196) (35) (387) (536) (624) (617) (512) (598)
80% Confidence Interval (624) (853) (735) (772) (491) (365) (218) (655) (638) (701) (705) (624) (727)
WNP-3 Obligation 36 48 48 48 48 0 48 0 0 48 48 48 48
WNP-3 Adjusted 80% CI Position (660)(900) (782) (820) (539) (365) (266) (655) (638) (748) (752) (672) (774)

Appendix F Page F-18 Loads and Resources Tables
Table F.17
Monthly Loads & Resources Energy Forecast – 2019 (in aMW)
December 12, 2002 Version
Year 2019 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,560 1,797 1,717 1,663 1,498 1,406 1,404 1,471 1,492 1,436 1,453 1,600 1,792
Potlatch Load 60 60 60 60 60 60 60 60 60 60 60 60 60
TOTAL LOADS 1,620 1,857 1,777 1,722 1,558 1,466 1,464 1,531 1,552 1,496 1,513 1,660 1,852
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
WNP-3 28 116 116 57 57 0 0 0 0 0 0 0 0
TOTAL CONTRACT RIGHTS 42 131 132 74 75 15 16 10 16 6 8 11 14
CONTRACT OBLIGATIONS
Canadian Entitlement 1 1 1 1 1 1 1 1 1 1 1 1 1
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
TOTAL CONTRACT OBLIGATIONS 2 2 2 2 2 2 2 2 2 2 2 2 2
NET CONTRACT POSITION 40 130 130 73 73 13 14 9 14 4 6 9 13
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 13 19 16 14 9 10 13 12 13 12 12 12 16
Sub-Total 462 393 426 396 525 772 807 507 370 234 256 381 472
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,107 1,051 1,081 1,047 1,172 1,414 1,444 1,137 1,001 874 902 1,034 1,129
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (549) (737) (627) (666) (376) (255) (96) (444) (596) (678) (664) (678) (771)
80% Confidence Interval (702) (928) (801) (834) (552) (424) (280) (712) (697) (755) (752) (790) (900)
WNP-3 Obligation 20 48 48 48 48 0 48 0 0 0 0 0 0
WNP-3 Adjusted 80% CI Position (722)(976) (849) (881) (600) (424) (327) (712) (697) (755) (752) (790) (900)

Appendix F Page F-19 Loads and Resources Tables
Table F.18
Monthly Loads & Resources Energy Forecast – 2020 (in aMW)
December 12, 2002 Version
Year 2020 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,611 1,857 1,773 1,716 1,547 1,451 1,449 1,517 1,540 1,485 1,499 1,649 1,848
Potlatch Load 60 60 60 60 60 60 60 60 60 60 60 60 60
TOTAL LOADS 1,671 1,917 1,833 1,776 1,607 1,511 1,509 1,577 1,600 1,545 1,559 1,708 1,908
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 12 13 12 11 12 6 3 4 6 8 11
TOTAL CONTRACT RIGHTS 13 15 15 17 17 15 16 10 16 6 8 11 14
CONTRACT OBLIGATIONS
Canadian Entitlement 1 1 1 1 1 1 1 1 1 1 1 1 1
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
TOTAL CONTRACT OBLIGATIONS 2 2 2 2 2 2 2 2 2 2 2 2 2
NET CONTRACT POSITION 12 14 14 16 16 13 14 9 14 4 6 9 13
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 12 18 15 13 9 10 12 12 12 11 11 11 15
Sub-Total 461 392 425 396 525 772 807 506 369 234 255 380 471
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,106 1,050 1,080 1,047 1,171 1,413 1,443 1,137 1,000 873 902 1,033 1,128
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 14 7 99 7 7 7 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 7 1 1 1 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 79 61 160 64 63 156 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (632) (914) (899) (777) (483) (240) (142) (490) (644) (728) (712) (727) (829)
80% Confidence Interval (785) (1,105) (1,073) (945) (659) (408) (326) (758) (746) (804) (800) (839) (958)

Appendix F Page F-20 Loads and Resources Tables
Table F.19
Monthly Loads & Resources Energy Forecast – 2021 (in aMW)
December 12, 2002 Version
Year 2021 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,669 1,927 1,838 1,778 1,605 1,503 1,502 1,570 1,595 1,542 1,553 1,705 1,914
Potlatch Load 62 62 62 62 62 62 62 62 62 62 62 62 62
TOTAL LOADS 1,731 1,989 1,900 1,840 1,667 1,565 1,564 1,632 1,657 1,603 1,615 1,767 1,976
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
TOTAL CONTRACT RIGHTS 13 15 16 17 17 15 16 10 16 6 8 11 14
CONTRACT OBLIGATIONS
Canadian Entitlement 1 1 1 1 1 1 1 1 1 1 1 1 1
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
TOTAL CONTRACT OBLIGATIONS 2 2 2 2 2 2 2 2 2 2 2 2 2
NET CONTRACT POSITION 12 14 14 16 16 13 14 9 14 4 6 9 13
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 11 16 14 12 8 9 11 11 11 10 10 10 14
Sub-Total 460 391 424 395 524 771 806 505 368 233 255 379 470
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,105 1,049 1,079 1,046 1,170 1,413 1,442 1,136 999 872 901 1,032 1,127
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (690) (988) (868) (843) (543) (356) (197) (546) (703) (787) (768) (786) (898)
80% Confidence Interval (843) (1,178) (1,042) (1,010) (719) (524) (381) (814) (804) (864) (856) (898) (1,027)

Appendix F Page F-21 Loads and Resources Tables
Table F.20
Monthly Loads & Resources Energy Forecast – 2022 (in aMW)
December 12, 2002 Version
Year 2022 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,732 2,002 1,908 1,845 1,666 1,560 1,558 1,627 1,655 1,602 1,611 1,765 1,985
Potlatch Load 62 62 62 62 62 62 62 62 62 62 62 62 62
TOTAL LOADS 1,793 2,064 1,970 1,907 1,728 1,621 1,620 1,688 1,717 1,664 1,673 1,827 2,047
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
TOTAL CONTRACT RIGHTS 13 15 16 17 17 15 16 10 16 6 8 11 14
CONTRACT OBLIGATIONS
Canadian Entitlement 0 0 0 0 0 0 0 0 0 0 0 0 0
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
TOTAL CONTRACT OBLIGATIONS 1 1 1 1 1 1 1 1 1 1 1 1 1
NET CONTRACT POSITION 12 14 14 16 16 13 14 9 14 4 6 9 13
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 10 15 13 11 7 8 10 10 10 9 10 10 13
Sub-Total 459 390 423 394 523 770 805 505 367 232 254 378 469
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,104 1,047 1,078 1,045 1,170 1,412 1,441 1,135 998 871 900 1,031 1,125
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 11 7 7 7 7 63 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 0 1 1 5 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 76 61 61 64 63 216 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (753) (1,064) (938) (910) (605) (413) (255) (603) (763) (849) (827) (847) (969)
80% Confidence Interval (906) (1,255) (1,113) (1,078) (781) (581) (438) (871) (865) (925) (915) (959) (1,098)

Appendix F Page F-22 Loads and Resources Tables
Table F.21
Monthly Loads & Resources Energy Forecast – 2023 (in aMW)
December 12, 2002 Version
Year 2023 Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Average Load 1,796 2,080 1,980 1,914 1,730 1,618 1,617 1,685 1,717 1,665 1,671 1,828 2,058
Potlatch Load 64 64 64 64 64 64 64 64 64 64 64 64 64
TOTAL LOADS 1,860 2,144 2,044 1,978 1,794 1,682 1,681 1,749 1,781 1,729 1,735 1,892 2,122
CONTRACT RIGHTS
Black Creek Hydro 1 0 0 0 0 0 0 0 11 0 0 0 0
Small Power 3 3 3 4 5 4 4 4 2 2 2 3 3
Upriver 9 12 13 13 12 11 12 6 3 4 6 8 11
TOTAL CONTRACT RIGHTS 13 15 16 17 17 15 16 10 16 6 8 11 14
CONTRACT OBLIGATIONS
Canadian Entitlement 0 0 0 0 0 0 0 0 0 0 0 0 0
Nichols Pumping net of PGE 1 1 1 1 1 1 1 1 1 1 1 1 1
TOTAL CONTRACT OBLIGATIONS 1 1 1 1 1 1 1 1 1 1 1 1 1
NET CONTRACT POSITION 12 14 14 16 16 14 14 9 15 4 6 9 13
HYDRO RESOURCES (Average Water)
Spokane River 123 128 149 156 159 159 150 101 60 76 94 107 143
Clark Fork 325 247 261 227 357 603 644 394 297 147 150 262 313
Mid-Columbia 10 14 12 10 7 8 9 9 9 9 9 9 12
Sub-Total 458 388 422 393 523 770 804 504 366 231 253 377 468
THERMAL RESOURCES (Full Capability)
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25 25
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222 222
Coyote Springs 2 132 134 134 133 133 131 129 127 127 131 133 134 134
Coyote Springs 2 duct burner 10 10 10 10 10 10 10 10 10 10 10 10 10
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7 7
Northeast 53 56 56 55 53 52 51 50 50 52 53 55 56
Rathdrum 150 157 156 153 150 147 145 142 143 146 150 154 156
Sub-Total 645 658 655 651 646 642 637 631 631 639 646 653 657
TOTAL RESOURCES 1,104 1,046 1,077 1,044 1,169 1,411 1,440 1,134 997 870 899 1,030 1,124
MAINTENANCE AND FORCED OUTAGE
Boulder Park 2 1 1 4 4 1 1 1 1 1 1 1 1
Colstrip 34 31 31 31 31 74 31 31 31 31 31 31 31
Coyote Springs 2 14 7 102 7 7 7 6 6 6 7 7 7 7
Coyote Springs 2 duct burner 1 0 8 1 1 1 1 1 1 1 1 1 0
Kettle Falls 5 3 3 3 3 23 3 3 3 3 3 3 3
Kettle Falls CT 1 1 1 1 1 3 1 1 1 1 1 1 1
Northeast 3 3 3 3 3 3 3 3 3 3 3 3 3
Rathdrum 20 16 16 15 15 45 45 14 14 15 15 15 16
TOTAL MAINT AND FORCED OUTAGE 79 61 163 64 63 156 90 59 59 60 60 61 61
NET POSITION Annual Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Conditions (824) (1,145) (1,116) (982) (671) (413) (316) (665) (828) (914) (890) (913) (1,046)
80% Confidence Interval (977) (1,336) (1,290) (1,150) (847) (581) (499) (933) (929) (991) (978) (1,025) (1,175)

Appendix F Page F-23 Loads and Resources Tables
Chart F.1
2004 Loads and Resources
Monthly Energy Position

0
500
1,000
1,500
2,000
2,500
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Hydro Net Contracts Base Thermal
Gas Dispatch Gas Peaking Units 80% Confidence Interval
Average Load

Appendix F Page F-24 Loads and Resources Tables
Chart F.2
2008 Loads and Resources
Monthly Energy Position
0
500
1,000
1,500
2,000
2,500
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Hydro Net Contracts Base Thermal
Gas Dispatch Gas Peaking Units 80% Confidence Interval
Average Load

Appendix F Page F-25 Loads and Resources Tables
Chart F.3
2013 Loads and Resources
Monthly Energy Position
0
500
1,000
1,500
2,000
2,500
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Hydro Net Contracts Base Thermal
Gas Dispatch Gas Peaking Units 80% Confidence Interval
Average Load

Appendix F Page F-26 Loads and Resources Tables
Chart F.4
2018 Loads and Resources
Monthly Energy Position
0
500
1,000
1,500
2,000
2,500
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Hydro Net Contracts Base Thermal
Gas Dispatch Gas Peaking Units 80% Confidence Interval
Average Load

Appendix F Page F-27 Loads and Resources Tables
Chart F.5
2023 Loads and Resources
Monthly Energy Position
0
500
1,000
1,500
2,000
2,500
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Hydro Net Contracts Base Thermal
Gas Dispatch Gas Peaking Units 80% Confidence Interval
Average Load

Appendix F Page F-28 Loads and Resources Tables
Table F.22
Annual Loads & Resources Capacity Forecast
2004-2023 (in MW)

Last Updated 12-12-2002 Notes 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
REQUIREMENTS
System Load 1 (1,470) (1,515) (1,570) (1,617) (1,672) (1,740) (1,803) (1,864) (1,920) (1,982) (2,039)
Contracts Out 2 (162) (163) (139) (59) (134) (112) (61) (136) (155) (155) (155)
Operating Reserves 3 (110) (110) (108) (108) (108) (108) (106) (106) (104) (104) (104)
Total Requirements (1,742) (1,788) (1,817) (1,784) (1,914) (1,960) (1,970) (2,106) (2,179) (2,241) (2,298)
RESOURCES
Hydro 4 1,177 1,177 1,135 1,134 1,133 1,131 1,084 1,083 1,044 1,043 1,041
Contracts In 5 232 182 182 104 179 157 107 82 82 82 82
Base Load Thermals 6 272 272 272 272 272 272 272 272 272 272 272
Gas Dispatch Units 7 412 412 412 412 412 412 412 412 412 412 412
Total Resources 2,093 2,043 2,001 1,922 1,996 1,972 1,875 1,849 1,810 1,809 1,807
Surplus (Deficit) 351 255 184 138 82 12 (95) (257) (369) (432) (491)
Notes:1. Loa est mates are rom t e oa orecast -7- ncu ng t e orecast or net Potatc oa . . Inc u es Pac orp Exc ange De very, N c o s Pump ng, an ana an Ent t ement Return contracts. Does not nc u e WNP- gaton.. 5 o y ro an 7 o t erma resources, per Nort west Power Poo reserve s ar ng agreement.4. Tota capac ty or system y ro C ar For an Spo ane R ver pro ects an contract y ro m -Co um a, Upr ver an ot er sma y ro . Contract y ro nu contract extensons eg nnng n 5.5. Inc u es non-y ro sma power contracts, B ac ree , mar et purc ases o MW at or -, Pac orp Exc ange Return, an WNP- Recept. BP. Inc u es o str p an Kett e Fa s.7. Inc u es Coyote Spr ngs, Bou er Par , an Kette Fa s CT.
2015 2016 2017 2018 2019 2020 2021 2022 2023
(2,115) (2,191) (2,270) (2,349) (2,425) (2,501) (2,592) (2,687) (2,780)
(154) (154) (4) (4) (2) (2) (2) (2) (2)
(104) (103) (103) (103) (102) (102) (102) (102) (101)
(2,373) (2,448) (2,377) (2,456) (2,529) (2,605) (2,696) (2,791) (2,883)
1,040 1,038 1,037 1,035 1,005 1,003 1,002 1,000 998
82 82 82 82 82 - - - -
272 272 272 272 272 272 272 272 272
412 412 412 412 412 412 412 412 412
1,806 1,804 1,803 1,801 1,771 1,687 1,686 1,684 1,682
(567) (644) (574) (655) (758) (918) (1,010) (1,107) (1,201)
mbers re ect t e Prest Rap s an Wanapum
Res ent a Exc ange s zero, assumes contract monet zaton.

Appendix F Page F-29 Loads and Resources Tables
Table F.23
Monthly Loads & Resources Capacity Forecast – 2004 (in MW)

Year 2004 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS
Peak Load 1424 1390 1359 1218 1166 1229 1398 1329 1147 1204 1359 1455
Potlatch 46 46 46 46 46 46 46 46 46 46 46 46
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 11 11 11 11 12 11 11 11 11 11 11 11
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
PacifiCorp Exchange -50 -50 0 0 0 0 0 0 0 0 0 0
Market Purchases -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 1400 1366 1426 1285 1275 1337 1506 1427 1255 1312 1385 1481
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 196 196 196 196 196 196 196 196 196 196 196 196
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1177 1176 1169 1175 1168 1183 1188 1181 1175 1176 1181 1182
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
SIP 0 0 0 0 0 0 0 0 0 0 0 0
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1861 1852 1837 1835 1821 1818 1816 1806 1812 1837 1853 1863
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -24 -39 -31 -3 0
Clark Fork River 0 -116 -160 0 0 0 0 0 -58 -188 -188 -58
Mid-Columbia 0 0 0 -55 -55 -55 0 0 0 0 0 0
Rathdrum 0 0 -84 -82 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 -111 0 0 0 0 0 0
0 -116 -244 -137 -380 -216 0 -24 -97 -219 -191 -58
Hydro Reserves 5% (Includes Box Canyon Gen) 62 62 62 62 62 63 63 61 60 61 62 63
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 41 41 23 33 44 44 45 47 47 48
110 110 103 103 85 96 107 105 105 107 110 110
Jan-04 Feb-04 Mar-04 Apr-04 May-04 Jun-04 Jul-04 Aug-04 Sep-04 Oct-04 Nov-04 Dec-04
CAPACITY SURPLUS (DEFICIT) 351 260 64 310 81 169 203 250 355 199 167 214
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young
Total Reserves
HYDRO RESOURCES
CAPACITY CONTRACTS
Total Maintenance

Appendix F Page F-30 Loads and Resources Tables
Table F.24
Monthly Loads & Resources Capacity Forecast – 2005 (in MW)

Year 2005 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1469 1432 1399 1255 1200 1263 1433 1365 1184 1239 1395 1503
Potlatch 46 46 46 46 46 46 46 46 46 46 46 46
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 12 11 11 11 12 11 12 11 11 11 8 8
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 -20 -20
Market Purchases -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 1496 1458 1466 1322 1309 1371 1542 1463 1292 1347 1398 1506
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 196 196 196 196 196 196 196 196 196 196 154 154
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1177 1176 1169 1175 1168 1183 1188 1181 1175 1176 1139 1140
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1861 1852 1837 1835 1821 1818 1816 1806 1812 1837 1811 1821
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -31 -3 0
Clark Fork River 0 -116 -160 0 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -55 -55 -55 0 0 0 0 0 0
Rathdrum 0 0 -84 -82 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 0 0 0 0 0 0 0 0
0 -116 -244 -137 -269 -105 0 -15 -154 -133 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 62 56 54 59 59 60 63 62 54 56 55 55
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 41 41 31 41 44 44 45 47 47 48
110 104 95 100 90 101 107 106 99 102 102 103
Jan-05 Feb-05 Mar-05 Apr-05 May-05 Jun-05 Jul-05 Aug-05 Sep-05 Oct-05 Nov-05 Dec-05
CAPACITY SURPLUS (DEFICIT) 255 174 32 276 153 241 167 222 267 255 206 110
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young
Total Reserves
HYDRO RESOURCES
CAPACITY CONTRACTS
Total Maintenance

Appendix F Page F-31 Loads and Resources Tables
Table F.25
Monthly Loads & Resources Capacity Forecast – 2006 (in MW)

Year 2006 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1524 1484 1448 1300 1241 1304 1474 1409 1229 1282 1440 1562
Potlatch 46 46 46 46 46 46 46 46 46 46 46 46
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 8 8 8 8 8 8 8 8 8 8 8 8
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen -20 -20 -20 -20 -20 -20 -20 -20 -20 -20 -20 -20
Market Purchases -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 1527 1487 1492 1344 1326 1389 1559 1484 1314 1367 1443 1565
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 154 154 154 154 154 154 154 154 154 154 154 154
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1135 1134 1127 1133 1126 1141 1146 1139 1133 1134 1139 1140
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1819 1810 1795 1793 1779 1776 1774 1764 1770 1795 1811 1821
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -43 -43 -43 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 -111 0 0 0 0 0 0
0 -166 -166 -145 -368 -204 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 60 52 51 53 58 58 61 60 52 52 55 55
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 33 44 44 45 47 47 48
108 99 98 99 81 92 105 104 97 99 102 103
Jan-06 Feb-06 Mar-06 Apr-06 May-06 Jun-06 Jul-06 Aug-06 Sep-06 Oct-06 Nov-06 Dec-06
CAPACITY SURPLUS (DEFICIT) 184 58 39 205 4 91 110 161 205 174 161 51
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No.11 January 10, 2003 Doug Young
Total Reserves
HYDRO RESOURCES
CAPACITY CONTRACTS
Total Maintenance

Appendix F Page F-32 Loads and Resources Tables
Table F.26
Monthly Loads & Resources Capacity Forecast – 2007 (in MW)

Year 2007 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1569 1525 1488 1336 1274 1338 1508 1444 1265 1316 1476 1610
Potlatch 48 48 48 48 48 48 48 48 48 48 48 48
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 8 8 8 8 8 8 8 8 8 8 8 8
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 1594 1550 1554 1402 1381 1445 1615 1541 1372 1423 1501 1635
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 153 153 153 153 153 153 153 153 153 153 153 153
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1134 1133 1126 1132 1125 1140 1145 1138 1132 1133 1138 1139
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1818 1809 1794 1792 1778 1775 1773 1763 1769 1794 1810 1820
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -43 -43 -43 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 -111 0 0 0 0 0 0
0 -166 -166 -145 -368 -204 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 60 52 51 53 58 58 61 60 52 52 55 55
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 33 44 44 45 47 47 48
108 99 98 99 81 92 105 104 97 99 102 103
Jan-07 Feb-07 Mar-07 Apr-07 May-07 Jun-07 Jul-07 Aug-07 Sep-07 Oct-07 Nov-07 Dec-07
CAPACITY SURPLUS (DEFICIT) 116 -6 -24 146 -52 34 53 103 146 117 102 -20
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No.11 January 10, 2003 Doug Young
Total Reserves
HYDRO RESOURCES
CAPACITY CONTRACTS
Total Maintenance

Appendix F Page F-33 Loads and Resources Tables
Table F.27
Monthly Loads & Resources Capacity Forecast – 2008 (in MW)

Year 2008 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1624 1577 1537 1382 1316 1379 1550 1488 1309 1359 1520 1662
Potlatch 48 48 48 48 48 48 48 48 48 48 48 48
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 8 8 8 8 8 8 8 8 8 8 8 8
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 1649 1602 1603 1448 1423 1486 1657 1585 1416 1466 1545 1687
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 152 152 152 152 152 152 152 152 152 152 152 152
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1133 1132 1125 1131 1124 1139 1144 1137 1131 1132 1137 1138
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1817 1808 1793 1791 1777 1774 1772 1762 1768 1793 1809 1819
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -43 -43 -43 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 0 0 0 0 0 0 0 0
0 -166 -166 -145 -257 -93 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 60 52 51 53 57 58 61 60 52 52 55 55
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 31 41 44 44 45 47 47 48
108 99 98 99 88 99 105 104 97 99 102 103
Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08 Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08
CAPACITY SURPLUS (DEFICIT) 60 -59 -74 99 9 96 10 58 101 73 57 -73
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No.11 January 10, 2003 Doug Young
Total Reserves
HYDRO RESOURCES
CAPACITY CONTRACTS
Total Maintenance

Appendix F Page F-34 Loads and Resources Tables
Table F.28
Monthly Loads & Resources Capacity Forecast – 2009 (in MW)

Year 2009 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1690 1638 1596 1436 1365 1429 1600 1541 1363 1410 1573 1724
Potlatch 50 50 50 50 50 50 50 50 50 50 50 50
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 8 8 8 8 8 8 8 8 8 8 6 6
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Grant Displacemen -22 -22 -22 -22 -22 -22 -22 -22 -22 -22 -22 -22
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Market Purchases -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 1695 1643 1642 1482 1452 1516 1687 1618 1450 1497 1576 1727
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 150 150 150 150 150 150 150 150 150 150 103 103
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1131 1130 1123 1129 1122 1137 1142 1135 1129 1130 1088 1089
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1815 1806 1791 1789 1775 1772 1770 1760 1766 1791 1760 1770
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -42 -42 -42 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
0 -166 -166 -144 -367 -92 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 60 52 51 53 57 58 61 59 52 52 53 53
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
108 99 98 99 81 99 105 103 97 99 100 101
Jan-09 Feb-09 Mar-09 Apr-09 May-09 Jun-09 Jul-09 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09
CAPACITY SURPLUS (DEFICIT) 12 -102 -115 64 -125 65 -22 24 65 40 -21 -160
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young
Total Reserves
HYDRO RESOURCES
CAPACITY CONTRACTS
Total Maintenance

Appendix F Page F-35 Loads and Resources Tables
Table F.29
Monthly Loads & Resources Capacity Forecast – 2010 (in MW)

Year 2010 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1753 1696 1651 1487 1412 1476 1647 1591 1414 1458 1624 1783
Potlatch 50 50 50 50 50 50 50 50 50 50 50 50
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 6 6 6 6 6 6 6 6 6 6 6 6
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen -21 -21 -21 -21 -21 -21 -21 -21 -21 -21 -21 -21
Market Purchases -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100 -100
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 1757 1700 1696 1532 1498 1562 1733 1667 1500 1544 1628 1787
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 103 103 103 103 103 103 103 103 103 103 103 103
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1084 1083 1076 1082 1075 1090 1095 1088 1082 1083 1088 1089
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1768 1759 1744 1742 1728 1725 1723 1713 1719 1744 1760 1770
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -29 -29 -29 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -131 -354 -79 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 58 49 49 51 56 56 58 57 50 50 53 53
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 106 97 96 97 79 98 102 101 95 96 100 101
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -95 -204 -214 -18 -203 -14 -112 -70 -30 -51 -73 -220

Appendix F Page F-36 Loads and Resources Tables
Table F.30
Monthly Loads & Resources Capacity Forecast – 2011 (in MW)

Year 2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1812 1751 1704 1535 1457 1520 1692 1638 1462 1504 1672 1839
Potlatch 52 52 52 52 52 52 52 52 52 52 52 52
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 6 6 6 6 6 6 6 6 6 6 4 4
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen -21 -21 -21 -21 -21 -21 -21 -21 -21 -21 -21 -21
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 1918 1857 1851 1682 1645 1708 1880 1816 1650 1692 1776 1943
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 102 102 102 102 102 102 102 102 102 102 63 63
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1083 1082 1075 1081 1074 1089 1094 1087 1081 1082 1048 1049
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1767 1758 1743 1741 1727 1724 1722 1712 1718 1743 1720 1730
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -29 -29 -29 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
0 -166 -166 -131 -354 -79 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 58 49 49 51 56 56 58 57 50 50 51 51
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
106 97 96 97 79 98 102 101 95 96 98 99
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -257 -362 -370 -169 -351 -161 -260 -220 -181 -200 -259 -414
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young
CAPACITY CONTRACTS
HYDRO RESOURCES
Total Maintenance
Total Reserves

Appendix F Page F-37 Loads and Resources Tables
Table F.31
Monthly Loads & Resources Capacity Forecast – 2012 (in MW)

Year 2012 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1868 1803 1753 1581 1498 1562 1734 1682 1507 1547 1716 1891
Potlatch 52 52 52 52 52 52 52 52 52 52 52 52
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 4 4 4 4 4 4 4 4 4 4 4 4
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 1993 1928 1919 1747 1705 1769 1941 1879 1714 1754 1841 2016
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 63 63 63 63 63 63 63 63 63 63 63 63
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1044 1043 1036 1042 1035 1050 1055 1048 1042 1043 1048 1049
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1728 1719 1704 1702 1688 1685 1683 1673 1679 1704 1720 1730
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -18 -18 -18 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
0 -166 -166 -120 -343 -68 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 56 47 47 50 54 55 56 55 48 48 51 51
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
104 95 94 96 77 96 100 99 93 94 98 99
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -369 -470 -475 -261 -437 -248 -358 -320 -282 -299 -324 -487
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young
CAPACITY CONTRACTS
HYDRO RESOURCES
Total Maintenance
Total Reserves

Appendix F Page F-38 Loads and Resources Tables
Table F.32
Monthly Loads & Resources Capacity Forecast – 2013 (in MW)

Year 2013 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1928 1859 1807 1630 1543 1607 1780 1730 1555 1593 1765 1948
Potlatch 54 54 54 54 54 54 54 54 54 54 54 54
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 4 4 4 4 4 4 4 4 4 4 4 4
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2055 1986 1975 1798 1752 1816 1989 1929 1764 1802 1892 2075
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 62 62 62 62 62 62 62 62 62 62 62 62
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1043 1042 1035 1041 1034 1049 1054 1047 1041 1042 1047 1048
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1727 1718 1703 1701 1687 1684 1682 1672 1678 1703 1719 1729
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -17 -17 -17 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -119 -342 -67 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 56 47 47 50 54 55 56 55 48 48 51 51
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 104 95 94 96 77 96 100 99 93 94 98 99
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -432 -529 -532 -312 -484 -295 -407 -371 -333 -348 -376 -547
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-39 Loads and Resources Tables
Table F.33
Monthly Loads & Resources Capacity Forecast – 2014 (in MW)

Year 2014 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 1985 1912 1858 1677 1586 1650 1823 1775 1602 1637 1811 2001
Potlatch 54 54 54 54 54 54 54 54 54 54 54 54
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 4 4 4 4 4 4 4 4 4 4 4 4
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2112 2039 2026 1845 1795 1859 2032 1974 1811 1846 1938 2128
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 60 60 60 60 60 60 60 60 60 60 60 60
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1041 1040 1033 1039 1032 1047 1052 1045 1039 1040 1045 1046
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1725 1716 1701 1699 1685 1682 1680 1670 1676 1701 1717 1727
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -17 -17 -17 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -119 -342 -67 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 55 47 47 49 54 55 56 55 48 48 50 51
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 104 95 94 96 77 96 100 99 93 94 98 99
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -491 -584 -585 -361 -529 -340 -452 -418 -382 -394 -424 -602
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-40 Loads and Resources Tables
Table F.34
Monthly Loads & Resources Capacity Forecast – 2015 (in MW)

Year 2015 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 2059 1980 1923 1737 1641 1706 1878 1834 1661 1694 1870 2071
Potlatch 56 56 56 56 56 56 56 56 56 56 56 56
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 3 3 3 3 3 3 3 3 3 3 3 3
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacement 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2187 2108 2092 1906 1851 1916 2088 2034 1871 1904 1998 2199
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 59 59 59 59 59 59 59 59 59 59 59 59
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4Upriver Fir 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1040 1039 1032 1038 1031 1046 1051 1044 1038 1039 1044 1045
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1724 1715 1700 1698 1684 1681 1679 1669 1675 1700 1716 1726
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -17 -17 -17 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -119 -342 -67 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 55 47 47 49 54 55 56 55 48 48 50 51
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 104 95 94 96 77 96 100 99 92 94 98 99
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -567 -654 -652 -423 -586 -398 -509 -479 -442 -453 -485 -674
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-41 Loads and Resources Tables
Table F.35
Monthly Loads & Resources Capacity Forecast – 2016 (in MW)

Year 2016 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 2135 2051 1991 1799 1698 1763 1936 1894 1723 1753 1931 2142
Potlatch 56 56 56 56 56 56 56 56 56 56 56 56
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 3 3 3 3 3 3 3 3 3 3 3 3
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 150 150 150 150 150 150 150 150 150 150 150 150
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2263 2179 2160 1968 1908 1973 2146 2094 1933 1963 2059 2270
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 57 57 57 57 57 57 57 57 57 57 57 57
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1038 1037 1030 1036 1029 1044 1049 1042 1036 1037 1042 1043
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1722 1713 1698 1696 1682 1679 1677 1667 1673 1698 1714 1724
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -16 -16 -16 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -118 -341 -66 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 55 47 47 49 54 55 56 55 48 48 50 50
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 103 95 94 96 77 96 100 99 92 94 98 98
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -644 -727 -722 -486 -644 -456 -569 -541 -506 -514 -548 -746
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-42 Loads and Resources Tables
Table F.36
Monthly Loads & Resources Capacity Forecast – 2017 (in MW)

Year 2017 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 2212 2122 2059 1862 1756 1821 1994 1955 1785 1812 1993 2215
Potlatch 58 58 58 58 58 58 58 58 58 58 58 58
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 3 3 3 3 3 3 3 3 3 3 3 3
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 0 0 0 0 0 0 0 0 0 0 0 0
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2192 2102 2080 1883 1818 1883 2056 2007 1847 1874 1973 2195
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 56 56 56 56 56 56 56 56 56 56 56 56
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1037 1036 1029 1035 1028 1043 1048 1041 1035 1036 1041 1042
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1721 1712 1697 1695 1681 1678 1676 1666 1672 1697 1713 1723
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -16 -16 -16 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -118 -341 -66 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 55 47 47 49 54 55 56 55 47 47 50 50
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 103 95 94 96 77 96 100 99 92 94 98 98
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -574 -651 -643 -402 -555 -367 -480 -455 -421 -426 -463 -672
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-43 Loads and Resources Tables
Table F.37
Monthly Loads & Resources Capacity Forecast – 2018 (in MW)

Year 2018 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 2291 2196 2130 1927 1815 1880 2054 2018 1849 1873 2057 2289
Potlatch 58 58 58 58 58 58 58 58 58 58 58 58
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 3 3 3 3 3 3 3 3 3 1 1 1
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 -82 -82
Enron/PGE 20 Cap 0 0 0 0 0 0 0 0 0 0 0 0
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2271 2176 2151 1948 1877 1942 2116 2070 1911 1933 2035 2267
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 54 54 54 54 54 54 54 54 54 25 25 25
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1035 1034 1027 1033 1026 1041 1046 1039 1033 1005 1010 1011
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1719 1710 1695 1693 1679 1676 1674 1664 1670 1666 1682 1692
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -15 -15 -15 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -117 -340 -65 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 55 47 46 49 54 55 56 55 47 46 49 49
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 103 94 93 96 77 96 100 99 92 92 96 97
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -655 -726 -715 -468 -615 -427 -542 -520 -487 -514 -554 -774
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-44 Loads and Resources Tables
Table F.38
Monthly Loads & Resources Capacity Forecast – 2019 (in MW)

Year 2019 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 2365 2264 2195 1987 1871 1935 2110 2076 1909 1930 2116 2358
Potlatch 60 60 60 60 60 60 60 60 60 60 60 60
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 1 1 1 1 1 1 1 1 1 1 1 1
BPA-WNP3 Gross -82 -82 -41 -41 0 0 0 0 0 0 0 0
Enron/PGE 20 Cap 0 0 0 0 0 0 0 0 0 0 0 0
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2345 2244 2216 2008 1933 1997 2172 2128 1971 1992 2178 2420
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 24 24 24 24 24 24 24 24 24 24 24 24
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1005 1004 997 1003 996 1011 1016 1009 1003 1004 1009 1010
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1689 1680 1665 1663 1649 1646 1644 1634 1640 1665 1681 1691
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -7 -7 -7 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -109 -332 -57 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 54 45 45 48 53 54 54 53 46 46 49 49
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 102 93 92 95 76 95 98 97 91 92 96 97
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -758 -823 -809 -549 -692 -503 -626 -606 -576 -574 -698 -928
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-45 Loads and Resources Tables
Table F.39
Monthly Loads & Resources Capacity Forecast – 2020 (in MW)

Year 2020 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 2441 2335 2263 2050 1928 1993 2167 2137 1971 1989 2178 2430
Potlatch 60 60 60 60 60 60 60 60 60 60 60 60
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 1 1 1 1 1 1 1 1 1 1 1 1
BPA-WNP3 Gross 0 0 0 0 0 0 0 0 0 0 0 0
Enron/PGE 20 Cap 0 0 0 0 0 0 0 0 0 0 0 0
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2503 2397 2325 2112 1990 2055 2229 2189 2033 2051 2240 2492
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 22 22 22 22 22 22 22 22 22 22 22 22
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1003 1002 995 1001 994 1009 1014 1007 1001 1002 1007 1008
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1687 1678 1663 1661 1647 1644 1642 1632 1638 1663 1679 1689
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -6 -6 -6 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -108 -331 -56 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 54 45 45 48 53 54 54 53 46 46 49 49
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 102 93 92 95 76 95 98 97 91 92 96 97
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -918 -978 -920 -654 -750 -562 -685 -669 -640 -635 -762 -1002
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-46 Loads and Resources Tables
Table F.40
Monthly Loads & Resources Capacity Forecast – 2021 (in MW)

Year 2021 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 2530 2417 2342 2122 1994 2059 2234 2207 2042 2057 2249 2513
Potlatch 62 62 62 62 62 62 62 62 62 62 62 62
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 1 1 1 1 1 1 1 1 1 1 1 1
BPA-WNP3 Gross 0 0 0 0 0 0 0 0 0 0 0 0
Enron/PGE 20 Cap 0 0 0 0 0 0 0 0 0 0 0 0
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2594 2481 2406 2186 2058 2123 2298 2261 2106 2121 2313 2577
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 21 21 21 21 21 21 21 21 21 21 21 21
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1002 1001 994 1000 993 1008 1013 1006 1000 1001 1006 1007
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1686 1677 1662 1660 1646 1643 1641 1631 1637 1662 1678 1688
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -6 -6 -6 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -108 -331 -56 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 54 45 45 48 53 54 54 53 46 46 48 49
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 102 93 92 94 76 95 98 97 91 92 96 97
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -1010 -1063 -1002 -728 -819 -631 -755 -742 -714 -706 -836 -1088
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-47 Loads and Resources Tables
Table F.41
Monthly Loads & Resources Capacity Forecast – 2022 (in MW)

Year 2022 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 2625 2506 2426 2200 2065 2131 2306 2283 2119 2130 2325 2603
Potlatch 62 62 62 62 62 62 62 62 62 62 62 62
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 1 1 1 1 1 1 1 1 1 1 1 1
BPA-WNP3 Gross 0 0 0 0 0 0 0 0 0 0 0 0
Enron/PGE 20 Cap 0 0 0 0 0 0 0 0 0 0 0 0
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2689 2570 2490 2264 2129 2195 2370 2337 2183 2194 2389 2667
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 19 19 19 19 19 19 19 19 19 19 19 19
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 1000 999 992 998 991 1006 1011 1004 998 999 1004 1005
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1684 1675 1660 1658 1644 1641 1639 1629 1635 1660 1676 1686
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -5 -5 -5 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -107 -330 -55 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 53 45 45 48 53 53 54 53 46 46 48 49
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 102 93 92 94 76 95 98 97 90 92 96 97
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -1107 -1154 -1088 -807 -891 -704 -829 -820 -792 -781 -914 -1180
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-48 Loads and Resources Tables
Table F.42
Monthly Loads & Resources Capacity Forecast – 2023 (in MW)
Year 2023 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
LOADS 2017
Peak Load 2716 2591 2507 2275 2133 2199 2374 2355 2193 2200 2398 2688
Potlatch 64 64 64 64 64 64 64 64 64 64 64 64
CAPACITY CONTRACTS
Black Creek Hydro 0 0 0 0 0 0 0 -10 0 0 0 0
Nichols Pumping 1 1 1 1 1 1 1 1 1 1 1 1
BPA Can. ENT> (Canada) 1 1 1 1 1 1 1 1 1 1 1 1
BPA-WNP3 Gross 0 0 0 0 0 0 0 0 0 0 0 0
Enron/PGE 20 Cap 0 0 0 0 0 0 0 0 0 0 0 0
Grant Displacemen 0 0 0 0 0 0 0 0 0 0 0 0
Market Purchases 0 0 0 0 0 0 0 0 0 0 0 0
BPA Residential Exchange 0 0 0 0 0 0 0 0 0 0 0 0
TOTAL REQUIREMENTS 2782 2657 2573 2341 2199 2265 2440 2411 2259 2266 2464 2754
HYDRO RESOURCES
System Hydro 973 972 960 959 952 971 979 978 970 969 974 976
Mid-Columbia 17 17 17 17 17 17 17 17 17 17 17 17
Small Hydro 4 4 4 4 4 4 4 4 4 4 4 4
Upriver Firm 4 4 9 16 16 12 9 3 5 7 7 6
Sub-Total 998 997 990 996 989 1004 1009 1002 996 997 1002 1003
THERMAL RESOURCES
Coyote Springs II 144 141 139 137 134 132 130 130 132 137 141 143
Colstrip 222 222 222 222 222 222 222 222 222 222 222 222
Northeast Turbine 60 59 57 56 55 55 50 50 55 56 57 60
Rathdrum CT 176 172 168 163 160 144 144 141 146 164 170 174
Boulder Park 25 25 25 25 25 25 25 25 25 25 25 25
Kettle Falls CT 7 7 7 7 7 7 7 7 7 7 7 7
Kettle Falls 50 50 50 50 50 50 50 50 50 50 50 50
Sub-Total 684 676 668 660 653 635 628 625 637 661 672 681
TOTAL RESOURCES 1682 1673 1658 1656 1642 1639 1637 1627 1633 1658 1674 1684
MAINTENANCE
Coyote Springs II 0 0 0 0 -134 0 0 0 0 0 0 0
Spokane River 0 0 0 0 0 0 0 -15 -52 -53 -3 0
Clark Fork River 0 -166 -166 -102 0 0 0 0 -102 -102 -102 -102
Mid-Columbia 0 0 0 -5 -5 -5 0 0 0 0 0 0
Rathdrum 0 0 0 0 -80 0 0 0 0 0 0 0
Kettle Falls 0 0 0 0 0 -50 0 0 0 0 0 0
Colstrip 0 0 0 0 -111 0 0 0 0 0 0 0
Total Maintenance 0 -166 -166 -107 -330 -55 0 -15 -154 -155 -105 -102
Hydro Reserves 5% (Includes Box Canyon Gen) 53 45 45 48 53 53 54 53 46 46 48 48
Thermal Reserves 7% (Includes Vaagen Gen) 48 48 47 46 23 41 44 44 45 47 47 48
Total Reserves 101 93 92 94 76 95 98 97 90 92 96 96
Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10
CAPACITY SURPLUS (DEFICIT) -1201 -1243 -1173 -886 -963 -776 -901 -896 -870 -855 -991 -1268
*Note: These figures assume maximum one hour peak loads for the month and one hour hydro capabilities. September 6, 2002 load forecast.
Revision No. 11 January 10, 2003 Doug Young

Appendix F Page F-49 Loads and Resources Tables
Chart F.6
2002 Hourly System Load Shapes by Quarter
600
700
800
900
1,000
1,100
1,200
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Q1 Q2 Q3 Q4 Annual

Appendix G Page G-1 TAC Meeting Materials
Appendix

TAC Meeting Agendas

May 2, 2002

1. Annual L&R Tabulation
2. Report Outline-Draft
3. Update on New Resources
4. Natural Gas Outlook
5. Confidence Interval Planning Concept
6. Meeting Intermediate Resource Needs
7. Company Structure for the Future
8. DSM Update/ EEE Overview
9. Model Use – Prosym/ Aurora
10. Scenarios for Load Forecast

September 24, 2002

1. Electric and Natural Gas Forecasts
2. Gas Outlook and Price Forecast
3. Gas and Electric DSM Plans
4. Electric Modeling Enhancements

January 23, 2003

1. WECC Marketplace
• Capacity Expansion/ Natural Gas Forecast/ Price Forecast
• Avista’s Outlook/ Resource Alternatives
2. Risk Analysis
• Load, Hydro, Natural Gas, and Price Variability
3. Avista’s Microturbine
4. Spokane River Relicensing

April 2, 2003

1. Accomplishments Since the last Meeting
2. TAC Members Review
3. Schedule to Finalize the Report
4. Report’s Inputs
5. Report’s Chapter Reviews
6. Final Results
7. Impacts on Avista and its Customers
8. Information in Appendices

Appendix H Page H-1 Wind Studies
Appendix

Wind Studies

Wind Energy

Wind energy has become more prominent in the Northwest in recent years due to three primary
drivers: a federal energy tax credits which reduces the cost of the plants by nearly one-third;
falling capital costs from new and better technologies and economies of scale; and legislative
pushes such as renewable portfolio standards, which have resulted from environmental activism.
There is nearly 500 MW (160 aMW of energy) of wind generation facilities presently installed or
in construction in the Northwest.

The Company recognizes these changes and has begun evaluating the potential for wind energy
on its system. Its preferred resource strategy includes 75 MW installed early in the acquisition
timeframe. Preliminary studies have verified that wind energy costs have indeed fallen
tremendously; however, system integration issues and costs caution the Company against
moving too fast. This section will summarize preliminary findings of an internal Company
study.

The Falling Costs of Wind Energy

Similar to generation technologies before it, wind generation plant costs have fallen to around
$1,000/kW, a fraction of what prices were a decade ago. Turbines are now much larger, are
based on simpler designs, and benefit from economies of scale as countries around the world
install the plants. Most significant development prior to the late-1990s was found in Europe,
where higher energy costs made the turbines more attractive relative to the United States where
electricity is comparatively less expensive. The Company estimates that with current federal tax
credit levels, wind energy plants can be installed and operated at a cost of approximately
$35/MWh in real levelized 2004 dollars, excluding integration and transmission expenses.

System Integration

One cost that has not fallen, and in fact may be rising due to increasingly constrained
transmission and hydro facilities, is system integration. All generation facilities must pay
integration charges in addition to their installation and operation. At a minimum, a plant must
purchase transmission to deliver its energy to a load center. A plant is also responsible for
various reserve products to protect the grid against forced outages. System integration costs
appear to be much higher for wind energy plants than other generation resources.

Traditional generation resources, while varying somewhat based on technology, benefit from
having fuel supplies that are predictable and controllable for hours, even days or months, ahead
of scheduled delivery. For example, a coal plant can have not only a predictable schedule of fuel
deliveries, but also a large storage pile in the event that deliveries are interrupted for a period of

Appendix H Page H-2 Wind Studies
time. Hydroelectric projects might or might not have significant storage capabilities, but nearly
all can be scheduled no less than on a pre-schedule or hour-ahead basis.

Traditional resources benefit from predictability. Wind, on the other hand, does not. An
installation of 100 MW has the potential on a given hour to generate somewhere between zero
and 100 MW. Unfortunately, this schedule is not as predictable as other sources of power. Wind
is not controllable in that Mother Nature decides when and how much energy will be generated.
This lack of predictability and control puts wind plants at a significant disadvantage. Third-party
estimates of wind integration costs have been put as high as $25 per MWh.

"Fuel" Availability

A second large disadvantage of wind plants is a lack of fuel availability. An exceptional
Northwest wind site can expect to have somewhere in the neighborhood of a 30 to 35 percent
fuel availability. While the wind generators themselves might be available to generate for 95
percent or more of the hours during a year, there is not enough wind to keep the plants operating
at high levels. This low fuel availability puts wind energy plants at a disadvantage on a cost per
MWh basis. For example, a one megawatt wind or gas turbine plant with a fifteen percent
capital recovery factor would incur an annual fixed expense of $150,000 assuming a $1,000/kW
installed cost. The wind plant would be expected to generate 2,980 MWh during the year
assuming a 33 percent fuel availability factor. The gas turbine plant with an identical installed
cost, on the other hand, would be capable of generating 8,322 MWh assuming a five percent
forced outage rate. On a per-MWh basis, capital recovery costs for the wind plant would be
$50.3 per MWh; the gas turbine plant would be $18.0 per MWh, or one-third as much.

Fuel Costs

The largest economic benefit of wind energy is that its fuel is free. While the variable operating
and maintenance costs are similar to that of a natural gas-fired turbine, such savings can be
significant. At $4 per decatherm, fuel costs for an efficient CCCT are $28 per MWh. Where gas
prices are higher, the benefit of a wind turbine increases further. Of course, natural gas prices
can also be lower, reducing the advantage of wind energy during those periods.

Another advantage of wind plants, and other low fuel cost facilities (e.g., mine-mouth coal
plants), is their hedge against natural gas price volatility. Utilities have long recognized the
benefits of generation portfolios with diverse fuel sources. The Company's hydroelectric dams
provide a similar benefit. Wind energy provides a strong hedge against natural gas price swings.
In fact, wind energy portfolios evaluated in the Company's IRP had the lowest financial risk.

Environmental Benefits

Wind energy plants are a renewable resource and do not emit pollutants into the environment.
Impacts are modest when compared to other technologies, and in many cases have been
addressed. For example, early concerns over bird kills have been all but eliminated by avoiding
migratory bird paths. While wind plants "consume" large tracts of land, these sites traditionally
are in remote areas where their installation does not tremendously affect other activities (e.g.,
farming).

Appendix H Page H-3 Wind Studies

Wind Energy Generation and Consideration of Capacity

The Company, as a hydro-dependent utility, is acutely aware of issues surrounding energy-
limited resources. Hydroelectric plants generally have very high capacities over a short
timeframe such as an hour. However, sustained capacity over many hours and days cannot be
planned for once storage water is gone.

A similar concept applies to wind generators. While wind generators have energy associated
with them, there is no means to reliably forecast generation more than a few hours ahead.
Because of this lack of predictability, the Company was concerned about including wind
generation in its capacity tabulations. To determine the potential for counting wind generator
capacity in its capacity tabulation, the Company reviewed a 25-year database of Northwest wind
sites from Oregon State University. On a statistical basis it was found that wind generators do
not provide any capacity. This result was the same when considering one wind site or a diverse
mix of sites across the Northwest. This last point is significant. Many in the Northwest believe
that while one wind site doesn’t provide any guarantee of generation in a given hour, a mix of
sites does. The Company took a hypothetical 20 percent share in five Northwest sites across
Washington, Oregon, Idaho, and Montana. The result was the same for the diversified mix–no
guarantee of capacity.

In addition to evaluating hourly capacity values, the Company reviewed the database to learn if it
could on a statistical basis rely on wind generators to provide some significant level of
generation over a weekly period. A week coincides well with the Company's hydro storage
management, and a minimum level of expected energy generating capability would allow wind's
integration into the weekly operating plan. Unfortunately, when reviewing 1994-2000 datasets,
it was learned that the Company couldn’t rely on wind generators to provide any significant
portion of their generating capability during a specific week.

These analyses highlight the apparent fact that any utility relying on wind energy not include
wind generator capacity in their capacity plans. Systems using wind energy will require other
generation resources capable of meeting the varying wind generator output. In the short term
this could mean relying on existing facilities at modest incremental cost. However, over the
longer-run it is likely that integrating wind energy will require additional capacity resources
that’s cost will be incurred by ratepayers.

Utility-Specific Issues

The Company recognizes the various benefits of wind energy, but after careful review has
determined that it will not rely too heavily on it without further study. System integration issues
appear to be significant, both in absolute cost and the physical capability of the Company's
generation system to accept its varying production. System integration is the largest single
barrier to a greater reliance on wind energy. To the extent the issues can be resolved through
further study, the Company sees the potential to rely upon this renewable resource for more of its
future requirements.

Appendix H Page H-4 Wind Studies
In late 2002 the Company joined a wind developer to create a wind integration model. The
model provides a simplified representation of system generators, transmission, and market hubs.
A specific advantage of this new approach is that reserve products, and AGC-responsive reserves
specifically, are represented in an attempt to account for "opportunity costs". Opportunity costs
the Company would incur from wind integration come from less-efficient turbine operations,
reduced on-peak generation levels due to carrying additional reserves, selling into less
advantageous marketplaces due to constrained transmission paths and water spilled when the
system has no other means to integrate wind energy.

Wind integration will require the host utility to manage its various generation turbines in
configurations that are sub-optimal and outside their most efficient range. While many of the
Company's generating turbines are capable of being responsive to some level of wind energy,
their efficiencies can vary by ten percent or more across their operating range. Control areas
oftentimes are obligated to operate in this manner with costs higher than they otherwise would
be, but wind integration will increase the frequency of these periods significantly as the system
moves in response to the level of wind generation on the system.

Wind energy output can vary tremendously during the day. Its output varies tremendously more,
and with less predictability, than load variation. To integrate wind, then, the Company will be
required to hold more turbines on AGC to provide for when wind doesn't generated as scheduled.
Additional AGC reserves are the most expensive reserves that the Company has to provide and
are generally carried by hydroelectric generators. Carrying AGC reserves means that turbines
are not available to generate at their full level during "super-peak" periods of the day. Super-
peak periods generally are in the mid-morning and late afternoon, when prices in the marketplace
are the highest. Instead of generating during these hours, wind energy reserves will require
hydro plant generators to generate in less valuable times of the day.

A third cost to the Company is expected to come from constrained transmission. The Company
at many times during the year uses the full capability of its transmission rights to deliver energy
either to its system or to a major market trading hub. When the Company has used all of its
transmission rights, it must either purchase additional rights or in a worst case sell its energy to
less-valuable marketplaces. Wind energy can require a large transmission reservation, as its
capacity is three times greater than its expected energy output. This requirement will necessarily
push the Company out into the non-firm transmission market on more occasions and also prevent
energy from always being delivered to the highest-price marketplace.

In the worst case, the Company could spill water to manage a varying wind energy plant. In this
case, however, the value of the wind energy is zero because it is being offset by lost water that
otherwise would be generated by a hydro plant. The Company would spill only under the worst
of conditions and consider this a last resort.

The impacts of these costs on some days are modest while on others are more significant. The
model provides a tally of them over a typical year, a critical water year, and an above-average
hydro year. Additionally, the model looks at integrating varying levels of wind energy on the
Company's system. The resultant estimated costs are substantial, with costs rising above ten
dollars per MWh under various potential scenarios. The model explains that the level of
forecasting error and size of the installation make very large impacts on integration costs. The

Appendix H Page H-5 Wind Studies
table below explains that forecast error is very important when scheduling wind. With perfect
forecasting, integration costs are below $3/MWh. However, as the forecast becomes less
accurate, prices rise substantially. A persistence forecast (what happened last hour is what will
happen this hour) has costs as much as six times a “perfect” forecast.

Table H.1
Preliminary Wind Integration Cost Estimates

Model Forecast Hydro Year
Type Error Wet Normal Dry
(90% CI) ($/MWh) ($/MWh) ($/MWh)
Persistence 30.0% 17.66 13.56 8.34
Meso-Scale 15.0% 7.65 5.55 4.77
7.5% Error 7.5% 4.90 3.63 3.28
Perfect Forecast 0.0% 2.70 2.23 1.88

A 300 MW plant would have even larger costs. Although the Company was unable to complete
runs at 300 MW except for a perfect forecast, integration costs were found to increase by a third
or more.

Modeling provides one look at potential system integration issues. Internal discussions within
the Company have identified operational considerations potentially beyond the breadth of the
study. Although the model purports to address the additional costs associated with bringing
larger quantities of wind energy into the Company's system, real-time operations could limit the
amount further. Discussions with other utilities integrating wind energy explain that doing so is
not a simple task. Additional scheduling staff likely will be needed. Operations will become
much more unpredictable. Therefore, although the model might suggest that as much as 300
MW of wind generation could be installed, the Company cannot at this time support that
conclusion.

Conclusions and Next Steps

The Company is both excited and concerned about the potential for wind generation in the
Northwest. On the one hand costs have fallen tremendously over the past couple decades,
making this renewable resource attractive with other traditional resources. On the other, wind
integration costs haven't gone away and will likely be significant. The results of this study
should be considered preliminary, as the Company has additional work to perform before it can
be certain its results are comprehensive. As indicated in the Action Plan of the IRP, the
Company over the next two years will perform additional studies to ensure that the full potential
and costs of wind energy are recognized. After this study the Company should be better
prepared to evaluate the resource against more traditional plants.

Appendix H Page H-6 Wind Studies
Interoffice Memorandum
Energy Resources

DATE: February 5, 2002

TO: Clint Kalich

FROM: Brad Simcox

SUBJECT: Wind Power Study

Introduction

This study began with the intention of analyzing the reliability of wind power. By using actual wind-
speed information to calculate theoretical generation data, we have been able to estimate the energy that
wind power could add to our system portfolio. On average, we can expect average capacity factor over
the year of 15 - 30%.

Discussion

We were able to obtain a large amount of wind-speed data from Stel Walker, the director of the wind
research cooperative at Oregon State University. The CD Stel sent us included hourly wind-speed data
from various sites around the Northwest for the last 25 years. No one site had a complete history, so the
first step in utilizing this data was auditing the information to find what periods and sites would give us
the most useful results.

We found that there were five sites that had significant amounts of data. They are as follows:

1) Browining Depot, MT: Browning Depot is located in north central Montana at an elevation of 4500
feet and has been an active BPA monitoring site since October 1985.

2) Cape Blanco, OR: Cape Blanco is located along the southern Oregon coast near the town of Port
Orford. Wind data has been collected at the site since October 1976. The Cape Blanco area sits on a
coastal bench roughly 200 ft. above sea level and consists of rolling pasturelands bordered by trees.

3) Goodnoe Hills, WA: Goodnoe Hills is located east of the Columbia Hills region of southern
Washington over looking the Columbia River Gorge. The site is located at an elevation of 2540 ft. The
winds at the site are generally dictated by large-scale pressure differences between the Pacific and the
interior of Oregon and Washington, and by the channeling effects of the Gorge.

Appendix H Page H-7 Wind Studies
4) Kennewick, WA: The Kennewick site is located in southern Washington near the town of Kennewick
at an elevation of 2200 feet and has been monitored since 1976.

5) Seven Mile Hill, OR: Seven Mile Hill is located in north-central Oregon, west of The Dalles near the
Columbia River Gorge. The site is situated along a ridge-line at an elevation of 1880 feet. Wind speeds
have been monitored at this site since October 1978.

Once I found these sites, I sorted through and deleted all of the missing data. I was then able to find runs
of data several months long that were useful for calculating average monthly capacity and average annual
capacity. I was able to estimate generation using the following formula:

P = 0.5 x rho x A x Cp x V3 x Ng x Nb

Where:

P = power in watts
rho = air density (about 1.225 kg/m3 at sea level, less higher up)
A = rotor swept area exposed to the wind (m2)
Cp = Coefficient of performance (0.59 maximum theoretically possible, 0.35 for a good design)
V = wind speed in meters/second (1 m/s = 2.24 mph)
Ng = generator efficiency
Nb = gearbox / bearings efficiency

The analysis was modeled using NEG Micon’s NM72/2000 2 MW wind turbine, and the following
assumptions were integrated into the study:

rho = 1
A = 4072 m2
Cp = 0.35
Ng = 0.8
Nb = 0.9
Minimum Wind-Speed = 4 m/s
Maximum Capacity = 2 MW

In addition to the analysis done for the aforementioned sites, I also completed a study that examined the
outcome if we had purchased a share of capacity from each of the five sites. The details of this test can be
seen in charts numbered 6 and 12, and also in the tables below in the rows labeled “diversified mix”.

Energy

After calculating the generation data, I was able to determine average monthly energy and I developed an
80% confidence interval for expected generation. This information is detailed in the attached graphs.

The attached graphs (labeled charts 1-6) detail monthly average energy by project site for every year in
the study. The dash marks represent average energy for the month in a particular year. The table below
provides annual average energy statistics and the periods of study for the different project sites that were
analyzed:

Appendix H Page H-8 Wind Studies

Table # Project Site Period of
Study
Annual Average
Energy (aMW)
Annual Capacity
Factor
Max Min
1 & 7 Browning Depot 1994 – 2000 0.32 0.17 0.71 0.14
2 & 8 Cape Blanco, OR 1994 – 2000 0.51 0.26 0.73 0.32
3 & 9 Goodnow Hills, WA 1994 – 2000 0.29 0.15 0.38 0.24
4 & 10 Kennewick, WA 1995 – 2000 0.54 0.27 0.76 0.38
5 & 11 Seven Mile Hill, OR 1995 – 2000 0.33 0.17 0.61 0.11
6 & 12 Diversified Mix 1994 – 2000 0.39 0.23 0.51 0.31

As you can see, the best site (Kennewick) produced on average only 27% of its rated capacity. I was also
able to find the amount of time that it would be impossible to generate using wind turbines at these sites.

Project Site % Time With No Generation
Browning Depot 31.0
Cape Blanco, OR 23.0
Goodnow Hills, WA 31.0
Kennewick, WA 25.0
Seven Mile Hill, OR 35.0
Diversified Mix 0.6

The best site, Cape Blanco in this case, still was not able to generate any energy 23% of the time due only
to low wind speeds. The “Diversified Mix” scenario was calculated by finding the amount of time that
none of the five sites were generating. Forced outages, planned maintenance, and icing conditions are not
considered in these percentages.

Capacity

The attached graphs (labeled charts 7-12) detail monthly average energy and provide 80%
confidence intervals* for average generation. The intervals show us, with 80% certainty, how
much generation we can expect at these different sites. Please note that in reality the minimum
generation possible is zero MW and the maximum possible generation with the assumed turbine
is 2 MW, however for illustrative purposes these limitations were not enforced. The connected
dash marks on the graphs represent the confidence interval limits, and the solid line in the middle
represents average monthly energy for the previously specified periods of study.

The charts show that during every month at every site there is a significant chance that actual
average energy will be close to zero aMW. This indicates that adding wind to our system could
bring along with it more variability in our generation portfolio and it could provide many
challenges to effectively integrate it into our system. In short, we cannot count on wind for
system capacity.

* At the 80% confidence level, wind resources cannot be relied upon for system capacity.

Appendix H Page H-31 Wind Studies
Interoffice Memorandum
Energy Resources

DATE: April 4, 2002

TO: Clint Kalich

FROM: Brad Simcox

SUBJECT: Wind Analysis Update

Clint-

Stel Walker, director of the wind research cooperative at OSU, had recently been in contact with us
regarding my wind energy analysis. While he approved of most of our methods and results, he did make
a couple of suggestions to improve the outcome of the study. Because of this, I went through and made
some changes to the study.

First, Stel thought that we should use a smaller 660 kW turbine to model the resource rather than the 2
MW machine that we had used in the initial study. This would give us less time with zero generation
(since this turbine can operate at lower wind speeds) and a higher annual capacity factor. Second, he
asked me to take into consideration that the sensors used to gather wind speed data and the height of the
actual turbine are different; typically, the turbine would be constructed at a higher altitude than the
sensors were placed at, so he gave me a formula to adjust for this difference. I used this factor for every
site except Cape Blanco, OR, which is a coastal site and according to Stel would have the highest wind
speeds at the height that the sensor was placed. For most sites, this added an extra 10% or so to the
calculated generation. Lastly, Stel made me aware that wind turbines “cut-out” when the wind speed
exceeds a certain point in order to avoid damage to the rotor. For both the 2MW and 660 kW turbines,
this wind speed is 25 m/s (or 56 mph). I made all of these adjustments to both the study using the 2 MW
turbine and the one with the 660 kW turbine.

After looking at the results, it is apparent that the 660 kW turbine does improve our annual capacity factor
and our decreases our time without any generation. However, none of these improvements warrant any
excitement – the numbers still look fairly poor. I have attached summaries by site that outline average
monthly generation, average annual generation, annual capacity factor, and time with zero generation.
Please let me know if you would like any additional detail provided or analysis performed regarding this
information.

Thanks.
Brad Simcox
Energy Resources Intern

Appendix I Page I-1 Capacity Expansion Process Details
Appendix

Capacity Expansion Process Details

© COPYRIGHT 2003 EPIS, INC. ALL RIGHTS RESERVED

AURORATM ELECTRIC MARKET MODEL

Capacity Expansion
Overview

AURORA simulates the addition of new-generation resources and the economic retirement
of existing units. New units are chosen from a set of available supply alternatives with
technology and cost characteristics that can be specified through time. New resources are
built only when the combination of hourly prices and frequency of operation for a resource
generate enough revenue to make construction profitable; that is, when investors can
recover fixed and variable costs with an acceptable return on investment. AURORA uses an
iterative technique in these long-term planning studies to solve the interdependencies
between prices and changes in resource schedules.

Also, existing units that cannot generate enough revenue to cover their variable and fixed
operating costs over time are identified and become candidates for economic retirement. To
reflect the timing of transition to competition across all areas, the rate at which existing units
can be retired for economic reasons is constrained in these studies for a number of years.

Future-Capacity Expansion Process - The model uses market economics to determine the
future resource retirements and additions. In simulating what happens in a competitive
marketplace, AURORA produces a set of future resources that have value in the
marketplace over the study period. Investors will only make future investments if they get a
return of and return on their investment dollars. The model assumes that investors will
invest to the point that they get their expected return. As future investments are made and
new capacity is added, electricity prices will fall. The prices will continue to decline as long
as investors are willing to make investments, and investors will invest as long as their
projects have a positive net-present value taking consideration all going forward costs and
return on investment. Hence, prices fall and at some point future investments no longer
earn the expected return. Once that happens more investment will not be made, and
without the investment prices are higher. This continues until the price for a market area is
in equilibrium and the future resources for the study period have reached the point where
last investment still has a positive net present value.

AURORA ELECTRIC MARKET MODEL
2 © COPYRIGHT 2003 EPIS, INC. ALL RIGHTS RESERVED
Capacity Expansion Modeling

In AURORA, future resource units may be put in the database with pre-determined start
dates. Or, you can use the long-term optimization logic that uses market economics to
determine the long-term resources and the start or retirement dates. Long-term
optimization studies are used to forecast capacity expansion resources and retirements.
AURORA performs an iterative future analysis where 1) resources that have negative going-
forward value (revenues less cost) are retired and 2) resources that add value are added to the
system. This is done on a gradual basis—where resources with positive net present value are
selected from the set of new resource options and added to the study. 3) AURORA then
uses the new set of resources to compute all of the values again. 4) The process of adding
and retiring resources is repeated. This whole process is continually repeated until value or
system price stabilizes indicating that an optimal set of resources is identified for the future
conditions assumed for the study.
The competitive marketplace will construct resources over the long-term such that there is
an expectation that the new resource will create value on a going-forward basis. Likewise,
existing resources that have no value on a going forward basis will eventually be retired
within the constraints of the system. Existing and potential resources can be studied to see
how well they will compete in the marketplace.

The goal of optimization process is to simulate the competitive marketplace by identifying
the investments in future resources that have the value in the marketplace. AURORA
assumes that new generators will be built (and existing generators retired) based on
economics. The economic measure used is real levelized value (revenues less cost) on a $
per MW basis. Investment cost is included in the cost portion of the formula.

Also, the methodology assumes that potentially non-economic contracts will not influence
the marketplace and that someone will capture the opportunity value of non-economic
contracts. Therefore contracts are not modeled in the pricing piece of AURORA.

In preparing for Long-term optimization studies, users will identify new resource options to
be evaluated in the study and determine parameters for the study.

NEW RESOURCES
The New Resources Table in the database is where the user defines a new resource and its
operating characteristics. The types of resource may be Wind, Solar, Nuclear, Coal, or Gas.
Also, new resources may include improved heat rates of existing technologies, re-
deployment of existing resources and emerging technologies.
The new resources input defines the variables of a new unit, including when the potential
unit will be placed in service. These variables provide controls for placing operating
constraints on all the units in the system.
AURORA ELECTRIC MARKET MODEL
3 © COPYRIGHT 2003 EPIS, INC. ALL RIGHTS RESERVED
AURORA will calculate a value for each unit using an approach that enables resources to be
compared on equal basis with different capacity sizes and different investment lives. This
also handles the economic comparisons when the resource end of life extends beyond study
period.
Therefore, investors are compensated for their investment and the economic decision holds
for not only over the study period but also over the life of the resource project. The capital
investment costs include:
· Rate of Return of attract capital investment
· Capital Recovery
· Income Tax Costs and Benefits
AURORA RESOURCE VALUE
AURORA determines resource value from the difference between market price and resource
cost. The basic value formula is:

Market Value = Market Revenues
minus
Fuel Costs
Variable O&M Costs
Fixed O&M Costs
Emission Costs
Capital Investment Costs
This value determination is performed for every hour for every resource in each market
region. Thus, a very accurate value is developed which takes into account system value
during on peak and off-peak and other hours, and during daily, seasonal, and annual periods
of time.
Incremental going forward costs and benefits: The user can specify the use of variable
operation and maintenance expenses along with fixed operation and maintenance expense in
the computation. However, the value computation should be performed on all forward
costs. This produces the best economic view of the resource. In the table above, the
carrying costs of the additional fixed operations and maintenances expense are calculated.
The resource value is computed as the present value of the hourly values over the study
period. The present value is determined at the nominal discount rate.
In the resource selection, the value used for adding and retiring resources in AURORA is the
net present value per MW capacity. This value is used to compare resources on equal basis
to allow comparisons of resources with different capacity sizes and different investment
lives. It also handles the economic comparisons when the resource end of life extends
AURORA ELECTRIC MARKET MODEL
4 © COPYRIGHT 2003 EPIS, INC. ALL RIGHTS RESERVED
beyond study period. Using this approach the result of the optimization study is a set of
resources that have value in market. In summary, the net present value per MW of each
resource is found for all periods of the study. This net present value is used in long term
future analysis for determining whether a new resource should be added to the system or
whether an old resource should be dropped.

SUMMARY OF STEPS IN CAPACITY EXPANSION STUDY
1. The first iteration begins with no changes in resources for the time period of the
study. (AURORA uses resources in Resources Table)
2. Enumerates all new resources
3. Computes value for each existing resource
4. Computes value for each new enumerated resource
5. Sorts resource values
6. Selects a small set of the most negative value existing resources to retire
7. Selects a small set of the most positive value new resources to add.
8. Rerun AURORA to compute electric prices and resource value
9. AURORA repeats the algorithm until the system stabilizes
In this way, resources that create value on a going-forward basis will be constructed while
those that have no value on a going forward basis will be retired. When the change in price
achieves the optimization criteria for price change, and when at least the minimum study
iterations are complete, the expansion study is complete. The minimum number of
iterations is important to make sure a full range of capacity options have been explored out
of thousands of potential resource options.
After the future resources have been identified, a resource modifier table is created—this
table is used for other long-term studies. The new RESOURCE MODIFIER table
becomes part of the AURORA input database. This table is the only output saved to the
input database.
The output of the capacity expansion or long-term optimization study is used for other long-
term analyses where the assumptions are applicable.

Appendix J Page J-1 Results of Capacity Expansion
Appendix

Results of Capacity Expansion

Table J.1
Resource Retirements and Additions

Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
5959 Battle R 3 Alberta Power Limited 10502 157000 13 01-01-1980 12-31-2028
5960 Battle R 4 Alberta Power Limited 10500 157000 13 01-01-1980 12-31-2028
5962 Milner 1 Alberta Power Limited 10501 152000 13 01-01-1980 12-31-2028
5963 Rainbow 1 APL Alberta Power Limited 10800 30000 13 01-01-1980 12-31-2025
5964 Rainbow 2 APL Alberta Power Limited 10400 43000 13 01-01-1980 12-31-2025
5965 Rainbow 3 APL Alberta Power Limited 11400 22000 13 01-01-1980 12-31-2028
5966 Sheerness 1 Alberta Power Limited 10353 389000 13 01-01-1980 12-31-2027
5968 Anaheim GT 1 Anaheim CA, City of 12800 48000 3 01-01-1980 12-31-2011
5970 Apache Station GT2 Arizona Electric Power Coopera 14362 20000 10 01-01-1980 12-31-2007
5971 Apache Station GT3 Arizona Electric Power Coopera 12990 69000 10 01-01-1980 12-31-2011
5972 Apache Station ST2 Arizona Electric Power Coopera 10293 175000 10 01-01-1980 12-31-2010
5973 Apache Station ST3 Arizona Electric Power Coopera 10293 175000 10 01-01-1980 12-31-2009
5977 Cholla 1 Arizona Public Service Company 10378 110000 10 01-01-1980 12-31-2028
5979 Cholla 3 Arizona Public Service Company 10399 260000 10 01-01-1980 12-31-2028
5981 Douglas 1 Arizona Public Service Company 13797 17000 10 01-01-1980 12-31-2007
5984 Four Corners 3 Arizona Public Service Company 11029 220000 9 01-01-1980 12-31-2028
5988 Ocotillo 1 Arizona Public Service Company 10782 115000 10 01-01-1980 12-31-2009
5989 Ocotillo 2 Arizona Public Service Company 10984 115000 10 01-01-1980 12-31-2008
5990 Ocotillo GT1 Arizona Public Service Company 14312 67000 10 01-01-1980 12-31-2009
5991 Ocotillo GT2 Arizona Public Service Company 15873 67000 10 01-01-1980 12-31-2005
5995 Saguaro 1 APSC Arizona Public Service Company 11195 110000 10 01-01-1980 12-31-2008
5996 Saguaro 2 Arizona Public Service Company 11322 99000 10 01-01-1980 12-31-2008
5997 Saguaro GT1 Arizona Public Service Company 13623 64000 10 01-01-1980 12-31-2008
5998 Saguaro GT2 Arizona Public Service Company 13718 64000 10 01-01-1980 12-31-2008
6000 West Phoenix 1B Arizona Public Service Company 9201 97000 10 01-01-1980 12-31-2011
6001 West Phoenix 2B Arizona Public Service Company 9201 97000 10 01-01-1980 12-31-2011
6002 West Phoenix 3B Arizona Public Service Company 9201 97000 10 01-01-1980 12-31-2011
6003 West Phoenix GT1 Arizona Public Service Company 13965 67000 10 01-01-1980 12-31-2007
6004 West Phoenix GT2 Arizona Public Service Company 13965 67000 10 01-01-1980 12-31-2007
6005 Yucca GT1 Arizona Public Service Company 14667 22000 10 01-01-1980 12-31-2006
6006 Yucca GT2 Arizona Public Service Company 14137 22000 10 01-01-1980 12-31-2006
6007 Yucca GT3 Arizona Public Service Company 11907 67000 10 01-01-1980 12-31-2013
6008 Yucca GT4 Arizona Public Service Company 12691 66000 10 01-01-1980 12-31-2010

Appendix J Page J-2 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
6009 Yucca ST1 Arizona Public Service Company 10190 75000 10 01-01-1980 12-31-2011
6018 Ben French 2 Black Hills Power & Light Comp 9240 2000 8 01-01-1980 12-31-2004
6019 Ben French 3 Black Hills Power & Light Comp 9240 2000 8 01-01-1980 12-31-2004
6020 Ben French 4 Black Hills Power & Light Comp 9240 2000 8 01-01-1980 12-31-2006
6021 Ben French 5 Black Hills Power & Light Comp 9240 2000 8 01-01-1980 12-31-2005
6022 Ben French GT1 Black Hills Power & Light Comp 12490 25000 8 01-01-1980 12-31-2007
6023 Ben French GT2 Black Hills Power & Light Comp 12490 25000 8 01-01-1980 12-31-2007
6024 Ben French GT3 Black Hills Power & Light Comp 12490 25000 8 01-01-1980 12-31-2007
6025 Ben French GT4 Black Hills Power & Light Comp 12490 25000 8 01-01-1980 12-31-2007
6026 Ben French IC1 Black Hills Power & Light Comp 9240 2000 8 01-01-1980 12-31-2004
6032 Osage 2 Black Hills Power & Light Comp 14750 10150 7 01-01-1980 12-31-2028
6033 Osage 3 Black Hills Power & Light Comp 14400 10150 7 01-01-1980 12-31-2028
6060 Boston Bar Diesel 1 British Columbia Hydro & Power 12000 2000 4 01-01-1980 12-31-2025
6065 Burrard Thermal 4 British Columbia Hydro & Power 12500 157000 4 01-01-1980 12-31-2025
6066 Burrard Thermal 5 British Columbia Hydro & Power 12500 157000 4 01-01-1980 12-31-2012
6067 Burrard Thermal 6 British Columbia Hydro & Power 12500 163000 4 01-01-1980 12-31-2009
6077 Keogh GT2 British Columbia Hydro & Power 12600 50000 4 01-01-1980 12-31-2024
6081 Lytton Diesel 1 British Columbia Hydro & Power 11500 3450 4 01-01-1980 12-31-2024
6101 Magnolia 4 Burbank Public Service Departm 11100 32000 3 01-01-1980 12-31-2011
6102 Magnolia 5 Burbank Public Service Departm 10010 22000 3 01-01-1980 12-31-2028
6103 Olive 1 Burbank Public Service Departm 10918 46000 3 01-01-1980 12-31-2011
6104 Olive 2 Burbank Public Service Departm 10080 60000 3 01-01-1980 12-31-2026
6105 Olive 3 Burbank Public Service Departm 14339 24000 3 01-01-1980 12-31-2011
6301 Cheyenne Diesel 1 Cheyenne Light Fuel & Power Co 14000 2000 7 01-01-1980 12-31-2005
6302 Cheyenne Diesel 2 Cheyenne Light Fuel & Power Co 14000 2000 7 01-01-1980 12-31-2006
6303 Cheyenne Diesel 3 Cheyenne Light Fuel & Power Co 14000 2000 7 01-01-1980 12-31-2006
6304 Cheyenne Diesel 4 Cheyenne Light Fuel & Power Co 14000 2000 7 01-01-1980 12-31-2005
6305 Cheyenne Diesel 5 Cheyenne Light Fuel & Power Co 14000 2000 7 01-01-1980 12-31-2006
6306 Valencia GT1 Citizens Utilities Company - A 15445 15800 10 01-01-1980 12-31-2006
6307 Valencia GT2 Citizens Utilities Company - A 16647 15800 10 01-01-1980 12-31-2006
6308 Valencia GT3 Citizens Utilities Company - A 15957 16000 10 01-01-1980 12-31-2006
6310 George Birdsall 1 Colorado Springs Utilities - C 13500 16000 8 01-01-1980 12-31-2006
6311 George Birdsall 2 Colorado Springs Utilities - C 13500 17000 8 01-01-1980 12-31-2006
6312 George Birdsall 3 Colorado Springs Utilities - C 13500 23000 8 01-01-1980 12-31-2007
6315 Martin Drake 4 Colorado Springs Utilities - C 14800 11000 8 01-01-1980 12-31-2004
6365 Bonanza 1 Deseret Generation & Transmiss 10463 420000 11 01-01-1980 12-31-2028
6371 Clover Bar 1 Edmonton Power 12500 165000 13 01-01-1980 12-31-2009
6372 Clover Bar 2 Edmonton Power 12500 165000 13 01-01-1980 12-31-2009
6373 Clover Bar 3 Edmonton Power 12500 165000 13 01-01-1980 12-31-2007
6374 Clover Bar 4 Edmonton Power 12500 165000 13 01-01-1980 12-31-2025
6376 Genesee 2 Edmonton Power 10352 406000 13 01-01-1980 12-31-2028
6377 Rossdale 10 Edmonton Power 14000 72000 13 01-01-1980 12-31-2008
6378 Rossdale 8 Edmonton Power 14000 71000 13 01-01-1980 12-31-2008
6379 Rossdale 9 Edmonton Power 14000 73000 13 01-01-1980 12-31-2007
6380 Copper 1 El Paso Electric Company 15800 71000 9 01-01-1980 12-31-2005
6381 Newman 1 El Paso Electric Company 10300 83000 9 01-01-1980 12-31-2011
6382 Newman 2 El Paso Electric Company 10300 82000 9 01-01-1980 12-31-2011

Appendix J Page J-3 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
6383 Newman 3 El Paso Electric Company 9900 104000 9 01-01-1980 12-31-2011
6384 Newman CC -- 4+CT1+CT2 El Paso Electric Company 8800 240000 9 01-01-1980 12-31-2013
6385 Rio Grande 6 El Paso Electric Company 11300 48000 9 01-01-1980 12-31-2007
6386 Rio Grande 7 El Paso Electric Company 10500 48000 9 01-01-1980 12-31-2009
6387 Rio Grande 8 El Paso Electric Company 9800 151000 9 01-01-1980 12-31-2013
6419 Animas 3 Farmington NM, City of 13500 9000 9 01-01-1980 12-31-2004
6420 Animas 4 Farmington NM, City of 13000 16000 9 01-01-1980 12-31-2005
6430 Grayson 3 Glendale CA, City of Public Se 13000 19000 3 01-01-1980 12-31-2009
6431 Grayson 4 Glendale CA, City of Public Se 11600 44000 3 01-01-1980 12-31-2011
6432 Grayson 5 Glendale CA, City of Public Se 10500 42000 3 01-01-1980 12-31-2013
6433 Grayson 6 Glendale CA, City of Public Se 13000 18000 3 01-01-1980 12-31-2011
6434 Grayson 7 Glendale CA, City of Public Se 12500 21000 3 01-01-1980 12-31-2010
6507 Brawley 1 Imperial Irrigation District - 17600 11000 3 01-01-1980 12-31-2007
6508 Brawley 2 Imperial Irrigation District - 17600 11000 3 01-01-1980 12-31-2007
6509 Coachella 1 Imperial Irrigation District - 14400 20000 3 01-01-1980 12-31-2004
6510 Coachella 2 Imperial Irrigation District - 14400 20000 3 01-01-1980 12-31-2011
6511 Coachella 3 Imperial Irrigation District - 14400 20000 3 01-01-1980 12-31-2011
6512 Coachella 4 Imperial Irrigation District - 14400 20000 3 01-01-1980 12-31-2010
6527 El Centro 3 Imperial Irrigation District - 11500 48000 3 01-01-1980 12-31-2011
6532 Rockwood 1 Imperial Irrigation District - 13400 25000 3 01-01-1980 12-31-2011
6533 Rockwood 2 Imperial Irrigation District - 13400 25000 3 01-01-1980 12-31-2011
6535 Yuma Axis 1 Imperial Irrigation District - 14100 20000 10 01-01-1980 12-31-2007
6539 Lamar Plt 4 Lamar CO, City of 12465 25000 8 01-01-1980 12-31-2007
6549 Logan City 4 Logan UT, City of 15456 700 11 01-01-1980 12-31-2004
6550 Logan City 5A Logan UT, City of 7840 1100 11 01-01-1980 12-31-2028
6552 Logan City 6 Logan UT, City of 14684 2250 11 01-01-1980 12-31-2005
6579 Haynes 2 Los Angeles Department of Wate 9578 222000 3 01-01-1980 12-31-2025
6582 Haynes 5 Los Angeles Department of Wate 9543 341000 3 01-01-1980 12-31-2025
6603 Scattergood 1 Los Angeles Department of Wate 9697 179000 3 01-01-1980 12-31-2025
6604 Scattergood 2 Los Angeles Department of Wate 9795 179000 3 01-01-1980 12-31-2025
6616 Valley 3 Los Angeles Department of Wate 10685 163000 3 01-01-1980 12-31-2011
6617 Valley 4 Los Angeles Department of Wate 10487 160000 3 01-01-1980 12-31-2012
6626 Medicine Hat 10 Medicine Hat, City of 11300 18000 13 01-01-1980 12-31-2025
6627 Medicine Hat 11 Medicine Hat, City of 11300 18000 13 01-01-1980 12-31-2025
6628 Medicine Hat 12 Medicine Hat, City of 16500 32000 13 01-01-1980 12-31-2008
6629 Medicine Hat 3 Medicine Hat, City of 17000 16000 13 01-01-1980 12-31-2006
6630 Medicine Hat 4 Medicine Hat, City of 18000 3000 13 01-01-1980 12-31-2004
6631 Medicine Hat 5 Medicine Hat, City of 11200 19000 13 01-01-1980 12-31-2025
6632 Medicine Hat 6 Medicine Hat, City of 18000 5000 13 01-01-1980 12-31-2005
6633 Medicine Hat 7 Medicine Hat, City of 16500 32000 13 01-01-1980 12-31-2008
6634 Medicine Hat 8 Medicine Hat, City of 10500 40000 13 01-01-1980 12-31-2025
6635 Medicine Hat 9 Medicine Hat, City of 10500 40000 13 01-01-1980 12-31-2025
6753 Allen GT1 Nevada Power Company - NV 12500 76000 14 01-01-1980 12-31-2010
6754 Clark 1 Nevada Power Company - NV 11100 42000 14 01-01-1980 12-31-2009
6755 Clark 2 Nevada Power Company - NV 10350 69000 14 01-01-1980 12-31-2009
6756 Clark 3 Nevada Power Company - NV 11400 70000 14 01-01-1980 12-31-2009
6758 Clark GT4 Nevada Power Company - NV 13000 59000 14 01-01-1980 12-31-2011

Appendix J Page J-4 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
6767 Sun-Peak 1 Nevada Power Company - NV 12300 70000 14 01-01-1980 12-31-2012
6768 Sun-Peak 2 Nevada Power Company - NV 12300 70000 14 01-01-1980 12-31-2012
6769 Sun-Peak 3 Nevada Power Company - NV 12300 70000 14 01-01-1980 12-31-2012
6771 Sunrise 2 Nevada Power Company - NV 13100 76000 14 01-01-1980 12-31-2011
6772 Alameda 1 Northern California Power Agen 16500 25000 2 01-01-1980 12-31-2004
6773 Alameda 2 Northern California Power Agen 16500 25000 2 01-01-1980 12-31-2004
6785 Lodi 1 Northern California Power Agen 14650 25000 2 01-01-1980 12-31-2005
6787 Roseville 1 Northern California Power Agen 15750 25000 2 01-01-1980 12-31-2004
6788 Roseville 2 Northern California Power Agen 15750 25000 2 01-01-1980 12-31-2004
6817 Contra Costa 6 Mirant 9385 340000 2 01-01-1980 12-31-2010
6818 Contra Costa 7 Mirant 9555 340000 2 01-01-1980 12-31-2010
6827 Downieville 1 Pacific Gas & Electric Company 13088 750 2 01-01-1980 12-31-2028
6859 Humboldt Bay 1 Pacific Gas & Electric Company 11913 52000 2 01-01-1980 12-31-2005
6860 Humboldt Bay 2 Pacific Gas & Electric Company 12352 53000 2 01-01-1980 12-31-2004
6861 Humboldt Bay GT2 Pacific Gas & Electric Company 14000 15000 2 01-01-1980 12-31-2005
6862 Humboldt Bay GT3 Pacific Gas & Electric Company 14000 15000 2 01-01-1980 12-31-2005
6863 Hunters Point 2 Pacific Gas & Electric Company 13134 107000 2 01-01-1980 12-31-2005
6864 Hunters Point 3 Pacific Gas & Electric Company 12582 107000 2 01-01-1980 12-31-2005
6865 Hunters Point 4 Pacific Gas & Electric Company 9759 163000 2 01-01-1980 12-31-2010
6866 Hunters Point GT1 Pacific Gas & Electric Company 12080 52000 2 01-01-1980 12-31-2006
6878 Mobile GT 1 Pacific Gas & Electric Company 14000 15000 2 01-01-1980 12-31-2024
6879 Mobile GT 2 Pacific Gas & Electric Company 14000 15000 2 01-01-1980 12-31-2024
6880 Mobile GT 3 Pacific Gas & Electric Company 14000 15000 2 01-01-1980 12-31-2024
6882 Morro Bay 1 Duke Energy 10293 163000 3 01-01-1980 12-31-2013
6883 Morro Bay 2 Duke Energy 10207 163000 3 01-01-1980 12-31-2025
6886 Moss Landing 6 Duke Energy 8882 739000 2 01-01-1980 12-31-2010
6887 Moss Landing 7 Duke Energy 8981 739000 2 01-01-1980 12-31-2012
6891 Oakland 1 Duke Energy 12080 55000 2 01-01-1980 12-31-2007
6892 Oakland 2 Duke Energy 12080 55000 2 01-01-1980 12-31-2009
6893 Oakland 3 Duke Energy 12080 55000 2 01-01-1980 12-31-2009
6901 Pittsburg 1 SEI 10445 163000 2 01-01-1980 12-31-2005
6902 Pittsburg 2 SEI 10161 163000 2 01-01-1980 12-31-2007
6903 Pittsburg 3 SEI 10410 163000 2 01-01-1980 12-31-2005
6904 Pittsburg 4 SEI 10371 163000 2 01-01-1980 12-31-2006
6905 Pittsburg 5 SEI 9653 325000 2 01-01-1980 12-31-2009
6906 Pittsburg 6 SEI 9625 325000 2 01-01-1980 12-31-2009
6907 Pittsburg 7 SEI 9697 720000 2 01-01-1980 12-31-2008
6954 Blundell 1 PacifiCorp 21248 23000 11 01-01-1980 12-31-2010
6956 Carbon 1 PacifiCorp 11200 70000 11 01-01-1980 12-31-2028
6957 Carbon 2 PacifiCorp 10500 105000 11 01-01-1980 12-31-2028
6975 Dave Johnston 2 PacifiCorp 10900 106000 7 01-01-1980 12-31-2028
6976 Dave Johnston 3 PacifiCorp 10700 230000 7 01-01-1980 12-31-2028
6985 Gadsby 1 PacifiCorp 11500 60000 11 01-01-1980 12-31-2004
6986 Gadsby 2 PacifiCorp 11200 75000 11 01-01-1980 12-31-2006
6987 Gadsby 3 PacifiCorp 10500 100000 11 01-01-1980 12-31-2006
7013 Little Mountain 1 PacifiCorp 14500 14000 11 01-01-1980 12-31-2006
7080 Broadway 1 Pasadena CA, City of 11750 42000 3 01-01-1980 12-31-2008

Appendix J Page J-5 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
7081 Broadway 2 Pasadena CA, City of 11200 42000 3 01-01-1980 12-31-2011
7082 Broadway 3 Pasadena CA, City of 10500 66000 3 01-01-1980 12-31-2013
7083 Glenarm GT1 Pasadena CA, City of 12200 26000 3 01-01-1980 12-31-2018
7084 Glenarm GT2 Pasadena CA, City of 12200 26000 3 01-01-1980 12-31-2018
7143 Bonnett 1#1 Provo City Corp - UT 41482 750 11 01-01-1980 12-31-2004
7144 Bonnett 1#2 Provo City Corp - UT 41482 750 11 01-01-1980 12-31-2004
7145 Bonnett 1#3 Provo City Corp - UT 41482 750 11 01-01-1980 12-31-2004
7146 Bonnett 1#4 Provo City Corp - UT 41482 750 11 01-01-1980 12-31-2004
7147 Bonnett 2 Provo City Corp - UT 41482 2000 11 01-01-1980 12-31-2004
7148 Bonnett 3 Provo City Corp - UT 41482 7000 11 01-01-1980 12-31-2004
7154 Alamosa CT1 Public Service Company of Colo 15070 17000 8 01-01-1980 12-31-2009
7155 Alamosa CT2 Public Service Company of Colo 14060 19000 8 01-01-1980 12-31-2009
7158 Arapahoe 1 Public Service Company of Colo 11730 45000 8 01-01-1980 12-31-2028
7159 Arapahoe 2 Public Service Company of Colo 11700 45000 8 01-01-1980 12-31-2028
7171 Cameo 1 Public Service Company of Colo 12440 23700 8 01-01-1980 12-31-2028
7177 Cherokee IC1 Public Service Company of Colo 14000 2750 8 01-01-1980 12-31-2006
7178 Cherokee IC2 Public Service Company of Colo 14000 2750 8 01-01-1980 12-31-2006
7184 Fort Lupton 1 Public Service Company of Colo 14150 50000 8 01-01-1980 12-31-2009
7185 Fort Lupton 2 Public Service Company of Colo 13970 50000 8 01-01-1980 12-31-2009
7186 Fruita 1 Public Service Company of Colo 14820 20000 8 01-01-1980 12-31-2009
7216 Valmont 5 Public Service Company of Colo 10050 189000 8 01-01-1980 12-31-2008
7217 Valmont 6 Public Service Company of Colo 13160 53000 8 01-01-1980 12-31-2010
7219 Zuni 1 Public Service Company of Colo 13630 39000 8 01-01-1980 12-31-2007
7220 Zuni 2 Public Service Company of Colo 13440 68000 8 01-01-1980 12-31-2007
7221 Las Vegas 1 Public Service Company of New 15752 20000 9 01-01-1980 12-31-2004
7222 Reeves 1 Public Service Company of New 11143 44000 9 01-01-1980 12-31-2009
7223 Reeves 2 Public Service Company of New 10972 44000 9 01-01-1980 12-31-2009
7224 Reeves 3 Public Service Company of New 14690 66000 9 01-01-1980 12-31-2006
7225 San Juan 1 Public Service Company of New 11255 316000 9 01-01-1980 12-31-2028
7226 San Juan 2 Public Service Company of New 12869 312000 9 01-01-1980 12-31-2006
7227 San Juan 3 Public Service Company of New 12258 488000 9 01-01-1980 12-31-2012
7338 Raton 4 Raton Public Service Company - 18100 4000 9 01-01-1980 12-31-2004
7339 Raton 5 Raton Public Service Company - 14200 8000 9 01-01-1980 12-31-2005
7357 McClellan 1 Sacramento Municipal Utility D 13695 50000 2 01-01-1980 12-31-2012
7379 Agua Fria 1 Salt River Project - AZ 10277 114000 10 01-01-1980 12-31-2010
7380 Agua Fria 2 Salt River Project - AZ 10346 114000 10 01-01-1980 12-31-2007
7381 Agua Fria 3 Salt River Project - AZ 10055 184000 10 01-01-1980 12-31-2011
7382 Agua Fria 4 Salt River Project - AZ 11788 87000 10 01-01-1980 12-31-2013
7383 Agua Fria 5 Salt River Project - AZ 13524 75000 10 01-01-1980 12-31-2010
7384 Agua Fria 6 Salt River Project - AZ 13044 75000 10 01-01-1980 12-31-2011
7392 Kyrene 1 Salt River Project - AZ 12827 34000 10 01-01-1980 12-31-2007
7393 Kyrene 2 Salt River Project - AZ 11323 72000 10 01-01-1980 12-31-2008
7394 Kyrene KY4 Salt River Project - AZ 13502 69000 10 01-01-1980 12-31-2009
7395 Kyrene KY5 Salt River Project - AZ 12867 61000 10 01-01-1980 12-31-2011
7396 Kyrene KY6 Salt River Project - AZ 13067 60000 10 01-01-1980 12-31-2010
7403 Santan 1 Salt River Project - AZ 9276 87000 10 01-01-1980 12-31-2012
7404 Santan 2 Salt River Project - AZ 8894 85000 10 01-01-1980 12-31-2011

Appendix J Page J-6 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
7412 Division 1 San Diego Gas & Electric Compa 16000 19000 3 01-01-1980 12-31-2006
7413 El Cajon 1 San Diego Gas & Electric Compa 16300 20000 3 01-01-1980 12-31-2004
7414 Encina 1 Dynegy and NRG 10300 107000 3 01-01-1980 12-31-2008
7415 Encina 2 Dynegy and NRG 10300 104000 3 01-01-1980 12-31-2008
7416 Encina 3 Dynegy and NRG 10400 110000 3 01-01-1980 12-31-2007
7417 Encina 4 Dynegy and NRG 10200 300000 3 01-01-1980 12-31-2006
7418 Encina 5 Dynegy and NRG 9620 330000 3 01-01-1980 12-31-2011
7419 Encina GT1 Dynegy and NRG 16800 18000 3 01-01-1980 12-31-2004
7422 Kearny 1 San Diego Gas & Electric Compa 15500 20000 3 01-01-1980 12-31-2006
7423 Kearny 2 San Diego Gas & Electric Compa 16400 78000 3 01-01-1980 12-31-2004
7424 Kearny 3 San Diego Gas & Electric Compa 16200 78000 3 01-01-1980 12-31-2006
7425 Miramar 1 San Diego Gas & Electric Compa 15100 47000 3 01-01-1980 12-31-2006
7427 Naval Training Ctr 1 Sithe 15500 20000 3 01-01-1980 12-31-2004
7428 North Island 1 San Diego Gas & Electric Compa 15100 22000 3 01-01-1980 12-31-2006
7429 North Island 2 San Diego Gas & Electric Compa 15100 22000 3 01-01-1980 12-31-2006
7430 South Bay 1 DENA - Port of San Diego 9500 146000 3 01-01-1980 12-31-2010
7431 South Bay 2 DENA - Port of San Diego 9800 150000 3 01-01-1980 12-31-2009
7432 South Bay 3 DENA - Port of San Diego 9900 175000 3 01-01-1980 12-31-2010
7433 South Bay 4 DENA - Port of San Diego 11400 222000 3 01-01-1980 12-31-2007
7434 South Bay GT1 DENA - Port of San Diego 13400 22000 3 01-01-1980 12-31-2006
7480 Battle Mtn 1 Sierra Pacific Power Company - 10180 2000 12 01-01-1980 12-31-2025
7481 Battle Mtn 2 Sierra Pacific Power Company - 10180 2000 12 01-01-1980 12-31-2025
7482 Battle Mtn 3 Sierra Pacific Power Company - 10180 2000 12 01-01-1980 12-31-2025
7483 Battle Mtn 4 Sierra Pacific Power Company - 10180 2000 12 01-01-1980 12-31-2025
7485 Brunswick 1 Sierra Pacific Power Company - 10428 2000 12 01-01-1980 12-31-2025
7486 Brunswick 2 Sierra Pacific Power Company - 10428 2000 12 01-01-1980 12-31-2025
7487 Brunswick 3 Sierra Pacific Power Company - 10428 2000 12 01-01-1980 12-31-2025
7498 Fort Churchill 1 Sierra Pacific Power Company - 10183 113000 12 01-01-1980 12-31-2009
7499 Fort Churchill 2 Sierra Pacific Power Company - 10295 113000 12 01-01-1980 12-31-2010
7502 Kings Beach 1 Sierra Pacific Power Company - 11100 2750 2 01-01-1980 12-31-2028
7503 Kings Beach 2 Sierra Pacific Power Company - 11100 2750 2 01-01-1980 12-31-2028
7504 Kings Beach 3 Sierra Pacific Power Company - 11100 2750 2 01-01-1980 12-31-2028
7505 Kings Beach 4 Sierra Pacific Power Company - 11100 2750 2 01-01-1980 12-31-2028
7506 Kings Beach 5 Sierra Pacific Power Company - 11100 2750 2 01-01-1980 12-31-2028
7507 Kings Beach 6 Sierra Pacific Power Company - 11100 2750 2 01-01-1980 12-31-2028
7514 Portola 1 Sierra Pacific Power Company - 10336 2000 2 01-01-1980 12-31-2028
7515 Portola 2 Sierra Pacific Power Company - 10336 2000 2 01-01-1980 12-31-2028
7516 Portola 3 Sierra Pacific Power Company - 10336 2000 2 01-01-1980 12-31-2028
7522 Tracy 3 Sierra Pacific Power Company - 10423 108000 12 01-01-1980 12-31-2008
7523 Tracy 4 Sierra Pacific Power Company - 11971 83000 12 01-01-1980 12-31-2012
7524 Tracy GT1 Sierra Pacific Power Company - 15300 11000 12 01-01-1980 12-31-2007
7525 Tracy GT2 Sierra Pacific Power Company - 15000 11000 12 01-01-1980 12-31-2007
7526 Tracy GT3 Sierra Pacific Power Company - 11819 83000 12 01-01-1980 12-31-2010
7527 Tracy ST1 Sierra Pacific Power Company - 12220 53000 12 01-01-1980 12-31-2007
7528 Tracy ST2 Sierra Pacific Power Company - 11066 83000 12 01-01-1980 12-31-2009
7529 Valley Road 1 Sierra Pacific Power Company - 10215 2000 12 01-01-1980 12-31-2025
7530 Valley Road 2 Sierra Pacific Power Company - 10215 2000 12 01-01-1980 12-31-2025

Appendix J Page J-7 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
7531 Valley Road 3 Sierra Pacific Power Company - 10215 2000 12 01-01-1980 12-31-2025
7532 Valmy 1 Sierra Pacific Power Company - 10047 258000 12 01-01-1980 12-31-2028
7537 Winnemucca 1 Sierra Pacific Power Company - 15900 15000 12 01-01-1980 12-31-2008
7543 Alamitos 1 Williams Energy 10956 175000 3 01-01-1980 12-31-2013
7544 Alamitos 2 Williams Energy 10658 175000 3 01-01-1980 12-31-2012
7545 Alamitos 3 Williams Energy 10236 320000 3 01-01-1980 12-31-2025
7546 Alamitos 4 Williams Energy 9690 320000 3 01-01-1980 12-31-2012
7549 Alamitos 7 Williams Energy 18510 147000 3 01-01-1980 12-31-2007
7589 Alta Power 1 (Coolwater) Reliant Energy 10428 65000 3 01-01-1980 12-31-2011
7590 Alta Power 2 (Coolwater) Reliant Energy 10430 81000 3 01-01-1980 12-31-2013
7593 El Segundo 1 Dynegy and NRG 10667 175000 3 01-01-1980 12-31-2010
7594 El Segundo 2 Dynegy and NRG 10620 175000 3 01-01-1980 12-31-2011
7595 El Segundo 3 Dynegy and NRG 9723 335000 3 01-01-1980 12-31-2011
7596 El Segundo 4 Dynegy and NRG 9593 335000 3 01-01-1980 12-31-2012
7597 Ellwood 1 Southern California Edison Com 14950 53000 3 01-01-1980 12-31-2009
7598 Mountain Vista 1 (Etiwanda) Reliant Energy 11143 132000 3 01-01-1980 12-31-2011
7599 Mountain Vista 2 (Etiwanda) Reliant Energy 11151 132000 3 01-01-1980 12-31-2010
7600 Mountain Vista 3 (Etiwanda) Reliant Energy 9616 320000 3 01-01-1980 12-31-2012
7601 Mountain Vista 4 (Etiwanda) Reliant Energy 9601 320000 3 01-01-1980 12-31-2013
7602 Mountain Vista GT5 (Etiwanda) Reliant Energy 20006 142000 3 01-01-1980 12-31-2005
7605 Riverside Canal Power Co 1 THERMO ECOTEK 13280 32000 3 01-01-1980 12-31-2008
7606 Riverside Canal Power Co 2 THERMO ECOTEK 13280 33000 3 01-01-1980 12-31-2008
7607 Riverside Canal Power Co 3 THERMO ECOTEK 12320 44000 3 01-01-1980 12-31-2009
7608 Riverside Canal Power Co 4 THERMO ECOTEK 12300 45000 3 01-01-1980 12-31-2010
7609 Huntington Beach 1 AES 9613 225000 3 01-01-1980 12-31-2012
7610 Huntington Beach 2 AES 9775 225000 3 01-01-1980 12-31-2012
7611 Huntington Beach GT5 AES 19997 110000 3 01-01-1980 12-31-2007
7634 Ocean Vista 1 (Mandalay) Reliant Energy 9519 215000 3 01-01-1980 12-31-2013
7635 Ocean Vista 2 (Mandalay) Reliant Energy 9579 215000 3 01-01-1980 12-31-2012
7636 Ocean Vista 3 (Mandalay) Reliant Energy 14393 147000 3 01-01-1980 12-31-2011
7665 Redondo Beach 5 AES 10374 175000 3 01-01-1980 12-31-2013
7666 Redondo Beach 6 AES 10716 175000 3 01-01-1980 12-31-2010
7667 Redondo Beach 7 AES 9559 480000 3 01-01-1980 12-31-2013
7668 Redondo Beach 8 AES 9500 480000 3 01-01-1980 12-31-2013
7671 MOUNTAINVIEW 1 THERMO ECOTEK 11523 63000 3 01-01-1980 12-31-2011
7672 MOUNTAINVIEW 2 THERMO ECOTEK 11577 63000 3 01-01-1980 12-31-2011
7733 Sundance 1 TransAlta Utilities Corporatio 10401 293000 13 01-01-1980 12-31-2028
7734 Sundance 2 TransAlta Utilities Corporatio 10400 294000 13 01-01-1980 12-31-2028
7737 Sundance 5 TransAlta Utilities Corporatio 10358 371000 13 01-01-1980 12-31-2028
7739 Wabamun 1 TransAlta Utilities Corporatio 11501 67000 13 01-01-1980 12-31-2027
7740 Wabamun 2 TransAlta Utilities Corporatio 11500 67000 13 01-01-1980 12-31-2027
7741 Wabamun 3 TransAlta Utilities Corporatio 10503 147000 13 01-01-1980 12-31-2027
7742 Wabamun 4 TransAlta Utilities Corporatio 10402 293000 13 01-01-1980 12-31-2027
7745 Trinidad 4 Trinidad CO, City of 13000 3000 8 01-01-1980 12-31-2005
7750 Nucla 1 Tri-State Generation & Transmi 11670 12000 8 01-01-1980 12-31-2028
7751 Nucla 2 Tri-State Generation & Transmi 11670 12000 8 01-01-1980 12-31-2028
7752 Nucla 3 Tri-State Generation & Transmi 11670 12000 8 01-01-1980 12-31-2028

Appendix J Page J-8 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
7754 Irvington 1 Tucson Electric Power Company 9864 81000 10 01-01-1980 12-31-2010
7755 Irvington 2 Tucson Electric Power Company 10182 81000 10 01-01-1980 12-31-2011
7756 Irvington 3 Tucson Electric Power Company 10822 105000 10 01-01-1980 12-31-2008
7757 Irvington 4 Tucson Electric Power Company 10219 156000 10 01-01-1980 12-31-2007
7758 Irvington GT1 Tucson Electric Power Company 15000 24000 10 01-01-1980 12-31-2009
7759 Irvington GT2 Tucson Electric Power Company 15000 25000 10 01-01-1980 12-31-2009
7760 Irvington GT3 Tucson Electric Power Company 15000 25000 10 01-01-1980 12-31-2009
7761 North Loop 1 Tucson Electric Power Company 15000 25000 10 01-01-1980 12-31-2006
7762 North Loop 2 Tucson Electric Power Company 15000 25000 10 01-01-1980 12-31-2009
7763 North Loop 3 Tucson Electric Power Company 15000 23000 10 01-01-1980 12-31-2009
7936 Los Alamos Unit 1 US ERDA-Los Alamos Area Office 14024 5000 9 01-01-1980 12-31-2004
7937 Los Alamos Unit 2 US ERDA-Los Alamos Area Office 14024 4000 9 01-01-1980 12-31-2004
7938 Los Alamos Unit 3 US ERDA-Los Alamos Area Office 13475 9000 9 01-01-1980 12-31-2004
7945 Vernon VER1 Vernon CA, City of 8000 4200 3 01-01-1980 12-31-2028
7946 Vernon VER2 Vernon CA, City of 8000 4200 3 01-01-1980 12-31-2028
7947 Vernon VER3 Vernon CA, City of 8000 4200 3 01-01-1980 12-31-2028
7948 Vernon VER4 Vernon CA, City of 8000 4200 3 01-01-1980 12-31-2028
7949 Vernon VER5 Vernon CA, City of 8000 4200 3 01-01-1980 12-31-2028
7950 Vernon VER6 Vernon CA, City of 12200 5400 3 01-01-1980 12-31-2018
7951 Vernon VER7 Vernon CA, City of 12200 5400 3 01-01-1980 12-31-2018
8006 Pueblo 6 West Plains Energy 13700 20000 8 01-01-1980 12-31-2007
8017 W N Clark 1 West Plains Energy 13100 17000 8 01-01-1980 12-31-2028
8018 W N Clark 2 West Plains Energy 12690 24000 8 01-01-1980 12-31-2028
8103 Aurora Project GTG - Mildred Lake AB Syncrude 8800 80000 13 07-07-2000 12-31-2025
8118 Delta-Person Project (Albuquerque) Delta Energy+John Hancock Life 8750 140000 9 05-01-2000 12-31-2011
8121 Drywood Plant Canadian Hydro 9000 6000 13 09-01-1999 12-31-2025
8129 Fort St Vrain Phase 1 repowering New Century Energies 8800 240000 8 05-01-1998 12-31-2013
8130 Fort St Vrain Phase 2 New Century Energies 8800 240000 8 05-01-1999 12-31-2013
8134 Fredonia 1 Puget Sound Energy - WA 10711 123636 1 01-01-1980 12-31-2008
8135 Fredonia 2 Puget Sound Energy - WA 10711 123636 1 01-01-1980 12-31-2008
8137 Gold Creek power plant TransCanada 9000 6000 13 07-01-2000 12-31-2025
8155 Poplar Hill ATCO Power (IPP) 9503 43000 13 06-30-1999 12-31-2025
8157 Rainbow Lake (ATCO Power) ATCO Power (IPP) 9503 43000 13 06-30-1999 12-31-2025
8172 Whitehorn 2 Puget Sound Energy - WA 10600 88879 1 01-01-1980 12-31-2009
8173 Whitehorn 3 Puget Sound Energy - WA 10600 88879 1 01-01-1980 12-31-2009
8270 COSO ENERGY DEV 4-6 CAL CAITHNESS ENERGY LLC 20000 84000 3 01-01-1980 12-31-2028
8271 COSO ENERGY DEV 7-9 CAL CAITHNESS ENERGY LLC 20000 76000 3 01-01-1980 12-31-2028
8272 COSO FINANCE PARTNERS 1- 3 CAITHNESS ENERGY LLC 20000 80000 3 01-01-1980 12-31-2028
8285 DEL RANCH LTD NILAND#2 CALENERGY 20000 38000 3 01-01-1980 12-31-2028
8307 ELMORE LTD CALENERGY 20000 38000 3 01-01-1980 12-31-2028
8334 GEM RESOURCES A
GEO EAST MESA LIMITED
PARTNERS 20000 20000 3 01-01-1980 12-31-2028
8335 GEM RESOURCES B
GEO EAST MESA LIMITED
PARTNERS 20000 20000 3 01-01-1980 12-31-2028
8372 HEBER GEO CALPINE/ERC 20000 47000 3 01-01-1980 12-31-2028
8408 LEATHERS LP CALENERGY 20000 38000 3 01-01-1980 12-31-2028
8501 ORMESA GEOTHERMAL II FPL ENERGY, INC 20000 18500 3 01-01-1980 12-31-2028

Appendix J Page J-9 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
8502 ORMESA I IE IH OESI POWER CORPORATION 20000 24000 3 01-01-1980 12-31-2028
8503 ORMESA IE OESI POWER CORPORATION 20000 38000 3 01-01-1980 12-31-2028
8504 ORMESA IH OESI POWER CORPORATION 20000 6500 3 01-01-1980 12-31-2028
8592 SECOND IMPERIAL GEO OGDEN POWER CORPORATION 20000 37000 3 01-01-1980 12-31-2028
8684 Valley 1 Los Angeles Department of Wate 10685 95000 3 01-01-1980 12-31-2011
8685 Valley 2 Los Angeles Department of Wate 10685 99000 3 01-01-1980 12-31-2011
8692 VULCAN BN GEO CALENERGY 20000 34000 3 01-01-1980 12-31-2028
8745 Biosphere 2 Center #G-4 Decisions Investments Corp 10000 1500 10 04-01-2000 12-31-2004
8747 Holly #5 Holly City of 10000 400 8 06-01-2000 12-31-2005
8755 Athol Kootenai Electric 10000 1640 1 03-01-2001 12-31-2028
8756 Bains Bains, LLC 10000 2500 1 05-01-2001 12-31-2006
8763 Drywood Canadian Gas & Electric 10000 6000 13 01-01-1980 12-31-2025
8770 Fort Nelson TransAlta 10000 45000 13 01-01-2000 12-31-2025
8784 Red Earth Creek Area Columbia Power Systems 9500 4000 13 01-01-1980 12-31-2004
8789 Springfield ICs Springfield Utility Board 10000 26700 1 04-01-2001 12-31-2011
8800 Calgary Energy Centre Calpine 8500 250000 13 12-01-2002 12-31-2013
8804 Cavalier Power Station PanCanadian 9500 106000 13 09-01-2001 12-31-2010
8811 Drywood Exp Canadian Gas & Electric 10000 7000 13 09-01-2001 12-31-2025
8813 Elmworth Area Northstone Power Corp 9500 15000 13 10-01-2001 12-31-2004
8815 Gillette Upgrade Black Hills 10000 10000 7 06-01-2001 12-31-2009
8834 Petitt Industrial Park California NEO 11000 49000 2 06-01-2001 12-31-2011
8839 Red Deer (A) API Grain Processors 12000 3500 13 06-01-2001 12-31-2007
8840 Red Deer (B) Collicutt Hanover Servcies 12000 2000 13 10-01-2001 12-31-2007
8847 Sturgeon Addition ATCO 10000 92000 13 12-01-2001 12-31-2025
8851 Taber area Maxim Energy Corp 10000 8500 13 12-01-2001 12-31-2025
8853 University of CA Riverside Southern States Power Co Inc 10000 6000 3 08-01-2001 12-31-2028
8854 Valleyview (AB) ATCO 9000 92000 13 11-01-2001 12-31-2011
8859 Sturgeon ATCO 10000 18000 13 01-01-1980 12-31-2025
8956 Cipres 1-2 Comision Federal de Electricidad 10000 54860 18 01-01-1980 12-31-2011
8957 Mexicali 1 Comision Federal de Electricidad 10000 31200 18 01-01-1980 12-31-2004
8958 Mexicali 2-3 Comision Federal de Electricidad 10000 41300 18 01-01-1980 12-31-2005
8959 Pdte Juarez 1-6 Comision Federal de Electricidad 9500 620000 18 01-01-1980 12-31-2012
8960 Pdte Juarez GT1-2 Comision Federal de Electricidad 10000 63220 18 01-01-1980 12-31-2011
9003 Grays Harbor Co PUD ICs Grays Harbor PUD 10000 12000 1 07-01-2001 12-31-2009
9004 Gunkel Orchards Gunkel Orchards 10000 3200 1 05-01-2001 12-31-2028
9010 Titan Titan 10000 15000 1 07-01-2001 12-31-2011
9011 Gillette GT 1 Black Hills 8600 40000 7 07-01-2000 12-31-2011
9012 Gillette GT 2 Black Hills 8600 40000 7 05-01-2001 12-31-2007
9015 Valmont Plant Expansion (Boulder) Black Hills 10000 40000 8 07-01-2001 12-31-2013
9024 Wyodak Expansion Black Hills 11680 40000 7 05-01-2001 12-31-2009
9153 BHG Gas Turbine #2 Black Hills Corporation 10000 34000 7 06-01-2001 12-31-2008
9154 Bountiful City 1A Bountiful City City of 11000 5100 11 06-01-2001 12-31-2007
9348 OR SBC Wind 03 N/A 0 30000 1 12-31-2003 12-31-2049
9349 OR SBC Wind 04 N/A 0 30000 1 12-31-2004 12-31-2049
9350 OR SBC Wind 05 N/A 0 30000 1 12-31-2005 12-31-2049
9351 OR SBC Wind 06 N/A 0 30000 1 12-31-2006 12-31-2049
9352 OR SBC Wind 07 N/A 0 30000 1 12-31-2007 12-31-2049

Appendix J Page J-10 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
9353 OR SBC Wind 08 N/A 0 30000 1 12-31-2008 12-31-2049
9354 OR SBC Wind 09 N/A 0 30000 1 12-31-2009 12-31-2049
9355 OR SBC Wind 10 N/A 0 30000 1 12-31-2010 12-31-2049
9356 OR SBC Wind 11 N/A 0 30000 1 12-31-2011 12-31-2049
9357 OR SBC Wind 12 N/A 0 30000 1 12-31-2012 12-31-2049
9358 CAN SBC Wind 03 N/A 0 90000 2 12-31-2003 12-31-2049
9359 CAN SBC Wind 04 N/A 0 90000 2 12-31-2004 12-31-2049
9360 CAN SBC Wind 05 N/A 0 90000 2 12-31-2005 12-31-2049
9361 CAN SBC Wind 06 N/A 0 90000 2 12-31-2006 12-31-2049
9362 CAN SBC Wind 07 N/A 0 90000 2 12-31-2007 12-31-2049
9363 CAN SBC Wind 08 N/A 0 90000 2 12-31-2008 12-31-2049
9364 CAN SBC Wind 09 N/A 0 90000 2 12-31-2009 12-31-2049
9365 CAN SBC Wind 10 N/A 0 90000 2 12-31-2010 12-31-2049
9366 CAN SBC Wind 11 N/A 0 90000 2 12-31-2011 12-31-2049
9367 CAN SBC Wind 12 N/A 0 90000 2 12-31-2012 12-31-2049
9368 CAS SBC Wind 03 N/A 0 90000 3 12-31-2003 12-31-2049
9369 CAS SBC Wind 04 N/A 0 90000 3 12-31-2004 12-31-2049
9370 CAS SBC Wind 05 N/A 0 90000 3 12-31-2005 12-31-2049
9371 CAS SBC Wind 06 N/A 0 90000 3 12-31-2006 12-31-2049
9372 CAS SBC Wind 07 N/A 0 90000 3 12-31-2007 12-31-2049
9373 CAS SBC Wind 08 N/A 0 90000 3 12-31-2008 12-31-2049
9374 CAS SBC Wind 09 N/A 0 90000 3 12-31-2009 12-31-2049
9375 CAS SBC Wind 10 N/A 0 90000 3 12-31-2010 12-31-2049
9376 CAS SBC Wind 11 N/A 0 90000 3 12-31-2011 12-31-2049
9377 CAS SBC Wind 12 N/A 0 90000 3 12-31-2012 12-31-2049
9378 MT SBC Wind 03 N/A 0 3000 6 12-31-2003 12-31-2049
9379 MT SBC Wind 04 N/A 0 3000 6 12-31-2004 12-31-2049
9380 MT SBC Wind 05 N/A 0 3000 6 12-31-2005 12-31-2049
9381 MT SBC Wind 06 N/A 0 3000 6 12-31-2006 12-31-2049
9382 MT SBC Wind 07 N/A 0 3000 6 12-31-2007 12-31-2049
9383 MT SBC Wind 08 N/A 0 3000 6 12-31-2008 12-31-2049
9384 MT SBC Wind 09 N/A 0 3000 6 12-31-2009 12-31-2049
9385 MT SBC Wind 10 N/A 0 3000 6 12-31-2010 12-31-2049
9386 MT SBC Wind 11 N/A 0 3000 6 12-31-2011 12-31-2049
9387 MT SBC Wind 12 N/A 0 3000 6 12-31-2012 12-31-2049
9388 NM SBC Wind 03 N/A 0 12000 9 12-31-2003 12-31-2049
9389 NM SBC Wind 04 N/A 0 12000 9 12-31-2004 12-31-2049
9390 NM SBC Wind 05 N/A 0 12000 9 12-31-2005 12-31-2049
9391 NM SBC Wind 06 N/A 0 12000 9 12-31-2006 12-31-2049
9392 NM SBC Wind 07 N/A 0 12000 9 12-31-2007 12-31-2049
9393 NM SBC Wind 08 N/A 0 12000 9 12-31-2008 12-31-2049
9394 NM SBC Wind 09 N/A 0 12000 9 12-31-2009 12-31-2049
9395 NM SBC Wind 10 N/A 0 12000 9 12-31-2010 12-31-2049
9396 NM SBC Wind 11 N/A 0 12000 9 12-31-2011 12-31-2049
9397 NM SBC Wind 12 N/A 0 12000 9 12-31-2012 12-31-2049
9398 AZ SBC Wind 03 N/A 0 70000 10 12-31-2003 12-31-2049
9399 AZ SBC Wind 04 N/A 0 70000 10 12-31-2004 12-31-2049

Appendix J Page J-11 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
9400 AZ SBC Wind 05 N/A 0 70000 10 12-31-2005 12-31-2049
9401 AZ SBC Wind 06 N/A 0 70000 10 12-31-2006 12-31-2049
9402 AZ SBC Wind 07 N/A 0 70000 10 12-31-2007 12-31-2049
9403 AZ SBC Wind 08 N/A 0 70000 10 12-31-2008 12-31-2049
9404 AZ SBC Wind 09 N/A 0 70000 10 12-31-2009 12-31-2049
9405 AZ SBC Wind 10 N/A 0 70000 10 12-31-2010 12-31-2049
9406 AZ SBC Wind 11 N/A 0 70000 10 12-31-2011 12-31-2049
9407 AZ SBC Wind 12 N/A 0 70000 10 12-31-2012 12-31-2049
AURORANewRes 1 New No 2916 Coal 400 MW na 9426 400000 6 01-01-2010 12-31-2049
AURORANewRes 10 New No 5352 CCCT 280 MW na 6233 280000 1 01-01-2022 12-31-2049
AURORANewRes 100 New No 5727 CCCT 280 MW na 6619 280000 3 01-01-2012 12-31-2049
AURORANewRes 101 New No 5729 CCCT 280 MW na 6619 280000 3 01-01-2012 12-31-2049
AURORANewRes 102 New No 5730 CCCT 280 MW na 6619 280000 3 01-01-2012 12-31-2049
AURORANewRes 103 New No 5731 CCCT 280 MW na 6619 280000 3 01-01-2012 12-31-2049
AURORANewRes 104 New No 5732 CCCT 280 MW na 6619 280000 3 01-01-2012 12-31-2049
AURORANewRes 105 New No 5733 CCCT 280 MW na 6619 280000 3 01-01-2012 12-31-2049
AURORANewRes 106 New No 5734 CCCT 280 MW na 6619 280000 3 01-01-2012 12-31-2049
AURORANewRes 107 New No 5735 CCCT 280 MW na 6619 280000 3 01-01-2012 12-31-2049
AURORANewRes 108 New No 5736 CCCT 280 MW na 6580 280000 3 01-01-2013 12-31-2049
AURORANewRes 109 New No 5737 CCCT 280 MW na 6580 280000 3 01-01-2013 12-31-2049
AURORANewRes 11 New No 5353 CCCT 280 MW na 6233 280000 1 01-01-2022 12-31-2049
AURORANewRes 110 New No 5738 CCCT 280 MW na 6580 280000 3 01-01-2013 12-31-2049
AURORANewRes 111 New No 5739 CCCT 280 MW na 6580 280000 3 01-01-2013 12-31-2049
AURORANewRes 112 New No 5742 CCCT 280 MW na 6580 280000 3 01-01-2013 12-31-2049
AURORANewRes 113 New No 5743 CCCT 280 MW na 6580 280000 3 01-01-2013 12-31-2049
AURORANewRes 114 New No 5745 CCCT 280 MW na 6580 280000 3 01-01-2013 12-31-2049
AURORANewRes 115 New No 5746 CCCT 280 MW na 6540 280000 3 01-01-2014 12-31-2049
AURORANewRes 116 New No 5747 CCCT 280 MW na 6540 280000 3 01-01-2014 12-31-2049
AURORANewRes 117 New No 5748 CCCT 280 MW na 6540 280000 3 01-01-2014 12-31-2049
AURORANewRes 118 New No 5749 CCCT 280 MW na 6540 280000 3 01-01-2014 12-31-2049
AURORANewRes 119 New No 5753 CCCT 280 MW na 6540 280000 3 01-01-2014 12-31-2049
AURORANewRes 12 New No 5368 CCCT 280 MW na 6158 280000 1 01-01-2024 12-31-2049
AURORANewRes 120 New No 5754 CCCT 280 MW na 6540 280000 3 01-01-2014 12-31-2049
AURORANewRes 121 New No 5755 CCCT 280 MW na 6540 280000 3 01-01-2014 12-31-2049
AURORANewRes 122 New No 5756 CCCT 280 MW na 6501 280000 3 01-01-2015 12-31-2049
AURORANewRes 123 New No 5757 CCCT 280 MW na 6501 280000 3 01-01-2015 12-31-2049
AURORANewRes 124 New No 5758 CCCT 280 MW na 6501 280000 3 01-01-2015 12-31-2049
AURORANewRes 125 New No 5759 CCCT 280 MW na 6501 280000 3 01-01-2015 12-31-2049
AURORANewRes 126 New No 5766 CCCT 280 MW na 6462 280000 3 01-01-2016 12-31-2049
AURORANewRes 127 New No 5767 CCCT 280 MW na 6462 280000 3 01-01-2016 12-31-2049
AURORANewRes 128 New No 5768 CCCT 280 MW na 6462 280000 3 01-01-2016 12-31-2049
AURORANewRes 129 New No 5772 CCCT 280 MW na 6462 280000 3 01-01-2016 12-31-2049
AURORANewRes 13 New No 5378 CCCT 280 MW na 6121 280000 1 01-01-2025 12-31-2049
AURORANewRes 130 New No 5774 CCCT 280 MW na 6462 280000 3 01-01-2016 12-31-2049
AURORANewRes 131 New No 5776 CCCT 280 MW na 6423 280000 3 01-01-2017 12-31-2049
AURORANewRes 132 New No 5777 CCCT 280 MW na 6423 280000 3 01-01-2017 12-31-2049
AURORANewRes 133 New No 5778 CCCT 280 MW na 6423 280000 3 01-01-2017 12-31-2049

Appendix J Page J-12 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 134 New No 5779 CCCT 280 MW na 6423 280000 3 01-01-2017 12-31-2049
AURORANewRes 135 New No 5780 CCCT 280 MW na 6423 280000 3 01-01-2017 12-31-2049
AURORANewRes 136 New No 5786 CCCT 280 MW na 6385 280000 3 01-01-2018 12-31-2049
AURORANewRes 137 New No 5787 CCCT 280 MW na 6385 280000 3 01-01-2018 12-31-2049
AURORANewRes 138 New No 5788 CCCT 280 MW na 6385 280000 3 01-01-2018 12-31-2049
AURORANewRes 139 New No 5789 CCCT 280 MW na 6385 280000 3 01-01-2018 12-31-2049
AURORANewRes 14 New No 5380 CCCT 280 MW na 6121 280000 1 01-01-2025 12-31-2049
AURORANewRes 140 New No 5790 CCCT 280 MW na 6385 280000 3 01-01-2018 12-31-2049
AURORANewRes 141 New No 5798 CCCT 280 MW na 6346 280000 3 01-01-2019 12-31-2049
AURORANewRes 142 New No 5799 CCCT 280 MW na 6346 280000 3 01-01-2019 12-31-2049
AURORANewRes 143 New No 5800 CCCT 280 MW na 6346 280000 3 01-01-2019 12-31-2049
AURORANewRes 144 New No 5801 CCCT 280 MW na 6346 280000 3 01-01-2019 12-31-2049
AURORANewRes 145 New No 5804 CCCT 280 MW na 6346 280000 3 01-01-2019 12-31-2049
AURORANewRes 146 New No 5806 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 147 New No 5807 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 148 New No 5808 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 149 New No 5809 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 15 New No 5386 CCCT 280 MW na 6085 280000 1 01-01-2026 12-31-2049
AURORANewRes 150 New No 5810 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 151 New No 5811 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 152 New No 5812 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 153 New No 5813 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 154 New No 5814 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 155 New No 5815 CCCT 280 MW na 6308 280000 3 01-01-2020 12-31-2049
AURORANewRes 156 New No 5820 CCCT 280 MW na 6270 280000 3 01-01-2021 12-31-2049
AURORANewRes 157 New No 5821 CCCT 280 MW na 6270 280000 3 01-01-2021 12-31-2049
AURORANewRes 158 New No 5822 CCCT 280 MW na 6270 280000 3 01-01-2021 12-31-2049
AURORANewRes 159 New No 5823 CCCT 280 MW na 6270 280000 3 01-01-2021 12-31-2049
AURORANewRes 16 New No 5399 CCCT 280 MW na 6048 280000 1 01-01-2027 12-31-2049
AURORANewRes 160 New No 5824 CCCT 280 MW na 6270 280000 3 01-01-2021 12-31-2049
AURORANewRes 161 New No 5826 CCCT 280 MW na 6233 280000 3 01-01-2022 12-31-2049
AURORANewRes 162 New No 5827 CCCT 280 MW na 6233 280000 3 01-01-2022 12-31-2049
AURORANewRes 163 New No 5829 CCCT 280 MW na 6233 280000 3 01-01-2022 12-31-2049
AURORANewRes 164 New No 5830 CCCT 280 MW na 6233 280000 3 01-01-2022 12-31-2049
AURORANewRes 165 New No 5831 CCCT 280 MW na 6233 280000 3 01-01-2022 12-31-2049
AURORANewRes 166 New No 5832 CCCT 280 MW na 6233 280000 3 01-01-2022 12-31-2049
AURORANewRes 167 New No 5833 CCCT 280 MW na 6233 280000 3 01-01-2022 12-31-2049
AURORANewRes 168 New No 5835 CCCT 280 MW na 6233 280000 3 01-01-2022 12-31-2049
AURORANewRes 169 New No 5845 CCCT 280 MW na 6195 280000 3 01-01-2023 12-31-2049
AURORANewRes 17 New No 5400 CCCT 280 MW na 6048 280000 1 01-01-2027 12-31-2049
AURORANewRes 170 New No 5846 CCCT 280 MW na 6158 280000 3 01-01-2024 12-31-2049
AURORANewRes 171 New No 5847 CCCT 280 MW na 6158 280000 3 01-01-2024 12-31-2049
AURORANewRes 172 New No 5848 CCCT 280 MW na 6158 280000 3 01-01-2024 12-31-2049
AURORANewRes 173 New No 5850 CCCT 280 MW na 6158 280000 3 01-01-2024 12-31-2049
AURORANewRes 174 New No 5856 CCCT 280 MW na 6121 280000 3 01-01-2025 12-31-2049
AURORANewRes 175 New No 5860 CCCT 280 MW na 6121 280000 3 01-01-2025 12-31-2049
AURORANewRes 176 New No 5862 CCCT 280 MW na 6121 280000 3 01-01-2025 12-31-2049

Appendix J Page J-13 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 177 New No 5863 CCCT 280 MW na 6121 280000 3 01-01-2025 12-31-2049
AURORANewRes 178 New No 5864 CCCT 280 MW na 6121 280000 3 01-01-2025 12-31-2049
AURORANewRes 179 New No 5865 CCCT 280 MW na 6121 280000 3 01-01-2025 12-31-2049
AURORANewRes 18 New No 5411 CCCT 280 MW na 6012 280000 1 01-01-2028 12-31-2049
AURORANewRes 180 New No 5866 CCCT 280 MW na 6085 280000 3 01-01-2026 12-31-2049
AURORANewRes 181 New No 5867 CCCT 280 MW na 6085 280000 3 01-01-2026 12-31-2049
AURORANewRes 182 New No 5868 CCCT 280 MW na 6085 280000 3 01-01-2026 12-31-2049
AURORANewRes 183 New No 5869 CCCT 280 MW na 6085 280000 3 01-01-2026 12-31-2049
AURORANewRes 184 New No 5870 CCCT 280 MW na 6085 280000 3 01-01-2026 12-31-2049
AURORANewRes 185 New No 5871 CCCT 280 MW na 6085 280000 3 01-01-2026 12-31-2049
AURORANewRes 186 New No 5872 CCCT 280 MW na 6085 280000 3 01-01-2026 12-31-2049
AURORANewRes 187 New No 5873 CCCT 280 MW na 6085 280000 3 01-01-2026 12-31-2049
AURORANewRes 188 New No 5874 CCCT 280 MW na 6085 280000 3 01-01-2026 12-31-2049
AURORANewRes 189 New No 5876 CCCT 280 MW na 6048 280000 3 01-01-2027 12-31-2049
AURORANewRes 19 New No 5413 CCCT 280 MW na 6012 280000 1 01-01-2028 12-31-2049
AURORANewRes 190 New No 5877 CCCT 280 MW na 6048 280000 3 01-01-2027 12-31-2049
AURORANewRes 191 New No 5878 CCCT 280 MW na 6048 280000 3 01-01-2027 12-31-2049
AURORANewRes 192 New No 5879 CCCT 280 MW na 6048 280000 3 01-01-2027 12-31-2049
AURORANewRes 193 New No 5880 CCCT 280 MW na 6048 280000 3 01-01-2027 12-31-2049
AURORANewRes 194 New No 5882 CCCT 280 MW na 6048 280000 3 01-01-2027 12-31-2049
AURORANewRes 195 New No 5885 CCCT 280 MW na 6048 280000 3 01-01-2027 12-31-2049
AURORANewRes 196 New No 5887 CCCT 280 MW na 6012 280000 3 01-01-2028 12-31-2049
AURORANewRes 197 New No 5889 CCCT 280 MW na 6012 280000 3 01-01-2028 12-31-2049
AURORANewRes 198 New No 5892 CCCT 280 MW na 6012 280000 3 01-01-2028 12-31-2049
AURORANewRes 199 New No 5893 CCCT 280 MW na 6012 280000 3 01-01-2028 12-31-2049
AURORANewRes 2 New No 2918 Coal 400 MW na 9426 400000 6 01-01-2010 12-31-2049
AURORANewRes 20 New No 5415 CCCT 280 MW na 6012 280000 1 01-01-2028 12-31-2049
AURORANewRes 200 New No 5894 CCCT 280 MW na 6012 280000 3 01-01-2028 12-31-2049
AURORANewRes 201 New No 5895 CCCT 280 MW na 6012 280000 3 01-01-2028 12-31-2049
AURORANewRes 202 New No 5919 CCCT 280 MW na 6822 280000 4 01-01-2007 12-31-2049
AURORANewRes 203 New No 5942 CCCT 280 MW na 6740 280000 4 01-01-2009 12-31-2049
AURORANewRes 204 New No 5952 CCCT 280 MW na 6700 280000 4 01-01-2010 12-31-2049
AURORANewRes 205 New No 5959 CCCT 280 MW na 6659 280000 4 01-01-2011 12-31-2049
AURORANewRes 206 New No 5974 CCCT 280 MW na 6619 280000 4 01-01-2012 12-31-2049
AURORANewRes 207 New No 5982 CCCT 280 MW na 6580 280000 4 01-01-2013 12-31-2049
AURORANewRes 208 New No 5989 CCCT 280 MW na 6540 280000 4 01-01-2014 12-31-2049
AURORANewRes 209 New No 5997 CCCT 280 MW na 6501 280000 4 01-01-2015 12-31-2049
AURORANewRes 21 New No 5477 CCCT 280 MW na 6659 280000 2 01-01-2011 12-31-2049
AURORANewRes 210 New No 6009 CCCT 280 MW na 6462 280000 4 01-01-2016 12-31-2049
AURORANewRes 211 New No 6027 CCCT 280 MW na 6385 280000 4 01-01-2018 12-31-2049
AURORANewRes 212 New No 6042 CCCT 280 MW na 6346 280000 4 01-01-2019 12-31-2049
AURORANewRes 213 New No 6049 CCCT 280 MW na 6308 280000 4 01-01-2020 12-31-2049
AURORANewRes 214 New No 6058 CCCT 280 MW na 6270 280000 4 01-01-2021 12-31-2049
AURORANewRes 215 New No 6078 CCCT 280 MW na 6195 280000 4 01-01-2023 12-31-2049
AURORANewRes 216 New No 6080 CCCT 280 MW na 6195 280000 4 01-01-2023 12-31-2049
AURORANewRes 217 New No 6091 CCCT 280 MW na 6158 280000 4 01-01-2024 12-31-2049
AURORANewRes 218 New No 6094 CCCT 280 MW na 6158 280000 4 01-01-2024 12-31-2049

Appendix J Page J-14 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 219 New No 6099 CCCT 280 MW na 6121 280000 4 01-01-2025 12-31-2049
AURORANewRes 22 New No 5478 CCCT 280 MW na 6659 280000 2 01-01-2011 12-31-2049
AURORANewRes 220 New No 6103 CCCT 280 MW na 6121 280000 4 01-01-2025 12-31-2049
AURORANewRes 221 New No 6119 CCCT 280 MW na 6048 280000 4 01-01-2027 12-31-2049
AURORANewRes 222 New No 6120 CCCT 280 MW na 6048 280000 4 01-01-2027 12-31-2049
AURORANewRes 223 New No 6134 CCCT 280 MW na 6012 280000 4 01-01-2028 12-31-2049
AURORANewRes 224 New No 6212 CCCT 280 MW na 6619 280000 5 01-01-2012 12-31-2049
AURORANewRes 225 New No 6228 CCCT 280 MW na 6540 280000 5 01-01-2014 12-31-2049
AURORANewRes 226 New No 6229 CCCT 280 MW na 6540 280000 5 01-01-2014 12-31-2049
AURORANewRes 227 New No 6232 CCCT 280 MW na 6540 280000 5 01-01-2014 12-31-2049
AURORANewRes 228 New No 6243 CCCT 280 MW na 6501 280000 5 01-01-2015 12-31-2049
AURORANewRes 229 New No 6249 CCCT 280 MW na 6462 280000 5 01-01-2016 12-31-2049
AURORANewRes 23 New No 5479 CCCT 280 MW na 6659 280000 2 01-01-2011 12-31-2049
AURORANewRes 230 New No 6250 CCCT 280 MW na 6462 280000 5 01-01-2016 12-31-2049
AURORANewRes 231 New No 6297 CCCT 280 MW na 6270 280000 5 01-01-2021 12-31-2049
AURORANewRes 232 New No 6308 CCCT 280 MW na 6233 280000 5 01-01-2022 12-31-2049
AURORANewRes 233 New No 6319 CCCT 280 MW na 6195 280000 5 01-01-2023 12-31-2049
AURORANewRes 234 New No 6331 CCCT 280 MW na 6158 280000 5 01-01-2024 12-31-2049
AURORANewRes 235 New No 6343 CCCT 280 MW na 6121 280000 5 01-01-2025 12-31-2049
AURORANewRes 236 New No 6349 CCCT 280 MW na 6085 280000 5 01-01-2026 12-31-2049
AURORANewRes 237 New No 6352 CCCT 280 MW na 6085 280000 5 01-01-2026 12-31-2049
AURORANewRes 238 New No 6357 CCCT 280 MW na 6048 280000 5 01-01-2027 12-31-2049
AURORANewRes 239 New No 6358 CCCT 280 MW na 6048 280000 5 01-01-2027 12-31-2049
AURORANewRes 24 New No 5486 CCCT 280 MW na 6619 280000 2 01-01-2012 12-31-2049
AURORANewRes 240 New No 6465 CCCT 280 MW na 6580 280000 6 01-01-2013 12-31-2049
AURORANewRes 241 New No 6490 CCCT 280 MW na 6462 280000 6 01-01-2016 12-31-2049
AURORANewRes 242 New No 6534 CCCT 280 MW na 6308 280000 6 01-01-2020 12-31-2049
AURORANewRes 243 New No 6592 CCCT 280 MW na 6085 280000 6 01-01-2026 12-31-2049
AURORANewRes 244 New No 6599 CCCT 280 MW na 6048 280000 6 01-01-2027 12-31-2049
AURORANewRes 245 New No 6606 CCCT 280 MW na 6012 280000 6 01-01-2028 12-31-2049
AURORANewRes 246 New No 6607 CCCT 280 MW na 6012 280000 6 01-01-2028 12-31-2049
AURORANewRes 247 New No 6741 CCCT 280 MW na 6423 280000 7 01-01-2017 12-31-2049
AURORANewRes 248 New No 6836 CCCT 280 MW na 6048 280000 7 01-01-2027 12-31-2049
AURORANewRes 249 New No 6848 CCCT 280 MW na 6012 280000 7 01-01-2028 12-31-2049
AURORANewRes 25 New No 5489 CCCT 280 MW na 6619 280000 2 01-01-2012 12-31-2049
AURORANewRes 250 New No 6849 CCCT 280 MW na 6012 280000 7 01-01-2028 12-31-2049
AURORANewRes 251 New No 6850 CCCT 280 MW na 6012 280000 7 01-01-2028 12-31-2049
AURORANewRes 252 New No 6851 CCCT 280 MW na 6012 280000 7 01-01-2028 12-31-2049
AURORANewRes 253 New No 6852 CCCT 280 MW na 6012 280000 7 01-01-2028 12-31-2049
AURORANewRes 254 New No 6961 CCCT 280 MW na 6501 280000 8 01-01-2015 12-31-2049
AURORANewRes 255 New No 6962 CCCT 280 MW na 6501 280000 8 01-01-2015 12-31-2049
AURORANewRes 256 New No 6972 CCCT 280 MW na 6462 280000 8 01-01-2016 12-31-2049
AURORANewRes 257 New No 6992 CCCT 280 MW na 6385 280000 8 01-01-2018 12-31-2049
AURORANewRes 258 New No 7005 CCCT 280 MW na 6346 280000 8 01-01-2019 12-31-2049
AURORANewRes 259 New No 7012 CCCT 280 MW na 6308 280000 8 01-01-2020 12-31-2049
AURORANewRes 26 New No 5490 CCCT 280 MW na 6619 280000 2 01-01-2012 12-31-2049
AURORANewRes 260 New No 7039 CCCT 280 MW na 6195 280000 8 01-01-2023 12-31-2049

Appendix J Page J-15 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 261 New No 7045 CCCT 280 MW na 6195 280000 8 01-01-2023 12-31-2049
AURORANewRes 262 New No 7052 CCCT 280 MW na 6158 280000 8 01-01-2024 12-31-2049
AURORANewRes 263 New No 7067 CCCT 280 MW na 6085 280000 8 01-01-2026 12-31-2049
AURORANewRes 264 New No 7079 CCCT 280 MW na 6048 280000 8 01-01-2027 12-31-2049
AURORANewRes 265 New No 7082 CCCT 280 MW na 6048 280000 8 01-01-2027 12-31-2049
AURORANewRes 266 New No 7085 CCCT 280 MW na 6048 280000 8 01-01-2027 12-31-2049
AURORANewRes 267 New No 7086 CCCT 280 MW na 6012 280000 8 01-01-2028 12-31-2049
AURORANewRes 268 New No 7088 CCCT 280 MW na 6012 280000 8 01-01-2028 12-31-2049
AURORANewRes 269 New No 7089 CCCT 280 MW na 6012 280000 8 01-01-2028 12-31-2049
AURORANewRes 27 New No 5491 CCCT 280 MW na 6619 280000 2 01-01-2012 12-31-2049
AURORANewRes 270 New No 7090 CCCT 280 MW na 6012 280000 8 01-01-2028 12-31-2049
AURORANewRes 271 New No 7091 CCCT 280 MW na 6012 280000 8 01-01-2028 12-31-2049
AURORANewRes 272 New No 7093 CCCT 280 MW na 6012 280000 8 01-01-2028 12-31-2049
AURORANewRes 273 New No 7094 CCCT 280 MW na 6012 280000 8 01-01-2028 12-31-2049
AURORANewRes 274 New No 7177 CCCT 280 MW na 6580 280000 9 01-01-2013 12-31-2049
AURORANewRes 275 New No 7178 CCCT 280 MW na 6580 280000 9 01-01-2013 12-31-2049
AURORANewRes 276 New No 7181 CCCT 280 MW na 6580 280000 9 01-01-2013 12-31-2049
AURORANewRes 277 New No 7193 CCCT 280 MW na 6540 280000 9 01-01-2014 12-31-2049
AURORANewRes 278 New No 7194 CCCT 280 MW na 6540 280000 9 01-01-2014 12-31-2049
AURORANewRes 279 New No 7197 CCCT 280 MW na 6501 280000 9 01-01-2015 12-31-2049
AURORANewRes 28 New No 5492 CCCT 280 MW na 6619 280000 2 01-01-2012 12-31-2049
AURORANewRes 280 New No 7199 CCCT 280 MW na 6501 280000 9 01-01-2015 12-31-2049
AURORANewRes 281 New No 7210 CCCT 280 MW na 6462 280000 9 01-01-2016 12-31-2049
AURORANewRes 282 New No 7219 CCCT 280 MW na 6423 280000 9 01-01-2017 12-31-2049
AURORANewRes 283 New No 7232 CCCT 280 MW na 6385 280000 9 01-01-2018 12-31-2049
AURORANewRes 284 New No 7258 CCCT 280 MW na 6270 280000 9 01-01-2021 12-31-2049
AURORANewRes 285 New No 7268 CCCT 280 MW na 6233 280000 9 01-01-2022 12-31-2049
AURORANewRes 286 New No 7271 CCCT 280 MW na 6233 280000 9 01-01-2022 12-31-2049
AURORANewRes 287 New No 7280 CCCT 280 MW na 6195 280000 9 01-01-2023 12-31-2049
AURORANewRes 288 New No 7282 CCCT 280 MW na 6195 280000 9 01-01-2023 12-31-2049
AURORANewRes 289 New No 7290 CCCT 280 MW na 6158 280000 9 01-01-2024 12-31-2049
AURORANewRes 29 New No 5494 CCCT 280 MW na 6619 280000 2 01-01-2012 12-31-2049
AURORANewRes 290 New No 7292 CCCT 280 MW na 6158 280000 9 01-01-2024 12-31-2049
AURORANewRes 291 New No 7299 CCCT 280 MW na 6121 280000 9 01-01-2025 12-31-2049
AURORANewRes 292 New No 7301 CCCT 280 MW na 6121 280000 9 01-01-2025 12-31-2049
AURORANewRes 293 New No 7302 CCCT 280 MW na 6121 280000 9 01-01-2025 12-31-2049
AURORANewRes 294 New No 7309 CCCT 280 MW na 6085 280000 9 01-01-2026 12-31-2049
AURORANewRes 295 New No 7316 CCCT 280 MW na 6048 280000 9 01-01-2027 12-31-2049
AURORANewRes 296 New No 7318 CCCT 280 MW na 6048 280000 9 01-01-2027 12-31-2049
AURORANewRes 297 New No 7324 CCCT 280 MW na 6048 280000 9 01-01-2027 12-31-2049
AURORANewRes 298 New No 7332 CCCT 280 MW na 6012 280000 9 01-01-2028 12-31-2049
AURORANewRes 299 New No 7334 CCCT 280 MW na 6012 280000 9 01-01-2028 12-31-2049
AURORANewRes 3 New No 3142 Coal 400 MW na 9451 400000 7 01-01-2009 12-31-2049
AURORANewRes 30 New No 5495 CCCT 280 MW na 6619 280000 2 01-01-2012 12-31-2049
AURORANewRes 300 New No 7335 CCCT 280 MW na 6012 280000 9 01-01-2028 12-31-2049
AURORANewRes 301 New No 7419 CCCT 280 MW na 6580 280000 10 01-01-2013 12-31-2049
AURORANewRes 302 New No 7432 CCCT 280 MW na 6540 280000 10 01-01-2014 12-31-2049

Appendix J Page J-16 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 303 New No 7438 CCCT 280 MW na 6501 280000 10 01-01-2015 12-31-2049
AURORANewRes 304 New No 7441 CCCT 280 MW na 6501 280000 10 01-01-2015 12-31-2049
AURORANewRes 305 New No 7459 CCCT 280 MW na 6423 280000 10 01-01-2017 12-31-2049
AURORANewRes 306 New No 7460 CCCT 280 MW na 6423 280000 10 01-01-2017 12-31-2049
AURORANewRes 307 New No 7506 CCCT 280 MW na 6233 280000 10 01-01-2022 12-31-2049
AURORANewRes 308 New No 7507 CCCT 280 MW na 6233 280000 10 01-01-2022 12-31-2049
AURORANewRes 309 New No 7513 CCCT 280 MW na 6233 280000 10 01-01-2022 12-31-2049
AURORANewRes 31 New No 5496 CCCT 280 MW na 6580 280000 2 01-01-2013 12-31-2049
AURORANewRes 310 New No 7514 CCCT 280 MW na 6233 280000 10 01-01-2022 12-31-2049
AURORANewRes 311 New No 7516 CCCT 280 MW na 6195 280000 10 01-01-2023 12-31-2049
AURORANewRes 312 New No 7519 CCCT 280 MW na 6195 280000 10 01-01-2023 12-31-2049
AURORANewRes 313 New No 7520 CCCT 280 MW na 6195 280000 10 01-01-2023 12-31-2049
AURORANewRes 314 New No 7522 CCCT 280 MW na 6195 280000 10 01-01-2023 12-31-2049
AURORANewRes 315 New No 7529 CCCT 280 MW na 6158 280000 10 01-01-2024 12-31-2049
AURORANewRes 316 New No 7530 CCCT 280 MW na 6158 280000 10 01-01-2024 12-31-2049
AURORANewRes 317 New No 7531 CCCT 280 MW na 6158 280000 10 01-01-2024 12-31-2049
AURORANewRes 318 New No 7532 CCCT 280 MW na 6158 280000 10 01-01-2024 12-31-2049
AURORANewRes 319 New No 7539 CCCT 280 MW na 6121 280000 10 01-01-2025 12-31-2049
AURORANewRes 32 New No 5497 CCCT 280 MW na 6580 280000 2 01-01-2013 12-31-2049
AURORANewRes 320 New No 7540 CCCT 280 MW na 6121 280000 10 01-01-2025 12-31-2049
AURORANewRes 321 New No 7549 CCCT 280 MW na 6085 280000 10 01-01-2026 12-31-2049
AURORANewRes 322 New No 7550 CCCT 280 MW na 6085 280000 10 01-01-2026 12-31-2049
AURORANewRes 323 New No 7551 CCCT 280 MW na 6085 280000 10 01-01-2026 12-31-2049
AURORANewRes 324 New No 7556 CCCT 280 MW na 6048 280000 10 01-01-2027 12-31-2049
AURORANewRes 325 New No 7563 CCCT 280 MW na 6048 280000 10 01-01-2027 12-31-2049
AURORANewRes 326 New No 7568 CCCT 280 MW na 6012 280000 10 01-01-2028 12-31-2049
AURORANewRes 327 New No 7570 CCCT 280 MW na 6012 280000 10 01-01-2028 12-31-2049
AURORANewRes 328 New No 7571 CCCT 280 MW na 6012 280000 10 01-01-2028 12-31-2049
AURORANewRes 329 New No 7572 CCCT 280 MW na 6012 280000 10 01-01-2028 12-31-2049
AURORANewRes 33 New No 5498 CCCT 280 MW na 6580 280000 2 01-01-2013 12-31-2049
AURORANewRes 330 New No 7573 CCCT 280 MW na 6012 280000 10 01-01-2028 12-31-2049
AURORANewRes 331 New No 7643 CCCT 280 MW na 6659 280000 11 01-01-2011 12-31-2049
AURORANewRes 332 New No 7661 CCCT 280 MW na 6580 280000 11 01-01-2013 12-31-2049
AURORANewRes 333 New No 7668 CCCT 280 MW na 6540 280000 11 01-01-2014 12-31-2049
AURORANewRes 334 New No 7669 CCCT 280 MW na 6540 280000 11 01-01-2014 12-31-2049
AURORANewRes 335 New No 7671 CCCT 280 MW na 6540 280000 11 01-01-2014 12-31-2049
AURORANewRes 336 New No 7676 CCCT 280 MW na 6501 280000 11 01-01-2015 12-31-2049
AURORANewRes 337 New No 7688 CCCT 280 MW na 6462 280000 11 01-01-2016 12-31-2049
AURORANewRes 338 New No 7740 CCCT 280 MW na 6270 280000 11 01-01-2021 12-31-2049
AURORANewRes 339 New No 7760 CCCT 280 MW na 6195 280000 11 01-01-2023 12-31-2049
AURORANewRes 34 New No 5499 CCCT 280 MW na 6580 280000 2 01-01-2013 12-31-2049
AURORANewRes 340 New No 7775 CCCT 280 MW na 6158 280000 11 01-01-2024 12-31-2049
AURORANewRes 341 New No 7787 CCCT 280 MW na 6085 280000 11 01-01-2026 12-31-2049
AURORANewRes 342 New No 7799 CCCT 280 MW na 6048 280000 11 01-01-2027 12-31-2049
AURORANewRes 343 New No 7802 CCCT 280 MW na 6048 280000 11 01-01-2027 12-31-2049
AURORANewRes 344 New No 7809 CCCT 280 MW na 6012 280000 11 01-01-2028 12-31-2049
AURORANewRes 345 New No 7811 CCCT 280 MW na 6012 280000 11 01-01-2028 12-31-2049

Appendix J Page J-17 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 346 New No 7812 CCCT 280 MW na 6012 280000 11 01-01-2028 12-31-2049
AURORANewRes 347 New No 7814 CCCT 280 MW na 6012 280000 11 01-01-2028 12-31-2049
AURORANewRes 348 New No 7879 CCCT 280 MW na 6659 280000 12 01-01-2011 12-31-2049
AURORANewRes 349 New No 7911 CCCT 280 MW na 6540 280000 12 01-01-2014 12-31-2049
AURORANewRes 35 New No 5500 CCCT 280 MW na 6580 280000 2 01-01-2013 12-31-2049
AURORANewRes 350 New No 7919 CCCT 280 MW na 6501 280000 12 01-01-2015 12-31-2049
AURORANewRes 351 New No 7929 CCCT 280 MW na 6462 280000 12 01-01-2016 12-31-2049
AURORANewRes 352 New No 7979 CCCT 280 MW na 6270 280000 12 01-01-2021 12-31-2049
AURORANewRes 353 New No 7989 CCCT 280 MW na 6233 280000 12 01-01-2022 12-31-2049
AURORANewRes 354 New No 8003 CCCT 280 MW na 6195 280000 12 01-01-2023 12-31-2049
AURORANewRes 355 New No 8009 CCCT 280 MW na 6158 280000 12 01-01-2024 12-31-2049
AURORANewRes 356 New No 8018 CCCT 280 MW na 6121 280000 12 01-01-2025 12-31-2049
AURORANewRes 357 New No 8179 CCCT 280 MW na 6423 280000 13 01-01-2017 12-31-2049
AURORANewRes 358 New No 8194 CCCT 280 MW na 6385 280000 13 01-01-2018 12-31-2049
AURORANewRes 359 New No 8219 CCCT 280 MW na 6270 280000 13 01-01-2021 12-31-2049
AURORANewRes 36 New No 5501 CCCT 280 MW na 6580 280000 2 01-01-2013 12-31-2049
AURORANewRes 360 New No 8234 CCCT 280 MW na 6233 280000 13 01-01-2022 12-31-2049
AURORANewRes 361 New No 8238 CCCT 280 MW na 6195 280000 13 01-01-2023 12-31-2049
AURORANewRes 362 New No 8257 CCCT 280 MW na 6121 280000 13 01-01-2025 12-31-2049
AURORANewRes 363 New No 8271 CCCT 280 MW na 6085 280000 13 01-01-2026 12-31-2049
AURORANewRes 364 New No 8272 CCCT 280 MW na 6085 280000 13 01-01-2026 12-31-2049
AURORANewRes 365 New No 8273 CCCT 280 MW na 6085 280000 13 01-01-2026 12-31-2049
AURORANewRes 366 New No 8286 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 367 New No 8287 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 368 New No 8288 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 369 New No 8289 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 37 New No 5502 CCCT 280 MW na 6580 280000 2 01-01-2013 12-31-2049
AURORANewRes 370 New No 8290 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 371 New No 8291 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 372 New No 8292 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 373 New No 8293 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 374 New No 8294 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 375 New No 8295 CCCT 280 MW na 6012 280000 13 01-01-2028 12-31-2049
AURORANewRes 376 New No 8599 CCCT 280 MW na 6659 280000 14 01-01-2011 12-31-2049
AURORANewRes 377 New No 8611 CCCT 280 MW na 6619 280000 14 01-01-2012 12-31-2049
AURORANewRes 378 New No 8612 CCCT 280 MW na 6619 280000 14 01-01-2012 12-31-2049
AURORANewRes 379 New No 8622 CCCT 280 MW na 6580 280000 14 01-01-2013 12-31-2049
AURORANewRes 38 New No 5503 CCCT 280 MW na 6580 280000 2 01-01-2013 12-31-2049
AURORANewRes 380 New No 8632 CCCT 280 MW na 6540 280000 14 01-01-2014 12-31-2049
AURORANewRes 381 New No 8639 CCCT 280 MW na 6501 280000 14 01-01-2015 12-31-2049
AURORANewRes 382 New No 8652 CCCT 280 MW na 6462 280000 14 01-01-2016 12-31-2049
AURORANewRes 383 New No 8680 CCCT 280 MW na 6346 280000 14 01-01-2019 12-31-2049
AURORANewRes 384 New No 8692 CCCT 280 MW na 6308 280000 14 01-01-2020 12-31-2049
AURORANewRes 385 New No 8699 CCCT 280 MW na 6270 280000 14 01-01-2021 12-31-2049
AURORANewRes 386 New No 8702 CCCT 280 MW na 6270 280000 14 01-01-2021 12-31-2049
AURORANewRes 387 New No 8706 CCCT 280 MW na 6233 280000 14 01-01-2022 12-31-2049
AURORANewRes 388 New No 8709 CCCT 280 MW na 6233 280000 14 01-01-2022 12-31-2049

Appendix J Page J-18 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 389 New No 8720 CCCT 280 MW na 6195 280000 14 01-01-2023 12-31-2049
AURORANewRes 39 New No 5505 CCCT 280 MW na 6580 280000 2 01-01-2013 12-31-2049
AURORANewRes 390 New No 8722 CCCT 280 MW na 6195 280000 14 01-01-2023 12-31-2049
AURORANewRes 391 New No 8729 CCCT 280 MW na 6158 280000 14 01-01-2024 12-31-2049
AURORANewRes 392 New No 8769 CCCT 280 MW na 6012 280000 14 01-01-2028 12-31-2049
AURORANewRes 393 New No 8772 CCCT 280 MW na 6012 280000 14 01-01-2028 12-31-2049
AURORANewRes 394 New No 8773 CCCT 280 MW na 6012 280000 14 01-01-2028 12-31-2049
AURORANewRes 395 New No 8914 SCCT 2x46 MW na 8771 92000 1 01-01-2017 12-31-2049
AURORANewRes 396 New No 8926 SCCT 2x46 MW na 8736 92000 1 01-01-2019 12-31-2049
AURORANewRes 397 New No 8929 SCCT 2x46 MW na 8736 92000 1 01-01-2019 12-31-2049
AURORANewRes 398 New No 8930 SCCT 2x46 MW na 8736 92000 1 01-01-2019 12-31-2049
AURORANewRes 399 New No 8932 SCCT 2x46 MW na 8736 92000 1 01-01-2019 12-31-2049
AURORANewRes 4 New No 3161 Coal 400 MW na 9402 400000 7 01-01-2011 12-31-2049
AURORANewRes 40 New No 5506 CCCT 280 MW na 6540 280000 2 01-01-2014 12-31-2049
AURORANewRes 400 New No 8933 SCCT 2x46 MW na 8736 92000 1 01-01-2019 12-31-2049
AURORANewRes 401 New No 8934 SCCT 2x46 MW na 8736 92000 1 01-01-2019 12-31-2049
AURORANewRes 402 New No 8969 SCCT 2x46 MW na 8692 92000 1 01-01-2023 12-31-2049
AURORANewRes 403 New No 8973 SCCT 2x46 MW na 8692 92000 1 01-01-2023 12-31-2049
AURORANewRes 404 New No 8982 SCCT 2x46 MW na 8683 92000 1 01-01-2024 12-31-2049
AURORANewRes 405 New No 9016 SCCT 2x46 MW na 8675 92000 1 01-01-2028 12-31-2049
AURORANewRes 406 New No 9017 SCCT 2x46 MW na 8675 92000 1 01-01-2028 12-31-2049
AURORANewRes 407 New No 9024 SCCT 2x46 MW na 8675 92000 1 01-01-2028 12-31-2049
AURORANewRes 408 New No 9025 SCCT 2x46 MW na 8675 92000 1 01-01-2028 12-31-2049
AURORANewRes 409 New No 9267 SCCT 2x46 MW na 8675 92000 2 01-01-2028 12-31-2049
AURORANewRes 41 New No 5512 CCCT 280 MW na 6540 280000 2 01-01-2014 12-31-2049
AURORANewRes 410 New No 9274 SCCT 2x46 MW na 8675 92000 2 01-01-2028 12-31-2049
AURORANewRes 411 New No 9275 SCCT 2x46 MW na 8675 92000 2 01-01-2028 12-31-2049
AURORANewRes 412 New No 9518 SCCT 2x46 MW na 8675 92000 3 01-01-2028 12-31-2049
AURORANewRes 413 New No 9524 SCCT 2x46 MW na 8675 92000 3 01-01-2028 12-31-2049
AURORANewRes 414 New No 11268 SCCT 2x46 MW na 8675 92000 10 01-01-2028 12-31-2049
AURORANewRes 415 New No 11269 SCCT 2x46 MW na 8675 92000 10 01-01-2028 12-31-2049
AURORANewRes 416 New No 11270 SCCT 2x46 MW na 8675 92000 10 01-01-2028 12-31-2049
AURORANewRes 417 New No 12521 SCCT 2x46 MW na 8675 92000 14 01-01-2028 12-31-2049
AURORANewRes 418 New No 12522 SCCT 2x46 MW na 8675 92000 14 01-01-2028 12-31-2049
AURORANewRes 419 New No 12596 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 42 New No 5513 CCCT 280 MW na 6540 280000 2 01-01-2014 12-31-2049
AURORANewRes 420 New No 12597 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 421 New No 12598 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 422 New No 12599 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 423 New No 12600 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 424 New No 12601 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 425 New No 12602 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 426 New No 12603 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 427 New No 12604 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 428 New No 12605 Wind 100 MW na 0 100000 1 01-01-2011 12-31-2049
AURORANewRes 429 New No 12836 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 43 New No 5516 CCCT 280 MW na 6501 280000 2 01-01-2015 12-31-2049

Appendix J Page J-19 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 430 New No 12837 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 431 New No 12838 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 432 New No 12839 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 433 New No 12840 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 434 New No 12841 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 435 New No 12842 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 436 New No 12843 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 437 New No 12844 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 438 New No 12845 Wind 100 MW na 0 100000 2 01-01-2010 12-31-2049
AURORANewRes 439 New No 13076 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 44 New No 5519 CCCT 280 MW na 6501 280000 2 01-01-2015 12-31-2049
AURORANewRes 440 New No 13077 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 441 New No 13078 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 442 New No 13079 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 443 New No 13080 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 444 New No 13081 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 445 New No 13082 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 446 New No 13083 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 447 New No 13084 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 448 New No 13085 Wind 100 MW na 0 100000 3 01-01-2009 12-31-2049
AURORANewRes 449 New No 13319 Wind 100 MW na 0 100000 4 01-01-2008 12-31-2049
AURORANewRes 45 New No 5520 CCCT 280 MW na 6501 280000 2 01-01-2015 12-31-2049
AURORANewRes 450 New No 13329 Wind 100 MW na 0 100000 4 01-01-2009 12-31-2049
AURORANewRes 451 New No 13331 Wind 100 MW na 0 100000 4 01-01-2009 12-31-2049
AURORANewRes 452 New No 13333 Wind 100 MW na 0 100000 4 01-01-2009 12-31-2049
AURORANewRes 453 New No 13342 Wind 100 MW na 0 100000 4 01-01-2010 12-31-2049
AURORANewRes 454 New No 13344 Wind 100 MW na 0 100000 4 01-01-2010 12-31-2049
AURORANewRes 455 New No 13376 Wind 100 MW na 0 100000 4 01-01-2014 12-31-2049
AURORANewRes 456 New No 13397 Wind 100 MW na 0 100000 4 01-01-2016 12-31-2049
AURORANewRes 457 New No 13402 Wind 100 MW na 0 100000 4 01-01-2016 12-31-2049
AURORANewRes 458 New No 13405 Wind 100 MW na 0 100000 4 01-01-2016 12-31-2049
AURORANewRes 459 New No 13611 Wind 100 MW na 0 100000 5 01-01-2012 12-31-2049
AURORANewRes 46 New No 5530 CCCT 280 MW na 6462 280000 2 01-01-2016 12-31-2049
AURORANewRes 460 New No 13618 Wind 100 MW na 0 100000 5 01-01-2013 12-31-2049
AURORANewRes 461 New No 13620 Wind 100 MW na 0 100000 5 01-01-2013 12-31-2049
AURORANewRes 462 New No 13622 Wind 100 MW na 0 100000 5 01-01-2013 12-31-2049
AURORANewRes 463 New No 13623 Wind 100 MW na 0 100000 5 01-01-2013 12-31-2049
AURORANewRes 464 New No 13624 Wind 100 MW na 0 100000 5 01-01-2013 12-31-2049
AURORANewRes 465 New No 13625 Wind 100 MW na 0 100000 5 01-01-2013 12-31-2049
AURORANewRes 466 New No 13652 Wind 100 MW na 0 100000 5 01-01-2016 12-31-2049
AURORANewRes 467 New No 13656 Wind 100 MW na 0 100000 5 01-01-2017 12-31-2049
AURORANewRes 468 New No 13674 Wind 100 MW na 0 100000 5 01-01-2018 12-31-2049
AURORANewRes 469 New No 13816 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049
AURORANewRes 47 New No 5531 CCCT 280 MW na 6462 280000 2 01-01-2016 12-31-2049
AURORANewRes 470 New No 13817 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049
AURORANewRes 471 New No 13818 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049
AURORANewRes 472 New No 13819 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049

Appendix J Page J-20 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 473 New No 13820 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049
AURORANewRes 474 New No 13821 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049
AURORANewRes 475 New No 13822 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049
AURORANewRes 476 New No 13823 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049
AURORANewRes 477 New No 13824 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049
AURORANewRes 478 New No 13825 Wind 100 MW na 0 100000 6 01-01-2008 12-31-2049
AURORANewRes 479 New No 14079 Wind 100 MW na 0 100000 7 01-01-2009 12-31-2049
AURORANewRes 48 New No 5536 CCCT 280 MW na 6423 280000 2 01-01-2017 12-31-2049
AURORANewRes 480 New No 14082 Wind 100 MW na 0 100000 7 01-01-2009 12-31-2049
AURORANewRes 481 New No 14088 Wind 100 MW na 0 100000 7 01-01-2010 12-31-2049
AURORANewRes 482 New No 14111 Wind 100 MW na 0 100000 7 01-01-2012 12-31-2049
AURORANewRes 483 New No 14112 Wind 100 MW na 0 100000 7 01-01-2012 12-31-2049
AURORANewRes 484 New No 14122 Wind 100 MW na 0 100000 7 01-01-2013 12-31-2049
AURORANewRes 485 New No 14127 Wind 100 MW na 0 100000 7 01-01-2014 12-31-2049
AURORANewRes 486 New No 14131 Wind 100 MW na 0 100000 7 01-01-2014 12-31-2049
AURORANewRes 487 New No 14146 Wind 100 MW na 0 100000 7 01-01-2016 12-31-2049
AURORANewRes 488 New No 14149 Wind 100 MW na 0 100000 7 01-01-2016 12-31-2049
AURORANewRes 489 New No 14336 Wind 100 MW na 0 100000 8 01-01-2010 12-31-2049
AURORANewRes 49 New No 5538 CCCT 280 MW na 6423 280000 2 01-01-2017 12-31-2049
AURORANewRes 490 New No 14339 Wind 100 MW na 0 100000 8 01-01-2010 12-31-2049
AURORANewRes 491 New No 14340 Wind 100 MW na 0 100000 8 01-01-2010 12-31-2049
AURORANewRes 492 New No 14341 Wind 100 MW na 0 100000 8 01-01-2010 12-31-2049
AURORANewRes 493 New No 14343 Wind 100 MW na 0 100000 8 01-01-2010 12-31-2049
AURORANewRes 494 New No 14344 Wind 100 MW na 0 100000 8 01-01-2010 12-31-2049
AURORANewRes 495 New No 14350 Wind 100 MW na 0 100000 8 01-01-2011 12-31-2049
AURORANewRes 496 New No 14351 Wind 100 MW na 0 100000 8 01-01-2011 12-31-2049
AURORANewRes 497 New No 14352 Wind 100 MW na 0 100000 8 01-01-2011 12-31-2049
AURORANewRes 498 New No 14354 Wind 100 MW na 0 100000 8 01-01-2011 12-31-2049
AURORANewRes 499 New No 14587 Wind 100 MW na 0 100000 9 01-01-2010 12-31-2049
AURORANewRes 5 New No 3164 Coal 400 MW na 9402 400000 7 01-01-2011 12-31-2049
AURORANewRes 50 New No 5539 CCCT 280 MW na 6423 280000 2 01-01-2017 12-31-2049
AURORANewRes 500 New No 14593 Wind 100 MW na 0 100000 9 01-01-2010 12-31-2049
AURORANewRes 501 New No 14597 Wind 100 MW na 0 100000 9 01-01-2011 12-31-2049
AURORANewRes 502 New No 14598 Wind 100 MW na 0 100000 9 01-01-2011 12-31-2049
AURORANewRes 503 New No 14599 Wind 100 MW na 0 100000 9 01-01-2011 12-31-2049
AURORANewRes 504 New No 14600 Wind 100 MW na 0 100000 9 01-01-2011 12-31-2049
AURORANewRes 505 New No 14601 Wind 100 MW na 0 100000 9 01-01-2011 12-31-2049
AURORANewRes 506 New No 14602 Wind 100 MW na 0 100000 9 01-01-2011 12-31-2049
AURORANewRes 507 New No 14603 Wind 100 MW na 0 100000 9 01-01-2011 12-31-2049
AURORANewRes 508 New No 14604 Wind 100 MW na 0 100000 9 01-01-2011 12-31-2049
AURORANewRes 509 New No 14896 Wind 100 MW na 0 100000 10 01-01-2016 12-31-2049
AURORANewRes 51 New No 5540 CCCT 280 MW na 6423 280000 2 01-01-2017 12-31-2049
AURORANewRes 510 New No 14897 Wind 100 MW na 0 100000 10 01-01-2016 12-31-2049
AURORANewRes 511 New No 14899 Wind 100 MW na 0 100000 10 01-01-2016 12-31-2049
AURORANewRes 512 New No 14900 Wind 100 MW na 0 100000 10 01-01-2016 12-31-2049
AURORANewRes 513 New No 14901 Wind 100 MW na 0 100000 10 01-01-2016 12-31-2049
AURORANewRes 514 New No 14902 Wind 100 MW na 0 100000 10 01-01-2016 12-31-2049

Appendix J Page J-21 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 515 New No 14909 Wind 100 MW na 0 100000 10 01-01-2017 12-31-2049
AURORANewRes 516 New No 14916 Wind 100 MW na 0 100000 10 01-01-2018 12-31-2049
AURORANewRes 517 New No 14918 Wind 100 MW na 0 100000 10 01-01-2018 12-31-2049
AURORANewRes 518 New No 14920 Wind 100 MW na 0 100000 10 01-01-2018 12-31-2049
AURORANewRes 519 New No 15119 Wind 100 MW na 0 100000 11 01-01-2013 12-31-2049
AURORANewRes 52 New No 5544 CCCT 280 MW na 6423 280000 2 01-01-2017 12-31-2049
AURORANewRes 520 New No 15122 Wind 100 MW na 0 100000 11 01-01-2013 12-31-2049
AURORANewRes 521 New No 15147 Wind 100 MW na 0 100000 11 01-01-2016 12-31-2049
AURORANewRes 522 New No 15152 Wind 100 MW na 0 100000 11 01-01-2016 12-31-2049
AURORANewRes 523 New No 15159 Wind 100 MW na 0 100000 11 01-01-2017 12-31-2049
AURORANewRes 524 New No 15170 Wind 100 MW na 0 100000 11 01-01-2018 12-31-2049
AURORANewRes 525 New No 15171 Wind 100 MW na 0 100000 11 01-01-2018 12-31-2049
AURORANewRes 526 New No 15172 Wind 100 MW na 0 100000 11 01-01-2018 12-31-2049
AURORANewRes 527 New No 15174 Wind 100 MW na 0 100000 11 01-01-2018 12-31-2049
AURORANewRes 528 New No 15188 Wind 100 MW na 0 100000 11 01-01-2020 12-31-2049
AURORANewRes 529 New No 15346 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 53 New No 5545 CCCT 280 MW na 6423 280000 2 01-01-2017 12-31-2049
AURORANewRes 530 New No 15347 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 531 New No 15348 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 532 New No 15349 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 533 New No 15350 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 534 New No 15351 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 535 New No 15352 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 536 New No 15353 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 537 New No 15354 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 538 New No 15355 Wind 100 MW na 0 100000 12 01-01-2011 12-31-2049
AURORANewRes 539 New No 15583 Wind 100 MW na 0 100000 13 01-01-2009 12-31-2049
AURORANewRes 54 New No 5546 CCCT 280 MW na 6385 280000 2 01-01-2018 12-31-2049
AURORANewRes 540 New No 15585 Wind 100 MW na 0 100000 13 01-01-2009 12-31-2049
AURORANewRes 541 New No 15586 Wind 100 MW na 0 100000 13 01-01-2010 12-31-2049
AURORANewRes 542 New No 15588 Wind 100 MW na 0 100000 13 01-01-2010 12-31-2049
AURORANewRes 543 New No 15589 Wind 100 MW na 0 100000 13 01-01-2010 12-31-2049
AURORANewRes 544 New No 15590 Wind 100 MW na 0 100000 13 01-01-2010 12-31-2049
AURORANewRes 545 New No 15592 Wind 100 MW na 0 100000 13 01-01-2010 12-31-2049
AURORANewRes 546 New No 15593 Wind 100 MW na 0 100000 13 01-01-2010 12-31-2049
AURORANewRes 547 New No 15595 Wind 100 MW na 0 100000 13 01-01-2010 12-31-2049
AURORANewRes 548 New No 15599 Wind 100 MW na 0 100000 13 01-01-2011 12-31-2049
AURORANewRes 549 New No 16087 Wind 100 MW na 0 100000 14 01-01-2010 12-31-2049
AURORANewRes 55 New No 5548 CCCT 280 MW na 6385 280000 2 01-01-2018 12-31-2049
AURORANewRes 550 New No 16088 Wind 100 MW na 0 100000 14 01-01-2010 12-31-2049
AURORANewRes 551 New No 16094 Wind 100 MW na 0 100000 14 01-01-2010 12-31-2049
AURORANewRes 552 New No 16096 Wind 100 MW na 0 100000 14 01-01-2011 12-31-2049
AURORANewRes 553 New No 16101 Wind 100 MW na 0 100000 14 01-01-2011 12-31-2049
AURORANewRes 554 New No 16102 Wind 100 MW na 0 100000 14 01-01-2011 12-31-2049
AURORANewRes 555 New No 16104 Wind 100 MW na 0 100000 14 01-01-2011 12-31-2049
AURORANewRes 556 New No 16117 Wind 100 MW na 0 100000 14 01-01-2013 12-31-2049
AURORANewRes 557 New No 16119 Wind 100 MW na 0 100000 14 01-01-2013 12-31-2049

Appendix J Page J-22 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 558 New No 16120 Wind 100 MW na 0 100000 14 01-01-2013 12-31-2049
AURORANewRes 559 New No 16333 Duke Moapa 1 CCCT 610 MW na 6659 610000 14 01-01-2011 12-31-2049
AURORANewRes 56 New No 5550 CCCT 280 MW na 6385 280000 2 01-01-2018 12-31-2049
AURORANewRes 560 New No 16358 Duke Moapa 2 CCCT 610 MW na 6659 610000 14 01-01-2011 12-31-2049
AURORANewRes 561 New No 16377 DSM Com HVAC 1 Avista Corp 0 8935.1 17 01-01-2005 12-31-2049
AURORANewRes 562 New No 16401 DSM Com Ltg 1 Avista Corp 0 2392.9 17 01-01-2004 12-31-2049
AURORANewRes 563 New No 16532 DSM Com HVAC 2 Avista Corp 0 893.5 17 01-01-2010 12-31-2049
AURORANewRes 564 New No 16551 DSM Com Ltg 2 Avista Corp 0 239.3 17 01-01-2004 12-31-2049
AURORANewRes 565 New No 16682 DSM Com HVAC 3 Avista Corp 0 89.4 17 01-01-2010 12-31-2049
AURORANewRes 566 New No 16701 DSM Com Ltg 3 Avista Corp 0 23.9 17 01-01-2004 12-31-2049
AURORANewRes 567 New No 16832 DSM Com HVAC 4 Avista Corp 0 8.9 17 01-01-2010 12-31-2049
AURORANewRes 568 New No 16851 DSM Com Ltg 4 Avista Corp 0 2.4 17 01-01-2004 12-31-2049
AURORANewRes 57 New No 5551 CCCT 280 MW na 6385 280000 2 01-01-2018 12-31-2049
AURORANewRes 58 New No 5552 CCCT 280 MW na 6385 280000 2 01-01-2018 12-31-2049
AURORANewRes 59 New No 5553 CCCT 280 MW na 6385 280000 2 01-01-2018 12-31-2049
AURORANewRes 6 New No 5339 CCCT 280 MW na 6270 280000 1 01-01-2021 12-31-2049
AURORANewRes 60 New No 5554 CCCT 280 MW na 6385 280000 2 01-01-2018 12-31-2049
AURORANewRes 61 New No 5557 CCCT 280 MW na 6346 280000 2 01-01-2019 12-31-2049
AURORANewRes 62 New No 5558 CCCT 280 MW na 6346 280000 2 01-01-2019 12-31-2049
AURORANewRes 63 New No 5559 CCCT 280 MW na 6346 280000 2 01-01-2019 12-31-2049
AURORANewRes 64 New No 5563 CCCT 280 MW na 6346 280000 2 01-01-2019 12-31-2049
AURORANewRes 65 New No 5564 CCCT 280 MW na 6346 280000 2 01-01-2019 12-31-2049
AURORANewRes 66 New No 5565 CCCT 280 MW na 6346 280000 2 01-01-2019 12-31-2049
AURORANewRes 67 New No 5568 CCCT 280 MW na 6308 280000 2 01-01-2020 12-31-2049
AURORANewRes 68 New No 5569 CCCT 280 MW na 6308 280000 2 01-01-2020 12-31-2049
AURORANewRes 69 New No 5574 CCCT 280 MW na 6308 280000 2 01-01-2020 12-31-2049
AURORANewRes 7 New No 5340 CCCT 280 MW na 6270 280000 1 01-01-2021 12-31-2049
AURORANewRes 70 New No 5575 CCCT 280 MW na 6308 280000 2 01-01-2020 12-31-2049
AURORANewRes 71 New No 5576 CCCT 280 MW na 6270 280000 2 01-01-2021 12-31-2049
AURORANewRes 72 New No 5577 CCCT 280 MW na 6270 280000 2 01-01-2021 12-31-2049
AURORANewRes 73 New No 5578 CCCT 280 MW na 6270 280000 2 01-01-2021 12-31-2049
AURORANewRes 74 New No 5584 CCCT 280 MW na 6270 280000 2 01-01-2021 12-31-2049
AURORANewRes 75 New No 5591 CCCT 280 MW na 6233 280000 2 01-01-2022 12-31-2049
AURORANewRes 76 New No 5600 CCCT 280 MW na 6195 280000 2 01-01-2023 12-31-2049
AURORANewRes 77 New No 5602 CCCT 280 MW na 6195 280000 2 01-01-2023 12-31-2049
AURORANewRes 78 New No 5603 CCCT 280 MW na 6195 280000 2 01-01-2023 12-31-2049
AURORANewRes 79 New No 5610 CCCT 280 MW na 6158 280000 2 01-01-2024 12-31-2049
AURORANewRes 8 New No 5345 CCCT 280 MW na 6270 280000 1 01-01-2021 12-31-2049
AURORANewRes 80 New No 5611 CCCT 280 MW na 6158 280000 2 01-01-2024 12-31-2049
AURORANewRes 81 New No 5612 CCCT 280 MW na 6158 280000 2 01-01-2024 12-31-2049
AURORANewRes 82 New No 5615 CCCT 280 MW na 6158 280000 2 01-01-2024 12-31-2049
AURORANewRes 83 New No 5621 CCCT 280 MW na 6121 280000 2 01-01-2025 12-31-2049
AURORANewRes 84 New No 5622 CCCT 280 MW na 6121 280000 2 01-01-2025 12-31-2049
AURORANewRes 85 New No 5623 CCCT 280 MW na 6121 280000 2 01-01-2025 12-31-2049
AURORANewRes 86 New No 5624 CCCT 280 MW na 6121 280000 2 01-01-2025 12-31-2049
AURORANewRes 87 New No 5625 CCCT 280 MW na 6121 280000 2 01-01-2025 12-31-2049
AURORANewRes 88 New No 5626 CCCT 280 MW na 6085 280000 2 01-01-2026 12-31-2049

Appendix J Page J-23 Results of Capacity Expansion
Resource # Name Utility Heat Rate Capacity (kW) Load Area Begin Date Retire Date
AURORANewRes 89 New No 5627 CCCT 280 MW na 6085 280000 2 01-01-2026 12-31-2049
AURORANewRes 9 New No 5351 CCCT 280 MW na 6233 280000 1 01-01-2022 12-31-2049
AURORANewRes 90 New No 5628 CCCT 280 MW na 6085 280000 2 01-01-2026 12-31-2049
AURORANewRes 91 New No 5629 CCCT 280 MW na 6085 280000 2 01-01-2026 12-31-2049
AURORANewRes 92 New No 5630 CCCT 280 MW na 6085 280000 2 01-01-2026 12-31-2049
AURORANewRes 93 New No 5633 CCCT 280 MW na 6085 280000 2 01-01-2026 12-31-2049
AURORANewRes 94 New No 5636 CCCT 280 MW na 6048 280000 2 01-01-2027 12-31-2049
AURORANewRes 95 New No 5638 CCCT 280 MW na 6048 280000 2 01-01-2027 12-31-2049
AURORANewRes 96 New No 5639 CCCT 280 MW na 6048 280000 2 01-01-2027 12-31-2049
AURORANewRes 97 New No 5640 CCCT 280 MW na 6048 280000 2 01-01-2027 12-31-2049
AURORANewRes 98 New No 5651 CCCT 280 MW na 6012 280000 2 01-01-2028 12-31-2049
AURORANewRes 99 New No 5654 CCCT 280 MW na 6012 280000 2 01-01-2028 12-31-2049

Appendix K Page K-1 Spokane River Relicensing
Appendix

Spokane River Relicensing

The Spokane River Project consists of five hydroelectric developments (HEDs): Post Falls,
Upper Falls, Monroe Street, Nine Mile, and Long Lake. The project produces an average of 95
MW of power at an approximate cost of $24/MWH. The operation of these developments is
governed in a single license issued by FERC, #2545. This license expires at the end of July
2007.

The Federal Power Act (FPA) of 1920 provides the Federal Energy Regulatory Commission
(FERC) exclusive authority to license all nonfederal hydroelectric projects that are located on
navigable waterways or federal lands. New licenses are normally issued for a period of 30 to 50
years.

The FERC relicensing process requires years of extensive planning, including environmental
studies, agency consensus and public involvement. The FPA was amended in 1986 by the
Electric Consumers Protection Act (ECPA). The amended law requires that FERC give equal
consideration to the non-generating benefits of the natural resource (fish, wildlife, aesthetics,
water quality, land use, and recreational resources, for example) along with the benefit of power
production. This range of issues is addressed through a consultation process, outlined in FERC
rules. In addition, other reviewing and conditioning authorities come into play, including the
National Environmental Policy Act (NEPA), the Clean Water Act, the Endangered Species Act,
and several portions of the Federal Power Act that create specific licensing conditioning
authorities.

These additional authorities reside in agencies at the local, state and federal level. In addition,
since the U.S. Supreme Court ruled that the Coeur d’Alene tribe owns the southern portion of
Lake Coeur d’Alene, the tribe has a significant stake in relicensing. Avista must negotiate past
and future storage charges with the tribe per Section 10(e) of the FPA. In addition, since the
project occupies federally-reserved lands for the tribe, the Bureau of Indian Affairs has
mandatory conditioning authority for a new project license, meaning that FERC has no discretion
regarding such conditions.

Consequently, the relicensing process can be very complicated, and at times has led to extended
conflict between interests. In an effort to resolve the range of issues in a more productive
fashion, relicensing efforts have more recently shifted to provide increased opportunity to
collaborate on issue resolution. This shift, recognized as the “Alternative Licensing Procedures,”
(ALP) also aims to improve coordination between the various legal authorities that come into
play during relicensing.

Avista began the relicensing process for this project several years ago with a series of
stakeholder interviews. This was near the end of the Clark Fork relicensing effort, which had
helped pioneer what became the ALP.

Appendix K Page K-2 Spokane River Relicensing

In 2001, two stakeholder meetings were held to form the relicensing team. In addition, the team
developed a Communications Protocol and Guiding Principles document. Through these efforts,
broad agreement developed to use the ALP. We made a request to FERC for approval to use the
ALP in April 2002. FERC approved the request in June 2002. We filed our formal Notice of
Intent to relicense the project in July 2002.

The ALP is a collaborative approach to decision-making for relicensing. The goal is to develop
a broad agreement that, in effect, would constitute our new license application. Over 100
stakeholder groups are involved in this effort, including: the Coeur d’Alene Tribe, U.S. Fish and
Wildlife Service, Bureau of Land Management, U.S. Forest Service, Idaho Department of
Environmental Quality, the Washington Department of Ecology, Washington Department of Fish
and Wildlife, Idaho Department of Fish and Game, Spokane Tribe, various local governments,
non-governmental interest groups, and numerous landowners and other individuals. The setting
of the project, extending through two states and several cities, as well as the broad range of other
concerns regarding the lakes, river, land use, etc. create a challenging relicensing atmosphere.

Five technical work groups, and a lead or plenary group constitute the effort currently. The work
groups have been meeting monthly to identify and discuss issues and scope studies, and will
ultimately propose protection, mitigation and enhancement measures. The upcoming year, 2003,
is the primary study season. Additional studies will follow in 2004, as will development of
proposals guiding a new license application. We must file our new application by the end of July
2005.

Relicensing has been proceeding with difficulty this year, given the wide range of interest and
high expectations of stakeholders. Our goal continues to be to reach a settlement agreement and
avoid the costs associated with protracted disagreement or heavy-handed unilateral agency
decision-making. A corollary goal is to develop, through this process, strong relationships with
the broad ranges of stakeholders that will help sustain shared interests during the implementation
of a new license.

Appendix L Page L-1 Transmission Planning
Appendix

Transmission Planning

Relationship to Resource Planning

Avista (Transmission) system Planning and Operations continues to respond to the requests from
Resource Planning for integration of resources to serve retail load. As Resource Planning
analyses installation of additional generation on the system, it will make requests for studies
from System Planning. System Planning will investigate the impacts and provide information as
requested to Resource Planing for use in evaluation of the cost-effectiveness of various resource
options. System Planning’s goal is to provide reliability and maximize the efficient use of the
transmission system.

Current Issues

Avista System Planning and Transmission Operations faces an uncertain future as a result of the
on-going restructuring of the Electric Transmission businesses as the industry moves toward a
more deregulated market. This turmoil includes several activities:

1. An increased emphasis on reliability. Both the North American Electric Reliability
Council (NERC) and the Western Electric Coordination Council (WECC) have instigated a
move toward mandatory compliance with reliability and operating criteria.
2. An increased emphasis on operational studies to determine the simultaneous capability of
transfer paths. This has resulted in the formation of four regional study groups that
determine simultaneous and non-simultaneous capabilities of all impacted transfer paths.
Included in this is the Northwest Operational Planning Study Group in which Avista
participates. The rule for operation states simply: if the flow pattern hasn’t been studied to
assure system integrity, then the system cannot be operated in that way.
3. A move toward consolidation of transmission resources into larger organization so that it will
be more completely separate from any merchant entities. On December 20, 1999 the Federal
Energy Regulatory Commission (FERC) issued its final rule (Order No. 2000) regarding the
development of Regional Transmission Organizations (RTOs). For further information
please see the write-up on RTOs and Avista’s relationship with the RTO West.

The big impact of #1 above is that previous to this move toward mandatory compliance, utilities
could occasionally violate WECC reliability criteria (usually unintentional) as long as there were
no detrimental effects on neighboring systems. Mandatory Compliance states that utilities must
now meet all criteria within their own boundaries as well as not affecting others. On June 18,
1999 the majority of the members of the WECC signed agreements to participate in the WECC’s
Reliability Management System (RMS). This system tracks violations of operating and planning
criteria with consequences ranging from letters to management and State Utility Commissions to
monetary penalties. The initial RMS implementation included only critical operating criteria. A

Appendix L Page L-2 Transmission Planning
pilot NERC compliance program is under way that will eventually blend with RMS. Ultimately
there will be a complete Mandatory Compliance system that will require utilities to get a long list
of important operating and planning criteria. The consequences for non-compliance may be
severe and include monetary penalties. The full implementation of Mandatory Compliance will
require national legislation to be effective and binding.

The increased emphasis on operational studies is a result of de-regulation and other factors
that put the transmission system of the Western Interconnection at a potentially higher
operational risk. The two large widespread outages in 1996 contributed to the urgency of
making sure the transmission system can handle transfer needs in each upcoming operating
season. While local interconnection studies are being performed, it is nearly impossible to do
long range system wide planning because no one knows what new generation will come to
fruition and what the actual generation patterns will be. Other factors, such as changes in
generation patterns on the Columbia river to help mitigate fish depletion have added complexity
to planning studies. As a result of all of this, more emphasis is being put on the near term
“operational” studies rather than longer term “planning” studies. Each sub-region will analyze
the allowable transfer levels for recognized transfer paths. Avista is an active participant in the
Northwest Operational Planning Study Group.

Expansion Possibilities & System Reconfiguration

The impact of expansion on the Avista transmission system is largely dependent upon the
location of the proposed expansion. Some of the possible solutions to various system constraints
may have the added benefit of making load and generation additions more easy to integrate.
These solutions include possible conversions of parts of the 115 kV system to a radial rather than
looped system and a significant amount of additional or reconductored 230 kV transmission
lines. Any new load or generation integration will continue to be handled on a case by case
basis.

Reliability

Avista’s transmission system is planned, designed, constructed and operated to meet peak load
demands and peak load transfers while assuring continuity of service during system disturbances
and to be consistent with sound economic planning principles. FERC Form 715 includes the
planning limits of both the transmission lines and transformer capabilities for the Avista system.
Avista Planning uses the Western Electric Coordinating Council’s “Reliability Criteria for
System Design” as a benchmark to determine the performance of Avista’s system in relation to
interconnections with other Northwest regions and utilities.

Appendix M Page M-1 Distributed Generation
Appendix

Distributed Generation

Distributed Generation (DG) is defined as:
Generation, storage, or DSM devices, measures and/or technologies that are connected to or
injected into the distribution level of the power delivery grid.

Potential benefits of DG:
• reduce circuit load
• reduce/deter T&D line construction
• customer satisfaction/service
• peak shaving
• voltage support
• fuel diversity
• increased reliability of service (some applications)
• reduced losses
• environmental advantages (i.e. burn landfill methane gas)

Potential disadvantages of DG:
• Intermittent power production (solar and wind)
• High initial capital costs
• Fuel supply and price (fuel cells, microturbines, etc.)
• Unknown maintenance cost
• Lower efficiencies
• No universally accepted standards for grid interconnection
• Need transfer switch to prevent back feed of electricity
• If power is sold to a utility, need power purchase agreement

There are some difficulties in connecting DG with the grid. In August 2002 FERC issued an
advance notice of proposed rulemaking seeking comments on standard small generator (less than
20 MW) interconnection agreements. The problems stem from:
• Lack of uniform standards and procedures.
• Project approval is too long.
• Application and interconnection fees frequently are viewed as arbitrary.
• Utility imposed operational requirements.
• Backup or standby charges are viewed as a rate-related barrier.

Power generation economics (including DG) depend on first cost, running efficiencies, fuel cost
(where applicable) and maintenance costs. Site suitability depends on size, weight, emissions,
noise and other factors. DG projections are that by 2015 the United States could account for
some 51,000 MW of installed capacity or about 5 percent of the national total. The amount of
DG presently in the U.S. is 60,000 but most of this is not connected to the grid. DG will be most
economically attractive to electric utilities in scenarios where they are faced with system

Appendix M Page M-2 Distributed Generation
constraints, particularly in transmission and distribution. For the end user, economics are
improved if customers can capture additional benefits such as reduced fuel costs for stream and
hot water through combined heat and power. Small DG equipment will fill niche markets where
T&D lines are constrained, peak loads are excessive, cogeneration opportunities exist, or grid
reliability is questioned. DG is generally defined as under 50 MW, but the majority of the
systems installed are rated less than 10 MW.

With the exception of Capstone Turbine, the microturbine market is several years from general
deployment. Commercial fuel cells are even further out but making gains. The real action in DG
is in natural gas reciprocating engines.

While the electric grid will certainly be powering the country for years to come, more and more
consumers will be augmenting their power supply with onsite power. Whatever the technology,
energy in the future will come from a variety of sources. The following is a list of DG sources:

Biomass

Generation from biomass is normally derived from methane gas (landfills etc.), municipal solid
waste, and cropland and/or forest materials. The Company’s service territory has examples of all
three (Minnesota Methane plant, Spokane solid waste facility and Kettle Falls wood-fired plant).
When generation is from wood wastes, the excess steam is used for other purposes (ex. kiln
drying) which greatly improve the overall efficiency.

The Company had a wood waste cogeneration facility bid in its last RFP. The price was about
70 mills/kWh. From past experiences the total cost of a wood-waste facility is between 50 and
70 mills/kWh.

Regulus Stud Mill has inquired about a power purchase contract and would probably start
construction when the avoided costs are sufficient to support the development. This facility
would be between 2.5 and 5.0 MWs.

Combustion Turbines

Conventional combustion turbine generators typically range in size from about 500 kW up to 25
MW for distribution applications. Fuels include natural gas, oil or a combination. Modern
single-cycle combustion turbine units typically have efficiencies in the range of 20 to 45 percent
at full load. When operating at less than full load, efficiencies can fall by as much as 25 percent.
Depending on size, costs can range between 300 and 650 $/kW, with the larger size units costing
less. Costs of 1000 $/kW or more include a gas compressor (usually needed), installation costs
and heat recovery capability.

Appendix M Page M-3 Distributed Generation
Fuel Cells

Fuel cells convert hydrogen gas to electricity through an electrochemical process, which does not
involve combustion. These chemical reactions produce electricity, heat, and water with zero
emissions. Fuel cells, therefore, are inherently quiet, have the potential to be environmentally
benign, and very efficient.

Fuel cells use hydrogen as the fuel and therefore need a cost-effective way to reform other
available fuels into hydrogen. Some of the fuels presently being used are natural gas, propane,
methanol, and diesel. There are five fuel cell technologies, named for their respective
electrolytes, ranging in operating temperatures from 50 degrees C. to 1000 degrees C. These are:
solid polymer or proton exchange membrane (PEM), alkaline, phosphoric acid (PAFC), molten
carbonate (MCFC), and solid oxide (SOFC). 200 kW phosphoric acid fuel cells have been
commercially available for the past few years. In the long run solid oxide fuel cells technologies
may hold the most promise, although the leading fuel cell technology at the moment is the PEM
cell. PEM is better suited for the transportation sector because they are lighter weight, start fast
and have lower temperatures.

Fuel cells today range in size from 1 kW to 3000 kW based on their configuration. The
efficiencies are between 36 and 60 percent and the installation cost range is determined to be
4000 to 5000 $/kW. The range of variable costs is 1.9 to 15.3 mills/kWh without the cost of
fuel.

Geothermal

Geothermal is a generating facility that uses the heat of the earth as its energy source. These
facilities are very site specific as relating to costs, etc. Some of the existing sites are generating
at a range of 50 to 60 mills/kWh.

Manure-To-Energy Digester

Using manure as a fuel for generating plants has been used in other areas. Presently there are a
few sites being evaluated for these facilities in the northwest. It takes about one dairy cow to
produce the fuel for 0.3 kW. Estimated capital costs are about $2800/kW.

Microturbines

Microturbines are in the market place as a substitute for internal combustion engines. They burn
a variety of fuels (natural gas, hydrogen, propane or diesel) and come in a wide range of sizes, 25
kW to 500 kW. The efficiencies range from 14 to 30 percent, although the majority of units have
about 27 percent. Capstone claims 70 to 80 percent efficiency when the unit is part of a more
expensive cogeneration system. Microtrubines have low NOx emissions making them
environmentally friendly. Without cogeneration, the capital costs range from 500 to 1200 $/kW
with variable costs of 4 to 10 mills/kWh.

Appendix M Page M-4 Distributed Generation
Reciprocating Engine

The most common alternate power source is the reciprocating engine. Fuels include natural gas,
diesel, landfill gas and digester gas. Reciprocating engines have higher emissions than many
alternatives and therefore usually require pollution control technology. They tend to be highly
reliable, but require more maintenance.

• Diesel: The cost and efficiency of these engines have a lot to do with their size. Size
range is between 20 kW and 6+ MW with costs of 350 to 500 $/kW and with an
efficiency of between 30 and 45 percent. Variable costs range between 5 and 15
mills/kWh. These units have a proven niche as standby generation in commercial and
industrial applications and dominate the DG market place.

• Natural Gas: These engines have basically the same characteristics as the diesel engines
but with a slightly higher capital and variable operating costs (7 to 20 mills/kWh). These
units generally have a range in size of 5 kW to 6 MW.

Ride-Through Technologies

There is a question if these technologies should be classified as DG. The difference between this
technology and DG is the time period in which the systems provide power to the load. In other
words, these systems have a finite period of time in providing energy. These technologies
include flywheel, battery, capacitors, magnetic energy storage, compressed air, and micro-
pumped storage. These energy storage facilities improve the efficiency, reliability and security
for DG systems plus they eliminate voltage swings because of shifting power loads.

The flywheel technology normally replaces batteries. Temperature ranges have no effect and
their life should be decades not years. Flywheels are generally in the 150 kW to 1 MW range.
Six kWh systems are presently in operation.

Small Hydro

There are several small hydro facilities operating in the Company’s service territory. Renewable
generating facilities, such as hydro, are encouraged by the federal legislation called PURPA.
Since the fuel is usually free, the major cost of these facilities is the capital.

Solar

Solar systems are still higher in cost than other forms of DG. There are two types of solar
generation, central solar station and photovoltaic. Thin film photovoltaic technology has been
commercial for several years and is usually just a few kW in size. Solar costs are 4000 to 10,000
$/kW with energy costs of 200 to 400 mills/kWh. Although the costs are presently around
$6/watt, the goal is to have the cost down to $3/watt in the next few years.

Appendix M Page M-5 Distributed Generation
There are many examples of solar generating systems. There is one located in downtown
Spokane that is 10 kW in size and cost $100,000 to install. A solar station in Mojave Desert, CA
of several megawatts produces energy at 150 mills/kWh. Another system in Kipland, CA has a
28 percent plant factor. Another solar station near Richland, WA cost $8,000/kW.

Wind

Wind generation has had a significant increase throughout the world with a corresponding
decrease in costs. There are approximately 17,000 MW of wind generation installed worldwide.
There are wind turbines now installed in 26 states. The five states with the greatest wind
potential are North Dakota, Texas, Kansas, South Dakota and Montana. One of the largest wind
farms is located in the northwest, the 293 MW Stateline Wind Generating Project.

The average cost of wind has decreased about 80 percent during the past decade. About half of
the decrease is the result of improved efficiency and economies of scale and the other half is
from improved manufacturing techniques.

The main problem with wind energy is that it is inconsistent. Having an intermittent fuel source
makes it difficult to schedule to serve firm loads. The capacity factor on the best sites that are
being developed is normally 25 to 30 percent. There has been one published capacity factor of 40
percent.

Some of the advantages for wind generation is it is renewable, no escalation in cost due to fuel
prices, and no air pollutants. There is also a federal tax credit of 17 mills/kWh for the first 10
years. So over the life of the facility (est. 20 years) it would reduce costs by about 7 mills.

Small wind turbines, that are available for home installations, have costs that range from 2500 to
5000 $/kW. The smaller sizes are usually from a few kW to about 50 kW. These units require
from 3 to 5 mph winds to start operating. A 10 kW home wind kit was advertised for $27,000.

The large wind turbines used in commercial wind farms are sized from 250 kW to over 1,500
kW. These units need 7 mph wind to start and at least 13 mph average annual wind speed to be
cost effective. The capital cost range from 700 to 1100 $/kW and produce energy at 40 to 60
mills/kWh before the tax credit is applied.

Installed Costs

DG installed costs can be as high as 2.5 times the equipment costs.
Reciprocating Engines 700 to 1500 $/kW
Gas Turbines 1000 to 1500
Microturbines 1500 to 2000
Fuel Cells 4000 to 5000

Appendix M Page M-6 Distributed Generation
Reliability

DG reliability is by nature a case-by-case issue. Most DG applications will probably have little
impact on the reliability of the distribution system, as it is presently measured. Supporting the
distribution system with DG can mutually benefit utilities and customers but can negatively
impact reliability. Where and how DG is interconnected determines its value to the system.

The Company’s View

The Company views DG as not a threat but as another choice available to the utility. In the
future there will be a vibrant market for personalized power that uses DG technology. The
Company is financially supporting fuel cell development and therefore is a part of the DG
movement. The key to any DG project is the source location relative to the substation. Presently
within the Company, any proposed DG project includes analysis to look at the effects on its
system.

Appendix N Page N-1 Historic Data
Appendix

Historic Data

Hydroelectric Plants

Post Falls
FERC License Expiration Date: 07/31/2007

Rated Capacity: Total No. 1 No. 2 No. 3 No. 4 No. 5 No. 6
(Peak in MW) 18.0 2.9 2.9 2.9 2.9 2.9 3.5

Upper Falls
FERC License Expiration Date: 07/31/2007

Rated Capacity: Total No. 1
(Peak in MW) 10.2 10.2

Monroe Street
FERC License Expiration Date: 07/31/2007

Rated Capacity: Total No. 1
(Peak in MW) 14.8 14.8

Nine Mile
FERC License Expiration Date: 07/31/2007

Rated Capacity: Total No. 1 No. 2 No. 3 No. 4
(Peak in MW) 24.5 4.1 4.1 8.1 8.2

Long Lake
FERC License Expiration Date: 07/31/2007

Rated Capacity: Total No. 1 No. 2 No. 3 No. 4
(Peak in MW) 88.0 22.0 22.0 22.0 22.0

Little Falls
FERC License Expiration Date: N/A (License not required)

Rated Capacity: Total No. 1 No. 2 No. 3 No. 4
(Peak in MW) 36.0 9.0 9.0 9.0 9.0

Maintenance and outage records for the above plants are not computerized and exist in log style
handwritten form. It would take many man-hours to obtain the necessary data to determine accurate
forced outage and availability data. Because of this, five years of data is not included. The data is
available for inspection or recording at any time.

Appendix N Page N-2 Historic Data
Noxon Rapids
FERC License Expiration Date: 03/01/2046

Rated Capacity: Total No. 1 No. 2 No. 3 No. 4 No. 5
(Peak in MW) 527 102 102 102 91 130

Forced Equivalent Forced Equivalent
Outage Availability Outage Availability
Year Month Rate Factor Year Month Rate Factor

1998 Jan 0.98 99.40 2001 Jan 0.00 100.00
Feb 0.00 100.00 Feb 0.00 99.97
Mar 1.08 97.53 Mar 0.40 81.75
Apr 0.37 99.82 Apr 0.00 100.00
May 1.17 98.62 May 0.22 99.84
Jun 0.00 100.00 Jun 0.65 99.58
Jul 0.00 99.57 Jul 0.05 99.98
Aug 8.21 96.00 Aug 0.46 83.53
Sep 2.99 92.14 Sep 0.27 96.95
Oct 4.35 90.39 Oct 46.91 38.67
Nov 0.38 98.37 Nov 53.27 59.53
Dec 0.35 99.74 Dec 22.46 72.51

1999 Jan 0.02 99.88 2002 Jan 0.04 85.79
Feb 0.01 95.27 Feb 0.19 87.36
Mar 0.00 93.12 Mar 0.22 79.93
Apr 0.26 99.82 Apr 0.12 88.29
May 0.00 100.00 May 0.37 99.67
Jun 0.00 99.67 Jun 0.30 99.70
Jul 0.00 99.86 Jul 0.16 99.49
Aug 0.00 100.00 Aug 5.45 97.57
Sep N/A N/A Sep 0.00 99.93
Oct 2.66 75.74 Oct 0.00 100.00
Nov 0.00 80.00 Nov 0.87 92.43
Dec 0.03 91.19 Dec 0.00 100.00

2000 Jan 0.06 99.82
Feb 0.43 99.72
Mar 0.00 93.42
Apr 0.00 100.00
May 0.00 100.00
Jun 0.00 100.00
Jul 0.00 100.00
Aug 1.53 99.16
Sep 0.00 97.78
Oct 0.00 87.42
Nov 1.54 79.15
Dec 0.00 93.33

Equivalent Availability Factor = Availability Factor = (Available Unit Days/Period Unit Days) * 100.
Forced Outage Rate = (Forced Outage Unit Days/(Service Unit Days + Forced Outage Unit Days)) * 100.

Appendix N Page N-3 Historic Data
Cabinet Gorge
FERC License Expiration Date: 03/01/2046

Rated Capacity: Total No. 1 No. 2 No. 3 No. 4
(Peak in MW) 246 63.5 57.5 67.5 57.5

Forced Equivalent Forced Equivalent
Outage Availability Outage Availability
Year Month Rate Factor Year Month Rate Factor

1998 Jan 1.11 97.86 2001 Jan 2.67 73.87
Feb 0.02 99.27 Feb 0.00 74.81
Mar 0.04 99.98 Mar 1.33 74.93
Apr 0.00 100.00 Apr 0.00 100.00
May 0.06 99.94 May 0.05 99.96
Jun 0.01 99.99 Jun 0.00 99.92
Jul 0.00 100.00 Jul 3.31 97.98
Aug 0.01 100.00 Aug 0.00 99.13
Sep 0.00 99.88 Sep 0.00 100.00
Oct 0.08 91.84 Oct 0.00 100.00
Nov 0.00 99.82 Nov 0.00 100.00
Dec 0.32 99.63 Dec 0.00 100.00

1999 Jan 0.00 100.00 2002 Jan 0.00 99.94
Feb 0.00 95.27 Feb 0.03 99.69
Mar 0.00 100.00 Mar 0.00 100.00
Apr 0.00 100.00 Apr 0.00 99.81
May 0.01 99.99 May 0.19 99.82
Jun 0.00 100.00 Jun 0.00 100.00
Jul 0.05 99.96 Jul 0.00 100.00
Aug 0.51 99.74 Aug 0.00 100.00
Sep 0.00 100.00 Sep 0.00 100.00
Oct 0.00 98.86 Oct 0.00 75.56
Nov 0.00 100.00 Nov 0.00 78.32
Dec 0.00 100.00 Dec 0.00 98.32

2000 Jan 0.00 99.58
Feb 0.00 100.00
Mar 0.00 100.00
Apr 0.62 99.48
May 0.00 100.00
Jun 0.00 100.00
Jul 0.00 100.00
Aug 0.00 100.00
Sep 0.00 77.50
Oct 0.00 75.00
Nov 0.00 75.00
Dec 0.99 74.26

Equivalent Availability Factor = Availability Factor = (Available Unit Days/Period Unit Days) * 100.
Forced Outage Rate = (Forced Outage Unit Days/ (Service Unit Days + Forced Outage Unit Days)) * 100.

Appendix N Page N-4 Historic Data
Coal-Fired Plants

Colstrip No. 3
Rated Capacity = 700 MW
Service Date = 1/10/1984
Design Plant Life = 35 years
Avista’s Share = 15%

Forced Equivalent Forced Equivalent
Outage Availability Outage Availability
Year Month Rate Factor Year Month Rate Factor

1998 Jan 8.51 84.98 2001 Jan 10.26 77.61
Feb 15.19 85.01 Feb 0.00 95.68
Mar 8.22 91.97 Mar 0.00 47.47
Apr 0.00 86.53 Apr 0.00 0.00
May 0.09 100.00 May 25.85 48.33
Jun 0.00 100.00 Jun 0.05 99.63
Jul 0.00 99.70 Jul 0.80 98.48
Aug 13.14 87.08 Aug 1.61 97.01
Sep 0.00 97.95 Sep 0.38 96.41
Oct 27.42 71.73 Oct 0.67 92.01
Nov 0.00 99.99 Nov 14.17 85.21
Dec 0.00 99.61 Dec 0.00 98.60

1999 Jan 14.65 82.50 2002 Jan 85.51 14.32
Feb 27.07 72.23 Feb 4.32 59.16
Mar 11.34 86.98 Mar 3.29 96.62
Apr 0.18 98.74 Apr 0.00 97.18
May 0.00 69.43 May 0.00 97.84
Jun 0.15 99.85 Jun 84.90 15.12
Jul 17.37 81.59 Jul 84.30 12.67
Aug 4.43 92.76 Aug 0.00 99.20
Sep 0.10 90.98 Sep 10.50 87.76
Oct 0.36 95.36 Oct 5.10 93.84
Nov 18.77 79.71 Nov 27.40 71.09
Dec 0.00 98.22 Dec 100.00 0.00

2000 Jan 9.55 88.97
Feb 2.46 97.04
Mar 0.00 99.75
Apr 16.11 84.49
May 22.63 15.02
Jun 10.83 87.11
Jul 14.74 82.43
Aug 6.82 81.48
Sep 0.24 92.81
Oct 0.00 95.23
Nov 0.43 94.26
Dec 16.53 83.70
Note:
Avista uses 111 MW/unit based on an over pressure mode of operation.
Forced Outage Rate = Forced Outage Hours/ (Service Hours + Forced Outage Hours) * 100.
Equivalent Availability Factor:
(Available Hours – ((Derated Hours * size of Reduction)/ Maximum Capacity) * 100)/ Period Hours

Appendix N Page N-5 Historic Data
Colstrip No. 4
Rated Capacity = 700 MW
Service Date = 4/6/1986
Design Plant Life = 35 years
Avista’s Share = 15%

Forced Equivalent Forced Equivalent
Outage Availability Outage Availability
Year Month Rate Factor Year Month Rate Factor

1998 Jan 0.00 98.11 2001 Jan 0.00 99.85
Feb 0.00 99.97 Feb 0.10 99.89
Mar 0.00 95.58 Mar 0.00 96.09
Apr 0.00 91.99 Apr 0.13 96.40
May 0.12 47.40 May 7.80 91.15
Jun 22.18 77.82 Jun 55.65 43.82
Jul 7.22 93.83 Jul 11.18 88.41
Aug 0.29 85.84 Aug 0.60 98.52
Sep 0.25 90.99 Sep 0.36 89.95
Oct 0.00 99.98 Oct 0.00 99.98
Nov 25.28 74.52 Nov 0.00 95.59
Dec 6.15 93.98 Dec 23.97 73.83

1999 Jan 1.97 93.95 2002 Jan 12.86 81.42
Feb 0.28 98.51 Feb 0.00 99.37
Mar 9.33 89.78 Mar 0.40 79.45
Apr 0.40 98.29 Apr 0.28 90.80
May 0.12 97.78 May 0.00 98.94
Jun 0.00 59.90 Jun 0.00 99.52
Jul 0.50 72.31 Jul 0.70 98.76
Aug 0.07 94.22 Aug 0.00 99.65
Sep 0.00 98.71 Sep 10.72 87.65
Oct 0.20 98.85 Oct 13.28 82.91
Nov 0.00 99.89 Nov 0.00 85.53
Dec 0.00 92.27 Dec 0.00 98.78

2000 Jan 12.67 87.03
Feb 9.65 90.46
Mar 3.38 96.65
Apr 14.58 85.44
May 3.43 97.78
Jun 0.00 6.88
Jul 36.71 57.15
Aug 1.47 99.52
Sep 91.53 8.47
Oct 63.48 37.05
Nov 0.86 98.50
Dec 0.00 99.80

Note: Avista uses 111 MW/unit based on an over pressure mode of operation.

Appendix N Page N-6 Historic Data
Other Resources

Kettle Falls
Rated Capacity = 50 MW
Service Date = 12/1/1983
Design Plant Life = 35 years

Forced Forced
Outage Availability Outage Availability
Year Month Rate Factor Year Month Rate Factor

1998 Jan 0.00 100.00 2001 Jan 3.90 96.10
Feb 4.40 95.60 Feb 0.00 100.00
Mar 0.05 96.47 Mar 0.00 100.00
Apr 0.00 100.00 Apr 0.22 99.78
May 0.00 100.00 May 0.81 99.53
Jun 0.00 0.00 Jun 0.11 99.89
Jul 0.33 95.22 Jul 3.20 96.80
Aug 0.25 99.75 Aug 0.12 99.88
Sep 0.60 99.40 Sep 0.00 100.00
Oct 0.52 99.61 Oct 0.05 99.95
Nov 0.00 100.00 Nov 0.00 100.00
Dec 2.81 97.19 Dec 0.04 99.97

1999 Jan 0.11 99.89 2002 Jan 0.19 99.81
Feb 0.54 99.17 Feb 0.00 100.00
Mar 0.48 99.64 Mar 17.16 82.84
Apr 0.16 99.87 Apr 0.00 100.00
May 0.00 100.00 May 0.00 100.00
Jun 1.40 62.28 Jun 0.00 0.00
Jul 0.19 99.85 Jul 0.00 0.00
Aug 2.83 97.17 Aug 0.00 100.00
Sep 1.97 98.03 Sep 5.84 94.16
Oct 30.02 69.98 Oct 0.00 100.00
Nov 0.59 99.41 Nov 2.70 97.30
Dec 24.01 75.99 Dec 0.67 99.33

2000 Jan 4.76 95.24
Feb 2.25 97.75
Mar 0.09 99.91
Apr 10.58 90.02
May 0.14 99.92
Jun 4.41 95.59
Jul 4.91 95.09
Aug 0.23 99.77
Sep 0.00 100.00
Oct 0.00 100.00
Nov 1.10 98.90
Dec 0.00 100.00

Availability Factor = (Available Hours/ Period Hours) * 100

Appendix N Page N-7 Historic Data
PURPA Hydroelectric Plants

John Day Creek Hydroelectric Project/David Cereghino
Rated Capacity = 900 kW
Hours Connected to System = Not Available
Level of Dispatchability = none
Expiration Date = 9/21/2022

Year Month Generation-MWh Year Month Generation-MWh

1998 Jan 156 2001 Jan 66
Feb 142 Feb 30
Mar 110 Mar 10
Apr 141 Apr 30
May 150 May 44
Jun 428 Jun 400
Jul 425 Jul 400
Aug 430 Aug 219
Sep 401 Sep 163
Oct 307 Oct 86
Nov 292 Nov 101
Dec 268 Dec 85

1999 Jan 246 2002 Jan 175
Feb 206 Feb 0
Mar 148 Mar 0
Apr 268 Apr 59
May 286 May 117
Jun 423 Jun 171
Jul 395 Jul 412
Aug 438 Aug 381
Sep 354 Sep 209
Oct 273 Oct 125
Nov 202 Nov 107
Dec 166 Dec 95

2000 Jan 124
Feb 74
Mar 85
Apr 88
May 108
Jun 367
Jul 389
Aug 211
Sep 60
Oct 110
Nov 121
Dec 85

Note: Scheduled energy not metered energy.

Appendix N Page N-8 Historic Data
Jim Ford Creek Power Project/Ford Hydro Limited Partnership
Rated Capacity = 1,500 kW
Hours Connected to System = Not Available
Level of Dispatchability = none
Expiration Date = 4.14.2023

Year Month Generation-MWh Year Month Generation-MWh
1998 Jan 730 2001 Jan 48
Feb 639 Feb 67
Mar 894 Mar 267
Apr 774 Apr 863
May 516 May 850
Jun 554 Jun 393
Jul 433 Jul 315
Aug 254 Aug 0
Sep 51 Sep 0
Oct 0 Oct 0
Nov 0 Nov 15
Dec 360 Dec 126

1999 Jan 587 2002 Jan 230
Feb 1040 Feb 627
Mar 665 Mar 650
Apr 973 Apr 937
May 942 May 888
Jun 463 Jun 336
Jul 84 Jul 149
Aug 0 Aug 0
Sep 0 Sep 0
Oct 0 Oct 0
Nov 3 Nov 0
Dec 57 Dec 9

2000 Jan 418
Feb 360
Mar 892
Apr 994
May 719
Jun 438
Jul 73
Aug 0
Sep 0
Oct 0
Nov 25
Dec 7

Appendix N Page N-9 Historic Data
Big Sheep Hydroelectric Project/Sheep Creek Hydro, Inc.
Rated Capacity = 1,500 kW
Hours Connected to System = Not Available
Level of Dispatchability = none
Expiration Date = 6/4/2021

Year Month Generation-MWh Year Month Generation-MWh

1998 Jan 898 2001 Jan 76
Feb 469 Feb 113
Mar 830 Mar 181
Apr 1218 Apr 629
May 988 May 1206
Jun 1066 Jun 1170
Jul 1221 Jul 759
Aug 575 Aug 225
Sep 458 Sep 132
Oct 139 Oct 139
Nov 176 Nov 337
Dec 317 Dec 434

1999 Jan 695 2002 Jan 638
Feb 748 Feb 543
Mar 695 Mar 761
Apr 1142 Apr 1133
May 1029 May 1180
Jun 1121 Jun 829
Jul 1150 Jul 951
Aug 1076 Aug 218
Sep 703 Sep 147
Oct 254 Oct 139
Nov 161 Nov 143
Dec 654 Dec 400

2000 Jan 422
Feb 443
Mar 1147
Apr 1180
May 1211
Jun 1079
Jul 898
Aug 241
Sep 168
Oct 164
Nov 127
Dec 103

Appendix N Page N-10 Historic Data
Upriver Power Project/City of Spokane
Rated Capacity = 16,700 kW
Hours Connected to System = Not Available
Level of Dispatchability = none
Expiration Date = 7/1/2004

Year Month Generation-MWh Year Month Generation-MWh

1998 Jan 6090 2001 Jan 1871
Feb 9035 Feb 1918
Mar 9495 Mar 3900
Apr 9867 Apr 7329
May 9908 May 10071
Jun 8178 Jun 5661
Jul 3527 Jul 1758
Aug 1423 Aug 452
Sep 2178 Sep 994
Oct 3678 Oct 3072
Nov 4232 Nov 3832
Dec 8602 Dec 7159

1999 Jan 10724 Jan 9274
Feb 8703 Feb 7793
Mar 10238 Mar 10929
Apr 9255 Apr 7410
May 8349 May 7295
Jun 8383 Jun 7427
Jul 6266 Jul 5753
Aug 2520 Aug 1374
Sep 2417 Sep 2127
Oct 3467 Oct 3589
Nov 4844 Nov 2615
Dec 9988 Dec 3648

2000 Jan 7597
Feb 9352
Mar 10715
Apr 7098
May 8327
Jun 9501
Jul 3620
Aug 1170
Sep 2341
Oct 4239
Nov 3914
Dec 3245

Appendix N Page N-11 Historic Data
Meyers Falls/Hydro Technology Systems
Rated Capacity = 1300 kW
Hours Connected to System = Not Available
Level of Dispatchability = none
Avista sold the plant to Hydro Technology on 2/12/99
Expiration Date = 12/31/2006

Year Month Generation-MWh Year Month Generation-MWh

1999 Jan 0 2001 Jan 817
Feb 0 Feb 865
Mar 439 Mar 773
Apr 829 Apr 947
May 825 May 916
Jun 871 Jun 945
Jul 834 Jul 791
Aug 877 Aug 251
Sep 826 Sep 75
Oct 757 Oct 165
Nov 819 Nov 378
Dec 877 Dec 562

2000 Jan 1603 2002 Jan 841
Feb 929 Feb 911
Mar 198 Mar 870
Apr 914 Apr 959
May 884 May 913
Jun 941 Jun 949
Jul 914 Jul 925
Aug 891 Aug 618
Sep 572 Sep 259
Oct 575 Oct 288
Nov 757 Nov 439
Dec 834 Dec 610

Appendix N Page N-12 Historic Data
PURPA Thermal Plants

Minnesota Methane/MM Spokane Energy LLL
Rated Capacity = 900 kW
Hours Connected to system = Not Available
Level of Dispatchability = none
Expiration Date = 4/03/2016

Year Month Generation-MWh Year Month Generation-MWh

1998 Jan 0 2001 Jan 406
Feb 0 Feb 232
Mar 0 Mar 348
Apr 0 Apr 432
May 0 May 242
Jun 228 Jun 340
Jul 454 Jul 241
Aug 417 Aug 173
Sep 420 Sep 230
Oct 417 Oct 359
Nov 529 Nov 366
Dec 496 Dec 314

1999 Jan 379 2002 Jan 388
Feb 256 Feb 186
Mar 418 Mar 277
Apr 411 Apr 374
May 515 May 402
Jun 433 Jun 327
Jul 482 Jul 336
Aug 456 Aug 257
Sep 472 Sep 257
Oct 473 Oct 246
Nov 457 Nov 288
Dec 473 Dec 325

2000 Jan 320
Feb 413
Mar 393
Apr 496
May 427
Jun 485
Jul 412
Aug 490
Sep 459
Oct 454
Nov 494
Dec 367

Appendix O Page O-1 Avoided Cost Details
Appendix

Avoided Cost Details

Administrative avoided costs, as opposed to those developed with a model, are determined by a
public utility commission process that is intended to represent the costs a utility would otherwise
incur to generate or purchase power if not acquired from another source. These costs would
apply to customer owned resources made available to the Company.

In general, avoided costs are meant to represent the incremental cost of new electric resources
available to a utility. Avoided cost rates reflect the price of power from the avoided resource or
resource mix. These rates are often applied to the purchase of energy from PURPA qualifying
facilities (QF). In some cases, the avoided cost is used to determine the cost-effectiveness of
potential resource alternatives.

Presently, the avoided cost methodology used in the filed tariff for the purchase of qualifying
facilities output is very different as determined in the two states of Washington and Idaho. In
Washington the avoided cost schedule provides baseline payments for QFs under one megawatt.
These standard firm energy rates are based on projected monthly market prices capped at the cost
of a gas-fired CCCT. The annual rates in $/MWh for the next four years are as follows:

• 2004 – $33.11
• 2005 – $33.67
• 2006 – $33.79
• 2007 – $35.50

For QFs over one megawatt, the WUTC has in place a bidding system that allows the company
to compare the value of a QF to other resource alternatives.

In Idaho the avoided cost schedule is for QFs under ten megawatts. The IPUC assumes that
there are no future surplus periods for the utilities and the avoided resource of choice is a gas-
fired CCCT. The non-levelized rates in $/MWh for the next four years are as follows:

• 2004 – $41.35
• 2005 – $42.39
• 2006 – $43.45
• 2007 – $44.54

For QFs over ten megawatts, the IPUC methodology uses the company’s IRP in determining the
rate to be paid a QF. The methodology is based on the preferred resource plan as found in the
current IRP report.

Appendix P Page P-1 NWPPC Assumptions
Appendix

NWPPC Assumptions

The following text contains assumptions from the Northwest Power Planning Council (NWPPC)
regarding new resources. This data comes directly from the most recent draft of the forthcoming
NWPPC Fifth Power Plan.

DRAFT

Northwest Power Planning Council
New Resource Characterization for the Fifth Power Plan
Natural Gas Simple-Cycle Gas Turbine Power Plants
May 20, 2002

This paper describes the technical characteristics and cost and performance assumptions to be
used by the Northwest Power Planning Council for assessments involving new natural gas
simple-cycle gas turbine power plants. The intent is to characterize a typical facility, recognizing
that actual facilities will differ from these assumptions in the particulars. We anticipate using
these assumptions in our price forecasting and system reliability models. The assumptions may
also be used in analyzing the issue of maintaining adequate system reliability. Others may use
the Council’s technology characterizations for their own purposes.

Gas (“combustion”) turbine power plants are based on aircraft jet engine technology. A gas
turbine power plant consists of a gas compressor, fuel combustors and a gas expansion turbine.
Air is compressed in the gas compressor. Energy is added to the compressed air by combusting
liquid or gaseous fuel in the combustor. The hot, compressed air is expanded through the gas
turbine. The gas turbine drives both the compressor and an electric power generator. Gas
turbine power plants are available as heavy-duty “frame” machines specifically designed as
stationary engines, or as aeroderivative machines - aircraft engines adapted to stationary
applications. Aeroderivative machines tend to be more thermally efficient than frame machines,
but more costly to purchase and operate. Stationary gas turbine technology development is
strongly driven by gas turbine applications in the military and aerospace industries.

The principal environmental concerns associated with simple-cycle gas turbines have been
emissions of nitrogen oxides (NOx) and carbon monoxide (CO). Noise has been a concern at
sites near residential and commercial areas. Fuel oil operation may produce sulfur dioxide. Like
other fossil fuel power plants, gas turbines produce carbon dioxide. Within the past decade, the
commercial introduction of “low-NOx” combustors and high temperature selective catalytic
controls for NOx and CO, has enabled the control of NOx and CO emissions from simple-cycle
gas turbines to levels comparable to combined-cycle power plants.

Because of the ability of the Northwest hydropower system to supply short-term peaking
capacity, simple-cycle gas turbines have been a minor element of the regional power system. As

Appendix P Page P-2 NWPPC Assumptions
of January 2000, about 900 megawatts of simple-cycle gas turbine capacity was installed in the
Northwest, comprising less than 2% of system capacity. The power price excursions, threats of
shortages and abnormally poor hydro conditions of 2000 and 2001 sparked a renewed interest in
simple-cycle turbines as a hedge against high power prices, shortages and poor water. About
360 megawatts of simple-cycle gas turbine capacity has been installed in the region since 2000,
primarily by large industrial consumers exposed to wholesale power prices and by utilities with
direct exposure to hydropower uncertainty (including Bonneville slice customers).

The proposed reference plant is generally based on the 47 megawatt (nominal) General Electric
LM6000PC Sprint gas turbine generator. Aeroderivative gas turbines such as the LM6000 have
been the predominant type of simple-cycle machine installed in response to last year’s price
excursions, both in the Northwest as well as elsewhere on the western grid. Fuel is assumed to
be pipeline natural gas. A firm gas transportation contract with capacity release capability is
assumed, in lieu of backup fuel. Air emission controls include water injection plus selective
catalytic reduction for NOx control and an oxidation catalyst for CO control. The machine is
assumed to be located at an existing gas-fired power plant site and would therefore not require
development of site infrastructure.

Issues:

Is the assumption of firm gas transportation in lieu of backup fuel such as fuel oil or propane
reasonable?

We are assuming emission control levels comparable to those required of permanently sited
simple-cycle units in California. Are these reasonable, or unrealistically stringent for the
Northwest? Would capital or O&M costs change significantly with less stringent environmental
controls?

The proposed forced outage assumption is much lower than those reported in the Generation
Availability Data System. The average age of units represented in the GADS data is greater than
20 years and not believed to be representative of new units. The proposed forced outage
assumption is based on monitoring of newer units (LM6000s).

In general, the proposed assumptions are those needed by the Council for its analytical efforts. Is
there additional information that might be useful to others that we should include for this and
other technologies?

We have not assessed the availability of sites (i.e. potential capacity limits) because earlier
capacity addition studies show little development of simple-cycle gas turbines. However,
simple-cycle gas turbines may be an economical approach to maintaining system reliability.
How should we approach the issue of site availability and infrastructure requirements?

The capital cost estimate is based on a limited number of published cost reports. Can we assume
that these “Press release” costs are a reasonable basis for generic capital costs?

Appendix P Page P-3 NWPPC Assumptions
Table 1: Resource characterization: Natural gas simple-cycle gas turbine power plants

Facility Natural gas-fired aeroderivative gas turbine generator
set. 47 MW new & clean output @ ISO conditions.
Water injection plus SCR for NOx control, CO
catalyst for CO control. Single unit at existing power
plant site.
Based on GE LM6000 PC Sprint
Fuel Pipeline natural gas, firm transportation contract with
capacity release provisions.

Technology base year 2000 Fifth plan base year.
Price base year 2000 Fifth plan base year.
Net power output New & clean: 47.1 MW
Lifetime average: 46.6 MW
GE LM6000PC Sprint rating less 2% inlet & exhaust
losses.
Arbitrary 1% average lifetime degradation.
Lead time Development: 12 months
Construction: 12 months
4th plan values.
Availability Scheduled outage factor: 6% (21 days/yr)
Forced outage rate: 3%
Mean time to repair: 80 hours
Availability: 91%
Scheduled outage based on 1995 - 99 GADS “Jet
Engines” 20+ MW capacity and consistent w/fleet
monitoring. FOR based on LM6000 fleet
monitoring. MTR based on GADS.
Heat rate (HHV) New & clean: 9550 Btu/kWh
Lifetime average: 9750 Btu/kWh
Vintage improvement: -0.6%/yr
GE Aero Energy LM6000, adjusted for inlet &
exhaust losses. ISO conditions.
Improvement is average for 2000 - 2019 from 4th
Plan.
Seasonality Will provide table of ambient temperature/output
factors using historical weather data for three regions.
Existing table needs to be normalized to ISO output
needs.
Service life 30 years 4th Power plan.

Capital cost Development: $2.5 million ($54/kW)
Construction (overnight): $680/kW (base) +/- 20%

Development cost based on 4th Plan factors.
Construction costs based on published costs from
several projects.
Capital replacement $1.25/kW/yr Based on a feasibility study supplied to the Council.

Appendix P Page P-4 NWPPC Assumptions
Non-fuel O&M cost Fixed O&M: $13/kW/yr
Property Tax: $13/kW/yr
Insurance: $2/kW/yr
Variable: $32.40/MWh
Vintage improvement-0.6%/yr
Based on a feasibility study supplied to the Council
except prop tax & insurance. Property tax &
insurance are Council’s generic values of 1.4% &
0.25% assessed value, respectively.
Vintage improvement is 4th Plan forecast average for
2000 - 2019.
Financing Mix of IPP & Utility

SOx Negligible
NOx 5 ppmv@15% O2 Permanent permit reqmts for recent CA peakers.
CO 6 ppmv@15% O2 Permanent permit reqmts for recent CA peakers.
Particulates 0.01gr/scf Permanent permit reqmts for recent CA peakers.
CO2 1115 lb/MWh (560 T/Gwh) Based on EPA “standard” fuel carbon content
assumptions.

Site Availability Not assessed.

________________________________________

q:\jk\5th plan\resource update\5p resource asmp gas gt plants (052002).doc

Appendix P Page P-5 NWPPC Assumptions
DRAFT

Northwest Power Planning Council
New Resource Characterization for the Fifth Power Plan
Coal-Fired Power Plants
May 17, 2002

This paper describes the technical characteristics and cost and performance assumptions to be
used by the Northwest Power Planning Council for assessments involving new coal-fired power
plants. The intent is to characterize a typical facility, recognizing that actual facilities will differ
from these assumptions in the particulars. We anticipate using these assumptions in price
forecasting and system reliability assessment models. Others may use the Council’s technology
characterizations for their own purposes.

Coal-fired steam-electric power plants are a mature technology, in use for over a century. Coal-
fired power plants are the major source of power in eastern electricity supply systems and the
second largest component of the western grid. Currently, over 36,000 megawatts of coal steam-
electric power plants are in service on the western electricity grid, comprising about 23% of
generating capacity. In recent years, however, the economic and environmental advantages of
combined-cycle gas turbines, low load growth and promise of advanced coal-based technologies
with superior efficiency and environmental characteristics eclipsed conventional coal-fired
steam-electric technology, at least in the United States. Since 1990, less than 500 megawatts of
new coal-fired steam electric plant entered service on the western grid.

The future prospects for coal-fired steam-electric power plants may be changing. Like
reciprocating internal combustion engines, another mature technology, the economic and
environmental characteristics of coal-fired steam-electric power plants have greatly improved.
These factors, combined with the prospect of stable or declining coal prices may reinvigorate the
competition between coal and natural gas and lessen the near-term prospects for revolutionary
coal-based technologies.

The capital cost of coal-fired steam-electric plants has declined about 25% (constant dollars)
since the early 1990s with little or no sacrifice to thermal efficiency, reliability or environmental
performance. This cost reduction is attributable to plant performance improvements, automation
and reliability improvements, equipment cost reduction, reduced construction schedule, and
increased market competition (DOE, 1999). Coal prices also have declined during this period as
a result of stagnant demand and productivity improvements in mining and transportation. By
way of comparison, the Council’s 1991 power plan estimated the overnight capital cost of a new
coal-fired steam-electric plant to be $1775/kW and the cost of Powder River coal at
$0.68/MMBtu (year 2000 dollars). The capital and fuel costs proposed for the Fifth Power Plan
are $1468/kW and $0.71/MMBtu, respectively.

Though the economics have improved, other issues associated with future development of coal-
fired power plants remain largely unchanged. The issues cited in the Fourth Power Plan - air
quality impacts, carbon dioxide and global climate change, water impacts, solid waste, site

Appendix P Page P-6 NWPPC Assumptions
availability, coal transportation, electric power transmission and impacts of coal mining and
transportation - remain significant.

The proposed reference plant is a subcritical 400 megawatt pulverized coal-fired unit. It is one
of two or more co-located similar units. Because of increasing constraints on the availability of
water, we assume the plant is equipped with dry mechanical draft cooling. The plant would be
equipped with flue gas desulfurization, fabric filter particulate control and would use combustion
NOx control. In view of cost and performance improvements achieved in recent years with
conventional technology, the potential for further improvements, and difficulties experienced
with development of advanced technologies, future improvements in cost and performance is
based on evolutionary improvements to conventional technology.

Issues:

• In previous power plans, location-specific coal-fired power plant costs (including
transmission interconnection and site infrastructure) were based on actual Northwest sites
that had been proposed for development. The availability of capacity for future
development was based on the same approach. This approach no longer appears practical
now that power price forecasting and other Council analyses demand a west-wide view.
What approach should the Council use in expanding the basis plant assumptions to the
various load-resource areas used in the Council’s models? What are the important
variables among prospective sites? Do we need to assess possible constraints on resource
development?
• What should we assume with respect to future environmental requirements for coal-fired
capacity? Will mercury and other air toxins be controlled and how would plant cost and
performance be affected? The reference design does not include selective catalytic
reduction (SCR) for additional NOx control. Should we assume that SCR would be
typically installed on new plants.
• The proposed scheduled outage factor seems high (~30 days/yr) but is consistent with
GADS data and new plant design objectives. Do this assumption require revision?
• Our current assumption regarding future technology development is limited to heat rate
improvement and is taken from the Energy Information Administration Annual Energy
Outlook 2002. The basis is unclear. Should we look at an alternative approach, e.g.
adoption of some advanced technology or achievement of US DOE performance goals by
some future date?
• Capital replacement assumptions affect the retirement of existing capacity in power price
forecasting and other modeling. Are the proposed assumptions realistic?

References

DOE (1999): US Department of Energy. Market-based Advanced Coal Power Systems.
March 1999.

EIA (2001): US Department of Energy, Energy Information Administration. Assumptions to
the Annual Energy Outlook 2002. December 2001.

Appendix P Page P-7 NWPPC Assumptions

Table 1: Resource characterization: Coal-fired power plants

Facility 400 MW (nominal) pulverized coal-fired subcritical
steam-electric plant, 2400 psig/1000oF/1000oF reheat.
Dry mechanical draft cooling. Low-NOx burners;
lime spray dryer; fabric particulate filter. “Reference
plant” design. Co-sited with one or more additional
units.
Reference plant from DOE, 1999, modified to suit
western coal and site conditions.
Fuel Western subbituminous coal. 9300 Btu/lb, 0.4% S. Characteristics are for Powder River Basin coal.
Technology base year 2000 Fifth plan base year.
Price base year 2000 Fifth plan base year.
Net power output New & clean: 385 MW
Lifetime average: 374 MW
DOE (1999) Derated 3% for dry cooling.
Average degradation based on 4th plan GT values.
Lead time Development: 36 months
Construction: 36 months
Development shortened from 4th plan 48 months.
Availability Scheduled outage factor: 9%
Forced outage rate: 7%
Mean time to repair: 40 hours
Availability: 85%
Availability factors based on 1995 - 99 GADS, but
consistent w/DOE (1999) reduced redundancy
design.
Heat rate (HHV) New & clean: 9350 Btu/kWh
Lifetime average: 9550 Btu/kWh
Vintage improvement: -0.34%/yr
DOE (1999), increased 3% for dry cooling.
Average degradation based on 4th plan GT values.
Vintage improvement From EIA (2001)
Service life 30 years DOE (1999). Reduced from 4th Power plan (40 yrs).

Capital cost Development: $25/kW
Construction (Overnight): $1403/kW
Startup: $26/kW
Working capital: $14/kW
Development cost factors from 4th Plan.
Construction, startup & working capital from DOE
(1999) plus estimated dry cooling, land & owner’s
admin costs. No allowance for site infrastructure.
Capital replacement To 30 yrs: $15/kW/yr
Over 30 yrs: $20/kW/yr
EIA (2001).
Non-fuel O&M cost Fixed O&M : $25/kW/yr
Property Tax: $20/kW/yr
DOE (1999) except prop tax & insurance. Prop tax
& insurance 1.4% & 0.25% assessed value,

Appendix P Page P-8 NWPPC Assumptions
Insurance: $4/kW/yr
Variable: $0.5/MWh
Vintage improvement: 0%/yr
respectively.
Financing IPP See Table 2 (To follow)

SOx Calculation to be supplied 95% removal
NOx 4.09 lb/Mwh (2.05 T/GWh) DOE (1999) Est. 2005 BACT
Particulates 0.272 lb/Mwh (0.136 T/GWh) DOE (1999) Est. 2005 BACT
CO2 Calculation to be supplied

Site Availability The current AURORA run (with no limits on new
capacity) result in the following build levels by 2020:
AB - 700 MW, CO 1750 MW, ID 3150 MW, MT 350
MW, WY 1140 MW.

________________________________________ q:\jk\5th plan\resource update\5p resource asmp coal-fired plants (051602).doc

Appendix P Page P-9 NWPPC Assumptions
DRAFT

Northwest Power Planning Council
New Resource Characterization for the Fifth Power Plan
Natural Gas Combined-Cycle Gas Turbine Power Plants
August 27, 2002

This paper describes the technical characteristics and cost and performance assumptions to be
used by the Northwest Power Planning Council for new natural gas combined-cycle gas turbine
power plants. The intent is to characterize a facility typical of those likely to be constructed in
the Western Electricity Coordinating Council (WECC) region over the next several years,
recognizing that each plant is unique and that actual projects may differ from these assumptions.
These assumptions will be used in our price forecasting and system reliability models and in the
Council’s periodic assessments of system reliability. The Council may also use these
assumptions in the assessment of other issues where generic information concerning natural gas
combined-cycle power plants is needed. Others may use the Council’s technology
characterizations for their own purposes.

A combined-cycle gas turbine power plant consists of one or more gas turbine generators
equipped with heat recovery steam generators to capture heat from the gas turbine exhaust.
Steam produced in the heat recovery steam generators powers a steam turbine generator to
produce additional electric power. Use of the otherwise wasted heat in the turbine exhaust gas
results in high thermal efficiency compared to other combustion-based technologies. Combined-
cycle plants currently entering service can convert about 50 percent of the chemical energy of
natural gas into electricity (HHV basis2). Additional efficiency can be gained in combined heat
and power (CHP) applications (cogeneration), by bleeding steam from the steam generator,
steam turbine or turbine exhaust to serve direct thermal loads3.

A single-train combined-cycle plant consists of one gas turbine generator, a heat recovery steam
generator (HSRG) and a steam turbine generator (“1 x 1” configuration). Using “FA-class”
combustion turbines - the most common technology in use for large combined-cycle plants - this
configuration can produce about 270 megawatts of capacity at reference ISO conditions4.
Increasingly common are plants using two or even three gas turbine generators and heat recovery
steam generators feeding a single, proportionally larger steam turbine generator. Larger plant
sizes result in economies of scale for construction and operation, and designs using multiple

2 The energy content of natural gas can be expressed on a higher heating value or lower heating
value basis. Higher heating value includes the heat of vaporization of water formed as a product
of combustion, whereas lower heating value does not. While it is customary for manufacturers
to rate equipment on a lower heating value basis, fuel is generally purchased on the basis of
higher heating value. Higher heating value is used as a convention in Council documents unless
otherwise stated. 3 Though increasing overall thermal efficiency, steam bleed for CHP applications will reduce the
electrical output of the plant. 4 International Organization for Standardization reference ambient conditions: 14.7 psia, 59o F,
60% relative humidity.

Appendix P Page P-10 NWPPC Assumptions
combustion turbines provide improved part-load efficiency. A 2 x 1 configuration using FA-
class technology will produce about 540 megawatts of capacity at ISO conditions. Other plant
components include a switchyard for electrical interconnection, cooling towers for cooling the
steam turbine condenser, a water treatment facility and control and maintenance facilities.

Additional peaking capacity can be obtained by use of various power augmentation features,
including inlet air chilling and duct firing (direct combustion of natural gas in the heat recovery
steam generator). For example, an additional 20 to 50 megawatts can be gained from a single-
train plant by use of duct firing. Though the incremental thermal efficiency of duct firing is
lower than that of the base combined-cycle plant, the incremental cost is low and the additional
electrical output can be valuable during peak load periods.

Gas turbines can operate on either gaseous or liquid fuels. Pipeline natural gas is the fuel of
choice because of historically low and relatively stable prices, deliverability and low air
emissions. Distillate fuel oil can be used as a backup fuel, however, its use for this purpose has
become less common in recent years because of additional emissions of sulfur oxides,
deleterious effects on catalysts for the control of nitrogen oxides and carbon monoxide, the
periodic testing required to ensure proper operation on fuel oil and increased turbine
maintenance associated with fuel oil operation. It is now more common to ensure fuel
availability by securing firm gas transportation.

The principal environmental concerns associated with gas-fired combined-cycle gas turbines are
emissions of nitrogen oxides (NOx) and carbon monoxide (CO). Fuel oil operation may produce
sulfur dioxide. Nitrogen oxide abatement is accomplished by use of “dry low-NOx” combustors
and a selective catalytic reduction system within the HSRG. Limited quantities of ammonia are
released by operation of the NOx SCR system. CO emissions are typically controlled by use of
an oxidation catalyst within the HSRG. No special controls for particulates and sulfur oxides are
used since only trace amounts are produced when operating on natural gas. Fairly significant
quantities of water are required for cooling the steam condenser and may be an issue in arid
areas. Water consumption can be reduced by use of dry (closed-cycle) cooling, though with cost
and efficiency penalties. Gas-fired combined-cycle plants produce less carbon dioxide per unit
energy output than other fossil fuel technologies because of the relatively high thermal efficiency
of the technology and the high hydrogen-carbon ratio of methane (the primary constituent of
natural gas).

Because of high thermal efficiency, low initial cost, high reliability, relatively low gas prices and
low air emissions, combined-cycle gas turbines have been the new resource of choice for bulk
power generation for well over a decade. Other attractive features include significant operational
flexibility, the availability of relatively inexpensive power augmentation for peak period
operation and relatively low carbon dioxide production. Combined-cycle power plants are an
increasingly important element of the Northwest power system, comprising about 87 percent of
generating capacity currently under construction. Completion of plants under construction will
increase the fraction of gas-fired combined-cycle capacity from 6 to about 11 percent of total
regional generating capacity.

Appendix P Page P-11 NWPPC Assumptions
Proximity to natural gas mainlines and high voltage transmission is the key factor affecting the
siting of new combined-cycle plants. Secondary factors include water availability, ambient air
quality and elevation. Initial development during the current construction cycle was located
largely in eastern Washington and Oregon with particular focus on the Hermiston, Oregon
crossing of the two major regional gas pipelines. Development activity has shifted to the I-5
corridor, perhaps as a response to east-west transmission constraints and improving air emission
controls.

Issues associated with the development of additional combined-cycle capacity include
uncertainties regarding the continued availability and price of natural gas, volatility of natural
gas prices, water consumption and carbon dioxide production. A secondary issue has been the
ecological and aesthetic impacts of natural gas exploration and production. Though there is some
evidence of a decline in the productivity of North American gas fields, the continental supply
appears adequate to meet needs at reasonable price for at least the 20-year period of the
Council’s power plan. Importation of liquefied natural gas from the abundant resources of the
Middle East and the former Soviet states and could enhance North American supplies and cap
domestic prices. The Council forecasts that US wellhead gas prices will escalate at an annual
rate of about 0.9% (real) over the period 2002 - 21. Though expected to remain low, on average,
natural gas prices have demonstrated both significant short-term volatility and longer-term, three
to four year price cycles. Both effects are expected to continue. Additional discussion of natural
gas availability and price is provided in the Council issue paper Draft Fuel Price Forecasts for the
Fifth Power Plan (Document 2002-07). The conclusions of the paper with respect to natural gas
prices are summarized in Appendix A of this document.

Water consumption for power plant condenser cooling appears to be an issue of increasing
importance in the west. As of this writing, water permits for two proposed combined-cycle
projects in northern Idaho have been recently denied, and the water requirement of a proposed
central Oregon project is highly controversial. Significant reduction in plant water consumption
can be achieved by the use of closed-cycle (dry) cooling, but at a cost and performance penalty.
Over time it appears likely that an increasing number of new combined-cycle projects will use
dry cooling.

Carbon dioxide, a greenhouse gas, is an unavoidable product of combustion of any power
generation technology using fossil fuel. The carbon dioxide production of a gas-fired combined-
cycle plant on a unit output basis is much lower than that of other fossil fuel technologies. The
reference plant, described below, would produce about 0.8 lb CO2 per kilowatt-hour output,
whereas a new coal-fired power plant would produce about 2 lb CO2 per kilowatt-hour. To the
extent that new combined-cycle plants substitute for existing coal capacity, they can substantially
reduce average per-kilowatt-hour CO2 production.

The proposed reference plant is based on the General Electric 7FA gas turbine generator in 2 x 1
combined-cycle configuration. The baseload capacity is 540 megawatts and the plant includes
an additional 70 MW of power augmentation using duct burners. The plant is fuelled with
pipeline natural gas using a firm gas transportation contract with capacity release provision. No
backup fuel is provided. Air emission controls include dry low-NOx combustors and selective
catalytic reduction for NOx control and an oxidation catalyst for CO and VOC control.

Appendix P Page P-12 NWPPC Assumptions
Condenser cooling is wet mechanical draft. Specific characteristics of the reference plant are shown in Table 1.

Table 1
Resource characterization: Natural gas combined-cycle gas turbine power plant
(2002 Dollars)

Facility description and basic
assumptions

Facility Natural gas-fired combined-cycle gas turbine power
plant. 2 GT x 1 ST configuration. 7FA gas turbine
technology. 540 MW new & clean baseload output @
ISO conditions, plus 70 MW of capacity augmentation
(duct-firing). No cogeneration load. Dry SCR for
NOx control, CO catalyst for CO control. Wet
mechanical draft cooling.

Fuel Pipeline natural gas. Firm transportation contract with
capacity release provisions. Seasonal variation in
capacity release value.
See Appendix A for a summary of the
gas price forecast and structure.
Project developer Consumer-owned utility: 5%
Investor-owned utility: 5%
Independent power producer: 90%
See Appendix B for project financing
assumptions.
Technology base year 2002 Representative of projects entering
service in 2002.
Price base year 2000 5th Plan price year.
Lead time Development: 24 months
Construction: 24 months

Service life 30 years

Appendix P Page P-13 NWPPC Assumptions

Technical Performance
Net power New & clean: 540 MW (baseload), 610 MW (peak)
Lifetime average: 528 MW (baseload), 597 MW
(peak)
Lifetime average based on 1 %
degradation per year, 98.75%
recovery at hot gas path inspection or
major overhaul. GE data.
Operating limits
Minimum load: 40 %.
Cold start: 3 hours
Ramp rate: 7 %/min
Minimum load: One GT in service,
point of minimum constant firing
temperature operation.
Scheduled outages
Scheduled outage factor: 5% (18 days/yr). Based on a planned maintenance
schedule of a 7-day annual inspection,
a 10-day hot gas path inspection &
overhaul every third year and a 28-
day major overhaul every sixth year.
Planned maintenance intervals are GE
baseline recommendations for
baseload service. In addition,
assumes two additional 28-day
scheduled outages and one six-month
plant rebuild during the 30-year plant
life.
Forced outages
Forced outage rate: 5%
Mean time to repair: 24 hours
NERC Generating Availability Data
System (GADS) weighted average
equivalent forced outage rate for
combined-cycle plants. Mean time to
repair is GADS average for full
outages.
Availability (lifetime average,
busbar)
90% (1-SOR)*(1-FOR). Derate additional
2.2% if using new & clean capacity.
Heat rate (HHV, net, ISO conditions) New & clean (Btu/kWh): 6880 (baseload); 9290
(incremental duct firing); 7180 (full power)
Lifetime average (Btu/kWh): 7030 (baseload); 9500
(incremental duct firing); 7340 (full power)

Baseload is current new & clean
rating for GE 207FA. Lifetime
average is new & clean value derated
by 2.2%. Degradation estimates are
from GE. Duct firing heat rate is
GRAC recommendation.
Future technical im rovement 2002-21 annual average: -0.6%. Assume 7B technolo full

Appendix P Page P-14 NWPPC Assumptions
(expressed as improvement in thermal
efficiency)
commercial by 2005; 7H by 2010;
asymptotic to ultimate potential by
2060.
Seasonal power output (ambient air
temperature sensitivity)
Seasonal power output factors for selected WECC
locations are shown in Figure 1.
Based on power output ambient
temperature curve for GE STAG
combined-cycle plant using 30-year
monthly average temperatures.
Elevation adjustment for power
output
See Table 2 for power output elevation correction
factors for selected WECC locations.
Based on standard gas turbine altitude
correction curve.

Costs
Development & construction Baseload configuration: $565/kW (overnight);
621 $/kW (all-in).
Power augmentation configuration: $525/kW
(overnight);
577 $/kW (all-in).

Excludes financing fees and interest
during construction. Assumes
“equilibrium” market conditions.
Normalized cost of a 1x1 plant
estimated to be 110% of example
plant costs. Incremental cost of
power augmentation using duct
burners $225/kW. Values are based
on new and clean rating.
Development & construction cash
flow (%/yr)
3%/97%
Capital replacement $1.60/kW/yr1 Levelized equivalent of 10% of initial
capital investment in Year 15. Value
is based on new and clean rating.
Fixed operating costs Baseload configuration: $7.25/kW/yr.
Power augmentation configuration: $6.50/kW/yr.
Includes operating labor, routine
maintenance, general & overhead,
fees, contingency and an allowance
for startup costs and average sales tax.
Excludes property taxes and
insurance (separately calculated in the
Council’s models). Normalized fixed
O&M cost for a 1x1 plant estimated
to be 167% of that for the example
2x1 lant. Values are based on new

Appendix P Page P-15 NWPPC Assumptions
and clean rating.
Variable operating costs $2.80/MWh

Includes consumables, SCR catalyst
replacement, makeup water and
wastewater disposal costs, long-term
major equipment service agreement,
contingency and an allowance for
sales tax. Excludes any greenhouse
gas fees.
Interconnection and regional
transmission costs
$15.00/kW/yr Bonneville point-to-point
transmission rate (PTP-02) plus
Scheduling, System Control and
Dispatch, and Reactive Supply and
Voltage Control ancillary services,
rounded. Omit for busbar
calculations. Value is based on new
and clean rating.
Regional transmission losses 1.9% BPA contractual line losses. Omit for
busbar calculations.
Vintage cost reduction 2002-21 annual average: -0.6% (capital and fixed
O&M costs)
Assumes cost reductions related to
increase in gas turbine specific work
by factor of 0.3. Assumes 7B
technology full commercial by 2005;
7H by 2010; asymptotic to ultimate
potential by 2060.

Appendix P Page P-16 NWPPC Assumptions

Emissions (Plant site, excluding gas
production & delivery)

Particulates (PM-10) Typical permit limits, baseload
operation: 0.02 T/GWh
SOx Typical actual: 0.002 T/GWh Typical permit limits, baseload
operation: 0.02 T/GWh
NOx Typical actual: 0.039 T/GWh Typical permit limits, baseload
operation: 0.04 T/GWh
CO Typical actual: 0.005 T/GWh Typical permit limits, baseload
operation: 0.04 T/GWh
Hydrocarbons/VOC Typical actual: 0.0003 T/GWh Typical permit limits, baseload
operation: 0.01 T/GWh
Ammonia Typical actual: 0.0000006 T/GWh Slip from catalyst. Typical permit
limits, baseload operation: 0.004
T/GWh
CO2 411 T/GWh (baseload operation)
429 T/GWh (full power operation)
Based on EPA standard fuel carbon
content assumptions
and lifecycle average heat rates.
Availability for future development
Site Availability 2001 - 2020 Initially not limited. Extent of future development to be
tested in AURORA runs. If the
resulting development significantly
exceeds the inventory of currently or
likely permitted sites in any load-
resource area this issue will be
revisited.

Appendix P Page P-17 NWPPC Assumptions
Figure 1
Gas turbine combined-cycle average monthly power output temperature correction factors
for selected locations
(relative to ISO conditions)

Table 2
Gas turbine power output elevation correction factors for selected locations

Location
Elevation
(ft)
Power Output
Factor
Buckeye, AZ (nr. Palo Verde) 890 0.972
Caldwell, ID 2370 0.923
Centralia, WA 185 0.995
Ft. Collins, CO 5004 0.836
Great Falls, MT 3663 0.880
Hermiston, OR 640 0.980
Livermore, CA 480 0.985
Wasco, CA (nr. Kern County
plants) 345 0.990
Winnemucca, NV 4298 0.859

Combined-cycle Power Output Factor
(ISO ambient temperature base)
0.850
0.900
0.950
1.000
1.050
1.100
1.150
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Po
w
e
r

O
u
t
p
u
t

F
a
c
t
o
r
Buckeye, AZ
Caldwell, ID
Centralia, WA
Ft. Collins, CO
Great Falls, MT
Hermiston, OR
Livermore, CA
Wasco, CA
Winnemucca, NV

Appendix P Page P-18 NWPPC Assumptions
REVISED DRAFT

Northwest Power Planning Council
New Resource Characterization for the Fifth Power Plan
Wind Power Plants
July 23, 2002

This paper describes the technical characteristics and cost and performance assumptions to be
used by the Northwest Power Planning Council for new wind power plants. The intent is to
characterize a typical facility, recognizing that actual facilities may differ from these
assumptions. This is particularly true of wind power projects. Costs are sensitive to location and
size of a wind farm and energy production is sensitive to the quality of the wind resource. In
addition, the value of energy from a site is a function of the seasonal and daily variations of the
wind. The assumptions that follow will be used in our price forecasting and system reliability
models and in the Council’s periodic assessments of system reliability. The Council may also
use these assumptions in the assessment of other issues where generic information concerning
wind power plants is needed. Others may use the Council’s technology characterizations for
their own purposes.

Wind energy is converted to electricity by wind turbine generators - electric generators driven by
rotating airfoils. Because of the low energy density of wind, bulk electricity production from
windpower requires tens or hundreds of wind turbine generators arrayed in a wind power plant.
A wind power plant (often called a “wind farm”) includes meteorological towers, strings of wind
turbine generators, turbine service roads, a control system interconnecting individual turbines
with a central control station (often remote), a voltage transformation and transmission system
connecting the individual turbines to a central substation, a substation to step up voltage for long-
distance transmission and an electrical interconnection to the main transmission grid.

The typical wind turbine generator being installed in commercial-scale projects is a horizontal
axis machine of 600 to 1500 kilowatts rated capacity with a three-bladed rotor 150 to 250 feet in
diameter. The machines are mounted on tubular towers ranging to about 260 feet height. Trends
in machine design include improved airfoils; larger machines; taller towers and improved
controls. Improved airfoils increase energy capture. Larger machines provide economies of
manufacturing, installation and operation. Because wind speed generally increases with
elevation above the surface, taller towers and larger machines intercept more energy. Turbine
size has increased rapidly in recent years and multi-megawatt (2000 - 2750kW) machines are
being introduced. These machines are likely to see initial service in European offshore
applications.

Many of the issues that formerly impeded the development of wind power have been resolved,
clearing the way for the significant development occurring in the Northwest in recent years.
Concerns regarding avian mortality, aesthetic and cultural impacts have been alleviated by the
choice of dryland agricultural areas for project development. The resulting land rent revenue has
also garnered political support from the agricultural community. Though per-kilowatt installed
costs appear not to have greatly declined, turbine performance, turbine reliability and siting has
improved, increasing energy capture thereby reducing energy production costs. A robust market

Appendix P Page P-19 NWPPC Assumptions
for “green” power has developed in recent years, driven by retail green power options, utility
efforts to diversify and “green up” resource portfolios, green power acquisition mandates
imposed by public utility commissions as a condition of utility acquisitions, and system benefits
funds established in conjunction with industry restructuring. Equally important, the federal
production tax incentive has been extended, though with some interruption.

In spite of the recent unprecedented development of windpower, issues affecting continued
development of the resource remain. As of this writing, wholesale power costs are low and are
anticipated to remain so for several years. The cost of firming and shaping wind farm output to
serve load are not well understood and can be substantial. While it appears possible that several
hundred megawatts of wind power can be shaped at relatively low cost using the Northwest
hydropower system, the cost of firming and shaping additional amounts of wind energy are
uncertain, pending further operating experience and analysis. Wind power, because of its
intermittency, has been subject to generation imbalance penalties intended to constrain gaming
by operators of schedulable thermal resources. The Bonneville Administrator has just signed a
Record of Decision exempting wind power from imbalance penalties for a period of one year.
The issue has received considerable publicity and is likely to be addressed in federal energy
legislation and discussions of future transmission management. Northwest wind development to
date has not required expansion of transmission capacity, which can be expensive for wind
because of its relatively low capacity factor. However, the availability of prime sites with easily
accessible surplus transmission capacity is limited. Finally, the competitive position of wind
power remains dependent upon the federal production tax credit.

The first commercial-scale wind plant in the Northwest using contemporary technology is the 25
MW Vansycle project in Umatilla County, Oregon. Since Vansycle entered service in late 1998,
four additional windfarms have been placed in service or are under construction. Now in
operation or under construction within the region are 412 megawatts of wind capacity, producing
about 130 average megawatts of energy. In addition, Northwest utilities have contracted for 110
megawatts of capacity, producing about 44 megawatts of energy from two Wyoming projects.
Northwest wind farms range in size from 25 to 265 megawatts, and are comprised of 16 to nearly
400 machines ranging in size from 600 to 1500 kW. Several of these sites are capable of
significant expansion and additional sites have been proposed for development.

Four geographically-based generic resource types are used in modeling future wind resources:

• Basin & Range: Favorably-oriented ridges in the basin and range geographic province
ranging from Oregon and Idaho south to Arizona.

• Cascades and Inland: Favorably-oriented ridges lying within and east of the Columbia
River Gorge and other Cascades features that channel westerly winds.

• Northern California: California north of the Path 15 transmission constraint.
Temperature-driven winds with a strong summer peak and strong diurnal shape.

• Northwest Coast: Coastal sites with storm-driven wind patterns.

Appendix P Page P-20 NWPPC Assumptions
• Rockies & Plains: Areas within and east of Rocky Mountain features that channel
prevailing westerly winds. Storm-driven winds with a strong winter-peaking shape.

• Southern California: California south of the Path 15 transmission constraint.
Temperature-driven winds with a strong summer peak and strong diurnal shape.

References:

DWIA (2002): Danish Wind Industry Association, Guided tour on Wind Energy ,
www.windpower.org.

EPRI (1997): Electric Power Research Institute, Renewable Energy Technology
Characterizations (EPRI TR-1094496). December, 1997.

Appendix P Page P-21 NWPPC Assumptions
Table 1
Resource characterization: Wind power plants

Facility description and basic assumptions
Facility 50 MW central-station wind power project. Five resource
types are modeled, varying by wind quality and seasonal
and daily wind characteristics. The resource types and
WECC areas for which they are used in the Council’s
work are:
Basin & Range - S. ID, NV, UT, AZ
Cascades & Inland - E. WA & OR, N. ID
Northern California - N. CA
Northwest Coast - W. WA & OR
Rockies & Plains - AB, MT, WY, CO, NM
Southern California - S. CA & Baja
Typical projects may range from 25 to 300 MW.
Technology base year 2002 vintage design
Price base year 2000 5th Plan price year.
Lead time Development: 24 months
Construction: 12 months

Service life 20 years Typical design life for Danish wind turbine generators
(DWIA, 2002).

Appendix P Page P-22 NWPPC Assumptions

Technical Performance
Net power 50 MW Assumed to include in-farm losses.
Scheduled outages
Included in capacity factor.
Forced outages
Included in capacity factor.
Capacity Factor
(net)
Basin & Range - 28 %
Cascades & Inland - 30%
Northern California - 34 %
Northwest Coast - 30%
Rockies & Plains - 39 %
Southern California - 34 %
Power delivered to transmission interconnection. Net of
in-farm losses and outages.
Vintage performance
improvement
2002-21 average annual: 0.0 %. Performance improvement is modeled as estimated
vintage cost reduction (below).
Seasonal pattern Table 2 and Figure 1
Diurnal pattern California - Table 3 and Figure 3, other areas - no diurnal
pattern.

Appendix P Page P-23 NWPPC Assumptions

Costs
Development &
construction
$1060/kW (overnight); $1100/kW (typical all-in) Includes project development, turbines, site
improvements, erection, substation, startup costs &
working capital. “Overnight” cost excludes interest
during construction. Range: $1120/kW for 25 MW
project to $930/kW for 300 MW project (overnight).
Capital replacement $2.50/kW/yr (levelized) Gearbox overhaul and generator bearing replacement
at year 10 at 5% of installed cost ($57/kW). EPRI
(1997).
Fixed operating costs $14.00/kW/yr. Excludes property taxes and insurance (separately
calculated in the Council’s models), integration and
shaping costs and land royalty.
Variable operating
costs
$1.00/MWh

Land lease. Approximation of 2.5% of forecast wholesale
power costs (EPRI 1997). Also typical of per-kWh
payment agreements.
Interconnection and
regional transmission
costs
$15.00/kW/yr Bonneville point-to-point transmission rate (PTP-02) plus
Scheduling, System Control and Dispatch, and Reactive
Supply and Voltage Control ancillary services, rounded.
Omit for busbar calculations. Bonneville 2002
transmission tariff.
Regional transmission
losses
1.9% BPA contractual line losses. Omit for busbar calculations.
Firming and shaping $15.00/MWh
Vintage cost reduction 2002-21annual average: -2.0 %. Proxy for both cost and performance improvements.
Council Fourth Plan estimate based on historical and
potential improvements.

Appendix P Page P-24 NWPPC Assumptions

Development, financing and capital-related costs
Financing 80% Independent power producer; 20% consumer-owned
utility.
Assumptions provided separately
Tax depreciation 5 years
Property tax 1.4%/yr of book value. Average regionwide conditions. Council assumption.
Insurance 0.3%/yr of book value.
Availability for future development
Site Availability 2001 -
2020
Initially not limited. Forecasted extent of future development will be tested in
AURORA model runs. If this level significantly exceeds
1000MW in any load-resource area this issue will be
revisited.

Appendix P Page P-25 NWPPC Assumptions

Table 2
Normalized monthly wind energy distribution

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Basin & Range 1.19 1.39 1.07 1.05 0.94 0.71 0.56 0.61 0.72 0.74 1.59 1.43
Cascades & Inland 1.03 0.90 1.07 1.07 1.21 1.07 1.11 1.07 0.94 0.73 0.85 0.96
Northern California 0.22 0.28 0.69 1.13 1.81 1.88 2.10 1.85 0.96 0.65 0.24 0.18
Northwest Coast 1.19 1.57 1.07 0.86 0.84 0.84 1.01 0.54 0.66 0.80 1.40 1.21
Rockies & Plains 1.61 1.57 1.02 0.84 0.77 0.73 0.35 0.42 0.52 1.00 1.30 1.88
Southern California 0.68 0.66 0.97 1.28 1.75 1.33 1.47 0.95 0.87 0.82 0.65 0.57

Figure 1
Normalized monthly wind energy distribution

0.00
0.50
1.00
1.50
2.00
2.50
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
No
r
m
a
l
i
z
e
d

M
o
n
t
h
l
y

E
n
e
r
g
y

O
u
t
p
u
t
Basin & Range
Cascades & Inland
Northern California
Northwest Coast
Rockies & Plains
Southern California

Appendix P Page P-26 NWPPC Assumptions
Table 3
Diurnal wind energy distribution
(Hourly fraction of daily energy)

Hour
Northern
California
Southern
California
1 0.056 0.049
2 0.054 0.048
3 0.050 0.047
4 0.047 0.045
5 0.045 0.043
6 0.042 0.040
7 0.040 0.037
8 0.037 0.033
9 0.034 0.031
10 0.032 0.029
11 0.031 0.029
12 0.031 0.029
13 0.031 0.031
14 0.031 0.034
15 0.033 0.037
16 0.034 0.041
17 0.036 0.044
18 0.039 0.047
19 0.042 0.050
20 0.046 0.052
21 0.049 0.052
22 0.051 0.052
23 0.054 0.051
24 0.055 0.050

Appendix P Page P-27 NWPPC Assumptions
Figure 2
Diurnal wind energy distribution

________________________________________
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q:\jk\5th plan\resource update\wind\5p resource asmp wind plants (072302).doc

0.000
0.010
0.020
0.030
0.040
0.050
0.060
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour
Ho
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Northern California
Southern California

Appendix Q Page Q-1 DSM Modeling Details
Appendix

DSM Modeling Details

The following table represents input assumptions used in modeling the Company’s DSM efforts
in AURORA. It includes price, capacity, and energy information for each price tier of the six
DSM resources that were developed.

Table Q.1
DSM Resource Assumptions

Price Measure Utility Cost Capacity Energy Capacity
Tier Component ($/MWh) (kW) (akW) Factor
1 Commercial HVAC 36.12 8935.11 878.45 9.8%
1 Commercial Lighting 13.28 2392.93 1325.47 55.4%
1 Commercial DHW 12.95 40.91 24.80 60.6%
1 Residential HVAC 17.13 540.37 159.82 29.6%
1 Residential Lighting 19.40 5619.69 924.66 16.5%
1 Residential DHW 30.92 14.72 7.81 53.0%

2 Commercial HVAC 45.16 893.51 87.84 9.8%
2 Commercial Lighting 16.59 239.29 132.55 55.4%
2 Commercial DHW 16.19 4.09 2.48 60.6%
2 Residential HVAC 21.41 54.04 15.98 29.6%
2 Residential Lighting 24.25 561.97 92.47 16.5%
2 Residential DHW 38.65 1.47 0.78 53.0%

3 Commercial HVAC 56.44 89.35 8.78 9.8%
3 Commercial Lighting 20.74 23.93 13.25 55.4%
3 Commercial DHW 20.24 0.41 0.25 60.6%
3 Residential HVAC 26.76 5.40 1.60 29.6%
3 Residential Lighting 30.31 56.20 9.25 16.5%
3 Residential DHW 48.31 0.15 0.08 53.0%

4 Commercial HVAC 70.56 8.94 0.88 9.8%
4 Commercial Lighting 25.93 2.39 1.33 55.4%
4 Commercial DHW 25.30 0.04 0.02 60.6%
4 Residential HVAC 33.45 0.54 0.16 29.6%
4 Residential Lighting 37.89 5.62 0.92 16.5%
4 Residential DHW 60.38 0.01 0.01 53.0%

The following charts depict the hourly load shapes for each of the six DSM resources modeled
within AURORA. These shapes are designated as the hourly shape for a typical week for a
given month. Each month of the year is represented by one of the twelve charts included.

Appendix Q Page Q-2 DSM Modeling Details
Chart Q.1
January Load Shapes

Chart Q.2
February Load Shapes
0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW
0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW

Appendix Q Page Q-3 DSM Modeling Details
Chart Q.3
March Load Shapes

Chart Q.4
April Load Shapes

0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW
0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW

Appendix Q Page Q-4 DSM Modeling Details
Chart Q.5
May Load Shapes

Chart Q.6
June Load Shapes

0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW
0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW

Appendix Q Page Q-5 DSM Modeling Details
Chart Q.7
July Load Shapes

Chart Q.8
August Load Shapes

0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW
0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW

Appendix Q Page Q-6 DSM Modeling Details
Chart Q.9
September Load Shapes

Chart Q.10
October Load Shapes

0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW
0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW

Appendix Q Page Q-7 DSM Modeling Details
Chart Q.11
November Load Shapes

Chart Q.12
December Load Shapes
0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW
0%
20%
40%
60%
80%
100%
120%
Sunday Monday Tuesday Wednesday Thursday Friday Saturday
Typical Week
Pe
r
c
e
n
t

o
f

C
a
p
a
c
i
t
y
Com HVAC Com Ltg Com DHW Res HVAC Res Ltg Res DHW

Appendix Q Page Q-8 DSM Modeling Details
Table Q.2
DSM Resource Net Market Value
2004-2023 (in thousands of dollars)

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 NPV
Com HVAC 1 -467 -417 -417 -330 -221 -124 -30 23 0 87 209 154 168 209 192 119 157 125 -21 117 -1,090
Com HVAC 2 -116 -112 -114 -107 -98 -89 -81 -78 -83 -76 -66 -74 -75 -73 -78 -88 -88 -94 -112 -102 -903
Com HVAC 3 -20 -20 -20 -20 -19 -19 -18 -18 -19 -18 -17 -18 -19 -19 -20 -21 -22 -23 -25 -24 -190
Com HVAC 4 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 -3 -4 -4 -4 -4 -4 -4 -31
Com Ltg 1 360 383 392 427 469 505 542 568 575 610 658 660 684 713 729 728 763 774 758 818 5,248
Com Ltg 2 29 31 32 35 39 43 46 49 49 52 57 57 59 62 63 63 66 66 65 70 443
Com Ltg 3 2 2 2 3 3 3 4 4 4 4 5 5 5 5 5 5 5 5 5 6 34
Com Ltg 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2

Com DHW 1 6 7 7 7 8 9 9 10 10 11 11 12 12 12 13 13 13 14 13 14 92
Com DHW 2 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 8
Com DHW 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1
Com DHW 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Res HVAC 1 64 68 70 78 87 95 102 108 109 116 126 126 131 137 140 139 146 148 143 156 984
Res HVAC 2 4 5 5 6 6 7 8 8 8 9 10 10 10 11 11 11 11 12 11 12 74
Res HVAC 3 0 0 0 0 0 0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 4
Res HVAC 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Res Ltg 1 516 561 578 651 740 817 895 949 961 1,037 1,140 1,133 1,175 1,230 1,254 1,242 1,306 1,319 1,266 1,392 8,563
Res Ltg 2 28 32 33 40 48 56 63 68 68 75 85 83 87 91 93 90 96 96 90 101 588
Res Ltg 3 0 0 0 1 2 2 3 3 3 4 5 5 5 5 5 5 5 5 4 5 25
Res Ltg 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Res DHW 1 0 0 0 0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 6
Res DHW 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Res DHW 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Res DHW 4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Appendix Q Page Q-9 DSM Modeling Details
Chart Q.13
Hourly Electric Market Prices vs. Commercial HVAC
2004

Chart Q.14
Hourly Electric Market Prices vs. Residential HVAC
2004
$0
$10
$20
$30
$40
$50
$60
$70
$80
Q1 Q2 Q3 Q4
Co
s
t

(
$
/
M
W
h
)
Price Com HVAC 1 Com HVAC 2 Com HVAC 3 Com HVAC 4
$0
$10
$20
$30
$40
$50
$60
Q1 Q2 Q3 Q4
Co
s
t

(
$
/
M
W
h
)
Price Res HVAC 1 Res HVAC 2 Res HVAC 3 Res HVAC 4

Appendix Q Page Q-10 DSM Modeling Details
Chart Q.15
Hourly Electric Market Prices vs. Commercial Lighting
2004

Chart Q.16
Hourly Electric Market Prices vs. Residential Lighting
2004
$0
$10
$20
$30
$40
$50
$60
Q1 Q2 Q3 Q4
Co
s
t

(
$
/
M
W
h
)
Price Com Ltg 1 Com Ltg 2 Com Ltg 3 Com Ltg 4
$0
$10
$20
$30
$40
$50
$60
Q1 Q2 Q3 Q4
Co
s
t

(
$
/
M
W
h
)
Price Res Ltg 1 Res Ltg 2 Res Ltg 3 Res Ltg 4

Appendix Q Page Q-11 DSM Modeling Details
Chart Q.17
Hourly Electric Market Prices vs. Commercial DHW
2004

Chart Q.18
Hourly Electric Market Prices vs. Residential DHW
2004

$0
$10
$20
$30
$40
$50
$60
Q1 Q2 Q3 Q4
Co
s
t

(
$
/
M
W
h
)
Price Com DHW 1 Com DHW 2 Com DHW 3 Com DHW 4
$0
$10
$20
$30
$40
$50
$60
$70
Q1 Q2 Q3 Q4
Co
s
t

(
$
/
M
W
h
)
Price Res DHW 1 Res DHW 2 Res DHW 3 Res DHW 4