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SALES AND LOAD FORECAST
FOR THE 2004 INTEGRATED RESOURCE PLAN
SALES AND LOAD FORECAST
FOR THE 2004 INTEGRATED RESOURCE PLAN
July 2004
Table of Contents
Page
List of Tables ii
List of Figures iii
Introduction 1
2004 IRP versus 2002 IRP 3
Overview of the Forecast 5
Residential 12
Commercial 14
Irrigation 16
Industrial 18
Additional Firm Load 20
Company Firm Load 22
Company Firm Peak 23
Astaris Load 25
Company System Load 26
Contract Off-System Load 27
Total Company Load 28
Appendix A: Historical and Projected Sales and Load 31
Residential Load 32
Commercial Load 34
Irrigation Load 36
Industrial Load 38
Additional Firm Sales and Load 40
Company Firm Load 42
Astaris Load 44
Company System Load 46
Contract Off-System Load 48
Total Company Load 50
List of Tables
Table Description Page
1 Residential Fuel Price Escalation, 2004-2013 6
2 Average Load and Peak Demand Forecast Scenarios 9
3 Forecast Probabilities 10
4 Firm Load Growth 11
5 Residential Load Growth 12
6 Commercial Load Growth 14
7 Irrigation Load Growth 16
8 Industrial Load Growth 18
9 Additional Firm Load Growth 20
10 Firm Load Growth 22
11 Firm Summer Peak Load Growth 23
12 Firm Winter Peak Load Growth 24
13 System Load Growth 26
14 Total Company Load Growth 28
15 Historical Residential Sales and Load, 1970 - 2003 32
16 Projected Residential Sales and Load, 2004 - 2015 33
17 Historical Commercial Sales and Load, 1970 - 2003 34
18 Projected Commercial Sales and Load, 2004 - 2015 35
19 Historical Irrigation Sales and Load, 1970 - 2003 36
20 Projected Irrigation Sales and Load, 2004 - 2015 37
21 Historical Industrial Sales and Load, 1970 - 2003 38
22 Projected Industrial Sales and Load, 2004 - 2015 39
23 Additional Firm Sales and Load - Historical Data, 1970 - 2003 40
24 Additional Firm Sales and Load - Projections, 2004 - 2015 41
25 Historical Company Firm Sales and Load, 1970 - 2003 42
26 Projected Company Firm Sales and Load, 2004 - 2015 43
27 Historical Astaris Sales and Load, 1970 - 2003 44
28 Projected Astaris Sales and Load, 2004 45
29 Historical Company System Sales and Load, 1970 - 2003 46
30 Projected Company System Sales and Load, 2004 - 2015 47
31 Historical Contract Off-System Sales and Load, 1970 - 2003 48
32 Projected Contract Off-System Sales and Load, 2004 - 2006 49
33 Historical Total Company Sales and Load, 1970 - 2003 50
34 Projected Total Company Sales and Load, 2004 - 2015 51
ii
List of Figures
Figure Description Page
1 Forecasted Electricity Prices 6
2 Forecasted Natural Gas Prices 7
3 Forecasted Firm Load 11
4 Forecasted Residential Load 12
5 Forecasted Residential Use Per Customer 13
6 Forecasted Commercial Load 14
7 Forecasted Commercial Use Per Customer 15
8 Forecasted Irrigation Load 16
9 Forecasted Industrial Load 18
10 Industrial Electricity Consumption by Industry Group 19
11 Forecasted Additional Firm Load 20
12 Forecasted Firm Load 22
13 Forecasted Firm Summer Peak 23
14 Forecasted Firm Winter Peak 24
15 Historical Astaris (FMC) Load 25
16 Forecasted System Load 26
17 Forecasted Contract Off-System Load by Customer 27
18 Forecasted Total Load 28
19 Composition of Electricity Sales 29
iii
Introduction
Idaho Power Company (Idaho Power or the Company) has prepared the 2004 Sales
and Load Forecast as an appendix to its 2004 Integrated Resource Plan (IRP). The
Sales and Load Forecast presents the Company’s best estimate of the future demand
for electricity within its service territory. The forecast covers the 10-year period
from 2004 through 2013. For planning purposes, the future demand for electricity
by customers in the Company’s service territory is represented by three load
forecasts: (1) a 50th percentile or expected case load forecast, (2) a 70th percentile
load forecast, and (3) a 90th percentile load forecast. These forecasts define three
possible load conditions evaluated in the 2004 IRP. The expected case total load
growth rate is 2.2 percent per year over the ten-year planning period. This is Idaho
Power’s estimate of the most probable outcome for load growth during the planning
period and is based on the most recent economic forecast for the Company’s service
territory.
Two additional load forecasts for the Idaho Power service territory were prepared
that provide a range of possible load growths for the 2004-2013 planning period due
to variable economic and demographic conditions. The high economic growth and
low economic growth scenarios were prepared based upon statistical analysis to
empirically reflect uncertainty inherent in the load forecast.
The expected case load forecast assumes median temperatures and median rainfall.
Since actual loads can vary significantly dependent upon weather conditions, two
alternative scenarios were considered to address the load variability due to weather.
A 70th percentile load forecast and 90th percentile load forecast were prepared to
illustrate the weather-related uncertainty inherent in forecasting electrical loads.
The 70th percentile load forecast assumes monthly loads that can be exceeded in 3
out of 10 years (30 percent of the time). The 90th percentile load forecast assumes
monthly loads that can be exceeded in 1 out of 10 years (10 percent of the time).
In the expected case scenario, total company load is forecast to increase to 2,049
average megawatts in the year 2013 from the 2004 forecast load of 1,678 average
megawatts. The expected case forecast total load growth rate averages 2.2 percent
per year over the 10 years of the planning period (2004-2013). The number of Idaho
Power retail customers increases from the December 2003 level of 423,167
customers to about 516,900 retail customers at year-end 2013. The Company
system peak load is forecast to grow to 3,794 megawatts in the year 2013 from the
2003 actual system peak of 2,944 megawatts. The highest system peak on record
was 2,963 megawatts and occurred on July 12, 2002 at 4:00 p.m. In the expected
case scenario, the Company system peak increases at an average growth rate of 2.5
percent per year over the 10 years of the planning period (2004–2013).
This Sales and Load Forecast is strongly influenced by the 2004 Economic Forecast
developed by an outside consultant, John Church of Idaho Economics. The 2004
Economic Forecast is based on the Global Insight forecast of national and regional
economic activity. The Global Insight economic forecast is modified by Idaho
Economics to reflect anticipated service area conditions.
1
Economic growth assumptions influence several of the individual class of service
growth rates. Economic growth information for Idaho and its counties can be found
in Appendix A, 2004 Economic Forecast. The number of households in the state of
Idaho is projected to grow at an annual average rate of 1.6 percent during the
forecast period. Growth in the number of households within individual counties in
Idaho Power’s service area differs from statewide household growth patterns.
Service area households are derived from county specific household forecasts. The
number of households and employment projections along with customer
consumption patterns are each used to form load projections.
In addition to the economic assumptions used to drive the expected case forecast
scenario, several specific assumptions were incorporated in the forecasts of the
individual sectors. Further discussion of these assumptions is presented in the
sections of this report pertaining to these individual sectors.
The future load impacts of previous, ongoing, and future Idaho Power conservation
programs are not explicitly considered within the 2004 Sales and Load Forecast.
These programs, and their expected impacts are addressed in more detail in the
Company’s 2004 Conservation Plan. This plan is an additional appendix to the 2004
IRP.
The expected case load forecast represents Idaho Power's most probable outcome for
load growth during the planning period. However, the actual path of future
electricity sales will not follow exactly the path suggested by the expected case load
forecast. Therefore, four additional load forecasts were prepared, two that provide a
range of possible load growths due to economic uncertainty and two that address the
load variability associated with abnormal weather. The "high growth" and "low
growth" scenarios provide boundaries on each side of the expected case scenario and
reflect economic uncertainty. The "70th percentile" and "90th percentile" load
forecast scenarios were developed to assist the Company in reviewing the resource
requirements that would result from higher loads due to more adverse weather.
Several recent topics that were not considered in the development of the 2004 Sales
and Load Forecast include seasonal rates, time-of-use rates, and block rates that
were each implemented in June of 2004. Idaho Power expects to address the
impacts of these significant changes to rate structure in the 2006 IRP.
During the 10-year forecast horizon there could be major changes in the electric
utility industry. However, the implications of any major changes are unknown at
this time and are not reflected in this forecast. The alternative sales and load
scenarios of the 2004 Sales and Load Forecast were prepared under the assumption
that Idaho Power will continue to serve all customers in its franchised service
territory during the planning period.
2
2004 IRP versus 2002 IRP
Average Load Comparisons
The 2004 IRP average load forecast is lower than the 2002 IRP average load
forecast. An additional year of higher electricity prices (due to the 2002/2003
Power Cost Adjustment rate increase) combined with a weak national and service
area economy temporarily stalled load growth. However, the reduction in electricity
prices in May 2003 and a slow recovery in the service area economy have already
caused some load growth to return, although at a slower pace than before and
starting at a lower level than previously forecast in the 2002 IRP. Significant factors
that influenced the outcome of the 2004 IRP load forecast include:
• A much weaker service area economy experienced in the past few years.
• A slower growing service area economic forecast from Idaho Economics.
• Two years of significantly higher retail electricity prices.
• Electricity prices in the 2002 IRP were assumed to only remain significantly
higher for one year.
• The 2004 IRP residential, commercial, and industrial load forecasts are each
lower than the 2002 IRP forecast.
• In April 2002 the special contract between Astaris and Idaho Power Company
was terminated. Astaris had been the Company’s largest individual customer
and in some past years had averaged nearly 200 average megawatts.
• A flat load forecast was assumed for the INEEL in this year’s forecast
compared to expanding load growth assumed in the 2002 IRP.
• Simplot Fertilizer loads have actually dropped by 30% compared to steady
growth assumed in the 2002 IRP.
• Initially, slower growth at Micron Technology than assumed in 2002 IRP.
• Sales to City of Weiser and Raft River Rural Electric Cooperative, Inc. are
forecast to be somewhat slower than that assumed in the 2002 IRP.
3
Peak Hour Comparisons
Average loads and peak day temperatures drive the peak model regressions. The
lower average loads forecast in the 2004 IRP resulted, in most cases, in lower
monthly peak forecast figures. However, the peak forecast results and comparisons
with the last IRP differ for a number of reasons that include:
• The update of the 12 peak model regressions using MetrixND (a statistical
software from RER, an Itron Company).
• The re-specification of the winter month peak equations (October-April).
• The winter equations previously were constructed using Box-Jenkins
transformations that utilized three temperature intervals as drivers. The new
monthly models use only one temperature driver. This results in more
reasonable results especially when analyzing the various probabilities of peak
day temperatures.
• The modeling procedure in the 2004 IRP peak model was carefully reviewed
and logic changes were made to more accurately forecast the peaks at various
percentiles of temperatures.
• The new peak model allows peaks to be calculated at 0, 10, 20, 30, 40, 50, 60,
70, 80, 90, 95, and 100 percentiles of peak day temperatures for each month
of the year.
• The addition of more recent peak data to the peak model regressions. The
August 2001, July 2002, and July 2003 peak day temperatures were near the
100th percentile and their addition to the regression models impacted forecast
results.
• The 2002 IRP summer peak regression models didn’t use the 2001 peak data
as the 2001 voluntary load reduction program, that paid irrigators not to use
electricity, impacted the 2001 peaks.
• The Company continues to utilize a median peak day temperature driver in
lieu of an average peak day temperature driver. The median peak day
temperature has a 50 percent probability of occurrence. Peak day
temperatures are not normally distributed and can be skewed by one or more
extreme observations and the median temperature better reflects expected
temperatures.
4
Overview Of The Forecast
The sales and load forecast is constructed by developing a separate forecast for each
individual sales category. Independent sales forecasts are prepared for each of the
major customer classes: residential, commercial, irrigation, and industrial.
Individual energy and peak demand forecasts are developed for Micron Technology,
Simplot Fertilizer Company, Idaho National Engineering and Environmental
Laboratory (INEEL), the City of Weiser, and Raft River Rural Electric Cooperative,
Inc. (the electric distribution utility serving Idaho Power Company’s former
customers in the state of Nevada). These five special contract customers are
combined into a single forecast category labeled Additional Firm Load. Lastly, the
contract off-system category represents long-term contracts to supply firm energy
and demand to off-system customers. The assumptions for each of the individual
categories are described in greater detail in their respective sections.
Since the residential, commercial, irrigation, and industrial sales forecasts provide a
forecast of sales as they are billed, it is necessary to adjust these billed sales to the
proper timeframe to reflect the required generation needed in each calendar month.
To determine calendar-month sales from billed sales, the billed sales must first be
allocated to the calendar months in which they are generated. The calendar-month
sales are then converted to calendar-month load by adding losses and dividing by the
number of hours each month.
Loss factors are determined by Idaho Power’s Distribution Planning Department.
The annual average energy loss coefficients are multiplied by the calendar-month
load, yielding the system load including losses.
The peak load forecast was prepared in conjunction with the 2004 sales forecast.
Idaho Power has two distinct peak periods: a winter peak resulting from space
heating demand that normally occurs in December or January, and a larger summer
peak that normally occurs in June or July. The summer peak generally occurs when
extensive air conditioning usage coincides with significant irrigation demand.
Peak loads are forecast via twelve regression equations and are a function of
temperature, space heating saturation (winter only), air-conditioning saturation
(summer only), nonweather-sensitive base load, and precipitation (summer only).
The peak forecast utilizes a statistically derived peak day temperatures based on 30
or more years of climate data for each month. Peak loads for the INEEL, Micron
Technology, Simplot Fertilizer, the City of Weiser, Raft River Rural Electric
Cooperative, Inc., and the firm off-system contracts are forecast based on historical
analysis and contractual considerations.
The primary exogenous factors in the forecast are macroeconomic and demographic
data. Global Insight, a national econometric consulting firm, provides the
macroeconomic forecasts. The national econometric projections are tailored to
Idaho Power’s service area. Specific demographic projections are developed for the
service area from national and local census data.
5
Fuel Prices
Fuel prices, in combination with service area economic data, impact long-term
trends in electricity sales. Changes in relative fuel prices can also have significant
impacts on the future demand for electricity.
Global Insight provides the forecasts of long-term changes in nominal electricity and
nominal natural gas prices. Short-term electricity prices are generated internally
from Idaho Power financial models. The nominal price estimates are adjusted for
projected inflation by applying the appropriate economic deflators to arrive at real
fuel prices. The projected average annual growth rates of fuel prices in nominal and
real terms (adjusted for inflation) are presented in table 1. The growth rates shown
are for residential fuel prices and can be used as a proxy for fuel price growth rates in
the commercial, industrial, and irrigation sectors.
Residential Fuel Price Escalation, 2004-2013
(average annual percent change)
Nominal Real*
Electricity 1.4%-1.1%
Natural Gas 0.8%-1.6%
*adjusted for inflation table 1
Figure 1 illustrates electricity prices (in cents per kWh) over the historical period
1973 through 2003 and over the forecast period 2004 through 2015. Both nominal
and real prices are shown. Current nominal electricity prices are expected to decline
through 2005 and then slowly climb to nearly seven cents per kWh by the end of the
forecast period. Real electricity prices (inflation-adjusted) are expected to decline
over the forecast period at an average rate of 1.1 percent each year.
Forecasted Electricity Prices
(cents per kWh)
figure 1
0
1
2
3
4
5
6
7
8
1975 1980 1985 1990 1995 2000 2005 2010 2015
Nominal Actual Nominal Forecast Real
6
Electricity prices for Idaho Power customers were significantly higher in 2002 and
2003 because of the Power Cost Adjustment impact on rates. However, as of 2004,
electricity prices for Idaho Power customers are projected to return to levels closer to
normal, at between five and six cents per kWh for residential customers. Except for
the past three years, Idaho Power’s electricity prices have been historically quite
stable. Over the 1990 through 2000 period electricity prices rose only eight percent
overall, an annual average compound growth rate of 0.8 percent each year.
Figure 2 illustrates the average natural gas price (in dollars per therm) paid by
residential customers over the historical period 1973 through 2003 and over the
forecast period 2004 through 2015. Natural gas prices remained stable and flat
throughout the 1990s before moving sharply higher in 2001. Since 2001, natural gas
prices have continued to remain at significantly higher price levels. Natural gas
prices are expected to again move upward in 2004 to a price level sixty percent
above the prices experienced throughout the 1990s.
Forecasted Natural Gas Prices
(dollars per therm)
figure 2
$0.00
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
$0.70
$0.80
$0.90
$1.00
$1.10
1975 1980 1985 1990 1995 2000 2005 2010 2015
Nominal Actual Nominal Forecast Real
Nominal natural gas prices are expected to continue upward throughout the forecast
period (2004-2013) at an average rate of 0.8 percent per year. Real natural gas
prices (adjusted for inflation) are expected to decline over the same period at an
average rate of 1.6 percent each year.
If natural gas prices continue to outpace electricity prices, as they have over the past
several years, at some point the operating costs of space heating and water heating
homes with electricity will become comparable with that of natural gas. Eventual
price parity could have a significant impact on future electricity demands.
7
Forecast Probabilities
Load Forecasts Based on Weather Variability
The future demand for electricity by customers in Idaho Power’s service territory is
represented by three load forecasts reflecting a range of load uncertainty due to
weather. The expected case load forecast represents the most probable projection of
system load growth during the planning period and is based on the most recent
economic forecast for the Company’s service area.
The expected case load forecast assumes median temperatures and median
precipitation, i.e., there is a 50 percent chance that loads will be higher or lower than
the expected case loads due to colder-than-median or hotter-than-median
temperatures or wetter-than-median or drier-than-median precipitation. Since
actual loads can vary significantly dependant upon weather conditions, two
alternative scenarios were considered that address load variability due to weather.
Maximum load occurs when the highest recorded levels of heating degree days
(HDD) are assumed in winter and the highest recorded levels of cooling and growing
degree days (CDD and GDD) combined with the lowest recorded level of
precipitation are assumed in summer. Conversely, the minimum load occurs when
the lowest recorded levels of heating degree days are assumed in winter and the
lowest recorded levels of cooling and growing degree days combined with the highest
level of precipitation are assumed in summer.
For example, at the Boise Weather Service Office the median HDD in December over
the 1948-2003 period was 1,040 HDD. The 70th percentile HDD is 1,068 HDD and
would be exceeded in three out of ten years. The 90th percentile HDD is 1,194 HDD
and would be exceeded in one out of ten years. The 100th percentile HDD (the
coldest December on record) is 1,619 and occurred in December 1985. This same
concept was applied in each month throughout the year in only the weather sensitive
customer classes: residential, commercial, and irrigation.
In the 70th percentile residential and commercial load forecasts, temperatures in
each month were assumed to be at the 70th percentile of HDD in wintertime and at
the 70th percentile of CDD in the summertime. In the 70th percentile irrigation load
forecast, GDD were assumed to be at the 70th percentile and precipitation at the
30th percentile reflecting drier-than-median weather. The 90th percentile load
forecast was similarly constructed.
Idaho Power loads are highly dependant upon weather and these two scenarios allow
us to carefully examine load variability and how it may impact resource
requirements. It is important to understand that the probabilities associated with
these forecasts apply to any given month. To assume that temperatures and
precipitation would maintain a 70th percentile or 90th percentile level continuously
month after month throughout the year would be much less probable. It is the
monthly forecast numbers that are being evaluated for resource planning and one
8
must be careful in interpreting the meaning of the annual average load figures being
reported and graphed.
The load scenarios prepared for the 2004 Integrated Resource Plan are summarized
in table 2, below. Three average load scenarios were prepared based upon a
statistical analysis of historical monthly weather variables listed. The probability
associated with each individual average scenario is also indicated in the table. In
addition, three peak demand scenarios were prepared based upon a statistical
analysis of historical peak day temperatures. The probability associated with each
individual peak demand scenario is also indicated in table 2.
The analysis of resource requirements is based on the 70th percentile average load
forecast coupled with the 90th percentile peak demand forecast so that a more
adverse representation of peak demands could be considered. Alternatively, the
expected case average load forecast and the 50th percentile peak demand forecast
were coupled together for consideration, as well as the 90th percentile average load
forecast and 95th percentile peak demand forecast.
Average Load and Peak Demand Forecast Scenarios
Forecasts of Average Load
Weather Probability Weather
Scenario Probability of Exceeding Driver
90th Percentile 90%1 in 10 year HDD, CDD, GDD, Prec.
70th Percentile 70%3 in 10 year HDD, CDD, GDD, Prec.
Expected Case 50%1 in 2 year HDD, CDD, GDD, Prec.
Forecasts of Peak Demand
Weather Probability Weather
Scenario Probability of Exceeding Driver
95th Percentile 95%1 in 20 year Peak Day Temperatures
90th Percentile 90%1 in 10 year Peak Day Temperatures
50th Percentile 50%1 in 2 year Peak Day Temperatures
table 2
Load Forecasts Based On Economic Uncertainty
The expected case load forecast is based on the most recent economic forecast for the
Company’s service territory and represents Idaho Power’s most probable outcome
for load growth during the planning period. Two additional load forecasts for the
Idaho Power service territory were prepared that provide a range of possible load
growths for the 2004-2013 planning period due to variable economic and
demographic conditions. The high economic growth and low economic growth
scenarios were prepared based upon statistical analysis to empirically reflect
uncertainty inherent in the load forecast. The average growth rates for the high and
9
low growth scenarios were derived from the historical distribution of one-year
growth rates over the period 1979 through 2003.
The estimated probabilities for the three different load scenarios are reported in
table 2. The probability estimates are calculated using the annual growth rates in
firm sales observed between 1979 and 2003. The standard deviation observed
during the historical time period is used to estimate the dispersion around the
expected case scenario. The probability estimates assume that the expected forecast
is the median growth path; that is, there is a 50 percent probability that the actual
growth rate will be less than the expected case growth rate, and a 50 percent chance
that the actual growth rate will be greater than the expected case growth rate. In
addition, the probability estimates assume that the variation in growth rates will be
equivalent to the variation in growth rates observed over the past 25 years (1979
through 2003).
Forecast Probabilities
Scenario 1-Year 5-Year 10-Year
Low Growth 90%90%90%
Expected Case 50%50%50%
High Growth 10%10%10%
Low Growth 26%26%26%
Expected Case 48%48%48%
High Growth 26%26%26%
table 3
Probability of Occurrence
Probability of Exceeding
Two types of probability estimates are reported in table 3. The first probability
shows the likelihood that the load growth rate in the specified scenario will be
exceeded. For example, over the next 10 years there is a 10 percent probability that
the actual growth rate will exceed the growth rate projected in the high scenario, and
conversely, a 10 percent chance that the actual growth rate would fall below that of
the low scenario. In other words, over a 10-year time period there is an 80 percent
probability that the actual growth rate of firm load will fall between the growth rates
projected in the high and low scenarios. The second probability estimate, the
probability of occurrence, indicates the likelihood that the actual growth will be
closer to the growth rate specified in that scenario than to the growth rate specified
in any other scenario. For example, there is a 26 percent probability that the actual
growth rate will be closer to the high scenario than to any of the other forecast
scenarios for the entire 10-year planning horizon. Probabilities for shorter 1-year
and 5-year time periods are also shown in table 3.
10
Firm Load Growth
(average megawatts)
Growth Rate
(% Per Year)
Scenario 2003 2008 2013 2003-2013
High Growth 1,631 1,960 2,228 3.2
Expected Case 1,631 1,846 2,049 2.3
Low Growth 1,631 1,747 1,893 1.5
table 4
Firm load includes the sum of residential, commercial, industrial, irrigation, as well
as special contracts (excluding Astaris), the City of Weiser, and Raft River Rural
Electric Cooperative, Inc. Company firm load projections are reported in table 4 and
pictured in figure 3. The expected case firm load forecast growth rate averages 2.3
percent per year over the 10 years of the planning period. The low scenario projects
that firm load will increase at an average rate of 1.5 percent per year throughout the
forecast period. The high scenario projects load growth of 3.2 percent per year. The
Company has experienced both the high and low growth rates in the past. These
scenario forecasts provide a range of projected growth rates that cover
approximately 80 percent of the probable outcomes as measured by Idaho Power
Company’s historical experience.
Forecasted Firm Load
(average megawatts)
figure 3
70th PercentileExpected Case
Low Growth
High Growth
800
1,000
1,200
1,400
1,600
1,800
2,000
2,200
2,400
1980 1985 1990 1995 2000 2005 2010 2015
The remainder of the 2004 Sales and Load Forecast document is organized by
individual sectors. All information pertaining to a particular sector can be found
under the appropriate heading.
11
Residential
Residential Load Growth
(average megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
90th Percentile 550 605 659 1.8
70th Percentile 521 573 624 1.8
Expected Case 507 557 607 1.8
table 5
The expected case residential load is forecast to increase from 507 average
megawatts in 2003 to 607 average megawatts in 2013; an average annual compound
growth rate of 1.8 percent. In the 70th percentile scenario residential load is forecast
to increase from 521 average megawatts in 2003 to 624 average megawatts in 2013,
matching the expected case residential growth rate. The residential load forecasts
are reported in table 5 and shown graphically in figure 4.
Forecasted Residential Load
(average megawatts)
figure 4
Expected Case
70th Percentile
90th Percentile
300
350
400
450
500
550
600
650
700
1980 1985 1990 1995 2000 2005 2010 2015
Sales to residential customers made up 24 percent of the Company’s system sales in
1970 and 34 percent of system sales in 2003. The residential customer proportion of
system sales is forecast to be approximately 33 percent in 2013. There were 354,704
residential customers as of December 2003. The number of residential customers is
projected to increase to around 431,667 by December 2013. The relative customer
proportions of the total company electricity sales are shown in figure 19 (page 29).
12
The average sales per residential customer were about 10,000 kWh in 1970. Average
sales increased to nearly 14,800 kWh per residential customer in 1979 and declined
to 13,100 kWh in 2001. In 2002 and 2003 residential use per customer dropped
dramatically, about 500 kWh per customer from 2001, the result of two years of
significantly higher electricity prices combined with a weak national and service area
economy. The reduction in electricity prices in mid-May 2003 and a recovery in the
service area economy are expected to cause residential use per customer growth to
return to a pattern of slow decline. The average sales per residential customer are
expected to decline to approximately 12,400 kWh per year in 2013. Average annual
sales per residential customer are shown in figure 5.
Forecasted Residential Use Per Customer
(weather adjusted kWh)
figure 5
11,000
11,500
12,000
12,500
13,000
13,500
14,000
14,500
15,000
15,500
16,000
1975 1980 1985 1990 1995 2000 2005 2010 2015
The residential sales forecast is based on a forecast of the number of residential
customers and an econometric analysis of residential use per customer. The number
of residential customers being added each year is a direct function of new service
area households provided by the 2004 Economic Forecast. The customer forecast
for 2003-2013 shows an average annual growth rate of 2.1 percent.
The residential use per customer estimates consider several factors affecting
electricity sales to residential customers. Residential use per customer is a function
of HDD (wintertime), CDD (summertime), use per customer trends, and the price of
electricity. The resulting forecast of residential use per customer is multiplied by the
residential customer forecast to obtain the residential energy forecast.
13
Commercial
The commercial category is primarily made up of Idaho Power Company’s Small
General Service and Large General Service customers. Other schedules that are
considered part of the commercial category are Unmetered General Service, Street
Lighting Service, Traffic Control Signal Lighting Service, and Dusk to Dawn
Customer Lighting.
Commercial Load Growth
(average megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
90th Percentile 414 497 572 3.3
70th Percentile 405 486 560 3.3
Expected Case 400 481 554 3.3
table 6
In the expected case scenario, commercial load is projected to increase from 400
average megawatts in 2003 to 554 average megawatts in 2013. The average annual
compound growth rate of commercial load is 3.3 percent during the forecast period.
As summarized in table 6, the commercial load in the 70th percentile scenario is
projected to increase from 405 average megawatts in 2003 to 560 average
megawatts in 2013. The commercial load forecasts are illustrated in figure 6.
Forecasted Commercial Load
(average megawatts)
figure 6
Expected Case
70th Percentile
90th Percentile
150
200
250
300
350
400
450
500
550
600
650
1980 1985 1990 1995 2000 2005 2010 2015
As of December 2003, there were about 54,765 commercial customers. The number
of commercial customers is expected to increase at an average annual growth rate of
2.3 percent, reaching 68,350 customers in 2013. Commercial customers comprised
14
nearly 17 percent of the Company’s system sales in 1970 and 27 percent of system
sales in 2003. The commercial customer proportion of system sales is projected to
increase to nearly 30 percent of system sales by 2013. The relative customer
proportions of the Company’s total electricity sales are shown in figure 19 (page 29).
The average consumption per commercial customer increased to a record 67,286
kWh in 2001. However, two years of significantly higher electricity prices combined
with a weak national and service area economy caused a setback in the growth of
commercial use per customer in 2002 and 2003. The reduction in electricity prices in
mid-May 2003 and a slow recovery in the service area economy are expected to cause
commercial use per customer growth to return, although at a slower pace than before
and starting at a lower level than previously forecast in the 2002 IRP. The average
consumption per commercial customer is expected to increase to approximately
71,000 kWh per customer in 2013. Average annual use per commercial customer is
pictured in figure 7.
Forecasted Commercial Use Per Customer
(weather adjusted kWh)
figure 7
48,000
52,000
56,000
60,000
64,000
68,000
72,000
76,000
80,000
84,000
1975 1980 1985 1990 1995 2000 2005 2010 2015
The commercial sales forecast is based on a forecast of the number of commercial
customers and an econometric analysis of commercial use per customer. The
number of commercial customers being added each year is a direct function of the
number of new residential customers being added. The number of residential
customers being added is a direct function of the number of new service area
households as provided by the 2004 Economic Forecast. The commercial customer
forecast for 2003-2013 shows an average annual growth rate of 2.3 percent.
The commercial use per customer equation considers several factors affecting
electricity sales to commercial customers. Commercial use per customer is a
function of HDD (wintertime), CDD (summertime), use per customer trends, and
electricity prices. The forecast of commercial use per customer is multiplied by the
commercial customer forecast to obtain the commercial energy forecast.
15
Irrigation
The irrigation category is made up of Irrigation Service customers. Service under
this Schedule is applicable to power and energy supplied to farm customers and
organizations at one Point of Delivery for the operation of irrigation pump motors.
Irrigation Load Growth
(average megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
90th Percentile 230 236 239 0.4
70th Percentile 208 215 218 0.4
Expected Case 190 197 200 0.5
table 7
The expected case irrigation load is forecast to increase from 190 average megawatts
in 2003 to 200 average megawatts in 2013; an average annual compound growth
rate of 0.5 percent. The expected case, 70th percentile, and 90th percentile scenarios
forecast slow growth in irrigation load over the 2003-2013 time period. In the 70th
percentile scenario, irrigation load is projected to increase from 208 average
megawatts in 2003 to 218 average megawatts in 2013. The individual irrigation load
forecasts are reported in table 7 and shown graphically in figure 8. The figure
graphically illustrates the poorer economic conditions and the drop-off in land
development experienced by the agricultural economy in the mid-1980s.
Forecasted Irrigation Load
(average megawatts)
figure 8
Expected Case
70th Percentile
90th Percentile
100
125
150
175
200
225
250
275
300
1980 1985 1990 1995 2000 2005 2010 2015
16
In early 2001 wholesale electricity prices reached unprecedented levels and Idaho
Power, in an attempt to minimize reliance on the market, developed a voluntary load
reduction program that paid irrigators not to use electricity in 2001. The voluntary
load reduction program was effective and resulted in a 30 percent reduction in 2001
irrigation sales or approximately 499,319 MWh. The 2001 irrigation sales and
corresponding loads have been adjusted upward by 499,319 MWh to reflect a more
normal 2001 irrigation season and at the same time obtain more reasonable growth
rate calculations. In the future, Idaho Power does not anticipate that it will be
necessary to implement similar load reduction programs to irrigators.
The 2004 irrigation sales forecast considers several factors affecting electricity sales
to the irrigation class. Irrigation electricity sales are a function of temperatures,
precipitation, spring rainfall, the price of electricity, and a linear trend component.
Considerations are made for the unusually low electricity consumption in the 2001
crop year due to the voluntary load reduction program.
Actual irrigation electricity sales have grown from the 1970 level of 816,000
megawatt hours to a peak amount of 1,990,000 megawatt hours in 2000. During
the period 1970 through 1996, the Company experienced an increase in electricity-
using irrigated acres of 1,179,000 acres. This growth in total electricity-using
irrigated acres represented approximately a 2.9 percent average annual compound
rate of growth. The Company projects no growth in irrigated acres in the service
area and limited growth in sprinkler irrigation or conversion to sprinkler irrigation.
Irrigation sales represented nearly 16 percent of weather-normalized company
system sales in 1970. Irrigation sales reached a maximum proportion of nearly 20
percent of company system sales in 1977. In 2003 the irrigation proportion of
system sales was nearly 13 percent. By 2013 irrigation is projected to comprise
about 11 percent of company system sales. The customer load proportions are shown
in figure 19 on page 29.
In 1970 Idaho Power had about 7,300 irrigation accounts. By 2003 the number of
irrigation accounts had increased to 16,020, and there are projected to be nearly
18,793 irrigation accounts at the end of the planning period in 2013.
Since 1990, the Company has experienced a growth in the number of irrigation
customers, but no growth in electricity sales (weather-adjusted). The number of
customers has increased because customers are converting previously furrow-
irrigated land to sprinkler-irrigated land. However, the conversion rate is low. Also,
the kWh use-per-customer for these customers is substantially less than the average
existing Idaho Power irrigation customer. This is due to the fact that water is drawn
from canals and not from deep ground-water wells.
In the future, factors related to the conjunctive management of ground and surface
water and the possible litigation associated with the resolution will require
consideration. Depending on the resolution of these issues, irrigation sales may be
impacted.
17
Industrial
The industrial category is made up of Idaho Power Company’s Large Power Service
or Schedule 19 customers that consistently require over 1,000 kilowatts each billing
period. There were about 50 industrial customers of Idaho Power in 1970 that
comprised eight percent of the Company’s system sales. By December 2003 the
number of industrial customers had risen to 110, representing about 17 percent of
system sales.
Industrial Load Growth
(average megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
Expected Case 255 298 344 3.0
table 8
In the expected case forecast, industrial load grows from 255 average megawatts in
2003 to 344 average megawatts in 2013, an average annual growth rate of 3.0
percent (table 8). The industrial load forecasts in the 70th and 90th percentile
scenarios are identical to the expected case industrial load scenario. The industrial
load forecast is pictured in figure 9.
Forecasted Industrial Load
(average megawatts)
figure 9
Expected Case
100
150
200
250
300
350
400
450
1980 1985 1990 1995 2000 2005 2010 2015
The industrial energy forecast is based upon service area employment projections
taken from the 2004 Economic Forecast. The Company’s Schedule 19 customers
were categorized and their historical electricity sales were summarized by economic
activity.
18
The importance of each economic sector was determined by ranking each sectors
electricity usage from largest to smallest. The appropriate employment series were
then matched to each economic sector. A single driver was constructed by weighting
the various employment series by the importance of each economic activity. The
percentage change in the weighted employment driver was used to escalate
electricity sales to the industrial customers over time.
The pie chart in figure 10 below illustrates the 2003 industrial electricity consumption
by industry group. By far the largest share of electricity was consumed by the Food and
Kindred Products sector (48 percent), followed by Stone, Clay, Glass, and Concrete
Products (7 percent), Electronic and Other Electrical Equipment (6 percent), and
Industrial and Commercial Machinery (6 percent). As the chart shows, several other
industry groups make up the remaining share of the 2003 industrial electricity
consumption.
Industrial Electricity Consumption by Industry Group
(based on 2003 figures)
figure 10
Lumber and Wood
Products
2.6%
Electric, Gas, and
Sanitary Services
2.6%Health Services
5.0%
Industrial and Commercial
Machinery
6.0%
Stone, Clay, Glass, and
Concrete Products
6.6%
Electronic and Other
Electrical Equipment
6.0%
Educational Services
4.5%
National Security
3.5%
Other Industries
15.0%
Food and Kindred Products
48.2%
19
Additional Firm Load
Special contracts exist for five large customers that are recognized as firm load
customers. These customers are Micron Technology, Simplot Fertilizer, Idaho
National Engineering and Environmental Laboratory (INEEL), the City of Weiser,
and Raft River Rural Electric Cooperative, Inc. (Raft River). Together, these
customers make up the additional firm load category.
Additional Firm Load Growth
(average megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
Expected Case 128 142 155 2.0
table 9
In the expected case forecast, additional firm load is expected to increase from 128
average megawatts in 2003 to 155 average megawatts in the year 2013, an average
growth rate of 2.0 percent per year over the planning period (table 9). The
additional firm load energy and demand forecasts in the 70th and 90th percentile
scenarios are identical to the expected load growth scenario. The scenario of
projected additional firm load is illustrated in figure 11.
Forecasted Additional Firm Load
(average megawatts)
figure 11
Expected Case
0
25
50
75
100
125
150
175
200
1980 1985 1990 1995 2000 2005 2010 2015
20
Micron Technology is currently the Company’s largest individual customer. In this
forecast, electricity sales to Micron Technology are expected to steadily rise throughout
the forecast period. The primary driver of long-term electricity sales growth at Micron
Technology is employment growth in the Electronic Equipment sector as provided by
the 2004 Economic Forecast. Micron’s contract allows them to expand capacity up to
100 megawatts.
The Simplot Fertilizer plant is the largest producer of phosphate fertilizer in the
western United States. In late August of 2002, Simplot Fertilizer closed its ammonia
production facility. The ammonia plant represented about 11 MW or about one-third
of the entire Simplot load. The ammonia is now being purchased on contract from an
outside supplier. Offsetting the decline is the equipment required to unload and store
the ammonia, which consists of an additional 3 or 4 MW. The future electricity usage
at the plant is expected to continue to increase, although at a relatively slow rate of
growth. Employment growth in the Chemical and Allied Products sector is the
primary driver of long-term electricity sales growth at Simplot Fertilizer.
The Department of Energy provided an energy consumption and peak demand
forecast through 2007 for the INEEL. The forecast calls for loads to remain flat
throughout the forecast period. Looking back ten years ago, the annual loads at the
INEEL were quite volatile due to operational constraints affecting the availability of
their nuclear reactor to generate electricity. However, as of October 1994, the
INEEL nuclear reactor no longer generates electricity and, consequently, the amount
of electricity provided by Idaho Power increased considerably.
The City of Weiser is surrounded by and dependent upon the economic health of the
Idaho Power service territory. Electricity sales to the City of Weiser are assumed to
vary directly with household growth in Idaho’s Washington County, in which the City
of Weiser resides.
A term sales contract with Raft River was established as a full-requirements contract
after being approved by the Federal Energy Regulatory Commission (FERC) and the
Public Utility Commission of Nevada. Raft River is the electric distribution utility
serving Idaho Power Company’s former customers in the state of Nevada. Idaho
Power Company sold the transmission facilities and rights-of-way that serve about
1,250 customers in northern Nevada and 90 customers in southern Owyhee County
to Raft River. The closing date on the transaction was April 2, 2001. Raft River is
also located entirely within Idaho Power Company’s load control area.
21
Company Firm Load
Firm load is the sum of the individual loads of the residential, commercial,
industrial, and irrigation customers, as well as special contracts (excluding Astaris),
the City of Weiser, and Raft River. Firm load excludes not only Astaris, but also all
contracts to provide firm energy to off-system customers. Without the dampening
effects of Astaris and expiring off-system contracts on load growth, firm load more
accurately portrays the underlying growth trend within the service territory than
total load, which includes both Astaris and off-system commitments. The expiration
of off-system contracts also explains why the firm load growth rates (table 10) are
higher than the total load growth rates (table 14) over the planning period.
Firm Load Growth
(average megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
90th Percentile 1740 1962 2171 2.2
70th Percentile 1672 1889 2094 2.3
Expected Case 1631 1846 2049 2.3
table 10
In the expected case forecast, total firm load is expected to increase from 1,631
average megawatts in 2003 reaching 2,049 average megawatts in the year 2013, an
average growth rate of 2.3 percent per year over the planning period (table 10). In
the 70th percentile forecast, total firm load is expected to increase from 1,672 average
megawatts in 2003 reaching 2,094 average megawatts in the year 2013, an average
growth rate of 2.3 percent per year over the planning period (table 10). The three
scenarios of projected firm load are illustrated in figure 12.
Forecasted Firm Load
(average megawatts)
figure 12
Expected Case70th Percentile90th Percentile
800
1,000
1,200
1,400
1,600
1,800
2,000
2,200
2,400
1980 1985 1990 1995 2000 2005 2010 2015
22
Company Firm Peak
As defined here, firm peak load includes the sum of the individual coincident peak
demands of the residential, commercial, industrial, and irrigation customers, as well
as special contracts (excluding Astaris), the City of Weiser, and Raft River.
Firm Summer Peak Load Growth
(megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
95th Percentile 2980 3389 3811 2.5
90th Percentile 2966 3374 3794 2.5
50th Percentile 2888 3285 3694 2.5
table 11
The all-time firm summer peak demand was 2,963 megawatts, recorded on July 12,
2002, at 4:00 p.m. One year later, on July 22, 2003, at 5:00 p.m., the firm peak
reached 2,944 megawatts, nearly matching the record peak of the previous year. The
summer firm peak load growth has accelerated over the past ten years as air-
conditioning has become standard in nearly all new residential home construction
and new commercial buildings. The 2001 summer peak was dampened by the nearly
30 percent cutback in irrigation load due to the 2001 voluntary load reduction
program.
In the 90th percentile forecast, total firm summer peak load is expected to increase
from 2,966 megawatts in 2003 reaching 3,794 megawatts in the year 2013, an
average growth rate of 2.5 percent per year over the planning period (table 11).
Forecasted Firm Summer Peak
(megawatts)
figure 13
50th Percentile
95th Percentile90th Percentile
1,600
1,800
2,000
2,200
2,400
2,600
2,800
3,000
3,200
3,400
3,600
3,800
4,000
4,200
1980 1985 1990 1995 2000 2005 2010 2015
23
In the 95h percentile forecast, total firm summer peak load is expected to increase
from 2,980 megawatts in 2003 reaching 3,811 megawatts in the year 2013. The
three scenarios of projected firm summer peak load are illustrated in figure 13.
The maximum firm winter peak demand was 2,342 megawatts reached in December
1998. Evident from the graph is the fact historical winter firm peak load is more
variable than summer firm peak load. The range in temperatures in winter months
is far greater than the range in temperatures in summer months. The wider spread
of the winter forecast lines in figure 14 illustrates the higher variability associated
with winter temperatures.
Firm Winter Peak Load Growth
(megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
95th Percentile 2469 2780 3059 2.2
90th Percentile 2397 2708 2987 2.2
50th Percentile 2211 2521 2801 2.4
table 12
In the 90th percentile forecast, total firm winter peak load is expected to increase
from 2,397 megawatts in 2003 reaching 2,987 megawatts in the year 2013, an
average growth rate of 2.2 percent per year over the planning period (table 12). In
the 95th percentile forecast, total firm winter peak load is expected to increase from
2,469 megawatts in 2003 reaching 3,059 megawatts in the year 2013, an average
growth rate of 2.2 percent per year over the planning period (table 12). The three
scenarios of projected firm winter peak load are illustrated in figure 14.
Forecasted Firm Winter Peak
(megawatts)
figure 14
90th Percentile
50th Percentile
95th Percentile
1,400
1,600
1,800
2,000
2,200
2,400
2,600
2,800
3,000
3,200
3,400
1980-81 1985-86 1990-91 1995-96 2000-01 2005-06 2010-11 2015-16
24
Astaris Load
The Astaris elemental phosphorous plant, located on the western edge of Pocatello,
Idaho, ceased large-scale production in mid-December of 2001. Four months later,
in April 2002, the special contract between Astaris and Idaho Power Company was
terminated. Since then Astaris (now FMC Corporation) has been billed for electric
service as a Schedule 19 (see Industrial discussion). Therefore, Astaris load since
May 1, 2002, as a special contract customer are zero. Astaris had been the
Company’s largest individual customer and in some past years had averaged nearly
200 average megawatts. The historical average annual load at Astaris is presented in
figure 15.
Historical Astaris (FMC) Load
(average megawatts)
figure 15
0
25
50
75
100
125
150
175
200
225
250
1980 1985 1990 1995 2000 2005 2010 2015
25
Company System Load
System Load Growth
(average megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
90th Percentile 1740 1962 2171 2.2
70th Percentile 1672 1889 2094 2.3
Expected Case 1631 1846 2049 2.3
table 13
System load is made up of firm load plus Astaris load, but excludes long-term off-
system contracts. The expected case system load forecast is based upon an economic
forecast for the service territory and represents Idaho Power’s most probable load
growth during the planning period. The expected case forecast system load growth
rate averages 2.3 percent per year over the 2003 to 2013 time period. Company
system load projections are reported in table 13 and pictured in figure 16.
In the expected case forecast, Company system load is expected to increase from
1,631 average megawatts in 2003 reaching 2,049 average megawatts in the year
2013. In the 70th percentile forecast, Company system load is expected to increase
from 1,672 average megawatts in 2003 reaching 2,094 average megawatts in the
year 2013, an average growth rate of 2.3 percent per year over the planning period
(table 13).
Forecasted System Load
(average megawatts)
figure 16
Expected Case
70th Percentile
90th Percentile
1,000
1,200
1,400
1,600
1,800
2,000
2,200
2,400
1980 1985 1990 1995 2000 2005 2010 2015
26
Contract Off-System Load
The contract off-system category represents long-term contracts to supply firm
energy to off-system customers. Long-term contracts are contracts with duration
greater than one year and effective during the forecast period. At this time, only one
long-term contract remains and that is with the city of Colton, California. The
Colton contract is scheduled to expire during the forecast period causing negative
annual growth.
In this forecast, sales to Colton, California, are assumed to continue through May of
2005. Long-term contracts with Washington City and Utah Associated Municipal
Power Systems (UAMPS) expired in June 2002 and December 2003, respectively,
and have not been renewed.
As illustrated in figure 17, the historical consumption for the contract off-system
load category was considerable in the early 1990s, however, after 1995 off-system
loads begin to decline through 2004. As intended, the off-system contracts and their
corresponding energy requirements expired as the Company’s current projections of
surplus energy diminish due to retail load growth.
Forecasted Contract Off-System Load by Customer
(average megawatts)
figure 17
0
50
100
150
200
250
'92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07
Montana
Sierra Pacific
UAMPS
Washington CityElko Colton
OTECC
27
Total Company Load
Total Company Load Growth
(average megawatts)
Growth Rate
(% Per Year)
2003 2008 2013 2003-2013
90th Percentile 1781 1962 2171 2.0
70th Percentile 1713 1889 2094 2.0
Expected Case 1672 1846 2049 2.0
table 14
Accompanied by an outlook of moderate economic growth for the Idaho Power
service territory throughout the forecast period, the 2004 Sales and Load Forecast
projects continued growth in the Company’s total load. Total load is made up of
system load plus long-term off-system contracts. Total company load projections are
listed in table 14 and illustrated in figure 18. The expected case scenario average
growth rate of 2.0 percent per year represents the most probable outlook expected
by the Company. Even though Idaho Power’s system load is expected to increase at a
2.3 percent average annual compound growth rate, the expiration of the UAMPS
contract in December 2003 and the Colton contract during the forecast period
reduces Idaho Power’s total load growth rate to a 2.0 percent average annual
compound growth rate. In the 70th percentile forecast, Company total load is
expected to increase from 1,713 average megawatts in 2003 and reach 2,094 average
megawatts in the year 2013.
Forecasted Total Load
(average megawatts)
figure 18
Expected Case
70th Percentile
90th Percentile
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
2,100
2,200
2,300
1980 1985 1990 1995 2000 2005 2010 2015
28
The composition of total company electricity sales by year is shown in figure 19.
Residential sales are forecast to be over 20 percent higher in 2013 gaining nearly 0.9
million MWh over 2003. Commercial sales are expected to be nearly 40 percent
higher or nearly 1.4 million MWh above 2003 followed by industrial (35 percent
higher or nearly 0.8 million additional MWh) and irrigation (only 5 percent higher
in 2013). Electricity sales to Astaris, as a special contract customer, ended in April
2002. The one remaining long-term contract with Colton, California, to provide firm
energy off-system will expire as of May 2005.
Composition of Electricity Sales
(000's of MWh)
figure 19
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
15,000
16,000
17,000
18,000
1990 1995 2000 2005 2010 2015
Residential
Commercial
Irrigation
Industrial
Astaris
Additional Firm Sales
Contract Off-System
The additional firm sales category (which represents sales to Micron Technology,
Simplot Fertilizer, INEEL, City of Weiser, and Raft River) is forecast to grow by
nearly 22 percent over the 2003 through 2013 time period.
29
30
Appendix A
Appendix A. Historical and Projected Sales and Load
31
32
Residential Load
Historical Residential Sales and Load, 1970-2003
(weather adjusted)
Percent kWh per Billed Sales Percent Average Load Percent
Year Customers Change Customer (000s of MWh)Change (megawatts)Change
1970 132,135 9,982 1,319 152
1971 138,071 4.5%10,537 1,455 10.3% 167 10.1%
1972 145,208 5.2%10,959 1,591 9.4% 184 9.8%
1973 152,957 5.3%11,527 1,763 10.8% 203 10.3%
1974 160,151 4.7%12,070 1,933 9.6% 223 10.2%
1975 167,622 4.7%12,941 2,169 12.2% 250 11.9%
1976 175,720 4.8%13,471 2,367 9.1% 271 8.6%
1977 184,561 5.0%13,688 2,526 6.7% 290 6.9%
1978 194,650 5.5%14,310 2,785 10.3% 322 10.9%
1979 202,982 4.3%14,786 3,001 7.7% 343 6.5%
1980 209,629 3.3%14,652 3,071 2.3% 350 2.1%
1981 213,579 1.9%14,399 3,075 0.1% 350 0.1%
1982 216,696 1.5%14,429 3,127 1.7% 357 2.0%
1983 219,849 1.5%14,366 3,158 1.0% 362 1.5%
1984 222,695 1.3%14,152 3,152 -0.2% 357 -1.6%
1985 225,185 1.1%14,082 3,171 0.6% 363 1.6%
1986 227,081 0.8%14,172 3,218 1.5% 368 1.4%
1987 228,868 0.8%14,103 3,228 0.3% 367 -0.3%
1988 230,771 0.8%14,350 3,312 2.6% 377 2.9%
1989 233,370 1.1%14,391 3,358 1.4% 385 2.1%
1990 238,117 2.0%14,338 3,414 1.7% 393 2.0%
1991 243,207 2.1%14,474 3,520 3.1% 402 2.2%
1992 249,767 2.7%14,167 3,538 0.5% 408 1.5%
1993 258,271 3.4%14,221 3,673 3.8% 415 1.8%
1994 267,854 3.7%14,005 3,751 2.1% 434 4.6%
1995 277,131 3.5%14,008 3,882 3.5% 439 1.0%
1996 286,227 3.3%13,771 3,942 1.5% 457 4.1%
1997 294,674 3.0%13,689 4,034 2.3% 463 1.4%
1998 303,300 2.9%13,677 4,148 2.8% 473 2.2%
1999 312,901 3.2%13,584 4,251 2.5% 487 2.9%
2000 322,402 3.0%13,378 4,313 1.5% 499 2.5%
2001 331,009 2.7%13,133 4,347 0.8% 475 -4.9%
2002 339,764 2.6%12,629 4,291 -1.3% 489 2.9%
2003 349,219 2.8%12,635 4,412 2.8% 506 3.6%
table 15
33
Residential Load
Projected Residential Sales and Load, 2004-2015
Percent kWh per Billed Sales Percent Average Load Percent
Year Customers Change Customer (000s of MWh)Change (megawatts)Change
2004 357,467 2.4%12,525 4,477 1.5% 513 1.3%
2005 365,400 2.2%12,541 4,583 2.4% 524 2.1%
2006 373,593 2.2%12,519 4,677 2.1% 535 2.1%
2007 382,030 2.3%12,482 4,769 2.0% 545 2.0%
2008 390,622 2.2%12,472 4,872 2.2% 557 2.2%
2009 398,661 2.1%12,462 4,968 2.0% 568 1.9%
2010 406,053 1.9%12,448 5,055 1.7% 578 1.7%
2011 413,227 1.8%12,439 5,140 1.7% 587 1.7%
2012 420,467 1.8%12,424 5,224 1.6% 597 1.7%
2013 427,885 1.8%12,410 5,310 1.6% 607 1.6%
2014 434,980 1.7%12,393 5,391 1.5% 616 1.5%
2015 442,013 1.6%12,373 5,469 1.5% 625 1.5%
table 16
34
Commercial Load
Historical Commercial Sales and Load, 1970-2003
(weather adjusted)
Percent kWh per Billed Sales Percent Average Load Percent
Year Customers Change Customer (000s of MWh)Change (megawatts)Change
1970 21,375 42,769 914 105
1971 22,077 3.3%45,386 1,002 9.6% 115 9.1%
1972 22,585 2.3%46,140 1,042 4.0% 120 4.3%
1973 23,286 3.1%48,140 1,121 7.6% 128 7.3%
1974 24,096 3.5%49,025 1,181 5.4% 136 5.8%
1975 25,045 3.9%51,213 1,283 8.6% 147 8.3%
1976 26,034 3.9%52,507 1,367 6.6% 157 6.6%
1977 27,112 4.1%52,410 1,421 3.9% 162 3.4%
1978 27,831 2.7%52,474 1,460 2.8% 169 4.3%
1979 28,087 0.9%56,389 1,584 8.4% 180 6.4%
1980 28,797 2.5%54,136 1,559 -1.6% 178 -1.0%
1981 29,567 2.7%54,282 1,605 3.0% 184 3.3%
1982 30,167 2.0%54,123 1,633 1.7% 186 1.3%
1983 30,776 2.0%52,589 1,618 -0.9% 186 -0.2%
1984 31,554 2.5%53,054 1,674 3.4% 190 2.3%
1985 32,417 2.7%53,634 1,739 3.9% 199 4.5%
1986 33,208 2.4%53,292 1,770 1.8% 202 1.8%
1987 33,975 2.3%52,856 1,796 1.5% 204 0.9%
1988 34,723 2.2%54,186 1,882 4.8% 215 5.1%
1989 35,638 2.6%55,245 1,969 4.6% 226 5.4%
1990 36,785 3.2%56,172 2,066 4.9% 237 4.7%
1991 37,922 3.1%55,813 2,117 2.4% 243 2.5%
1992 39,022 2.9%56,337 2,198 3.9% 253 4.2%
1993 40,047 2.6%57,461 2,301 4.7% 261 3.2%
1994 41,629 4.0%58,264 2,425 5.4% 280 7.4%
1995 43,165 3.7%58,620 2,530 4.3% 288 2.8%
1996 44,995 4.2%62,063 2,793 10.4% 323 12.1%
1997 46,819 4.1%62,012 2,903 4.0% 333 3.2%
1998 48,404 3.4%62,847 3,042 4.8% 348 4.5%
1999 49,430 2.1%64,054 3,166 4.1% 363 4.3%
2000 50,117 1.4%66,163 3,316 4.7% 384 5.8%
2001 51,501 2.8%67,286 3,465 4.5% 382 -0.3%
2002 52,915 2.7%64,648 3,421 -1.3% 390 2.0%
2003 54,194 2.4%64,428 3,492 2.1% 400 2.6%
table 17
35
Commercial Load
Projected Commercial Sales and Load, 2004-2015
Percent kWh per Billed Sales Percent Average Load Percent
Year Customers Change Customer (000s of MWh)Change (megawatts)Change
2004 55,653 2.7%65,444 3,642 4.3% 417 4.3%
2005 57,119 2.6%66,534 3,800 4.3% 435 4.1%
2006 58,576 2.6%67,157 3,934 3.5% 450 3.5%
2007 60,069 2.5%67,715 4,068 3.4% 465 3.4%
2008 61,583 2.5%68,302 4,206 3.4% 481 3.4%
2009 63,018 2.3%68,866 4,340 3.2% 496 3.2%
2010 64,363 2.1%69,408 4,467 2.9% 511 2.9%
2011 65,678 2.0%69,948 4,594 2.8% 525 2.8%
2012 67,002 2.0%70,460 4,721 2.8% 540 2.8%
2013 68,350 2.0%70,953 4,850 2.7% 554 2.7%
2014 69,656 1.9%71,436 4,976 2.6% 569 2.6%
2015 70,956 1.9%71,917 5,103 2.6% 583 2.6%
table 18
36
Irrigation Load
Historical Irrigation Sales and Load, 1970-2003
(weather adjusted)
Percent kWh per Billed Sales Percent Average Load Percent
Year Customers Change Customer (000s of MWh)Change (megawatts)Change
1970 7,319 117,868 863 98
1971 7,518 2.7%134,026 1,008 16.8% 115 16.8%
1972 7,815 4.0%124,924 976 -3.1% 111 -3.4%
1973 8,341 6.7%134,174 1,119 14.6% 128 15.0%
1974 8,971 7.6%142,618 1,279 14.3% 146 14.3%
1975 9,480 5.7%154,038 1,460 14.1% 167 14.1%
1976 9,936 4.8%152,873 1,519 4.0% 173 3.8%
1977 10,238 3.0%154,284 1,580 4.0% 180 4.3%
1978 10,476 2.3%146,493 1,535 -2.8% 176 -2.3%
1979 10,711 2.2%156,417 1,675 9.2% 190 8.0%
1980 10,854 1.3%154,019 1,672 -0.2% 190 0.0%
1981 11,248 3.6%164,547 1,851 10.7% 211 10.8%
1982 11,312 0.6%151,076 1,709 -7.7% 195 -7.4%
1983 11,133 -1.6%143,379 1,596 -6.6% 182 -6.7%
1984 11,375 2.2%130,672 1,486 -6.9% 169 -7.2%
1985 11,576 1.8%127,751 1,479 -0.5% 169 -0.2%
1986 11,308 -2.3%129,567 1,465 -0.9% 167 -0.9%
1987 11,254 -0.5%125,311 1,410 -3.7% 161 -3.7%
1988 11,378 1.1%128,786 1,465 3.9% 167 3.6%
1989 11,957 5.1%133,471 1,596 8.9% 182 9.2%
1990 12,340 3.2%139,925 1,727 8.2% 197 8.2%
1991 12,484 1.2%134,100 1,674 -3.0% 191 -3.1%
1992 12,809 2.6%133,950 1,716 2.5% 195 2.2%
1993 13,078 2.1%130,080 1,701 -0.8% 194 -0.6%
1994 13,559 3.7%125,900 1,707 0.3% 195 0.4%
1995 13,679 0.9%125,400 1,715 0.5% 196 0.5%
1996 14,074 2.9%122,235 1,720 0.3% 196 0.0%
1997 14,383 2.2%112,803 1,622 -5.7% 185 -5.4%
1998 14,695 2.2%113,273 1,665 2.6% 190 2.6%
1999 14,912 1.5%115,262 1,719 3.3% 196 3.3%
2000 15,253 2.3%121,481 1,853 7.8% 211 7.4%
2001 15,522 1.8%109,834 1,705 -8.0% 195 -7.8%
2002 15,840 2.0%104,668 1,658 -2.8% 189 -2.7%
2003 16,020 1.1%104,034 1,667 0.5% 190 0.5%
table 19
37
Irrigation Load
Projected Irrigation Sales and Load, 2004-2015
Percent kWh per Billed Sales Percent Average Load Percent
Year Customers Change Customer (000s of MWh)Change (megawatts)Change
2004 16,434 2.6%104,421 1,716 3.0% 195 2.7%
2005 16,729 1.8%103,022 1,723 0.4% 197 0.7%
2006 17,026 1.8%101,058 1,721 -0.2% 196 -0.2%
2007 17,323 1.7%99,591 1,725 0.3% 197 0.3%
2008 17,618 1.7%98,144 1,729 0.2% 197 0.0%
2009 17,913 1.7%96,745 1,733 0.2% 198 0.5%
2010 18,209 1.7%95,383 1,737 0.2% 198 0.2%
2011 18,506 1.6%94,077 1,741 0.2% 199 0.2%
2012 18,801 1.6%92,815 1,745 0.2% 199 0.0%
2013 19,095 1.6%91,597 1,749 0.2% 200 0.5%
2014 19,393 1.6%90,391 1,753 0.2% 200 0.2%
2015 19,690 1.5%89,223 1,757 0.2% 201 0.2%
table 20
38
Industrial Load
Historical Industrial Sales and Load, 1970-2003
Percent kWh per Billed Sales Percent Average Load Percent
Year Customers Change Customer (000s of MWh)Change (megawatts)Change
1970 49 9,173,784 445 51
1971 50 3.3% 10,474,941 525 17.9% 60 17.2%
1972 56 12.1% 10,944,714 615 17.2% 71 17.3%
1973 63 12.3% 10,889,056 687 11.7% 79 11.4%
1974 65 2.2% 11,464,249 739 7.6% 84 6.9%
1975 71 10.5% 11,014,121 785 6.1% 90 7.3%
1976 73 3.0% 11,681,540 858 9.3% 99 9.0%
1977 85 15.1% 10,988,826 929 8.3% 106 7.4%
1978 99 17.6% 9,786,753 972 4.7% 111 4.8%
1979 109 9.6% 9,989,158 1,087 11.8% 126 13.3%
1980 112 2.7% 9,894,706 1,106 1.7% 125 -0.4%
1981 118 5.7% 9,718,723 1,148 3.9% 132 5.5%
1982 122 3.5% 9,504,283 1,162 1.2% 133 0.5%
1983 122 -0.3% 9,797,522 1,194 2.7% 137 3.4%
1984 124 1.5% 10,369,789 1,282 7.4% 147 7.1%
1985 125 1.2% 10,844,888 1,357 5.9% 155 5.7%
1986 129 2.7% 10,550,145 1,357 -0.1% 155 -0.3%
1987 134 4.1% 11,006,455 1,474 8.7% 169 9.0%
1988 133 -1.0% 11,660,183 1,546 4.9% 176 4.6%
1989 132 -0.6% 12,091,482 1,594 3.1% 183 3.5%
1990 132 0.2% 12,584,200 1,662 4.3% 190 4.3%
1991 135 2.5% 12,699,665 1,719 3.4% 196 2.9%
1992 140 3.4% 12,650,945 1,770 3.0% 202 3.3%
1993 141 0.5% 13,179,585 1,854 4.7% 212 4.9%
1994 143 1.7% 13,616,608 1,948 5.1% 223 5.1%
1995 120 -15.9% 16,793,437 2,021 3.7% 230 3.1%
1996 103 -14.4% 18,774,093 1,934 -4.3% 221 -4.1%
1997 106 2.7% 19,309,504 2,042 5.6% 235 6.3%
1998 111 4.6% 19,378,734 2,145 5.0% 244 4.2%
1999 108 -2.3% 19,985,029 2,160 0.7% 247 1.0%
2000 107 -0.8% 20,433,299 2,191 1.5% 250 1.3%
2001 111 3.5% 20,618,361 2,289 4.4% 261 4.2%
2002 111 -0.1% 19,441,876 2,156 -5.8% 246 -5.5%
2003 112 1.0% 19,950,866 2,234 3.6% 255 3.7%
table 21
39
Industrial Load
Projected Industrial Sales and Load, 2004-2015
Percent kWh per Billed Sales Percent Average Load Percent
Year Customers Change Customer (000s of MWh)Change (megawatts)Change
2004 114 1.5% 20,198,080 2,296 2.7% 263 3.1%
2005 116 2.1% 20,465,291 2,374 3.4% 272 3.2%
2006 118 1.7% 20,783,739 2,452 3.3% 280 3.3%
2007 119 0.8% 21,288,653 2,533 3.3% 290 3.3%
2008 121 1.7% 21,561,643 2,609 3.0% 298 3.0%
2009 122 0.8% 21,999,442 2,684 2.9% 307 2.9%
2010 124 1.6% 22,298,462 2,765 3.0% 316 3.0%
2011 125 0.8% 22,766,760 2,846 2.9% 325 2.9%
2012 126 0.8% 23,213,111 2,925 2.8% 334 2.8%
2013 128 1.6% 23,477,579 3,005 2.7% 344 2.8%
2014 131 2.3% 23,576,332 3,088 2.8% 353 2.8%
2015 131 0.0% 24,208,060 3,171 2.7% 363 2.7%
table 22
40
Additional Firm Sales and Load
(includes Micron Technology, Simplot Fertilizer, INEEL, City of Weiser, and Raft River Rural Electric Cooperative, Inc.)
Additional Firm Sales and Load - Historical Data, 1970-2003
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
1970 318 36
1971 294 -7.6% 34 -7.6%
1972 284 -3.5% 32 -3.8%
1973 290 2.2% 33 2.5%
1974 282 -2.8% 32 -2.8%
1975 314 11.2% 36 11.2%
1976 277 -11.8% 32 -12.1%
1977 311 12.4% 36 12.7%
1978 357 14.7% 41 14.7%
1979 373 4.7% 43 4.7%
1980 360 -3.7% 41 -3.9%
1981 376 4.5% 43 4.8%
1982 368 -2.2% 42 -2.2%
1983 425 15.5% 48 15.5%
1984 467 9.9% 53 9.6%
1985 473 1.4% 54 1.6%
1986 482 1.9% 55 1.9%
1987 503 4.3% 57 4.3%
1988 531 5.6% 60 5.3%
1989 671 26.5% 77 26.9%
1990 625 -6.9% 71 -6.9%
1991 661 5.7% 75 5.7%
1992 680 2.9% 77 2.6%
1993 689 1.3% 79 1.6%
1994 741 7.4% 85 7.4%
1995 877 18.4% 100 18.4%
1996 988 12.6% 113 12.3%
1997 1,048 6.0% 120 6.3%
1998 1,112 6.2% 127 6.2%
1999 1,121 0.8% 128 0.8%
2000 1,143 1.9% 130 1.7%
2001 1,118 -2.1% 128 -1.9%
2002 1,139 1.9% 130 1.9%
2003 1,120 -1.7% 128 -1.7%
table 23
41
Additional Firm Sales and Load
(includes Micron Technology, Simplot Fertilizer, INEEL, City of Weiser, and Raft River Rural Electric Cooperative, Inc.)
Additional Firm Sales and Load - Projections, 2004-2015
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
2004 1,152 2.8% 131 2.6%
2005 1,168 1.4% 133 1.7%
2006 1,194 2.3% 136 2.3%
2007 1,220 2.2% 139 2.2%
2008 1,249 2.4% 142 2.1%
2009 1,275 2.1% 146 2.3%
2010 1,304 2.3% 149 2.3%
2011 1,326 1.7% 151 1.7%
2012 1,346 1.5% 153 1.2%
2013 1,361 1.1% 155 1.4%
2014 1,380 1.4% 157 1.4%
2015 1,398 1.4% 160 1.4%
table 24
42
Company Firm Load
Historical Company Firm Sales and Load, 1970-2003
(weather adjusted)
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
1970 3,859 489
1971 4,284 11.0% 542 10.8%
1972 4,508 5.3% 572 5.4%
1973 4,981 10.5% 631 10.3%
1974 5,415 8.7% 687 9.0%
1975 6,011 11.0% 763 11.0%
1976 6,388 6.3% 809 6.0%
1977 6,766 5.9% 856 5.8%
1978 7,109 5.1% 905 5.8%
1979 7,721 8.6% 974 7.6%
1980 7,767 0.6% 978 0.4%
1981 8,056 3.7% 1,017 4.0%
1982 7,998 -0.7% 1,010 -0.7%
1983 7,991 -0.1% 1,012 0.3%
1984 8,061 0.9% 1,011 -0.1%
1985 8,219 2.0% 1,037 2.5%
1986 8,292 0.9% 1,046 0.8%
1987 8,410 1.4% 1,057 1.1%
1988 8,735 3.9% 1,099 3.9%
1989 9,189 5.2% 1,161 5.7%
1990 9,495 3.3% 1,201 3.4%
1991 9,691 2.1% 1,220 1.6%
1992 9,903 2.2% 1,252 2.6%
1993 10,219 3.2% 1,280 2.2%
1994 10,573 3.5% 1,342 4.8%
1995 11,026 4.3% 1,380 2.9%
1996 11,376 3.2% 1,442 4.5%
1997 11,649 2.4% 1,471 2.0%
1998 12,112 4.0% 1,523 3.5%
1999 12,417 2.5% 1,565 2.8%
2000 12,816 3.2% 1,624 3.8%
2001 12,924 0.8% 1,586 -2.3%
2002 12,665 -2.0% 1,591 0.3%
2003 12,925 2.0% 1,630 2.4%
table 25
43
Company Firm Load
Projected Company Firm Sales and Load, 2004-2015
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
2004 13,283 2.8% 1,675 2.7%
2005 13,648 2.8% 1,719 2.6%
2006 13,978 2.4% 1,760 2.4%
2007 14,315 2.4% 1,803 2.4%
2008 14,666 2.4% 1,846 2.4%
2009 15,000 2.3% 1,889 2.3%
2010 15,328 2.2% 1,930 2.2%
2011 15,647 2.1% 1,970 2.1%
2012 15,961 2.0% 2,008 2.0%
2013 16,274 2.0% 2,049 2.0%
2014 16,587 1.9% 2,088 1.9%
2015 16,898 1.9% 2,127 1.9%
table 26
44
Astaris Load
Historical Astaris Sales and Load, 1970-2003
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
1970 1,657 189
1971 1,508 -9.0% 172 -9.0%
1972 1,819 20.6% 207 20.3%
1973 1,645 -9.6% 188 -9.3%
1974 1,643 -0.1% 188 -0.1%
1975 1,557 -5.3% 178 -5.3%
1976 1,575 1.2% 179 0.9%
1977 1,418 -10.0% 162 -9.7%
1978 1,542 8.8% 176 8.8%
1979 1,395 -9.6% 159 -9.6%
1980 1,513 8.5% 172 8.2%
1981 1,634 8.0% 186 8.3%
1982 1,554 -4.9% 177 -4.9%
1983 1,610 3.6% 184 3.6%
1984 1,701 5.7% 194 5.4%
1985 1,614 -5.1% 184 -4.9%
1986 1,554 -3.7% 177 -3.7%
1987 1,692 8.9% 193 8.9%
1988 1,635 -3.4% 186 -3.6%
1989 1,703 4.2% 194 4.5%
1990 1,604 -5.8% 183 -5.8%
1991 1,609 0.3% 184 0.3%
1992 1,570 -2.4% 179 -2.7%
1993 1,437 -8.4% 164 -8.2%
1994 1,420 -1.2% 162 -1.2%
1995 1,567 10.4% 179 10.4%
1996 1,689 7.8% 192 7.5%
1997 1,628 -3.6% 186 -3.4%
1998 1,273 -21.8% 145 -21.8%
1999 1,051 -17.4% 120 -17.4%
2000 1,490 41.7% 170 41.4%
2001 684 -54.1% 78 -54.0%
2002 11 -98.3% 1 -98.3%
2003 0 -100.0% 0 -100.0%
table 27
45
Astaris Load
Projected Astaris Sales and Load, 2004
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
2004 0 0.0% 0 0.0%
table 28
46
Company System Load
Historical Company System Sales and Load, 1970-2003
(weather adjusted)
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
1970 5,517 688
1971 5,792 5.0% 723 5.1%
1972 6,328 9.3% 789 9.1%
1973 6,626 4.7% 828 4.9%
1974 7,059 6.5% 884 6.8%
1975 7,568 7.2% 949 7.4%
1976 7,963 5.2% 997 5.0%
1977 8,184 2.8% 1,026 2.9%
1978 8,652 5.7% 1,090 6.3%
1979 9,115 5.4% 1,141 4.7%
1980 9,280 1.8% 1,159 1.5%
1981 9,689 4.4% 1,213 4.7%
1982 9,552 -1.4% 1,196 -1.4%
1983 9,601 0.5% 1,205 0.8%
1984 9,762 1.7% 1,215 0.8%
1985 9,833 0.7% 1,231 1.3%
1986 9,845 0.1% 1,232 0.1%
1987 10,102 2.6% 1,260 2.3%
1988 10,370 2.7% 1,294 2.7%
1989 10,892 5.0% 1,365 5.5%
1990 11,099 1.9% 1,393 2.1%
1991 11,299 1.8% 1,413 1.4%
1992 11,473 1.5% 1,440 1.9%
1993 11,656 1.6% 1,452 0.9%
1994 11,993 2.9% 1,512 4.1%
1995 12,593 5.0% 1,568 3.7%
1996 13,065 3.7% 1,644 4.9%
1997 13,277 1.6% 1,666 1.4%
1998 13,385 0.8% 1,675 0.6%
1999 13,468 0.6% 1,691 0.9%
2000 14,306 6.2% 1,802 6.6%
2001 13,608 -4.9% 1,668 -7.4%
2002 12,677 -6.8% 1,593 -4.5%
2003 12,925 2.0% 1,630 2.4%
table 29
47
Company System Load
Projected Company System Sales and Load, 2004-2015
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
2004 13,283 2.8% 1,675 2.7%
2005 13,648 2.8% 1,719 2.6%
2006 13,978 2.4% 1,760 2.4%
2007 14,315 2.4% 1,803 2.4%
2008 14,666 2.4% 1,846 2.4%
2009 15,000 2.3% 1,889 2.3%
2010 15,328 2.2% 1,930 2.2%
2011 15,647 2.1% 1,970 2.1%
2012 15,961 2.0% 2,008 2.0%
2013 16,274 2.0% 2,049 2.0%
2014 16,587 1.9% 2,088 1.9%
2015 16,898 1.9% 2,127 1.9%
table 30
48
Contract Off-System Load
Historical Contract Off-System Sales and Load, 1970-2003
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
1970 386 44
1971 439 13.6% 50 13.6%
1972 448 2.0% 51 1.7%
1973 489 9.3% 56 9.6%
1974 501 2.3% 57 2.3%
1975 568 13.5% 65 13.5%
1976 613 7.9% 70 7.6%
1977 659 7.5% 75 7.8%
1978 684 3.7% 78 3.7%
1979 759 11.1% 87 11.1%
1980 762 0.3% 87 0.0%
1981 752 -1.2% 86 -1.0%
1982 736 -2.2% 84 -2.2%
1983 710 -3.5% 81 -3.5%
1984 747 5.2% 85 4.9%
1985 779 4.3% 89 4.6%
1986 670 -13.9% 77 -13.9%
1987 644 -4.0% 73 -4.0%
1988 675 4.9% 77 4.6%
1989 740 9.7% 84 10.0%
1990 968 30.8% 111 30.8%
1991 1,537 58.8% 175 58.8%
1992 1,348 -12.3% 154 -12.5%
1993 1,557 15.5% 178 15.8%
1994 1,811 16.3% 207 16.3%
1995 1,583 -12.6% 181 -12.6%
1996 1,285 -18.8% 146 -19.1%
1997 674 -47.5% 77 -47.4%
1998 716 6.2% 82 6.2%
1999 568 -20.6% 65 -20.6%
2000 587 3.3% 67 3.1%
2001 538 -8.4% 61 -8.2%
2002 454 -15.7% 52 -15.7%
2003 346 -23.6% 40 -23.6%
table 31
49
Contract Off-System Load
Projected Contract Off-System Sales and Load, 2004-2006
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
2004 26 -92.6% 3 -92.6%
2005 11 -57.6% 1 -57.4%
2006 0 -100.0% 0 -100.0%
table 32
50
Total Company Load
Historical Total Company Sales and Load, 1970-2003
(weather adjusted)
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
1970 5,903 734
1971 6,231 5.6% 775 5.6%
1972 6,775 8.7% 842 8.6%
1973 7,115 5.0% 886 5.2%
1974 7,559 6.2% 943 6.5%
1975 8,136 7.6% 1,017 7.8%
1976 8,576 5.4% 1,069 5.2%
1977 8,844 3.1% 1,104 3.2%
1978 9,336 5.6% 1,171 6.1%
1979 9,875 5.8% 1,231 5.1%
1980 10,042 1.7% 1,249 1.4%
1981 10,442 4.0% 1,302 4.3%
1982 10,288 -1.5% 1,283 -1.5%
1983 10,311 0.2% 1,289 0.5%
1984 10,509 1.9% 1,303 1.1%
1985 10,611 1.0% 1,323 1.5%
1986 10,515 -0.9% 1,311 -0.9%
1987 10,746 2.2% 1,336 1.9%
1988 11,045 2.8% 1,374 2.8%
1989 11,632 5.3% 1,452 5.7%
1990 12,067 3.7% 1,507 3.8%
1991 12,836 6.4% 1,595 5.8%
1992 12,821 -0.1% 1,599 0.2%
1993 13,213 3.1% 1,636 2.3%
1994 13,804 4.5% 1,726 5.5%
1995 14,176 2.7% 1,755 1.7%
1996 14,350 1.2% 1,795 2.3%
1997 13,951 -2.8% 1,746 -2.7%
1998 14,100 1.1% 1,760 0.8%
1999 14,036 -0.5% 1,758 -0.1%
2000 14,893 6.1% 1,871 6.4%
2001 14,146 -5.0% 1,732 -7.5%
2002 13,130 -7.2% 1,646 -4.9%
2003 13,271 1.1% 1,671 1.5%
table 33
Total Company Load
Projected Total Company Sales and Load, 2004-2015
Billed Sales Percent Average Load Percent
Year (000s of MWh)Change (megawatts)Change
2004 13,308 0.3% 1,678 0.4%
2005 13,659 2.6% 1,720 2.5%
2006 13,978 2.3% 1,760 2.3%
2007 14,315 2.4% 1,803 2.4%
2008 14,666 2.4% 1,846 2.4%
2009 15,000 2.3% 1,889 2.3%
2010 15,328 2.2% 1,930 2.2%
2011 15,647 2.1% 1,970 2.1%
2012 15,961 2.0% 2,008 2.0%
2013 16,274 2.0% 2,049 2.0%
2014 16,587 1.9% 2,088 1.9%
2015 16,898 1.9% 2,127 1.9%
table 34
51