peak demand and energy projection bandwidths 2003â2012 projections
PEAK DEMAND AND ENERGY PROJECTION BANDWIDTHS 2003–2012 PROJECTIONS
Prepared by Load Forecasting Working Group
Approved by NERC Planning Committee July 15, 2003
North American Electric Reliability Council
2003–2012 Peak Demand and Energy Projection Bandwidths Table of Contents INTRODUCTION ........................................................................................................................................ 1 RESULTS ..................................................................................................................................................... 1 METHODOLOGY ....................................................................................................................................... 3 LOAD FORECASTING WORKING GROUP .......................................................................................... 16
Table 1: U.S. Summer Peak Demand ............................................................................................ 6 Table 2: U.S. Annual Net Energy for Load ................................................................................... 6 Table 3: Canada Winter Peak Demand.......................................................................................... 8 Table 4: Canadian Annual Net Energy for Load ........................................................................... 8 Table 5: Eastern Interconnection Summer Peak Demand ........................................................... 10 Table 6: Eastern Interconnection Annual Net Energy For Load ................................................. 10 Table 7: Western Interconnection Summer Peak Demand .......................................................... 12 Table 8: Western Interconnection Annual Net Energy For Load................................................ 12 Table 9: ERCOT Interconnection Summer Peak Demand .......................................................... 14 Table 10: ERCOT Interconnection Annual Net Energy For Load .............................................. 14 Figure 1: U.S. Peak Demand 2003–1012 Projection ..................................................................... 5 Figure 2: U.S. Net Energy for Load 2003–1012 Projection .......................................................... 5 Figure 4: Canada Net Energy for Load 2003–2012 Projection ..................................................... 7 Figure 5: Eastern Interconnection Peak Demand 2003–2012 Projection ...................................... 9 Figure 6: Eastern Interconnection Net Energy for Load 2003–2012 Projection ........................... 9 Figure 7: Western Interconnection Peak Demand 2003–2012 Projection................................... 11 Figure 8: Western Interconnection Net Energy for Load 2003–2012 Projection........................ 11 Figure 9: ERCOT Interconnection Peak Demand 2003–1012 Projection................................... 13 Figure 10: ERCOT Interconnection Net Energy for Load 2003–2012 Projection ...................... 13 Figure 11: Sensitivity Bands for Predictor Variables .................................................................. 15
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2003–2012 Peak Demand and Energy Projection Bandwidths
INTRODUCTION The North American Electric Reliability Council (NERC) Load Forecasting Working Group (LFWG) is responsible for developing bandwidths around the aggregated United States and Canadian annual forecasts of peak demand and annual net energy for load. In addition, the group is charged with developing bandwidths around the three Interconnections 1) Eastern, 2) ERCOT, and 3) Western. This report discusses the methodology and resulting bandwidths around the 2003-2012 NERC aggregated projections. Forecasts cannot precisely predict the future. Instead, many forecasts report probabilities of a range of possible outcomes. Each demand projection, for example, is assumed to represent the expected midpoint of possible future outcomes. This means that a future year’s actual demand may deviate from the midpoint projections due to the inherent variability of the key factors that drive electrical usage. In the case of the NERC aggregated projections, there is a long-run 50% probability that actual demand will be higher than the forecast midpoint and a long-run 50% probability that it will be lower. For planning and analytical purposes, it is useful to have an estimate not only of the expected midpoint of possible future outcomes, but also of the distribution of probabilities around the projection. Accordingly, the LFWG develops upper and lower 80% confidence bands around the NERC-aggregated projections. This means that there is a long-run 80% probability that future demand will occur within these bands. Concurrently, there is a 10% chance that future demand could be less than the lower band and a 10% chance that future demand could be higher than the upper band. This report is organized in three sections. The first section presents the bandwidth results, the second section describes the methodology used to develop the bandwidths and the final section shows the results in chart and table format. RESULTS The graphical and numerical results of the bandwidth analyses are included in the following figures and tables: Figure 1/Table 1 — United States Summer Peak Demand Figure 2/Table 2 — United States Annual Net Energy for Load Figure 3/Table 3 — Canada Winter Peak Demand Figure 4/Table 4 — Canada Annual Net Energy for Load Figure 5/Table 5 — Eastern Interconnection Summer Peak Demand Figure 6/Table 6 — Eastern Interconnection Annual Net Energy for Load Figure 7/Table 7 — Western Interconnection Summer Peak Demand Figure 8/Table 8 — Western Interconnection Annual Net Energy for Load Figure 9/Table 9 — ERCOT Interconnection Summer Peak Demand
Figure 10/Table 10 — ERCOT Interconnection Annual Net Energy for Load Table 11 — Sensitivity Bands for Predictor Variables
Load Forecasting Working Group
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2003–2012 Peak Demand and Energy Projection Bandwidths For the United States, the aggregated projected demand rises from 720 GW in 2003 to 863 GW in 2012, which represents an average annual growth rate of 2.0%. There is a 10% chance that the 2012 peak demand will be 944 GW or higher. This would represent an average annual growth of at least 2.5% over the 2003–2012 period. Correspondingly, there is a 10% chance that the 2012 peak demand will be 790 GW or lower, which would represent an average annual growth of no more than 1.6%. The width of the 80% confidence interval in 2012 is 154 GW, of which 81 GW are above the NERC-aggregate forecast and 73 GW are below. The percent differences from the base projection for the upper and lower bandwidths in 2012 are 9.4% and – 8.5%, respectively. The NERC-aggregated projections of Canadian winter peak demand rise from 89.3 GW in 2003/04 to 98.4 GW in 2012/13, which represents an average annual growth rate of 1.1%. There is a 10% chance that the 2012/13 demand will be 124.6 GW or higher. This would represent an average annual growth rate of at least 2.6% over the 2003/04–2012/13 period. A 10% chance also exists that the 2012/13 peak demand will be 76.5 GW or lower. This would represent an average annual growth of no more than –0.6%. The width of the 80% confidence interval in 2012/13 is 48 GW, of which 26 GW are above the NERC forecast and 22 GW are below. The percent differences from the base projection for the upper and lower bandwidths in 2012/13 are 26.6% and –22.2%, respectively. The U.S. net energy for load aggregated forecast is projected to increase at an average annual growth rate of 1.8% from 2003 to 2012. The 80% bandwidths represent average annual growth rates for the high and low bands of 2.3% and 1.4% per year, respectively. In Canada, net energy for load is projected to grow at an average annual rate of 1.3%. The upper and lower bands for energy have average annual growth rates of 2.8% and -0.4%, respectively, over the forecast period. For the Eastern Interconnection, which is the largest of the three Interconnections, peak demand is projected to rise from 597 GW in 2003 to 709 GW in 2012, which represents an annual average growth rate of 1.9%. There is a 10% chance that the 2012 demand will be 788 GW, which would represent a 2.5% annual growth rate. On the low side, there is a 10% chance that the 2012 peak will be 638 GW, which would represent a 1.4% annual rate of growth. The Western Interconnection peak demand is projected to increase from 137 GW in 2003 to 164 GW in 2012, a 2.1% annual average growth rate. The 80% confidence intervals for the Western Interconnection represent average annual growth rates for the high and low bands of 2.6% and 1.6% per year, respectively. For the ERCOT Interconnection, peak demand is projected to rise from 58 GW in 2003 to 72 GW in 2012, which represents a 2.5% annual growth rate. The average annual growth rates for the 80% high and low confidence intervals are 3.1% and 2.0% per year, respectively.
Load Forecasting Working Group
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2003–2012 Peak Demand and Energy Projection Bandwidths The Eastern Interconnection’s aggregated net energy for load projection is expected to increase at an average annual growth rate of 1.6% from 2003 to 2012. The average annual growth rates for the 80% confidence high and low bands are 2.2% and 1.0% per year, respectively. For the Western Interconnection, the upper band for energy, the aggregated energy projection, and the low band for energy have average annual growth rates of 2.5%, 2.0%, and 1.4%, respectively, over the 2003 to 2012 period. Using this same format, ERCOT’s average annual growth rates are 3.3%, 2.7 and 2.1%. METHODOLOGY The principal features of the current methodology include: 1. Econometric models for the United States and Canada represent the NERC-aggregated projection of annual net energy for load as a function of key economic variables, energy prices and weather. An intercept is included in the model to account for other less important determinants of net energy for load. 2. Regression models for the Interconnections represent the projection of net energy for load as a function of NERC total energy usage plus an intercept term that accounts for statistically random determinants of net energy for load.
3. A Monte Carlo simulation model is used to estimate the energy and demand bandwidths. This analysis incorporates explicit uncertainty in the economic, price and weather variables themselves and in the interrelationships among the variables. The simulation for demand also explicitly includes uncertainty in load factor that accounts for the variability in peaking weather conditions. The econometric model for U.S. energy relates net energy for load positively to real (inflation adjusted) U.S. Gross Domestic Product (GDP), real (inflation adjusted) U.S. price of natural gas, population-weighted heating and cooling degree days. The net energy for load is related negatively to the real (inflation adjusted) U.S. price of electricity. The Canadian model is analogous except that cooling degree days are excluded because of their statistical insignificance. The Interconnection model includes an equation for each of the three Interconnections and relates their individual net energy for load to the NERC total energy usage. Monte Carlo simulations are used to enable various sources of forecast uncertainty to be addressed. One source of uncertainty is the future magnitudes of the economic variables. To represent this, a range of possible growth rates is developed around an 80% probability that the actual growth rate will be within that range. A Delphi survey of LFWG members is used to estimate the midpoint and upper and lower growth rates for the relevant variables in the United States model. A statistical time series model is used to determine the variability of economic and price variables in the Canadian model. Table 11 shows the growth rates assumed for the economic variables used in the United States and Canadian simulations. The Monte Carlo simulation accounts for uncertain growth rates by sampling these variables randomly from a distribution derived from the information in the table. Another source of uncertainty arises from the relationships among the explanatory variables and net energy for load. These relationships, or coefficients, are obtained directly from the econometric results; however, these coefficients are sample estimates of the true relationship. Consequently, the likely distribution of the “true” coefficients is determined from the estimation Load Forecasting Working Group
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2003–2012 Peak Demand and Energy Projection Bandwidths results. The simulation treats uncertainty in the relationship between energy and demand by sampling load factor randomly from a distribution derived from historical variations in this variable. For each forecast year, the mean of this distribution was taken to be the load factor implicit in the energy and peak demand projections for that year. These methods allow the bandwidth analysis to explicitly incorporate the effects of abnormal weather on peak demand. The advent of deregulation, an unusually volatile economy with extended periods of high and low growth and atypical weather patterns in recent years have led to increasingly greater levels of forecast uncertainty. To statistically address the greater uncertainty stemming from these events, the probability distributions for the key variables driving electricity demand in the United States have correspondingly widened during this period. The bandwidths around the NERC aggregated projections of long-term energy and peak demand forecasts explicitly reflect the combined uncertainty from these contingencies.
Load Forecasting Working Group
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2003–2012 Peak Demand and Energy Projection Bandwidths Figure 1: U.S. Peak Demand 2003–1012 Projection U n it e d S t a t e s P e a k D e m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n Th o u s a n d s o f M W ( S u m m e r )
1000 A c tu a l H ig h B a n d B a s e Pr o je c tio n Low Band
900
2 .5 % / yr
2 .0 % / yr
800 1.6 % / yr
700
600
500 1990
1995
2000
2005
2010
Figure 2: U.S. Net Energy for Load 2003–1012 Projection Un it e d S t a t e s Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n Millio n s o f MW h
5300 A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
4800
2 .3 %/ yr
1.8 %/ yr
4300
1.4 %/ yr
3800
3300
2800 1990
Load Forecasting Working Group
1995
2000
2005
2010
5
2003–2012 Peak Demand and Energy Projection Bandwidths Table 1: U.S. Summer Peak Demand 2003–2012 Projection Bandwidth* (Gigawatts) % NERC % Difference Difference Projection Difference -37 -5.1 720 5.3 -42 -5.7 737 5.7 -45 -6.0 752 6.2 -48 -6.3 767 6.9 -52 -6.6 782 7.5 -55 -6.9 797 8.0 -59 -7.2 813 8.5 -66 -7.9 832 8.6 -70 -8.2 848 9.0 -74 -8.5 863 9.4 Average Annual Growth Rate 2003-2012 1.6% 2.0% * Difference and percentage based on data prior to rounding. Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 683 695 707 718 730 742 754 766 778 790
Difference 38 42 47 53 58 64 69 71 76 81
90% High Bound 757 778 799 820 841 861 882 903 924 944 2.5%
Table 2: U.S. Annual Net Energy for Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours) % NERC % Difference Difference Projection Difference -169 -4.4 3,815 4.6 -196 -5.0 3,894 5.0 -200 -5.1 3,950 6.1 -223 -5.6 4,025 6.6 -245 -6.0 4,100 7.1 -268 -6.4 4,174 7.5 -290 -6.8 4,248 8.0 -319 -7.4 4,330 8.3 -344 -7.8 4,406 8.7 -373 -8.3 4,487 8.9 Average Annual Growth Rate 2003–2012 1.4% 1.8% * Difference and percentage based on data prior to rounding. Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 3,646 3,698 3,750 3,802 3,854 3,906 3,958 4,010 4,062 4,114
Load Forecasting Working Group
Difference 175 195 239 263 289 315 340 358 382 401
90% High Bound 3,989 4,089 4,189 4,289 4,389 4,488 4,588 4,688 4,788 4,888 2.3%
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2003–2012 Peak Demand and Energy Projection Bandwidths Figure 3: Canada Peak Demand 2003–1012 Projection
C a n a d a P e a k De m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n Th o u s a n d s o f MW ( S u mme r )
130 A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
120
2 .6 %/ yr
110 1.1%/ yr
100 90 80
-0 .6 %/ yr
70 1990
1995
2000
2005
2010
Figure 4: Canada Net Energy for Load 2003–2012 Projection C a n a d a Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Millio n s o f MW h 800
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
700
2 .8 %/ yr
1.3 %/ yr
600
500 -0 .4 %/ yr
400 1990
Load Forecasting Working Group
1995
2000
2005
2010
7
2003–2012 Peak Demand and Energy Projection Bandwidths Table 3: Canada Winter Peak Demand 2003–2004 & 2012–2013 Projection Bandwidth* (Gigawatts)
Year 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13
10% Low Bound 80.7 80.2 79.7 79.3 78.8 78.3 77.9 77.4 76.9 76.5 -0.6
Difference -9 -10 -12 -14 -15 -16 -18 -19 -21 -22
% Difference -9.7 -11.2 -13.0 -14.6 -15.9 -17.4 -18.6 -19.8 -21.0 -22.3
NERC Projection 89.3 90.3 91.7 92.8 93.7 94.8 95.6 96.6 97.4 98.4
% Difference 10.8 12.8 14.2 15.9 17.7 19.5 21.4 23.2 25.0 26.7
Difference 10 12 13 15 17 18 20 22 24 26
Average Annual Growth Rate 2003/04−2012/13 1.1%
90% High Bound 99.0 101.8 104.7 107.5 110.4 113.2 116.1 118.9 121.8 124.6 2.6%
* Difference and percentage based on data prior to rounding. Table 4: Canadian Annual Net Energy for Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours) % NERC % Difference Difference Projection Difference -46 -8.9 522 9.7 -55 -10.5 529 11.6 -63 -11.9 535 13.7 -74 -13.7 545 15.1 -83 -15.0 551 17.0 -93 -16.6 560 18.5 -99 -17.6 564 20.8 -107 -18.8 571 22.6 -115 -20.0 577 24.4 -125 -21.4 585 25.9 Average Annual Growth Rate 2003-2012 -0.4% 1.3% * Difference and percentage based on data prior to rounding. Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 475 474 472 470 468 467 465 463 462 460
Load Forecasting Working Group
Difference 51 61 73 82 94 104 117 129 141 151
90% High Bound 572 590 609 627 645 663 681 700 718 736 2.8%
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2003–2012 Peak Demand and Energy Projection Bandwidths
Figure 5: Eastern Interconnection Peak Demand 2003–2012 Projection Ea s t e r n In t e r c o n n e c t io n P e a k De m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Th o u s a n d s o f MW ( S u mme r ) 800 2 .5 %/ yr
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
700
1.9 %/ yr
600
1.4 %/ yr
500
400 1990
1995
2000
2005
2010
Figure 6: Eastern Interconnection Net Energy for Load 2003–2012 Projection Ea s t e r n In t e r c o n n e c t io n Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Millio n s o f MW h 2 .2 %/ yr
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
3900
1.6 %/ yr
3400 1.0 %/ yr
2900
2400 1990
Load Forecasting Working Group
1995
2000
2005
2010
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2003–2012 Peak Demand and Energy Projection Bandwidths Table 5: Eastern Interconnection Summer Peak Demand 2003–2012 Projection Bandwidth* (Gigawatts)
Year
10% Low Bound
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
562.8 570.0 578.6 586.3 595.6 604.1 612.2 621.1 629.6 638.3
% Difference Difference -33.9 -38.6 -42.3 -46.3 -49.3 -53.1 -56.9 -63.2 -67.2 -70.4
-5.7 -6.3 -6.8 -7.3 -7.7 -8.1 -8.5 -9.2 -9.6 -9.9
NERC Projection 596.7 608.6 620.9 632.6 644.9 657.2 669.1 684.3 696.8 708.7
90% High Bound
% Difference Difference 5.8 6.4 7.2 7.9 8.8 9.3 9.9 10.1 10.7 11.2
34.7 38.9 44.5 50.2 56.5 61.1 66.3 69.2 74.5 79.5
631.4 647.5 665.4 682.8 701.4 718.3 735.4 753.5 771.3 788.2
Average Annual Growth Rate 2003-2012 1.4%
1.9%
2.5%
Table 6: Eastern Interconnection Annual Net Energy For Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours)
Year
10% Low Bound
Difference
% Difference
NERC Projection
% Projection
Difference
90% High Bound
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
3,056.2 3,094.4 3,122.0 3,153.6 3,187.0 3,223.2 3,256.8 3,287.9 3,321.8 3,354.4
-162.2 -188.4 -196.8 -261.2 -245.5 -269.2 -289.7 -318.2 -340.8 -369.3
-5.0 -5.7 -5.9 -7.8 -7.2 -7.7 -8.2 -8.8 -9.3 -9.9
3,218.4 3,282.8 3,318.8 3,347.8 3,432.5 3,492.4 3,546.5 3,606.1 3,662.6 3,723.7
5.2 5.9 7.1 7.9 8.3 8.9 9.6 10.0 10.6 11.0
168.2 192.2 234.2 264.2 285.7 310.9 340.4 362.0 388.3 409.3
3,386.6 3,475.0 3,553.0 3,612.0 3,718.2 3,803.3 3,886.9 3,968.1 4,050.9 4,133.0
Average Annual Growth Rate 2003–2012 1.0%
1.6%
2.2%
*Difference and percentage based on data prior to rounding.
Load Forecasting Working Group
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2003–2012 Peak Demand and Energy Projection Bandwidths
Figure 7: Western Interconnection Peak Demand 2003–2012 Projection W e s t e r n In t e r c o n n e c t io n P e a k De m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Th o u s a n d s o f MW ( S u mme r ) 180 2 .6 %/ yr
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
160
2 .1%/ yr
140
1.6 %/ yr
120
100 1990
1995
2000
2005
2010
Figure 8: Western Interconnection Net Energy for Load 2003–2012 Projection W e s t e r n In t e r c o n n e c t io n Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Millio n s o f MW h 1150
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
1050
2 .5 %/ yr
2 .0 %/ yr
950 850
1.4 %/ yr
750 650 550 1990
Load Forecasting Working Group
1995
2000
2005
2010
11
2003–2012 Peak Demand and Energy Projection Bandwidths Table 7: Western Interconnection Summer Peak Demand 2003–2012 Projection Bandwidth* (Gigawatts) Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 129.2 133.1 135.2 136.9 139.0 140.8 142.7 144.4 146.6 148.7 1.6%
% NERC % Difference Difference Projection Difference -7.4 -5.4 136.6 5.3 -8.6 -6.1 141.7 6.1 -9.4 -6.5 144.6 6.8 -10.3 -7.0 147.2 7.6 -11.0 -7.3 150.0 8.4 -11.8 -7.7 152.6 8.9 -12.7 -8.1 155.4 9.5 -14.0 -8.9 158.4 9.7 -14.9 -9.3 161.5 10.3 -15.7 -9.5 164.4 10.8 Average Annual Growth Rate 2003–2012 2.1%
90% High Bound 144.2 150.3 154.5 158.4 162.6 166.2 170.2 173.8 178.1 182.1
Difference 7.6 8.6 9.9 11.2 12.6 13.6 14.8 15.4 16.6 17.7
2.6%
Table 8: Western Interconnection Annual Net Energy for Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours)
Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 801.7 811.3 828.2 840.4 850.7 859.4 872.0 884.9 896.6 908.5 1.4%
% NERC % Difference Difference Projection Difference -39.5 -4.7 841.2 4.9 -45.9 -5.4 857.2 5.5 -48.5 -5.5 876.7 6.6 -55.2 -6.2 895.6 7.2 -61.0 -6.7 911.7 7.8 -6.9 -7.2 926.3 8.3 -72.4 -7.7 944.4 9.0 -80.0 -8.3 964.9 9.4 -85.9 -8.7 982.5 10.0 -93.5 -9.3 1,002.0 10.3 Average Annual Growth Rate 2003-2012 2.0%
Difference 41.0 46.8 57.8 64.1 71.0 77.3 85.0 91.0 97.9 103.7
90% High Bound 882.2 904.0 934.5 959.7 982.7 1,003.6 1,029.4 1,055.9 1,080.4 1,105.7 2.5%
*Difference and percentage based on data prior to rounding.
Load Forecasting Working Group
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2003–2012 Peak Demand and Energy Projection Bandwidths Figure 9: ERCOT Interconnection Peak Demand 2003–1012 Projection ERC O T In t e r c o n n e c t io n P e a k De m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n Th o u s a n d s o f MW ( S u mme r )
85 A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
75
3 .1%/ yr
2 .5 %/ yr
65 2 .0 %/ yr
55
45
35 1990
1995
2000
2005
2010
Figure 10: ERCOT Interconnection Net Energy for Load 2003–2012 Projection ERC O T In t e r c o n n e c t io n Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Millio n s o f MW h 400 3 .3 %/ yr
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
350
2 .7 %/ yr
300
2 .1%/ yr
250
200 1990
Load Forecasting Working Group
1995
2000
2005
2010
13
2003–2012 Peak Demand and Energy Projection Bandwidths Table 9: ERCOT Interconnection Summer Peak Demand 2003–2012 Projection Bandwidth* (Gigawatts) Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 54.3 55.3 56.4 57.5 58.7 59.9 61.1 62.1 63.4 64.8 2.0%
% NERC % Difference Difference Projection Difference -3.3 -5.7 57.6 5.9 -3.8 -6.4 59.1 6.5 -4.2 -6.9 60.6 7.2 -4.6 -7.4 62.1 8.0 -4.9 -7.7 63.6 8.8 -5.3 -8.1 65.2 9.4 -5.7 -8.6 66.8 10.0 -6.4 -9.3 68.5 10.2 -6.8 -9.7 70.2 10.8 -7.2 -10.0 72.0 11.3 Average Annual Growth Rate 2003–2012 2.5%
Difference 3.4 3.8 4.4 5.0 5.6 6.1 6.7 7.0 7.6 8.2
90% High Bound 61.0 62.9 65.0 67.1 69.2 71.3 73.5 75.5 77.8 80.2 3.1%
Table 10: ERCOT Interconnection Annual Net Energy for Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours)
Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 272.4 277.0 283.4 289.9 296.8 303.1 308.6 314.6 321.5 327.7
Difference -14.9 -17.4 -18.4 -21.0 -23.5 -26.0 -28.2 -31.3 -33.9 -37.1
% Difference -5.2 -5.9 -6.1 -6.8 -7.3 -7.9 -8.4 -9.0 -9.5 -10.2
NERC Projection 287.3 294.4 301.8 310.9 320.3 329.1 336.8 345.9 355.4 365.0
% Difference 5.4 6.0 7.3 7.9 8.5 9.1 9.8 10.3 10.9 11.3
Average Annual Growth Rate 2003–2012 2.1% 2.7% *Difference and percentage based on data prior to rounding.
Load Forecasting Working Group
Difference 15.4 17.7 21.9 24.4 27.4 30.1 33.1 35.6 38.6 41.1
90% High Bound 302.7 312.1 323.7 335.3 347.7 359.2 369.9 381.5 394.0 406.1 3.3%
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2003–2012 Peak Demand and Energy Projection Bandwidths Figure 11: Sensitivity Bands for Predictor Variables Real Annual Percentage Growth Rate Projections 2003–2012 10% Low Bound
50% Base Case
90% Upper Bound
Gross Domestic Product ($1996 for U.S. and $1992 for Canada) United States
2.1
2.9
3.7
Canada
1.8
2.8
3.8
Price of Electricity ($1996 for U.S. and $1993 for Canada)1 United Stated
-1.7
-0.1
2.4
Canada
-1.7
-0.1
2.0
Price of Natural Gas ($1996)2 United States
-2.0
0.7
3.0
Canada
n/a
n/a
n/a
1
Electric utility industry real average price of electricity to total ultimate customers.
2
Gas utility industry real average price of natural gas for residential customers.
Load Forecasting Working Group
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2003–2012 Peak Demand and Energy Projection Bandwidths
LOAD FORECASTING WORKING GROUP
John L. Harris (Chairman-SERC) Enterprise Risk Management Progress Energy Aldo Colandrea (ECAR) Director - Corporate Forecasting The Detroit Edison Company Art Ekholm (ERCOT) Manager, Marketing Services TXU Electric
George McClure (MAPP-Canada) Statistical Officer Manitoba Hydro Yves Nadeau (NPCC-Canada) Manager, Load and Revenue Forecasting
Hydro-Québec Leo Green (FRCC) System Planning Department Florida Power & Light Company
John W. Pade (NPCC-U.S.) Manager of Load Forecasting New York Independent System Operator
John M. Reynolds (MAAC) Sr. Engineer, Capacity Adequacy Planning Department PJM Interconnection, LLC.
Robert Shields (SPP) Senior Rates Analyst Arkansas Electric Cooperative Corporation
Joel Gaughan (MAIN) Senior Economist Wisconsin Electric Power
J. Chris Reece (WSCC-U.S.) Consulting Engineer Puget Sound Energy
Scott Loseke (MAPP-U.S.) Energy Market Planning Nebraska Public Power District
Brian Nolan (NERC Staff Coordinator)
Gene Gorzelnik Craig Kellas (MAPP-Canada) Manager, Market Forecast Manitoba Hydro
Load Forecasting Working Group
(Consultant)
16
Prepared by Load Forecasting Working Group
Approved by NERC Planning Committee July 15, 2003
North American Electric Reliability Council
2003–2012 Peak Demand and Energy Projection Bandwidths Table of Contents INTRODUCTION ........................................................................................................................................ 1 RESULTS ..................................................................................................................................................... 1 METHODOLOGY ....................................................................................................................................... 3 LOAD FORECASTING WORKING GROUP .......................................................................................... 16
Table 1: U.S. Summer Peak Demand ............................................................................................ 6 Table 2: U.S. Annual Net Energy for Load ................................................................................... 6 Table 3: Canada Winter Peak Demand.......................................................................................... 8 Table 4: Canadian Annual Net Energy for Load ........................................................................... 8 Table 5: Eastern Interconnection Summer Peak Demand ........................................................... 10 Table 6: Eastern Interconnection Annual Net Energy For Load ................................................. 10 Table 7: Western Interconnection Summer Peak Demand .......................................................... 12 Table 8: Western Interconnection Annual Net Energy For Load................................................ 12 Table 9: ERCOT Interconnection Summer Peak Demand .......................................................... 14 Table 10: ERCOT Interconnection Annual Net Energy For Load .............................................. 14 Figure 1: U.S. Peak Demand 2003–1012 Projection ..................................................................... 5 Figure 2: U.S. Net Energy for Load 2003–1012 Projection .......................................................... 5 Figure 4: Canada Net Energy for Load 2003–2012 Projection ..................................................... 7 Figure 5: Eastern Interconnection Peak Demand 2003–2012 Projection ...................................... 9 Figure 6: Eastern Interconnection Net Energy for Load 2003–2012 Projection ........................... 9 Figure 7: Western Interconnection Peak Demand 2003–2012 Projection................................... 11 Figure 8: Western Interconnection Net Energy for Load 2003–2012 Projection........................ 11 Figure 9: ERCOT Interconnection Peak Demand 2003–1012 Projection................................... 13 Figure 10: ERCOT Interconnection Net Energy for Load 2003–2012 Projection ...................... 13 Figure 11: Sensitivity Bands for Predictor Variables .................................................................. 15
i
2003–2012 Peak Demand and Energy Projection Bandwidths
INTRODUCTION The North American Electric Reliability Council (NERC) Load Forecasting Working Group (LFWG) is responsible for developing bandwidths around the aggregated United States and Canadian annual forecasts of peak demand and annual net energy for load. In addition, the group is charged with developing bandwidths around the three Interconnections 1) Eastern, 2) ERCOT, and 3) Western. This report discusses the methodology and resulting bandwidths around the 2003-2012 NERC aggregated projections. Forecasts cannot precisely predict the future. Instead, many forecasts report probabilities of a range of possible outcomes. Each demand projection, for example, is assumed to represent the expected midpoint of possible future outcomes. This means that a future year’s actual demand may deviate from the midpoint projections due to the inherent variability of the key factors that drive electrical usage. In the case of the NERC aggregated projections, there is a long-run 50% probability that actual demand will be higher than the forecast midpoint and a long-run 50% probability that it will be lower. For planning and analytical purposes, it is useful to have an estimate not only of the expected midpoint of possible future outcomes, but also of the distribution of probabilities around the projection. Accordingly, the LFWG develops upper and lower 80% confidence bands around the NERC-aggregated projections. This means that there is a long-run 80% probability that future demand will occur within these bands. Concurrently, there is a 10% chance that future demand could be less than the lower band and a 10% chance that future demand could be higher than the upper band. This report is organized in three sections. The first section presents the bandwidth results, the second section describes the methodology used to develop the bandwidths and the final section shows the results in chart and table format. RESULTS The graphical and numerical results of the bandwidth analyses are included in the following figures and tables: Figure 1/Table 1 — United States Summer Peak Demand Figure 2/Table 2 — United States Annual Net Energy for Load Figure 3/Table 3 — Canada Winter Peak Demand Figure 4/Table 4 — Canada Annual Net Energy for Load Figure 5/Table 5 — Eastern Interconnection Summer Peak Demand Figure 6/Table 6 — Eastern Interconnection Annual Net Energy for Load Figure 7/Table 7 — Western Interconnection Summer Peak Demand Figure 8/Table 8 — Western Interconnection Annual Net Energy for Load Figure 9/Table 9 — ERCOT Interconnection Summer Peak Demand
Figure 10/Table 10 — ERCOT Interconnection Annual Net Energy for Load Table 11 — Sensitivity Bands for Predictor Variables
Load Forecasting Working Group
1
2003–2012 Peak Demand and Energy Projection Bandwidths For the United States, the aggregated projected demand rises from 720 GW in 2003 to 863 GW in 2012, which represents an average annual growth rate of 2.0%. There is a 10% chance that the 2012 peak demand will be 944 GW or higher. This would represent an average annual growth of at least 2.5% over the 2003–2012 period. Correspondingly, there is a 10% chance that the 2012 peak demand will be 790 GW or lower, which would represent an average annual growth of no more than 1.6%. The width of the 80% confidence interval in 2012 is 154 GW, of which 81 GW are above the NERC-aggregate forecast and 73 GW are below. The percent differences from the base projection for the upper and lower bandwidths in 2012 are 9.4% and – 8.5%, respectively. The NERC-aggregated projections of Canadian winter peak demand rise from 89.3 GW in 2003/04 to 98.4 GW in 2012/13, which represents an average annual growth rate of 1.1%. There is a 10% chance that the 2012/13 demand will be 124.6 GW or higher. This would represent an average annual growth rate of at least 2.6% over the 2003/04–2012/13 period. A 10% chance also exists that the 2012/13 peak demand will be 76.5 GW or lower. This would represent an average annual growth of no more than –0.6%. The width of the 80% confidence interval in 2012/13 is 48 GW, of which 26 GW are above the NERC forecast and 22 GW are below. The percent differences from the base projection for the upper and lower bandwidths in 2012/13 are 26.6% and –22.2%, respectively. The U.S. net energy for load aggregated forecast is projected to increase at an average annual growth rate of 1.8% from 2003 to 2012. The 80% bandwidths represent average annual growth rates for the high and low bands of 2.3% and 1.4% per year, respectively. In Canada, net energy for load is projected to grow at an average annual rate of 1.3%. The upper and lower bands for energy have average annual growth rates of 2.8% and -0.4%, respectively, over the forecast period. For the Eastern Interconnection, which is the largest of the three Interconnections, peak demand is projected to rise from 597 GW in 2003 to 709 GW in 2012, which represents an annual average growth rate of 1.9%. There is a 10% chance that the 2012 demand will be 788 GW, which would represent a 2.5% annual growth rate. On the low side, there is a 10% chance that the 2012 peak will be 638 GW, which would represent a 1.4% annual rate of growth. The Western Interconnection peak demand is projected to increase from 137 GW in 2003 to 164 GW in 2012, a 2.1% annual average growth rate. The 80% confidence intervals for the Western Interconnection represent average annual growth rates for the high and low bands of 2.6% and 1.6% per year, respectively. For the ERCOT Interconnection, peak demand is projected to rise from 58 GW in 2003 to 72 GW in 2012, which represents a 2.5% annual growth rate. The average annual growth rates for the 80% high and low confidence intervals are 3.1% and 2.0% per year, respectively.
Load Forecasting Working Group
2
2003–2012 Peak Demand and Energy Projection Bandwidths The Eastern Interconnection’s aggregated net energy for load projection is expected to increase at an average annual growth rate of 1.6% from 2003 to 2012. The average annual growth rates for the 80% confidence high and low bands are 2.2% and 1.0% per year, respectively. For the Western Interconnection, the upper band for energy, the aggregated energy projection, and the low band for energy have average annual growth rates of 2.5%, 2.0%, and 1.4%, respectively, over the 2003 to 2012 period. Using this same format, ERCOT’s average annual growth rates are 3.3%, 2.7 and 2.1%. METHODOLOGY The principal features of the current methodology include: 1. Econometric models for the United States and Canada represent the NERC-aggregated projection of annual net energy for load as a function of key economic variables, energy prices and weather. An intercept is included in the model to account for other less important determinants of net energy for load. 2. Regression models for the Interconnections represent the projection of net energy for load as a function of NERC total energy usage plus an intercept term that accounts for statistically random determinants of net energy for load.
3. A Monte Carlo simulation model is used to estimate the energy and demand bandwidths. This analysis incorporates explicit uncertainty in the economic, price and weather variables themselves and in the interrelationships among the variables. The simulation for demand also explicitly includes uncertainty in load factor that accounts for the variability in peaking weather conditions. The econometric model for U.S. energy relates net energy for load positively to real (inflation adjusted) U.S. Gross Domestic Product (GDP), real (inflation adjusted) U.S. price of natural gas, population-weighted heating and cooling degree days. The net energy for load is related negatively to the real (inflation adjusted) U.S. price of electricity. The Canadian model is analogous except that cooling degree days are excluded because of their statistical insignificance. The Interconnection model includes an equation for each of the three Interconnections and relates their individual net energy for load to the NERC total energy usage. Monte Carlo simulations are used to enable various sources of forecast uncertainty to be addressed. One source of uncertainty is the future magnitudes of the economic variables. To represent this, a range of possible growth rates is developed around an 80% probability that the actual growth rate will be within that range. A Delphi survey of LFWG members is used to estimate the midpoint and upper and lower growth rates for the relevant variables in the United States model. A statistical time series model is used to determine the variability of economic and price variables in the Canadian model. Table 11 shows the growth rates assumed for the economic variables used in the United States and Canadian simulations. The Monte Carlo simulation accounts for uncertain growth rates by sampling these variables randomly from a distribution derived from the information in the table. Another source of uncertainty arises from the relationships among the explanatory variables and net energy for load. These relationships, or coefficients, are obtained directly from the econometric results; however, these coefficients are sample estimates of the true relationship. Consequently, the likely distribution of the “true” coefficients is determined from the estimation Load Forecasting Working Group
3
2003–2012 Peak Demand and Energy Projection Bandwidths results. The simulation treats uncertainty in the relationship between energy and demand by sampling load factor randomly from a distribution derived from historical variations in this variable. For each forecast year, the mean of this distribution was taken to be the load factor implicit in the energy and peak demand projections for that year. These methods allow the bandwidth analysis to explicitly incorporate the effects of abnormal weather on peak demand. The advent of deregulation, an unusually volatile economy with extended periods of high and low growth and atypical weather patterns in recent years have led to increasingly greater levels of forecast uncertainty. To statistically address the greater uncertainty stemming from these events, the probability distributions for the key variables driving electricity demand in the United States have correspondingly widened during this period. The bandwidths around the NERC aggregated projections of long-term energy and peak demand forecasts explicitly reflect the combined uncertainty from these contingencies.
Load Forecasting Working Group
4
2003–2012 Peak Demand and Energy Projection Bandwidths Figure 1: U.S. Peak Demand 2003–1012 Projection U n it e d S t a t e s P e a k D e m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n Th o u s a n d s o f M W ( S u m m e r )
1000 A c tu a l H ig h B a n d B a s e Pr o je c tio n Low Band
900
2 .5 % / yr
2 .0 % / yr
800 1.6 % / yr
700
600
500 1990
1995
2000
2005
2010
Figure 2: U.S. Net Energy for Load 2003–1012 Projection Un it e d S t a t e s Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n Millio n s o f MW h
5300 A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
4800
2 .3 %/ yr
1.8 %/ yr
4300
1.4 %/ yr
3800
3300
2800 1990
Load Forecasting Working Group
1995
2000
2005
2010
5
2003–2012 Peak Demand and Energy Projection Bandwidths Table 1: U.S. Summer Peak Demand 2003–2012 Projection Bandwidth* (Gigawatts) % NERC % Difference Difference Projection Difference -37 -5.1 720 5.3 -42 -5.7 737 5.7 -45 -6.0 752 6.2 -48 -6.3 767 6.9 -52 -6.6 782 7.5 -55 -6.9 797 8.0 -59 -7.2 813 8.5 -66 -7.9 832 8.6 -70 -8.2 848 9.0 -74 -8.5 863 9.4 Average Annual Growth Rate 2003-2012 1.6% 2.0% * Difference and percentage based on data prior to rounding. Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 683 695 707 718 730 742 754 766 778 790
Difference 38 42 47 53 58 64 69 71 76 81
90% High Bound 757 778 799 820 841 861 882 903 924 944 2.5%
Table 2: U.S. Annual Net Energy for Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours) % NERC % Difference Difference Projection Difference -169 -4.4 3,815 4.6 -196 -5.0 3,894 5.0 -200 -5.1 3,950 6.1 -223 -5.6 4,025 6.6 -245 -6.0 4,100 7.1 -268 -6.4 4,174 7.5 -290 -6.8 4,248 8.0 -319 -7.4 4,330 8.3 -344 -7.8 4,406 8.7 -373 -8.3 4,487 8.9 Average Annual Growth Rate 2003–2012 1.4% 1.8% * Difference and percentage based on data prior to rounding. Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 3,646 3,698 3,750 3,802 3,854 3,906 3,958 4,010 4,062 4,114
Load Forecasting Working Group
Difference 175 195 239 263 289 315 340 358 382 401
90% High Bound 3,989 4,089 4,189 4,289 4,389 4,488 4,588 4,688 4,788 4,888 2.3%
6
2003–2012 Peak Demand and Energy Projection Bandwidths Figure 3: Canada Peak Demand 2003–1012 Projection
C a n a d a P e a k De m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n Th o u s a n d s o f MW ( S u mme r )
130 A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
120
2 .6 %/ yr
110 1.1%/ yr
100 90 80
-0 .6 %/ yr
70 1990
1995
2000
2005
2010
Figure 4: Canada Net Energy for Load 2003–2012 Projection C a n a d a Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Millio n s o f MW h 800
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
700
2 .8 %/ yr
1.3 %/ yr
600
500 -0 .4 %/ yr
400 1990
Load Forecasting Working Group
1995
2000
2005
2010
7
2003–2012 Peak Demand and Energy Projection Bandwidths Table 3: Canada Winter Peak Demand 2003–2004 & 2012–2013 Projection Bandwidth* (Gigawatts)
Year 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13
10% Low Bound 80.7 80.2 79.7 79.3 78.8 78.3 77.9 77.4 76.9 76.5 -0.6
Difference -9 -10 -12 -14 -15 -16 -18 -19 -21 -22
% Difference -9.7 -11.2 -13.0 -14.6 -15.9 -17.4 -18.6 -19.8 -21.0 -22.3
NERC Projection 89.3 90.3 91.7 92.8 93.7 94.8 95.6 96.6 97.4 98.4
% Difference 10.8 12.8 14.2 15.9 17.7 19.5 21.4 23.2 25.0 26.7
Difference 10 12 13 15 17 18 20 22 24 26
Average Annual Growth Rate 2003/04−2012/13 1.1%
90% High Bound 99.0 101.8 104.7 107.5 110.4 113.2 116.1 118.9 121.8 124.6 2.6%
* Difference and percentage based on data prior to rounding. Table 4: Canadian Annual Net Energy for Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours) % NERC % Difference Difference Projection Difference -46 -8.9 522 9.7 -55 -10.5 529 11.6 -63 -11.9 535 13.7 -74 -13.7 545 15.1 -83 -15.0 551 17.0 -93 -16.6 560 18.5 -99 -17.6 564 20.8 -107 -18.8 571 22.6 -115 -20.0 577 24.4 -125 -21.4 585 25.9 Average Annual Growth Rate 2003-2012 -0.4% 1.3% * Difference and percentage based on data prior to rounding. Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 475 474 472 470 468 467 465 463 462 460
Load Forecasting Working Group
Difference 51 61 73 82 94 104 117 129 141 151
90% High Bound 572 590 609 627 645 663 681 700 718 736 2.8%
8
2003–2012 Peak Demand and Energy Projection Bandwidths
Figure 5: Eastern Interconnection Peak Demand 2003–2012 Projection Ea s t e r n In t e r c o n n e c t io n P e a k De m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Th o u s a n d s o f MW ( S u mme r ) 800 2 .5 %/ yr
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
700
1.9 %/ yr
600
1.4 %/ yr
500
400 1990
1995
2000
2005
2010
Figure 6: Eastern Interconnection Net Energy for Load 2003–2012 Projection Ea s t e r n In t e r c o n n e c t io n Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Millio n s o f MW h 2 .2 %/ yr
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
3900
1.6 %/ yr
3400 1.0 %/ yr
2900
2400 1990
Load Forecasting Working Group
1995
2000
2005
2010
9
2003–2012 Peak Demand and Energy Projection Bandwidths Table 5: Eastern Interconnection Summer Peak Demand 2003–2012 Projection Bandwidth* (Gigawatts)
Year
10% Low Bound
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
562.8 570.0 578.6 586.3 595.6 604.1 612.2 621.1 629.6 638.3
% Difference Difference -33.9 -38.6 -42.3 -46.3 -49.3 -53.1 -56.9 -63.2 -67.2 -70.4
-5.7 -6.3 -6.8 -7.3 -7.7 -8.1 -8.5 -9.2 -9.6 -9.9
NERC Projection 596.7 608.6 620.9 632.6 644.9 657.2 669.1 684.3 696.8 708.7
90% High Bound
% Difference Difference 5.8 6.4 7.2 7.9 8.8 9.3 9.9 10.1 10.7 11.2
34.7 38.9 44.5 50.2 56.5 61.1 66.3 69.2 74.5 79.5
631.4 647.5 665.4 682.8 701.4 718.3 735.4 753.5 771.3 788.2
Average Annual Growth Rate 2003-2012 1.4%
1.9%
2.5%
Table 6: Eastern Interconnection Annual Net Energy For Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours)
Year
10% Low Bound
Difference
% Difference
NERC Projection
% Projection
Difference
90% High Bound
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
3,056.2 3,094.4 3,122.0 3,153.6 3,187.0 3,223.2 3,256.8 3,287.9 3,321.8 3,354.4
-162.2 -188.4 -196.8 -261.2 -245.5 -269.2 -289.7 -318.2 -340.8 -369.3
-5.0 -5.7 -5.9 -7.8 -7.2 -7.7 -8.2 -8.8 -9.3 -9.9
3,218.4 3,282.8 3,318.8 3,347.8 3,432.5 3,492.4 3,546.5 3,606.1 3,662.6 3,723.7
5.2 5.9 7.1 7.9 8.3 8.9 9.6 10.0 10.6 11.0
168.2 192.2 234.2 264.2 285.7 310.9 340.4 362.0 388.3 409.3
3,386.6 3,475.0 3,553.0 3,612.0 3,718.2 3,803.3 3,886.9 3,968.1 4,050.9 4,133.0
Average Annual Growth Rate 2003–2012 1.0%
1.6%
2.2%
*Difference and percentage based on data prior to rounding.
Load Forecasting Working Group
10
2003–2012 Peak Demand and Energy Projection Bandwidths
Figure 7: Western Interconnection Peak Demand 2003–2012 Projection W e s t e r n In t e r c o n n e c t io n P e a k De m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Th o u s a n d s o f MW ( S u mme r ) 180 2 .6 %/ yr
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
160
2 .1%/ yr
140
1.6 %/ yr
120
100 1990
1995
2000
2005
2010
Figure 8: Western Interconnection Net Energy for Load 2003–2012 Projection W e s t e r n In t e r c o n n e c t io n Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Millio n s o f MW h 1150
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
1050
2 .5 %/ yr
2 .0 %/ yr
950 850
1.4 %/ yr
750 650 550 1990
Load Forecasting Working Group
1995
2000
2005
2010
11
2003–2012 Peak Demand and Energy Projection Bandwidths Table 7: Western Interconnection Summer Peak Demand 2003–2012 Projection Bandwidth* (Gigawatts) Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 129.2 133.1 135.2 136.9 139.0 140.8 142.7 144.4 146.6 148.7 1.6%
% NERC % Difference Difference Projection Difference -7.4 -5.4 136.6 5.3 -8.6 -6.1 141.7 6.1 -9.4 -6.5 144.6 6.8 -10.3 -7.0 147.2 7.6 -11.0 -7.3 150.0 8.4 -11.8 -7.7 152.6 8.9 -12.7 -8.1 155.4 9.5 -14.0 -8.9 158.4 9.7 -14.9 -9.3 161.5 10.3 -15.7 -9.5 164.4 10.8 Average Annual Growth Rate 2003–2012 2.1%
90% High Bound 144.2 150.3 154.5 158.4 162.6 166.2 170.2 173.8 178.1 182.1
Difference 7.6 8.6 9.9 11.2 12.6 13.6 14.8 15.4 16.6 17.7
2.6%
Table 8: Western Interconnection Annual Net Energy for Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours)
Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 801.7 811.3 828.2 840.4 850.7 859.4 872.0 884.9 896.6 908.5 1.4%
% NERC % Difference Difference Projection Difference -39.5 -4.7 841.2 4.9 -45.9 -5.4 857.2 5.5 -48.5 -5.5 876.7 6.6 -55.2 -6.2 895.6 7.2 -61.0 -6.7 911.7 7.8 -6.9 -7.2 926.3 8.3 -72.4 -7.7 944.4 9.0 -80.0 -8.3 964.9 9.4 -85.9 -8.7 982.5 10.0 -93.5 -9.3 1,002.0 10.3 Average Annual Growth Rate 2003-2012 2.0%
Difference 41.0 46.8 57.8 64.1 71.0 77.3 85.0 91.0 97.9 103.7
90% High Bound 882.2 904.0 934.5 959.7 982.7 1,003.6 1,029.4 1,055.9 1,080.4 1,105.7 2.5%
*Difference and percentage based on data prior to rounding.
Load Forecasting Working Group
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2003–2012 Peak Demand and Energy Projection Bandwidths Figure 9: ERCOT Interconnection Peak Demand 2003–1012 Projection ERC O T In t e r c o n n e c t io n P e a k De m a n d 2 0 0 3 - 2 0 1 2 P r o je c t io n Th o u s a n d s o f MW ( S u mme r )
85 A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
75
3 .1%/ yr
2 .5 %/ yr
65 2 .0 %/ yr
55
45
35 1990
1995
2000
2005
2010
Figure 10: ERCOT Interconnection Net Energy for Load 2003–2012 Projection ERC O T In t e r c o n n e c t io n Ne t En e r g y f o r L o a d 2 0 0 3 - 2 0 1 2 P r o je c t io n
Millio n s o f MW h 400 3 .3 %/ yr
A c tu a l Hig h B a n d B a s e Pr o je c tio n Low Band
350
2 .7 %/ yr
300
2 .1%/ yr
250
200 1990
Load Forecasting Working Group
1995
2000
2005
2010
13
2003–2012 Peak Demand and Energy Projection Bandwidths Table 9: ERCOT Interconnection Summer Peak Demand 2003–2012 Projection Bandwidth* (Gigawatts) Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 54.3 55.3 56.4 57.5 58.7 59.9 61.1 62.1 63.4 64.8 2.0%
% NERC % Difference Difference Projection Difference -3.3 -5.7 57.6 5.9 -3.8 -6.4 59.1 6.5 -4.2 -6.9 60.6 7.2 -4.6 -7.4 62.1 8.0 -4.9 -7.7 63.6 8.8 -5.3 -8.1 65.2 9.4 -5.7 -8.6 66.8 10.0 -6.4 -9.3 68.5 10.2 -6.8 -9.7 70.2 10.8 -7.2 -10.0 72.0 11.3 Average Annual Growth Rate 2003–2012 2.5%
Difference 3.4 3.8 4.4 5.0 5.6 6.1 6.7 7.0 7.6 8.2
90% High Bound 61.0 62.9 65.0 67.1 69.2 71.3 73.5 75.5 77.8 80.2 3.1%
Table 10: ERCOT Interconnection Annual Net Energy for Load 2003–2012 Projection Bandwidth* (Thousands of Gigawatthours)
Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
10% Low Bound 272.4 277.0 283.4 289.9 296.8 303.1 308.6 314.6 321.5 327.7
Difference -14.9 -17.4 -18.4 -21.0 -23.5 -26.0 -28.2 -31.3 -33.9 -37.1
% Difference -5.2 -5.9 -6.1 -6.8 -7.3 -7.9 -8.4 -9.0 -9.5 -10.2
NERC Projection 287.3 294.4 301.8 310.9 320.3 329.1 336.8 345.9 355.4 365.0
% Difference 5.4 6.0 7.3 7.9 8.5 9.1 9.8 10.3 10.9 11.3
Average Annual Growth Rate 2003–2012 2.1% 2.7% *Difference and percentage based on data prior to rounding.
Load Forecasting Working Group
Difference 15.4 17.7 21.9 24.4 27.4 30.1 33.1 35.6 38.6 41.1
90% High Bound 302.7 312.1 323.7 335.3 347.7 359.2 369.9 381.5 394.0 406.1 3.3%
14
2003–2012 Peak Demand and Energy Projection Bandwidths Figure 11: Sensitivity Bands for Predictor Variables Real Annual Percentage Growth Rate Projections 2003–2012 10% Low Bound
50% Base Case
90% Upper Bound
Gross Domestic Product ($1996 for U.S. and $1992 for Canada) United States
2.1
2.9
3.7
Canada
1.8
2.8
3.8
Price of Electricity ($1996 for U.S. and $1993 for Canada)1 United Stated
-1.7
-0.1
2.4
Canada
-1.7
-0.1
2.0
Price of Natural Gas ($1996)2 United States
-2.0
0.7
3.0
Canada
n/a
n/a
n/a
1
Electric utility industry real average price of electricity to total ultimate customers.
2
Gas utility industry real average price of natural gas for residential customers.
Load Forecasting Working Group
15
2003–2012 Peak Demand and Energy Projection Bandwidths
LOAD FORECASTING WORKING GROUP
John L. Harris (Chairman-SERC) Enterprise Risk Management Progress Energy Aldo Colandrea (ECAR) Director - Corporate Forecasting The Detroit Edison Company Art Ekholm (ERCOT) Manager, Marketing Services TXU Electric
George McClure (MAPP-Canada) Statistical Officer Manitoba Hydro Yves Nadeau (NPCC-Canada) Manager, Load and Revenue Forecasting
Hydro-Québec Leo Green (FRCC) System Planning Department Florida Power & Light Company
John W. Pade (NPCC-U.S.) Manager of Load Forecasting New York Independent System Operator
John M. Reynolds (MAAC) Sr. Engineer, Capacity Adequacy Planning Department PJM Interconnection, LLC.
Robert Shields (SPP) Senior Rates Analyst Arkansas Electric Cooperative Corporation
Joel Gaughan (MAIN) Senior Economist Wisconsin Electric Power
J. Chris Reece (WSCC-U.S.) Consulting Engineer Puget Sound Energy
Scott Loseke (MAPP-U.S.) Energy Market Planning Nebraska Public Power District
Brian Nolan (NERC Staff Coordinator)
Gene Gorzelnik Craig Kellas (MAPP-Canada) Manager, Market Forecast Manitoba Hydro
Load Forecasting Working Group
(Consultant)
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