EIA411 May 1, A Report to the Office of Energy Emergency Operations Department of Energy Under EIA-411

Transcription

1 EIA411 May 1, 2006 A Report to the Office of Energy Emergency Operations Department of Energy Under EIA-411 All questions concerning this data should be directed to: Jason Speer Southwest Power Pool 415 N. McKinley, #140 Plaza West Little Rock, AR (501) jspeer@spp.org

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3 Table of Contents Introduction Introduction Identification of Reporting Utilities Definitions Item 1 Projected Energy & Peak Demand for the First Ten Years & Actual Data for the Previous Year Item 2 Item 2.1 Item 2.2 Item 2.3 Item 2.4 Existing and Projected Generating Units Utility Data Capacity for Existing Generators in Reporting Year Projected Generating Capacity Installations, Changes, and Removals Jointly Owned Generators Item 3 Item 3.1 Item 3.2 Projected Capacity & Demand for Ten Years Summer Winter Item 4 Projected Capacity Purchases and Sales Item 5 Bulk Electric Transmission System Map Item 6 Item 7 Proposed Bulk Electric Transmission Line Additions Annual Data on Transmission Line Outages for EHV Lines 3

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5 INTRODUCTION 5

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7 INTRODUCTION The following table shows a five-year comparison of the Summer Peak Demand, the Winter Peak Demand and the Annual Energy for Southwest Power Pool. Section 1 Table 1 Historical Demands Summer Demand (MW) Winter Demand (MW) Annual Energy (GWh) 2001 (4-1-02) (4-1-03) (4-1-04) (4-1-05) (4-1-06) %/Change* 3.9% 1.8% 4.8% * Percentage change from 2004 to 2005 The following table shows the ten-year capacity margin projections for a five-year period. OE Table 2 Present and Historical Capacity Margins OE OE OE OE % % 17.75% % 17.92% 20.39% % 17.24% 18.39% 15.98% % 17.14% 18.11% 15.59% 15.50% % 16.47% 18.02% 14.98% 14.50% % 14.97% 15.70% 14.31% 14.60% % 14.48% 15.47% 12.98% 12.70% % 13.78% 14.53% 12.95% 13.40% % 12.78% 13.45% 13.09% 13.10% % 12.62% 13.52% 13.50% % 12.31% 11.30% % 10.10% % 7

8 IDENTIFICATION OF REPORTING UTILITIES SPP SYSTEMS REPORTING CODES AEP West Public Service Company of Oklahoma Southwestern Electric Power Company Aquila Inc. Missouri Public Service Company WestPlains Energy Arkansas Electric Cooperative Corporation Board of Public Utilities, Kansas City, Kansas Central Louisiana Electric Company City of Clarksdale, Mississippi City of Lafayette, Louisiana City Power & Light, Independence, Missouri City Utilities, Springfield, Missouri Empire District Electric Company Grand River Dam Authority Kansas City Power & Light Company Louisiana Energy & Power Authority Midwest Energy Inc. Northeast Texas Electric Cooperative Oklahoma Gas & Electric Company Oklahoma Municipal Power Authority Public Service Comm. Of Yazoo City Southwestern Power Administration Southwestern Public Service Company Sunflower Electric Power Corp. Western Farmers Electric Cooperative Western Resources, Inc. Kansas Power & Light Company Kansas Gas & Electric Company PSOK SOEP MIPU WEPL AECC KACY CELE CLWL LAFA INDN SPRM EMDE GRRD KCPL LEPA MIDW NTEC OKGE OMPA YAZO SWPA SWPS SUNC WEFA KAPL KAGE 8

9 GENERAL DEFINITIONS These definitions are intended for use in the preparation of a response to Form EIA-411. They are not intended to conflict with or replace definitions used in other reporting forms, glossaries, or dictionaries. 1. REPORTING YEAR The calendar year in which the report is filed. For instance, 2006 is the Reporting Year for a report filed April 1, PREVIOUS YEAR Is the calendar year immediately before the reporting year. For a report filed April 1, 2006, the Previous Year is SUMMER PEAK PERIOD For the purposes of this report, the summer peak period begins on June 1 and extends through September WINTER PEAK PERIOD For the purposes of this report, the winter peak period begins on December 1 and extends through March 31 of the following year. For instance, winter 2005 begins December 1, 2005, and extends through May 31, It is convenient to describe the winter peak period by means of two years. Thus, the winter referred to here would be winter 2005/ CAPACITY A measure of the ability to generate electric power, is usually expressed in megawatts (MW). Capacity can refer to the output of a single generator, a plant, an entire electric system, a power pool, or a Region. Summer or Winter Capacity is a reference to the expected generator capacity at the time of the summer or winter peak demand period. 6. NET CAPABILITY The maximum load-carrying ability of the equipment, exclusive of station use, under specified conditions for a given time interval independent of the characteristics of the load. (Capability is determined by design characteristics, physical condition, adequacy of prime mover, energy supply, and operating limitations such as cooling a circulating water supply and temperature, headwater and tailwater elevations, and electrical use.) 7. NET CAPACITY The maximum capacity (or effective rating) modified for ambient limitations, that a generating unit, power plant, or electric system can sustain over a specified period of time (such as a month or season), less the capacity used to supply the demand of station or auxiliary needs (such as fan motors, pump motors, and other equipment essential to operation of the generating units). 9

10 8. DISTRIBUTED GENERATION Small-scale generating units located in close proximity to the load being served, and connected to the grid at distribution voltages, typically less than 69kV. Such units may be, for example, reciprocating engines, micro turbines, small combustion gas turbines, fuel cells, or photovoltaic. These units may be applied in a variety of ways, including back-up, power quality, peak shaving, or stand-by. 10

11 ITEM 1 PROJECTED ENERGY & PEAK DEMAND FOR THE FIRST TEN YEARS AND ACTUAL DATA FOR THE PREVIOUS YEAR 11

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13 ITEM 1 PROJECTED ENERGY AND PEAK DEMAND FOR THE FIRST TEN YEARS AND ACTUAL DATA FOR THE PREVIOUS YEARS This item reports actual annual Net Energy for Load and seasonal Peak Demand for the previous year and estimated values for the reporting year and for each of the nine additional years. Peak Hour Demand in Megawatts (MW) should correspond to Total Internal Demand as reported on line 03 of Item 3. Net Energy for Load is to be reported in gigawatthours (Gwh). It is the electrical energy requirements of an electric system, defined as system net generation plus energy received from others less energy delivered to others through interchange. It includes system losses but excludes energy required for the storage at energy storage facilities. For the purposes of this report, the summer period extends from June 1 through September 30 and the winter period from December 1 through March 31 of the following year. For example, winter 2005 begins December 1, 2005 and extends through March 31,

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15 Item 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year SPP Monthly Data Actual Data 2005 Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 01 Peak Hour Demand-MW Net Energy-GWh Reporting Year 2006 Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 03 Peak Hour Demand-MW Net Energy-GWh Next Year 2007 Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 05 Peak Hour Demand MW Net Energy-GWh Ten Year Projection Actual 07 Peak Hour Demand Summer-MW Ten Year Projection Actual 08 Peak Hour Demand 2005/ / / / / / / / / / /16 Winter-MW Ten Year Projection Actual 09 Net Annual Energy Annual-GWh

16 ITEM 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year Monthly Data Actual Data 2005 Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 01 Peak Hour Demand - MW AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 16

17 ITEM 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year Monthly Data Actual Data 2005 Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 02 Net Energy - GWh AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 17

18 ITEM 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year Monthly Data Reporting Year 2006 Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 03 Peak Hour Demand - MW AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 18

19 ITEM 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year Monthly Data Reporting Year 2006 Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 04 Net Energy - GWh AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 19

20 ITEM 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year Monthly Data Next Year 2007 Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 05 Peak Hour Demand - MW AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 20

21 ITEM 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year Monthly Data Next Year 2007 Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 06 Net Energy - GWh AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 21

22 ITEM 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year Actual Previous Year Actual Ten Year Projection Peak Hour Demand Summer - MW AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 22

23 ITEM 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year Actual Previous Year Actual Ten Year Projection 2005/ / / / / / / / / / /16 08 Peak Hour Demand Winter - MW AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 23

24 ITEM 1 Projected Energy and Peak Demand for the First Ten Years and Actual Data for the Previous Year Actual Previous Year Actual Ten Year Projection Net Annual Energy GWh AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 24

25 ITEM 3 PROJECTED CAPACITY AND DEMAND FOR TEN YEARS SUMMER AND WINTER 73

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27 ITEM 3 Projected Capacity and Demand for Ten Years Report Capacity and Demand projected for the summer and winter peak periods of the ten-year period. Peak demands reported here should agree with the corresponding entries in Item 1. Capacity data reported in Item 3 is consistent with Item 2. The information in Item 3 is to be reported in megawatts (MW) for each peak period on the same basis as reported in Item 1 as follows: Column number: 01 Internal Demand Peak hour integrated megawatt demand is defined as the sum of the demands of all customers that a system serves, including the demands of the organization providing the electric service, plus the losses incidental to that service. Total Internal Demand is the sum of the metered (net) outputs of all generators within the system and the metered line flows into the system, less the metered line flows out of the system. The demand of station service or auxiliary needs (such as fan motors, pump motors, and other equipment essential to the operation of the generating units) is not included. Internal Demand includes adjustments for utility indirect demand-side management programs such as conservation programs, improvements in efficiency of electric energy use, rate incentives, and rebates. Internal Demand should not be reduced by Direct Control Load Management or Interruptible Demand, which are reported on Lines 04 and 05. The Internal Demand of nonmember systems of the Council or Reporting Party should be included to the extent known. State in a footnote if Internal Demand includes or does not include Standby Demand. 02 Standby Demand The Demand specified by contractual arrangement with a customer to provide power and energy to that customer as a secondary source or backup for an outage of the customer s primary source. Standby Demand is intended to be used infrequently by any one customer. If Standby Demand is included in Line 01, report 0 on Line 02. If there are no arrangements for Standby Demand, report 0 on Line

28 03 Total Internal Demand As reported in Item 1 (Peak Hour Demand). Line 01 plus Line Direct Control Load Management The magnitude of customer demand that can be interrupted at the time of the Council or Reporting Party seasonal peak by direct control of the System Operator by interrupting power supply to individual appliances or equipment on customer premises. This type of control usually reduces the demand of residential customers. Direct Control Load Management as reported here does not include Interruptible Demand (Line 05). Line 01 (Internal Demand) should not incorporate the effect of this reduction in demand. 05 Interruptible Demand The magnitude of customer demand that, in accordance with contractual arrangements, can be interrupted at the time of the Council or Reporting Party seasonal peak by direct control of the System Operator or by action of the customer at the direct request of the System Operator. In some instances, the demand reduction may be effected by direct action of the System Operator (remote tripping) after notice to the customer in accordance with contractual provisions. For example, demands that can be interrupted to fulfill planning or operating reserve requirements normally should be reported as Interruptible Demand. Interruptible Demand as reported here does not include Direct Control Load Management (Line 04). Line 01 (Internal Demand) should not incorporate the effect of this reduction in demand. 06 Net Internal Demand Total Internal Demand less Direct Control Load Management and Interruptible Demand. Line 03 minus Line 04 minus Line Total Net Operable Capacity Is the sum of the values reported on Schedule 2, Line 9, for all generators included by the reporting region. 7a Jointly Owned Unit Capacity Is the capacity of all jointly owned units. The controlling area with the jointly owned unit will have a negative value. 76

29 7a1 New Capacity Additions Is any additional future generation capacity. These values include planned projects but not exploratory projects. 7a2 Total Control Area Capacity The sum of lines 7, 7a, and 7a1. 7b Uncommitted Capacity Uncommitted Capacity includes the total amount of generating resources that are physically located in the Region, but are not dedicated to or contractually committed to serve load in the Region. 7b1 Reliability Derating Unit Specific Subtotal The total amount of reduction in the maximum capability of the units that can be specifically identified due to transmission constraints, or the amount of generator capability that cannot be relied upon due to other issues, such as wind and hydro conditions. 7b2 Reliability Derating Group Subtotal The total amount of reduction in the maximum capability of the units that cannot be specifically identified (i.e., allocated or prorata derating) due to transmission constraints or the amount of generator capability that cannot be relied upon due to other issues, such as wind and hydro conditions. 7b3 Scheduled Maintenance Scheduled Maintenance should be used to report capacity that will be unavailable due to scheduled maintenance during the entire reporting period. 7c Other Generation The total amount of generation reported in the EIA 860 that is not included in Regional calculations of Planned Capacity Resources, e.g., behind the meter, self-use, etc. 7d Subtotal Committed Capacity Resultant of subtracting lines 7b, 7b1, 7b2, 7b3, and 7c from line 7a. 77

30 8 Generator Capacity less than 1 Megawatt The total of all grid-connected capacity less than 1 megawatt, regardless of physical location, that is dedicated to satisfying the needs of the reporting region. 8a Distributed Generator Capacity less than 1 Megawatt The amount of the capacity reported on line 8 that is comprised of distributed generators, as defined in the glossary. 8b Other Capacity less than 1 Megawatt The amount of the capacity reported on line 8 that is not comprised of distributed generators as defined in the glossary. (This should equal line 8, less line 8a.) 9 Total Net Generator Capacity The sum of line 7d and line 8. 9b Distributed Generator Capacity, 1 Megawatt or Greater The amount of the capacity reported on line 7 that is comprised of distributed generators, as defined in the glossary. This is broken out for informational purposes. 10 Total Capacity Purchases/Transfers The total of all capacity purchases from sources outside the boundaries of the Reporting Party as reported in Schedule 4 at the time of the purchaser s peak demand. If not equal to the total in Schedule 4, Parts A and B, explain in a footnote on Schedule 9. 10a Full Responsibility Purchases Total of all purchases for which the seller is contractually obligated to deliver power and energy to the purchaser with the same degree of reliability as provided to the seller s own native load (customers). Each purchaser and seller must agree on which of their transactions are reported under this heading. 78

31 11 Total Capacity Sales/Transfers The total of all capacity sales to purchasers outside the boundaries of the Reporting Party, as reported in Schedule 4 at the time of the seller s peak demand. If not equal to the total in Schedule 4, Parts C and D, explain in a footnote on Schedule 9. 11a Full Responsibility Sales Total of all sales for which the seller is contractually obligated to deliver power and energy to the purchaser with the same degree of reliability as provided to the seller s own native load (customers). Each purchaser and seller must agree on which of their transactions are reported under this heading. 12 Planned Capacity Resources Utility- and IPP-owned generating capacity that is existing or in various stages of planning or construction, less inoperable capacity, plus planned capacity purchases from other resources, less planned capacity sales. Equal to Line 09 plus Line 10 minus Line

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33 ITEM 3.1 PROJECTED CAPACITY AND DEMAND FOR TEN YEARS SUMMER 81

34 Item 3.1 Projected Capacity and Demand for Ten Years Summer 2005 Demand in Megawatts a 7a1 7a2 7b 7b1 7b2 7b3 7c 7d 8 8a 8b 9 9b 10 10a 11 11a 12 Direct Total Net Jointly New Total Derating Derating Subtotal Generator Distributed Other Total Net Distributed Total Capacity Full Total Capac Full Planned Internal Standby Total Internal Control Load Interruptible Net Internal Operable Owned Capacity Control Area Uncommited Unit Spec. Group Scheduled Other Commited Capacity Generator Capacity Generator Generator Purchases/ Responsibility Sales/ Responsibility Capacity System Demand Demand Demand Management Demand Demand Capacity Unit Capacity Additions Capacity Capacity Subtotal subtotal Maintenance Generation Capacity < 1 MW Capacity < 1MW < 1 MW Capacity Capacity >1 MW Transfers Purchases Transfers Sales Resources AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 82

35 Item 3.1 Projected Capacity and Demand for Ten Years Summer 2006 Demand in Megawatts a 7a1 7a2 7b 7b1 7b2 7b3 7c 7d 8 8a 8b 9 9b 10 10a 11 11a 12 Direct Total Net Jointly New Total Derating Derating Subtotal Generator Distributed Other Total Net Distributed Total Capacity Full Total Capac Full Planned Internal Standby Total Internal Control Load Interruptible Net Internal Operable Owned Capacity Control Area Uncommited Unit Spec. Group Scheduled Other Commited Capacity Generator Capacity Generator Generator Purchases/ Responsibility Sales/ Responsibility Capacity System Demand Demand Demand Management Demand Demand Capacity Unit Capacity Additions Capacity Capacity Subtotal subtotal Maintenance Generation Capacity < 1 MW Capacity < 1MW < 1 MW Capacity Capacity >1 MW Transfers Purchases Transfers Sales Resources AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 83

36 Item 3.1 Projected Capacity and Demand for Ten Years Summer 2007 Demand in Megawatts a 7a1 7a2 7b 7b1 7b2 7b3 7c 7d 8 8a 8b 9 9b 10 10a 11 11a 12 Direct Total Net Jointly New Total Derating Derating Subtotal Generator Distributed Other Total Net Distributed Total Capacity Full Total Capac Full Planned Internal Standby Total Internal Control Load Interruptible Net Internal Operable Owned Capacity Control Area Uncommited Unit Spec. Group Scheduled Other Commited Capacity Generator Capacity Generator Generator Purchases/ Responsibility Sales/ Responsibility Capacity System Demand Demand Demand Management Demand Demand Capacity Unit Capacity Additions Capacity Capacity Subtotal subtotal Maintenance Generation Capacity < 1 MW Capacity < 1MW < 1 MW Capacity Capacity >1 MW Transfers Purchases Transfers Sales Resources AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 84

37 Item 3.1 Projected Capacity and Demand for Ten Years Summer 2008 Demand in Megawatts a 7a1 7a2 7b 7b1 7b2 7b3 7c 7d 8 8a 8b 9 9b 10 10a 11 11a 12 Direct Total Net Jointly New Total Derating Derating Subtotal Generator Distributed Other Total Net Distributed Total Capacity Full Total Capac Full Planned Internal Standby Total Internal Control Load Interruptible Net Internal Operable Owned Capacity Control Area Uncommited Unit Spec. Group Scheduled Other Commited Capacity Generator Capacity Generator Generator Purchases/ Responsibility Sales/ Responsibility Capacity System Demand Demand Demand Management Demand Demand Capacity Unit Capacity Additions Capacity Capacity Subtotal subtotal Maintenance Generation Capacity < 1 MW Capacity < 1MW < 1 MW Capacity Capacity >1 MW Transfers Purchases Transfers Sales Resources AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 85

38 Item 3.1 Projected Capacity and Demand for Ten Years Summer 2009 Demand in Megawatts a 7a1 7a2 7b 7b1 7b2 7b3 7c 7d 8 8a 8b 9 9b 10 10a 11 11a 12 Direct Total Net Jointly New Total Derating Derating Subtotal Generator Distributed Other Total Net Distributed Total Capacity Full Total Capac Full Planned Internal Standby Total Internal Control Load Interruptible Net Internal Operable Owned Capacity Control Area Uncommited Unit Spec. Group Scheduled Other Commited Capacity Generator Capacity Generator Generator Purchases/ Responsibility Sales/ Responsibility Capacity System Demand Demand Demand Management Demand Demand Capacity Unit Capacity Additions Capacity Capacity Subtotal subtotal Maintenance Generation Capacity < 1 MW Capacity < 1MW < 1 MW Capacity Capacity >1 MW Transfers Purchases Transfers Sales Resources AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 86

39 Item 3.1 Projected Capacity and Demand for Ten Years Summer 2010 Demand in Megawatts a 7a1 7a2 7b 7b1 7b2 7b3 7c 7d 8 8a 8b 9 9b 10 10a 11 11a 12 Direct Total Net Jointly New Total Derating Derating Subtotal Generator Distributed Other Total Net Distributed Total Capacity Full Total Capac Full Planned Internal Standby Total Internal Control Load Interruptible Net Internal Operable Owned Capacity Control Area Uncommited Unit Spec. Group Scheduled Other Commited Capacity Generator Capacity Generator Generator Purchases/ Responsibility Sales/ Responsibility Capacity System Demand Demand Demand Management Demand Demand Capacity Unit Capacity Additions Capacity Capacity Subtotal subtotal Maintenance Generation Capacity < 1 MW Capacity < 1MW < 1 MW Capacity Capacity >1 MW Transfers Purchases Transfers Sales Resources AREC CELE CLWL EMDE GRRD INDN KACP KACY KAGE KAPL LAFA LEPA MIDW MIPU OKGE OMPA PSOK SOEP SPRM SUNC SWPA SWPS WEFA WEPL YAZO Total: Note: AEPW=PSOK & SOEP Aquila = MIPU & WEPL Westar Energy = KAGE & KAPL 87