ML20003G882
| ML20003G882 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 04/30/1981 |
| From: | KANSAS GAS & ELECTRIC CO. |
| To: | |
| Shared Package | |
| ML20003G881 | List: |
| References | |
| WCGS-ER(OLS), WCGS-ERCOLS-R01, WCGS-ERCOLS-R1, NUDOCS 8105040105 | |
| Download: ML20003G882 (600) | |
Text
{{#Wiki_filter:1 [ ] WCGS-ER(OLS ) WOLF CREEK GENERATING STATION, UNIT NO. 1 ENVIRONMENTAL REPORT OPERATING LICENSE STAGE REVISION 1 INSTRUCTIONS POR INSERTING REVISION 1 Remove and insert the pages, tables, figures, and tabs listed below. Dashes (--) in the remove or insert column of the instructions indicato no action required. The Revision 1 tab, transmittal letter, and these instructions should be placed at the end of volume 2 material. REMOVE INSERT VOLUME 1 CHAPTER 1 Page 4.0-1/11 through 1.0-v Page 1.0-1/11 through 1.0-v Pages 1.1-1/2 through 1.1-31/32 Pages 1.1-1/2 through 1.1-32 Pages 1.1-3 5 /36 through Pages 1.1-35/35a through 1.1-45/46 1.1-45a/46 ex Pages 1.1-49/50 through 1.1-55 Pages 1.1-49/50 through 1.1-55 Tables 1.1-1 through 1.1-6 (V) (Sheet 4 of 4) Tables 1.1-1 through 1.1-6 (Sheet 4 of 4) Tables 1.1-7b through 1.1-33/34 Tables 1.1-7b through 1.1-33/34 Figures 1.1-1/2 through 1.1-9/10 Figures 1.1-1/2 through 1.1-9/10 Page 1.2-1 Page 1.2-1 Pages 1.3-1/2 and 1.3-3/4 Pages 1.3-1/2 and 1.3-3/4 CHAPTER 2 Pages 2.0-vii/viii through Pages 2.0-vii/viii through 2.0-xiii/xiv 2.0-xiv(a) Figure 2.1-6 Figure 2.1-6 Pages 2.3-1/2 through 2.3-9/10 Pages 2.3-1/2 through 2.3-9/10 Tables 2.3-1 (Sheet 3 of 3)/ Tabics 2.3-1 (Sheet 3 of 3)/ 2.3-2 (Sheet 1 of 4) through 2.3-2 (Sheet 1 of 4) through 2.3-3 (Sheet 11 of 12)/ 2.3-3 (Sheet 12 of 12) (Sheet 12 of 12) Tables 2.3-6/7 through 2.3-37 Tables 2.3-6 through 2.3-34 (Shoot 1 of 2)/(Sheet 2 of 2) (Sheet 2 of 2) Figure 2.3-7a VOLUME 2 CilAPTER 5 l ]# } Pages 5.0-lii/iv and 5.0-v/vi Pages 5.0-lii/iv and 5.0-v/vi (,,/ Page 5.1-21/22 Page 5.1-21/22 and 5.1-22a/22b Tables 5.1-3/4 through 5.1-9/10 Figure 5.1-3 8105040/068
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(' N CHAPTER 6 Pages'6.0-i/11 cnd 6.0-iii/iv Pages 6.0-1/11 and 6.0-iii/iv Pages 6.1-9/10 through 6.1-15/16 Pages 6.1-9/10 through 6.1-15/16 Pages 6.1-19/20 through Pages 6.1-19/20 through 6.1-31/32 6.1-32a Table 6.1-14/15 Table 6.1-14/15 Page 6.2-3/4 Page 6.2-3/4 CHAPTER 8
- Page 8.0-1/11 Page 8.0-i/ii Pages 8.1-1/2 and 8.1-3/4 Pages 8.1-1/2 through 8.1-3/4 Tables 8.1-1/2 Tables 8.1-1/2 Page 8.2-1/2 Page 8.2-1/2 Tables 8.2-1/2 Tables 8.2-1/2 i
CHAPTER 9 Page 9.0-1/11 Page 9.0-i/ii Pages 9.1-1/2 through 9.1-5 Pages 9.1-1/2 through 9.1-4/5 Table 9.1-1 Table 9.1-1 , Page 9.2-1/9.3-1 Page 9.2-1/9.3-1 l CHAPTER 11
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! Table 11.1-1 Table 11.1-1 Page 11.2-1/2 Page 11.2-1/2 Tables 11.2-1/2 Tables 11.2-1/2 REVISION 2 Revision 1 tab (directly behind Chapter 13 material) Place transmittal letter and these instructions behind
- Revision 1 tab.
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WCGS-ER (OLS ) TABLE OF CONTENTS Section, Title Page 1.0 PURPOSE OF THE FACILITY AND 1.1-1 ASSOCIATED TRANSMISSION 1.1 . SYSTEM DEMAND AND RELIABILITY 1.1 -1 1.1.1 LOAD CHARACTERISTICS 1.1-9 1.1.1.1 Load Analysis 1.1-10 1.1.1.2 Demand Projections 1.1-14 1.1.1. 3 Power Exchanges 1.1-37 1.1.2 SYSTEM CAPACITY 1.1-38 1.1.2.1 Capacity Planning 1.1-40 1.1.2.2 Fuel Sources and Prices 1.1-42 1.1.2.3 Bulk Power Planning 1.1-46. 1.1.3 RESERVE MARGINS 1.1-50 1.1.3.1 Reserve Requirements and Margins 1.1-50 1.1.3.2 Scheduled and Forced Outages 1.1-52
-~ 1.1.4 EXTERNAL SUPPORTING STUDIES. 1.1-54 1.
1.5 REFERENCES
1.1-55 OTHER OBJECTIVES 1.2-1 1.2 CONSEQUENCES OF DELAY 1.3-1 1.3 EFFECTS OF DELAY ON RESERVE MARGINS 1.3-1 1.3.1 - EFFECTS OF DELAY'ON FUEL CONSUMPTION 1.3-2 1.3.2 1.3-3 1.3.3 EFFECTS OF DELAY ON OTHER APPLICANT COSTS i i t i i 1.0-1 i l
WCGS-ER(OLS) TABLE OP CONTENTS (CONTINUED) LIST OF TABLES Table Title 1.1-1 KG&E Load and Capability Data, 1965-1990 1.1-2 KCPL Load and Capability Data, 1965-1995 1.1-3 KEPCo Load and Capability Data, 1971-1990 1.1-4a KG&E Installed Capacity, 1974-1992 1.1-4b KGLE Actual and Proposed Capacity Changes, 1975-1992 l 1.1-Sa KCPL Ins talled Capacity, 1974-1990 1.1-5b KCPL Actual and Proposed Capacity Changes, 1975-1990 l 1.1-6 Participation in Pools and Associations 1.1-7a SPP Load and capability Data, 1965-1977 1.1-7b SPP Comparison of Forecast and Actual Capability, Load and Margins, 1971-1980 1.1-8 SPP Energy and Peak Loads, 1978-1989 t 1.1-9 SPP Projected Resources, Demand and Margins, 1980-1989 1.1-10 SPP Long Range Peak Demand, Resources and Reserve, 1990-1999 l 1.1-11 MOKAN Pool Load and Capability Data, 1971-1989 l 1.1-12 KG&E System Loads, Annual System Energy and Peak Demand, 1968-1990 1.1-13 KCPL Sys tem Loads, Annual System Energy and Peak Demand, 1968-1990 1.1-14 KEPCo System Loads, Annual Sys tem Energy and Peak Demand, 1971-1995 1.0-11 Rev. 1 4 / 81
/ \ WCGS-ER(OLS) b 7ABLE OF CONTENTS (CONTINUED) LIST OF TABLES Table Title 1.1-15 Fuel Mix - Percentage Distribution of Annual Net Generation, 1970-1990 1.1-16 Trends in Fuel Costs by Fuel, in Cents per Million Btu, 1970-1990 1.1 Trends in Fuel Costs for System Operations in Cents per Million Btu, 1968-1990 1.1-18 System Operations,' Peak llour Conditions, 1973-1980 l 1.1-19 Number and Growth of Residential Customers, 1968-1990 l 1.1-20 Trends in Use of Electricity - Residential Electric Ileating, 1969-1980 l 7-~ s- / 1.1-21 Average Annual Consumption of Ener y by' Residential Customers, 1970 .390 l 1.1-22 Distribution of Energy Consumption by Catagory, 1964-1989 l 1.1-23 Average Annual Costs by Consumer Category, 1971-1985 l 1.1-24 Economic Growth Indicators, Kansas and Missouri 1.1-25 KG&E Comparison of Forecast and Actual Peak Loads and Energy, 1972-1980 l 1.1-26 KCPL Comparison of Forecast and Actual Peak Loads and Energy, 1972-1980 l 1.1-27 KG&E and KCPL Interchange Budget for 1984-1985 l 1.1-28 KG&E Monthly Loads and Interchange, First Two Years with WCGS in Service v Rev. I 1.0-lii 4/81
WCGS-ER(OLS) TABLE OF CONTENTS (CONTINUED) LIST OF TABLES Table Title 1.1-29 KCPL Monthly Loads and Interchange, First Two Years with WCGS in Service 1.1-30 Projected Fuel Mix, First Three Years of Planned Operations With and Without WCGS 1.1-31 Projected Fuel Mix, Peak Day Generation Percentage Distribution, 1980-1990 1.1-32 KG&E Actual and Projected Fuel Costs, i 1980-1990 1 1.1-33 KCPL Actual and Projected Fuel Costs, 1980-1990 l 1.1-34 Fuel Costs as a Percentage of Total Operating Costs, 1965-1980 l O O Rev. I 1.0-iv 4/81
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l t I l WCGS-ER(OLS)
-TABLE OF CONTENTS (CONTINUED)
LIST OF FIGURES Figure Title 1.1-1 KG&E Load Duration curve, 1984 1.1-2 KG&E Load Duration Curve, 1985 1.1-3 KCPL Load Duration Curve, 1984-1985 1.1-4 KEPCo Load Duration Curve, 1984-1985 , 1.1-5 KG&E Hourly Locd Curve, Typical Summer Peak Day i 1.1-6 KG&E Hourly Load Curve, Typical Winter Peak Day 1.1-7 KG&E Hourly Load Curvo, Typical Spring-Fall Day 1.1-8 KCPL Hourly Load Curve, Typical Summer Peak Day 1.1-9 KCPL Hourly Load Curve, Winter Peak Day 1980 C 1.1-10 KCPL Hourly Load Curve, Typical Spring-Pall Day 1.1-11 KCPL Econometric Model Forecast Diagram Rev. 1 1.0-v 4/81
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1 WCGS-ER(OLS') CHAPTER 1.0 l Q r PURPOSE OF THE FACILITY AND ASSOCIATED TRANSMISSION 1.1 SYSTEM DEMAND AND' RELIABILITY
-The Wolf Creek Generating
- Station, Unit No. 1 (WCGS), an 1150 MWe_ base load plant, is a major addition which will supply both capacity and energy to the systems of the appli-cants. The plant is scheduled for service in time to meet the 1984 summer peak loads.
Joint ownership of WCGS is on the basis of an undivided 41.5 percent. each for the Kansas Gas and Electric Company (KG&E) and the Kansas . City Power and Light Company (KCPL) and 17 , i percent for the' Kansas Electric Power Cooperative, Inc. - (KEPCo). Allocation of power produced by the plant will~ also be on a 41.5 percent, 41.5 percent, 17 percent basis, i
- 477.25 MW - to KG&E, . 477.25 MW to KCPL, and 195.5 to KEPCo.
KG&E is the agent for the three utilities during the con-struction period and will continue in that role- during operations. KEPCo was added as a co-owner subsequent to the submission of the ER(CPS). I Kd&E, of Wichita, Kansas, provides e16ctrical service to approximately 229,000 customers in 25 counties of Southeast l Kansas, including the Wichita Metropolitan Area. Wholesale service is provided to 31-communities and 8 rural electric ' l cooperatives. The estimated population in the 8,100 square 9 mile service area is about 610,000 persons. l KCPL, a Missouri corporation of Kansas City, Missouri, pro-vides electrical service to about 343,000 customers in 94 I l communities of 23 west Missouri and east Kansas counties. l Wholesale service is provided to 7 other communities, 2 l l electric cooperatives and two utilities. Its service area t covers approximately 4,700 square miles with a population of i about one million pe rsons . Customers in Missouri account for approximately 75 percent of~the total sales of energy
- and those in Kansas for about 25 percent. The Kansas City Metropolitan Area is the source of approximately 95 percent l of the utility's revenues. KCPL also provides steam service to 218 customers in Kansas City, Missouri. Itc service area l is contiguous- to that of KG&E at KCPL's southwest boundary. l i
l l 2 i Rev. 1
- 1.1-1 4/81
WCGS-ER(OLS) KEPCo, of Topeka, Kansas, was incorporated in Februa ry, 1975 l as a rural electric generation and transmission cooperative. KEPCo members include 26 distribution electric cooperatives and one generation and transmission coope rative. All-requirement wholesale power agreements have been executed by 25 of its 26 members, rural electric distribution coopera-tives located in the castern two-thirds of Kansas. At this time KEPCo has neither generation nor transmission facil-ities, and the ownership of 17 percent of WCGS will repre-sent KEPCo's first owned generating capacity. Another 29.35 MW of capacity will be added in 1986, representing two low-head hydro projects. Itoweve r, in the long term KEPCo in-tends to own and/or control all of the power resources required to meet the total power obligation of its members and to meet the reserve requirements of any pool agreements. Investigations are continuing on plans for joint owne rship of future load generating capacity and for participation through ownership or purchase in the existing generation capacity of major Kansas utilities. KEPCo proposes to tra nsmit its power and power purchased from major utilities ove r the transmission lines of the utilities throughout the state to interconnections with member coope ratives which will distribute power over their individually owned distribution networks. Arrangements have been made for coordination, transmission and delivery of 90 MW of hydro-peaking power purchased from the Southwestern Power Administration (SPA). 30 MW of this hydro-peaking power is currently being delivered into Kansas. An addition-al 60 MW of hydro-peaking power will be purchased from the SPA, contingent on the ~ completion of generation facilities at the liarry S Truman Dam located near Warsaw, Missouri. In the long term KEPCo intends to build transmission lines, as future plans are developed with major power suppliers in Kansas. The combined service area for KEPCo's membe rs extends over the eastern-most part in the rural areas of the state of Kansas and includes rural communities and farmsteads. KEPCo's membe rs provide electric service to an estimated population of about 355,000 in an area of approximately l 40,000 square miles, i KEPCo plans to use 135.5 MW of its WCGS power and 60 MW of its SPA power along with power purchased from ove rlying investor-owned utilities to serve its full requirement dis-tribution members. The remaining 60 MW of WCGS power and 30 MW of SPA power are to be sold to its single generation and transmission cooperative member, Sunflower Electric Cooperative. To meet the projected demand for peak power and energy with- l in their service areas, the three utilities have planned and Rev. 1 1.1-2 4 / 81
i i WCGS-ER(OLS) implemented programs of additions to their generating capa-city as follows: , NET CAPACITY' INCREASES - Pe riod ' KG&E KCPL KEPCo MW Pe rcent MW Percent MW Percent 4 1970-1980 830 72.1 1152 63.3 0 0 1980-1990 742 37.5 323 11.4 225
- 1
- Represents all of KEPCo's owned capacity.
i 1 i i 2 ) 1 Rev. I 1.1-2a 4/81
I WCGS-ER(OLS) These additions to capacity, shown in Tables 1.1-4a and 1.1-Sa for KG&E and KCPL, have been and will be made to meet projected growth in peak demand and annual l energy requirements as follows: INCREASES IN PEAK DEMAND AND ENERGY g REQUIREMENTS, 1970-1990, IN PERCENT Peak Demand Energy Requirements Period KG&E KCPL KEPCo KG&E KCPL KEPCO 1970-1980 60.4% 46.6% 138.8% 64.4% 45.6% 113.1% 1980-1990 21.6 39.8 84.6 20.0 54.9 79.9 Shown for 1971-1980 As indicated above, changes in peak demand and energy requirements correspond to changes in net capacity, despite the fact that planning for capacity additions takes place many years in advance of the completion of an addition to capacity. Tables 1.1-12, 1.1-13 and 1.1-14 provide details on past and projected loads, Tables 1.1-1, 1.1-2, and 1.1-3 show the effect of considering the total system responsibil-ity of each Applicant. , Reserve margins both with and without WCGS are shown below for the early years of WCGS operation. RESERVE MARGINS" IN PERCENT With WCGS Without WCGS Year KG&E KCPL KG&E KCPL 1984 44.9 28.8 1G.2 12.8 1985 40.2 24.4 14.4 8.9 1986 44.1 20.0 18.8 5.1 1987 33.6 15.9 15.2 1.5 1988 35.8 11.8 12.0 - 2.0 1989 32.5 8.0 9.3 - 5.4 1990 29.7 2.9 7.0 -10.0
" Do not reflect external obligations.
If WCGS is not in operation, 80 MW of Northeast 1, 2, 4, 5 and 7 will be retained by KCPL. l Interchange purchases are planned to cover KCPL's reserve margin deficiencies in 1988 and thereafter with WCGS in operation. A new 455 MW unit is tentatively planned for 1991. i l Rev. 1 i 1.1-3 4/81
WCGS-ER(OLS) O The increments represented by their respective shares of WCGS capacity are large additions to the capacities of the three utilities. Shares of WCGS capacity in 1984 will represent 18.4 percent of KG&E's capacity, 14.9 percent of KCPL's capacity and 100 percent of KEPCo's owned capacity. Because it is a major addition, the reserve margins for KG&E, as shown above, will be adequate for the period shown, with WCGS in operation. KCPL will have adequate ma rgins throughout 1986 but be below its internal and pool require-ments thereafter. Without WCGS, KG&E's margin would fall below the pool requirement of 15 percent in 1988, and KCPL's margin would be below its internal planning require-ment of 20 percent and the pool requirement of 15 percent in 1984, quickly becoming seriously deficient. Reserve margin requirements are discussed in Section 1.1.3. In addition to meeting projected peak loads and energy requirements, WCGS will provide a reliable source of power that_is not dependent upon fossil fuels. In the recent past KG&E depended completely on natural gas from local sources for fuel, while KCPL depended primarily on coal and second-arily on natural gas, from local sources. The changes in fuel mix that have occurred and are projected are shown in Table 1.1-15 and summarized below: ( FUEL MIX - PERCENTAGE DISTRIBUTION OF ANNUAL NET GENERATION KG&E KCPL 1970 1980 1990 1970 1980 1990 Coal - 49.4 56.1 69.2 93.5 73.1 Oil 0.5 1.9 1.9 0.1 0.9 2.6 Gas 99.5 48.7 14.6 30.7 5.6 0.1 Nuclear - - 29.4 - - 24.2 Total 100.0 100.0 100.0 100.0 100.0 100.0 NOTE: A median capacity factor of 70% is assumed for WCGS in 1990. KG&E and KCPL will continue to reduce the use of natural gas ) and minimize the use of oil in compliance with the 1978 l Fuels Use Act and national energy policy. The importance of WCGS in making this possible is evident in the tabulation above. Diversification of fuel sources will tend to increase the reliability of the systems of the Applicants and of the (A) U region by reducing their dependence on fossil fuels for gen-eration. The value of such diversification is demonstrated I Rev. I 1.1-4 4/81
l 1 i WCGS-ER(OLS) by the tabulation below, which shows the planned fuel mix in percentage of generation in 1984, both with and without WCGS. 1 9 l 1 1 l O Rev. 1 1.1-4a 4/81 l l l _ - - - -..l
WCGS-ER(OLS) ( j 1984 FUEL MIX, IN PERCENT With WCGS Without WCGS Fuel KG&E KCPL KG&E KCPL Coal 61.7% 83.9% 55.6% 97.3% Oil 0.3 1.7 11.2 2.6 ' l Gas 18'.1 0.1 33.1 0.1 ' Nuclear 19.9 14.3 0 0 100% 100% 100% 100%
- i Assumes median of WCGS capacity factor range. I The cos ts of fossil fuels are increasing rapidly, as shown in Table 1.1-16. In the period 1970 to 1990 the costs for i individual fuels are expected to have increased by factors ranging from 10 to 75. In addition, the availability of l fossil ftiels is questionable, although natural gas has been more abundant than was thought possible a few years ago.
Even so, the use of natural gas as boiler fuel must be dis-continued by 1990, except for peaking purposes, in accord-ance with the 1978 Fuels Use Act. The-1978 Fuels Use'Act also limits gas consumption at each station to no more'than b' the average usage by. the station in the years 1974 through 1976. However, if the reduction of oil consumption contin-ues to be a national policy, natural gas may be made avail- l able to . utilities on an opportunity basis for a longer period of time. Since late 1979 suppliers of gas to Kansas utilities have not made . firm commitments on supply quan-tities and prices. The associations of which KG&E and KCPL are members or participants are shown in the following table:
. Regional Pools and Associations KG&E KCPL Southwest-Power Pool (SPP) X X Missouri-Kansas Pool (MOKAN) X X Companies-Associated - Southwestern X X Power ' Administration (SPA)
South Central Electric Companies .X Kansas City - Twin Cities X O V Missouri-Kansas-Oklahoma Interconnection Agreement X Rev. 1 1.1-5 4/81
l WGS-ER(OLS ) As indicated above, both KG&E and KCPL are membe rs of the SPP which is one of the nine regional coordinating groups of the Natural Electric Reliability Council (NERC). KG&E and KCPL are also membe rs of MOKAN, an association of nine Kansas and west Missouri utilities. KEPCo inteads '.o become a member of SPP and MOKAN once it has received its appro-priate authorizations from the Rural Electrification Admin-intration (REA). Details on pools and associations are l provided in Table 1.1-6, and pool planning criteria are discussed in Section 1.1.2.3. Each of the Applicants has been engaged in a major ef fort to l increase efficient use of energy through programs to reduce ' waste, to improve energy conversion processes and to reduce the growth rate in demand for energy, and peak demand in l pa rticula r. None of the Applicants is conducting advertis- I ing programs that will stimulate the growth in peak demand. In fact, each is involved in educational campaigns to en- I courage wise use of ene rgy. Both KG&E and KCPL have had advertising programs promoting the wise use of energy since I 1972. All media have been used - enclosures to billing statements, spot radio and television announcements, news-paper and magazine ad ve rtisements in their service areas, distribution of booklets and pamphlets, group meetings and advisory services and seminars. Consumer consultants have l advised hundreds of audiences on the ef ficient use of appli-ances and equipment, and energy management seminars have been held for architects and builders and for commercial and industr'ial customers. KG&E of fers a computer bcrvice for analyzing individual cus- l tome rs ' needs and potential savings from insulation, storm windows, improved eq uipment, and other conservation mea; sures. KG&E and KCPL schedule one-on-one meetings with l major customers to deview conservation methods. Since there is little substantiation for the belief that " pure" conservati)n techniques (s'ach as insulation, weather-ization, ever. c.ustomer moderation) provide any noticeable savings on peak demand, KCPL is actively seeking methods to moderate the growth in peak demand in an offort to delay the need to bujid future generation facilities. The Company is evaluating and implementing programs which will reduce its projected peak demand and improve its overall system load factor to achieve increased efficiencies for existing gener-ation. Two management level planning committees--the Energy Supply Coordinating Committee and the System Expansion Alternatives Committee--work together to project future generation requirements and to evaluate alternatives that would affect peak load. O Rev. 1 1.1-6 4/81
WCGS-ER(OLS) KCPL maintains that the electric utility's role in conserva-( ) tion should be ' directed primarily to the control of system peak demand. Informational programs will continue to inform the customer about . ' " peak alerts, " seasonal and time-of-use conside rations, how to buy or maintain energy ef ficient air conditioning, how to make cost efficient buying decisions on home improvements, and how to buy new homes that use energy efficiently on peak. KCPL also plans to promote high efficiency air conditioning (SEER) and appliances through programs directed -to appliance dealers and maufacturers. Group presentations stress the use of energy efficient appliances and equipment and on-peak conservation practices. Technical information is made available to all customers, and energy management training seminars are conducted for industrial and commercial customers. Home service programs include material on the wise use of energy for students and teachers. In addition to customer education, KCPL is conducting and i- monitoring research programs to provide a base for future load management and energy . application decisions. Testing of radio control systems for residential air conditioning during 1979 and 1980, for example, has shown a potential for reducing customer load on peak from .6 to .7 KW or 9 percent of the average KW demand per customer. Further j research will evaluate radio control systems for commercial l and industrial air conditioning. KCPL is also investigating 5 the potential for small wind energy conversion systems (windmills) and other cogeneration technologies. Research findings from other utilities on two-way communication sys-tems for load management, load research, meter reading and system operation are being monitored and evaluated. Future research to determine the load management potential for improved efficiency in commercial and industrial light-ing is planned. KCPL has been active in residential, commercial and indus-trial energy audits. The billing system has been used several times to advise residential customers on insulation audits that can be provided by an outside contractor for-Energy Efficiency Systems. Over 35,000 audits have been conducted. Surveys indicate that energy conservation mea-sures have been introduced directly into at least 6,000 homes. Other installations have been made by homeowners and by contractors. Building energy analyses are provided for the design of new residential, commercial and industrial construction. The Residential Conservation Services (RCS) program is being implemented; this will provide a formal system for residen-tial energy audits by utilities. Future expansion of RCS and the possible addition of Commercial and Apartment Con-servation Service (CACS) will extend the program to both Rev. I 1.1-6a 4/81
WCGS-ER(OLS) small and la rge apartments and complexes. KCPL will rein-force these programs with load management programs and audits to commercial and industrial customers, with empha-sis on the Company's 300 largest commercial and industrial cus tomers . Other residential research is being conducted to determine the cost ef fectiveness and contributions to savings on peak from passive solar home design (KCPL 's Quail Valley Pro-ject), new home conservation techniques and existing home energy improvements. Work is proceeding to encourage local I homebuilde rs to improve their standards of construction in I new homes by adopting KCPL's "150 Plus Energy Conserving ! Ilome Program" during 1981. . O l l l O Rev. 1 1.1-6b 4/81
l WCGS-ER(OLS) O i KG&E's program.is much the same as that of KCPL in terms of k public contact to stimulate an awareness of the need for conserva tion. : Energy Efficiency Awards are given to dwell-ing units and commercial structures that meet high energy conservation s tanda rds . The use of electric heating is
- discouraged in homes that are poorly insulated. KG&E has also adopted an action program to reduce energy consumption at all company facilities.. Power is being transmitted at l higher voltages in new lines, and worn out conductors are replaced by larger conductors to reduce line losses. The most efficient generating units are used for base load.
KCPL and KG&E have experimented with ice storage air condi-tioning systems in which of f-peak generation at lower rates is used to produce ice for use in daily air conditioning. Results show that the systems work well to control demand, but rate incentives must be developed to encourage mass production so as to reduce the cost. Kansas utilities have a joint research and development program to analyze the effects of voltage reduction on energy saving. KG&E has also conducted experiments on off-peak pumping for irriga-tion. Industrial rates are designed to encourage customers to schedule production so that the greatest load requirements s come during of f-peak months and daily of f-peak periods. _) l a . Rev. 1 l 1.1-7 4/81 t ? t
WCGS-ER(OLS) l Passive load control, a promising load management technique, l involves the use of load limiting devices owned by the cus- I tomer and installed on his eq uipment . The results of a May, 1978 survey of industry by KCPL revealed that 51 per-cent of the industrial and commercial customers surveyed had installed or were considering passive control devices. It appears that cus tome rs who will benefit from such devices will install them. Price signals are conveyed to customers through rate design, such as increased rates, interruptible rates and time-of-day pricing. Neither KCPL nor KG&E has had much in the way of positive response to proposals for time-of-day pricing; few industrial and commercial customers are willing or able to change work shifts. In KCPL's survey 83 percent of the respondents indicated no interest in time-of-day pricing, 94 percent showed no interest in peaking generators or co-generation, and 69 percent did not want interruptible rates. KCPL does have one demand curtailment contract with Armco, its la rges t electric load customer. The contract provides for reduction of up to 100 MW of load, as requested by KCPL. Only five KG&E customers have taken advantage of an experi- l mental of f-peak rate. I Most effort is concentrated on the area of customer educa-tion involving load management and the wise use of energy. Peak Watch and multi-media informational programs have been successful in educating customers. Most of the membe r cooperatives of KEPCo have adopted the Kansas Energy Efficiency Alert program (KEE-92*) which utilizes radio stations to broadcast information on weather conditions that will af fect peak loads. Messages advise on the rising demand for electricity in peak periods and recom-1 O Rev. 1 1.1-8 4/81 l l
WCGS-ER(OLS) O mend actions for holding the peak down. The individual co-operatives follow programs nimilar to those of KG&E and KCPL
. (~) to inform their customers concerning energy efficient appli-1 l
ances and equipment and on the need and means for reducing , demand and consumption. In addition, low-interest loans 1 have been made available to some rural electric consume rs l for installation of insulation and other energy. conservation measures. These loans are administered by KEPCo members and the REA. It is difficult to measure the effectiveness of the util-ities' load management and conservation programs in terms of reduced rates of growth in peak demand and total energy consumption. There are many other factors involved includ-ing length and severity of hot and cold weather, energy prices, fuel competition, changing demands for housing, and the use of more energy ef ficient equipment. However, all utilities believe that their load management and conserva-tion programs have been effective in promoting more effi- l cient use of energy and in reducing the rates of growth. I Minor inconsistencies will exist between data previously reported to the Federal Energy Regulatory Commission, to the REA, and to both SPP and MOKAN and data shown in various tables herein. KG&E and KCPL, like most other utilities, continuously test and re-rate generation capacity, updato load forecasts, and report load data for various reporting
'q j pe riods; i.e., as of the time of the summer peak, as of the end of a fiscal or calendar year, or for a contract year, beginning June 1 of each year.
1.1.1 LOAD CHARACTERISTICS Most of the utilities in the SPP and MOKAN regions exper-ience their annual peak loads in the summer, with relatively little dive rsity . Since they are in the same general cli-matic zone, there is little difference between a simul-taneous peak and a non-coincident peak load. For example, KG&E and KCPL frequently experience a summer peak on the same day or within the same few days. As shown in Table 1.1-18 in six out of the last eight years, the two com-panies experienced their summer peak hour conditions on the same day or within one to eight days of each other, in July and August. For each utility the peak comes in the after-noon when, *:cgard less of cost, residential air conditioning l is turned on. KEPCo, too, experiences its peak loads in 1 July and August. I- the last ten years five peak loads have come in July and fot in August. Utilities in MOKAN and SPP are experiencing growth in demand. Because of this growth and the lack of diversity during the summer months the option is reduced of purchasing large y blocks of power. Rev. 1 1.1-9 4/81
WCGS-ER(OLS) Tables 1.1-7a and 1.1-7b through 1.1-11 present consolidated data on SPP and MOKAN. In the period from 1965 to 1977 the summer peak demand in SPP increased by 144 percent for an l average annual rate of 7.7 percent. In the same period the I accredited capacity increased 169 percent for an average annual rate of 8.6 percent. (Comparable data are not avail- l able for other periods because of membership changes. ) For the period from 1977 to 1990, the summer peak load is pro-jected to increase 112 percent for an average annual growth rate of 6.0 percent. Capacity is projected to double at an average rate of 5.5 percent. In the long term from 1990 to 1999 a 53 percent increase in peak load is projected for SPP at an average annual growth rate of 4.9 percent, with capacity increasing at a slightly lower average rate of 4.7 percent per year. Reserve margins for SPP ars projected to decline from 26.9 percent in 1982 to 19 to 20 percent in the 1990's. The MOKAN systen. peak load increased 66 percent from 1971 to 1980 for an average annual growth rate of 5.8 percent. Accredited capacity increased 70 percent for an average annual growth rate of 6.1 percent. For the period 1980 to 1989 the system peak load is projected to increage at a rate of 3.1 percent and accredited capacity at a rate of 3.4 percent. The installed capacity balance for MOKAN, shown in Table 1.1-11 is projected to be negative in 1986 if WCGS is not in operation. SPP projects summer installed capacity margins of 19 to 24 percent for the period 1984-1989 (Table 1.1-9). However, because of forced outages, the actual summer mar-gins at the times of peak loads, shown in Table 1.1-7b have frequently been below the required 15 percent. In 6 of the last-10 yea rs the actual operating margins at the times of summer peaks have been below 15 percent. Unlike the situation for pools, councils and utilities in other regions, the winter peaks in t.his general region are not approaching the summer peaks in magnitude. 1.1.1.1 Load Analysis Tables 1.1-12, 1.1-13 and 1.1-14 present for the Applicants their historical and projected growth in peak loads and annual energy requirements. As a basis for the discussion which follows, the actual and projected annual peak loads l and energy requirements are shown below for five year inter-vals over the period 1970 to 1990. l 9 Rev. 1 1.1-10 4/81
WCGS-ER(OLS) (3 () PEAK DEMAND AND ANNUAL ENERGY l Peak Load in MW Annual Energy in GWH Year KG&E KCPL KEPCo KG&E KCPL KEPCo
~
- 1970 1077 1499 203 4748 6324 1032 1975 1337 1903 319 6199 7857 1347 1980 1727 2198 484 7807 9205 2199 1985 1845 2574 662 8019 11717 2957 1990 2100 3072 894 9369 14255 3955
- 1971 data shown for KEPCo.
The nature of the growth that has occurred and is expected to occur for KG&E is summarized in the following tabulation. KG&E GROWTH IN PEAK DEMAND AND ENERGY Peak Demand Energy Requirements Period Percentage Avg. Annual Percentage Avg. Annual Increase Growth Increase Growth h 1970-1975 24.1% 4.4% 30.6% 5.5% s 1975-1980 29.2 5.3 25.9 4.7 1970-1980 60.4 4.8 64.4 5.1 1)80-1985 6.8 1.3 2.7 0.5 J985-1990 13.8 2.6 16.8 3.2
'.980-1990 21.6 2.0 20.0 1.8 1970-1990 95.0 3.4 97.3 3.5 Growth in both peak demand and annual energy was relatively high in the late 1960's and early 1970's but fell off some-what in the mid 1970's to an average rate of growth which is projected by KG&E to continue over the long term. In 1981 KEPCo will report its loads to REA and other agencies. This
! reporting change tends to distort future growth rates-slightly for KG&E, which had reported KEPCo's ceak load as a l I part of the KG&E load. In 1980 KG&E experienced a heat storm which set new records for both peak demand and annual energy consumption. If the , l 1980 figures shown above were adjusted for the weather ! anomalies to a " normalized" peak and annual energy, the com-pa risons shown would change. The increase to 1980 would be lower and 'the projections beyond 1980 higher than shown. t
's_ !
Rev. 1 1.1-11 4/81 6
- _ . _ . _ _ . _ - ,. - . _ . _ . . _ . _ . _ _ _ _ _ ~ . _ _ . . _ . - - _ , . _ , - , - - . . . - _ _ . -
WCGS-ER(OLS) In Figure.s 1.1-1 and 1.1-2 the expected load duration curves are given for KG&E for the first two years of operation with WCGS. In Figures 1.1-5, 1.1-6 and 1.1-7 hourly load curves are presented for typical summer and winter peak days and for l a typical spring / fall day. The following tabula tion summarizes recent and anticipated growth trends for KCPL (Table 1.1-13): 1 1 1 O l O Rev. I 1.1-11a 4/81
l WCGS-ER(OLS ) I n j KCPL GROWTH IN PEAK DEMAllD AND ENERGY
' Peak Demand Energy Requirements Period Percentage Avg. Annual Percentage . Avg. Annual Increase Growth Increase Growth 1970-1975 2:7. 0 4.9 24.2 4.4 1975-1980 15.5 2.9 17.2 3.2 1970-1980 46.6 3.9 45.6 3.8 1980-1985 17.1 3.1 27.3 4.9 1985-1990 19.3 3.6 21.7 4.0 1980-1990 39.8 3.4 54.9 4.5 1970-1990 104.9 3.7 125.4 4.1
, As with KG&E, KCPL has experienced some decline in growth for both peak demand and annual energy and projects for the future a slightly lower rate of growth in peak demand and a slightly higher rate of growth for energy. In 1980, largely because of a summe r heat s to rm, new records were set for peak demand and annual energy. " Normalization" of the 1980 figures above would af fect the comparisons above. KCPL's expected load duration curves for 1984 and 1985 oper-t N_, ation are presented in Figures 1.1-3a and 1.1-3b. Hourly load curves are presented for a typical summer peak day, for the 1980 winter peak day and for a typical spring / fall day ' in Figures 1.1-8, 1.1-9 and 1.1-10. The following tabulation summarizes KEPCo's recent and projected peak demands and annual energy requirements (Table 1.1-14): KEPCO GROWTH IN PEAK DEMAND AND ENERGY Peak Demand Energy Requirements Period Percentage Avg. Annual Percentage Avg. Annual Increase Growth Increase Growth 1971-1975 57.1% 11.9% 30.6% 6.9% 1975-1980 52.0 8.7 63.2 10.3 1971-1980 138.8 10.2 113.1 8.8 1980-1985 36.6 6.4 34.5 6.1 1985-1990 35.1 6.2 33.7 6.0 1980-1990 84.6 6.3 79.9 6.0 1971-1990 340.7 8.1 283.3 7.3 k Note: Actual 1980 data not yet available. l Rev. 1 1.1-12 4/81
WCGS-ER(OLS) l With the exception of 1976 and 1977 for annual energy and l 1977 for summer peak, there has been a continuing high rate of growth. Based on studies made for KEPCo, (Lee, Jan., 1978 and June, 1978), it is believed that the relatively high growth of the past will be sustained. Most of KEPCo's load is in rural areas that are experiencing population gains as well as increased per capita use of energy. 1 1 O f i l O ! Rev. I 1.1-12a 4/81
WCGS-E R(OLS ) KEPCo's expected load duration curve for 1984 and 1985 is l
/ presented in Figure 1.1-4.
To meet increasing demands for peak power and annual energy within their service areas, both KG&E and KCPL have con- ; struction programs - for making additions to their generating l capacities as the needs develop. Historical and planned l additions over the 20 year period described in the above analyses are as follows: (Tables 1.1-4a, 1.1-4b, 1.1-Sa and 1.1-Sb) TWENTY YEAR CHANGES IN GENERATING CAPACITY Accredited Generating Capacity Ten Year Increases in Capacity MW MW Percent Year KG&E KCPL Period KG&E KCPL KG&E KCPL 1970 1151 1686 1970-80 830 1152 72.1 68.3 1980 1981 2838 1980-90 742 323 37.5 11.4 1990 2723 3161
- At time of Summer Peak Between 1970 and 1980 KG&E's installed capacity increased by 830 MW, an increase of 72.1 percent, or an average annual increase of 5.6 percent. In the same decade, KCPL's capa-city increased by 1152 MW, an increase of 68.3 percent, or an average annual increase of 5.3 percent. In the ten year period from 1980 to 1990 KG&E's capacity is scheduled to increase by 742 MW or 37.5 percent, for an average annual increase of 3.2 percent. In the same period KCPL's capacity is scheduled to increase 323 MW or 11.4 percent, for an average annual increase of 1.1 percent.
KEPCo will not have any owned capacity until WCGS is on line in April 1984, when it will have 195.5 MW of generating capacity. In 1986 29.35 MW of low-head hydro capacity is scheduled to be added. Accredited summer capacity changes for the applicants by primary fuel from 1980 to 1990 were and are scheduled to be: l l O V l Rev. 1 0 1.1-13 4/81
~. - - - - - .- ---...--,a--.- r- ---m~ -- w -e--
WCGS-ER(OLS) NET CAPACITY CHANGES, 1980-1990 IN MW Gas Oil Coal Nuclear Hydro Total KG&E -6 -1 +272 +477 0 +742 KCPL 0 -28 -126 +477 0 +323 KEPCo 0 0 0 +196 + 28 +224 O l 1 O Rev. I 1.1-13a 4/81
WCGS-ER(OLS) As adjusted for weather anomalies, KG&E and KCPL anticipate _[o} v slower growth rates in peak load for the decade 1980-90 than were experienced in the pe riod 1970-80. The reasons for a slower rate of growth are primarily load management, conservation and a reduction in demand due to higher prices. Mild summer weather in some years has also slowed the growth in summer peaks. A part of the apparent decline in growth for KG&E is due to the change in reporting of the peak load for KEPCo, discussed above. KEPCo expects its membe rs to add more customers as population migrates from urban to suburban and rural areas which are served by the rural electric cooperatives. The projected growth rates in peak demand for KG&E and KCPL l are lower than those of SPP and NERC, while those for KEPCo are higher. A comparison follows: PROJECTED GROWTH RATES IN PEAK DEMAND l Period. KG&E KCPL KEPCo SPP NERC (US) 1980-85 1.3% 3.1% 6.4% 5.3% 4.3% 1985-90 2.6 3.6 6.2 4.9 4.2 1980-90 2.0 3.4 6.3 5.1 4.2
.O tb Projected growth in annual' energy follows a pattern similar ~l to that for peak load for all of the Applicants. Each pro-jects a continuing growth but at a slower rate than in the past.
1.1.1.2 Demand Projections 1.1.1.2.1 KG&E Method Peak and energy forecasting by KG&E involves a combination of techniques - surveys of present and planned use; extra-polation oi historical use; and analyses of economic condi-
- tiens, population growth, household formation, household i income, industrial development, price of electricity, price and availability of competitive energy sources, and other conside rations for each specific market category. A dis-aggregated approach to markets is taken, with the applica-tions of experienced judgement. The forecast for energy sales is prepared separately for five categories - resi-dential, comme rcial, industrial, street and highway light-
- ing, and sales for resale. Basic assumptions are made that l
apply to all categories, and specific assumptions are made l Om Rev. 1 1.1-14 4/81
WCGS-ER(OLS) that are applicable to individual categories. The general assumptions relate largely to population, economic condi-tions and development. Forecast updates are made at the end of each calendar year, for the following ten year period. 1.1.1.2.1.1 Residential Forecast Residential energy consumption forecasts are based on sta-tistical data collected on population and household sizes and income; saturation trends for major appliances and electric heating, including heat pumps; energy substitution, improved appliance efficiencies; improved thermal condi-tions; decreasing size of dwellings and increasing number of apartments. Customer growth is estimated on the basis of the trends in population growth and the number of persons per household. As shown in Table 1.1-19, the average growth rate for residential customers over the past twelve years has been l 1.9 percent per year, substantially higher than the growth rate of 0.9 percent for population in the Wichita Metropoli-tan Area. Future growth out to 1990 is projected to average 2.5 percent per year. The greater growth in the number of residential customers is attributed largely to a decline in the number of persons per household which contributes to increased household formation, to high employment, and to the growth in apartment living. Consumption of electricity by various classes of residential users is the next consideration. Among the significant classes of users is that of residential electric heating. As shown in Table 1.1-20 KG&E's electric heating customers comprised 13 percent of the total customers at the end of 1980, with steady growth in numbers over the past ten years. This important class of user consumes twice as much electric energy per year as is consumed in homes without electric heating. Because of future uncertainties on the availabil-ity of and the price competition with natural gas, it is necessary to observe this customer class very closely. It appea rs that penetration of the residential home heating-marke t is declining because of competition from gas, which continues to be available at relatively low cost, compared to other fuels. Average annual consumption of energy by all residential customers has grown steadily since 1970, as shown in Table 1.1-21 and is projected to continue to increase but at a slower rate. As shown in Table 1.1-22 residential use accounts for one-fourth of KG&E's total consumption. The i residential share of the total energy market is projected to increase slightly. l The State of Kansas has mandated that new air conditioning equipment and heat pumps must carry a high energy efficiency I Rev. 1 1.1-15 4/81
WCGS-ER(OLS). } rating (EER).- In addition, electric heating may not be introduced into new homes within the jurisdiction of the Kansas Corporation ~ Commission that do not meet prescribed l
. insulation standards. <
l . , o-h i, !I P 1 i 3 F t-
).
a E i i Rev. 1 1.1-15a 4/81
WCGS-ER(OLS) Builders and banks are useful sources for information on the number of housing units planned and being developed. Con-side ration of cons truction trends along with the factors I discussed above permits the development of estimates on residential energy consumption. 1.1.1.2.1.2 Industrial Forecast Major factors conside red in the industrial category are production levels, the price of electricity and the prices and availability of alternative energies. KG&E's major cus-t<imers, accounting for about 78 percent of annual industrial energy consumption, are surveyed periodically, and projec-tions of peak load and energy requirements over the next ten year pe riod are obtained from each customer. Most of the industrial customers are able to provide fairly accurate estimates of their anticipated load and energy requirements over a five year period. It is recognized that the state of the economy and external events may af fect the planning of many of the industries in the KG&E service area. Some of the customers, such as those with grain mill products have energy growth rates that cor-relate generally with regional population growth. The l energy consumption of others involved in petroleum refining, petroleum and gas production, petrochemical production, pipeline transportation snd coal mining depends upon pricing and availability of energy resources, demand for products and recovery techniques. There could be major changes in the requirements of these industries for both capacity and ene rgy, depending upon national energy policies and inter-national petroleum availability. Two problems involved in forecasting energy demands are particula rly related to industry. For rany industry groups an economic recession may mean an abrupt cut-back by a major industrial facility. This may have a significant ef fect on peak loads and on energy consumption. And, in some indus-tries a plant may be put back on line with ve ry little notice. A utility must be prepared for significant swings in load and energy consumption. In planning major new plants or expansions, industry personnel advise a utility of their req uirements several years in ad van ~ce of start-up. Depending upon the size of the plant, this may or may not af fect a r.t ility 's capacity planning. But, there are in-stances in which a utility has planned to accommodate the requirements of a major new plant only to find that because of economic conditions start-up has been delayed for a year or more. That economic conditions clearly play a role in load planning is demonstrated by Table 1,1-24 which shows the changes that have occurred in Kansas and Missouri economic conditions in recent years. i Rev. 1 ( 1.1-16 4/81
WCGS-ER(OLS)
/ The local aircraft industry is doing well at this time but l
( could be adversely af fected if there were a deep and lasting ' recession. Many industrial plants have made all possible cost-effec-tive conservation- modifications and have . installed load control equipment. Although KG&E has an off-peak rate, only five users have- l adopted it. New or expanded - industrial operations may be I i able to make more offective use of the rate. KG&E . has ' no interruptible customers, but it does have a number of ~ continuous process plants in which product would be damaged by service interruptions.- Projected energy and load requirements described by the major industrial users are combined with historical trends j to providt- a basis for forecasting industrial load growth. As shown . in Table 1.1-22 the industrial category has been , the largest for KG&E and is projected to remain so. 1.1.1.2.1.3 Commercial Forecast Commercial projections are developed through conside ration of population and income growth, past trends and the extent to which electricity will be substituted for other energy, considering price and availability. Historically the com-mercial market has lagged both the economy and the growth in population and household income. Continuing surveys are made of the major users in the commercial category - hospi- -
- . tals, major shopping centers, the school systems, colleges, and governmental entities to determine what changes in use are likely to occur and if and when' energy (fuel) switching will take place. The greater than anticipated availability l of natural gas has deterred some switching to electric space heating, but any future reductions in natural gas availabil-ity will affect commercial users before residential users.
Builde rs and banks are visited : regularly to determine what , construction is taking place, what is planned and what the-electrical requirements will be. Attention is also given to the conservation efforts of commercial users.
- All of these factors are considered in projecting commercial usage. Commercial use accounts for about 20 percent of KG&E's ' total consumption. (Table 1.1-22) l
- O Rev. 1 l 1.1 -17 4/81
WCGS-ER(OLS) 1.1.1.2.1.4 Projection of Other Uses "Other uses" than industrial, residential and commercial accounts for less than 18 percent of total consumption. The category "other uses", consists of street and highway light-U. ing and sales for resale. Street and highway lighting represents only about one percent of total consumption and is projected graphically, with adjustments for expansion of urban areas and the increased efficiency of lighting sources. This category is not expected to achieve an in-creased growth rate. The sales for resale category includes sales to rural elec-tric cooperatives, distribution municipals and generating municipals. Growth rate patterns for this group are differ-ent than for KG&E as a whole. Rural electric cooperative requirements have grown faster than those of KG&E while those of the distribution municipals have grown slower. The generating municipals project . a growth rate slightly higher ~ than that for KG&E as a whole. For each of the segments in the sales for resale category individual projections of requirements . arc obtained and conso) ida ted for projection purposes. Changes in supply of energy or in the economics of generation are also taken into account for these estimates. 'It is anticipated that all of the requirements of the distribution municipals served at wholesale by KG&E will be met. The generating municipals are expected to expand their purchases because in most cases their plants burn gas and oil which will become increasingly costly and raay even be unavailable. During peak periods, however, the generating municipals are expected to use their own plants to provide support in meeting peak loads. 1.1.1.2.1.5 Forecast of Peak Demand KG&E demand forecasts are also made annually and based in part upon assumptions similar to those used in making the energy consumption projections. In addition, a procedure has been + developed that approximates the demand fo recas t. This proc edure is based upon several years of observations which have shown that the daily peak loads in April are very steady since they are independent of heating and cooling effects. The total April load , less the industrial load, then becomes a base on which the weather-sensitive load builds. Major industrial loads are steady throughout the year and are very little affected by heating or cooling req uirements. Using the April base, a ratio is established as a measurement of the weather-sensitive portion of KG&E's O Rev. I 1.1-18 4/81 1
~ - - - - - - . . _ _ _ _ _ - - - - . .. .._
+
WCGS-ER(OLS) p =1oads. Conse rvation is considered in that the April base load _ is below the long te rm trend by an amount that is
-t bj realistically assumed to be due to conservation efforts and is so projected into the future. A projected April base is multiplied by a trend in the ratio of peak to April base, _and the projected industrial load, based on survey into rma tion, is : added. to obtain a total system peak demand.
It has been recognized that the difference between a hot and a cool summer can mean a variation of about 5 percent j in the annual system peak. i
.In addition, tests of reasonableness are applied in which
- peak load forecasts are compared with total energy require-ments, and past and projected summer month energy usage data are analyzed to insure internal consistency. 1.1.1.2.1.6 Econometric Model KG&E has-not believed that an econometric model would pro-l- _ vide suf ficiently improved forecasting to justify its cost. There are so many subjective inputs involved in the develop-ment of energy and load forecasts that the sophistication of a more complex approach seemed unlikely to yield greater accuracy or assure more confidence in the results. However, consideration is being given to the development of an econometric/end use model as an additional tool to support the existing methodology.
~
1.1.1.2.2 KCPL Method In past years, KCPL has utilized a disaggregated approach to energy and load forecasting, combining. survey, economic and population data with trends, in much the same manner as KG&E. Recently, however, KCPL has developed an econometric model which is used as a tool in the development of fore-casts of peak loads and annual energy requirements. The model uses historical relationships over time between the demand for electricity - energy and peak - in key months and certain economic factors. Demand and energy projections s developed with the model are based upon statistical analysis
- .of factors that have been shown (or are hypothesized ) to
- influence the demand for electricity. The major factors
, used in the model au population, real income levels, the level of industrial production activity and the real prices l of electricity, natural gas and other fuels. Other variables i used are the number of residential customers, air condition-l ing saturation and FERs, and weather related va riables . 1.1.1.2.2.1 KCPL Econometric Model - In late 1979 an econometric model was adopted as a tool in long term load forecasting. It is recognized in developing ( the model that review, refinement and updating will be re-quired to take into consideration events, developments and policies-that cannot now be accurately measured in terms of ' effect upon demand for electricity. Among these are: Rev. 1 1.1-19 4/81 _ . - - _ . - , _ . . _ . . _ . . ._ . -_. ._. . - , _ , . . . _ . - . - _ . _ . . . _ . . _ . . - ~ . _ . . _ _ _ _ . _ _ _ _ . _ _ _ _ _ . _ _
WCGS-ER(OLS) (1) The uncertainty of the national and inter-national situation with respect to the supply and price of oil; and, I (2) The potential for electro-mechanical control of customer peak use of electric equipmenc as a means for load management which is current-l ly being analyzed. I All projected demands are normalized to adjust for weather anomalies. As a result of extensive study of the econometric model projections and discussion by the key executives and offices of the Company, it was decided that the official KCPL long-term forecast for 1980-1990 would be a 3.6 percent l compound growth in net system peak and a 4.0 percent com-pound growth in energy sales. Projected peak loads and annual energy are . given in Table 1.1-13. The projections also take into account the provi- l sion for an up-to-100 MW curtailment of load for Armco. The major assumptions used in simulating t5 econometric model are as follows:
- 1. The long-term real price of electricity is assumed to increase at 0% annually for the demand forecast and decline at 1% annually for the energy scenario. The rationale be-hind the dichotomy in energy and demand price growth is based on the current rate making philosophies which are shifting more of the cost of electricity into the on-peak periods.
The increase in' the real price of energy is expected to be less than the general rate of inflation because demand conservation will result in an improved load factor causing a downward pressure on the per unit cost of energy. Price assumptions used in the fore-cast are based on analysis of KCPL 's corpo-rate planning model results. O Rev. 1 1.1-20 4/81
WCGS-ER(OLS) , 73 2. According to the Natural Gas Policy Act of 1978 (H.R. 5289, P.L. 95-621), a portion of ('v) the National Energy Plan, the ceiling price of "new" natural gas, as defined by the Act, will gradually be allowed to rise according to an established formula until January 1, 1985, when price controls would be removed. Based on the estimates of Price Waterhouse, and Company, Data Resources, Inc., and the Electric Power Research Institute, it is projected that the "most likely" scenario for real natural gas price increases will be 4% annually for 1979-1985, 7.5% from 1985-1990, g and 1.6% thereafter.
- 3. Total real income, real income pe r capita, and industrial activity are projected to increase at 2.7%, 1.8%, and 3.2% respective-ly over the long term. These estimates were
- either supplied directly or derived from macroeconomic projections from the March 1979 Wharton Econometric Model and the population projections explained below.
- 4. Population projections provided by the Uni-versity of Missouri call for a compound growth rate of .45% in the Missouri portion s
" ) of the Kansas City SMSA (Clay, Jackson, and Platte Counties) served by KCPL. This rather low population growth rate is related pri-marily to the expected population decreases i in Jackson County through 1990. The popula- I tion of Johnson County Kansas is projected to increase at a 1.7% compounded yea rly rate from 1980-2010. These estimates were sup-plied by the Johnson County Community College.
A discussion follows of the additional factors that were considered in developing the econometric model. The KCPL service area encompasses portions of both Missouri and Kansas, but there are extreme dif ferences in the social, l population and economic characteristics of the two states. l The Missouri portion of the service area can best be viewed as a mature urban-economic area. There is a well establish-ed industrial base with 70% of Missouri industrial KWH sales being made to the durable goods production sector. In recent years, the Kansas City, Missouri central city area l has experienced a net out-migration through population shift l to the suburbs. The reduction in population levels has caused a corresponding loss of commercial customers in the
/ central city area. To complicate matte rs further, the l
( )) majority of the high growth areas on the Missouri side of the Kansas City SMSA are within the service areas of neigh-l l boring utilities. ; Rev. I I 1.1-21 4/81
I WCGS-ER(OLS) In contrast, the Kansas portion of the service area can be characterized as an economic area still in the development state. In the early 1960's, this area was primarily a l " bedroom" community with little industrial activity of its own. It was characterized by very high rates of population growth and high income levels which continue today. More recently, the area has been characterized by rapid growth in the commercial sector with the construction of shopping centers and office buildings. The industrial sector, stimu-lated by incentives such as a "right to work" law, a developing labor force, government issued revenue bonds and certain tax benefits is beginning to develop. l Because of the9e structural and economic differences between the two states, accurate modeling and forecast results re-quired that energy sales be modeled by state. Energy sales to Kansas customers are expected to grow at a faster rate than sales to Missouri customers. This is a direct result of the high 1cvels of population growth and economic development now being experienced and expected to continue in Kansas. l Ilousehold size in all portions of the SMSA is projected to continue its decline of recent years. Ilousehold size in Jackson and 21ay Counties is projected to decrease from approximately 2.6 Pe rsons/Ilousehold in 1979 to 2.2 Persons / Ilousehold in 2010. Johnson County household size is pro-jected to decrease from 3.0 to 2.4 Persons /Ilousehold over the same period. Decreasing household size implies a great-er number of residential custome rs for a given population level. Sensitivity analyses were conducted on both the energy and demand models using various high and low growth scenarios for the driving va riables . The growth range produced for the energy forecast is from 1.6 percent fo 4.5 percent and the growth range for the demand forecast is from 1.7 percent to 5.5 percent. The table below summarizes projected energy growth rates by state, by sector, and in total over the period from 1980 to l 2010. O Rev. I 1.1-22 4/81
._. . -. _. .~.
d WCGS-ER(OLS)- O PROJECTED ENERGY GROWTH RATES BY STATE AND SECTOR 1980 - 2010 l Missouri Kansas Total KCPL Residential 4.0% 4.4% 4.1% Commercial 2.4 5.6 3.5 Industrial 2.5 6.5 3.1 Other 3.1 4.5 3.4 Average 2.9% 5.2% 3.6% The percentage breakdown of total KCPL Kwh sales among the various sales classifications for the past five years is shown below. KCPL KWH SALES Industrial 27% Commercial 39 i Residential 29 i Other 5
/~ Total 100%
Cus tome rs in each of these sectors use electricity for different reasons. Industrial customers use electricity in ! the manufacturing process for such things as machinery drive, process heating, furnaces and environmental equipment applications. Commercial customers typically use electri-city in lighting, heating, refrigeration, air conditioning, and specialized appliance use. However, the commercial class is a broad class with considerable heterogeneity of end uses (e.g., supe rma rkets, offices, schools, gas sta-tions, cable TV amplifiers, traffic signals). As a result, there are very diverse usage patterns which are different from those of other sales clatsifications. The residential sector, though, is relatively homogeneous, with custome rs using electricity for the same purposes -- lighting, cooking, heating, cooling, and operating various i appliances. To the extent differences in usage levels among households exist, they are not so extreme as in other classes and can be accounted for by proper model specifica-tion. l lO [ Rev. 1 l l 1.1-23 4/81 L \ _
i WCGS-ER(OLS) Because of the differing usage patterns, each sales classi-fication has been modeled separately in order to isolate l those factors that exert a level of influence on sales in one sector and a different level or no influence in other Se ctors . The net system peak demand was modeled on a total company basis due to the lack of historical demand data by class. The structure of the forecast is shown in Figure 1.1-11. All energy modeling was done on an of f-calendar year, semi-annual basis using the pe riods October through March and April through September to facilitate the estimation of weather effects upon sales levels. Demand modeling was based on peak demands during the months of July and August when there is the greatest probability of a system peak occurring. , The data base was developed as follows:
- 1. Semi-annual data bases from 1967-1979 were l developed for each of the sales classifica-tions, residential, commercial, industrial, etc. Sales and customer statistics were taken from KCPL billing records, annual reports, and appliance surveys.
- 2. Production indices were provided by the Kansas City Federal Reserve Board.
- 3. The U.S. Department of Labor supplied price index information, and the Gas Service Company of Kansas City , Missouri, supplied local gas price information.
- 4. Historical and projected population estimates were provided by the U.S. Census Bureau, the University of Missouri, and the Johnson County Community College.
- 5. Weather data were obtained from the National Oceanic and Atmospheric Administration.
- 6. Income and household size data were obtained from Sales and Marketing Management Magazine.
- 7. Typical electric bills used in all the model estimations were derived from KCPL's tariff and load research data. All typical bills include any applicable fuel adj ustments or fuel su rcharges and were calcula ted at fixed demand and energy levels.
Rev. 1 1.1-24 4/81
WCGS-ER(OLS) f'~N 8. Wharton Econometric Forecasting Associates l was the source of projections of national (V) economic va riables that are used as driving variables in the majority of the service area models. The March 1979 Wharton Model was used as a source for Federal Reserve Board (FRB) production indices and income per capita projections. The FRB Production Index is projected to increase at 3.3% through 1989. Real per capita income is projected t.o grow at 1.8% through 1989.
- 9. The natural gas price projections were based upon information supplied by the Electric Power Research Institute, Price Waterhouse and Compa ny, and Data Resources, Inc., and assume deregulation by 1985, pursuant to the National Energy Act. l
- 10. All simulations are weather normalized.
Weather normalized energy sales estimates were obtained by using long-run (42-year) l ave rages for cooling and heating degree days in model simulations. The average cooling degree hours for the peak day and the pre- , vious three days used in the demand model were averaged over the historical data-base g period to establish a normal level. S tatistical testing procedures were developed as follows:
- 1. A criterion was set that all driving or independent variables must pass statistical significance tests indicating a high proba-bility that they have an effect different from zero upon the dependent va riable in question' (e.g., KWH, KW, custome rs ) . The mathematical sign associated with any parti-cular independent variable coefficient was required to conform with a priori economic theory. In some cases where the estimated coef ficient was strongly confirmed by theory, but the associated significance level of the coef ficient was questionable, the independent variable was kept in the model, g.
f k V Rev. 1 1.1-25 4/81
l WCGS-ER(OLS)
- 2. A secondary check 'on independent variables was undertaken to ensure that the associated coefficients were of a proper magnitude (i.e., that observed by other researche rs ) .
- 3. Tests were conducted on each model for the presence of severe autocorrelation, and cor-rections were made if required.
1.1.1.2.2.2 Industrial Forecast In order to demonstrate the principles of the econometric model, the methodology for the industrial catego ry is de-scribed in detail. The other categories are described in general. Industrial KWH sales in Missouri have accounted for approxi-mately 33 percent of total Missouri KWH sales in recent years. One large cu stomer, Armco Steel, typically accounts for more than 35 percent of Missouri Industrial sales and for this reason, Armco KWH usage was projected independently of other Missouri industrial sales. The model for the' industrial class hypothesizes that sales are a function of the level of industrial output, the price of electricity and the price of competitive fuels. As a means of analyzing industrial electricity consumption as it relates to real physical output, the Federal Reserve Board Production index was used as a proxy for localized output in lieu of a suitable localized production index. Since electricity is used as a factor input in the indus-trial process for such things as machinery drive, process heat, etc., it is an obvious assumption that as the level of production increases or decreases, electricity consumption should do likewise. It is also assumed that the industrial consumption of electricity is price sensitive both to electric prices and the price of energy alternatives. This price elasticity ef fect will manifest itself in terms of either conservation or substitution effects and is measured in terms of its own clasticity, cross elasticity, or combined elasticity. Implicit within the industrial model described below are certain technological changes contained in the historic data i and, consequently, certain technological changes are im-plicitly incorporated within the forecast itself. The model derived for the Missouri Industrial Sales classi-fication is: O Rev. 1 1.1-26 4/81
WCGS-ER(OLS) A DEPENDENT VARIABLE: LMIKWH Right Hand Estimated Standard "T" l Variable Coef ficien_t Error- Statistic , C 19.988 .933 21.4 LSFRB .522 .083 6.3 PZ .200 .050 -4.0 SEAS .068 .008 8.0 DDCUS .037 .013 2.8 PPZ .006 .001 -4.1 R = .968 R = .957 DW = 2.00 C = Constant R = Coefficient of Determination R =R Adjusted LMIKWH = Log (Mjssouri Industrial Sales Excluding Armco)
\ LSFRB = Log (FRB Production Index)
PZ = Log (Real Price of Electricity /Real Price of Gas Fuels) SEAS = Seasonal Production Variable DDCUS = Dummy to Account for Customer Reclassification in 1970 PPZ = PZ Subsequent to 1973 Oil Embargo, O Otherwise (Test for changing price elasticity) All Log values referenced in this documentation are natural logs The va riable PZ is the ratio of electric price to gas price and as "such represents a combined price elasticity for both gas and electricity. A rmco Steel is involved in the production of wire, wire
. rope, steel products and ingots. Future yea rly estimates of electric usages to 1983 were obtained from Armco and reflect greater intensity of future use. Alternative modeling ef forts were undertaken to analyze the relation cf Armco usage to external production indices. These models showed that there has been a historical relationship between l the FRB durable index and Armco usage, but because of the l \ nature of the large discrete Armco load additions, the models were judged to have relatively low explanatory power. After analyzing a detailed survey questionnaire l
Rev. 1 1.1-27 4/81
i 4 WCGS-ER(OLS) answered by Armco, the forecast supplied by Arn.co, and applying judgment, it was concluded that subsequent to 1983 ' Armco usage would increase by 2 percent per year. O l l l W. 1 1.1-27a 4/81
WCGS-ER(OLS) ['N The independent va riable assumptions described above were (U) used to simulate the industrial model and were combined with results based on the Armco estimates. As a followup to the statistical portion of the forecast, a customer survey was completed by approximately 34 la rge industrial customers. Analysis of the survey indicates I that a significant amount of the growth in the near future as in the recent past, will come in the form of environmen-tal protection devices. To investigate further the other effects environmental constraints may have on industrial growth, officials were interviewed in the Environmental Pro-tection Agency (EPA) and the Mid-American Regional Council (MARC). The Kansas portion of the Kansas City area is l presently under a new' industrial construction moratorium ordered by the EPA. Iloweve r, conditional approval for the Kansas air quality control plan is expected sometime in early 1981. Conditional approval of the Kansas plan will allow the resumption of industrial construction activity. All industrial pe rmits submitted prior to July 1, 1979 are permitted to go ahead with construction so the effect on industrial construction is expected to be minimal if condi-tional approval of the Kansas plan is given as expected. l The MARC did not feel that meeting these standa rds would present much of a problem for industrial growth in this area v
] at the present time and cited the fact that, in comparison with other cities, the Kansas City area does not seem to be in bad shape. It was noted, however, that high-pollution industrial growth such as the construction of power plants in the metropolitan area would definitely present problems.
I It is noted that environmental constraints may come into play that could reduce future KWH consumption levels below what the models are now projecting. In particular, this may be the case in such industries as primary metals, chemicals and petroleum products. 1 1 Another important point developed by the survey is that many firms have implemented an energy conservation program. There remains pctential for further conservation efforts, but a portion of the historical data analyzed for the forecast was obtained during a pe riod of time when these conservation programs were in place, and their effect is implicitly assumed in future projections. ! Rev. 1 1.1-28 4/81
WCGS-ER(OLS) A description of the methodology used in developing the Kansas industrial forecast follows: l l The majority of the assumptions used in modeling the Kansas sales classifications are the same as those detailed in the section on the Missouri energy forecast. Redundant explana-tions are omitted from the Kansas energy forecast explana-tion. l Industrial KWH sales in Kansas have accounted for approxi-l mately 9.0 percent of total Kansas sales in recent years and l have shown dramatic growth over the historical period anal-yzed. The industrial base was so small that the addition of new industrial customers rbsulted in extrdmely high percent-age growth rates. Efforts by governmental and private sectors in Kansas to promote industrial development are described below:
- 1) The Kansas Right-to-Work law guarantees all workers the freedom to choose a union or non-union shop. Only 15 percent of the non- l agricultural labor force is union affiliated.
- 2) Tax-Exempt Industrial Revenue Bonds are issued by municipalities for the purpose of purchasing land, cons tructing buildings and equipment for lease and eventual sale. Users of this method of financing are exempt from ad valorem taxes for a period of ten years.
The cost of the building and all pe rmanent fixtures are exempt from the state sales tax.
- 3) The attitude of the state government in en-couraging industrial expansion is reflected by the Job Expansion and Credit Act which per-mits a credit against state income tax for ten years, based upon the numbe r of jobs created and the amount of investment up to a maximum reduction of 50 percent. l
- 4) The Kansas Freeport Law exempts from taxation all pe rsonal property, moving through the state or consigned to a warehouse from a point out s ide the state, which is in transit to a final destination outside Kansas. Goods manu- )
factured in-state, stored in a bonded ware- i house are also tax exempt if over 35 percent l i of the preceding year's shipments went out of state. l Rev. 1 3.1-29 4/81 l
WCGS-ER(OLS, (O b)
- 5) Pealtors in Kansas have developed excellent Industrial' Parks in Johnson County, Kansas with land readily available for industrial sites, complete with speculative buildings and rail facilities.
It should also be noted that the high population growth in Johnson County has made a large, diversified and well trained labor force available to prospective industrial employers. As in Missouri, there is one relatively large industrial customer, Pittsburg & Midway (P&M) Coal Mining Company, which accounts for roughly 6 percent of Kansas industrial l sales. A special set of circumstances surrounds P&M Mining in that it has a " captive" customer, and its sole function is to supply coal for 'the La Cygne No. 1 generating unit. For this reason, P&M electrical usage was projected inde-pendently of other Kansas industrial KWH sales. The model derived for the Kansas Industrial Sales (excluding the P&M Mining) classification is: DEPENDENT VARIABLE: LKIKWH h Right Hand Estimated Standard "T" d Variable Coefficient Error Statistic C 16.347 1.522 10.7 LSFRB 1.099 .289 3.8 LRKP .946 .210 -4.5 LKGAS .552 .081 6.8 DDCUS .400 .064 6.3 R = .991 2 5 = .989 DW = 1.99 f C = Constant i R = Coefficient of Determination R =R Adjusted LKIKWH = Log (Kansas Industrial Sales Excluding l Pittsburg & Midway Mining Kwh) LSFRB = Log (FRB Production Index) LRKP = Log (Real Price of Electricity) LKGAS = Log (Real Price of Gas Fuels Variable) l DDCUS = Dummy Variable to Account for Customer ! / Reclassification in 1970 Rev. I 1.1-30 4/81
WCGS-ER(OLS) For P&M a relationship was developed that related electri- l city used at the mine to the tons of coal burned at La Cygne No. 1. Using KCPL's fuel budge t fo r future years at La Cygne No. 1, projections of electric sales to the mine were made. It is estimated that the P&M mine will use approxi-mately 20,000 MWH per year in the foreseeable future. It should be stressed that the long-term level of usage is necessarily limited by the amount of recoverable coal in the ground. The simulation results of the Kansas industrial model were combined with the P&M estimates to yield the total Kansas industrial KWH forecast. As shown in Table 1.1-22, industrial use is expected to decline slightly as a percentage of total consumption. 1.1.1.2.2.3 Commercial Forecast Total commercial sales of electricity have accounted for approximately 39 percent of Missouri and Kansas sales in l recent yea rs . Table 1.1-22 indicates that commercial sales a re expected to decline slightly as a percentage of total sales over the next ten years. Factors specifically conside red in the commercial models were: (1) Commercial activity and KWH usage which have been shown to be positively related to the level of total real income in a given area. The effects of population and population density upon commercial KWH consumption are implicitly considered through the use of the total real income independent va riable ; (2) Price clasticities for electricity and gas fuels which are estimated in each commercial model. (3) Cooling degree days, which are positively related to level of usage because of the high level of comme rcial air conditioning loads and the fact that as temperature rises in-creasingly high loads are placed on the system. Separate statistical models were developed for Missouri and Ka nsas . l l 9 Rev. I 1.1-31 4/81
WCGS-ER(OLS) I
. q 1.1.1.2.2.4 Residential Forecast t
i In recent years residential sales have accounted for about 23 percent of Missouri energy . sales and over 40 percent of l Kansas energy- sales. As shown in Table 1.1-22 overall i residential- energy sales are expected to increase as a percentage of total KCPL sales. Because the residential category is more homogeneous, it is better suited to economic analysis than the other cate-i gories. Analysis can proceed almost directly in conformance with a standard set of economic assumptions regarding income, prices and weather. Modeling methodologies are based on determing the number of customers and the average level of use. The number of customers is a function of population and household size, and these numbers were model-ed .on a county by county basis in both Missouri and Kansas, using available population data, historic relationships
- between population and customers and regression and time trend analysis. Average use was estimated by analyzing income levels, ' appliance saturation, energy prices, and the l intensity of use and the efficiency of the appliances and equipment. For heating and cooling equipment the severity of weather largely determines intensity of use. Projections were weather normalized to remove this effect. Electrical appliances and equipment saturation studies have provided data on - trends for va rious types of household equipment.
Price elasticity was also analyzed for its effect upon intensity of use. 1.1.1.2.2.5 Other Forecasts Detailed analyses were made of other classifications such as traffic signals, street lighting, public authorities, and sales for resale. Each classification was modeled if data permitted, or sales were projected on the basis of historical sales analysis and judgmental trending. 1.1.1.2.3 KEPCo Method
- The KEPCo projections for peak load and annual energy (Table i 1.1-14) are based on the April 1977 Power Requirements Study l (PRS) of KEPCo and its member systems. Each of the 26 dis-tribution member cooperatives prepared an individual PRS l which was based on a thorough review - of the existing and potential needs of the system. KEPCo's PRS was prepared in
- I accordance with REA Bulletin No. 120.1. System manage rs developed growth projections with consideration to the l following factors:
Rev. 1 1.1-32 4/81 _e_ - - , __-..m_.,,..-..._,-..,._,..-,,-,%-m-,-,, v. , -,,e.m,m.....~r,.m__,.,m-._,y.,-.,,.,.-,,,,,.,,..,w-r- .y,_m..__ , , . ,,,.m.
1 WCGS-ER(OLS) O In the 1978 analyses of the projections made by the coopern-tives (Lee, 1978), it was further concluded that deviations in 197 7 - f rom ' the 1976 projections were due to abnormal weather conditions and temporary changes in the local econo- I mies. l 1.1.1.2.4 Recent Growth History Recent and projected average annual growth rates based on Tables . 1.1-12, 1.1-13 and 1.1-14 are shown ,below for- the three utilities. These growth rates were discussed in Section 1.1.1.1. The areas in Kansas and Missouri served by the Applicants experienced one of the hottest summers in history in 1980. During a July heat storm temperatures in Kansas C l.ty were . above 100 F on 22 days; on 17 consecutive days temg/atures ranged between 102 F and 109 F. Both KG&E and KCPL set new records for peak demand. The new peaks were 17.2 percent higher than the 1979 peak demand for KG&E and 11.9 percent hi@er for KCPL. New records were also set for annual con-sumption of energy. AVERAGE ANNUAL GROWTH IN PEAK DEMAND AND ENERGY Peak Demand Energy Consumption Time Period KG&E KCPL KEPCo KG&E KCPL KEPCo 1970-1975 4.4% 4.9% 11.9% 5.5% 4.4% 6.9% 1975-1980 5.3 2.9 8.7 4.7 3.2 10.3, 1970-1980 4.8 3.9 10.2 5.1 3.8 8.8 1980-1985 1.3 3.1 6.4 0.5 4.9 6.1 1 1985-1990 2.6 3.6 6.2 3.2 4.0 6.0 1980-1990 2.0 3.4 6.3 1.8 4.5 6.0 1970-1990 3.4 3.7 8.1 3.5 4.1 7.3
- From 1971 If the comparisons were modified to reflect " normalized" 1980 demand and energy (adj usted for weather anomalies) those based on 1980 would change. The historical compari-sons would be lower and the projections higher; but not significantly.
The projected growth rates in peak demand for both KG&E and KCPL are below those of SPP . and NERC. SPP projects a
-regional growth rate of 5.1 percent and NERC a growth of 4.2 percent for the United States in the period 1980-1990. In 1978 the Department of Energy developed a forecast O December, of growth in summer peak demand of 4.9 percent for the U.S.
in the pe riod 1979-97 (Department of Energy, 1978). It is I Rev. 1 1.1-35 4/81
WCGS-ER(OLS) , believed that the estimates by KG&E and KCPL are conserva- l tive, particula *1y for KG&E which is in an area of low unemployment. The decline in annual energy and peak load growth experienced and projected can be attributed both to conservation efforts and to higher prices for electrical energy. Energy consumption is more likely to be affected :by price increases than peak loads. During summer periods of extreme heat, such as in 1980, air conditioning is univers- l ally used, regardless of price, whereas on more moderate days some of the air conditioning may not be used. The same applies to periods of extremely cold weather for those who use electric space heating. O O Rev. 1 1.1-35a 4/81
WCGS-ER(OLS) g Customers of the Applicants have been given a negative (n) V' stimulus in the form of rising prices that should have in-hibited consumption and encouraged conservation. Table 1.1-23 shows the changes that have occured since petroleum shortages firs t occured and prices began to rise rapidly. In the period 1972 to 1980, average prices per KWH more than l doubled for each category of user, with industrial use rs experiencing the largest unit increases. The escalation of rates for KG&E over the last 8 years has averaged 15.6 l percent per year for industrial, 11.1 percent for commercial ! and 11.1 percent for residential users. KCPL's unit rates have risen similiarly, but they were substantially higher than KG&E's rates in 1973 and continue to be slightly higher. j KCPL's rates have risen at an average annual rate of 14.4 l pe rcent for industrial, 11.5 percent for commercial and 10.7 percent for residential users. The rates of increase over the past few years for KEPCo members have been higher than for KG&E and KCPL, with an average annual increase of 14.6 percent for indus trial / comme rcic1, 16.6 percent for irriga-tion and 13.6 percent for residential. From 1972 to' 198 0, a period of high rates of increase in l costs for boiler fuels and consequently for electrical e ne rgy, KG&E increased the number of residential customers served by nearly 21 percent and KCPL by 13 percent. From 1974 to 1980 KEPCo's ave rag' number of cus tomers increased
/m by 12 percent. (See Tab:e 1.1-19) As shown in Table (v ) 1.1-21, average annual use by residential customers in the period 1972 to 1980 has increased 36 percent for KG&E and 21 percent for KCPL. From 1974 to 1980, KEPCo's average annual use by residential customers increased 45 percent.
Despite the dramatic increases in rates, customer use has
- continued to grow. Much of this increase in average con-sumption is due to the large number of homes with electric space heating. But, as shown in Table 1.1-20, even homes I without electrical space heating showed an increase of 20 percent for KCPL and 31 percent for KG&E in average annual consumption from 1972 to 1980.
Comparisons of forecast and actual peak loads and energy for KG&E and KCPL are provided in Tables 1.1-25 and 1.1-26. Despite the great uncertainties due to weather, both utilities have been remarkably accurate in predicting short range 1 cads ar.d energy. 7 4
\. h v
Rev. I 1.1-36 4/81
WCGS-ER(OLS) 1.1.1.3 Power Exchanges , l Table J.1-18 presents a statement of system operations for (' both KG&E and KCPL at peak hour conditions for the part 8 summer pe ak s . Over the past 8 years net interchanges by KG&E at the time of peak load never exceeded 10 percent of the peak load except in 1980, but firm and emergency pur- l chases frequently ranged from 22 to 49 percent of the net i load. Emergency sales were as high as 20 to 29 percent of l the net load. KCPL's net interchanges were as high as 20 I percent of the net load due to relatively high receipts of I non-firm power, amounting to as much as 28 percent of the ! net load. As shown in Tables 1.1-1 and 1.1-2 KG&E and KCPL plan to make capacity purchases and sales in the future. The purchases and sales in MW at the time of peak load ~ for the period 1973 to 1980 (See Table 1.1-18) were as follows: l PEAK LOAD PURCHASES AND SALES (MW) KG&E KCPL Year Purchases Sales Purchases Sales 1973 260 167 290 213 1974 190 109 395 35 1975 357 292 291 9S 1976 673 537 608 258 1977 523 642 714 55 1978 147 154 621 9h 1979 345 260 465 202 1980 548 279 570 549 ( KG&E and KCPL have generally been net purchasers at the time of the peak load. As membe rs of SPP and MOKAN, KG&E and KCPL will continue to make short term sales in order to adhere to their reliability agreements and to ethance the economy and reliability of operations. KEPCo now relies upon purchased power to meet all of its l needs and will still be meeting most of its requirements through purcha'es even after WCGS is on line. Anticipated interchange budgets are provided in Tables 1.1-27, 1.1-28 and 1.1-29 for the first two years of WCGS operation. KG&E and KCPL expect to sell more energy than , they purchase when WCGS is in operation. l l KG&E and KCPL maintain interconnections with other utili- l ties as follows: Rev. 1 1.1-37 4/91 l
WCGS-ER(OLS)
. /] ,
(V ! SYSTEM INTERCONNECTIONS KG&E 345-kV - Associated Electric Cooperative, Inc. and Union Electric Co. 161-kV - Empire District Electric Co. (3) 345-kV - Kansas City Power & Light Co. (2) 161-kV - Kansas City Power & Light Co. 345-kV - Kansas Power and Light Co. 138/115-kV - Kansas Power and Light Co. 161-kV - Kansas Power and Light Co. and Omaha Public Power District 345-kV - Oklahoma Gas and Electric Company 138-kV - Oklahoma Gas and Electric Company 345-kV - Public Service Organization of Oklahoma 138-kV - Public Service Organization of Oklahoma 138-kV - Western Power Division of Central Tele-phone & Utilities Corp. KCPL 161-kV - Associated Electric Cooperative Inc. 161-kV - Board of Public Utilities
'N 345-kV - Iowa Public Service Co.
,) 345-kV - Interstate Power Co.
345-kV - Kansas Gas and Electric Company (2) 161-kV - Kansas Gas and Electric Company 345-kV - Kansas Power & Light Co. 161-kV - Kansas Power h Light Co. 161-kV - Missouri Power & Light Co. 345-kV - Missouri Public Service Co. (2) 161-kV - Missouri Public Service Co. 345-kV - Northern States Power Co. 345-kV - Omaha Public Power District 345-kV - St. Joseph Light & Power Co. (2) l 161-kV - St. Joseph Light & Power Co. 161-kV - Southwestern Power Administration 345-kV - Union Electric Co. 161-kV - Union Electric Co. 1.1.2 SYSTEM CAPACITY KG&E and KCPL participate in interchange . agreements, but each utility is responsible for planning and c.rranging its own power supply and for the adequacy and reliability of its own generation system. KEPCo will participate in inter-change agreements when it has capacity and has become a member of SPP and MOKAN. O) ( v Rev. 1 1.1-38 4/81
l WCGS-ER(OLS) , I KG&E and KCPL maintain ten year peak load and energy fore-cast and generation schedules to determine when capacity additions will be needed and to insure that adequate margins are provided. These schedules are reviewed annually and more frequently if advisable in order to assess what kind of capacity may be required and the lead times necessary to develop the capacity. Projected fuel costs and availability and the financing of future capacity are important f acto rs in developing long-range plans for expansion. Units sel-ected for capacity additions are those that are judged to be the most cost-ef fective in meeting future needs, considering fuel constraints. - KEPCo's first capacity was 30 MW of hydro peaking power pur-chased from the SPA under a long-term contract which began in 1980. The first owned capacity will be the 195.5 MW from ' WCGS in 1984. Two low-head hydro plants are to be added in 1986, with a total capacity of 29.35 MW. As with the other Applicants, KEPCo maintains peak load and energy forecast schedules in its planning process. Its long-term objective is to own all capacity required to serve the needs of its membe rs . Tables 1.1-4a and 1.1-Sa present for KG&E and KCPL the in-stalled capacities by plant and unit for the period 1974-1992. Actual and proposed capacity changes are shown in l Tables 1.1-4b and 1.1-5b. Load and capability data for KG&E and KCPL over the period 1965-1990 are given in Tables 1.1-1 and 1.1-2. Similar data are provided over the period 1971-1995 for KEPCo in Table l 1.1-3. Each of these three tables shows peak and system responsibility, accredited and system capacity and capacity balance, the latter both with and without WCGS. Without WCGS each company will suffer deficiencies in its capacity balance. Table 1.1-7a presents load and capability data for the SPP for the period 1965-1977, and Table 1.1-7b provides a com-parison of forecast and actual capability for the pe riod 1971-1980. Of particular interest in the latter table is l the fact that, because of forced outages, in all but two of the ten yea rs shown, the actual operating margins at the l times of summer peak loads were lower than those fo reca s t . In six of those yea rs the actual operating margins were i below the SPP margin requirement of 15 percent as a result of the forced outages. SPP monthly energy and peak loads are given in Table 1.1-8 for the years 1978-1981, and both seasonal loads and annual ener y are given for 1978 and 1979 and projected for 1980-1989. SPP projects a growth rate of 5.3 percent for both summer peak loads and annual energy over the pe riod 1980-1989. Rev 1 1.1-39 4/81
-a i
WCGS-ER(OLS)~ Table 1.1-9 presents SPP projected resources, demand and i O margins for the period 1989-1989. summer peaks are above 20 percent until af ter 1987 when they decline to 19.8 percent in 1988 and 19.1 percent in 1989. The margins shown for
.It should be noted, however, that these margins are based upon the assumption that planned capacity additions will be built on time. It i's likely that many of the additions will -
be delayed and that some may be cancelled, particularly . in l the latter part of . the 1980's. As a result, the margins given are optimistic. The addition of the 1150 MW of WCGS capacity (KEPCo plans to join SPP) will account for 1.9 per-
- . cent- of the projected summer net capability of SPP in 1984.
A longer term SPP forecast for the period 1990-1999 is given in Table 1.1-10. This table shows margins remaining above , the 15 percent SPP requirement - over that time period. How-ever, nearly all of the capacity additions projected for this period are shown as fossil or " unknown energy source", l and there is doubt that some of these facilities will be built or that many will be completed on schedule.
- MOKAN load and capability dat'a for the period 1971-1988 are shown in Table 1.1-11. The capacity balances of MOKAN will I j
be negative in 1986 without-WCGS. l , Peak hour conditions in the systems of KG&E and KCPL for the period 1973-1980 are given in Table 1.1-18 and discussed in l [ Section 1.1.1.3. Over this period KG&E was generally a net purchaser of amounts ranging from 4 to 18 percent of its net l . ; load except in 1977 when it sold 7.5 percent of its genera-tion and in 1978 when there was virtually no net inter-change. For the entire period shown KCPL was a net pur-chaser of power in amounts ranging from 4.5 to 28 percent of j its net load. i , 1.1.2.1 Capacity Planning j Capacity planning by KG&E and KCPL must be closely related to the availability of fuels. Table 1.1-15 shows the major shifts that have taken place in fuel mix and those that are contemplated. In 1970 KG&E had no coal capacity, and 99.5 percent of its energy . production was fueled by ga s. In 1975 gas accounted for 66.8 percent cf production, coal for 18.3 and oil for 14. 9. In 1980 coal accounted for 49.4 : percent of production, gas for 48.7 and oil for 1.9 percent. By 1990 with diversification into nuclear fuel the use of gas will decline to be tween 13 and 16 percent, coal will account for 56.1 percent of energy production and oil for , i L t j Rev. 1 l 1.1-40 4/81
WCGS-En(oLS ) about 2 percent. Nuclear will provide between 25 and 29 l percent of the annual not generation. KCPL will remain pro-dominantly a coal fueled utility, but its 1980 dependence on coal for 93.5 percent of generation will decline to 71.5 l pe rcent in 1990, and gas, which provided 30.7 percent of the generation in 1970, will decline to 0.1 percent by 1985, with WCGS in operation. Oil use which was insignificant in 1970 was 4.0 percent in 1975 and is expected to provide be-tween 2 and 3 percent of ge neration in 1990 when nuclear will account for 23 to 26 percent of generation. The contribution of WCGS to diversification of fuel sources l is shown in Table 1.1-30 which providea the projected fuel mix for the first three years of planned operation both with and without WCGS. Without WCGS much greater reliance must ba placed upon gas and oil by KG&E and on coal by KCPL. The importance of WCGS to peak day operations is illustrated in Table 1.1-31. In 1985 WCGS should provide 27 percent of KG&E's peak day generation. Without WCGS, gas, oil and purchases would make up most of the difference. For MCPL, WCGS would provide 13.3 percent of the peak day production in 1985 and 22.8 percent in 1990. Without WCGS the dif fer-ence would be made up by purchases and by additional con-sumption of oil. The situation would be similar for both companies in 1990. For both companies it is assumed that purchases would be possible, which may not be the case. Major capacity additions under construction or being planned or considered by KG&E and KCPL are as follows: CAPACITY ADDITIONS KG&E Season or Month and Year Unit Function Fuel Capacity - MW Spring 1983 Jeffrey No. 3 Base Coal 136 April 1984 WCGS , Base Nuclear 477 Spring 1986 Jeffrey No. 4 Base Coal 136 Jef frey units will be operated by Kansas Power and Light; KG&E will have a 20 percent shnre of each. O Rev. 1 1.1-41 4/81
WCGS-ER(OLS)
/9 CAPACITY ADDITIONS KCPL
{l Month and Year Unit Function Fuel Capacity MW April 1984 WCGS Base Nuclear 477 March 1991 Unspecified Base Coal 455 As a means of increasing reliability, diversifying fuel mix and developing a gradual build-up in generating capacity, KG&E has acquired and plans to acquire a 20 percent interest in each unit of the Jeffrey Energy Center. Two 680 MW units have been completed, each of which provides KG&E with 136 MW of base . load generation capacity. Two additional 680 MW units are under construction or planned, e.ach of which will provide KG&E with additions of 136 MW of base load gener-ating capacity in 1983 and 1986. WCGS will provide 477 MW in 1984. KCPL is relying on WCGS to help meet projected load demands in 1984 and beyond. In addition, 455 MW, a 70 percent inte-rest in a new 650 MW coal-fired unit, is budgeted for 1991. During the ' interim between the addition of WCGS and another new unit, reserve ma rgin deficiencies are tentatively planned to be ameliorated by the purchase of interchange
-) power or by the use of other power supply alternatives.
(d Alternative methods of meeting the companies obligations are currently under study. Over the period 1981-1990 there will also be other reratings 1 and retirements for both utilities, as shown in Tables 1.1-4b and 1.1-5b. 1.1.2.2 Puel Sources And Prices i 1.1.2.2.1 Coal In 1980 KG&E used more than 2.5 millio'n tons of coal, and l KCPL used about 5.4 million tons. Most of both companies' i , requirements are purchased under long-term contracts. Coal for La Cygne No. 1 is supplied by the Pittsburg & Midway
- Coal Mining Company at La Cygne, Kansas under a contract '
i that expires in the year 2002. Approximately 1,630,000 tons are to be provided each year. In years when additional i coal supplies are needed, such additional quantities are I purchased on the spot market. j v Rev. 1 1.1-42 4/81 i
WCGS-ER(OLS ) Coal for La Cygne No. 2 is supplied by the Amax Coal Company from Gillette, Wyoming, under a contract that expires in 1996. The annual entitlement is 1,890,000 tons which is supplemented by spot purchases. KCPL has contracts with the Peabody Coal Company in Missouri and Oklahoma calling for delivery of 2,150,000 tons por year. These contracts l expire in 1986 and 1996. KCPL also has a contract with the Arch Mineral Co rporation in llanna, Wyoming, calling for 500,000 tons per year; the contract expires in 1986. Iatan No. 1 is being supplied with 2.1 million tons of Wyoming coal per year through December, 1983 and 1.7 million tons per year in 1984 and 1985 by the ARCO Coal Company. KCPL's wholly-owned subsidiary, WYMO Fuels, Inc. is expected to supply Iatan No. I after expiration of the ARCO contract. KCPM:. Me of Iatan coal purchases is ab6ut 70 percent of the total, caseu on its ownership position. Coal for the Jef frey Energy. Center, in which KG&E has a 20% interest, is to be supplied under a contract with the Amax Coal Company which expires in 2013. KG&E's ave rage share for the Jeffrey Energy Center will be about 1.6 million tons per year for the period 1980 through 2013. Table 1.1-15 indicates the significant change that has occurred in the ten year period, 1970-1980, during which KG&E has conve rted from a gas-fueled unit to one that uses coal as its primary generation source. KCPL 's use of coal has also increased as the une of gas has declined. Further fuel dive rsification will be provided by WCGS which will also permit further reductions in gas consumption. l 1.1.2.2.2 Oil KG&E burned 304,000 barrels of oil in 1980 and KCPL about 165,000 barrels. KG&E purchases most of its oil from local produce rs . KCPL generally makes spot purchases d en neces-sary. Both companies minimize the use of oil whenever pos-s ib le . 1.1.2.2.3 Natural Gas During 1980 about 28 pe rcent of KG&E's gas was provided by l the Kansas Gas Supply Company under three contracts that expire in 1990. The remaining req uirement was obtained l under month-to-month interstate interruptible gas contracts. KG&E used about 43 billion cubic feet of na tu ral gas in l 1980. l O Rev. 1 1.1-43 4/81
WCGS-ER(OLS) [j) ( KCPL's use of natural gas decreased in 1980; about 6 billion cubic feet were burned. Gas has been purchased from the Gas Se rvice company on an interruptible basis to displace l I the more expensive oil used for startup and flame stabiliza-tion at steam stations . It is also used to provide addi- ) tional steam production for electric generation and steam sales when coal burning equipment is out of service for repair. At times it is also necessary for KCPL to burn natural gas to meet air quality regulations. 1.1.2.2.4 Nuclear Fuel The Applicants have received from Westinghouse Electric l Corporation a quantity of uranium hexafluoride equivalent to 719,000 pounds of uranium concentrates. Another 525,000 pounds of uranium concentrates has been purchased which, combined with the 719,000 pounds from Westinghouse, will complete the initial core load and a portion of the first reload for WCGS. The balance of the Uranium concentrate requirements for the first six reloads, except for 700,000 pounds, will be met by a contract with Westinghouse to sup-ply 1,700,000 pounds. The remaining '700,000 pounds is to be purchased on the open market. Contracts exist for the con-ve rsion of these concentrates to uranium hexafluoride. m 1.1.2.2.5 Fuel Costs
- Tables 1.1-32 and 1.1-33 present actual and projected burned fuel costs. December 1980 burned fuel costs for KG&E and. l KCPL were as follows:
FUEL COSTS IN CENTS PER MMBTU DECEMBER 1980 l Fuel KG&E KCPL Coal 96.1 103.4 Oil 205.5 108.8 Gas 169.3 252.6 d System Cost 132.7 107.0 -g. Projected 1984 fuel costs provide a compari' son of fossil and l nuclear fuel costs. v) Rev. I 1.1-44 4/81 l (
l l WCGS-ER(OLS ) FUEL COSTS IN CENTS PER MMBTU 1984 l Fuel KG&E KCPL Coal 157.8 168.2 Oil 279.7 1068.2 Gas 266.7 540.8 Nuclear 78.6 77.4 System Cost 161.8 171.7 The importance of nucicar fuel in providing lower cost ene rgy is clea rly demonstrated in this comparison. KCPL's projected high costs fo r coal and gas in 1984 reflect the expected low usage of these fuels. Additional perspective on rising fuel costs is given by Tables 1.1-16 and 1.1-17. Changes in the decade 1970-1980 are given below: TRENDS IN PUEL COSTS CENTS PER MMBTU KG&E KCPL Puol 1970 1980 1970 1980 Coal 26.7 96.1 25.3 100.1 011 25.4 205.5 76.2 381.5 Gas 22.3 169.3 27.5 223.0 Trends in fuel costs for overall system operations for the past and projected to 1990 from Tables 1.1-32 and 1.1-33 are as follows: SYSTEM COSTS IN CENTS PER MMBTU Year KG&E KCPL 1970 22.3 26.1 1 *n 5 58.5 50.3 1980 132.7 109.4 1985 179.9 184.4 1990 290.9 290.6 With increases in individual fuel costs ranging from factors of 3.6 to 8.1 be tween 1970 and 1980 and system fuel costs increasing by factors of 4.2 to 6.0 in the same period, it is clear that the impact on total operating costs has been se rious . Table 1.1-34 shows that in t.he pe riod 1965-1980 l Rev. I 1.1-45 4/81
. . _ _ - - ___ - _ _ _ _ _ _ _ _ . _ - _ _ _ _ . . . _ _ . . - _ _ . _ = - _ _ . . _ _ _ _ . ._ __.
I WCGS-ER(OLS) fuel costs doubled as a percentage of total operating costs. 1 For KG&E fuel cost.s were 20.9 percent of operating costs in 1965 and 49.7 percent in 1980. For KCPL they were 18.5 per- , cent in 1965 and 34.9 percent in 1980. i
- l 4
i i f ) ! i \ l i 1 1 1 Rev. I 1.1-45a 4/81
WCGS-ER(OLS) 1.1.2.3 Bulk Power Planning Both KG&E and KCPL are membe rs of SPP, the regional relia-bility council, and of MOKAN. KEPCo intends to apply for membership in both SPP and MOKAN. SPP is a regional member of NERC and has established plan-ning criteria to which all interconnected member bulk power systems must subscribe. Planning criteria set forth by SPP are intended to serve as guidelines for the development of more specific criteria by each system or control area (Southwest Power Pool, 1978). Individual company members of SPP have been assigned to groups as shown in Table 1.1-6. These assignments are based on company location, and a com- l pany can request reassignment to another group or to be included in more than one group. SPP has developed its criteria such that instability or cascading outages will not occur. Among the major criteria are the following:
- 1. Sufficient reactive capacity shall be avail-able within the SPP system to maintain sys-tem voltage within 5 percent of normal at the ,
major busses of the transmission system.
- 2. To prevent the isolation of a portion of the SPP system, resulting from multiple contin-gencies, unde r-f requency relays shall be in-stalled for selective removal of load.
- 3. Planning for capacity additions must provide a total generating capacity available to SPP that exceeds the predicted annual peak obli-gation by a margin of 15 percent, or alter-natively, a probability study shall be made so as to ensure that the probability of losd exceeding available capaci!, shall not be greater than one occurrence in ten years, and provided that in no case shall the re-serve be less than 12 percent greater than the predicted peak load obligation.
- 4. Special generating unit and plant design featu res are recommended to provide greater system reliability.
- 5. In order to be assured of adequate generating capacity, sufficient quantities of standby fuel are to be provided, when practicable, to permit normal system operation, based on ex-perience rela tive to curtailments and inter-ruptions.
Rev. 1 1.1-46 4/81
i I WCGS-ER(OLS) (w']j
/
- 2. Integrated operation and interchange of power between the Missouri companies and Associated;
- 3. Purchase of hydro peaking power by Missouri Companies from Associated;
- 4. Reserve capacity sales to Associated by Missouri Companies;
- 5. Standby service to Associated; and
- 6. Interchange of requisitioned power ser-vice be tween Missouri companies and Associated.
As of May 11, 1979 The Companies' hydro-electric peaking power entitlement under this agreement was reduced to zero. (2) The South Central Electric Companies Coordi-nation Agreement (KG&E) involves:
- 1. The exchange of seasonal diversity;
- 2. Deferred diversity capacity;
- 3. Firm power purchases;
- 4. Economy energy sales;
- 5. Emergency service; and, G. Coordinated maintenance schedules.
(3) The Kansas City - Twin Cities Coordination , Agreement (KCPL) provides for:
- 1. Cons truction and operation of 345-kV interconnection facilities for power ex-changes; and
- 2. Interchange of:
- a. Emergency energy;
- b. Scheduled outage energy;
- c. Economy energy;
- d. Short term power; and,
- e. Participation power (4) The Missouri-Ka nsas-Oklahoma Interconnection Agreement (KG&E) provides for:
1.1-49
WCGS-ER(OLS)
- 1. Construction and operation of 345-kV transmission lines and interconnections ,
for power exchanges l l
- 2. Interchange of:
- u. Emergency energy; ,
- b. Economy energy; l
- c. Excess energy; 1
- d. Replacement energy; Participation power; and l l
- e. ;
- f. Firm power; and
- 3. Direct scheduling of power transfers 1.1.3 RESERVE MARGINS 1.1.3.1 Reserve Requirements And Margins System generating capacity requirements and reserve margins for both KG&E and KCPL are determined on the basis of pro-jected system peak loads and system peak responsibilities plus the required minimum reserve. The internal planning minimum reeGrve margin for KG&E and KEPCo is 15 percent, and l it is 20 percent for KCPL. Both SPP and MOKAN have required '
minimum reserve margins of 15 percent, and MOKAN assesses a capacity charge on a member company with a reserve margin deficiency. Tables 1.1-1 and 1.1-2 provide detail for KG&E and KCPL on historical and projected loads, capability and capacity balances based on MOKAN requirements. Neither utility uses loss of load probability studies as a sole determination of a necessary reserve margin, although KCPL is now conducting some loss of load probability studies to refine its reserve margin planning. Reserve margins are calculated on the basis of each system's net I hour peak load and the corresponding accredited generating capacity which for KG&E and KCPL would represent the sammer peak loads and the accredited summer generating capacity. Basic margin estiniates for the early years of WCGS operation from 1984 to 1990 both with and without WCGS are given in the table below. If these margins were based on total system responsibility for KG&E and KCPL, they would be lower. l l t l l O Rev. 1 1.1-50 4/81
l WCGS-ER(OLS) I A
, RESERVE MARGINS" Year KG&E KCPL With WCGS Without WCGS With WCGS Without WCGS MW Percent MW Percent MW Percent MW Percent 1984 802 44.9 325 18.2 716 28.8 319 12.8 1985 742 40.2 265 14.4 627 24.4 230 8.9 1986 833 44.1 356 18.8 534 20.0 137 5.1 1987 773 39.6 296 15.2 438 15.9 41 1.5 -
1988 718 35.8 241 12.0
~
339 11.8 - 58 - 2.0 1989 668 32.5 191 ~ 9.3 236 8.0 - 161 - 5.4 1990 623 29.7 146 7.0 89 2.9 - 308 -10.0 b Do not reflect external obligations. If WCGS is not in operation, 80 MW of Northeast 1, 2, 4, 5 and 7 will be retained. With WCGS KG&E will be well within internal and pool margin requirements for the period shown, KCPL will be within internal and pool requirements through 1986 but will fall below its internal margin regoirement in 1987 and below pool requirements in 1988 and beyond. WCGS represents a large block of capacity which boosts the margins of both companies in the early years of operation. However, without WCGS KG&E would be below its internal and the. pool require-(Vc) ments in 1985 and after 1987, declining to 7 percent margin in 1990. KCPL would be below its internal and pool require-ments for the full period,~with negative margins after 1987. Data are not presented for KEPCo because, as shown on Table 1.1-3, KEPCo will be dependent upon firm and contract par- l chases to meet its commitments for the foreseeable fatore. At the time of the anticipated 1984 sammer peak WCGS will l represent a significant percentage of the accredited generating capacity of each of the owners, as shown below: PERCENTAGE OF CAPACITY REPRESENTED BY WCGS l 1984 i , KG&E KCPL KEPCo* 18.4% 14.9% 100.0% WCGS will be the only generation resource owned by KEPCo and will represent 30.5 percent of KEPCo's capacity responsibility in 1984. gg Upon going into service, WCGS will be the largest generating anit for both KG&E and KCPL and the only unit for KEPCo. (v) The next largest units will be La Cygne No. 1 for KG&E with 370 MW of capacity and Iatan No. 1 for KCPL with 469 MW of l capacity. Rev. 1 1.1-51 4/81
WCGS-ER(OLS) In 1984, 58.7 percent of the accredited generating capacity l of KG&E will consist of 4 large units, ranging from 315 to 477 MW in capacity. KCPL's 5 1arge units, ranging in capa-city from 315 to 477 MW, will constitute 65.0 percent of its l accredited generating capacity. Without WCGS, the loss of production on any of these units would bring the utility involved drastically below its required reserve margin. In addition to Wolf Creek, two other units, La Cygne No. I and No. 2 are owned jointly by KG&E and KCPL, each utility ownino half of each unit. 1.1.3.2 Scheduled And Forced Outages 1.1.3.2.1 Scheduled Outages KG&E develops a two-ye ar and a ten-year ove rhaul schedule each summer, and those schedules are updated as conditions dictate. In preparing the schedules there is coordination among other utilities with which jointly-owned units are ope rated . Overhaul schedules depend upon the size of a unit, the number of hours of operation during a year, types of fuel used and the necessity for special work or repairs. The length of time planned for boiler overhaul is based on past experience. Kansas law and insurance company regula-tions require an annual internal inspection of all boilers. Units la rge r than 200 MW require outages of 3 to 6 weeks and smaller units about 2 weeks. Turbine generator work is generally performed during boiler maintenance, with a major overhaul at intervals ranging from 5 to 10 years. Outages are scheduled for particula r times of the year so as to optimize availability with respect to anticipated loads and the operating costs of units. No outages are scheduled during the system's peak load period from mid-June to mid-Au gus t. Coal burning units are not scheduled for outages during the winter peak load period of December through February because natural gas curtailments may occur in this period, and there may : shortages of fuel oil. La rge unit outayes are scheduled for March through May and September through November, the periods of minimum system load. KCPL's' general plan fo r scheduling outages is similar to that of KG&E. The frequency of scheduled maintenance is based on KCPL's experience, the utility industry's exper- ) ience and the manufacturer's recommendation. Generator l maintenance is planned annually for the next 5 year period. l O l l Rev. 1 1 1.1-52 4/81 l
i 1 l 1 WCGS-E R(OLS ) l C N A combination of three methods is used for scheduling unit l f
\
V
! maintenance. The first is a manual method in which the .
larges t units are scheduled in the valley of the annual loads, and the smaller units are scheduled around these l outages. The second method uses a Power System Simulator computer program which analyzes the costs of different maintenance schedules. An output. from the program is a schedule for maintenance based on KCPL load and maintenance cycles. The third method uses the Maintenance Evaluation Program (MEVAL) an optimizing computer program which is on the Control Data Cybernet timesharing system. The combined results of the three methods are used to develop an op timum schedule which is cost-ef fective and within all given constraints. 1.1.3.2.2 Forced Outages KG&E has had relatively few forced outages on its wholly-owned gas / oil-fired plants in recent years, and these have been minor in terms of effect on the system. In March of 1978 severe icing caused a short in a 138-kV line that tripped Gordon Evans No. 2 off line. Gordon Evans No. I ! was restricted to 68 MW due to the loss of fuel oil burner pump motors as a result of the incident. The outage was of short duration. In July of 1979 a wind storm damaged the fan venturis on the cooling tower of Gordon Evans No. 2 which caused the unit load to be restricted to 160 MW. Capacity was recovered in stages and was fully restored within 11 days. Experience on the La Cygne Plant jointly owned by KG&E and KCPL has been less favorable as summarized below: l l l t
\
l Rev. I 1.1-53 4/81 l
l WCGS-ER(OLS) LA CYGNE OUTAGE EXPERIENCE Outage 4 Date Date Duration Year Unit Off On In Hours Cause 1973 La Cygne No. 1 9/17 10/06 450 Unknown 1974 " 6/25 7/19 586- Repair cold re-heat line 11/21 1975 2/17 2112 Hydrogen fan repair 4/04 4/30 638 Hydrogen fan failure 10/14 11/14 733 1976 8/23. 9/20 690 Turbine blade damage 1977 11/10 12/25 1071 Reblade low pressure turbine 1978 6/08 7/16 944 Hydrogen fan failure 1979 2/04 2/11 183 Slag tap problem 2/27 3/13 364 Reheater tube leak and generator vibration 7/08 8/16 919 Turbine blade failure 1980 3/02 3/18 392 Generator vibration 3/23 4/01 222 " " 12/2 12/11 195 Waterwall tube leak , 1978 La Cygne No. 2 10/22 11/10 461 Boiler slag removal Major outages. 1 l 9 Rev. 1 , 1.1-53a 4/81 ! l
. -_ _ .- I
WCGS-ER(OLS) [ h Some of these outages . lasted for several weeks and occurred V during summer peak . periods. Over th'e past' 8 years ' forced I outages on La Cygne No. I have amounted to a high percentage of its availability. This unit is currently KG&E's largest and KCPL 's' third , largest. l Other forced outages experienced by KCPL during the same time period were: OTHER KCPL OUTAGE EXPERIENCE Outage Date Date Duration Year Unit Off On In Hours Cause 1976 Hawthorn No. 5 10/19 10/27 206 Mill area explosion Hawthorn a'o. 4 10/21 11/4 349 Inspect and wash air heater 1978 Hawthorn No. 5 2/10 2/28 436 Reheater leaks Hawthorn No. 4 11/03 11/18 374 Induced draft fan Hawthorn No. 1 11/18 Damage to turbine generator exciter
.1979 7/14 6240 Hawthorn No. 2 1/10 2/9 718 Control valves Hawthorn No. 2 2/24 10/17 2032 High pressure turbine
. Hawthorn No. 4 4/21 4/30 231 Generator reduction gears Hawthorn No. 5 7/3 7/12 288 Repair reheat tube leaks 1980 Hawthorn No. 5 12/17 1/05 458 Turbine vibration Hawthorn No. 5 4/30 5/08 195 Economizer tube leak Hawthorn No. 3 12/08 12/16 175 De slag boiler
. Hawthorn No. 1 12/14 12/21 170 Economizer tube leak Hawthorn No. 4 12/22 12/29 163 Water wall tube leaks Major outages.
- 1.1.4 EXTERNAL SUPPORTING STUDIES
; Documents filed annually in response to a FERC request are l
consolidated by SPP into the " Southwest Power Pool Regional ! Reliability Council Coordinated Bulk Power Supply Program" which is submitted to the Economic Regulatory Administration I of the Department of Energy. The most recent issue is that of April 1, 1980. l Data extracted from the annual reports are presented in l Tables 1.1-7a, 1.1-7b, 1.1-8, 1.1-9 and 1.1-10 on past loads, margins and capability, and estimates given on future energy, loads, capacity and margins. u[ v} l I l Rev. 1 l 1.1-54 4/81 l
..2 t .}
WCGS-ER(OLS) It is the policy of SPP to maintain as high an interconnec-tion capability with adjoining regions as is economically feasible . Joint studies are made of potential system emergencies and their effects on the systems involved. Through these studies the effectiveness of existing and planned interconnections, can be periodically measured and the design of systems updated so that interconnection capa-bility and reliability can be maintained. O O Rev. 1 1.1-54a 4/81
WCGS-ER(OLS) O Transmission load studies coordinated by SPP e s tab li.*'t the h maximum import capacity through system interconnections. An individual member of MOKAN and SPP does not necessarily carry enough reserve capacity to cover the outage of its own sy s '.em ' s largest unit. Rather, reliance is placed on neigh-boving member systems through interconnections for emergency ar4d maintenance support. Implicit in the use of a 15 per-cent reserve margin (rather than the capacity of the largest unit by each SPP membe r) is the interconnection capability which will provide the necessary reliability for continuity of service. Periodic studies verify the reliability of this concept. 1.1.5 1 REFERENCES Black I Veatch, 1979, Environmental Assessment of Wolf Creek Generating Station, Unit No. 1 for Kansas Elec-tric Power Cooperativa, Inc. Department of Energy 1978, Bulk Electric Power Load and Supply Projections, 1988-1997, Contiguous United States, DOE / ERA-0020. Lee, Hoburg B., 1978a, Report to Kansas Electric Power Cooperative, Inc., Concerning the April 1977 Power Requirements Studies of KEPCo and its member systems. t ( Lee, Hoburg B., 1978b, Memorandum to Charles Ross and Joe Mulholland, Analysis of 1977 Loads of KEPCo Members in Relation to Projected Loads in REA Approved Power Requirements Study. National Electric Reliability Council, 1980, Annual Report l for 1979 1 1 National Electric Reliability Council, 1980, 10th Annual l Review of Overall Reliability and Adequacy of the North American Bulk Power System. Southern Engineering Company of Georgia, 1980, Feasibility l Analysis of Participation in Wolf Creek Generating Sta-i tion, Unit No. 1 with _ Hydro Peaking Power Purchases from the Southwestern Power Administration, Prepared for Kansas Electric Power Cooperative, Inc. Southwes t Power Pool, 1980, Regional Reliability Council l Coordinated Bulk Power Supply Program, A Report to the Economic Regula tory Administration, Department of l Ene rgy . l Rev. 1 - 1.1-55 4/81
s k I 6 WCGS-ER TABLE 1 s . ' KG&E LOAD AND CAI ACTUAL 1965-1980 AND l IN M1 System Capacity Responsibility System Peak Responsibility System Firm Firm System Total Accredited Peaking Load Purchases Sales Peak Required System Generating Capacij Net (minus ) (plus) Responsibility Rese rve Responsibility Capacity Purchaq Year 1 Hour (a) (Hydr < 1965 746 - - 746 75 821 764 - 1966 839 50 - 789 79 868 764 - 1967 848 - 16 864 86 950 1,153 - 1968 923 65 30 888 107 995 1,153 - 1969 998 290 200 908 109 1,017 1,151 - 1970 1,077 100 - 977 117 1,094 1,151 - 1971 1,079 125 65 1,019 122 1,141 1,153 - 145 77 1,065 138 1,203 1,153 - 1972 1,133 100 1,092 164 1,256 1,566 - 1973 1,192 - 100 1,225 184 1,409 1,565 - 1974 1,325 - 1975 1,337 100 - 1,237 186 1,423 1,564 - 100 1,287 193 1,480 1,564 -
! 1976 1,387 -
100 14 1,337 201 1,538 1,879 - 1977 1,423 1,899 1978 1,533 100 16 1,449 217 1,666 - 100 15 1,388 208 1,596 1,883 - 1979 1,473 1,981 1980 1,727 73 31 1,685 253 1,938 - 107 90 1,708 256 1,964 1,975 - 1981 1,725 1,975 1982 1,675 137 186 1,724 259 1,983 - 190 1,783 267 2,050 i,111 - 1983 1,730 137 136 1,818 273 2,091 2,588 - 1984 1,785 203 128 1,870 281 2,151 2,588 - 1985 1,845 103 120 1,907 286 2,193 2,724 - 1986 1,890 103 122 1,969 295 2,264 2,724 - 1987 1,950 103 2,724 - 103 124 2,026 304 2,330 1988 2,005 2,724 - 103 126 2,078 312 2,390 1989 2,055 2,445 2,724 - 2,100 103 129 2,126 319 1990 10%-1963 through 1967; 12%-1968 through 1971; 13%-1972; 15%-1973 and fo I*f I Reserve requirements: (Without WCGS, the firm sales would increase by 50 MW and the 39 MW For 1984 and thereaf ter. sale would not be in effect.) Because of reporting perio Source: MOKAN Pool Report which is for contract year beginning 1 June. may dif fer from those in other reports, f , e I
1 OLS) 1-1
' ABILITY DATA 'ROJECTED 1981-1990 f
System Capacity Peaking Capacity Capacity Capacity r (Kansas) Sales Planned Total Capacity Balance as Purchase Sales Purchases capacity System L__ (plus) (minus) (plus) Additions As Without (minus) Capacity Planned WCGS fl 40 - (b) 10 55 - 849 + 28 50 - 10 50 10 - 217 19 814 - 54 50 - 129 1,005 + 50 55 180 - 1,074 + 79 50 - 75 1,021 + 75 - 1,201 4 50 -
+ 107 50 -
50 1,203 + 50 50 - 62 80 - 1,203 0 50 - 200 1,536 40
+ 280 50 -
1,415 + 6 1,554 + 131 40 - 75 33 75 - 297 1,604 + 124 32 125 - 125 1,740 + 202 25 25 - 25 - 1,831 + 165 1,883 + 281 1,981 + 43 1,975 + 11 1,975 - 8 39 - 2,111 + 61 39 2,549 + 458 2,549 37
+ 398 -
97 39 - 39 - 2,685 + 492 -
- - 4 39 2,685 + 421 2,685 75 39 -
+ '55 -
140 39 2,685 + 295 2,685 - 200
+ 240 -
255 ping )oci ty figures Rev. 1 4/81
f' ~l I 1 i WCGS-ER(OLS) TABLE 1.1-2 KCPL LOAD AND CAPABILITY DATA ACTUAL 1965-1980 AND PROJECTED 1981-1995 IN MW l System Capacity Responsibility System Peak Responsibility { System Firm Firm Total Peaki Load Ptrchases Sales System Required System Accredited Capac i Net Peak teserve Responsibility Generating Purch 3 Year i Hour (minus) (plus) Responsibility (a) _ Capacity (Hydr i 1965 1,020 - 45 1,;65 107 1,172 1,099 19C 1966 1,186 65 53 1,174 117 1,291 1,123 243 = 1967 1,186 20 10 1,176 118 1,294 1,123 243 1968 1,276 180 50 1,146 138 1,284 1,187 243 1969 1,409 150 150 1,409 169 1,578 1,694 !41 1970 1,499 - 3 1,502 180 1,682 1,686 ; 43 j 1971 1,574 40 36 1,570 188 1,758 1,684 241 1972 1,676 55 40 1,661 216 1,877 1,813 43 1973 1,757 40 63 1,780 26' 2,047 2,224 243 1974 1,907 - - 1,907 236 2,193 2,224 243 1975 1,903 - 18 1,921 288 2,209 2,334 194 1976 1,920 100 - 1,820 273 2,093 2,361 194 1977 J,980 - - 1,980 297 2,277 2,675 162 1978 2,097 - - 2,097 315 2,412 2,560 155
? 1979 1,964 - - 1,964 393 2,357 2,560 1980 2,157 - -
2,157 431 2,588 2,838 1981 2,235 - - 2,235 4 4'/ 2,682 2,884 1982 2,315 - - 2,315 463 2,778 2,804 1983 2,398 - - 2,398 480 2,878 2,804 1984 2,485 - - 2,4E5 497 2,982 3,201 1985 2,574 - - 2,574 515 3,089 3,201 1986 2,667 - - 2,667 533 3,200 3,201 1987 2,763 - - 2,763 553 3,316 3,201 1988 2,862 - - 2,862 572 3,434 3,201 1989 2,965 - - 2,965 593 3,558 3,201 1990 3,072 - - 3,072 614 3,686 3,161 1991 3,183 - - 3,183 637 3,820 3,616 1992 3,298 - - 3,298 660 3,958 3,600 1993 3,417 - - 3,417 683 4,100 3,512 1994 3,540 - - 3,540 708 4,248 3,490 1995 3,667 - - 3,667 733 4,400 3,397 (a) Rese rve req uirement : 10%-1963 through 1967; 12%-1968 through 1971; 13%-1972; 15%-1973 through 1978; 1979 and following, 20% KCPL internal minimum reserve. (b) For 1984 and thereaf ter. If WCGS is not in operation, KCPL will retain 80 MW of Northeast 1, 2, 4, 5 and 7 capacity. Source: MOKAN Pool Report and KCPL. MOKAN Pool data are reported for contract year beginning 1 June. Because of reporting period, figures may differ from those in other reports.
\
l 6
. . . ~ . - .. . . - .
r l
'4 [
7 i r I i (. System Capacity Peaki.ig Capacity. Capacity Capacity capacity Balance i ty . . (Kansas) Sales Purchases Planned' Total As Without
- Ocs
. Purchases Sales Capacity System Planned WCGS #1 p) - (plus) -(minus) . (minus)-. (plus) Zdditions capacity (b)
;76 -15 - - 1,202 + 30
' 95 55 - - 1,216 - 75 95 -
116 - 1,387 + 93
- '95 -
11 - 1,346 + 62 I - 95 255 7 - 1,594 + 16
- - 95 100 - - 1,734 + 52
-- 95 75 95 - 1,852 + 94
-. 95 55 55 - 1,961 + 84 95 130 - - 2,222 + 175 95, -- - -
2,372 + 179
- 76 - - - 2,452 + 243 76 100 - - 2,379 + 286
- 63 225 25 -
2,574 + 297 60 25 25 - 2,655 + 243
- ' - - 2,560 + 203 l 150 -
+ 278 2,688 + 10 0 l
l 300 - + 46- 2,584 - 98 l - -
- 80 2,804 + 20 r - - - 2,804 '- 74
+ 397 3,201 + 219 - 178
- - - 3,201 + 112 - 285
- - - 3,201 + 1 - 396 125 - 3,326 + 10 - 387 250 - 3,451 + 17 - 380 i 375 - 3,576 + 18 - 379 550 - 40 3,711 + 25 - 372 225 + 455 3,841 + 21 - 376 375 - 3,975 + 17 - 380 600 - 4,112 + 12 - 385 775 - 4,265 + 17 - 380
- 1,025 - 4,422 + 22 - 375 I
l Rev. 1 l~ 4/81 t' l I l l I i I l-L l l I ! I i J
m_~.~ m. _ -m_...._ ._m.._.__.._ . . _ _ . _ ._ _ _ _ _ , _ _ , _ _ _ , ,_ _, , _ _ _ .
'N ' ' '
-7
\ '%
f f-WCGS-ER(OLS) TABLE 1.1 ICEPCO LOAD AND CAPABII1TY DATA
' ACTUAL 1977-1979 AND' PROJECTED 1980-1990 h IN MW Actual a'r(J Total REPCo Required Projected Firm SPA Firm Power: Power Responsi- Reserves for Capacity Generation Capacity .
Year Demand Sales (a) Purchases ( bj, bility Demand WCGS & Hydro (c) Responsibility Capacity (d) Deficit (e) 1977 337.4 0 0 337.4 0 337.4 0 -337.4 1978 376.8 0 0 376.8 0 376.8 0 ^ -376.8 1979 413.3 0 0 413.3 0 413.3 0 -413.3 1980 484.2 0 30 454.2 0 454.2 0 -454.2 1981 515.4 20 60 ~475.4 0 475.4 0 - -475.4 1982 548.4 30 90 488.4- 0 488.4 0 -488.4 1983 538.8 30 90 , 523.8 0 523.8 0 -523'.8 1984 621.3 90 100 611.3 29.3 640.6 195.5 -445.1 1985 661.5 . 90 105 646.5 29.3 675.8' 195.5- -480.3 1986 702.4 90 105 .687.4 33.73 721.13 224.8L. '- 496.3 1987 745.9 90 105 730.9 33.73 764'.63 224.85 -539.8 1988 792.1 90 105 777.! 33.73 810.83' 224.85 -586.0 1989 841.4 90 105 826.4 33.73 860.13 224.85' I635.3 893.8' 90 105 878.8- 33.73. 912.53 224.85 -687.7 1990 (a) REPCo firm sales to Sunflower Electric Cooperative of SPA and Wolf Creek Generating Station power. (b) 'REPCo firm purchases of SPA hydro-peaking power. (c) Required reserves are equal to 15% of NEPCo's total capacity ownership in WCGS and low-head hydro projects as specified in the guidelines of the Southwest Power Pool. (d) MEPCo's 17% of Wolf Creek Generating Station plus the generation (29.35 MW) from two low-head hydro projects.
*e)~ The capacity deficit will be made up by contracted purchases from Kansas utilities.
Sources REPCo. Rev. 1 4/81
9 I i f WCGS-ER(OLS) TABLE 1.1-4a KG&E I INSTALLED CAPACITY IN MW 'I 1974-1992 Capacity Factor Range Major Units Plant & Unit Primary Fuel Function In Percent 1974 1975 g LaCygne No. 1 Coal Base 36.0 - 43.0 412 412 4[ LaCygne No. 2 g Coal Base 60.0 - 70.0 Jeffrey No. 1(gy oa ase Jeffrey No. 2 c) Coal Base 60 Est. JeffreyNo.3lcy gy Coal Base 60 Est. Jeffrey No. 4 Coal Base 60 Est. Wolf Creek (d) Nuclear Base 50.0 - 75.0 l Gordon Evans No.1 II Base & Intermediate II 34.8 - 58.9 162 162 10 Cordon Evans No. 2 Gas & No. 6 OilI *I II 34.8 - 58.9 381 381 3C Murray Gill No. 1 Gas && No. C.as No.66 Oil 011I9'I Base & Intermediate (h) 24.9 - 41.9 51 51 E Murray Gill No. 2 Gas & No. 6 Oi1 I9I Base && Intermediate Base Intermediate (h) 24.9 - 41.9 78 78 1 Hurray Gill No. 3 Gas & No. 6 011 I9I Base & Intermediate 44.7 - 64.4 120 120 1E Murray Gill No. 4 Gas & No. 6 011 I9I Base & Intermediate Ii} 44.7 - 64.4 121 121 If Neosho No. 1 & 2 Coal Peaking 48 48 ( Neosho No. 3 Gas Inte rmediate (k) 3.3 - 62.1 75 75 t Intermediate & PeakingI "I I 2.6 - 42.1 "I Ripley No. 1, 2 & 3 Gas & No. 6 Oi1 III 89 89 9 Wichita No. 3 & 4 Cas & No. 2 Oil Peaking 24 24 E Wichita No. 5 No. 2 Oil Pe aking 3 3 Total Installed Capacity 1564 1564 15C Total or KG&E allocation, when jointly owned. Summer rating. ggy 50% share. KCPL is operator. 20% share. KCPL is or will be cperator. gg 41.5% share. KG&E will be operator. (f) Gas through 1984 - then No. 6 011. Base through 1983 - then intermediate. I9I th) Gas through 1984 - No. 6otherwise 011 thereafter. (1) Base 1979, 1981, 1982 - intermediate. Base 1974 through 1979 and in 1981 - otherwise intermediate. UIDeleted. Base in 1974 and 1982, intermediate otherwise until 1981, then peaking from 1983 on. (m) Gas through 1986 - No. 6 011 thereafter. Base in 1974, intermediate 1975,1977 and 1982 - otherwise peaking. In) Capacity factor was 91.2% in 1974 when used for base load. NOTE: Generation capabilities, as tested, are reported to the MOKAN Poolascontractkyearvalues. These values may vary from those reported in FERC Report No. 12, which gives year end values and those reported to SPP as summer peak values. O l I
db t i L l Actual Proj ect ed [ 1977 1978 1979- 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 t 400 400 400 370 370 370 370 370 370 370 370 370 370 370 370 370 315 325 325 315 315 315 315 315 315 315 315 315 315 315 315 315 136 136 138 138 138 138 138 138 138 138 138 138 138 138 138 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 136 477 477 477 477 477 477 477 477 477 l 146 149 149 149 149 149 149 '149 149 149 149 149 149 149 149 149 t 350 359 359 359 357 357 357 357 357 357 357 357 357 357 357 357 46 46 46 46 45 45 45 45 45 45 45 45 45 45 45 45
> 74 74 74 74 71 71 71 71 71 71 71 71 71 71 71 71 100. 108 108 108 108 108 108 108 108 108 108 108 108 108 108 108 L 100 106 106 106 106 106 106 106 106 106 106 106 106 106 106 106 1 38 47
> 75 69 69 69 68 68 68 68 68 68 68 68 68 68 68 68 i' 86 88 88 80 38 88 88 88 88 88 88 88 88 88 88 88 l 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 1 3 3 3 3 3 3 3 ,3 3 3 3 3 3 3 3 3 1 1753 1930 1883 1981 1974 1974 2110 2587 2587 2773 2723 2723 2723 2723 2723 2721 I Rev. 1 4/81 i
n > ~. ~. -- - -m - . - - -- ~ - a - ; Y.
.g 6 4 '
NCGS-ER(OLS) TABLE 1.1-4b FG6E ^ ACTUAL AND PROPOSE.1) CAPACITY CHANGES - + - Function. Nature MN Primary ' Total Annua! -
. Year ILit e .. Unit or Plant on Load of Change change Fuel Net Change 1975 ' June 30 LaCygne No. I name perating , - 23 Coal - 23 1976 JJune 30 LaCygne No. 1 Base Rerating ' + 23 Coal June 30 'Murray Gill No. 2. Intermediate' Rotating . + 1 Gas June 30 Murtay Gill No. 3 Base 'Rerating
- I Gas June 30 Goraton Evans ho. I Base perating +- 1 Gas Juno 30 k apley Peaking Rerating + 1' Gas + 27 1:
~ 1977~ May 10 Lacygne No. 2 name . Addition -+315 Coal June 30 Lacygne No. I base Berating := 12 Coal J ure 30 Lacygne No. 2 haso Rcrating + 10' Coal
- Jurue 30 Murr.ey Gill No.. I Inte rmediate kerating - 5 Ga s - '
J uraa 30 .Muraay Gill No. 2 Intermediate Rerating - 5 Cas June 30 Murray Gill No. 3- Hasa Rerating = 21 Gas
- June 30 Mua ray Gill No. 4 haue Perating '- 21 Ga s -
June 30 - Ostdon Evans No. I Base Berating - 17 Gas June 30 Gurdon Evans No. 2 Haso - Rerating - 31 Gas June 30 . Neosho Mc. I 6 2 Peaki ng kerating - 10 Coal-
' June 30 Ripley (Intermediate Rcrating - 4 Cas
., June 30'.Nichita No. 36 4. " Peaking Rerating = 4 Cas +195 197u- July 38. Jeffrey No.'l .
Hase Addition +136 Coal June 30 Gordon Evans No.1 Base ~ Rerating + 3 Cas June 30 Gordon Evans No. 2 Dase Rerating + 9 Cas June 30 Murray G111 No. 3 -Base Perating + 8 Gas Jusa- 30 Murray Gill No. 4 , base Rorating + 6 Cas June 30 Neonho No. I 6 2 Peaking.' Rerating
- 9 Coal -g Jutus 10 Nece.ho No. 1 Intermediate Perating =6 Cas e June 30 Ripley Peaking ' Rcrating .+ 2 Cas +167
.1979 Jusae 30 Neosho No. ! 6 2 Peaking Ret i reme nt - 47 Coal - 47 1980 Spr im; 'Jeffrey No. I Base. Rurating + 2 Coal Jef f rey No. 2 - Base Addition +136 ' Coal . + 98 Lacygne No. I Base Rerating - 30 Coal Lacygne No. 2 Base Berating - 10 Coa!
1981 June 30 Girdon Evans No. 2 Base Rerating -2 Cas = 7 , Mua ray Ga ll No.1 - base Rerating - I Gas Murray Gill No. 2 Base Rerating .= 3 Gas Neosho No. 3 Base Berating - I Gas 1982 No Change 1985 . fipt asy ' 'Jeffrey No. I hase Addition +136 Coal. +136 1984 April Null Creek Daso Addition +477 Nuclear +477 198'a SprirN Jeffrey No. 4 Base Addition +136 Coal +136 , 1986 tu's No Change 1992
. ~.a_-..
1:r e tout notes to Tatile 3.1-4a for planned changes of function on load and of primary fuel for various units. Rev. 1 4/81 I i
- s w .,
l I WCGS-ER(OLS) 1 5 TABLE 1.1-5a KCPL I# INSTALLED CAPACITY 1974-1990 Capacity Factor Range Major Units Actua Plant & Unit Primary Fuel Function In Percent 1974 1975 1976 g LaCygne No. 1 Coal Base 36.0 - 43.0 412 412 412 41 LaCygne No. 2 Coal Base 60.0 - 70.0 31 Montrose No. 1 Coal Base 44.0 - 59.0 185 180 180 18 Montrose No. 2 Coal Base 53.9 - 67.6 182 178 178 17 Montrose No. 3 Coal Base 51.0 - 68.4 193 188 188 18 Hawthorn No. 5 Coal Base 30.0 - 47.3 520 520 480 4a Iatan No. 1(C' Coal Base 60.0 - 73.0 Wolf Creek (d) Nuclear Base 50.0 - 75.0 Hawthorn No. 1 Coal Inte rmediate 30.0 - 41.0 75 75 73 Hawthorn No. ? Coal Intermediate 34.1 - 44.5 78 78 73 0 Hawthorn No. 3 Coal Intermediate 27.0 - 40.2 118 119 105 10 Hawthorn No. 4 Coal Intermediate 31.0 - 36.0 133 133 105 1C Grand Ave. No. 1,5,7,8,9 Coal Inte rmediate 99 99 99 7 Northeast No. 1,2,4,5,7 Gas-Steam Peaking 128 135 135 8 Northeast No. 11 & 12 No. 2 011) (Peaking 101 101 101 5 Northeast No. 13 & 14 No. 2 Oil) Gas (Peaking 116 116 10 Northeast No. 15 & 16 No. 2 Oil) turbines (Peaking 116 10 Northeast No. 17 & 18 No. 2 Oil) (Peaking IC Total Installed Capacity 2224 2334 2361 26( I Total or KCPL allocation when jointly owned. Summer rating. gey 50% share. KCPL is operator. 70% share. KCPL will be operator. St. Joseph Light and Power Co. owns (d)18% and Empire District Electric Co. Owns 12%. 41.5% share. KG&E will be operatr>r. i NOTE: Generation capabilities are based on summer peak values. Those may vary from those reported in FPC Report No.12 which gives year end values. I t
l
' l
)INMW I l Projected I1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 ) 400 400 370 370 370 370 370 370 370 370 370 370 370 ) 325 325 315 315 315 315 315 315 315 315 315 315 315 ) 173 173 162 150 150 150 150 150 150 150 150 150 150 174 174 174 150 150 150 150 150 150 150 150 150 150 ) 180 180 180 160 160 160 160 160 160 160 160 160 160 450 450 450 450 450 450 450 450 450 450 450 450 150 469 469 469 469 469 469 469 469 469 469 469 477 477 477 477 477 477 477 65 65 55 65 55 55 55 55 55 55 55 55 55 65 65 55 65 55 55 55 55 55 55 55 55 55 90 90 70 85 70 70 70 70 70 70 70 70 70 90 90 70 85 70 70 70 70 70 70 70 70 70 70 70 70 70 40 40 40 40 40 40 40 40 - 80 80 80 80 80 95 95 95 85 85 85 85 85 85 85 85 85 85 101 101 101 95 95 95 95 95 95 95 95 95 95 101 101 101 95 95 95 95 95 95 95 95 95 95 101 101 101 95 95 95 95 95 95 95 95 95 95 3560 3560 2838 2884 2004 2004 3201 3201 3201 3201 3201 3201 3161
*i/8}
I 1 l l l l l l
WCGS-E R (OLS ) TABLE NO. 1.1-5b "x NCPL ACTUAL AND PROPOSED CAPACITY OHANGES 1975-1990 Total Annual Function Nature Prima ry Net Change Year Date Plant and Unit on Load of Change MW Change Puel (MW Summer) 1975 Northeast ! Peaki ng Rerating + 2 Gas Northeast 2 Peaking Rerating + 1 Gas kortheast 4 Pm *ki ng Rerating + 1 Gas Northeast 5 Pe.si>q perating + 3 Gas kortheast 11, 14 Peaking Addition + !!6 No. 2 011 + !!0 HawtNern 3 Intermediate Rerating
- 1 Coal Montrose 1 Base Rcrating -
5 Coal Montrose 2 Base perating - 4 Coal Montrose 3 Base perating - 5 Coal 1976 Northeast 15, 16 Peaking Addition + 116 No. 2 Oil Hawthorn ! Intermediate perating - 2 Coal Hawt horn 2 Intermed. ate Rerating - 5 ccal + 27 Hawthorn 3 Inte rmediat e Herating - 14 Coal Hawthorn 4 Interrediat e Rcrating - 28 Coal Hawthorn 5 Base Rerating - 40 Coal 1977 Grand Ave. 5 Intermediate perating - 6 Coal Grand Ave. 7 Inte rmediate perating - 9 Coal Grand Ave. 8 Int e rmediate Deact iva tion - 14 Coal Northeast 1 Peaking Pirating - 29 Gas Northeast 2 ? caking < ..tivation - 22 Cas Nort heast 4 Peaking Rorating - 1 Gas + 280 Northeast 5 Pe ak ing herating - 3 Gas Northeast II, 12 Peaking ne rating - 6 No. 2 Oil Northeast 13, 14 Pe ak ing 6erating - 15 No. 2 Oil Northeast 15, 16 Pea k i ng ne rat i ng - 15 No. 2 Oil Northeast 17, 18 Peaking Addition + 101 No. 2 Oil Lacygne 2 hase Addit it e + 315 8 Coal Hawt horn i Int e rmedia te Rorating - 8 Coal Hawthorn 2 Inte rmediat e Rerating - 8 Coal 1978 Hawt horn 3 Intermediate Rerating - 15 Coal Hawthorn 4 Intermediate Retating - 15 Coal f Ns Hawthorn 5 Base perating - 30 Coal j $ Montrose i Base perating - 7 Coal - 81 ( f Montrose 2 Hase Rerating - 4 Coal _- Montrose 3 Bast Rerating - 8 Coal Lacygne ! Has: Rerating - 12 Coal Lacygne 2 Hase perating + 10 Coal 1980 Mar latan I Base Addition + 469 b gg,g Lacygne I pase perating - 30 Coal l Lacygne 2 hase Rerating - 10 Coal Montrose 1 Base Rerating - Il Coal Hawthorn 1 Intermediate Rerating - 10 Coal + 278 l Hawthorn 2 Intermediate Rerating - !? Coal Hawt horn 3 Intermediate scrating - 20 Coal Hawthorn 4 I nte rmediate Perating - 20 Coal Northeast 1,2,4,5,7 Peaking Not Accredited - 30 Gas 1981 Montrose 1 Base Herating - 12 Coal Montrose 2 Base serating - 24 Coal Montrose 3 Base Rerating - 20 Coal Hawthorn ! Intermediate Peratin3 + 10 Coal + 46 Hawthorn 2 Intermediate Rerating + 10 Coal Hawthorn 3 Intermediate kerating + 15 Coal Hawthorn 4 Inte rmediate Herating + 15 Coal No rt heast 1,2,4,5,7 Peakira Accredit ed + 80 Ga s Northeest II, 12 Peaking Rorating - 10 No. 2 011 Northevet I I, 14 Peak ing Perating - 6 No. 2 Oil Northeast 15, 16 Peaking Hera t ing - 6 No. 2 Oil No rt heas t 17, 18 Peaki ng Addition - 6 No. 2 Oil 199J H.nethorn I intermediate perating - 40 Coal Haw t ho r n 2 Intermediate Rerating - 10 Coal Hawthorn 3 Inte rmediat e Rerating - 15 Coal - 80 Hawt hurn 4 Intermediate Roratieg - 15 C Coal Jan Grand Ave. 5 Intermediate Deact ivation - 7 Coal Jan Grand Ave. 7 Intermediate Deactavation - 30 Coal 19H4 Jan No r t hea s t ! Peaking Ret ire ment - 7 Cas No rt heast 4 Peaking Retirement - 30 Ga s + 397 Northeast 5 Peaking Ret irement - 30 Gas Northeast 7 Peaking Retirement - 13 Ga s
,,, April Wolf Creek Dase Addition + 477 Nuclea r f 1990 Jan Crand Ave. 9 Intermediate Retirement - 40 Coal - 40 a
Juant Ownership: NCPL 50% C Joint Ownerships NCPL 704 Wanter Capacaly unty Rev. I 4/81
WCGS-ER(OLS)
- . t 1
*g Y , :> i TABLE 1.1-6 l (SilEET 1 of 4)
PARTICIPATION IN POOLS AND ASSOCIATIONS 1 SOUT!! WEST POWER POOL (SPP) Southwest Power Pool Coordination Agreement, dated December 17, 1969, with various amendments, the latest of which is da ted Janua ry 1, 198 0. l Participating Parties: Group A Alexandria Light & Power Department, Louisiana Arkansas Electric Cooperative Corporation Cajun Electric Power Cooperative, Inc. Central Louisiana Electric Coyggny, Inc. (The)(b) Gulf States Utilities Company Laf ayette Utility System, Louisia na b) Middle South Utilities, Inc. Arkansas Power & Light Company Arkansas-Missouri Power Company Louisiana Power & Light Company Mississippi Power & Light Company New Orleans Public Service, Inc. _ Group B Grand River Dam Authority New Mexico Electric Service Compgg Oklahoma Gaa & Electric Company Public Service Company of Oklahoma (b) Southwestern Electric Power Compa I Southwestern Power Administration Southwestern Public Service Company (b) Western Farmers Electric Cooggve(b) West Texas Utilities Company l Group C 1 Board of Public Utilities, Kansas g y, Kansas Central Kansas Power Company, Inc. Chanute Municipal Utilities, Kansas City Power & Light Department, Independence, Missouri Cof feyville Municipal Water & Light Degg{tment, Kansas Empire District Electric Company g e) Kansas City Power & Light Company I"I Non-membe r system. Is operated and data are reported by Southwestern Public Service Company (b) Designated SPP Control Area (c) System included in Electric Reliability Council of Texas Rev. 1 4/81
WCGS-ER(OLS) TABLE 1. J -6
/] l (SHEET 2 of 4)
(V Kansas Gas & Electric Company (b) KansasPower&LightCompany(Tygj Missouri Public Service Company (b) St. Joseph Light & Power Company Sunflower Electric Cooperative, Inc. WesternPowerDivision,ggntralTelephone& Utilities Corporation Winfield Municipal Light & Water, Kansas Group D Associated Electric Cooperative, Inc.(a)(b) City Utilities, Springfgd, Missouri Missouri Edison Company Missouri Power & Light Com g y Missouri Utilities Company Group E ( Non-Membe rs ) City of Houma, Louisiana City of Monroe, Louisiana City .of Natchitoches, Louisiana City of Ruston, Louisiana Jonesboro City Water & Light, Arkansas O Morgan City Municipal Utilities, Louisiana
'vl Ottawa Water & Light, Kansas Ponca City Water & Light, Oklahoma MISSOURI KANSAS POOL (MOKAN)
GeneralParticipationagreemenyj"GPA") MOKANCoordinationagreemenkc) Kansas Facilities agreement Missouri Facilities agreement (c) Missouri Coordination Agreement (c) Amendments to General Participation agreement Participating Parties: Board of Public Utilities, Kansas City, Kansas (The) Central Kansas Power Company, Inc. Empire District Electric Company -(The) Kansas City Power & Light Company Kansas Gas & Electric Company Kansas Power & Light Company (The) Missouri Public Service Company Saint Joseph Light and Power Company (Mo) I"I Data for these member systems of SPP are reported by O) (U contiguous councils Designated SPP Control Areas ! (c)These are not MOKAN-wide agreements, but they are MOKAN related Rev. 1 4/81 _ _ _ _ ,4 . . , , , , . . . - , , . . ,
l
)
WCGS-ER(OLS) TABLE 1.1-6 L (SHEET 3 of 4) 1 Western Power Division, Central Telephone & Utilities Corporation Sunflower Electric Cooperative, Inc. Note: Not all of the above participants are signator-f to each agreement. COMPANIES - ASSOCIATED - SOUTHWESTERN POWER ADMINISTRATION (SPA) Associated - Companies contract Exhibit B, Amended Missouri Participation Agreement Service Schedule E-MPA SPA - Companies Contract SPA - Associated Contract Amendatory Agreement Concurrence by Companies Western Missouri Participation Agreement Exhibit A, Amended Peaking Capacity Sales Agreement - KG&E and KPL Participating Parties: , Associated Electric Cooperation, Inc. Empire District Electric Company (The) Kansas City Power & Light Company Kansas Gas & Electric Company Kansas Power & Light Company (The) Missouri Public Service Company Southwestern Power Administration Note: Not all of the above participants are signatory to each agreement SOUTH CENTRAL ELECTRIC COMPANIES Coordination Agreement Various interconnection agreements among the member companies. Participating Parties: Arkansas Power & Light Company Central Louisiana Electric Company, Inc. (The) Empire District Electric Company (The) Gulf States Utilities Company Kansas Gas & Electric Company Louisiana Power & Light company Mississippi Power & Light Company New Orleans Public Service, Inc. Oklahoma Gas and Electric Company Public Service Company of Oklahoma Southwestern Electric Power Company 1 I
WCGS-ER(OLS )
. TABLE 1.1-6 g'"g (SHEET 4 of 4) b KANSAS CITY - TWIN CITIES Memorandum of Understanding - South Section Addendum No. I and No. 2 Coordinating Agreement Facilities agreement Service schedule for participation power Service (KCPL and NSP)
Participating Parties: Iowa Public Service Company Interstate Power Company Kansas City Power & Light Company Northern States Power Company Omaha Public Power District St. Joseph Light & Power Company MISSOURI-KANSAS-OKLAHOMA (MKO) Missouri-Kansas-Oklahoma Interconnection Agreement, dated September 22, 1971 g Participating Parties: b Associated Electric Cooperative, Inc. Kansas Gas and Electric Company Public Service Company of Oklahoma Union Electric Company I
\
e
1 WCGS-ER(OLS) TABLE 1.1-7b SOUTHWEST POWER POOL I *I COMPARISON OF FORECAST AND ACTUAL 1971-1980 CAPABILITY LOAD AtdD MARGINS IN MW 1971 1972 1973 1974 Forecast -Fore Forecast Forecast Forecast item 4-1-71(b) Actual 4-1-72(c) Actual 4-1-73 Actual 4-1-74 Actual d 27,502 27,502 32,002 32,002 34,765 34,738 38,474 36,198 41,3
- 1. Net Dependable Capability 4,410 5,567 5,567 5,809 5,726 6,206 6,206 2,0
- 2. All Scheduled Purchases 4,410 4,169 4,169 4,734 4,734 3,839 4,332 4,112 4,112 <
- 3. All Scheduled Sales 27,743 32,835 32,835 36,735 36,132 40,568 38,292 42,-
- 4. Total Resources (1+2-3) 27,743
"" ~" ~~ ~~ "~
--- -~
- 5. Inoperable Capability ---
27,743 32,835 32,835 36,735 36,132 40,568 38,292 42,
- 6. Operable Resources (4-5) 27,743 23,653 22,187 27,896 27,552 30,568 29,367 32,711 32,078 34,
- 7. Peak Hour Demand
~~ ~~ ~" ~~
- 8. Interruptible Demand 22,187 27,896 27,552 30,568 29,367 32,711 32,078 34,
- 9. Demand Requirements (7-8) 23,653 4,090 5,556 4,939 5,283 6,167 6,765 7,857 6,214 7,
- 10. Gross Margin (6-9)
- 11. Unavailable Capacity til 150 92 375 67 78 745 748
- a. Scheduled Outages
--- 1,570 --- 950 --- 3,735 --- 1,626
- b. Forced Outages
--- --- 59 25 --- 258 --- ---
- c. Fuel Limited 111 1,720 151 1,350 67 4,071 745 2,374 Total 3,836 4,788 3,933 6,1( 1 2,694 7,112 3,840 7,
- 12. Net Margin (10-11) 3,979 Net Margin as Percent of Demand (9) 16.8 17.3 17.2 14.3 20.0 9.2 21.7 12.0 13.
I*IAs reported to FPC and FERC April 1, each year, under Docket R-362. (b)The figures reported include all members of SWPP through April, 1980 Revised June 28, 1971 I#IRevised May 1, 1972 (d) Breakdown not available i
\
l l
1975 1976 1977 1978 1979
- as t Forecast 1?80 Forecast Forecast Forecast Forecast L Actual 4-1-76 Actual 4-1-77 Actual 4-1-78 Actual 4-1-79 Actual 4-1-80 Actual
)9 40,644 42,199 42,014 44,846 43,739 46,s87 46,457 47,802 45,651 50,824 49,713 f4 3,084 2,464 2,464 2,164 7,457 5,411 8,688 5,303 5,901 5,168 5,882 f8 678 1,320 1,'22 0 379 5,258 3,704 4,343 3,377 2,543 4,139 3,945 l5 43,050 43,343 43,158 46,13? 44,938 48,194 50,802 49,728 49,009 51,853 51,590 g --- --- --- --- 549 135 304 190 1,777 96 221 9 43,050 43,343 43,158 46,131 44,389 48,059 50,498 49,538 47,232 51,757 51,369 0 33,300 35,307 33,764 37,090 36,847 38,946 39,191 41,094 38,783 41,478 43,346 35 --- --- 104 124 115 15 9 33,300 35,307 33,764 37,090 36,811 946 39,191 40,990 38,659 41,363 43,331 p 0,850 8,036 9,394 9,G41 7,577 9,113 11,307 8,548 8,573 10,394 8,038 0 1,336 20 2,353 --- 600 44 --- > 1,457 0 --- 44 ---
--- 1,190 ---
3,958 --- -- --- --- 5,720 IdI 3,783 20 3,543 0 4,558 44 O 3,385 IdI 44 44 i) 7,067 8,016 5,851 9,041 3,019 9,069 5,587 8,548 5,188 10,350 7,994 ) 31.9 22.7 17.3 27.4 8.2 23.3 14.3 20.9 13.4 25.0 18.4 i 1 i Rev. 1 4/81
.i
O O WCGS-ER(OLS) O TABLE 1.1-8 SOUTHWEST POWER POOL ENERGY AND PEAK LOADS 1978-1989 l 9 Monthly - 1979-1981 Seasonally 1978-1989 Month Energy (GWH) Peak Load (MW) Season Load (MW) 1979* 1980 1981 1979* 1980 3981 Jan 16,324 16,208 17,339 27,533 28,259 30,'179 S 78* 39,191 Feb 14,171 14,642 15,489 27,032 27,132 29,091 W 78-79* 28,350 Mar 14,135 14,576 15,644 23,627 25,768 27,495 S 79* 37,722 Apr 13,415 14,046 15,054 24,290 26,295 28,037 W 79-80* 28,404 May 14,659 15,807 16,953 27,658 31,900 33,813 S 80 41,478 ' Jun 16,787 18,593 19,431 34,581 38,663 40,677 W 80 30,215 Jul 19,134 21,305 22,446 36,347 41,279 43,387 S .81 43,589 Aug. 19,344 20,945 22,036 36,727 41,323 43,393 W 81-82 31,773 Sep 15,930 18,248 19,165 34,689 38,432 40,431 S 82 45,857 Oct 14,967 15,746 16,564 29,131 30,519 32,108 W 82-83 33,543 l Nov 14,298 15,103 15,878 26,257 28,404 29,960 S 83 48,501 i Dec 14,990 16,438 17,363 27,328 29,802 31,479 W 83-84 35,574 S 84 51,027 W 84-85 37,531 Year Energy (GWHL S 85 53,649 W 85-86 39,553 1978* 191,550 S 86 56,266 1979* 191,762 W 86-87 41,594 1980 201,512 S 87 59,089 1981 212,728 W 87-88 43,743 1982 223,948 s 88 62,021 1983 236,908 W 88-89 46,008 1984 249,694 S 89 64,981 1985 262,682 W 89-90 48,222 1986 276,104 1987 290,391 1988 305,344 1989 320,246
- Actual Southwest Power Pool 1980 Rev. 1 4/81 i
in q d C,_ d 4 I WCGS-ER (OLS)
. TABLE 1.1-9 ,
SOUTHWEST POWER POOL PROJECTED RESOURCES, DEMAND AND MARGINS g 1980-1989 v IN MW 1980 1981 1982 1983 1984 Resources Summer
- Winter
- Summer Winter Summer Winter Summer Winter Summer Winter
- 1. Net Capability 50,824 52,076 53,789 53,842 58,358 58,613 61,072 60,852 61,680 62,461
- 2. Scheduled Imports 5,168 4,098 4,259 2,895 3,990 3,159 3,837 2,765 3,360 2,857
- 3. Scheduled Exports 4,139 4,038 ^4,000 4,523 3,963 4,127 3,455 3,261 3,329 3,181
. 4. Total Resources (1+2-3) 51,853 51,336 54,048 52,214 58,385 57,645 61,454 60,356 61,711 62,137
- 5. Inoperable Capability 96 105 96 .105 289 298 289 - 298 289- 282
- 6. Operable Resources (4-5) 51,757 51,231 53,952 52,109 58,096 57,347 61,165 60,058 61,422 61,855 Demand
- 7. Peak Ecur Demand 41,478 30,215 43,589' 31,773 45,857 33,543 48,501 35,574 51,027 37,531
- 8. Inte-ruptible Demand s 115 115 115 115 115 115 115 115 115 115
- 9. Demand Requirements (7-8) 41,363 30,100 43,474 '31,658 45,742 33,428 48,386 35,459 50,912 37,416 Margin
' 10. Gross margin .
10,394 21,131 10,478 20,451 12,354 23,919 12,779 24,599 10.510 24,439
- 11. Scheduled Outages 44 3,356 83 3,594 60 4,158 83 5,282 60 5,478
- 12. Net Margin (10-118 -
10.350 17,775 10,395 16,857 12,294 19,761 12,696 19,317 10,450 18,961
- 13. het Margin as Percent of sand (12/91 25.0 59.1 23.9 53.2 26.9 59.1 26.2 54.5 20.5 50.7 1985 1986 1987 1988 1989 Resources Summe r Winter S weer Winter Sur w r Winter Summer Winter Sumne r Winter
- 1. pet Capability .66,912 67,347 68,627 68,670.- 71,622 72,592 74,528 74,654 77,674 ?8,114
' 2. Scheduled Imports 3,089 2,757 2,807 2,478 2,690 2,454 2,685 2,450 2,564 2,327
- 3. Scheduled Exports 3,054 3,050 3,153 3,243 3,017 3,199 2,949 3,127 2,880 3,055
- 4. Total Resources (1+2-3) 66,947 67,054- 68,281 67,905 71,295 .71,847 74,264 , 73,977 77.358 77,386
- 5. Inoperable Capability 289 182 193 233 157 197 119 159 83 123
- 6. Operable Resources (4-5) 66,658 66,772 68,088 67,672 71,138 71,650 74,145 s 73,818 77,275 77,263 Demand
- 7. Peak Bour Demand . 53,649- 49,553 56,266 41,594 59,089 43,743 62,021 46,008 64,981 48,?22
- 8. Interruptible Demand - 115 115 115 115 115 115 115 .
115 - 115 115
, 9. Demand Requirements (7-8) 53,534 39,438 56,151 41,479 58,974 43,628 61,906 ' 45,893 64,866 48,107 Margin ,
- 10. Gross Margin' 13,124 27,334 11,937 26,193 12,164 28,022 12,239 27,925 12,409 29,156
- 11. Schedated Outages - - - - . - - - - - - -
- 12. Det Margin (2 0-11) .
13,124 27,334 11,937 26,193 12,164 28.022 12,239 27,925 12,409 29,156
- 13. Met Margin as Percent. of Demand (12/97 24.5 .69.3 21.3 63.1 20.6 64.2 19.8 60.8 19.1 60.6
- Summer - 1980 is June through September Winter-1980 is December 1979 through Parch 1980.
Sources Southwest Power Pool,1980 Rev. 1 4/81 0 {N 4.
'4 n,
,, a.r - -- v - s -
i I WCGS-ER(OLS ) TABLE 1.1-10 gx ( ). SOUTHWEST POWER POOL LONG RANGE PEAK DEMAND, RESOURCES AND MARGIN 1990-1999 f IN MW Margin Increase Resources as % Peak Hour Per Year To Serve of Peak Year Demand % Demand Margin Demand 1990 68,146 4.9 82,388 14,242 20.9 1991 71,426 4.8 86,603 15,177 21.2 1992 74,888 4.8 90,369 15,481 20.7 I 1993 78,517 4.8 94,420 15,903 20.3 i 1994 82,296 4.8 99,056 16,760 20.4 1995 86,316 4.9 104,809 18,493 21.4 1996 90,688 5.1 108,822 18,134 20.0 *' j 1997 94,924 4.7 114,609 19,685 20.7 , 1998 99,570 4.9 119,515 19,945 20.0 l 1999 104,463 4.9 124,454 19,991 19.1 STATEMENT OF PROJECTED Cl.PABILITY ADDITIONS DURING THIS PERIOD l Unknown l Hydro Nuclear Fossil or Other Total Percent 1.04 5.65 61.26 32.05 100.00 Source: Southwest Power Pool, 1980 I Rev. 1 4/81
k N WCGS-ER(OLS) TABLE 1.1-11 MOKAN POOL LOAD AND CAPABILITY DATA (a) ACTUAL 1971-1980 AND PROJECTED 1981-1989 IN MW System Capacity Responsibility Sys tem Peak Responsibility System Firm Firm System Required Total System Accredited Peaking Load Purchases Sales Peak Reserve Responsibility Generating Purch Net (minus) (plus) Responsibility (b) Capacity (Hydr Year 1 Hour 1971 4,852 195 160 4,817 577 5,394 5,617 2S 1972 5,208 262 264 5,210 676 5,886 5,790 25 1973 5,505 230 110 5,385 808 6,193 6,673 2S 1974 6,026 188 56 5,894 885 6,779 6,950 25 1975 6,082 187 80 5,975 897 6,872 7,229 22 1976 6,279 334 68 6,013 902 6,915 7,141 2: 1977 6,690 232 89 6,547 983 7,530 8,028 15 1978 7,108 231 90 6,967 1,045 8,012 8,404 15 1979 7,031 278 95 6,848 1,028 7,876 8,747 1980 8,064 249 109 7,924 1,189 9,113 9,693 1981 8,068 3 #7 355 8,026 1,205 9,231 9,864 1982 8,383 3Y6 376 8,363 1,256 9,619 9,844 1983(d) 8,657 394 373 8,636 1,297 9,933 10,512 1984 9,034 353 381 9,062 1,361 10,423 11,456 1985 9,353 351 403 9,405 1,412 10,817 12,080 1986 9,664 349 434 P,749 1,462 11,211 12,080 1987 9,987 347 463 10,103 1,515 11,618 12,080 1988 10,300 345 489 10,444 1,567 12,011 12,051 1989 10,617 342 511 10,786 1,619 12,405 12,096 (a) For contract year, beginning 1 June. Does not include Associated Companies (b) Reserve 12% of peak responsibility in 1971, 13% in 1972, 15% in 1973 and following (c) For 1984 and thereafter. Represents 954 MW assigned to KG&E and KCPL (d) Based on MOKAN report dated May 1980, with WCGS slipped 1 year MOK AN Pool Reports 1971-1980 k
/
/
3
/
I I System capacity l , Dapacity Peaking Capacity Capacity Capacity Planned Total Capacity Balance 2c3 (Kansas) Sales Purchases capacity System As With
- 3) Purchares sam (minus) (plus) Additions Capacity Planned WCGSg (plus) (minus) 95 95 549 249 5,615 + 221 95 95 403 353 6,038 + 152 95 95 324 82 6,729 + 536 95 95 264 89 7,073 + 236 76 76 158 153 7,462 + 590 76 76 323 368 7,424 + 509 63 63 689 {
684 8,221 + 691 60 60 390 335 8,539 + 527 295 420 114 8,972 > +
+1096 475 325 -
9,543 + 430 675 375
- 9,564 + 333 375 375 -
9,844 + 225 375 330 5
- 10,467 + 534 389 340 -
11,407 + 984 + 12 339 330 12,071
+1254 + 282 h - -
340 331 - 12,071 + 860 - 113 p - - 346 417 - 12,151 + E33 - 440 p - - 352 493 300 12,492 + 4 81 - 491 358 349 772 12,859 + 454 - 518 Rev. 1 4/81 k
h
\d !
W WccS-EatoLS) ! TABLE 1.1*12 NG6E SYSTEM LOADS, I ANNUAL SYSTEM ENERGY AND PEAR DEMAND ACTUAL 1968-1980 PROJECTED 1981-1990 l a ! A nnua l Summer Winter
- Annual 1 Ene rgy increase _ Peak Increase Peak System !
Year (GWH) GWH l Demand (P'W) NW % Demand (MW) Load Factor ! 1968 4,146 274 7.1 923 75 8.9 646 51.1 1969 4,455 309 7.5 998 75 8.1 681 50.9 1970 4,748 293 6.6 1,077 79 7.8 688 50.3 1971 4,818 70 1.5 1,079 2 0.2 745 51.0 1972 5,158 340 7.1 1,137 58 5.4 808 51.6 1973 5,526 358 6.9 1,202 65 5.7 829 52.4 1974 5,799 281 5.1 1,325 123 10.2 867 50.0 1975 6,199 40a 6.9 1,337 12 1.0 1,003 52.9 1976 6,442 243 3." 1,387 50 3.7 1,016 52.9 1977 6,6a5 243 3.a 1,423 36 2.6 1,056 53.6 1978 7,184 499 7. 1,533 110 7.7 1,120 53.5 19?9 7,189 5 0.0 1,473 3.9 1,160 55.7 1980- 7,807 618 8.6 1,727 254 17.2 1,195 51.5 1981 7,705 - 102 - 1.3 1,725 -2 0.0 1,208 51.0 1982 7,383 - 322 - 4.2 b 1,675 2.9 1,170 50.3 1983 7,590 J07 2.8 1,730 55 3.3 1,210 50.1 1984 7,802 212 2.7 1,785 55 3.2 1,250 49.9 1985 8,019 217 2.8 1,845 60 3.4 1,290 49.6
^ 233 2.9 19P6 8,252 1,890 45 2.4 1,320 49.8
\
]
1987 1988 8,495 8,752 243 257 2.9 3.0 1,950 2,005 60 55 3.2 2.8 1,360 1,405 49.7 49.8 \d 1989 9,035 283 3.2 2,055 50 2.5 1,440 50.2 1990 9,369 334 3.7 2,100 45 2.2 1,470 50.9
- Summer is the period f rom June through September Winter is December through March of the fo11owing year b
Decre)ses because REPCo load not included in NG&E Load af ter 1981 Rev. 1 4/81
/"%
/ \ \v] ,
, -e-
t WCCS-E R(OLS ) TABLE 1.1-13 ,g
*f NCPL SYSTEM LOADS ANNUAI, SYSTEM ENERGY AND PEAK OEMAND ACTUAL 1968-1980 PROJECTED 1981-1990I *I Annua l Sunser fb) Winter (b) Annual Energy increase Peak Increase Year (GWH) GWH Pe ak System 8 Demand (MW) MW 8 Demand (MW) Load Factor 1968 5,552 476 9.4 1,276 1969 5,889 90 7.6 864 49.7 337 6.1 1,409 133 10.4 902 47.7 l 1970 6,324 435 7.4 1,4'49 90 6.4 965 48.2 1971 6,641 317 5.0 1972 7,174 1,574 75 5.0 1,017 48.2 533 8.0 1,676 102 f.5 1,117 48.9 1973 7,598 424 6.0 1,757 1974 7,556 81 4.8 1,091 49.4 0.6 1,907 150 8.5 1,107 1975 7,857 301 4.0 1,903 45.2 l
-4 -0.2 1,165 47.1 1976 8,06 169 2.1 1,920 17 0.8 1,215 47.7 1977 8,452 426 5.3 1,980 1978 60 3.1 1.276 48.7 9,012 560 4.i 2,097 117 5.9 1,312 49.1 1979 8,812 -20* ,'.2 1,964 -133 1980 9,205 -6.3 1,317 51.2 393 4.* 2,198 234 11.9 1,306 (c) 47.8 1981 10,016 811 8.8 2,235 1982 10,417 37 1.7 1,507 51.2 401 4.0 2,315 80 3.6 1,567 1983 10,832 415 4.0 2,198 52.4 1984 11,267 83 3.6 1, 29 51.6 435 4.0 2,485 87 3.6 1,694 1985 11,717 450 4.0 2,574 51.8 89 3.6 1,762 52.0 1986 12,186 469 4.0 2,667 1987 93 3.6 1,865 52.2 12,673 487 4.0 2,763 96 3.6 1,885 1988 13,179 506 4.0 2,862 52.4 1989 13,707 99 3.6 2,007 52.6 528 4.0 2,965 103 3.6 2,126 1990 14,255 548 4.0 3,0 72 52.8 107 3.6 2,205 53.0 m
(a) Growth rates beyond 1990, out to 2010, are projected at 4.0 percent for annual energy and 3.6 percent for summer peak load (b) Summer is the teriod from June through September Winter is December through March of the following year (c) Actual through March 12, 1981. Rev. 1 4/81 0
/N.
(v,/ WCGS-ER(OIS) TABLE 1.1-14 REPCO SYSTEM LOADS, ANNUAL SYSTEM ENERGY AND PEAK DEMAND ACTUAL 1971-1979 AND PROJECTED 1980-1995 I *I Annual Summer (b) gg,g,7(b) Energy Increase Peak increase Peak Year (GhH) GhH t Demand (MW) MW t Demand (MW) 1971 1,031.9 202.8 213.4 1972 1,108.3 76.4 7.4 219.6 16.8 8.3 222.6 1973 1,160.1 $1.8 4.7 259.3 39.7 18.1 237.9 1974 1,239.6 79.5 6.8 293.4 34.1 13.2 247.4 1975 1,347.2 107.6 8.7 318.5 25.1 b.6 252.2 1976 1,406.0 58.8 4.4 348.9 30.4 9.5 271.7 1977 1,491.3 85.3 6.1 337.4 -11.5 -3.3 305.1 1978 1,640.2 148.9 10.0 37F.8 39.4 11.7 350.2 1979 1,842.1 201.9 12.3 413.3 36.5 9.7 347.5 g 1980 2,198.5 356.4 19.3 484.2 70.9 17.2 370.8 1 1981 2,332.0 133.5 6.1 515.4 31.2 6.4 1982 2,474.8 142.8 6.1 548.4 33.0 6.4 1983 2,625.9 151.1 6.1 583.8 35.4 6.5 1984 2,786.6 160.7 6.1 621.3 37.5 6.4 1985 2,957.2 170.6 6.1 661.5 40.2 6.5 1986 3,333.9 176.7 6.0 702.4 40.9 6.. 1987- 3,321.2 187.3 6.0 745.9 43.5 6.2 1988 3,520.0 198.8 6.0 792.1 46.2 6.2 1989 3,730.9 210.9 6.0 81.1.4 49.3 6.2
/ \ 1990 3,954.8 223.9 6.0 893.8 52.4 6.2 1991 4,192.6 237.8 6.0 949.7 55.9 6.2 1992 4,444.9 252.3 6.0 1,009.7 60.0 6.3 1993 4,712.5 267.6 6.0 1,072.9 63.2 6.3 1994 4,996.7 284.2 6.0 1,139.6 66.7 6.3 1995 5,298.7 302.0 6.0 1,211.3 71.7 6.3 Data not available for years prior to 1971. Actual dasa for 1980 not yet available.
Summer is year. following the teriod f rom June through September. Winter is December through March of the l Rev. 1 4/81
. m v
i l
,- l WCGS-ER(OLS) '
* ' , . r<.
TABLE 1.1-15 's FUEL MIX - PERCENTAGE DISTRIBUTION OF ANNUAL NET GENERATION f 1970 1975 1980 1985 1990 e e e e High Low High Low Capacity Capacity capacity Capacity Fuel , Factor Factor Factor Factor KG&E Coal - 18.3 49.4 57.4 57.4 56.1 56.1 Oil 0.5 14.9 1.9 1.7 2.3 1.7 2.2 Gas 99.5 66.8 48.7 13.4 17.4 12.8 16.3 Nuclear - - - 27.5 22.9 29.4 25.4 Total 100.0 100.0 100.0 100.0 100.0 100.0 100.0 KCPL Coal 69.2 88.4 93.5 78.1 80.8 71.5 74.5 Oil 0.1 4.0 0.9 1.9 1.9 2.2 2.7 Gas 30.7 7.6 5.6 0.1 0.1 0.1 0.1 Nuclear - - - 19.9 17.2 26.2 22.8 Total 200.0 100.0 100.0 100.0 100.0 100.0 100.0 NOTE: May not add due to rounding. Represents fuel mix for high and low capacity factors of the WCGS expected operating range. Rev. 1 4/81
WCGS-ER(OLS) TABLE 1.1-16 O TRENDS IN FUEL COSTS BY FUEL IN. CENTS PER MILLION BTU Fuel 1970 1975 1980 1985 1990 KG&E Coal 26.6 40.6 96.1 '174.2 278.4 Oil 25.4 136.5 205.5 480.9 835.1 Gas 22.3 45.1 169.3 333.9 673.9 Nuclear - - - 78.5 82.8 System 22.3 58.5 132.7 179.9 290.9 KCPL , Coal 25.3 42.4 100.1 184.5 294.1 Oil 76.2 209.7 381.5 1207.5 2080.8 Gas 27.5 58.4 223.0 677.6 2080.3 Nuclear - - - 77.4 81.3 System 26.1 50.3 109.4 184.4 290.6 i i
- For 1985 and 1990 a median capacity factor is assumed for 4 WCGS.
l I O Rev. 1 4/81
l WCGS-ER(OLS ) ; TABLE 1.1-17 TRENDS IN FUEL COSTS FOR SYSTEM OPERATIONS IN CENTS PER MILLION BTU KG&E KCPL Before , , Before , , Year WCGS High Low WCGS High Low 1968 21.8 22.5 1969 22.1 23.0 1970 22.3 26.1 1971 24.3 29.4 1972 24.4 30.6
, 1973 27.1 32.9 1974 33.3 38.2 1975 58.5 50.3 1976 67.2 60.0 1977 99.3 74.4 1978 109.3 87.8 1979 122.7 107.3 1980 132.7 10 'J . 4 , 1981 142.5 149.2 1982 162.8 158.0 1983 187.2 170.9 1984 159.0 164.9 171.7 172.4 1985 173.8 186.0 181.9 186.3 1986 178.9 193.4 216.5 223.7 1987 182.7 197.3 215.7 223.6 1988 205.3 222.2 232.7 243.7 1939 233.8 258.4 257.1 275.2 1990 276.6 306.0 279.6 294.4
- For 1984 and later. Shows effect of assuming the high and low capacity factors of the WCGS expected operating range.
4 4 i O', Rev. 1 4/81
l l l
/ \
i i Y.,E WCGS-E R (O LS ) TABLE 1.1-18 SYSTEM OPERATIONS, PEAN HOUR CONDITIONS 1973-1980 ) (IN MW) T KG&E 1973 1974 1975 1976 1977 1978 1979 1980 Peak Date Aug. 20 Jul 22 Jul 21 Aug 10 Jul 20 Aug 17 Aug 6 July 15 Peak Hour 4-5 pm 4-5 pm 3-4 pm 4-5 pm 4-5 pm 5-6 pm 4-5 pm 5-6 pm Net Generation 1126.5 1259.2 1268.4 1260.2 1539.4 1531.4 1361.4 1423.2 Pu rcha ses Fire Contract + 150.0 + 150.0 + 140.0 + 213.0 + 248.0 + 147.0 + 115.0 + 103.0 Emergency + 110.0 + 40.0 + 217.0 + 460.0 + 275.0 .0 + 230.0 + 445.0 Total + 260.0 + 190.0 + 357.0 + 673.0 + 525.0 + 147.0 + 345.0 + 548.0 Sales Firm Contract - 80.0 - 90.0 - 40.0 - 73.0 - 269.0 - 105.0 - 15.0 - 30.0 Municipals - 16.6 - 3.6 - 30.0 - 59.2 - 48.0 - 48.8 - 55.0 - 29.1 Eme rgency - 70.0 - 15.0 - 222.0 - 405.0 - 325.0 0 - 190.0 - 220.0 Total - 166.6 - 108.6 - 292.0 - 537.2 - 642.0 - 153.8 - 260.0 - 279.1 Inad ve rte nt - 18.0 - 16.0 + 4.0 - 9.0 + 3.0 + 8.0 + 27.0 + 35.0 Net Inter- + 75.4 + 65.4 + 63.0 + 126.8 - 116.0 + 1.2 + 112.0 + 303.9 change Net Load 1201.9 1324.6 1337.4 1387.0 1423.4 1532.6 1473.4 1727.1
/
( KCPL Peak Date Aug. 20 Jul 19 Aug 21 Aug IP Aug 8 Aug 25 Aug 7 Jul 15 Peak Hour 3-4 pm 3-4 pm 3-4 pm 2-3 pm 4-5 pm 5-6 pm 4-5 pm 3-4 pm Net Generation 1678 1558 1660 1598 1419 1635 1687 2189 Inter change Received Firm + 210 + 243 + 231 + 288 + 16 9 + 196 + 25 - Non-Firm + 80 + 152 + 60 + 320 + 545 + 425 + 440 + $70 Total + 290 + 395 + 291 + 608 + 714 + 621 + 465 + 570 Delivertd Fire - 143 - 95 - 94 - 176 - 78 - 84 - 27 - 159 Non-Fire - 70 0 - 1 - 92 - 17 - 14 - 175 - 390 Total - 213 - 95 - 95 - 268 - 95 - 98 - 202 - 549 Inad ve r tent + 2 + 49 + 47 - 18 - 58 - 61 + 14 - 12 Net Inter- + 79 + 349 + 243 + 322 + 561 + 462 + 277 + 9 change Net Load 1757 1907 1903 1920 1980 20v7 1964 2198 l Rev. 1 4/81 I S
\
g,
l WCGS-E R(O LS ) TABLE 1.1-19 NUMBER AND GROWTH OF RESIDENTIAL CUSTOMERS , KG&E KCPL KEPCo . ' - $ ', 3 Year End Growth Average Growth Average Growth No. for No. for for No. for for Year % Year Year % Year Year % Year 1968 163,508 1.2 251,257 -2.2 1969 165,424 1.1 252,354 0.4 1970 165,668 0.2 256,452 1.6 1971 166,697 0.6 261,865 2.1 1972 169,761 1.8 267,320 2.1 1973 172,896 1.8 273,532 2.3 1974 177,162 2.5 278,973 2.0 72,529 1975 180,772 2.0 281,708 1.0 73,857 1.8 1976 187,013 3.5 284,296 0.9 75,209 1.8 1977 190,174 1.7 288,376 1.4 76,919 2.3 1978 194,773 2.4 293,402 1.7 77,974 1.4 1979 200,024 2.7 298,413 1.7 79,736 2.26 1980 205,265 2.6 301,417 1.0 81,540 2.26 1981 211,376 3.0 305,860 1.5 83,048 1.85 1982 217,076 2.7 310,781 1.6 84,585 1.85 1983 222,446 2.5 315,928 1.7 86,149 1.85 1984 228,013 2.5 319,469 1.1 87,743 1.85 1985 233,852 2.6 322,738 1.0 89,400 1.88 1986 239,663 2.5 326,521 1.2 91,054 1.85 1987 245,562 2.5 330,815 1.3 92,738 1.85 1988 251,524 2.4 335,585 1.4 94,454 1.85 1969 257,577 2.4 339,746 1.2 1990 263,655 2.4 344,436 1.4 KEPCo data not available for earlier years. Rev. 1 4/81 0
1 l l l WCGS-ER(OLS)
\ ) TABLE'1.1-20 TRENDS IN USE OF ELECTRICITY RESIDENTIAL ELECTRIC HEATING Electric Heating Customers Annual Consumption of Energy For Year Numbe r Percentage Homes with Elec. Homes without Ending of Total Res. Space Heating Elec. Space (KWH) Heating (KWH)
Kansas Gas & Electric Company 1969 4,522 2.7 18,133 6,168 1970 5,197 3.1 20,566 6,878 1971 5,814 3.5 20,455 6,835 1972 7,411 4.4 19,698 7,151 1973 9,155 5.3 20,066 7,554 1974 12,833 7.2 18,319 7,427 1975 15.293 8.5 21,136 7,929 , 1976 19,376 10.4 18,779 7,800 1977 21,532 11.3 18,736 8,113 1978 23,586 12.1 20,179 8,596 1979 25,765 12.9 19,016 7,923 1980 26,768 13.0 18,606 9,375 O Kansas City Power and Light 1969 3,887 1.5 19,413 , 5,927 1970 4,803 1.9 19,395 6,541 1971 6.043 2.3 18,220 6,787 1972 6,749 2.5 18,454 7,061 1973 7.348 2.7 18,940 7,416 1974 7,911 2.8 18,248 7,152 1975 8,633 3.1 20,709 7,836 1976 9,278 3.3 19,441 7,371 1977 10,286 3.6 19,726 7,505 1978 11,106 3.8 21,636 7,956 1979 12,135 4.1 21,041 7,440 1980 12,346 4.1 19,645 8,489 Kansas Electric Power Cooperative, Inc. 1974 3,741 5.2 1975 4,863 6.6 l 1976 4,749 6.3 l 1977 5,267 6.8 1978 5,474 7.0 ' O Note: Missing data are not available. Rev. 1
'4/81 l
. , --r-- - -
r-- ,
WCGS-E E (OLS ) TABLE 1.1-21 AVERAGE ANNUAL CONSUMPTION OF ENERGY BY RESIDENTI AL CUSTOMERS KG&E KCPL KEPCo Year KWH % Incr. KWH % Incr. KWH % Incr. 1970 7,325 11.9 6,765 10.5 1971 7,345 0.2 7,027 3.9 1972 7,792 6.1 7,317 4.1 1973 8,317 6.4 7,726 5.6 1974 8,338 0.3 7,423 - 3.9 8,573 1975 9,150 9.7 8,166 10.0 9,016 5.2 l 1976 9,090 - 0.7 7,717 - 5.5 9,317 3.3 1977 9,413 3.6 7,920 2.6 9,309 - 0.1 l 1978 10,136 7.7 8,404 6.1 10,017 7.6 1979 9,496 - 6.3 7,557 - 10.1 11,154 11.4 1980 10,708 12.8 8,880 17.5 12,420 11.4
; 1981 9,528 - 11.0 8,719 - 1.8 12,971 4.4 1982 9,637 1.1 9,022 3.5 13,547 4.4 1983 9,665 0.3 9,294 3.0 14,149 4.4 1984 9,723 0.6 9,581 3.1 14,777 4.4 1985 9,801 0.8 9,885 3.2 15,433 4.4 1986 9,864 0.6 10,203 4.2 16,118 4.4 1987 9,940 0.8 10,724 4.1 16,834 4.4 1988 10,015 0.8 11,137 3.9 17,582 4.4 1989 10,187 1.7 11,581 4.0 1990 10,377 1.9 12,038 3.9 4
KEPCo data not available for earlier years. O Rev. 1 4/81
WCGS-ER(OLS)
'[^N TABLE 1.1-22 U DISTRIBUTION OF ENERGY CONSUMPTION BY CATEGORY ACTUAL 1964-197.*, PROJECTED 1984-1989 Il PERCENT Category 1964 1969 1974 1979 1984 1989 Kansas Gas & Electric Company a Residential 22.5 19.4 24.9 24.7 26.4 26.3 Commercial 17.5 14.8 18.6 18.4 19.2 19.7 Industrial 45.0 32.1 38.2 36.7 37.4 34.9 Kansas City Power and Light Company Residential 25.9 28.2 29.7 27.4 30.0 31.3 Commercial 37.5 38.8 38.0 38.7 36.6 36.3 Industrial 32.1 28.9 28.0 29.0 28.5 27.4 Kansas Electric Power Cooperatives !
Residential 58.2 54.2 45.6 Comm. & Ind. 35.9 37.4 43.2 k Irrigation 4.0 7.5 9.7 i Earlier data not available. 1984 distribution includes
, that for energy to be sold to Sunflower Cooperative. l l
i iO Rev. 1 4/81
i [ i WCGS-ER(OLS) i TABLE 1.1-23 AVERAGEANNUALCOSTSBYCgNSUMERCATEGORY 1971-1985 IN CENTS PER KWH KG&E KCPL KEPCo I} Commercial & Year Residential Commercial Industrial Residential Commercial Industrial Residential Industrial Irrigation 1971 1.99 1.96 1.04 2.66 2.21 1.28 1972 1.96 1.94 1.04 2.63 2.20 1.30 1973 1.95 1.96 1.06 2.76 2.32 1.39 1974 2.17 2.24 1.24 3.01. 2.57 1.58 2.69 2.28 2.65 , 1975 2.59 2.67 1.68 3.46 2.93 1.95 3.16 2.79 3.28 ! 1976 2.82 2.86 1.91 3.86 3.28 2.20 3.80 3.24 3.78 t 1977 3.43 3.45 2.43 4.10 3.52 2.39 4.28 3.68 4.59
-1978 3.78 3.82 2.72 4.54 3.90 2.67 4.72 4.19 5.32 1979 3.97 4.00 2.89 5.37 4.65 3.23 5.10 4.51 5.71 1980 4.57 4.51 3.32 6.02 5.29 3.77 4
1981 4.69 4.70 3.51 6.56 5.76 4.09 1982 4.90 4.92 3.72 6.61 5.81 4.11 1983 5.17 5.19 3.99 6.68 5.88 4.15 1984 4.90 4.92 3.72 6.62 5.84 4.14 1985' 5.12 5.14 3.94 6.68 5.89 4.16 (a) Actual through 1980. Estimated thereafter. (b) Missing data are not available. Rev. 1 4/81
WCGS-E R(O LS ) TABLE 1.1-2d [ ECONOMIC GROWTH INI EMPLOYMENT AND UNEMPI 1 d Employme nt Total Manufac- Construc-Se rvic Non Agric. turing tion Trade Year Wichita SMSA N 57,346 6,104 32,317 24,84 1970 139,133 24,5! 132,683 45,054 6,163 31,342 1971 6,913 33,254 2 5,1C 1972 142,079 41,042 48,558 6,983 35,263 27,1: 1973 153,763 28,8f 165,025 50,917 8,567 36,483 1974 7,563 36,881 30,3! 1975 167,962 52,442 8,458 37,683 31,0] 1976 169,979 51,221 10,008 38,425 32,5; 1977 175,942 51,317 9,233 37,675 34,0: 1978 186,688 58,800 67,312 11,592 44,267 37,0! 1979 190,089 39,3f 207,483 65,175 10,008 45,208 1980 State of Kansas N 138,033 32,342 161,267 104,5E 1972 776,828 113,45 836,250 157,717 34,958 175,842 1973 181,150 122,5; 891,183 163,058 36,792 1974 182,642 132,6d 1975 1,000,767 161,883 36,800 161,733 41,308 201,225 139,95 1976 872,456 148,8: 994,900 168,642 44,142 209,558 1977 215,7G8 154,55 197P 1,045,083 183,258 44,200 199,133 51,050 224,342 163,8C 1979 1,104,467 172,8( 1,107,833 187,700 48,392 227,908 1980 Kansas City SP 117,600 25,900 126,400 82,3( 1971 511,400 526,300 118,500 27,500 131,700 86,91 1972 138,500 95,41 1973 549,600 122,100 26,900 117,000 25,200 141,500 99,9I 1974 554,300 550,000 108,600 25,00'. 140,700 103,61 1975 146,100 110,8' 1976 571,200 114,100 2 4,7 'J O 119,700 24,400 153,500 116,6I 1977 595,500 28,S00 161,700 120,9I 1978 623,500 124,500 127,41 637,800 127,900 29,400 161,800 1979 155,800 131,0 Nov '80 617,700 119,900 24,400 State of Miss-427,100 71,300 379,200 262,7 1971 1,655,000 1,699,300 438,300 72,000 391,900 274 9 1972 407,800 293,9 1973 1,770,500 457,000 75,800 450,000 72,800 418,500 304,9 1974 1,790,500 405,300 69,500 412,000 311,6 1975 1,740,600 424,900 72,200 428,500 326,5 1976 1,797,800 1,861,800 439,600 77,800 446,100 340,1 1977 465,800 360,4 1978 1,953,100 456,800 84,300 2,002,900 459,700 92,000 475,400 378,d 1979 483,900 392,1 Nov '80 1,986,600 429,900 77,200 f *l Yearly Source, averages Center for Business and Economic Research Wichita State University (c) Source, Employment and Earnings
/ U.S. Dept. of Commerce
(
,/
,/
I ICATORg I OYMENT g Aircraft Unemploy- Unemploy-ies and Parts ment 4 Population ment U.S. t l 6 20,867 8.1 389,352 0 15,650 4.9 9.1 5.9 0 19,413 5.7 9 24,404 5.6 3.6 4.9 3 27,825 3.7 4 30,221 5.7 5.6 3 28,950 5.4 8.5 27,829 7.7 1 4.8 394,900 7.0 3 33,654 3.5 ' 0 40,825 2.7 6.0 7 40,442 5.8 3.8
')
3 4.0 2,249,071 (1970) 0 3.1 5 3.4 2 4.6 8 4.2 3 4.1 0 2,320,996 3.2 8 2.9 8 4.0 SA(# 0 5.6 1,273,926 0 4.3 (1970) 0 4.2 0 4.6 0 6.8 U 6.0 0 5.7 0 4.2 0 1,517,600 4.3 0 6.4 pri ICI 3 3 4.9 4,677,623 (1970) 4.2 @ 3.9 8 4.6 e 6.8 6.2 8 5.9 4,860,000 5.0 8 4.5 7.1 Rev. 1 4/L1
O.
. - .s s WccS-ERIOLS)
TABLE 1.1-25 NG6E COMPARISON OF FORECAST AND ACTUAL PEAR LOADS AND l ENERGY BY YEARS 1972-1980 AND MONTHS 1978-1980 1 Forecast Peak Load Forecast Energy Sales Month 6 Date Made Forecast Actual Difference
- Date Forecast Actual Difference"!
Year MW MW 4 GWH GMt 4 1972 12/21/71 1130 1137 ' - 0.6 12/21/71 $209 5225 - 0.3 1973 b b 1202 b b b 5516 b l 1974 1/10/74 1350 13'5 1.9 1/10/74 6268 5799 7.5 1975 1/28/75 1410 1337 5.2 1/28/75 6266 6199 1.1 1976 2/10/76 1460 1387 5.0 2/18/76 6845 6442 5.9 1977 2/21/77 1495 1423 4.8 2/21/77 6776 6685 1.3 1978 4/11/78 1540 1533 1.5 - 4/11/78 7231 7184 0.4 1979 3/29/79- 1585 1473 7.1 3/29/79 7629 7189 5.7 1980 1/14/80 1585 1727- - 9.0 1/14/80 7451 7807 - 4.8 Jan 1978 1/16/78 1050 1056 - 0.6 11/23/77 611 621 - 1.6 Feb 980 1018 - 3.9 525 547 - 4.2 Mar 920 1009 - 9.7 553 539 2.5 Apr 890 832 6.5 514 475 7.6 May 1060 1117 - 5.4 560 527 5.9 Jun 1340 1379~ - 2.9 625 623 0.3 Jul 1540 1491 3.2 767 787 - 2.6 Aug 1540 1533 0.5 737 743 - 0.8 Sep 1400 1458 - 4.1 561 655 -12.3 Oct 1050 954 9.1 561 525 6.4 Nov 1000 98 '/ 1.3 559 535 4.3
/ h Dec 1080 til? - 3.0 619 606 2.1 ,
s,,, Total 7213 7184 0.4 s Jan 1979 2/14/79 1120 1120 0.0 12/31/78 661 669 - 1.2 Feb 1100 1098 0.2 572 575 - 0.5 Mar 1020 940 7.8 596 552 7.4 Apr 920 915 0.5 540 502 7.0 May 1100 967 12.1 554 529 4.5 Jun 1400 1369 2.2 685 606 11.5 Jul 1585 1459 7.9 821 741 10.8 Aug 1585 1473 7.1 774 719 7.6 Sep 1500 1348 10.1 614 593 3.5 Oct 1000 1027 - 2.7 575 549 4.7 Nov 1040 1032 0.8 594 557 6.6 Dec 1360 1060 9.4 643 596 7.9 Total 7629 7189 6.1 Jan 1980 2/8/80 1100 1102 - 0. 2 ' 2/8/80 692 629 9.1 Feb 1085 1066 1.8 589 590 - 0.2 Mar 1007 1025 - 1.8 580 590 - 1.7 Apr 908 941 - 3.6 538 521 3.2 May 1086 1092 - 0.6 566 550 2.8 Jun 1382 1626 -17.7 669 721 - 7.8 Jul 1585 1727 - 9.0 753 938 -24.6 Aug 1585 1663 - 4.9 707 841 -19.0 Sep 1481 1564- - 5.6 615 682 -10.9 Oct 990 1037 - 4.7 %42 563 - 3.9 i Nov 1025 1025 0.0 579 $58 3.6 Dec 1140 1073 5.9 621 624 - 0.5
~
Total 7451 7807 - 4.8 g When forecast is below actual, difference is negative ;-[ c.% Not available t J Rev. 1 , , fss,/ , 4/81 i l 1
l l l l WCGS-E R(OLS ) TABLE 1.1-26 O1 NCFL COMPARISON OF FORECAST SND ACTUAL PEAR LOADS AND ENERGY BY YEARS 1972-1980 AND MONTHS 1978-1980 Forecast Peak Load Forecast Energy Sales Month 6 Date Made Forecast Actual Difference Date Forecast Actual Difference Year NW MW 4 GWH GWH % 1972 10/21/71 1700 1676 1.4 10/27/71 6571 6614 - 0.6 1973 10/31/72 1800 1757 2.4 11/01/72 6944 7081 - 2.0 1974 11/12/73 1900 1907 - 0.4 11/12/73 7554 6970 7.3 1975 10/02/74 1940 1903 1.9 10/31/74 7330 7247 1.3 1976 3/25/76 1995 1920 3.8 3/25/76 7831 7436 5.0 1977 11/09/76 2035 1980 2.7 11/09/76 8069 7900 2.1 1978 9/26/77 2110 2097 0.6 9/26/77 8366 8359 0.1 1979 - - 1964 - - - 8218 - 1980 11/14/79 2157 - 21*8 - 1.9 5/21/79 8914 8612 3.5 9/26/77 9/26/77 Jan 1978 1250 1274 - 1.9 673 668 0.7 Feb 1260 1276 - 1.3 646 659 - 2.0 Mar 1180 1199 - 1.6 632 652 - 3.2 Apr 1215 1156 4.9 590 618 - 4.8 May 1530 1500 2.0 613 587 4.2 Jun 1930 1953 - 1.2 667 653 2.1 Jul 2110 2052 2.8 809 778 3.8 Aug 2110 2097 0.6 867 845 2.5 Sep 2005 2050 - 2.2 878 971 0.8 Oct !?tt 1254 5.4 700 734- - 4.9 Nov 1255 1243 1.0 645 637 1.2 Dec 1300 1286 1.1 646 657 - 1.7 Total 8366 0359 0.1 1979 NA 1/30/80 5/21/79 Jan 1980 1345 1280 5.1 724 687 5.4 Feb 1316 1274 4.9 705 673 4.8 Mar 1275 1217 4.8 689 667 3.3 Apr 1303 1289 1.1 650 641 1.4 May 1527 1395 9.5 637 541 17.7 Jun 1877 2034 - 7.7 699 691 1.2 Jul 2157 2198 - 1.9 856 936 - 8.5 Aug 2157 2149 0.4 917 934 - 1.8 Sep 1880 2001 - 6.0 914 877 4.2 Oct 1389 1210 8.5 752 683 10.1 I Nov 1347 1233 9.2 678 618 9.7 Dec 1384 1299 6.5 693 664 4.4 Total 8914 8612 3.5 Due to a strike no forecast was made for 1979 in 1978. Rev. 1 4/81 0
WCGS-ER(OLS) TABLE 1.1-27 KG&E and KCPL INTERCHANGE BUDGET FOR 1984-1985 KG&E I 1984 1985 Energy Capacity Energy Capacity In MWH In MW In MWH In MW_ _ Purchases Firm 0 0 0 0 Non-firm 400,000 0 400,000 0 Total 400,000 0 400,000 0 Sales I Firm 240,000 46 200,000 38 40 O Non-firm 760,000 50 760,000 ! Total 1,000,000 96 960,000 78 f r KCPL I Purchases ! 59,250 25 59,250 25 r Firm 536,880 - 465,360 - Non-firm i 596,130 25 524,610 25 , Total Sales 58,065 25 58,065 25 Firm 261,110 - 242,730 - Non-firm , 319,175 25 300,795 25 Total l
\ /
v Rev. 1 4/81
WCGS-ER(OLS) TABLE 2.1-28 KG&E MONTHLY LOADS AND INTERCHANGE, FIRST TWO YEARS WITH WCGS IN SERVICE Year Month I
,"eak (MW) Energy (1000 MWH)_
1984 Jan Purchases (1000 MWH)_ sales (2000 MWH) 1250 715 60 Feb 90 1253 600 60 March 1150 90 597 30 April 1040 80 551 20 May 1240 80 580 20 June 1580 70 682 30 July 1785 80 803 40 Aug us t 1785 70 758 40 Sept. 1690 70 618 20 Oct. 1130 80 571 20 Nov. 1170 90 624 20 Dec. 1300 100 673 40 100 1985 Jan. 1290 735 60 Feb. 1270 90 616 60 March 1180 90 615 30 April 1070 80 567 20 May 1280 80 595 20 June 1620 70 700 = 30 July 1845 80 824 40 August 1845 70 781 40 Sept. 1740 70 662 20 Oct. 1160 80 586 20 Nov. 1200 90 643 20 Dec. 1340 100 695 40 100 Rev. I 4/81 0
.- -__ . . . . - - . . - - ~ _ - - - - _ - - . .. - - . - . . - _ - - - - _ _ . -- __- .- . .-- - -.
\ WCGS-ER(OLS)
G TABLE 1.1-29 1 I KCPL
' MONTHLY LOADS AND INTERCHANGE, FIRST TWO YEARS WITH WCGS IN SERVICE i, -
Year Month Peak (MW) Energy (1000 MWH) Purchases (1000 MWH) Sales (1000 MWH) ; [ 1984 Apr 15(1 809 25.08 10.04 May 1793 857 37.39 14.86 Jun 2305 981 32.01 22.48 i Jul 2460 1205 88.51 14.97 Aug 2485 1140 54.24 30.19 Sep 2269 918 29.91 41.03 Oct 1584 872 57.74 41.32 Nov 1573 872 49.73 46.34 Dec 1694 925 45.68 19.28 i l 1985 Jan 1723 986 17.35 21.98 J
- Feb 1702 898 17.00 14.00 Mar 1615 905 21.89 28,78 Apr 1606 843 37.28 10.29 May 1864 889 16.25 32.88 Jun 2397 1025 25.79 26.96 Jul 2574 1257 81.27 12.50 Aug 2574 1181 101.44 15.65 Sep 2358 954 60.24 32.43 Oct 1647 907 45.17 18.79
} Nov 1663 910 20.45 13.00 Dec 1762 961 21.22 15.46 Rev. 1 4/81 l i i i 1 1 . k i
-- - . ~ , - , - . - , r --- - , - - , ,~,w.-, ,,...,e,--. ---,.m .e.m-.--. ---rry, , --.r_--..e,.-,,y
O O WCGS-ER(OLS) TABLE 1.1-30 PROJECTED FUEL MIX FIRST THREE YEARS OF PLANNED OPERATIONS WITH AND WITHOUT WCGS (TOTAL GENERATION) l IN PERCENT High Capacity Factor" Low Capacity Factor" 1984 1985 1986 1984 1985 1986 Fu21 Type With Without With Without With Without With Without With Without With Without WCGS WCGS WCGS WCGS WCGS WCGS WCGS WCGS WCGS WCGS WCGS WCGS KG&E Coal 61.7 b b b b 57.4 60.4 61.7 57.4 60.4 Oil 0.3 1.7 1.2 0.3 2.3 1.8 , Gno 16.3 13.4 9.7 19.9 17.4 13.5 Nuclear 21.7 27.5 28.7 18.1 22.9 24.3 Tctal 100.0 100.0 400.0 100.0 100.0 100.0 KCPL Coal 82.3 97.3 78.1 97.0 75.3 93.2 84.5 97.3 80.8 97.0 78.7 93.2 Oil 1.9 2.6 1.9 2.9 3.6 6.8 1.8 2.6 1.9 2.9 3.9 6.8 Gno 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Nuclear 15.7 - 19.9 - 21.0 - 13.6 - 17.2 - 17.4 - Total 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 NOTE: May not' add due to rounding.
- Represent's the fuel mix for high and low capacity factors of the WCGS expected operating range.
b Fuel mix for years without WCGS will be provided later. Rev. 1 4/81
- __ ~ . _ - _ _ _ . _ . ___ ..
4 WCGS-ER(OLS) l
/N TABLE 1.1-31
\\-') PROJECTED FUEL MIX, PEAK DAY GENERATION PERCENTAGE DISTRIBUTION 1985 1990 Fuel 1980 With, Without With, Without WCGS WCGS WCGS WCGS l KG&E Coal 50 43 50 46 46 Oil 0 )
) 30 43 30 44 Gas 50 )
Nuclear - 27 0 24 0 Purchases 0 0 7 0 10 Total 100.0 100.0 100.0 100.0 100.0
.I Q KCPL Coal 87 83.7 82.6 71.5 74.1 Oil 10 2.9 4.5 5.6 11.0 Gas 3 0.1 0.1 0.1 0.1 Nuclear -
13.3 0 22.8 0 Purchases 0 0 12.8 0 14.8 Total 100.0 100.0 100.0 100.0 100.0 Assumes median capacity factor for WCGS.
\s
**1781
WCGS-ER(OLS) f TABLE 1.1-32 KG&E ACTUAL AND PROJECTED FUEL COSTS 1980-1990 f Month Coal Oil Gas Nuclear System
& Year $/ Ton C/MMBTU $/Bb1 C/MMBTU $/MCF C/MMBTU C/MMBTU C/MMBTU 1980 Jan 21.68 128.49 12.55 197.50 1.56 162.88 -
152.26 Feb 18.34 107.30 12.93 202.68 1.56 163.72 - 139.43 Mar 15.74 92.85 14.77 232.53 1.62 167.58 - 139.89 Apr 16.42 89.93 - - 1.59 165.76 - 133.59 May 16.56 92.60 - - 1.45 150.83 - 118.31 Jun 16.34 93.00 18.81 296.78 1.68 175.89 - 135.14 Jul 16.14 89.50 13.32 209.53 1.71 177.51 - 131.82 Aug 16.20 89.58 12.56 198.72 1.56 162.89 - 125.32 Sep 16.69 94.99 12.95 204.15 1.53 159.37 - 121.36 Oct 16.02 96.07 12.70 199.44 1.55 163.36 - 128.29 Nov 17.12 100.07 20.14 316.32 1.82 189.71 - 141.76 Dec 16.55 93.27 21.78 390.39 1.83 190.97 - 128.78 1981 Jan 18.33 103.57 12.32 195.48 1.65 171.97 - 125.25 Feb 18.67 106.18 13.34 211.70 1.53 159.79 - 122.99 ' Mar 19.22 107.27 13.31 211.29 1.76 183.16 - 143.02 Apr 20.31 113.36 - - 1.82 189.89 - 142.52 May 19.51 114.58 - - 1.97 205.66 - 166.78 Jun 19.89 112.26 - - 1.74 181.35 - 135.72 Jul 19.80 112.73 - - 1.83 190.37 - 146.80 Aug 20.25 114.72 - - 1.71 178.34 - 138.19 Sep 20.30 116.40 - - 1.89 197.86 - 151.88 Oct 19.75 115.07 - - 1.86 200.59 - 153.05 Nov 22.15 119.85 - - 1.84 192.66 - 143.96 Dec 20.78 118.08 - - 1.80 187.72 - 143.94 By Year , 1980 36.86 96.07 12.74 205.49 1.62 169.29 - 132.69 1981 19.91 112.66 13.19 209.35 1.30 187.98 - 142.46 1982 22.61 128.09 14.39 228.36 2.05 214.23 - 162.75 1983 25.55 145.27 15.85 251.59 2.45 256.05 - 187.23 1984 27.73 157.80 17.62 279.66 2.55 266.74 78.60 161.78 1985 30.60 174.18 30.29 480.87 3.19 333.90 78.60 179.94 1986 33.25 189.80 35.57 564.61 3.73 390.64 67.50 186.24 1987 36.31 207.56 38.51 611.32 4.23 442.66 67.60 190.02 1988 40.14 229.25 42.86 672.32 4.66 487.19 70.90 213.60 1999 44.08 252.02 47.35 751.74 5.26 550.05 76.70 244.76 1990 48.72 278.36 52.60 835.13 6.44 673.94 82.80 290.92 Burned Costs. Assumes median capacity factor for WCCS. Rev. 1 4/81
l WCGS-ER(OLS)
/
(
's, TABLE 1.1-33 KCPL ACTUAL AND PROJECTED FUEL COSTS 1980-1990 M: nth Coal oil Gas Nuclear System
& Year T/ Ton C/MMBTU $/Bb1 C/MMBTU $/MCP C/MMBTU C/MMBTU C/MMBTU 1980 Jcn 18.37 93.80 19.09 330.71 1.75 183.79 -
99.58 Feb 18.40 94.66 19.06 330.16 1.88 198.16 - 97.48 M2r 19.19 98.44 20.13 238.72 1.85 194.46 - 106.41 Apr 18.87 92.09. 19.63 340.05 1.85 194.33 - 100.70 MEy 17.81 94.06 20.09 247.62 2.36 248.24 - 103.06 Jun 18.23 96.75 20.59 356.38 2.23 234.99 - 111.27
; Jul 19.09 99.83 22.00 380.58 2.23 234.82 -
116.87 Aug 19.12 99.91 25.14 434.84 2.23 234.91 - 114.62 Szp 19.70 103.89 26.07 451.00 2.25 236.22 - 113.86 i Oct 20.36 110.33 27.46 474.92 2.27 238.76 - 117.67 Nov 19.95 108.01 30.72 529.02 1.56 164.21 - 111.94 Dec 19.54 103.43 6.31 108.78 2.40 252.59 - 107.02 1981 l Jan 23.59 122.85 43.11 739.05 2.62 262.50 - 134.21 p sFeb 23.81 123.84 43.00 740.16 2.50 250.00 - 138.02
' jer 24.95 125.52 35.21 740.48 2.62 276.17 -
149.09 k ,/Apr s 23.36 122.02 42.85 739.74 2.62 275.66 - 146.38 May 23.46 123.33 43.36 740.24 2.62 275.88 - 145.78 Jun 23.20 121.50 42.61 739.87 2.62 275.66 - 146.92
, Jul 23.51 122.46 43.10 740.29 2.62 275.58 -
165.40 Aug 23.37 121.87 42.98 741.13 2.62 275.72 - 155.27 Sep 23.29 122.42 43.38 741.45 2.62 275.89 - 150.84 Oct 23.71 123.82 43.07 740.23 2.62 275.55 - 146.12 Nov 24.56 125.50 43.21 740.71 2.62 276.04 - 159.21 Dec 26.15 130.16 43.34 740.97 2.50 250.00 - 148.99 Year
- 1 1980 19.10 100.10 22.06 381.52 2.12 222.97 -
109.43 I 1981 23.87 123.68 42.98 740.44 2.62 275.80 - 149.19 t 1982 26.15 137.70 48.50 836.86 3.28 344.79 - 157.97 1983 29.05 153.35 54.83 945.65 4.10 431.46 - 170.87 4 1984 31.73 168.23 61.90 1068.20 5.14 540.79 77.4 171.68 1985 34.74 184.47 70.21 1207.51 6.44 677.63 77.4 184.36 1986 38.14 202.54 78.00 1384.68 8.05 850.00 66.7 221.43 1987 41.32 221.18 86.76 1896.19 10.08 1060.53 67.0 220.10 1988 45.35 243.58 96.64 1664.88 12.61 1327.63 70.1 240.29 1989 49.92 268.41 107.64 1855.16 15.79 1666.67 75.7 268.74 1990 54.24 294.06 120.71 2080.85 19.76 2080.03 81.3 290.58
" Burned costs. Assumes median capacity factor for WCGS.
i
) Rev. 1 V 4/81 I
I 1
f WCGS-ER(OLS) TABLE 1.1-34 l FUEL COSTS AS A PERCENTAGE OF TOTAL OPERATING COSTS 1965-1980 Year KG&E KCPL 1965 20.9 18.5 1966 21.3 18.6 1967 23.1 , 17.2 1968 22.6 14.6 1969 24.8 18.8 1970 24.7 22.3 1971 25.6 23.6 1972 , 25.1 . 24.5 1973 27.5 23.2 1974 30.7 25.2 l 1975 39.8 26.6 1976 37.5 29.1 1977 45.2 33.3 1978 48.1 34.4, 1979 49.7 31.4 1980 49.7 34.9 l Outages caused this anomaly 1 O Rev. 1 4 4/81
) %J 100 -
90
- 80 -
70 - o 60 - I 3 50 - a E 2 40 - 30 - 20 - IO - 0 - O to 20 30 40 50 60 70 80 90100 l l
% TIME l Rev. 1 4/81 WOLF CREEK GENERATING STATION UNIT NO. I D"<MNTAL REPORT 10PERATING LICENSE ST4iG l FIGURE 1.1-1 KG&E LOAD DURATION CURVE f 1984
100 - O 90 80 - 70 - l i cr 60 - o I I 2 50 - a 2 E 40 - I 2 m - 20 - 10 - 0 O 10 20 30 40 50 60 70 80 90 10 0
% TIME I
l Rev. 1 4/81 WOLF CREEK GENERATING STATION UNIT NO. I DMROMENTAL REPORT (PERMING LIENSE STMiF3 FIGURE 1.1-2 KG&E LOAD DURATION CURVE 1985 c-.e--,,, v,.wm..._e...,v_. -
O 100 c 1 90 - 80 - kO 70 - _J
@ 60 I
g 50 - d a 40 - 5 b 30 . H 5 20 - n. 10 - 0 C 0 20 30 40 '50 60 70 80 90 100 PERCENT OF TIME l I Rev. 1 4f81 WOLF CRE5K GENERATING STATIO,N ; UNIT NO. I !
' DMRONMENTAL ftEPCRT QPERSTING LICENSE STMiG s _-
FIGURE 1.1-3a KCPL LOAD DURATION CURVE 1984 l I _.______m_____.
- _ . ,r . , -- - - - - - ---
I 10 0 90 - I 80 - l l O o 70 - m i 60 - N y 50 - a g 40 -
<t '6 30 -
i b o
@ 20 -
c. 10 - 0 ' ' ' ' ' ' ' ' ' O 10 20 30 40 50 60 70 80 ry 10 0 PERCENT OF TIME Rev. 1 4/81 l WOLF CREEK GENERATING STATio,N l UNIT NO. I DMROMENTAL REPORT (PERATING LKENSE SM FIGURE !.1-3b KCPL LOAD DURATION CUR'/E 1985 __. . _ . . _ . _ . . . _ _ _ _ _ _ - ~ . _ . _ . - - - ~
1 l (
)
100 - 90 80 - ic 4 y 70 - 8 60 - Z - y 50 - n. 4 m 40 - 4 Z
< 30 -
2 ( tu ( o 20 - 10 - O O 10 20 30 40 50 60 70 80 90 10 0 TIME AS A PERCENT OF THE YEAR Rev. 1 4/81 WOLF CREEK GENERATING STATION UNIT NO. I DMRONMENTAL REPORT OPERATING LICENSE STAGQ FIGURE 1.1-4 (f KEPCO LOAD DURATI0tl CURVE 1984-1985
1800 - 1600 - 1400 - 1200 - 1000 - 800 - 600 - o k i I hiY I8 I yJ 24 4 8 12 16 20 24 HOURS l l Fev. 1 4/81 WOLF CREEK GENERATING STATIO,N UNIT NO. I DMR0pmENTAL REPORT (PERATING LICENSE dM l FIGURE 1.1-5 KG&E I!0URLY LOAD CURVE TYPICAL SUMMER PEAK DAY l
- a. . -. _ _ - _ - - _ _ - - _ . . - _ - . . . . . . - . . . . . . - - _ . - .
O 1600 - 1400 - 1200 - y 1000 - 2 800 - 600 - 400 - t 0 ' ' i , , 12M 4AM BAM 12N 4PM 8PM 12M HOURS l l i Rev. 1 4/g1 WOLF CREEK GENERATING STATION UNIT NO. I DMRONMENTAL REPORT CPERATING UCENSE STAGE) FIGURE 1.1-6 KG&E HOURLY LOAD CURVE TYPICAL WINTER PEAK DAY
v 1200 - 1000 - 800 - 600 - 400 - 200 - T b 4k eb i 4k ek E (3 HOURS l l l l WOLF CREEK GENERATING STATION I UNIT NO. I I DMRONMENTAL REPORT OPERATING UCENSE STNiG l FIGURE 1.1-7 KG&E HOURLY LOAD CURVE ( TYPICAL SPRING-FALL DAY l l
- 0 2200 -
2000 - 1800 - 1600 - 1400 3 2 1200 - 1000 - 800 - 600 - Ot'12M 4AM 8AM 12N I 4PM i 8PM J (2M HOURS I i i Rev. 1 4/81 WOLF CREEK GENERATING STATIO,N UNIT NO. I DMRONMENTAL REPORT OPERADNG UCENSE SM FIGURE 1.1-8 , KCPL HOURLY LOAD CURVE ! TYPICAL SUMMER PEAK DAY l i l f
I l l k v 2200 - 2000 - 1800 - 1600 - i 1400 - 1
)
2 1 1200 4 I 1000 - j 800 - o 600 - 12M 4AM 8AM 12N 4PM 8PM 12M HOURS l Rev. 1 4/81 WOLF CREEK GENERATING STATION ~ UNIT NO. I DMONENTAL REPORT (PERATlW LICENSE STME) FIGURE 1.1-9 KCPL HOURLY LOAD CURVE WINTER PEAK DAY 1980 i 1
W O 1800 - 1600 - 1400 - 1200 - 2 1000 - i 800 600 - 4 0 12M 4AM 8AM 12N 4PM 8PM 12M HOURS WOLF CREEK GENERATING STATION UNIT NO. I ENVIRONMENTAL REPORT OPERATING UCENSE STAGO FIGURE 1.1-10 q j KCPL HOURLY LOAD CURVE TYPICAL SPRING-FALL DAY
i WCGS-ER(OLS) 1.2 OTHER OBJECTIVES
\ '
There are no other objectives to be met by the operation of WCGS than the production of power and energy ~ to be used in the service areas of the Applicants. 1 i j l a 5 t i I e 1
= l i
l' l s 1.2-1 i e
, . . . .-_~ -.-..._m. ..,....___..m. . - .. - . . . - , _ _ _ . _ _ , . . . _ _ _ _ . . _ _ . _ _ _ _ _ . . _ _ . _ . . _ _ _ _ _ _ . _ , . _ _ _ _ . . . - -
l l WCGS-ER(OLS)
/7 1.3 CONSEQUENCES OF DELAY '\ /
The consequences of delay will be serious for each of the Applicante in terms of declining margins, increasing fuel costs, consuming additional quantities of replacement fossil fuels, and incurring higher financing costs. 1.3.1 EFFECTS OF DELAY ON RESERVE MARGINS The table below shows for KG&E, KCPL and the pools the re- I duced reserve margins that will exist with a one, two, or three year delay.on WCGS. This tables does not reflect the total system obligations of the Applicants shown in Tables 1.1-1 and 1.1-2. RESERVE MARGINS IN PERCENT WITHOUT WCGS Year Length of Delay KG&E* KCPL MOKAN SPP 1985 One year 14.4% 8.9% 13.0% 22.8% 1986 Two years 18.8 5.1 10.4 19.6 1987 Three years 15.2 1.5 8. 3 19.0 m Do not reflect external obligations.
.(d
\
With a one year delay, KG&E's margin would be slightly below regoirements. KCPL's would be far below its internal margin requirement and those of MOKAN and SPP even with the reten-tion of 80 MW of Northeast 1, 2, 4, 5 and 7 capacity. MOKAN would fall below its margin requirement, but SPP would be well within its margin. MOKAN is projecting a capacity increase of 12 percent and SPP an increase of over 20 per-cent between 1980 and 1984, bot there may be delays for some of this planned capacity which means that the margins will be lower than stated. Half of MOKAN's increase is represented by WCGS. l Though not listed, KEPCo would have no owned capacity because WCGS will represent its first block of owned j capacity. Though power might be available to KEPCo in l the region or from adjacent regions the economic consequen-l ces would be severe since the cooperatives would have to make commitments to parchase power at relatively high cost. l A tvo year delay would bring KCPL farther below internal and pool requirements, and KCPL would be required by MOKAN to pay capacity charges because of the reserve margin deficien-i cies. KG&E's 136 MW of added capacity in 1986 will boost I its margin above requirements. O
\ t q ,/
Rev. I 1.3-1 4/81 l l . _ _ . . _ _ _ .- ._ --.- - .._ -.-- -- -
l WCGS-ER(OLS) The MOKAN margin would have declined further to 10.4 per-cent, and the projected margin for SPP would remain comfor-tably at 19.6 percent. Of significance, though, are pro-jected capacity increases of 26.5 percent by MOKAN and 31.7 percent by SPP in the period 1980-1985. With delays, the margins shown are likely to be even lower. KEPCo would still have no reserve margin and would be forced to make arrangements to purchase high cost power. l With a three year delay KG&E's margin would barely be within regoirements, but KCPL's margin would have declined to 1.5 percent. The MOKAN reserve margin would still be below re-quirement, but the projected margin for SPP would be well within regoirements. Again it is noted that MOKAN and SPP margins are based on increases in capacity between 1980 and 1986 of 26.5 percent for MOKAN and 35 percent for SPP. It is onlikely that all of this capacity will be installed on schedole. KEPCo would still have no reserve margin and would have to make arrangements for porchase and transmission of high cost makeup power. I If external obligations are taken into account (as shown in Tables 1.1-1 and 1.1-2) the margins discossed in the three delay cases would be substantially lower. If no WCGS capacity were to be added, the effects would be the same as those for the delays except that the cooperatives would be better able to plan for long term commitments on power porchase and transmission, if both are available. A new coal-fired plant could not be planned and constracted so as to be in operation by 1984 to "986.
. The option cf par-chasing capacity from neighboring otilities for long periods of time would probably not exist. Large blocks of power l egoivalent to the capacity of a major unit are onlikely to be available on a continuing basis. Other companies in the region are experiencing delays in bringing plants on line and in obtaining financing for new plants.
1.3.2 EFFECTS OF DELAY ON FUEL CONSUMPTION There would be greater consumption of fossil fuels with substantially higher costs if there were a delay in the operation of WCGS. The following table summarizes the fuel consumption and costs per year, with comolatives also given. O Rev. 1 1.3-2 4/81
WCGS-ER(OLS ) pl t ADDITIONAL FUEL CONSUMPTION AND COSTS WITHOUT WCGS AND WITH INDICATED DELAYS Unit 1985 1986 1987 l Fuel Measure One Two Cumulative Three cumulative Year Year Year Delay Delay Delay KG&E Coal (000) Tons - - - - - Oil (000) Bbls 236 697 933 683 1,616 Gas MMCF 31,639 29,352 61,171 29,929 91,100 Net Additional Fuel Cost (000) $89,156 $137,590 $226,646 $167,034 $393,780 KCPL Coal (000) Tons 800 954 1,754 1,057 2,811 Oil -(000) Bbls 129 206 335 693 1,028 Gas MMCF 50 15 65 0 65 l Net Additional l Fuel Cost (000) $21,270 $32,994 $54,264 $82,211 $136,475 O V As shown, large quantities of coal, oil and gas would be burned to replace the nuclear fuel. With a three year delay, there would be additional consumption of 2.8 million i tons of coal, 2.6 million barrels of oil and 91 billion I cubic . feet of gas by the two companies at a net additional cost of $530 million. This does not include additional fuel burned by other utilities that would supply KEPCo. In making a comparison of fuel costs with and without WCGS, a credit is applied for unused nuclear fuel in the without WCGS case. In addition, KEPCo would be paying high costs for make-up l power and transmission. I i If the WCGS capacity were not added, these rates of consump-tion and related costs would continue until additional capa-city could be provided. 1.3.3 EFFECTS OF DELAY ON OTHER APPLICANT COSTS If there were a delay in the WCGS operating date other large additional costs woulo be incurred by the Applicants. The largest of these would be the allowance for funds used during cons truction (AFUDC). These costs are estimated as follows: O . Rev. I 1.3-3 4/81
WCGS-ER(OLS) ADDITIONAL AFUDC COSTS IN MILLIONS OF DOLLARS Period of. Delay Annual Cumulative One Year $197 $197 Two Years 220 417 Three Years 257 674 Prope rty taxes would also have to be paid, amounting to about $12 million per year. Costs for plant and support i personnel, for maintaining the . plant in a secure condition after the completion of construction and for insurance would be more than 20 million dollars per year. Total cumulative costs for each year of delay are estimated as follows: ESTIMATED TOTAL COSTS INCURRED WITH WCGS DELAY Cumulative Costs by Cost Element Period of Delay In Millions Of Dollars Fuel AFUDC Other Total One Year 117 197 31 345 Two Years 296 417 34 747 Three Years 530 674 36 1,240 l The impact of additional costs of this magnitude upon the applicants would be very serious. l
, I l
l l i e t 9 Rev. 1 1.3-4 4/81
WCGS-ER(OLS) - /m
.( \
. \ ,) 3 LIST OE TABLES (continued) t Ta bl e No . Title 2.2-11 Number of Species, Dirds per Hour, and Species Diversity of Avifauna Recorded in Two Communities near hCGS, May 1974-January 1979 2.2-12 Number of Avian Species and Individuals Observed Along the 20-Mile Wildlife Survey Route Near hCGS Site, May, 1973-January 1979 2.2-13 Eastern Cottontail and Bobwhite Population Indices Compiled along the 20-Mile Wildlife Survey Route Near WCGS, June 1973-1978 2.2-14 Amphibians and Reptiles Observed in the Vicinity of the WCGS Site 2.2-15 Major Algal Groups Comprising a Mini
- mum of 10 Percent of the Density of Phytoplankton Collected in the Neosho River, 1973-78
-2.2-16 Mean Density (Units /ml) of Phytoplankton in Samples
_ (<f s ' Collected, 1973-78
- 2.2-17 Mean Carbon Fixation Rate (mg C/m per hr) from Phytoplankton Samples Collected, 1973-78 2.2-18 Mean Chlorophyll a Concentration (mg chl a/m 3) from Phytoplankton Samples Collected, 1973-78 2.2-19 Diversity of Phytoplankton Collected, 1974-78 2.2-20 Major Algal Groups Comprising a Minimum of 10 Percent of the Density of Phytoplankton Collected in Wolf Creek, 1973-78 2.2-21 ,
Periphytic Algal Taxa Collected from Natural
- Substrates, 1973-78 2.2-22 Algal Taxa Comprising 10 Percent or More of Total Periphyton Abundance or Biovolume on Natural Substrates, 1973-78 2.2-23 Composition, Mean Density (No./m ) and General Characteristics of Zooplankton, 1973-78 3
2.2-24 Mean Seasonal Abundance (No./m ) of Major Zoo- [A
}
e' plankton Taxa Collected in the Neosho River, 1974-78 s 2.0-vii
i WCCS-ER(OLS) LIST OF TABLES (continued) Table No. Title 2.2-25 Mean Seasonal Abundance (No./m 3 ) of Major Zoo-plankton Taxa Collected in Wolf Creek, 1974-78 2.2-26 Drift Densities (No. Organisms /100 m3 ) of Selected Macroinvertebrate Families in the Tailwaters of John Redmond Reservoir on the Neosho River (Loca-tion 1), 1976-78 2.2-27 Macroinvertebrate Data from the Neosho River (Locations 10 and 4), 1973-78 2.2-28 Macroinvertebrate Densities (No./m2 ) of Selected Families f rom Wolf Creek (Locations 7,2,3, and 5) , 1973-78 2.2-29 Checklist of Fish Species Collected by all Sampling Methods, 1973-78 2.2-30 Number and Relative Abundance of Fish Collected Annually by All Sampling Methods in the Neosho River and Wolf Creek, 1973-78 2.2-31 Number and Relative Abundance of Fish Collected by Seining in Wolf Creek During the Preconstruction and Construction Phases, 1973-78 2.2-32 Number and Relative Abundance of Fish Collected by Seining in the Neosho River During the Pre-construction and Construction Phases, 1973-78 2.2-33 Fish Collected by Electroshocking in the Neosho River, 1977-1978 2.2-34 Species and Number of Fish Collected by Electro-shocking at Each Sampling Location in the Neosho River, 1977-78 l 2.2-35 Abundance of Fish Larvae Collected From the Tall-l waters of John Redmond Reservoir, 1976-78 L 2.3-1 Monthly and Annual Averagt and Extreme Temperatures l for Burlington, Topeka, and Wichita, Kansas 2.3-2 Annual Statistics and Diurnal Variation of Meteoro-logical Parameters at Wolf Creek Generating Station 2.3-3 Composite Monthly Statistics and Diurnal Variation of Meteorological Parameters at Wolf Creek Generatina Station Rev. 1 , 2.0-viii 4/81
WCGS-ER(OLS)
- A
/ \ LIST OF TABLES (continued)
Tab'le-No. Title 2.3-4 Monthly and Annual Average Dewpoint Temperatures for Topeka and -Wichita , ' Kansas 2.3-5 Mean Relative Humidity and Mean Number of Days with Heavy Fog at Topeka, Kansas 2.3-6 Mean Relative Humidity and Mean Number of Days with Heavy Fog at Wichita, Kansas 2.3-7 Monthly and Annual Average and Maximum Pr eci pi ta t io n and Snowfall for Burlington, Topeka and Wichita, Kansas 2.3-8 Maximum Short Period Rainfall fo r- Topeka and Wichi ta Kansas 2.3-9 Total Number of Days with Freezing Precipitation in Wichita, Kansas-2.3-10 Annual Precipitation Wind Rose (10-meters)
.(
Oj 2.3-11 Annual Precipitation Wind Rose ( 6 0-me te r s)
~2.3-12 Monthly Precipitation Wind Rose (10m) 2.3-13 Monthly-Precipitation Wind Rose ( 60m) 2.3 Frequency Distribution of Precipitation 2.3-15 Monthly and Annual Joint Wind Speed and Wind Direction Frequency Distribution at the Chanute Flight Service Station, Kansas 2.3-16 Persistence of Wind Direction Frequency Distribution at Chanute F.S.S., Kansas 2.3-17 Joint Wind Speed, Wind Direction Frequency Distribution by Stability Class for Chanute F.S.S. , Kansas l 2.3-18 Joint Wind Frequency Distribution (Annual - 10m) 2.3-19 Joint Wind Frequency Distribution (Annual - 60m) 2.3-20 Joint Wind Frequency Distribution (Monthly - 10m)
, - ~ 2.3-21 Joint Wind Frequency Distribution (Monthly - 60m)
(. %.-
)
Pev. 1 2.0-ix 4/81
WCGS-ER(OLS) LIST OF TABLES (continued) Table No. Title k 2.3-22 Joint Wind Frequency Distribution by Stability Class (Annual - 10m) 2.3-23 Joint Wind Frequency Distribution by Stability Class ( Annual - 60m) 2.3-24 Joint Wind Frequency Distribution by Stability Class (Monthly - 10m) 2.3-25 Joint Wind Frequency Distribution by Stability Cla,s (Monthly - 60m)
- 2. :;-2 6 Wind Direction Persistence 2.3-27 Average Monthly and Annual Daylight Cloud Cover and Sunshine for Topeka and Wichita, Kansas 2.3-28 Persistence of Stability Frequency Distribution at Chanute F.S.S., Kansas 2.3-29 Stability Persistence Summary 2.3-30 Average Monthly and Annual Number of Days with Thunderstorms at Topeka and Wichita, Kansas 2.3-31 Number, Probability, and Recurrence Interval of Tornado Occurrences Per One Degree Longitude-Latitude Square in Kansas 2.3-32 Tornado Summary for Kansas 2.3-33 Fastest Mile of Wind for Eastern Kansas Using Fisher-Tippet Type I (Frechet) Distribution 2.3-34 Fastest Mile of Wind for Topeka and Wichita, Kansas 2.3-35 (Table Deleted) 2.3-36 (Table Deleted) 2.3-37 (Table Deleted) 2.4-1 Precipitation and Snowfall Data for Burlington, Kansas 2.4-2 Natural Streamflow of the Neosho River (1948-1963)
Rev. 1 I 2.0-x 4/81
WCGS-ER(OLS)
, A-( LIST OF TABLES (continued)
Table No. Title 2.4-3 Regulated Stream Flows of the Neosho River from 1964 to 1977. 2.4-4 In-Channel Hydraulic Parameters for the Neosho River 2.4-5 Municipalities and Rural Water Districts in Kannas Utilising the Neoshu River Downstream of the Site 2.4-6 Hydrogeclogic Characteristics of Bedrock Within a 5-Mile R3dius of Site 2.4-7 ' Permeabilities of Rock Units by Depth 2.4-8 Piezometer Water Level Readings-B-Borings 2.4-9 Piezometer Water Level Readings-P-HS-ESW-LK Borings 2.4-10 Cooling Lake Seepage Analysis 2.4 Summary of Surface Water Quality Data Collected ( ' During the Preconstruction and Construction Mon-itoring Studies
- 2.4-12 Summary of Groundwater Quality Data from 1973-78 2.4-13 Kansas Water Quality Criteria Applicable to the Neosho River t
I l r l I l + l . , (/"N s_-
/ f
. r Rev. 1 i
' 2.0-xi 4/81 l i I
hCGS-ER(OLS) l LIST OF TABLES (continued) Table No. Title 2 ;-l Modified Mercalli Intensity (Damage) Scale of 1931 2.5-2 Seismic Events Significant to the Site ' 2.5-3 Earthquakes Perceptible at the Site i O i
.t i O
2.0-xii j l J
e WCGS-ER(OLS) l l 1
-ry' (q ,/ LIST OF FIGURES I
CHAPTER 2.0 - THE SITE AND ENVIRONMENTAL INTERFACES Figure No. Title 2.1-1 Location of Site Within the State of Kansas i 2.1-2 ' Location of Site Within Cof fey County 2.1-3 Property Owned by Applicant 4 2.1-4 Plant Site Features 2.1-5 Layout of Dams, Dikes, Spillways, and Outlet Works 2.1-6 Site Features 2.1-7 Transportation Network Near the Site 2.1-8 Cities and Towns Within 50 Miles of the Site q 2.1-9 1970 Resident Population 0 to 10 Miles (\s /) 2.1-10 1980 Resident Population 0 to 10 Miles i 2.1-11 1990 Resident Population 0 to 10 Miles 2.1-12 2000 Resident Population 0 to 10 Miles 2.1-13 2010 Resident Population 0 to 10 Miles t i 2.1-14 2020 Resident Population 0 to 10 Miles 2.1-15 1970 Resident Population 10 to 50 Miles 2.1-16 1980 Resident Population 10 to 50 Miles 2.1-17 1990 Resident Population 10 to 50 Miles 2.1-18 2000 Resident Population 10 to 50 Miles 2.1-19 2010 Resident Population 10 to 50 Miles , l 2.1-20 2020 Resident Population 10 to 50 Miles
-2.1-21 Public Facilities and Institutions Within 5 Miles of the Site 2.0-xiii l
WCGS-ER(OLS) LIST OF FIGURCS (continued) Figure No. Title 2.1-22 Comulative Population Density, 1970 to 2020, within 50 Miles of the Site 2.1-23 Land Use Within 5 Miles 2.1-24 Zoning Within 5 Miles 2.1-25 Water Withdrawal Points on the Neosho River in Kansas Downstream of the Site 2.1-26 Municipal Ground-Water Supplies Within 20 Miles of the Site 2.1-27 Well Inventory Within 5 Miles 2.2-1 'ierrestrial Ecology Sampling Locations 2.2-2 Average Bimonthly Chlorophyll a and Biomass Values for Periphyton Collected from Natural Substrates, 1973-78 2.2-3 Average Bimonthly Density and Biovolume Values for Periphyton Collected from Natural Substrates, 1973-78 2.3-1 Regional Climatological Stations 2.3-2 Topographic Features Within 5 Miles of the Plant Site 2.3-3 Topographic Features Within 50 Miles of the Plant Site 2.3-4 Topographic Cross Sections Within a 5-Mile Radius of the Site 2.3-5 Topographic Cross Sections Within a 50-Mile Radius of the Site 2.3-6 Meteorological Tower Plot Plan 2.3-7 Hail Re po r t s , 1955-1967 2.3-7a Tornado Reports by One-Deg ree Squares, 1955-1967 2.3-8 Wind Gusts, 1955-1967 2.3-9 Wind Storms by One-Degree Squares, 1955-1967 Rev. 1 2.0-xiv 4/81
. - . - . _ , - - . . - - ~ . . . - - . . _ _ _ . - - - - . - . - - . ~ . _ . - _ .
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- WCGS-ER(OLS).- - -i p 3:. .
4 e LIST OF FIGURES (continued)~ l : J I' Figure No.. Title y. r "2.3 -. Wind Storms:by Two-Degree Squares, 1955-1967 ! + ( i 4 4 i I 5 i
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WCGS-ER(OLS) t 2.3 METEOROLOGY x The meteorology of-the Wolf Creek Generating Station. site and vicinity have previously been described in Section 2.6 of the Environmental Report - Construction Permit Stage [ER(CPS)]. Section 2.3 of the ER(OLS) updates some of the information previously presented, presents some new -information, and f also repeats. much of the information from the ER(CPS) for continuity.
' - All onsite meteorological conditions presented in the ER(OLS)
~are based on the 3-year period from June 1, 1973 to May 31, 1975 and March 5, 1979 to March 4, 1980. The ER(CPS) re-ferenced only the first 12 months of this period. Onsite data for temperature, water vapor, stability, and wind persistence are now included in the ER(OLS), whereas before they were only presented in the Preliminary Safety Analysis Report. Long-term data for cloud cover, sunshine, and the fastest mile winds at
~ Topeka and Wichita are also new.
The long-term data bases for temperature, water vapor, and precipitation in the ER(OLS) have been updated to the following years: WICHITA TOPEKA
/S( DATA ER (CPS) ER(OLS) ER (CPS ) ER(OLS).
Temperature (average) 1931-1960 1941-1970 1931-1960 1941-1970 (extremes) 1965-1972 1953-1978 1966-1972 1947-1978 Wa te r Va po r
' (relative humidity) 1953-1963 1954-1978 1964-1968 1965-1978 (fog) 1953-1963 1954-1978 1964-1968 1947-1978 Precipitation (average) 1931-1960 1941-1970 1931-1960 1941-1978 (snowfall) 1954-1972 1954-1978 1947-1972 1947-1978 The indicated revisions to Section 2.3 of the ER(OLS) have been made to incorporate new data and to maintain consistency witn the more comprehensive treatment of meteorology presented in Section 2.3 of the Final Sa fety Analysis Report.
i I l l ? ! l 's / , I 2.3-1 l Rev. 1 4/81 i
l WCGS-ER(OLS) 2.3.1 GENERAL O The climate of east-central Kansas is continental, charac-terized by rapid changes in temperature, marked extremes, and large daily and annual temperature ranges. Kansas weather is largely affected by two physical features: the Rocky Mountains to the west, and the Gulf of Mexico to the south. The mountains on the west prevent the import of moisture from the Pacific Ocean, while the Gulf is the moisture source for much of the precipitation in Kansas. The topography of the general site area consists of undulating terrain. The microclimate of the area is largely a result of the synoptic-scale weather phenomena with only a weak influence from the terrain; weather is uniform over the landscape. In the following' sections, weather-station summaries from nearby locations have been"used to establish site climatology. These station locations, as well as the site itself, are shown on Figure 2.3-1. Data from onsite measurements and from nearby stations of the National Weather Service are used in preparing this report. The only first order National Weather Service stations in the area are at Topeka and Wichita, both having extensive data. Burlington, 4 miles southwest of the site, has some limited data available that have been used when applicable. Because it has a good length of contin-uous record, is close to the site, and has approximately the same, elevation and exposure, the Chanute, Kansas, Flight Service Station (FSS) (National Climatic Center, 1955-1964) provided data that are used to characterize the wind and atmospheric stability of the site area. In comparison, Topeka is 56 miles north of the site, and its wind data are influenced by its location in the Kansas River Valley, while Wichita has a similar exposure to the site area but is 96 miles southwest of the site (Figure 2.3-1). Although these data are considered to be generally representative of meteorological conditions at the site, local variations, especially in the distribution of wind direction and speed, probably exist. These local variations can only be . identified by the onsite meteorological monitoring program. Data from onsite measurements cover the 3-year period from June 1, 1973 to May 31, 1975 and March 5, 1979 to March 4, 1980. General topographic features to a radius of 5 miles and l 50 miles f rom the- site are shown on Figure 2. 3-2 and 2. 3-3. l Topographic cross sections along 5-mile radial and 50-mile 2.3-2 s Rev. 1 4/81
[ WCGS-ER(OLS)
,m
( Y radial lines are shown in. Figures 2.3-4 and 2.3-5. The
's_ / detailed plot plan of-the meteorological facilities is shown in' Figure 2.3-6.
2.3.2 TEMPERATURE The normal temperatures range from 80 F in July and August to -29 P in January; however, Kansas has occasional severe outbreaks of hot spells in the summer and cold periods in the winter. Burlington has recorded both a high of 117 F and a. low of -27 F, Topeka a high of 109 F and a lowoof
-20 F,.and Wichita a high of 113 F and a low of -12 F.
The-annual average number of days with temperatures in excess of 90 F is approximately 60 to-70 for the region, while the. average. number of freezing days per year is about 120.
-Table 2.3-1 presents the monthly and annual average and extreme temperatures for Burlington, Wichita, and Topeka.
The annual mean temperatures based on these data are 57.0 F for Burlington, 54.3 F for Topeka, and 5.6.6 F for Wichita. Table 2.3-2 gives the diurnal variation'of temperature for the Wolf Creek Generating Station using the 3-year period of on-site data. This table also presents the annual average and extreme temperatures for the site. The annual mean temperature is 54.7 F (12.6 C), which compares favorably to the annual means for Burlington, Topeka,
) and Wichita. Diurnal variation, average, and extreme c
temperature data for the site are presented on a monthly basis in Table 2.3-3. Although Kansas is distant from major bodies of water, signifi-cant moist air incursions from the Gulf of Mexico occur during the summer months. This moist air inflow results in marked increases in wet bulb temperatures for the region from June to September. Monthly and annual average dewpoint temperatures for both Topeka and Wichita are presented in Table 2.3-4. Diurnal variation of dewpoin temperature and annual average and extreme dewpoint temperatures for the 3-year period of on-site data are listed in Table 2.3-2. The mean annual dewpoint temperature is 42.6 F (5.9 C), which compares favor-
, ably to the mean annual dewpoint at both Wichita and Topeka. )
On-site dewpoint statistics on a monthly basis are given 4 in Table 2.3-3. 2.3.3 WATER-VAPOR This portion of Kansas shows a marked diurnal change in relative humidity. As temperatures increase during the day, relative humiditien decrease accordingly. Likewise, when temperatures fall during the evening hours, there is x_/[ 2.3-3 l Rev. 1 4/81
WCGS-ER(OLS) an appreciable rise in the relative humidity values. There- - fore, the lowest relative humidity values are found during the afternoon hours, while the highest values occur in the early morning just before sunrise. Mean relative humidity values for Topeka and dichita are shown in Tables 2.3-5 and 2.3-6. Table 2.3-2 lists the diurnal variation of relative humidity l for the 3-year on-sito data base period. Annual average and extremes of relative humidity can also be found in this table. Monthly relative humidity statistics are presented in Table 2.3-3 for the 3-year period. The annual averages l show that the onsite data period was slightly drier than the long-term period. 2.3.4 FOG Heavy fog occurs relatively infrequently in the region around the site. Topeka averages about 15 days per year with heavy fog while Wichita has 17 such days. The months of December, January, and February show the greatest incidence of fog, averaging 2 to 3 such days per month (Tables 2.3-5 and 2.3-6). No on-site fog data is available. 2.3.5 PRECIPITATION Monthly and annual precipitation and snowfall normals and maxima for Burlington, Topeka, and Wichita are presented l in Table 2.3-7. This indicates an annual precipitation mean for Burlington of 38.0 inches, with 70 percent occurring from April through September. January is generally the driest month, while May is the wettest. The annual means for Topeka and Wichita are 34.7 and 30.6 inches, respectively. Maximum short-period rainfall during 10 intervals from 5 minutes to 24 hours at Topeka and Wichita appear in Table 2.3-8. Annual average snowfall in Burlington is 15.2 inches, with the greatest in February (U.S. Weather Bureau, 1965). A monthly total of 17 inches has been recorded at Burlington. The annual means for Topeka and Wichita are 20.9 and 15.4 inches, respectively. Freezing rain can be expected to occur f rom November through March; Table 2.3-9 shows that l during a 10-year period in Wichita, there were 83 such days (Bennett, 1959). Accumulation of ice of 0.25 inches once every year and at least 0.50 inches every 2 years can be expected. The mean duration of glaze ice on utility wires if an ice storm occurs is 53 hours for the State of Kansas as a whole (Bennett, 1959). The most commonly reported hailstopes are less than three-fourths inch in diameter and cause little or no property 2.3-4 Rev. 1 4/81
WCGS-ER(OLS)
/1 damage. Hailstones equal to or larger than three-fourths inch y ) in diameter are associated with severe thunderstorms. From x' 1955-1967, 832 hailstorms having hailstones equal.to or larger than three-fourths inch in' diameter were reported in 400 days in Kansas (Figure 2.3-7).
On-site precipitation data were not taken during the first two years of data gathering. However the data are available for the March 5, 1979 - March 4, 1980 period. Annual precipitation wind roses for the 10 and 60 m levels are _ presented in tabular form in Tables 2.3-10 and 11. -Monthly precipitation wind roses based on the one year of data are pre-sented in Tables 2.3-12 and 13. Table 2.3-14 presents the num-ber of hours with precipitation and precipitation rate distri-butions, by month, for the year of data. The total precipitation for the year was 28.16 inches with the maximum of 8.35 inches occurring in June 1979. 2.3.6 WIND CHARACTERISTICS Joint wind speed and direction frequency distributions for Chanute FSS from 1955 to 1964 are shown on a monthly and annual basis in Table 2.3-15. On the average, the prevailing wind direction l at Chanute is southerly from April turough-December, while north-northwesterly flow prevails during January and February. March has the maximum monthly wind speed, averaging 12.8 knots.- July l [~mh and August have the minimum monthly average wind speed.of 9.5 x ,/ knots. Calms were present 3.6 percent of the time while strong winds above 20 knots were observed 3.5 percent of the time. Calms occurred primarily during the summer months with a maximum fre-quency of 5.1 percent in June. Stong winds occurred primarily in the spring, with a maximum frequency of 9.0 percent in April. l Table 2.3-16 gives the frequency distribution for the persistence l of wind direction at Chanute FSS in each season. Southerly and north-northwesterly winds are most persistent, with the former dominating in spring, summer, and fall, and the latter in the winter. In the spring and summer the maximum persistence is . 60 hours, while during the fall and winter it is 45 hours and 36 hours, respectively. No calms last longer than 21 hours. The joint wind-stability characteristics of the site area are defined by Table 2.3-17. The table is based on 10 years of l standard National Weather Service (previously the U.S. Weather Bureau) 3-hourly observation at Chanute FSS, covering the per-iod January, 1955 to December, 1964. For each observation the stability existing at that time was calculated by the Turner-Pasquill method in program " STAR", supplied by the National Climatic Center, Ashville, North Carolina. In the version of the program used-for this study, Pasquill stability class G is 3[}/ not distinguished from class F; rather, the two are treated as 2.3-5 Rev. A 4/81
WCGS-ER(OLS) ! 1 a single class which is designated as F. The mean wind speeds I l for each stability class are as follows: l Stability Class Mean Wind Speed (knots) A 1.7 B 4.7 C l 9.2 ' l
. l
- l i
1 1 l
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Ol l l l l l e O Rev. 1 4/81 2.3-Sa -
~
WCGS-ER(OLS) f] D 13.1 C/
~
E 8.2 F 3.9 Tables 2.3-18 and 2.3-19 give the wind roses for the lower l level (10-m) and upper level (60-m) winds, respectively, for this 3-year period of onsite data. Wind roses on a monthly basis are provided.in Tables 2.3-20-(10-m) and 2.3-21 (60-m). Joint frequencies of wind speed, direction, and stability for the total period are presented in Tables 2.3-22 (10-m) and 2.3-23 (60-m). These-joint frequencies are given on a monthly basis in Tables 2.3-24 (10-m) and 2.3-25 (60-m). Diurnal variation of wind speed and direction, average, and extreme winds for the total period are presented in Table 2.3-2 and on a monthly basis in Table 2.3-3. Table 2.3-26 provides the total period lower level wind persistence for each stability class, all'elasses combined.(Pasquill All) and all stable classes tl (Pasquill #S#), respectively. I 2.3.7 CLOUD COVER AND SUNSHINE Average monthly and annual daylight cloud cover and sunshine i for Topeka and Wichita are given in Table 2.3-27. I tq ,
\j 2.3.8 STABILITY The seasonal persistence of stability frequency distribution at Chanute Flight Service Station is depicted in Table 2.3-28. l For all' seasons, only class D stability conditions have a persistence exceeding 15 hours. In spring, fall, and ,
winter more than 10 percent of class D stability conditions persist for longer than 102 hours, while the upper limit for summer persistence is 96 hours. Onsite stability statistics can be found for the total period ir Tables 2.3-2 and monthly in Table 2.3-3. Table 2.3-29 rcesents a stability persistence summary for the 3-year onsite data set. The only stability classes to persist more than 24 hours are classes D and E. 2.3.9 STORMS 2.3.9.1 Thunderstorms Thunderstorms may occur during every month of the year. The most damaging thunderstorms are those associated with the passage of a cold front or a squall line. The average monthly and annual number of days with thunderstorms for p-
, I
\_./ 2.3-6 Rev. 1 4/81 L
WCGS-ER(OLS) j~)
' \_/
both Topeka .and wichita are presented in Table 2.3-30.
~
The-maximum-frequency of' thunderstorms occurs in late spring and during the summer months, with the wintertime minimum in December and January. A thunderstorm day is defined as a day on which thunder is hea.rd at least once at that location. Thunder cannot usually be heard if the' lightning causingLit is more than about 15 miles away. While thunderstorm incidence data are based upon the observation of thunder generated by light-ning occurring wi. thin a region close to the observation station, these data do not contain a great deal of information which can be used to characterize lightning. For example, these. data do not provide information regarding the' type (e.g., cloud-to-ground versus cloud-to-cloud lightning) and severity of the disturbance or frequency of lightning
- occurrences. -
Observations indicate that the magnitude and incidence of lightning strikes to ground are substantially greater in frontal storms than experienced in air mass convective storms (Bodle, 1971). Storms of the air mass convection type account for the majority of annual thunderstorm days. Therefore, the mean annual number of days with thunderstorms probatly over-estimates the actual number of lightning-producing thunderstorms with strikes to the ground. C! Nevertheless, the number of thunderstorm days is used as
- 4. a measure of lightning occurrences. The mean annual number i of such days for Topeka and Wichita is 58 days and 55 days, 4
respectively (Environmental Data Service, 1978). Since the seasonal frequencies of lightning occurrences directly correlate with the seasonal frequencies of thunderstorm
; days, lightning is least frequent in fall and winter, with 0-4 thunderstorm days per month for Topeka and Wichita, and most prevalent in late spring, with 9-10 thunderstorm days per month in May and June (Environmental Data Service, 1978).
A more pertinent statistic than the number of thunderstorm days per year is the number of lightning strikes per square l mile per year (Uman, 1971). The strikes per area'have been ! determined from the combined results of several studies, and they indicate that the number of flashes to ground per square mile per year is between 0.05 and 0.8 times the number of thunderstorm days per year. Therefore, if the largest number of thunderstorm days (Topeka with 58 days) ic used, the expected number of strikes per year in a square mile area surrounding the site is betwen 3 and 46. l l A 15-year survey of Storm Data (U.S. Department of Commerce, ! f)s_- 1959-1973) for the site area showed frequent lightning incidents l 2.3-7 l Rev. 1 4/81 1 1
WCGS-ER(OLS) and associated damage. Qualitatively, lightning frequency directly correlatcs with that of hail and tornadoes, with a maximum in the spring. No quantitative data on frequency of lightning, nowever, were listed in those publications. 2.3.9.2 Tornadoes s Tornas tivity is significant in the site area. Table 2.3-31 es that tornadoes have been observed in the area around a site during almost every month, with about 70 percent tring during April, May, and June. Over 30 percent or the total number were reported during May, the month of greatest frequency. January is the month of least activity with no tornadoes reported during the period (Poultney, 1973). About 90 percent of the Kansas tornadoes occurred between noon and midnight, with the greatest activity between 1600 and 1800 CST. Figure 2. 3-7a shows the total number l of tornadoes by 1-degree longitude-latitude squares for the 13-year period ending 1967 (Pautz, 1969). It is noted that there are several conflicting published values of tornado occurrences per 1-degree square (Poultney, 1973; Pautz, 1969; Thom, 1963). The dirferences might be attributed to the years sampled, or to the method of report classifica-tions used by the investigators. The monthly number of tornadoes per 1-degree longitude-lati-tude square for the period 1956 to 1971 is summarized in Table 2.3-31. During this period Kansas had a total of 92 tornadoes per 10,000 square miles, the largest in the United States (Poultney, 1973). The most severe storm to occur in the general area, from the standpoint of casualties and damage, was on June 8, 1966, when an early evening tornado passed through Topeka causing 16 fatalities, 406 injur,ies, and property losses in excess of $100 million. In 1972, there were 45 tornadoes reported in Kansas as a whole, with no deaths reported. Table 2.3-32 summarizes the total amount of damage caused by tornadoes between 1916 and 1950 (U.S. Weather Bureau, 1960). The probability of tornado occurrence must be examined statis-tically, since the possibility of a tornado striking a point is so low that it is difficult to predict its occurrence. For this reason, an annual frequency of tornadoes in an area (1-degree longitude-latitude square) is determined from climatological data, after which the point probability and return period are computed. According to Thom (1963), the probability (P) of a tornado hitting a single point l within a one-degree longitude-latitude square is:
- p. (2.8209 x t)
[2.3-1) 2.3-8 O Rev. 1 4/81 l 1 1
WCGS-ER(OLS). t '[K where:
- (v}.
x
'A'= the area-in square miles of a 1-degree-longitude-
' latitude square centered on the point; tU=.Ithe mean annual frequency of tornadoes in the area.
For-the 1-degree longitude-latitude square enclosing the
~
site, and using Thom's data for the years 1953-1962,
, t = 3.2.- Thus:.
-3
_ p =.(2.8209 x 3.2) = 2.38 x 10 land the return period (R)'for all tornadoes (recurrence interval) is: R= = = 420 years.
-3 2:.38 x 10 t
Using more recent data _from 1956-1971, the monthly and annual probabilities and recurrence intervals of a tornado occurrence per any 1-degree l longitude-latitude square in Kansas are 1 given in Table 2.3-31. l
- ~ 2.3.9.3 Hurricanes N/ The eastern Kansas location of the. site is about 1,400 miles 1 west of the Atlantic Ocean and about 800 miles north of the Gulf of Mexico. Because the strength of a hurricane is dissipated rapidly once the storm commences an overland trajectory, this distance minimizes the influence that a j hurricane would have upon the site. For a 93-year period,
- 1871-1963, the tracks of four dissipating hurricanes have been shown to pass through Kansas (Cry, 1965).
[
- l. 2.3.9.4 Extreme Winds i
i Strong winds occur in Kansas as a result of extratropical cyclones, thunderstorms, and tornadoes. Tornadoes are dis-cussed in Section 2.3.9.2. Extratropical cyclones usually produce _their highest wind speeds in winter.or spring because l o they are energized mainly by temperature contrasts between [ air masses. Thunderstorms are convectively driven and there-fore produce their strongest winds during the spring and summer months. L [ According to Pautz (1969), there were 877 reports of wind ! gusts (50. knots and greater) occurring in 453 days The in the ' State of Kansas from 1955 to 1967 (Figure 2.3-8). diurnal i distribution of these wind gusts shows a maximum between ~ 1800 CST and 2400 CST. Pautz also shows these data by 1-degree
) longitude-latitude squares. About 30 windstorms were reported f
\_/ in the square encompassing the site (Figure 2.3-9). Figure [
2.3-9 ; l' Rev. 1 .tr 4/81 l
WCGS-ER(OLS)
- 2.3-10 shows these windstorm reports averaged by 2-degree longitude-latitude squares. About 200 reports occurred in the site vicinity. This is a much higher rate of occur-rence than shown in the 1-degree square averages, attributed to the presence of a highly organized severe-storm network and the large number of severe Local Storm Unit personnel residing in the area (Pautz, 1969).
The fastest-mile wind is defined as the fastest observed 1-minute value when the direction is in tens of degrees (Environmental Data Service, 1978). Thom (1968) chose the annual fastest mile wind speed as the best available measure of wind.for design purposes. He calculated fastest mile wind speed values and mean recurrence intervals using reechet probability distributions. Some typical recurrence intervals and their related wind speeds for eastern Kansas are shown in Table 2.3-33. The 100-year return period fastest-mile l wind speed in the site region was calculated at 86 mph. In comparison, the fastest mile wind speed observed is 81 mph from the north in Topeka and 66 mph from the northwest in Wichita (Table 2.3-34). Gusts of lesser speeds are record- l ed from almost all directions (Environmental Data Service, 1969). In the 3-year period of onsite monitoring, no winds l greater than 50 knots were recorded. 2.3.10 AIR POLLUTION Meteorological conditions which are conducive to high air pollution potential are light winds, surface inversions, and stable layers aloft. The site area is characterized by frequent storm passages, cloudiness, high winds, and thermal instability, all of which favor rapid dispersion of atmospheric pollutants and, therefore, low air pollution potential. The geographical distribution of these periods of relatively good ventilation conditions is indicated by the tracks of the centers of well-defined cyclones l (Figure 2.3-11). Periods of limited dispersion or stagnation are often associated with slow moving, warm anticyclones with resulting thermal stability and numerous temperature inversions. Hosler (1961) has presented a climatological study on the frequency of temperature inversions in the United States. According to his study, the site is in an area where periods of high air pollution potential may be expected to occur approximately 30-40 percent of the time (Figure 2.3-12). The mixing height or mixing depth of the atmosphere, defined as that height through which relatively vigorous vertical mixing occurs, plays a significant role in the diffusion potential of a given area. Holzworth (1972) has indicated that maximum mixing heights for eastern Kansas vary from a mean of about 850 meters in the winter to about 1,600 meters 2.3-10 Rev. 1 4/81
l WCGS-ER(OLS) l
/~N l } \.- / TABLE 2.3-1 Sheet 3 of 3 MONTHLY AND ANNUAL AVERAGE AND l a
EXTREME TEMPERATURES FOR WICHITA, KANSAS Average Average-Daily Daily Extrem c,d) Extrem c,d) Month Maximum (b) Minimum (b) Average (b) Maximum Minimum January 41.4 21.2~ 31.3 75 (1967) -12 (1962) February 47.1 25.4 36.3 84 (1976) -6 (1971) March 55.0 32.1 43.6 89 (1956) -2 (1960) April 68.1 45.1 56.6 96 (1972)- 15 (1975) May 77.1 55.0 66.1 100 (1967) 31 (1976) June 86.5 65.0 75.8 106 (1956) 43 (1969) July 91.7 69.6 80.7 113 (1954) 51 (1975) (N August 91.0 68.3 79.7 110 (1964) 48 (1967)
'] September 81.9 59.2 70.6 105 (1978) 35 (1967)
October 71.3 47.9 59.6 95 (1954) 21 (1976) November 55.8 33.8 44.8 81 (1978) 1 (1975) December 44.3 24.6 34.5 83 (1955) -5 (1968) Annual 67.6 45.6 56.6 - 113 (1954) -12 (1962) a In degrees Fahrenheit. b Data Period 1941-1970. c Data Period 1953-1978. d Most recent in cases of multiple occurrence. Source: Environmental Data Service, 1978, Local climatological data, annual summary with comparative data, Wichita, Kansas: Environmental Science Services Administration, U.S. Department of Commerce, Silver Spring, Maryland. , l l ( LJ
l l kN GS-eft (C)LS) TABLE 2.3-2 STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERS V
- 9) l I
(ANNUAL) Page 1 of 4 STATISilCS AND DluRNAL VARIAfl0N OF METEOROLOGICAL PARAMETERS DATA PER1001 IMREE YlARS COMBINED DATA 50URCE1 DN-Slit WOLF CREEE s[NERATING STATION TA8LE 6ENtRATE01 06/2S/80. 23 33.23. Pugtigsjog.gagSgSECTRIC DAM!S AND MOORE JOB N01 7699-062 METEOROLOGICAL PARAMETERS (HEIGHTS IN METERS) CRT DEW STAS DELT4 STA8 WIND WING WIND WING REL
'" ' '"' DEET 4 5'" '" 5'"" "'" """'"
!!.;; it'.!! il'."005 ib'.il 10 00 10 00 60.00 60 00 SS 85 00 10.00 10.00 60.00 60.00 10.00
- MOUR DEG C DEG C DEG C DEG C M/SEC M/SEC PCI 1 10.6 S.7 .9 F 11 E 40 $$E 73 S 70.2 2 10.2 S.6 .9 F 1.1 E 4.0 SSE 7.2 5 71 4 3 9.8 S.S .8 F 1.1 E 3.9 $$[ 7.2 S 72.3 4 9.5 S.4 .8 F 11 [ 40 SSE 71 5 73 3 5 9.2 S.3 .8 F 11 E 4.0 SSE 71 5 74.1 6 9.1 S.3 .7 E 10 E 4.0 SSE 7.1 S 74.6 7 9.4 S.5 .3 E .S E 42 SSE 69 5 74 1 8 10 1 58 .1 E .1 E 4.5 S 6.8 5 72.8 9 11 3 61 ..S 0 .6 D S.0 5 6.9 S$W 68.5 10 12.5 6.2 .8 C .9 0 S.4 SSW 7.8 SSW 64.4 11 13.7 63 .9 8 -1.0 0 S.6 SSW Tel SSW 60 5 12 14.8 63 .9 8 -1 1 D 56 SSW 71 $$W 57 2 13 15.S 6.3 .9 8 -1 1 C S.7 SSW 7.2 SSW St.6 14 16 0 62 .9 8 *1 1 D S.8 SSW 7.3 $$v St.9 15 16.4 62 .8 C -1.1 0 S.7 SSW 7.3 SSW St.7 16 16.6 6.1 .8 C -1 0 0 S.6 5 7.2 S St.1 17 16.3 6.8 .6 D .8 0 S.2 5 71 $ 51.*
18 15.6 61 .2 L .4 0 47 SSE 70 SSE St.2 19 14.6 6.2 .2 E .1 E 42 SE 7.0 SSE S75
' 41 72
- 61 0 20 - 13.S 6.2 .6 E .6 L SE SSE 21 12 7 61 .8 F .9 E 41 SE 7.4 SSE 63 7 22 12.0 60 .8 F 10 [ 41 SE 7.4 SSE 65 8 23 11 5 S.9 .9 F 1.1 E 4.1 SE 7.S SSE 67.4 24 10.# S.p .9 F 1.1 F 4.1 SSE 7.4 SSE 68.8 4888 LUTE Mar 39.6 28.5 16.5 20.7 100 0 Av6 DAIL7 MAX 17.4 87 73 10.3 79.7
' ' ::t 5 ti:t ffi:AficMEAN !!:t S::
' ' 55'
?:!
AVb OAl(7 MIN 7.8 3.0 2.1 4.0 47.1 A850LUIL MIN -22.7 -27 0 0.0 0.0 11.7 STANDARD DEU 10.9 9.9 24 29 17.7 VALID 085 26122 2470S 243SF 243S7 243?? 24327 25670 626 25619 68S 24961 24821 483 24704 8600 INVALID 085 42 IS19 1947 1947 1977 1977 1513 TOTAL 085 26 04 26304 26384 92.6 26304 92 6 26304 92 5 26304 92.S 26304 97 6 26304 97.4 263u4 94.9 2 304 4.4 26304 93.9 OATA REC 0VLAV 9 .3 94.2 < Rev. 1 ! 4/81 l l l l
WCGS-ER(OLS) / k.M ^ TABLE 2.3-2 (Continued) STATISTICS AND DIURNAL VARIATION 07 METEOROLOGICAL PARAMETERS ' ' (ANNUAL) Page 2 of 4 STAf!SitCS AND DIURNAL VARIAtl0N OF METEOROLOGICAL PARAMETERS DATA PERIOD: JUNE l e1973 THROUGH MAT 31e1974 OATA SOURCE: 04-SITE - W OL F CREEK GENERAllNG STAllo,' IABLE EENERATEDI 06/25/80. 20.11.01. BURLINGTONeNANSAs RANSAS GAS AND ELECTRIC DAMCS AND MOORE JOB NOI 7699 %2 METEOROLOGICAL PA."AMETERS IHEIGHTS IN METER $5 ORT DEW DELTA STA8 DELTA STA8 WIND WING WIND WIND REL bulu POINI TEMP CLASS TEMP CLASS SPEED DIR SPEED 10 10.00 10.00 10.00 DIR HUMlo 10.00 10.00 60 00 00 60 00 85.00 85.00 10.00 10.0C 60.00 60 00 10.00 H0un DEG C DEG C DEG C DEG C M/SEC M/SEE PCT 1 11 3 7.1 .9 F 10 E 4.8 $$E 7.6 5 71 1 2 11 0 71 .9 F 1.0 E 41 $$C 7.5 5 72.4 3 18.6 7.0 .8 F 10 E 4. 0 $$[ 7.5 $ 73.4 4 10 3 6.9 .8 F .9 C 8.A SSE 7.4 5 74.4 5 18 1 6.9 .8 F .9 s.1 E S 7.4 $$W 75 2 6 10.0 6.8 .7 E .8 E 42 $$E 7.4 S S *J 75 6 7 10.4 71 .3 E .5 [ 43 $ 72 S 74.8 8 11 2 7.4 .2' E .1 [ 4.7 7.1 5 $$W 72 5 % , 9 12.4 7.7 .5 0 0
.7 52 SSW 7.3 $$W 68.9 le 13.6 7.9 *.8 C -1 0 0 55 $$W 7.3 $$W 64.9 11 14.7 8.0 .8 C -1 1 0 57 SSW 7.5 SSW 61 1 12 15.7 81 .9 8 -1 1 C 5.7 S$W 73 $$w 57 8 13 16.4 8.1 .9 8 -1 2 C 58 $$W 75 $$W 55.4 le 86 9 7.9 .9 8 -1 2 58 C $$W 7.5 $$W 53.9 IS 17 3 7.9 .8 C -1.1 D 5.7 SSW 7.6 $$W 52 7 16 17 3 78 .7 0 -1.0 0 5.5 5 7.5 $$W 52 5 17 16.9 7.8 .5 0 .7 0 51 5 7.4 S 53.5 18 16.2 7.8 .1 E .3 E 45 $$t 7.3 $ 55 8 19 15.2 7.8 .3 E .2 E 41 SSE 7.5 $$E 59 3 20 '. 14.2 77 .6 C .6 E 41 7.6 SE *SSE 62 3 21 13.4 7.7 .9 F .9 E 40 SE 7.7 SSE 64 9 !
22 12 8 75 .9 F t.0 E 40 SSE 7.8 SSE 67.0 23 12.3 7.4 .9 F 10 7.9 C 4.1 $$E $$[ 68 5 24 !!.7 7.2, .9 F 11 [ 41 $$E 7.8 $ 69.9 1 ASSOLUTE MAN 37 5 28.5 AVG DAILY MAX 18.3 10.3 16.5 20.7 100 0 I 76 10.8 88.0 MEAN 13.4 7.5 .1 E .1 E 4.7 5 CLIMATIC MEAN 33.5 74 4.8 7.5 7.4 5 64.9 64 5 AWG DAILY M3% 8.8 4.5 2.0 A8 SOLUTE MIN -22 7 -27 0 0.0 4.0 00 47.9 16 4 STANUAND DEv !!.I 9.9 2.5 2.9 17.0 VAL 10 085 4696 8306 7819 FA19 8584 8564 INVALID 085 64 454 8434 8396 8097 7986 m300 TOTAL 085 941 941 176 176 326 364 663 774 460 8760 8760 0760' 0760 8760 ar60 8760 8760 DATA REC 0vEnv 99 3 9e.a a9.3 69.3 8760 R760 8760 98 0 98.0 96.3 95.6 92.4 91 2 94.7 N ,/ Re v . 1 4/81 _---______m m.___u - - - - _ _ _ _ _ - -. w - V ----we -
,- -,- , + - - - m.. , . , . , , . , y -=ny w, .. , . -y--
WCGS-ER(OLS) TABLE 2. 3-2 (continued) O'. l l STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERS if (ANNUAL) Page 3 of 4 STA11STICS add OlganAL DATA PERIOD: Juht 1,1974 VAntafloh 0F METE,0a0 LOGICAL PARAMETESS THA0V8N MAT 38 3975 DATA SOURCE: ON-stit TABLE GEhEAATED: 06/25/80. 22.45.29 WCLF CREEN GEhE AA TIhG S TATION BUA {gG0 suggt5 DAMES AND MOORE J08 NO: 7699-062 DRT METE 0A0 LOGICAL PARAMETERS (HEIGHTS IN METERSI DEW DELTA STAB DELTA BUL8 PolN! TEMP CLAS$ T
$1A8 WIND WIhD WIND WING REL 4 10.00 10 00 10.E00MP 10.00 CLASS SPEED DIR SPEED DIA HUMID MOUR 18 00 10.00 60 00 60 00 85 00 85.08 18.80 11 00 60 00 60 08 18.80 DES C DEG C OCG C DEG C M/SEC MFSEC 1 18.3 S.3 .8 PCI F 11 E 45 $$C 2 18 0 S.3 .8 7.1 S 71 2 F l.1 E 3 40 $$E 70 96 Set .7 $ 72.4 E 1.1 E 40 $$E 4
93 6.9 5 73 2 S.O .7 E 1.0 C 4.0 $$E 5 90 6.9 $ 4.9 .7 C 1.1 74 1 6 E 4.0 $$E 9.0 S.8 .6 68 $ 75 0 E .9 E 7 40 $$E 67 9.4 S.2 .I E .4
$ 75.4 L 42 $$C 8 10 2 6.S S.S .4 0 .2 S 74.7 9 11.4 E 46 5 6.4 58 .7 D .7 5 72.5 18 0 S.2 5 12 5 S.8 .9 66 S 68.8 8 -1 0 0 11 S.S $$W 6.8 13.6 S.8 -10 4 3 64.9
-1.1 0 S.7
!? 14 6 S.9 -1.0
$$W 6.9 $ 60.9
& -1 1 13 C S.8 $$W 7.8 15 3 S.8 -1 0 A SSW 58.0
-1 1 C 59 SSW 14 15.7 7.I $$W SS.7 5.8 - -1 0 A -1.1 15 D S.9 $$W 7.2 16.1 S.8 .9 8
$$W St.1
-1.1 0 S.8 $$W 16 16 2 S.7 *.9 7.1 $$W S2.9 8 -1 0 17 16.0 0 Set S$W 71 S.7 .7 0 .8
$$W S2.2 0 S.4 lb 15 2 5 7.0 $ 55.2 5.8 .3 0 .4 0 19 4.8 14 2 S.9 el C S 6.8 5 SS.7
.2 E 45 28 t 13 2 S.9 .5
$$E 6.8 $$C 59.4 E 6 L 21 12.4 41 SE 70 S.8 .7 E .9
*SSE 62 8 22 11 7 E 42 SE 72 S.7 .7 C 10
$$E 65 2 E 42 23 11 2 S.6 .8 SC 7.2 $5E 67 1 24 F 10 E 43 $5E 18 8 S.4 .8 F 73 SSE 68 6 11 E 4.2 $$C 72 5 69.9 AS$8LUTC Mar 59.6 22 8 Av6 DAILY MAI 17.0 83 15.9 7.4 19.7 100.0 MCA8 12.4 10 2 CLIMATIE MEAN 12.4 S.6 .0 E .1 80 3 S.S E 48 $ 6.9 4.8 S 64 9 AWS DAILY MIN, 7.7 2.7 70 69.4 A884Luft MIN -15.9 -22.5 {.2 s.0 S.8 48 5 STAWOAAD DEv 18.7 92 00 12.7 UA 2.4 29 1008g 8756 87g 18 2 03 470g 87ge 8gg 8ggg 8 8 g
ISTALl COVERT DATA A 8768 188 8 8760 99 7 87t8 99 3 87 99.68 3 81 9 r .68 87 8760 8$60gg8760 8g g 8ggg 87gg 1 97.60 1 97 9 97 7 95 6 8760. 95.S 4760 e 99.7 Rev. 1 4/81 Ot l 1
,_,. w - _ . . _
WCGS-ER(OLS) O) g V TABLE 2.3-2 (continued) STATISTICS AND DIURW.L VARIATION OF METEOROLOGICAL PARAMETE V (ANNUAL) Page 4 of 4 STATISTICS DATA AND DIVANAL.1979 PERICO: MARCH 5 THROUSMVARIATION MARCH 4.1980 OF METEOROLOGICAL PARAMETERS DATA SDutCE: Oh-S!fC IABLL GENERATE 0: 06#25/80 23.15 15. WOLF C4EE4 GENERA 7thG STATION BURLINGiogenANSAS mANSAS GAS AND ELECTRIC DAMES AND MOOAE JOB NO: 7699-062 METEOROLO61 CAL PARAMETERS (ME lGHTS IN ME TE AS) CRT DEW DELTA BULB POINI STAB DELTA STAS WIND WIND WIND TEMP TEMP WIND GEL 10.00 CLA3e'
- 10. 5 10.00 ChASS t .00 SPEED OIR SPEE D DIA MUMID 10.06 10 00 60 00 60 00 85.00 85.00 10 00 10.dr 60.00 60.00 10.0 M0ut DEG C DEG C DEG C DEG C M/SEC M/SEC PCT 1 10 8 46 18 F 1.3- F 38 SE 72 SSE *80 2 9.6 4.S 1.0 F 1.3 F 3.8 $$E 71 $$E 69 1 3 9.3 4.4 1.0 F 13 F 38 $$E 71 SSE 70.1 4 8.8 4.2 .9 F 12 F 3.8 $$E 71 S 71 1 5 8.6 42 .9 F 12 F 3.8 SSE 71 6 83 4.0 5 71 8
.8 F 11 E 3.9 $$E 70 7 8.4 41 .6
$ 72 5 E .8
[ E 39 $$E 69 $ 72.8 s 8.9 4.3 .1 E 2 E 43 9 5 68 S 70.9 10 1 4.6 .4 0 .5 0 4.7 3 6.7 10 11.5 4.9 .7 S 67.7 0 .8 D 51 SSW 68 $$W 63.4 11 12.8 4.9 .8 C ~1 0 0 S.4 $$W 70 $$W 59 2 12 14.0 5.0 .8 C -1 1 0 S.4 $$k 70 SSW 55.6 13 14.8 4.8 .8 C -1 1 0 55 SSW 7.1 14 IS.S 47 .8 SSW S2.6 C -1 1 0 5.S 15 15.8 SSW 7.1 3 50.3 4.8 *.8 C -1 1 0 56 5 71 16 1 49.3 16.1 4.6 .7 0 -1.0 0 5.5 $ 7.2 17 16.0 46 .6 5 48.4 0 .8 0 52 $$E 70 $$E 48.6 18 15 3 4.7 .3 0 .S 0 4.7 SE 68 SE 19 14.4 4.8 58 8
.1 E .0 E 42 SE 68 SE 53 7 28 1 13.1 4.9 .6 E .6 E 40 E SE 7.0 SE 57.6 21 12 2 48 .8 F .9 E 40 ESE 73 SE 68.7 22 18 5 48 .9 F 11 40 23 E ESE 7.3 SE 63 2 11 1 47 .9 F 1.2 24 F 3.9 SE 7.2 SE 64.8 18 3 46, 1.0 F 1.3 F 3.8 SE 7.2 SSE 66.4 l
A8$8 LUTE MAI 34 1 24.4 AW6 DAILY MAN 17 0 7.4 14.8 70 }8.8 a0 0 500 0 MEAN 11 9 46 77.9 CLIMATIC ME AN .2 E .2 82 8 46 E 4.5 $$E 7.0 SSE 61 6 46 7.0 61.4 l Av6 O AIL T Mik 7. 1.8 A858 LUTE MIb -18.05 -21 4 22 41 44.8 0.0 0.0 STANDARD DEV 10 8 10 3 11.7 2.4 2.9 AL D OSI 8678 7742 7838 17.8 ava[lig085 7858 7237 7237 8669 git 1842 946 946 1547 8662 8486 8473 7674 0:m.En.E., i8:; im im m im 115 1 gte ga 3310 i % g547em im u:22 : 6: i6.t m:
,v ) '
7 Rev. I 4/81 1
WCGS-ER(OLS) TABLE 2.3-3 STATISTICS AND DIURNAL VARIATION OF METEOROIOGICAL PAF.'ViETERS V ; 1 (MONTHLY) Page 1 of 12 ; STATISTICS DATA PERIDO: AND DIURNAL VARI ATION OF METEOROLOGICAL PARAMETERS ALL JANUARY COMBINED DATA SOURCE: ON-SITE TABLE GENERATED. 03/16/01. 20.36.22. WOLF CREEM QENERATING STATION BURLINGTON. MANSAS MANSAS GAS AND ELECTRIC DAMES AND MOORE JOB NO: 7699-062 NETEOROLOGICAL PARAMETERS (HEIGHTS IN METERS) DRV DEW DELTA STAB DELTA STAB WIND BULB POINT WIND WIND WIND REL TEMP CLAGS TEMP CLASS SPEED DIR SPEED 10.00 10.00 10.00 10.00 DIR HUMID 10.00 1O.00 60.00 60 00 85.00 85. QO 10.00 t O. 00 60.00 60.00 10. 00 HOUR DEO C DEG C DEG C DEO C M/SEC N/SEC PCT 1 -22 -3. 7 .6 E .8 E 3. 7 WNW 6. 7 WNW 69.3 2 -2.3 -5. 7 .6 E .8 E 3. 9 NW 69 NW 69.7 3 -2.4 -5. 9 .5 E .7 E 4.1 NNW 7, 1 NW 70.3 4 -2. 0 -6. 0 ? E .6 E 4. 2 NW 7. 0 NW 70.6 5 -3.0 -6. 2 4 E .6 E 4. 2 NW 7, t WNW 70.7 6 -3.2 -6.3 4 E .5 E 4.1 NNW 7, 1 NW 70.9 7 -3 3 -6 4 4 E .6 E 4.1 NNW 7. 3 NW 70.9 3 -3.3 -6.3 .3 E .5 E 4. 2 NW 7. O WNW 71.5 9 -0. 0 -6. 1 .1 E .1 E 4. 4 N 7. 1 NW 71.7 10 -2. O -5. 3 .5 D .5 D 4. 9 NNW 7. O WNW 70.2 11 .9 -4.9 .7 D .7 D 5.1 N 6. 9 W 68.0 12 .4 -4. 3 7 D .8 D 5.1 W 6. 6 WSW 65.1 13 .8 -4.2 .B C .9 D 5. 2 W 6. 8 W 63.2 14 1. 5 -4.4 .7 D .9 D 5. 3 WSW 6. 8 WSW 61.7 IS 8. 9 -4.3 .7 D .9 D 5. 3 W 6. 8 WSW 59.8 16 1. 9 -4. 5 .6 D .8 D 5. 2 W 6. 8 WSW 59.4 17 1. 6 -4.7 .4 D .6 D 4. 6 NW 6. 7 SW 59.4 18 .8 -4. 0 .O E .1 E 4.1 ENE 6. 6 SSW 61.3 19 .2 -4.9 .3 E .3 E 4. 0 ENE 6. 9 s 63.6 20 .6 - 5. 1 .4 E .5 E 4.1 NE 7. I NW 65.2 21 - 1. 0 -5. 2 .5 E .6 E 4. 0 ENE 7. 3 W 66.1 22 -1. 2 -5. 4 .5 E .7 E 3. 9 NNW 7. I W 67.4 23 - 1. 5 -5. 6 .6 E .9 E 3. 9 NW 7. 1 W 67.6 24 - 1. 9 - 5. 7 .5 *
.8 E 3. G W 6. 9 WNW 68 2 ABSOLUTE MAX t6 6 1O. 3 Av0 DAILY MAX 3. t -2.0 13. e 18.I 94.3
- 7. 0 10. 3 78 6 PEAN - 1. 1 - 5. 3 .1 E CLIMATIC MEAN - 1. 0 .1 E 44 NW 6. 9 WNW 66.7
-3. 5 4. 4 6. 7 65.9 AVO DAILY MIN - 5. 1 -0. 9 ASSOLUTE MIN -22.7 -27.O 3. 8 34 53.2 O. O O. O 19.2 STANOARD DEV 7. I 6. 3 2. 2 2. 9 IS 9 VALID 089 2201 2060 2173 2173 1641 INVALID OSS 31 172 59 59 1641 2039 2037 1976 8970 2031 TOTAL OBS 591 591 193 195 2232 2232 2232 2232 2232 2232 2232 256 262 205 DATA RECOVERY 99.6 92.3 97.4 97 4 2232 2232 2232 2232 73 5 73. 5 91.4 98. 3 ee 3 88 3 91 O Rev. 1 4/81
WCGS-ER(OLS) p) I TABLE 2.3-3 (/' STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERS V (MONTHLY) Page 2 of 12 STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERS DATA PERIOD: ALL FEBRUARY COMB 3NED DATA SOURCE: ON-SITE WOLF CREEK GENERATING STAT 10N TA5LE GENERATED: 03/16/81. 20.56.04. BURLINGTON, KANSAS MANSAS CAS AND ELECTRIC DAMES AND MOORE VOS NO: ' 7699-062 METEOROLOGICAL PARAMETERS (NE10 HTS IN METERS) DRY DEW DELTA STAB DimTA STA8 WIND WIND WIND WIND REL BUL9 POINT TEMP CLASS TEMP CLASS SPEED DIR SPEED DIR NUMID 10.00 10.00 10.00 10.00 10.00 10.00 60 00 60.00 85.00 85. 00 10.00 10.00 60.00 60.00 10.00 NOUR DEG C DEO C DEG C DEO C M/SEC M/SEC PCT 1 - 1. 2 -5. 8 .5 E .6 E 4. 2 NNW 7. 3 NNW 68. O 2 - 1. 4 -6.0 .5 E .6 E 4. 3 N 7. 2 N 68.0 3 -1.7 -6. 1 .5 E .6 E 4. 2 N 7. 3 NNW 68.1 4 -2. O -6.3 .5 E .6 E s1 NNW 7. 5 NW- 68.2 5 -2.2 -6. 5 .4 E .6 E 4. 4 NNW 7. 5 NNW 68. 5
- 6 -2.4 -6 6 .4 E .5 E 4. 4 NW 7. 5 NNW 69.2 7 -2. 5 -6. 6 .3 E .4 E 4. 4 NW 7, 2 NNW 69.4 8 -2.6 -6.6 .2 E .3 E 4. 4 NNW 7. O NNW 70.1 9 -2.0 -6. 1 .2 E .3 E 4. 9 NW 7. 0 NNW 69.9
~
10 -1. O -S. 4 .6 D .7 D 5. 4 NNW 7. O NNW 68. 8 11 .1 -3.1 .7 D -1.O D 5. 5 WNW 7. O NW 66.3 12 1.1 -4.7 .8 C - 1. 1 D 5. 6 W 6. 0 WNW 64.3 13 1. 9 -4.3 .8 C - 1. 1 D 5. 7 W 7. O WNW 62.2 14 2. 5 -4 3 .8 C - 1. 1 D 5. 8 W 7. a WNW 60.6 15 3. O -4. O .7 D - 1. 1 D 5. 7 WNW 7. O WNW 60.O 16 32 -4.0 .7 D -1.0 D 5. 5 WNW 6. 9 NW 59.2 17 3.1 -4.1 .6 D .9 D 5. 2 NW 6. 9 NW 40.3 18 2. 5 -4.3 .3 D .5 D 4. 7 NNW 6. 8 NNW 61.6 19 1. 6 -4.5 .1 E .O E 4.1 N 6. 8 NNW 63.4 20 1. 0 -4.7 4 E .3 E 4.1 N 6. 9 NNW 65.0 21 .4 -5. O ,S E .5 E 43 NNW 7. 3 NNW 66.1 22 .1 -5. 2 .5 E ,& E 4. 3 N 7. 2 NNW 64.8 23 .4 -5. 4 .6 E .7 E 4. 4 NNW 7. 3 NNW 67.2 24 .7 -5. 3 .6 E .7 E 4. 3 NNW 7. 3 N 67.7 AB E dTE MAX 19.3 5. 7 16.1 10.6 98.7 Av0 DAILY MAX 4. 4 -2.0 7. 6 10.5 77.7 MEAN .O -53 .O E .1 E 4. 7 NNW 7. I NW 65.O CLIMATIC MEAN .1 -5. 3 4. 8 7. 1 66.1 AVO DAILY MIN -4.2 -8 6 2. O 3. 6 54.4 ASSOLufE MIN -18.5 -21.3 Q. O O. O 16 .4 STANDARD DEV 6. 4 5. O 2. 6 3. I 16.2 f ALID 089 2040 200, 2033 2033 2040 2040 1955 1853 1618 1617 2000 NVALIO Oss O 36 7 7 0 0 45 187 422 423 40 OTAL 039 2040 2040 2040 2040 2040 2040 40 2040 2040 2040 2040 DATA RECOVERY 100.O 98.2 99. 7 99.7 100.O 100.O O9 90.8 79.3 79.3 98 O h
\j Rev. 1 4/81
( l ! l l l l
WCGS-ER(OLS) TABLE 2.3-3 STATISTICS AND DIURNAL VARIATION OF METEOROIDGICAL PARAMETERS V (MONTHLY) ap 3 of M STATISTICS DATA PERIOD:AND DIURNAL ALL VARI ATION OF PETEOROLOGICAL PAP 4 METERS MARCH COMBINED DATA SOURCE: ON-SITE TABLE GENERATED. 03/16/88. 20.59.30 WOLF CREEK GENERATING STATION BURLINGTON. MANSAS M ANSAS OAS AND ELECTR IC DAMES AND NOORE JOS NO: 7699-062 METEOROLOGICAL PARAMETERS (HEIGHTS IN METERS) DRV DEW DELTA STAD DELTA BULS POINT STAB WIND WIND WIND WIND REL TEMP CLASS TEMP CLASS SPEED DIR SPEED to Oc 10 00 10.00 10.00 DIR HUMID 10.00 10.00 60.00 60.00 85.00 85.00 10. 00 t O. 00 60.00 60.00 10.00 HOUR DE0 C DEQ C DEO C DEO C N/SEC M/FEC PCT I 4. 2 - 1. 0 . .5 E .B E 4. 0 ESE 7. 5 S 67.3 2 4. 3 .9 .6 E .8 E 4. 7 ESE 7. 4 S 68.1 3 3. 9 .9 .6 E .8 E 4. 6 ESE 7. 2 S 69.2 4 3. 6 .9 .5 E .9 E 4. 7 SE 7. 5 S 5 70.6
- 3. 5 .8 .5 E .9 E 4. 0 SE 7. 6 8 71.0 6 3. 4 .e .5 E .B E 3. 1 SE 7. 0 9 71.4 7 3. 3 .B .3 E .6 E 5. 0 SE 7. 6 SSE 72.1 8 3. 7 .5 .1 E .1 E 5. 2 SSE 7. 2 SSE 71. 6 9 4, B .1 ,6 D 5 D 5. 7 8 7. 4 9 69.0 10 6. 0 .2 .e C .9 D 6. 2 SW 7. 3 WSW 65.4 11 7. 1 .3 .9 B ~ 1. O D SW
- 6. 6 7. 6 SW 61. &
12 9. 0 .4 .9 0 - 1. 1 D 6. 7 SW 7. e BW 13 5e e 89 6 .9 9 - 1. 1 D 6. 8 SW e. 0 WSW 55.9 14 9. 5 .6 -1. 0 A - 1. 1 D 6. 7 EW 7. 9 SW 54. 7 15 9. 9 .6 .9 8 - 1. 1 D 6. 7 WSW 16 10.4 8 ) WSW 53.1
.7 9 D - 1. 0 D 6. 6 SW GO SW 31. 9 17 10.3 .5 .7 D .9 D 6. 4 SW 7. 9 SSW St. 4 18 9. 0 .4 .5 D .6 D 5. 6 SW 7. 4 SSW 52. 6 19 89 .4 .1 E .1 E 9C SE 7. 3 SSE 56 9 20 7. 7 .4 .2 E .2 E 4. 0 ESE 7. 3 SE 60.8 21 6. 8 .2 .4 E .5 E 4. 0 ESE 7. 5 SE 63.1 22 6. 0 .1 .4 E .6 E 4. 9 E 7. a ESE 23 44.6
- 5. 5 .4 .5 E .7 E 5. 0 E O. 0 ESE 65.4 24 50 .6 .5 E .8 E 4. 9 SSE 7. 8 8 66.4 AB E.UTE MAN 29 9 15. B Av0 DAILY MAX 18.0 3 4 15.0 10.4 90.5 89 13.4 78 7 MEAN 64 .1 .1 E CLIMATIC MEAN 6. 1 .O E 5. 5 SSE 7. 6
-5 5. 6 S 63.1
- 7. 6 62.8 AUG DAILY MIN 1. 3 -4.2 A8huTE MIN -13.2 -le O 2. 4 O. 0
- 3. 9 46 9 STANDAND DEV
.e 17.2 eO 6. 9
- 2. 9 3. 4 16.8 VALID OSS 8488 1474 1488 1488 1489 INVALID OBS 15 I496 1476 1475 1437 1437 1473 TOTAL OBS 1 t t t 13 34 8489 1489 1409 1489 1499 1489 i
52 52 to DATA RECOVERY 99 9 99 0 99 9 99.9 3489 1499 1499 1489 1489 99 9 99. 9 99.1 99.I 96 3 96.5 j 9e 9 i l Rev. 1 ' 4/81 I l l
WCGS-ER(OLS) A TABLE 2.3-3 (
)
V- STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERS V (MONTHLY) Page 4 of 12 I * *"' *
- SIi13Ndi$o*" M APY L"C'"daI o M"**"
DATA SOURCE- ON-SITE WOLF CREEM OENERATING STATION T ABLE GENER ATED: 03/16/81. 21.02.41. BURLINQTON. MANSAS MANSAS CAS AND ELECTRIC DAMES AND MOORE WB NO: 7699-062 NETEOROLD01 CAL PARAMETERS (HEt9 HTS IN METERS) DRY DEW DELTA STA3 DELTA STAB lin ND WIND BULE POINT WIND WIND REL TEMP CLAGS TEMP CLASS S.*EED DIR SPEED DIR HUMID t o 00 10.00 10.00 10.00 1O. 00 10.00 60.00 60.00 SS. 00 85.00 10. 00 10.00 60.00 60.00 10.00 HOUR DEO C DEO C DEO C DEO C M/SEC M/SEC PCT
- 1. 10.4 4. 5 .8 F 1. 1 E 5. O Se e. 3 BSE 66.7 2 10.0 4. 3 .7 E 1. 0 E 4. 9 SE B. 2 SSE 67.4 3 9. 6 4. 2 .7 E 1. 0 E 5. 0 SE 8. 3 SSE 68. 5 4 9. 2 4.1 .7 E 1. 1 E 4. 9 SE B. 2 SSE 69.6 5 8. 9 3. 9 .7 E 1. 0 E 5. 0 SE s. 3 SSE 70.4 6 8. 0 39 .6 E .9 E 5. 0 SSE e. 2 SSE 71. 2 7 9. 1 4.1 .2 E .4 E 5. 4 SE s. 2 SSE 71.1 9 10.2 4. 4 .5 D .4 D 6. 2 SSE B. 3 SSE 67.4
\ 9 11. 5 4. 7 .7 D .9 D 6. 7 9 8. 2 SSE 62.9
< 10 12.7 4. 7 .9 9 -1.O D S
- 6. 9 92 9 58. 5 a
11 13.9 4. 7 .9 D - 1. 8 D 7.1 SSW 0. 6 SSW 54.1 12 14.9 4. 7 .9 9 - 1. 1 D 7.1 SW G. 6 SW 51. 9 13 15.5 4. 6 .9 B - 1. 1 D 7. 2 SW s. 6 SW 50.2 14 16.0 4. 6 ,9 D - 1. 1 D 7. 2 SW G. 6 SSW 49.2 15 16.3 4. 4 .9 D -1.0 D 7. 3 SSW e. 9 SSW 47.9 16 16.4 4. 6 -8 C - 1. 0 D 7. 2 SSW e. 9 SSW 47.7 17 16.3 4. 5 7 D .9 D 6. 9 SSW 86 SSW 47. 5 18 15.9 4. 5 .5 D .6 D 6. 2 S 8. 1 S 48. 9 19 15.0 4. 8 .1 E .1 E 5. 2 SE 7. 6 SSE 52. 1 20 13.9 4. 9 4 E .4 E 4. 0 SE 7. 7 SE 56.0 21 12.9 4. 9 .6 E .7 E 4. 9 SE s.1 SE 59.0 p 22 12.2 4. 7 .6 E .9 E 5.1 SE 8. 3 SE 61.2 23 11.5 4. 7 .9 F 1. 0 E 5. 1 SE 9. 3 SE 63. 5 24 11.0 4. 6 .9 F 1. 1 F 5. 0 SE e2 SSE 65.2 AtmuTE MAX 28.0 19.2 16.2 20.7 97.9 AVG DA!LY NAX 17.7 7. 6 9. 1 11.9 77.9 MEAN 12.6 4. 5 .O E .O E 5. 9 CLIMATIC MEAN 82.5 4. 6 SSE e. 3 SSE 59. 6
- 5. 9 e. 3 60.A AVO DA!LY MtN 7. 3 1. 6 2. 7 4. 7 AS h WTE MIN -7. 6 -11.8 43.3
- 0. 0 0. 0 19.3 STANDARD DEV 6. 7 6. 3 2. 7 3. I 17.8 VALID SS 2155 2010 2115 2115 2104 2104 2120 2120 2117 NVALI OSS 5 142 45 45 56 56 40 40 2:37 43 43 201e TAL 39 2160 2160 2160 2160 2160 2160 2160 142 fA RECOVERY 99.S 93 4 97.9 2160 2160 2160 2160 97.9 97.4 97.4 99.I 98 1 98 0 98.O 93.4 Rev. 1
(,/ 4/81
i
?"I-E R (OLS )
TABLE 2.3-3 STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERS y (MONTIILY) Page 5 of 12 BTATISTI DATA PERSOD.AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERB ALL MAY COMS!NED DATA SOURCE: ON-SITE WOLF CREEM GENERATING STATION TABLE CENERATED: 03/16/81. 28. 03.12. BURLINGTON, MANSAS MANSAS QAU AND ELECTRIC DAMES ANJ MOORE W8 NO: 7699-062 METEOROLOGICAL PARAMETERS lHEIGHTS IN METERS) DRV DEW DELTA STAD DELTA STAB WIND WIND WIND WIND R EL BULB POINT TEMP CLASS TEMP CLASS SPEED DIR SPEED DIR HUMID 10 00 to 00 SO 00 10 00
- 10. 00 10.00 60.00 60.00 83.00 GS. 00 10 00 10.00 60.00 60.00 10.00 HOUR DEO C DEC C DEO C DEO C M/SEC M/SEC PCT I le 2 10.7 .9 F l. 2 F 4. 4 SE 7. 2 SSE 70.4 2 IS 9 10 6 1. 0 F 1. 2 F 4. 3 SE 7. 0 SE 72.0 3 15.4 10.S .9 F 1. 2 F 4. 2 GE S. 9 SE 73.2 4 15.0 10.3 .9 F 1. 2 F 4. 2 SE 7. 0 SE 74.3 5 14.5 10.3 .9 F 1. 3 F 4. 2 SE 7. 0 GSE 73.9 6 14.4 10.3 .9 F 1. 2 F 42 SE 7. 0 SSE 76 7 7 15.0 10 7 .1 E .4 E 4. 4 SSE 69 SSE 73.9 8 16.3 11.3 .6 D .S D 5. 0 SSE 6. 4 SSE 72.3 9 87.7 11.6 .e C .9 D 5. 0 G 7. 0 SSE 68.4 10 18 9 11.3 .B C - 1. 0 0 6.1 Sf d 7. 5 SSE 63.9 11 19. 8 II, 4 .9 8 - 1. 1 D 6. 2 SSE 7. 4 SSE 60. 1 12 20.7 11. 2 - 1. 0 A - 1. 2 C 6. 3 SSE 7. 6 SSE 36.1 13 21.4 11.1 - 1. 0 A - 1. 2 C 6. 4 SSE 7. 7 SSE 33 6 14 21.9 11. 0 .9 B - 1. 1 D 6. 3 S 7. 7 B St. G IS 22.4 11.1 .9 9 - 1. 8 D 6. 2 SSE 7. 4 SSE 30. 4 16 22 6 11.0 -. 0 C - 1. 0 D 6. 1 5 7. 3 GSE 49.S 17 22 6 11.1 .7 D .9 D 3. 9 SSE 7. 4 SSE 49.9 le 22.2 11. 2 .S D .7 D 5. 6 SE 7. 2 SE St. S 19 21.2 11.4 2 E .2 E 4. 0 SE 6. 9 SE SS O 20 20.0 11. 4 .3 E .3 E 4. 4 SE 7. 0 SE SO S 21 19.0 11.4 .6 E .9 E 4. 1 SE SE
- 6. 9 62.5 22 18 2 II. 4 .8 F 1. 0 E 4. 3 ESE 7. 2 GE 63.3 23 17.6 11. 3 .9 F 1. 1 E 4. 3 SE 7. 2 SE 67.3 24 16.9 S t.1 .9 F 1. 2 F 4. 3 SE 7. 3 SE 69.9 At UTE MAX 30.0 22 C 16.5 20, t Av ALLY MAN 23 4 13 8 98 7 eO 10.6 St. 2 MEAN 19 6 11. 0 .O E .O E SE CLAMATIC MEAN 88.6 18. O
- 5. I 7. 2 SSE 63.4 S. ! 7. 3 63 3 AVO DAILY MIN 13 7 83
- 2. 3 40 43.0 ASSOLUTE MIN 34 - 1. 3 0. 0 0C 18.0 STANOARD DEV 3O S I 2. 6 30 la 7 VALID 08S 2190 2194 216S 2365 2154 2154 2186 2106 2170 INVALID 088 42 48 67 67 78 78 2171 2194 44 46 el 62 48 TOTAL CBS 2232 2232 2232 *s232 2232 2232 2232 2232 2232 CATA necOvERY 98 8 97.8 97 0 97.0 2232 ??32 96 3 96. S 97.9 97 9 97.3 97.2 97,0 Rev. 1 4/81
WCGS-ER(OLS) 7%
/ i-
, e TABLE 2.3-3
\j STATISTICS AND DIURNAL VARIATIGN OF METEOROLOGICAL PARAMETERS 1f (MONTHLY) Page 6 of 12 STATISTICS AND DIUR VARI ATION OF METEOROLOctCAL PARAMETERS DATA PERIOD; ALL COMSINED DATA SOURCE- ON-SITE TABLE GENERATED: 03/16/81. 21.07.14. ndOLF CREEM CENERATING STATION BURLINGTON. MANSAS MANSAS GAS AND ELECTRIC DAMES AND MOORE JOB NO: 7699-062 NETECpt0 LOGICAL PARAMETERS (HEIGHTS IN NETERS)
DRV DEW DELTA STAB DELTA STA9 WIND WIND WIND WIND SUL3 POINT TEMP CLASS . TEMP CLASS SPEED DIR SPEED REL 10.00 to 00 10.00 10 00 DIR HUMID 10.00 HOUR 10.00 60.00 60.00 85.00 85.00 10.00 10.00 60.00 60.00 i O. 00 DEO C DEG C DEC C DEO C M/SEC M/SEC PCT 1 19.3 14.4 .9 F 1. 2 F 3. 8 9 7. 2 S 73. 8 2 18.9 14.3 .9 F 1.1 F 3. 7 S 7. 0 S 75.1 3 18.4 14.1 .9 F 1. 2 F 3. 7 S 7. 0 S 76.1 4 18.0 84.0 .9 F 1. 1 E 3. 7 S 6. 8 9 77 8 5 17.7 13.9 ,9 F 1. 3 F 3. 5 S 6. 5 S 78.9 6 17.9 14.1 ,6 E .9 E 3. 8 S 6. 7 SSm 78.9 7 18.9 14.5 .2 E .1 E 4. 2 S 6. 3 S 75.9 s 8 20.4 14.8 .6 D .7 D 4. 0 SSW 6. 5 SSW 70.3 9 21.8 14.7 .8 C - 1. O D 5. O SSW 6. 6 SSW 64.4 10 22.8 14,5 .9 D - 1, 1 D 5.1 SSW 6. 6 SSW 60.4 11 23 8 14.4 ,9 D -1.2 C 5. 3 SSW 6. 7 SSW 56. 8 12 24.7 14.3 -1. 0 A -1. 2 C 5. 4 SSW 6. 8 SSW 53. 8 13 25.4 14.2 .9 8 -1.2 C 5. 6 SSW 7. C SSW St. 2 14 26.0 14.2 .9 9 - 1, 1 C 5. 5 SSW 7. 0 LSW 49.6 15 26.3 14.1 .9 D -3.1 D 5. 4 SSW 7. 0 SSW 48. 0 16 26 7 14.3 .8 C -1.O D 5. 5 S 7. 2 S 47.4 17 26.7 14.3 .7 D .9 D 5. 5 S 7. 3 9 47.9 18 26.1 14.6 .5 D .7 D 5. 2 S 7. 2 9 50.8 19 25.0 14.7 .2 E .3 E 4. 7 S 7. 2 8 54.0 20 23.6 14.9 .3 E .3 E 4. 2 SSE 7. 0 8 58. 9 21 22.4 14.9 .7 E .7 E 4. 0 ESE 7. 4 SSE 63.5 22 21.4 14.9 .9 F 9 E 4. 0 SSE 7. 4 S 66. 9 23 20.8 14.8 .9 F
- 1. 1 E 4. O SSE 7. 5 9 69.O 24 20.1 14.7 .9 F 1.1 F 3. 9 3 7. 4 S 71.1 ASSOLUTE MAI 37.O 24.7 AVO DAILY MAX 27.1 17.0 13 5 17. t I00.O
- 7. 0 99 82.1 MEAr4 22 2 CLIMATIC MEAN.
14.4 .O E .O E 4. 6 5 7. O 22.1 14. 5 S 63.4
- 4. 6 7. 0 63.9 AVO DAILY MIN 17.1 12.O 2. 2 t ASSOLUTC MIN 10.6 3. O 4. O 45.7 O. O O. O 17.3 BTANDARD DEV 4. 6 4. 3 2. 3 2. 7 18.2 VALID SS 2840 2095 2099 2098 1997 1997 2152 INVALI OSS 20 65 62 62 173 2188 2135 2124 2007 TOTAL SS 2160 2160 173 8 42 25 36 73 2160 2160 2160 2160 2160 2160 2160 2160 DATA RECOVERY 99.1 97.0 97.1 97. ! 92.0 92.0 99.6 98.1 2360 98 8 98 3 96.6 l
i x Rev. 1 4/81 1
I WCGS-ER(OLS) TABLE 2.3-3 ! ST/1TISTICS AND DIURNAL VARIATIOM OF METEOPOLOGICAL PARAMETERSV (MONT!!LY) Page 7 of 12 STATISTICS DATA PERIOD-AND DIURNAL alt. VARI ATION OF METEOROLOGICAL PARAMETERS JULY roMathED DATA SOURCE: ON-SITE TADLE CENERATED. 03/16/Bl. 28.09.16. WOLF CREEK CENERATING STAftDN BURLINGTON. MANSAS
% M ANSAS CAS AND E.LECTRIC DAMES AND MOORE JOB N1 7699-062 METEOROLOGICAL PARAMETERS (HEtCHTS IN METERSI DRV DEW DELTA STAB DELTA BULB PO NT STAB WIND WIND WIND WIND TEMP CLASS TEMP CLASS SPEED REL 10.00 10 00 10 00 t o 00 DlR SPEED DIR HUMID t O. 00 1O. 00 60 00 60,00 85.00 05 00 1O. 00 tO.00 60.00 60.00 t O. 00 HOUR DEQ C DEO C DEG C DEG C M/SEC M/SEC PCT 1 22.5 16. 7 4. 2 F 1. 5 F 34 SE 7. 1 SSE 70.2 2 22 1 16.7 1. 2 F 1. 4 F 3. 2 SSE 6. 8 SSE 78. 8 3 21.7 16.7 3.1 F 1. 5 F 3. 1 SSE 6. 9 SSE 4 73.2 21.3 16.7 t.1 F t. 3 F 3. O SSE 6. 6 9 75.2 5 21.0 16.7 11 F l. 4 F 2, 8 SSE 62 S 76 5 6 21.O 16 7 .7 E 1. O E 2. 9 SE 6O S 76,5 7 22. '
37,2 .I E .I E 3. 3 SSE 5. 6 S 74. 1 8 23.7 17.6 .7 0 .7 D 4. 0 9 S 5. 7 S 69.4 25.3 17.7 .9 D - 1. 0 D 4. 5 8 6O S 63.6 10 26.7 17.6 -1. 0 A - 1. 2 C 4. 6 S 6i S 38.6 11 27.9 17.3 .9 9 - 1. 1 C 4. 7 L 12 29 9
- 6. I S 54. 3 16 9 - 1. 0 A -L. 2 C 4. 6 9 6. 0 S 50. 1 13 29.6 16.6 -1. O A ~ 1. 3 8 4. 7 9 6. 2 SSE 47.2 14 30.3 16.5 - 1. 0 A - 1. 2 C 4. O SSE 6. 3 SSE 44.9 15 30.5 16.4 .9 D - 1. 2 C 4. 7 SSE 6. 5 16 SSE 44 4 30 5 46 3 .9 B -3.1 D 4. 7 SSE 6. 4 SSE 44.4 17 30 2 16 2 .7 D .9 D 4. 7 SSE 6. 4 SSE 44 2 is 29.7 16. 5 .5 D .7 D 4. 3 SSE 19
- 6. 5 SSE 46 9 28 5 16.7 .O E .1 E 3. 8 SE 6. 6 SSE 50 5 20 27.O 16.8 .5 E .6 E 3. 4 SE 6. 7 SE 54. 9 21 25.7 16.0 1. O F 1. 1 E 3. 5 SE 22 7. 1 SE 59.3 24 7 16.7 1. I F t. 2 F 35 SE 7, 2 SE 23 23 9 62.4 te. 6 8.1 F t. 3 F 3. 5 SE
, 7, 1 SSE 65.O 24 23.2 16.6 1. 2 F t. 4 F 3. 6 SE 7. 2 SSE 67.1 A35CLUTE mat 39 6 28 5 Av0 DAILY MAX 30.9 19.I 14 6 14.3 200.0 62 9. 0 79.7 L Af!C MEAN 16.
.O f AVO DAILY MIN 20 4 I' h 14 6 1. 0 ASSOLUTE MIN 83.3 7. 3 39 4 O. O OO STANDARD DEV 49 42'O IS 33 1. 9 2. 3 19 I VALIO 005 2201 2100 '9 2139 I
INVALID 039 31 52 f 1 2:43 2163 2226 2225 2157 2:29 TOTAL OSS 2232 93 49 49 4 2:54 f DA TA RECOVERY 2237 . 4 2?32 2232 2232 2232 7 75 103 78 98 6 97 ' e 95 e 96.9 2232 2232 2232 2232 96 9 99. 7 99 7 96 6 95 4 96.5 Rev. 1 4/81 '
1 WCGS-ER(OLS) A TABLE 2. 3 -3
.i \
\ f STATISTICS AND DIURNAL VARIATION OF METEOROIDGICAL PARAMETEFS- y (MONTHLW Page 8 of 12 l STATISTICS AND DIURNAL VARI AT!DN OF MTEOROLOGICAL PARAMETER 8 DATA PER100: ALL AUGUST COMBINED DATA SOURCE' ON-SITE WOLF CREEK GENERATING STATION TABLE GENERATED: 03/16/81. 21.10.48. BURLINGTON. MANSAS MANSAS GA8 AND ELECTRIC DAMES AND MOORE JOB NO: 7699-062 METEORCR DO! CAL PARAMETERS (HEIGHTS IN METERS)
DRY DEW DELTA STAS DELTA STAB WIND WIND SULO POINT WIND WIND REL TEMP C'. A S S TEMP CLASS BPEED DIR SPEED DIR HUMID 10.00 10.00 10.00 10.00 10.00 10.00 60.00 60.00 85.00 85.00 10.00 10.00 60.00 60.00 10.00 HOUR- DEO C DEO C DEO C DEO C M/SEC M/SEC PCT 1 21.1 16.5 .9 F 1.1 E 3. 3 BSE 6. 9 9 74.9 2 20.6 16.5 1. 0 F 1.1 F 3. 2 SSE 6. 7 S 77.9 3 20.2 16.3 .9. F 1. 1 F 3. 0 SSE 6. 5 S 78.9 4 19.9 16.3 .9 F 1. 2 F
, 3. 1 SSE 6. 3 S 80.1 5 19.5 16.2 .9 F 1. 1 E 3. 2 SSE 6. 3 S 81.3 6 19.5 16.3 .8 F 1.1 E 3. 3 SSE 6. 4 S 81. 6 7 20.2 16.5 .1 E .3 E 3. 5 s
S 5. 9 S 80.0 8 21.6 17.1 .5 0 6 D 4. 0 S 5. 6 S ?S 7 O As 11 12 9 10 23.1 24.3 25.6 26.5 17.2 17.3
- 17. O
.8
.8
.9 C
C O
-1.0
-1.1
-1, 2 D
C C
- 4. 4
- 4. 8
- 4. 9 SSW SSW SSW 59 63
- 6. 5 SSW SSW SS'W
- 10. 3 65.1 59.9 16.9 .9 9 - 1. 2 C 4. 9 8 6. 4 S 36.9 13 27.2 16.0 .', B -1.2 C 5. 0 S 6. 5 S 53.9 14 27.7 16.6 .9 9 -1. 2 C 5. 2 S 6. 7 8 51. 7 15 28.1 16.5 .8 C -1. 2 C 5. 0 S 6. 6 S 50.4 16 28.1 16.4 .B C - 1. 1 D 5. 1 S &B S 50.4 17 27.7 16. 5 .6 D .9 D 4. 9 SSE 6. 9 SSE 51. 7 18 26.9 16.7 .3 D .5 D 4. 3 SSE 6. 6 SSE 54. 9 19 25.7 17. 0 .2 E .O E 3. 8 SE 6. 8 SSE 59.8 20 24.3 17.1 .7 E .7 E 3. 5 SE 7.1 SSE 64.9 21 23.3 17.0 1. 0 F 1. 0 E 3. 5 SE 7. 4 SSE 68.5 22 22.6 16.9 1. 0 1.1 E 3. 5 SE 7. 4 SSE 70.8 23 22 0 16.0 1. 0 F 1. 1 F 3. 5 SE 7. 3 ' SSE 72.7 24 21.6 16.8 .y F 1. 1 E 3. 5 SSE 7.1 SSE 74.3 ASSOLUTE MAX 37.5 22 8 14,2 AVQ DAILY MAX 28 8 18.8 14.8 100.O
- 6. 5 9. 6 85.0 MEAN 23.6 16.7 .1 E .O E 4. O CLIMATIC MEAN 23.8 16.6 SSE 6. 6 8 67.O
- 4. 2 6. 7 66.3 AVO DAILY MIN 18.8 14.5 1. 9 As h uTE MIN 11.8 1. 8 3. 8 47.5
- 0. 0 0. 0 20.5 STANDARD DEV 4. 6 3. 6 1. 8 2. 6 16.9 VALID OSS 2217 2197 2171 2171 2172 2172 2224 INVALID Ost 15 35 61 61 2214 2191 2137 2195 60 60 8 18 41 95 37 TOTAL ODS 2332 2232 2232 223 2232 223 2232 DATA RECOVERY 97 3 98.4 97.3 97. 2232 2232 2232 2232 97.3 97. 99.6 99.2 98 2 95.7 98.3 4
, g / Rey, 1 a 4/81
l WCGS-ER(OLS) TABLE 2.3-3 STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERS V (MONTHLY) Page 9 of 12 I I I I l STATISTICS DATA PERIOD- AND SIURNAL VARI ATION OF METEOROLOGICAL PARAMETERS ' ALL ***TEMBER COMA 1NED DATA SOURCE: ON-SITE 4 T ABLE GENERATED: 03/16/88. 21.12.49. WOLF CREEK GENERATING STATION
' BVRLINGTON. KANSAS MANSAS CAS AND ELECTRIC DAMES AND MOORL WS NJ: 7699-062 METEOROLOGICAL PARAMETERS (HEIGHTS IN METERS)
DRY DEW DELTA STAD DELTA STAB WIND SULB POINT WIND WIND WIND REL TEMP CLASS TEMP CLASS SPEED DtR SPEED DtR HUMID 10.00 10 00 10.00 10 00 10.00 10. 00 60.00 60. 00 85.00 05. 00 10.00 t O. 00 60.00 60.00 10.00 HOUR DEO C DEG C DEQ C DEG C M/SEC M/SEC PCT 1 16.6 12.2 1. 5 F 1. 6 F 3. 0 SE 6. 4 SSE 75.4 2 16.2 12.1 1. 5 F 1. 6 F 2. 9 SE 6. 2 SSE 77.2 3 15.0 12.3 1. 5 F 1. 6 F 2. 9 SE 6. 2 SSE 78.3 4 15.S 14.9 1. 4 F 1. 6 F 3. 1 SE 6. 3 SSE 78. 9 5 15.2 11.7 1. 4 F 1. 5 F 3. 0 SE 6. 1 SSE 79.3 6 14 9 11.6 1. 4 F l. 5 F 3.1 ESE 6. 1 SSE 80 0 7 14.9 18. 6 1. 0 F 1. 3 F 3. 1 SE 5O CBE 80.1 e 15.9 12.0 .O E .3 E 3. 4 SE S. 6 SSE 77. S 9 17. 5 12.4 7 D .8 D 3. 9 SSE 5. 6 SSE -72.O to 19.0 12.3 .9 8 - 1. 0 D 4. 2 S 5. 6 SSE 66.3 11 20.3 12.3 A - 1. 1
-1. 0 0 4. 2 SSE 5. 7 SSE 62.3 12 21.2 12.1 - 1. 0 A ~ 1. 2 C 4. 4 SSE 5. 9 SSE 58. 6 13 22.0 12.0 - 1. 1 A - 1. 2 C 4. 4 SSE 6. 0 SSE 55.7 14 22.4 11.9 - 1. 0 A - 1. 2 C 4. S SSE 6, 1 SE 54.6 15 22.7 11. 7 .9 B - 1. 1 D 4S SE 6. 0 SE 53 6 16 23 0 11.7 .8 C - 1. 0 'D 4. 3 SE 5. 9 SE 52.4 17 22.0 11. 9 7 D .9 D 4. 0 SE S. 5 SE 53. 4 18 22.0 11. 0 .3 D .4 D 3. 4 SE 5. 5 SE S5. 3 19 20.7 12.1 5 E .4 E 2. 9 ESE 5. 8 SE 60.4 20 19 4 12.3 1. 3 F 1.1 F 2. 9 ESE 6. 3 SE 65.3 21 18.5 12.2 1. 4 F 1. 4 F 2. 9 ESE 6. 5 SE 68.1 22 17.0 12.2 1. 5 F 1. 5 F 2. 8 ESE 6. 3 SE 70 8 23 17.3 12.2 1. 5 F 1. 6 F 2. 9 SE 6. 4 SE 72.3 24 16.8 11.9 1. 5 F 1. 6 F 2. 9 SE 6. 4 SE 73.7 ABSOLUTE MAX 31.5 21. 7 Av0 DAILY MAA 23.7 14.4 15.8 16.8 96.9
- 5. 9 9. 1 83.3 MEAN 10 7 12. O .4 E .4 CLIMATIC MEAN 18.9 11.9 E 3. 5 BE 6. O SE 67.6 36 6. 0 65.9 AVO DA!LY MIN 14.0 9. 4 1. 4 ASSOLufE MIN 60 - 1. 5 0. 0
- 2. 9 40.S
- 0. 0 17.0 STANOARD DEV 51 5. 3 3. 9 2. 5 la 9 VALID OSS 2157 2114 1666 1666 2139 2139 INVALID 035 3 46 494 2144 2:43 2134 2103 2412 494 21 21 16 17 TOTAL OBS 2160 2160 2140 2860 2860 2860 26 57 48 DATA RFCOVERY 99 9 97 9 2160 2160 2860 2160 2160 7 7. t 77 8 97 0 99 0 99.3 99 2 9e a 97.4 97.8 Rev. 1 4/81
WCGS-ER(OLS) ' A
/ \ TABLE 2.3-3 "sj STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERS V (MONTHLY)
Page 10 of 12 STATISTICS DATA PERIOD: AND DIVANAL VAR *.4 TION OF M TEOROLOGICAL PARAMETERS ALL OCTOBER wCM51NED DATA SOURCE: ON-SITE TABLE GENERATED: 03/16/01. 21.14.50. WOLF CREEK GENERATING STAT 10H BURLINGTON. MANSAS MANSAS CAS AND ELECTRIC DAMES AND F100RE WD N0; 7699-062 METEOROLOGICAL PARAMETERS 1 HEIGHTS IN METERS) DRY DEW DELTA STAB DELTA STAB W1ND DvLB POINT WINO WIND W1ND REL TEMP CLASS TEMP CLASS SPEED DIR SPEED D1R HUMID 10.00 10.00 10.00 10.00 10.00 10.00 60.00 60.00 eS. 00 85.00 10.00 10.00 60.00 60.00 10.00 HOUR DEO C DEO C DEO C DEO C M/SEC M/SEC PCT 1 13.1 6. 9 1. 6 F 1. 7 F 3. 0 S 7. 5 9 67.5 2 12.7 7. 0 1. 5 F 1. 7 F 3. 7 SSE 7. 2 S 68.8 3 12.4 7. 0 1. 5 F 1. 7 F 3. 7 S 7. 2 S 70.1 4 12.0 6. 9 1. 5 F 1. 7 F 37 S 7. 3 8 71. 5 5 11.8 6. 9 1. 3 F 1. 5 F 3. 9 SSE 7. 4 S '2. 1 6 11. 5 6. 9 1. 3 F 1. 5 F 4. 0 SSE 7. 6 S 73.0 7 11.6 7, 2 1. 1 F 1. 4 F 4.1 SSE 7. A S 73. 8 9 12.4 7. 7 .4 E .6 E 4. 4 SSE 7. 3 S 71.9 9 14.0 7. 9 .5 D .5 0 5. 1 S 7. 0 S 66.9
< 10 15.7 7. 9 .7 D - 1. 0 5. 7
\ / D S 7. 4 S 61.2 sf 11 17.0 7. 9 .8 C -1.1 0 5. 9 8 7. 6 9 56. 9 12 - 18.3 7. 7 .9 0 - 1. 2 C 6.1 SSW 7. 8 S 52.3 13 19.0 7. 4 .9 0 -1.2 C 4 6. 0 SSW 7. 7 SSW 49.4 14 19.6 7. 1 .8 - 1. 1 C C 6. 0 SSW 7. 7 SSW 47.0 15 20.1 7. 2 .7 D - 1. 1 D 5. 8 SSW 7. 6 SSW 46.1 16 20.2 7. 0 .6 D .9 D 5. 6 "SW S 7. 5 SSW 45.7 17 19.7 7. 0 .3 D .6 D 5. 0 S 7. 2 S 47.2 19 19.5 7. 1 .3 E .1 E 3. 9 8 6. 0 SSE 50. 9 19 17.1 7. 1 .9 F 5
.9 E J. 6 SSE 7.1 SSE 54.8 20 16.1 7. I 1. 2 F 1. 2 F 3. 7 SSE 7. 2 SSE 57. 6 21 15.2 7. 0 1. 4 F 1. 5 F 3. 9 SSE 7. 4 SSE 60.1 22 14.5 7. 0 1. 5 F 1. 6 F 3. 8 f SSE 7. 5 8 62.6 23 14.0 7. 0 1. 5 F 1. 6 F 3. 8 S 7. 5 S 64.3 24 13.4 6. 8 1. 5 F 1. 7 F 3. 9 8 7. 6 S 66.0 ASSOLUTE MAX 31.7 20.7 AVO DAILY MAX 20.7 9. 6
- 14. 0 17,8 95.5 i
- 7. 3 10.5 76.1 1 MEAN 15.4 7. 2 .5 E CLIMATIC MEAN 15.5 6. S
.5 E 4. 5 9 7. 4 S 60.7
- 4. 6 7. 3 59,5 AVO DAILY M!N 10.3 3. 9 2. 0 i ASSOLUTE MIN .5 -8.9 4.1 43.O l
- 0. 0 0. 0 11.7 STANDARD DEV 5. 5 6. 6 2. 5 3. 0 20.4 VALID 38 2225 2046 1947 1047 1974 1974 2224 2223 INVALI OBS 7 186 365 305 258 259 9 200e 2007 2046 TOTAL OS 22 2232 9 224 225 106 2232 9232 2232 2232 2232 2232 2232 2232 DATA RECOVERY 99. 91 7 S2. 8 82 8 89 4 88. 4 99. 6 2232 99.6 90.0 89. 9- 91. 7 I l Rev. 1 g
w ) 4/81 I
1 l WCGS-ER(OLS) TABLE 2.3-3 STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETEPS y (MONTHLY) page 11 of 12 l STATISTICS AND DIURNAL VARIATION OF METEOROLO91 CAL PARAMETERS ' DATA PE4100: ALL NOVEMBER COMSINED DATA SOURCE: ON-SITE TADLE CENERATED: 03/16/01. 21.26.01. WOLF CREEK GENERATING STATION BURLINGTON. KANSAS KANSAS GA9 AND ELECTRIC DAMES AND MOORE jog NO: 7699-062 NETEOROLOQ1 CAL PARAMETERS (HEIGHTS IN NETERS) DRY DEW DELTA STAD DELTA STAB WIND BULD POINT WIND WIND WIND REL TEMP CLASS TEMP CLASS SPEED D1R SPEED DIR HUMID 10.00 10.00 10.00 10.00 10.00 10.00 60.00 60.00 85.00 85.00 10.00 1 10.00 60 00 60.00 10.00 I HOUR DEQ C DEG C DEG C DEO C M/SEC M/SEC PCT 1 5. 3 .2 .e F 1. 0 E 4. 2 SSW 7. 6 SW 69.0 2 3. 0 .1 .8 F 1. 0 E 4. 2 SW 7. 6 SW 69.8 3 4. 7 .1 .7 E .9 E 4. 2 SBW 7. 5 SW 70.9 4 4. 5 .O .6 E .9 E 4. 2 SSW 7. 4 SW
- 1. 5 l 5 4. 3 O .6 E .8 E 4. 3 SW 7. 5 SW 72.2 6 4. 2 .O .5 E .7 E 4. 3 SSW 7. 4 SW 73.1 7 4.1 .O .5 E .7 E 4. 4 SW 7. 4 SW 73 0 8 4. 2 .O .2 E .4 E 4. 6 SW 7. 3 SW 73.2 9 5. 2 .5 .4 D .4 E 5. 1 SW 7, 2 SW 70 6 10 6. 7 .7 .7 D .B D 56 SW 7, 2 SW 66.1 11 7. 9 .G .8 C -1.O D 5. .B WSW 7. 3 SW 61.4 12 9. 0 .0 .0 C -1. 0 D 5. 9 WSW 7. 5 SW 57.9 13 9. 9 .8 .e C -1. 0 D 6. 0 WSW 7. 6 SW 55.4 14 10.3 .7 .e C -1.0 D 6. 0 WSW 7. 7 WSW 53. 6 15 10.6 .9 -7 D -1, O D 5. 9 WSW 7. 7 WSW 53.4 16 10.5 .4 .6 D .8 D 5. 6 SW 7. 6 SW 52. 3 17 9. 9 .4 .2 E .4 E 4. 8 SW 7. 3 SW 53.7 18 8. 7 .4 .4 E .3 E 4. 3 SW 7. 3 SW 57. 5 19 7. 9 .4 .7 E .8 E 4. 2 SW 7. 6 SW 59. 8 20 7. 3 .4 .9 F 1. 0 E 4. 3 SSW 9. 0 SW 61.6 21 6. 8 .3 .9 F 1. 0 E 4. 4 SSW 7. 9 SW 63.1 22 6. 2 .2 .9 F 1. 0 E 4. 4 SSW 7. 9 SW 64.6 23 5. G .1 .9 F 1O E 4. 4 SSW 7. 9 SSW E6 1 24 5. 3 .O .8 F 1. 0 E 4. 2 SSW 7. 7 SW 67.0 ABSOLUTE MAX 23.9 16.3 Av0 DAILY MAX 11.4 3. 1 15.9 19.7 '00.O
- 7. 6 10.0 77.0 MEAT 4 6. 9 .3 .2 E .2 E 4 O SW CLIMATIC MEAN 6. B .2 7. 6 SW 64. 2
- 5. O 7. 6 62.3 AVO DAILY MSN 2. 3 -2. 0 2. 4 ABSOLUTE MIN ~ 7. 6 -14 7 O. O
- 4. 5 46.9 O. O 17.9 STANDARD DEV 57 6.1 2. 3 27 17.0 VALID 009 2160 2004 2131 2131 2160 2160 2152 2149 INVALID OSS O 76 29 29 O O 8 2146 2143 2004 TOTAL CBS 2160 2160 11 14 17 76 2160 2160 2160 2160 2160 2160 2160 2160 DATA RECOVERY 100.O 96 5 98.7 90.7 100 O 100. O 99. 6 99. 5 2160 99 4 99. 2 96 5 Rev. 1 .
4/81 ! t l l l
WCGS-ER(OLS) l 1
,q TnBLE 2.3-3 k,v) STATISTICS AND DIURNAL VARIATION OF METEOROLOGICAL PARAMETERS y
, (MONTHLY) Page 12 of 12 STATISTICS ANO DIURNAL VARI A1;ON OF METEOROLOGICAL PARAMETERS DATA PERIOD: ALL DECEMBER COMBINED DATA SOURCE: ON-SITE WOLF CREEK GENERATING STATION TABLE GENERATED: 03/16/81.
- 21.18.24 EURLINGTON. KANSAS KANSAS GAS AND ELECTitIC DAMES AND MOORE JOB NO: 7699-062 METEOROLOGICAL PARAMETERS (HEIGHTS IN METERS)
- DRY DEW DELTA STAS DELTA STAB WIND WIND WIND WIND REL BULB POINT TEMP CLASS TEMP CLASS SPEED DIR SPEED DIR HUMID 10.00 10.00 to 00 10.00 1O. 00 1O.00 60.00 60.00 Gb. 00 85.00 1O. 00 1O.00 60.00 60.00 1O 00 HOUR DEO C DEQ C DES C DEQ C M/SEC M/SEC PCT 1 .1 -4. 5 .6 E .9 E 4. 5 WSW 7. 8 WSW 67.7 2 .2 -4.6 .6 E .9 E 4. 6 SW 7. 7 WSW 68.4 3 .4 -4. 9 .5 E .9 E 4. 5 WSW 7. 6 WSW 68.8 4 .6 -4.9 .5 E .0 E 4. 6 WSW 7. 6 WSW 69.1 5 S -5. 0 .4 E .7 E 4. 5 WSW 7. 4 WSW 69.5 6 - 1. 0 - 3. 1 .4 E .7 E 4. 3 WSW 7. 2 W 70.1 7 - 1. 2 - 5. 1 .4 E .9 E 4. 3 WSW 7. 2 SW 71.0 0 - 1. 2 -5. 0 .3 E .6 E 4. 4 SW 7. 2 WSW 71.7 9 .8 -4.7 -2 E .1 E 4. 7 SW 7.1 SW 71.2 f(j '} 10 11
.3
- 1. 6
-4. 5
-4.3
.6 D 6 D 5. 2 WSW 7. 1 W 67.9
.7 D .7 D 5. 6 W 7. 2 W 63.8 12 2. 7 -3.8 .8 C .8 D 5. 6 W 7. 0 W 61. 2 13 3. 7 -3.6 .8 C .9 D 5. 7 W 7.1 W 58.3 14 4. 3 -3.7 B C .9 D 5. 0 WSW 7. 2 W, 55.I 15 4. 7 -3.9 .7 D .O D 5. 7 W 7. 2 W 53.6 16 4. 9 -3.9 .6 D .7 5 5. 4 W 7. 1 W 52.2 37 4. 2 -4.0 .4 D .4 D 4. 0 W 7. 0 W 53.9 to 3. 2 -4.0 .1 E .1 E 4. 4 WNW 7. 1 W 57.1 39 2. 4 -4 1 .4 E .4 E 4. 3 NNE 7. 5 NW 59. 5 20 1. 7 -4.3 .5 E .7 E 4. 4 NE 7. 6 NW 61.9 21 1. 2 -4.2 .6 E .8 E 4. 4 NE 7. 7 WNW 63.S 22 .8 -4.2 .6 E .8 E 4. 4 ENE 7. 7 WSW 65.4 23 .4 -4.3 .6 E .9 E 4. 4 WSW 7. 7 WSW 66.4 24 .1 -4.4 .6 E .9 E 4. 3 W 7. 7 WSW 67.6 AS M UTE MAX 19.7 12.2 13.9 16.9 97.9 AW DA!LY MAX 5. 9 - 1. 4 7. 4 10.4 77. 5 MEAN 1. 3 -4.4 .1 E .2 E 4. B W 7. 4 WSW 64.O CLIMATIC MEAN 1. 5
-4.4 4. 9 7. 4 62.6 AVO DAILY MIN -29 -7. 5 2. 4 4. 4 47.8 ASSOLUTE MIN -1 S. 7 -25.5 O. O O. O 12.7 STANDARD DEV 6. 0 5. 9 2. 4 2. 9 15.9 VALID OBS 2224 2016 1958 1959 1932 1932 2138 2137 2142 2340 2010 INVALID OBS 8 216 274 274 300 300 94 95 90 92 222 TOTAL 03S 2232 2232 2232 2232 2232 2232 2232 2232 2232 2232 2232 DATA RECOVERY 99.6 90 3 B7. 7 ts7. 7 96. 6 86. 6 95. G 95.7 96.O 95.9 90.1 Rev. 1 J 4/81 d
l l l t _ _ _ _ _ _ __ _ _ _ . _ __ . , , . _ . _ . , _ . _ , _ - . _ _ _ _ _ - - _ - _ _
1 WCGS-ER(OLS) TABLE 2.3-6 MEAN RELATIVE HUMIDITY AND MEAN NUMBER OF DAYS WITH HEAVY FOG AT WICHITA, KANSAS Central Standard TimeI "I MeanDaysw{gg Month 0000 0600 1200 1800 Heavy Fog January 76 79, 63 65 3 February 74 78 59 59 3 March 69 76 53 51 1 April .70 77 52 50 1 May 76 83 55 53 1 June 74 82 53 49 (b) July 67 78 49 45 (b) August 67 78 49 45 (b) i September 74 82 56 53 1 October 73 80 53 55 1 , November 74 79 57 62 2 December 75 79 61 66 3 Annual 72 79 55 54 17 a Data Period 1954-1978. b Less than 1/2. Source: t Environmental Data Service, 1978, Local climatological data, annual summary with comparative data, Wichita, Kansas: Environmental Science Services Administration, U.S. Department of Commerce, Silver Spring, Maryland, f'h O
WCGS-ER(OLS) < [~'N TABLE 2.3-7 Sheet 1 of 3 t MONTHLY AND ANNUAL AVERAGE AND MAXIMUM PRECIPITATION AND SNOWFALL FOR BURLINGTON, KANSAS
~
Average Maximum Average Maximum Precipitation (a) Precipitation (a) Snowf all (b) Snowf all (c) Month (inches) (inches) (inches) (inches) January 1.19 4.89 3.6 17.0 February 1.25 2.77 4.0 8.5 March 2.59 7.68 3.3 16.0 April 3.78 10.49 0.3 3.0 May 5.34 15.34 Trace Trace June 4.87 8.71 0.0 0.0 6 July 4.23 14.63 0.0 . 0.0 August 4.04 9.69 0.0 0.0 September 4.38 9.93 0.0 0.0 October 2.99 9.11 0.2 Trace November 1.94 9.52 0.8 4.0 { December 1.41 3.72 3.0 10.0
\
Annual 38.01 15.2
- a Data Period 1931-1960.
b Data Period 1896-1960. Data Period' 1951-1960. Source: U.S. Weather Bureau, 1965, Climatic summary of the United States, supplement for 1951 for 1951 through 1960: U.S. Weather Bureau, Depertment of Commerce, pp. 86-112. Rev. 1 ! 4/81 E
WCGS-ER(OLS) TABLE 2.3-7 (continued) Sheet 2 of 3 MONTHLY AND ANNUAL AVERAGE AND MAXIMUM PRECIPITATION AND SNOWFALL FOR POPEKA, KANSAS Average Maximum Average Maximum Precipitation (ahrecipitation(b) Snowf all(b) Snowfall (b) , Month (inches) (inches) (inches) (inches) January 0.97 5.24 (1949) 5.7 18.0 (1962) February 0.98 3.49 (1971) 4.5 22.4 (1971) March 2.17 8.44 (1973) 4.4 22.1 (1960) April 3.62 8.12 (1967) 0.6 6.8 (1970) May 4.01 7.83 (1977) 0.0 0.0 June 5.80 15.20 (1967) 0.0 0.0 July 4.21 12.02 (1950) 0.0 0.0 August 4.18 11.18 (1977) 0.0 0.0 September 3.28 12.71 (1973) 0.0 0.0 October 2.65 6.01 (1967) Trace 0.8 (1970) November 1.26 6.27 (1964) 1.3 9.4 (1972) December 1.53 4.30 (1973) 4.9 15.2 (1973) Annual 34.66 15.20 (1967) 20.9 22.4 (1971) a Data Period 1941-1970, b Data Period 1947-1978. Source: Environmental Data service, 1978, Local climatological data, annual summary with comparative data, Topeka, Kansas: Environ-mental Science Services Administration, U.S. Department of Commerce, Silver Spring, Maryland. Rev. 1 4/81
I WCGS-ER(OLS) f TABLE 2.3-7 (continued) [ \ Sheet 3 of 3 MONTHLY AND ANNUAL AVERAGE AND MAXIMUM PRECIPITATION AND~ SNOWFALL FOR WICHITA, KANSAS Average Maximum Average Maximum Precipitation (ahrecipitation(b) Snowf all(b) Snowfall (b) Month (inches) (inches) (inches) (inches) January <0.85 2.73 (1973) 4.3 18.5 (1962) February 0.98 2.12 (1975) 4.0 16.7 (1971) March 1.78 9.17 (1973) 2.9 16.5 (1970) April 2.95 5.57 (1976) 0.2 2.3 (1973) May 3.60 8.85 (1977) 0.0 0.0 June 4.49 10.46 (1957) 0.0 0.0 July 4.35 9.22 (1962) 0.0 0.0 August 3.10 7.91 (1960) 0.0 0.0 September 9.46 (1973) 0.0 0.0 ( 3.69 October 2.50 6.13 (1959) Trace 0.1-(1960) November 1.17 5.88 (1964) 1.0 7.1 (1972) December 1.12 2.80 (1973) 3.1 9.7 (1967) Annual 30.58 10.46 (1957) 15.4 18.5 (1962) a Data Period 1941-1970, b Data Pe#iod- 1954-1978. Source: I l Environmental Data Service, 1978, Local climatological data, annual summary with comparative data, Wichita, Kansas: Environ-mental Science Services Administration, U.S. Department of Commerce, l Silver Spring, Maryland. Rev. 1 4/81 0
WCCS-ER (OLS ) TABLE 2.3-8 MAXIMUM SHORT PERIOD RAINFALL FOR TOPEKA AND WICIIITA, KANSAS TOPEKA WICIIITA Time Sainfall , Rainfall Interval (inches) Date (inches) Date 5 Minutes 0.67(a) 9/14/30 0.66(c) 9/06/11 10 Minutes 1.19I "I 8/13/49 1.10(c) 6/14/31 15 Minutes- 1.52(a) 8/13/49 1.52(c) 6/14/31 30 Minutes 2.92(a) 8/13/49 2.31(c) 7/31/50 60 Minutes 4.16(a) 8/13/49 3.28(c) 7/31/50 2 Ilours 4.77(a) 8/13/49 3.54(c) 9/06/11 ?- 3 Itours 4.79(a) 8/13/49 4.93(c) 9/07/11 6 Ilours 4.85(a) 8/13/49 6.68(c) 9/06/11 12 Ilours 7.71 I8) 9/06/09 7.89(c) 9/06/11 24 Ilot'rs 8.08 II 9/06/09 7.99(b) 9/06/11 a Data Period 1900-1961. b Data Period 1889-1961. c Data Period 1903-1961. Sources: U.S. Weather Bureau, 1963, Maximum recorded United States point rainfall for 5 minutes to 24 hours for 296 first order stations: U.S. Weather Bureau, Department of Commerce, Technical Paper No. 2. U.S. Department of Commerce, 1978, Local Climatological Data, Topeka, Wichita, Kansas: National Oceanic and Atmospheric Administration, National Climatic Center, Asheville, N.C. Re v. 1 4/81 :
l WCGS-ER(OLS)
. TABLE 2. 3-9 TOTAL NUMBER OF DAYS WITH FREEZING PRECIPITATION IN WICHITA, KANSAS
- Month Number November 6 December 34 1
January 9 l February 23 March 11 Total 83 i
- Data Period 1939-1948.
I \ Source: l < Bennett, Iven, 1959, Glaze--its meteorology and climatology, geographical distribution and economic l effects: U.S. Army, Headquarters Quartermaster Research and Engineering Command, Natick, Massachusetts, Technical Report EP-105, 217 pp. Ia Rev. 1 4/81
l WCGS-ER(OLS) TABLE 2.3-J.0 ANNUAL PRECIPITATION WIND ROSE y (10 METERS) JOINT WIND FREQUENCY Dl%TRIBUTION DATA PERIODI MARCH 1979 THROUGH FEBRUARY 1980 WOLF CREEK GENERATING STATION PRECIPITA}0NWINORSE E kR /0 $ 31 A 0 N 7699-G42 5 OR 0 0-1 5 5 .0 3 Sf0 - 5 0.0 >10.0 TOTAL S ND NNE O 3 7 4 1 0 15 4 14 3.00 1 14 2.65 1.52 .38 0.00 5.68 NE O 5 7 4 1 0 17 4.34 0.00 1.89 2.65 1.52 .38 0.00 6.44 ENE O 5 IR S I O 29 4.36 0.00 1.89 6.82 1.89 .38 0.00 10 98 j 0.0! .7k 4.kk 1.8 11 00 8.b ESE o 2 6 7 2 1 18 5 70 0 00 .76 2.27 2.65 .76 .38 6.82 SE 2 2 7 12 3 0 26 5.32
.76 .76 2.65 4.55 1 14 0.00 9.85
.3 1.1 2.65 1.8 1.52 00! 7.k8
.3k 1 52 5.k8 3.4$ .7k .3k 12.h SSW l 3 4 6 1 0 15 4.80
.38 1 14 1 52 2.27 .38 0 00 5.68 Sw 0 2 2 4 2 0 10 5 37 l 0.00 .76 .76 1.52 .76 0.00 3.79 ;
wsv 0 0 1 1 0 0 2 4.65 I 0 00 0 00 .38 .38 0 00 0 00 .76 1 0.0b 1 52 11k .ik 0 00 0.0! 3.4f wNw 0 2 2 1 2 0 7 4.67 ' O.00 .76 .76 .38 .76 0 00 2.65 l Nw 0 0 2 1 0 0 3 4.23 0.00 0 00 .76 .38 0.00 0.00 1.14
, .76 11 1.8 1 52 .76 0.0 6.
N
.38 1
1.89 5 6
'3.03 8 2 1 23' 4.93 2.27 .76 .38 8.71 CALM o 0 CALM 0 00 0.00 TOTAL 8 45 104 7d 26 3 264 4.80 3.03 17.05 39.39 29.55 9.85 1.1 '+ 100 00 '
Num8E6.0F VALIO OBSERVATIONS WITH PRECIPITATION 264 3.01 PCT. NUN 8EE OF VALID OBSERVATIONS WITHOUT PRECIPITAfl0N 8399 9S.62 PCT. N B O 8 NO Ah8k Tl OTALAMOUNTOFPRkCIPITATIONFORDATAPERIOD 100lkINCHES 28.l i MEY ggg g [R T O N bbEh ' Rev. 1 O. 4/81
4
~
cx WCGS-ER(OLS) (O \ TABLE 2. 3- 11 u ANNUAL PRECIPITATION WIND ROSE (60 METERS) JOINT WINO FREQUENCY DISTRIBUTION DATA PERIO0t MARCH 1979,THROUGH FEBRUARY 1980 I , nWE S
$22A f3 l1 Eio,09988 if.'i453i. B 020'ANs5- s3?E T08' M i 7699-062 WIND WIND SPEED CATEGOWIES(METERS PER SECOND) MEAN SECTOR 0.0-1 5 1 5-3 0 3 0-5.0 5.0-1.5 7.5-10.0 >10.0 TOTAL SPEED NNE 0 1 1 7 8 2 19 7 44 0.00 .38 .38 2.65 3.03 .76 7.20 NE O 0 7 3 3 0' 13 5 66 0 00 0 00 2 65 1.14 1.14 0.00 4.92 0.00 0.00 ~ .76 6.b$ 4. h 1.52 13.
0.00 0.00 .7! 3.hh 22h 1.52 8.b
- 0.00 0.0! 0.00 2.2h 2.65 11 6.06
,^ SE o 1 2 4 to 6 23 8.77 0.00 .38 .76 1.52 3.79 2.27 8.71 SSE 0 1 2 7 7 4 21 7.80 0 00 .38 .76 2.65 2.65 1.52 7.99 0 00 .3 18 4.fh 3.4 1.52 11.36 0.00 0 00 .7! 2.2 18! .7$ 5.k8 SW 0 0 2 6 1 2 11 7.23 0.00 0 00 .76 2.27 .38 .76 4.17 0.0 .38 00 .76 ' O .38 1 52 l
l 0.0h 1.1 .3k 1.52 .3b .7k 4.!h 0 00 .3 .3 .38 0.00 .3 1 52 0.0h 00! .7k .3b .76 0.0 1.8h ! Op00 0.0 11 1.8 .76 .7 4. 5 0.0b 0 00 3.0! 2.2h 22h 11 8.N 0.0h 0 00 TOTAL 0 9 40 97 78 40 264 7.37 0.00 3.41 15 15 36.74 29.55 15 15 100.00 l0N 264 3.01 PCT. ROFVALLOObaERVAT'ONSW{THPRECIPigTAHON8jg 8[,"Pi888ja84%iTHUTPREC 9H { b AT b FOR DATA PERIOD hhbk$N 4E5
) X5 T Chuk Rev. 1 4/81
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r - WCGS-ER(OLS) 200R ORIGIM 4 , , l
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TABLE 2.3-12 (Continued) MONTHLY PRECIPITATION WIND ROSE (10 METERS) Page 2 of 3 ) i t1, .f . .. ... i,l. c n ..,.....w..s,..n.
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Y' v .- . T BLE 2.3 Shee't 1 of 13 Monthly and. Annual Joint Wind Speed and Wind Direction Frequency Distribution'at the. Chanute Flignt Service Station, Kansas a JOINT WIND SPEED. WIND DIRECTION FREQUEN'.;Y DISTRIBUITON (IN PERCENT) FOR THE MONTH OF JANUARY DATA SOURCE: CHANUTE F.S.S., KANSAS DATA PERIOD: JANUARY 1, 1955 TO DECEMBER 31, 1964 , SECTOR UPPER CL' ASS INTERVALS OF WIND SPEED (KNOTS) MEAN i 2.5 5.0 7.5 10.0 12.5 15.0 17.5 20.0 >20.o TOTAL SPEED j' i NNE .o .7 .8 2.3 .9 1.3 .6 .4 .2 7.2 11.2 NE .o .6 .4 .9 .4 .6 .o .1 .o 3.o 9.5 ENE .1 .7 .3 .5 .2 .1 .o .o .o 1.9 7.3 i E .o .7 .6 .7 .2 .2 .o .o .o 2.3 7.5
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~ ESE .9 - 1. 0 1.8 .2 .5 .o 4.5 8.5 j S' .o 1.1 1.1 1.5 .8 .4 .2 .2 .o 5.2 8.8 SSE .o 1.1 1.2 2.5 1.2 1.4 .4 .6 .2 s.6 1o.7 %
.5 .o .5 .9 3.0 1.9 2.3 1.3 2.1 .9 12.9 13.6 O SSW .o .7 .4 2.5 1.7 2.5 .6 .6 .5 9.6 12.4 $
i SW .o .4 .4 1.o .7 .7 .2 .a .1 3.6 10.9 W WSW .o .8 .5 1.1 .3 .2 .o .2 .o 3.0 8.4 3 ! W .o .4 .4 .3 .2 .2 .o .1 .o 1.8 9.5 O' l WNW .1 .6 .7' 1.3 .5 .4 .2 .3 .1 4.0 9.9 $ ! NW .o .6 1.0 1.9 .8 1.o .5 .7 .1 6.5 11.2 NNW .o 1.o 1.3 2.9 1.7 3.9 1.4 2.8 .5 15.5 13.2 j N .o .5 .8 2.1 .8 1.7 .4 .8 .4 7.6 12.3 CALM 2.8 i TOTAL .2 11.2 11.9 26.3 12.4 17.4 5.8 9.o 3.0 100.0 11.0
, NUMBER OF INVALID OBSERVATIONS = 3 -
1 Rev. 1 1 4/81 l
TABLE 2. 3-15 ( CO NTI NUED ) SHEET 2 OF 13 JOINT WIND SPEED, WIND DIRECTION FREQUENCY DISTRIBUITON (IN PERCENT) FOR THE MONTH OF FEBRUARY DATA SOURCE: CHANUTE F.S.S., KANSAS DATA PEPIOD: JANUARY 1, 1955 TO DECEMBER 31, 1964 - ~ SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) MEAN 2.5 5.0 7.5 10.0 12.5 15.0 17.5 20.0 >20.o TOTAL SPEED NNE .o .7 1.1 2.8 1.2 1.2 .2 .3 .1 7.6 10.5 NE .o .8 .6 2.1 .9 .6 .2 .4 .o 5.6 10.2 ENE .o .4 .4 1.0 .6 .4 .o .o .o 2.8 9.4 E .o .5 .5 1.0 .2 .5 .1 .2 .o 2.9 9.7 ESE .o .8 1.1 2.1 .4 .8 .o .o .o 5.3 9.1 SE .o .7 .7 1.8 .7 .9 .1 .3 .o 5.1 10.2 SSE .o .4 .5 1.8 1.1 1.7 1.o .4 .1 7.1 12.4 $ S .o .6 .8 2.4 1.5 2.5 .9 1.8 .3 10.6 12.9 O SSW .o .3 .6 1.4 1.1 1.3 1.1 .8 .3 6.8 12.9 I SW .o .5 .4 .7 .3 .4 .o .o .1 2.4 10.0 $ WSW .o' .4 .5 .5 .1 .2 .1 .2 .1 2.1 10.1 g W .o .3 .1 .5 .2 .3 .o .2 .1 1.7 11.3 & WNW .o .7 .5 1.1 .5 .6 .1 .4 .o 4.0 10.4
- 3 NW .o .8 .8 1.7 1.1 9 .2 .4 .o 5.9 10.6 NNW .o 1.2 1.2 4.3 1.o 4.2 1.1 1.9 .6 16.2 12.5 N .o 1.1 .9 2.0 1.3 2.6 .6 1.4 .2 10.2 12.2 CALM 3.5 ,
TOTAL .1 10.0 10.6 27.2 12.7 19.2 6.o 8.7 2.1 100.0 11.0 NUMBER OF INVALID OBSERVATIONS = 1 Rev. 1 4/81 O O O
f (% , ;kj TABLE 2.3-15 (CONTINUED) SHEET 3 OF 13 I JOINT' WIND SPEED, WIND DIRECTION. FREQUENCY r DISTRIBUITON (IN PERCENT) FOR THE MONTH OF MARCH
~
DATA SOURCE: CHANUTE'F.S.S., KANSAS
- DATA PERIOD
- JANUAR( 1, 1955 TO DECEf4BER ' 31 ', 1964 SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) MEAN'
- 2. 5 ' 5.0 7.5 10.0 12.5'15.0 17.5 20.0 >2o.o TOTAL SPEED ,
NNE .o .6 .6 2.2 1.1 1.3 .6 .4 .1 6.9 11.5 NE .O .5 .4 1.8 .9 .9 .2 .3 .o 5.2 11.0 ' ENE .o .5 .6 1.7 .6 1.0 .2 .1 .o 4.8 10.3
- E .O .4 .4 1.7 .3 '1. 5 .2 .2 .0 4.8 11.1 i ESE .o .5 .7 2.5 1.0 1.1 .3 .3 .1 6.6 II.o
, SE .O .4 .4 1.7 .8 1.4 .4 .4 .1 5.6 11.9 SSE .O .5 g . .4 2.2 1.2 1.9 .7 2.3 1.1 10.4 14.3 O ! S .o .3 .3 1.1 .7 1.9 .8 2.1 2.7 10.0 17.4 O I SSW .O .2 .2 .7 .5 .8 .5 1.0 1.0 4.9 15.9
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[ 13.2 *~ NW .O .5 .4 1.9 .9 1.6 .8 1.2 .2 7.6 13.0 1 NNW .0 .8 1.0 2.4 1.2 1.6 1.0 1.6 .7 10.2 12.8 j N .0 .3 .4 1.2 .7 1.7 .6 1.6 .3 6.9 14.0 1 CALM ' 2.3 TOTAL .1 7.1 7.3 24.6 11.7 18.9 7 . 3' 13.3 7.5 100.0 12.8 j NUMBER OF INVALID OBSERVATIONS = o 3 Rev. 1
; _________________________________________ 4/81 i
i i f 1 l i
TABLE 2. 3-15 ( CONTI NUED ) SHEET 4 OF 13 l JOINT WIND SPEED. WIND DIRECTION FREQUENCY DISTRIBUITON (IN PERCENT) FOR THE MONTH OF APRIL DATA SOURCE: CHANUTE F.S.S.. KANSAS DATA PERIOD: JANUARY 1 1955 TO DECEMBER 31, 1964 SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) MEAN 2.5 s.o 7.5 10.0 12.5 15.0 17.s 20.o >20.o TOTAL SPEED NNE .o .s .7 1.4 .9 1.1 .3 .3 .o s.3 11.1 NE .o .5 .4 1.6 .8 1.0 .5 .4 .o 5.1 11.3 ENE .o .1 .3 1.3 .4 .5 .3 .o .1 3.o 11.1 E .o .5 .8 1.5 .s .6 .2 .4 .o 4.6 10.6 ESE .o .5 .7 1.9 1.2 .8 .2 .1 .1 s.s 10.4 SE .o .8 .7 2.0 .8 .6 .4 .3 .2 s.8 10.6 SSE .o .4 .7 2.4 1.3 2.9 .8 2.s 1.s 12.5 14.6 S .o .4 .4 2.3 1.o 2.4 4.2 x
.8 4.0 15.5 17.3 SSW .o .5 .2 1.o .3 1.2 .4 1.4 1.1 6.1 15.8 Q
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.2 2.0 2.2 11.3 12.4 3O-WNW .o .7 .s 7 .3 .6 .5 .6 .2 4.0 NW .1 .8 .7 1.2 .5 .9 .5 1.1 12.3 $
.5 6.3 12.6
- NNW .o .9 1.2 2.0 1.2 2.o .6 1.6 .3 9.8 12.3 N .o .9 .5 1.6 .8 1.4 .s .7 .1 6.6 11.s CALM 3.1 TOTAL .3 8.4 8.3 22.5 10.7 17.2 6.1 14.4 9.0 100.0 12.7 NUMBER OF INVALID OBSERVATIONS = 2 Rev. 1
_________________________________________ 4 /81 e = 0 0 0
1 TABLE 2. 3-1S ' ( CONTINUED ) SHEET 5 OF '13 l. JOINT WIND-SPEED, WIND DIRECTION FREQUENCY DISTRIBUITON (IN PERCENT) FOR THE MONTH OF MAY DATA SOURCE: CHANUTE F.S.S., KANSAS
- . DATA PERIOD
- JANUARY 1, 1955 TO DECEMBER 31, 1964 SECTOR UPPER CLASS INTERVALS OF WIND SPEED'(KNOTS) MEAN 2.5 5.0 7.5 10.0 12.5 15.0 17.5 20.0 >20.o TOTAL' SPEED l NNE .o .6 .3 1.3 .6 .7 .1 .2 .o 3.9 10.3 NE .1 .8 .6 1.6 .8 .7 .2 .2 .o 5.1 9.8 ENE .o .6 .6 1.5 .2 .5 .1 .1 .o 3.6 9.1 E .o .9 .7 2.1 .6 .6 .o .2 .o 5.1 9.4 ESE .o 1.1 1.3 2.9 1.0 9 .2 .2 .1 7.7 9.7 SE .o .8 1.3 3.0 .8 1.0 .4 .6 .o 7.8 10.3 4
SSE .o .7 .c 2.7 2.3 4.0 1.5 . 2. 2 1.5 15.7 14.2
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i NNW .o .7 .5 1.2 .6 1.2 .3 .5 .o 4.9 11.1 j N .o .6 .6 1.0 .6 1.1 .2 .2 .o 4.3 10.8 . j CALM 3.3 1 TOTAL .1 10.3 9.1 24.3 12.o 17.1 5.3 11.6 6.9 100.0 12.0 ' { 4 NUMBER OF INVALID OBSERVATIONS = 7 Rev. 1 *
- j. 4/81 1
f 1 1
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TABLE 2.3-15 (CONTINUED) SHEET 6 OF 13 l JOINT WIND SPEED, WIND DIRECTION FREQUENCY - DISTRIBUITON (IN PERCENT) FOR THE MONTH OF JUNE DATA SOURCE: CHANUTE F.S.S., KANSAS DATA PERIOD: JANUARY 1, 1955 TO DECEMBER 31, 1964 SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) MEAN 2.5 5.0 7.5 10.0 12.5 15.0 17.5 20.0 >20.0 TOTAL SPEED NNE .O .9 1.0 1.0 .7 .8 .1 .1 .O 4.5 9.5 NE .O .9 .9 1.4' .4 .7 .2 .O .O 4.5 9.1 ENE .O .7 .5 1.0 .4 .4 .O .1 .O 3.2 8.9 E .0 .9 .9 1.6 .5 .7 .O .O .O 4.7 8.9 ESE .O 1.0 1.6 2.7 .7 .7 .2 .2 .O 7.2 9.1 SE .O 1.0 1.6 4.1 1.3 1.3 .3 .2 .O 9.9 9.6 SSE .O 1.2 1.5 4.9 2.4 3.2 1.2 1.5 .4 16.2 11.7 S
.O .9 1.5 4.9 2.4 4.5 1.5 3.3 1.0 20.1 13.2 O SSW .O .3 .7 1.8 .7 1.6 .6 1.2 .4 7.3 13.1 Y SW .O .4 .3 .9 .5 .2 .2 .O .O 2.6 9.8 WSW .O .2 .4 .4 .O .O .O 1.3
.1 .1 8.2 --
W .O .O
.2 .O .2 .1 .O .O .O .6 9.7 h WNW .O .5 .4 .6* .3 .1 .1 .O .O 1.9 8.5 3 NW .1 .7 .3 1.3 .2 .3 .O .O .O 3.0 8.2 NNW .O .7 .8 1.2 .4 .4 .O .1 .O 3.7 8.8 N .O 1.0 .4 1.5 .3 .5 .1 .2 .O 4.1 9.4 CALM 5.1 TOTAL .2 11.5 12.9 29.7 11.5 15.6 4.6 7.0 1.9 100.0 10.2 NUMBER OF INVALID OBSERVATIONS = 0 Rev. 1 4/81 O O O
t TABLE 2. 3-15 ( CONTI NUED ) SHEET 7- OF 13 l L JOINT. WIND SPEED, WIND DIRECTION FREQUENCY >= DISTRIBUITON (IN PERCENT) FOR THE MONTH OF JULY l DATA SOURCE's CHANUTE.F.S.S., KANSAS DATA PERIOD:' JANUARY 1,:1955 TO DECEMBER 31, 1964 l. i SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) MEAN 2.5 5.0 7.5 10.0 12.5 15.0 17.5 20.0 >20.o TOTAL SPEED ! NNE .o .9 .6 1.7 .4 .3 .o .2 .1 4.2 8.8 NE .o .9 1.0 1.9 .4 .2 .o .o .o 4.6 8.1 ENE *
.o .9 1.o 1.8 .6 .3 .o .o .o 4.6 4.2
! E .o 1.2 .8 1.7 .3 .3 .o .1 .o .4.4 8.2 ' j' ESE .o 1.5 2.5 3.5 .5 .6 .1 .2 .o 8.9 8.3 b SE .1 1.6 1.8 3.8 .8 .4 .2 .2 .o 8.9 8.5
- g SSE .o 1.3 1.9 6.2 2.7 2.3 1.0 .3 .1 15.9 10.4 o j S .o 1.4 1.2 6.3 3.6 4.4 1.4 2.0 .2 20.5 11.3 O.
. SSW .o .3 .6 2.5 1.9 2.5 .7 -1.1 .1 9.9 12.5 SW .o .6 .4 1.0 .5 .2 .2 .o '2.9 4
.1 . 9.3 m
- WSW .o .3 .2 .3 .2 .o .o .o .o 1.0 7.8 o l W .o .2 .o .3 .o .o .o .o .o .5 6.5 i --
WNW .o .3 .3 .3 .o .o .o .o .o [ 1.0 7.o . j NW .o .5 .2 .3 .1 .o .o .o .o 1.3 8.0 i NNW .o .8 .4 1.o .3 .2. .2 .1 .o 3.1 9.4 N .o 1.0 .8 1.1 .4 4 .o .2 .o 3.9 8.9 ! CALM '4.6 i TOTAL .2 13.6 13.8 33.5 12.8 12.5 3.9 4.4 .6 100.0 9.5 - NUMBER OF INVALID OBSERVATIONS = 1 P 1 Rev. 1
,4/81 i
k
TABLE 2. 3-15'( CONT I NUED ) SHEET 8 OF 13 l JOINT WIND SPEED, WIND DIRECTION FREQUENCY DISTRIBUITON (IN PERCENT) FOR THE MONTH OF AUGUST DATA SOURCE: CHANUTE F.S.S., KANSAS CATA PERIOD: JANUARY 1, 1955 TO DECEMBER 31, 1964 SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) MEAN 2.5 5.0 7.5 10.0 12.5 15.0 17.5 20.0 >20.o TOTAL SPEED NNE .O .9 .9 1.9 .6 .4 .2 .O .O 4.9 8.7 NE .o 1.4 1.5 1.2 .3 .2 .o .o .o 4.7 7.4 ENE .o 1.0 1.2 1.2 .4 .2 .1 .o .o 4.4 7.9 E .o 2.2 .8 2.o .2 .3 .o .1 .o 4.6 7.8 ESE .O 1.3 1.9 2.8 .7 .3 .1 .1 .o 7.2 8.2 SE .o 1.5 2.5 5.4 1.0 .9 .O .2 .o 11.5 8.7 - SSE .o .6 1.9 6.o 2.7 2.3 .4 .4 .2 14.4 10.5 g S .o .6 1.6 6.2 3.2 4.9 1.1 1.5 .3 19.4 11.9 O SSW .0 .3 .9 2.1 1.4 2.5 .9 1.3 .1 9.5 12.5 b SW .O .3 .3 .7 .2 .8 .2 .o .2 2.7 11.4 h WSW .o .2 .2 .1 .1 .o .o .1 .o .9 9.6 % W .o .4 .1 .2 .O .1 .O .0 .O .8 7.3 o WNW .0 .2 .3 .3 .1 .1 .o .0 .o 1.1 8.8 E NW .0 .6 .2 .; .1 .0 .o .1 .o 1.3 7.4 '" NNW .o .7 .5 1.1 .5 .5 .1 .' 1 .0 3.6 9.4 N .O 1.2 .5 1.7 .5 .6 .3 .2 .O 5.0 9.4 CALM 4.O t TOTAL .2 12.5 15.4 33.1 12.o 14.3 3.5 4.2 .8 100.0 9.5 NUMBER OF INVALID OBSERVATIONS = o Rev. 1 4/81 9 9 9~
b} a
+
TABLS 2. 3-15 ( CONT I NUED ) SHEET 9'OF'13
. JOINT WIND SPEED, WIND DIRECTION' FREQUENCY t
DISTRIBUITON (IN PERCENT) FOR THE MONTH OF SEPTEMBER DATA SOURCEi CHANUTE F.S.S., KAN'SAS DATA PERIOD: JANUARY '1 , 1955 TO DECEMBER 31, 1964
- . SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) MEAN 2.5 5.0 7.5 10.0 12.5 15.0-17.5- 20.0 >20.0 TOTAL SPEED 4
i NNE .o 1.0 1.0 l'. 8 1.3 1.4 .5 .2 .o 7.0 10.3 NE .O .6 .9 2.2 1.0 .8 .1 .2 .O 5.7 9.8 I ENE .o .7 .6 1.4 .8 .3 .O .0 .0 3.8 9.0 , i E .o 1.0 .6 1.3 .3 .3 .o .o .o 3.6 s.0 4 ESE .1 2.5 1.8 3.2 .8 .3 .o .O .O 7.8 7.9 SE .O 1.4 1.6 4.0 1.3 .5 .O .O .O 9.1 8.6 ! SSE .o .9 1.0 5.5 3.1 3.2 .8 1.0 .2 15.7 11.4 s l S .O .5 1.0 4.0 2.9 3.0 '1. 3 2.4 1.0 16.2 1 3 .' 2 @ m-j SSW .o .7 .6 1.7 .8 1.5 .6 1.I' .7 7. 7' 13.1, SW .o .5 .3 .5 .3 .3 .1 .1 .1 2.3 10.4 E !' WSW .O .3 .2 .4 .1 .1 .O .0 .0 1.2 8.7 . 3 ~.
.O .O .O .7' 6.8 O ')
W .0 .3 .' 2 .2 .1 .O WNW .o .6 .4 .3 .2 .1 .0 .1 .0 1.6 7.9 .b. l 7.3 NW .1 .5 .3 .7 .1 .1 .O .0 .0 1.9 NNW .0 .7 .7 1.7 .6 1.0 .2 .3 .0 5.3 10.5' N .o 1.o .9 1.5 1.0 1.2 .3 .2 .1 6.1 10.2 3 CALM 4.4 l !- TOTAL .5 12.2 12.1 30.3 14.5 14.2 3.9 5.7 2.3 100.0 10.1 4 l NUMBER OF INVALIO OSSERVATIONS = 4 1 1 3 'Rev.'l j 4/81 e 1 l I i -
TABLE 2. 3-15 ( CO NT I NUED ) SHEET 10 OF 13 l JOINT WIND SPEED, WIND DIRECTION FREQUENCY DISTRIBUITON (IN PERCENT) FOR THE MONTH OF OCTOBER DATA SOURCE: CHANUTE F.S.S., KANSAS DATA PERIOD: JANUARY 1, 1955 TO DECEMBER 31, 1964 SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) MEAN 2.5 5.o 7.5 10.0 12.5 15.0 17.5 20.0 >20.o TOTAL SPEED NNE .o .8 .7 1.4 .8 .6 .1 . .3 .o 4.7 9.8 NE .o .8 .6 .5 .3 .1 .1 .o .o 2.5 7.7 ENE .o .4 .5 .6 .3 .5 .2 .o .o 2.3 9.5 E .o .5 .6 1.0 .2 .o .o .o .o 2.3 7.9 ESE .o .8 1.5 2.9 .4 .1 .0 .o .o 5.8 8.2 SE .o .8 1.1 4.3 1.5 1.o .4 .1 .o 9.2 9.7 SSE .o 1.1 1.0 5.2 2.0 2.5 1.0 1.1- 4 14.3 11.7 S .c .3 1.o 5.5 3.2 3.1 1.2 2.5 .6 17.5 12.8 y SSW .o .4 .8 2.2 1.1 2.1 1.0 1.o .4 9.1 12.8 O SW .o .2 .4 .8 .3 .2 .o .1 .o 2.0 9.7 f WSW .o .3 .2 4 .o .1 .o .o .o 1.0 8.o y W .o .4 .2 .4 .1 .o .o .o .0 1.2 7.o -- WNW .o 1.1 .6 .4 .o .2 .o .2 .1 2.7 8.2 O NW .o 1.1 1.1 .8 .2 .5 .2 .2 .1 4.3 9.1 3 NNW .o 1.0 1.3 2.7 .8 l '. 6 .5 .6 .2 8.7 10.7 N .o 1.1 1.4 2.3 .8 1.5 .2 .5 .1 7.9 10.4 CALM 4.5 4 TOTAL .1 11.1 13.1 31.4 12.1 14.0 5.0 6.7 2.0 100.0 10.2 NUMBER OF INVALID OBSERVATIONS = 1 Rev. 1 4/81
-------------------------------- -------- c.
O O O
._m.1 _ _ _ .
\ g .
t T A B L E ' 2 . 3 - 1 5 ( C O'N T I N U E D ) SHEET 11-OF 13 L
' JOINT WIND SPEED, WItlD DIRECTION FREQUENCY 0ISTRIBUITON-(IN PERCENT) FOR THE MONTH OF NOVEMBER
. DATA SOURCE: CHANUTE F.S.S.. KANSAS- '
' DATA PERIOD: JANUARY 1, 1955'To DECEMBER _31, 1964
. SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) _MEAN 2.5 5.o 7.5 10.0 12.5 15.o'17.5 20.0 > 2c .'o -
TOTAL SPEED i NNE .o .5 .' 6 1.1 .7 .4 .2 .3 .o 3.8 10'.1 NE .o .5 .3 .7 .4 .5 .o .o .o 2.4/ 9.7 > ENE .o .5 .3 1.o .2 .2 .o .o .o 2.1' 8.5
- E .o .4 .4 .7 .1 .1 .o .o .o 1.7 7.8 ,
ESE .o .5 .8 1.2 .4 .o .o .o .o 2. 8. 8.1 SE .o .5 1.1 2.0 1.2 1.0 .3 .o .o 6.1 '9.9 SSE .o .5 .7 2.9 1.8 3.0 1.0 .8 .4 11.2 12.4 g j S .o .4 .8 3.5 2.3 3.9 1.5 3.1 1.3 16.7 14.1 O 't SSW .o .4 .8 2.3 1.5 2.2 .8 1.7 .3 10.0 1 3 .'o O f SW .o .6 .4 .9 .4 .5 .1 .4 .2 3.4 11.3 .$ 'l WSW .o .8 .5 .7 .4 .3 .,
.1 .1 3.o 9.1 ' 32 -
W .o ' I . o' .5 .7 .2 .2 .o .o . o' . 2.6 7.4 8 WNW .o .7 8 1.1 .4 .7 .2 .2 .o 4.o 9.9 [ .j NW .o 1.1 1.5 2.1 .8 1.4 .8 .3 .3- 8.4- 1o.9 *: NNW .o .'8 1.3 2 . '6 1.6 2.5 1.0 1.7 .5 12.o 12.6 i N .o 1.0 .6 2.1 1.0 1. 4 ' .3 .5 .2 7.2' 11.1 ' I CALM 2.7 i TOTAL .1 10.3 II.o 25.6 13.3 18.1 6.3 9.2 3.3 100.0 11.3 - i t NUMBER OF INVALID OBSERVATIONS = 1 Rev. 1 'li 4/81
.{
l
.J
TABLE 2. 3-15 ( CONTI NUED ) ,$HEET 12 CF 13 l J D.T n IND SPEEC , 4IND DIRECTION FREQUENCY DISTRIBUITON (IN PERCENT) FOR THE MONTH OF DECEMBER DATA SOURCE: CHANUTE F.S.S., KANSAS OATA PERIOD: JANUARY 1, 1955 TC DECEMBER 31, 1964 SECTOR UPPER CLASS INTERVALS OF WIND SPEED (KNOTS) MEAN 2.5 5.0 7.5 lo.o 12.5 15.0 17.5 20.0 >20.o TOTAL SPEED NNE .o .7 1.0 2.0 1.1 1.1 .5 .3 .1 6.8 10.7 NE .o .6 .9 1.0 .5 .5 .2 .2 .o 4.0 9.5 ENE .o .6 .3 .9 .2 .1 .1 .o .o 2.2 8.4 E .o .5 .8 .6 .2 .2 .o .o .o 2.5 8.o ESE .o .8 .6 1.3 .6 .4 .o .o .o 3.7 8.6 SE .o .7 1.0 1.7 .6 .4 .1 .o .o 4.5 8.8 SSE .o .7 1.0 2.7 1.4 1.8 .6 .7 .1 9.0 11.3 2 S .o .5 .8 3.7 2.2 3.1 1.5 1.5 1.0 14.4 13.2 @ SSW .o .8 .7 3.0 1.3 1.8 .2 .6 .3 8.7 11.4 f SW .o .5 .5 1.o .3 4 .o .1 .1 3.1 9.8 M WSW .o .7 .2 1.2 .2 .3 .o .o .1 2.9 9.0 3 W .o .3 .3 1.4 .2 .1 .o .o .o 2.5 8.8 WNW .o .8 1.0 1.3 .2 .5 .3 4 .2 4.7 10.3 m NW .o .7 1.1 2.0 1.0 1.5 .5 .f .1 7.6 11.2
~
NNW .o 1.2 1.2 3.2 1.5 2.2 1.0 .9 4 11.5 11.7 N .o .5 .9 2.3 1.3 2.5 .5 1.0 .1 9.2 12.0 CALM 2.7 TOTAL .1 lo.8 12.4 29.2 13.0 17.0 5.7 6.5 2.5 100.0 10.7 NUMBER OF INVALID OSSERVATIONS = 1 Rev. 1 4/81 9 O , O
_.___ ,_ - _ _ . -, ....-. ---~.-~--- -- --- - - - - - - ' - ~' ~ ~ '~'
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- 1 j .- 3 .
.f 3
TABLE 2. 3'_15 -( CONTI NUED ) SHEET'[13 CF'13 i
- ANNUAL JOINT WIND SPEED, WIND DIREC. TION' ~
1-FREQUENCY DISTRIBUTION (IN-PERCENT) .,. DATA SOURCE: CHANUTE . F . S.S . KANSAS l : DATA PERIGO: JANUARY 1, 1955 Tc DECEMBER 31,- 1964 !
- . SECTOR
! UPPER CLASS INTERVALS '0F-WIND SPEED (KNOTS) MEAN 5.o 7.5 10.0 12.5 15.0 17.5- 20.c >20.o TOTAL SPEED i i NNE .o .7 .8 1.7 .8 .9 .3 .3 .1 5 .' 6 ' 10.3 NE .o .7 .7 1.4 .6 .6 .1 .1 .O 4.4 .9.5 ENE .o .6 .6 1.2 .4 .4 .1 .O .0 3.2 9.0 l' [' E .o .7 .7 1.3 .3 .5 .O .1 .0 3.6 8.9 I j ESE .o .9 1.3 2.4 .7 .5 .2 .1 .o 6.1 8 '. 9 l- SE .o .9. 1.2 2.9 1.0 .8 .2 .2 .O -7. 4 9.5 j- SSE .o .8 1.1 3.8 1.9 2.5 .9 1.1 .5 12.6 12.1 4 t
'S .O .6 :s l .9 3.8 2.3 3.3 1.3 2. 6 - 1. 4 ' 16.2 13. S ~.
- . SSW .o .4 .6 1. 9 1.1 1.8 .7 1.1 .5 8.1 13.2-
~m -'
[ i SW .O .4 .3 .4 l' WSW .O .4 .3-
.7-
.6 .2
.4
.2
.1
.1
.2 .1 2.7 10.9 k 4
.I 1.9 W .O .4 .2 .5 .1 .2 .O .1
.1
.1 1.5 9.4 9.5 1O ,.
WNW i $. .O .6 .5 .7 .3 .4 . I' .3 3.0 1 NW .0 .7 .7 1.3 .5
.I 10.4 b. !
.7 .3 .4 .1 4.9 10.8-
- 1 NNW .O .9 .9 2.2 1.0 1.8 .6 1.0 .3 8.6- 11.9 l N .0 .8 .7 1.7 .'8 1.4 .3 .6 6.6 1
.1 11.3
?
CALM 3.6 I ! TOTAL .2 10.8 11.5 25.2 12.4 16.3 5 3 8.4 3.5 100.0 10.9 - 2 NUMBER OF INVALID OBSERVATIONS = 21 3 i Rev. l-i 4/s1 l <- -_ _. ___ . . t 4
& . -- - - +-- , - , % - - ----.,r. - * . . . .. . . , - ' . - ---- ------ - I
TABLE 2.3-16 Sheet 1 of 8 PERSISTENCE OF WIND DIRECTION FREQUENCY DISTRIBUTION (IN PERCENT) AT CHANUTE F.S.S., KANSAS
- SPRING Upper Class Intervals of Wind Direction Hours of Persistence NNE NE ENE E ESE SE SSE S 3 37.60 45.00 49.39 41.92 40.72 47.24 31.01 20.97 6 15.70 28.18 30.49 26.20 27.36 25.20 27.91 20.72 9 22.31 10.91 5.49 13.10 14.66 11.81 10.23 18.73 12 9.92 3.64 7.32 12.23 13.03 9.45 8.06 9.49 15 4.13 6.82 .00 6.55 .00 3.94 9.30 9.99 18 7.44 5.45 7.32 .00 1.95 2.36 4.65 3.00 s 21 2.89 .00 .00 .00 2.28 .00 3.26 3.50 @
24 .00 .00 .00 .00 .00 .00 2.48 3.00 m 27 .00 .00 .00 .00 .00 .00 .00 2.25 E 30 .00 .00 .00 .00 .00 .00 3.10 1.25 2 33 .00 .00 .00 .00 .00 .00 .00 1.37 o 36 .00 .00 .00 .00 .00 .00 .00 1.50 E 39 .00 .00 .00 .00 .00 .00 .00 .00 42 .00 .00 .00 .00 .00 .00 .00 1.75 45 .00 .00 .00 .00 .00 .00 .00 .00 48 .00 .00 .00 .00 .00 .00 .00 .00 51 .00 .00 .00 .00 .00 .00 .00 .00 54 .00 .00 .00 .00 .00 .00 .00 .00 57 .00 .00 .00 .00 .00 .00 .00 .00 60 .00 .00 .00 .00 .00 .00 .00 2.50
- Data Period 1955-1964.
Rev. 1 4/81 O O O
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Uv : e ( 'i N 814734 u D 1 - ~ 321 " n i d t n n i o W W 94962090000000000000 c G N 25739000000000000000 ( . t W . . . . . . . ..... . . I 07592 4 R 511 6 P 1 S 3 ( 2
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E 701' L 531 B A T 73000000000000000000 W 81000000000000000000 S . . . W 36 81 43300.000000000000000 85600000000000000000 W . . . . . . . ........... S 602
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TABLE 2. 3 1.6 (continued) Sheet 5 of 8 FALL Upper Class Intervals of Wind Direction Hours of Persistence NNE NS ENE E ESE SE SSE S 3 38.08 52.90 47.11 61.70 44.90 44.01 28.32 23.02 6 20.92 36.13 33.06 14.89 21.22 24.51 21.20 20.41 9 18.83 7.74 7.44 19.15 10 .86 19.94 18.71 12 15.06 .00 3.31 4.26 8.16 8.91 10.76 13.15 15 4.18 3.23 4.13 .00 6.12 2.79 11.08 7.37 18 .00 .00 4.96 .00 .00 6.69 3.80 5.44 21 2.93 .00 .00 .00 .00 .00 1.11 1.59 24 .00 .00 .00 .00 .00 2.23 3.80 2.72 - 27 .00 .00 .00 .00 .00 .00 .00 3.06 $ 30 .00 .00 .00 .00 .00 .00 .00 .00 @ 33 .00 .00 .00 .00 .00 .00 .00 1.25 sx
.00 .00 .00 .00 .00 .00 .00 .00 36 39 .00 .00 .00 .00 .00 .00 .00 .00 8 42 .00 .00 .00 .00 .00 .00 .00 1.59 G 45 .00 .00 .00 .00 .00 .00 .00 1.70 --
Re c. 1 4/31 O O O
1 O O TABLE 2.3-16' (continued) Sheet 6 of 8 , FALL + y Upper-Class Intervals of Hours of ' Persistence SSW SW WSW- W WNW NW NNW N Calm j 3 40.66 60.00 69.23 83.93 61.47 39.02 26.74 30.00 45.03. ! 6 23.02 40.00 12.31 10.71 16.51 2G.34 18.43 26.87 27.23 9 19.18 .00 4.62 5.36 13.76 11.71 14.16 18.75 10.99 12 6.14 .00 6.15 .00 3.67 7.80 12.58 10.00 8.38 ' 15 2.56 .00 7.69 .00 4.59 2.44 6.74 3.12 5.24 18 4.60 .00 .00 .00 .00 5.85 9.44 3.75 3.14 21 1.79 .00 .00 .00 .00 6.83- 3.15 2.19 .00 $' 24 2.05 .00 .00 .00 .00 .00 1.80 2.50 .00 i 27 .00 .00
.00 .00 .00 .00 2.02 2.81 .00 1 30 .00 .00 .00 .00 .00 .00 .00 .00 .00 $
33 .00 .00 .00 .00 .00 .00 4.94 .00 .00 g. 36 .00 .00 .00 .00 .00 .00 .00 .00 .00 e 39 .00 .00 .00 .00 .00 .00 .00 .00 .00 $ 42 .00 .00 .00 .00 .00 .00 .00 .00 .00 45 .00 .00 .00 .00 .00 .00 .00 .00 .00 s
+
Rev. 1 4/81
TABLE 2.3-16 (continued) Sheet 7 of 8 WINTER l
- Upper Class Intervals of Wind Direction l Hours of Persistence NNE NE ENE E ESE SE SSE S 3 26.67 44.94 61.19 60.82 34.34 42.63 43.67 22.52 6 21.33 22.47 14.93 26.80 26.26 23.16 20.25 23.05 9 22.00 13.48 17.91 .00 18.18 20.53 7.59 19.68 12 9.33 6.74 5.97 4.12 4.04 4.21 13.92 9.93 15 16.67 5.62 .00 .00 7.58 5.26 7.91 6.21 18 4.00 6.74 .00 . 00 6.06 .00 1.90 4.26 21 .00 .00 .00 .00 3.54 .00 2.22 6.21 24 .00 .00 .00 8.25 .00 4.21 2.53 4.26 27 .00 .00 .00 .00 .00 .00 .00 .00 30 .00 .00 .00 .00 .00 .00 .00 1.77 $
33 .00 .00 .00 .00 .00 .00 .00 .00 @ 36 .00 .00 .00 .00 .00 .00 .00 2.13 m b O b Rev. 1 4/81 9 9 9
ks o / 5 4 TABLE 2. 3- 16 (continued) Sheet 8'of 8 l WINTER- ; f
' Upper Class Intervals of Wind Direction f I ' Hours of .
Persistence SSW SW . WSW W 'WNW NW NNW N Calm- ! ! ~ 4- 3 40.29 59.00 78.26 63.89 59.35 37.14 19.17 33.33 54.03 i 6 25.51 28.00 17.39 22.22 20.65 21.43 19.46 24.39'20.97? ; ! 9 .14.78 9.00 4.35 8.33 11.61 16.07 11.59.14.63 9.68 j.
~
12 12.75 4.00 .00 5.56 .00 7.14 11.44 10.84 6.45 , J- 15 2.90 .00 .00 .00 .00 3.57 9.30 9.49' 4.03 ! 18 1.74 .00 .00. .00 -3.87 2.14 6.87 1.63 4.84 l 21 2.03- .00 .00 .00 4.52 2.50 9.01 5.69 .00 i 24 .00 .00 .00 .00 .00 5.71 3.43 .00 .00 i ! 27 .00 .00 .00 . 00 .00 .00 3.86 .00 .00 :s [ 30 .00 .00 .00 .00 .00 .00 4.29 .00 :
.00 @
- 33 .00 .00 .00 .00 .00 .00 1.57- .00 .00 -y~ ;
~
i- 36 .00 .00 .00 .00 .00 4.29 .00~ .00 .00 m ! 3E i i O I N l i 5 , I i l 1
-Rev. 1 4/81 ,
i 1 . . . - _ . a_ - .- .-_- - -
i MCGS-ER(OLS) TABLE 2.3-17 SHEET 1 OF 6 JOINT WIND SPEED, WIND DIRECTION FREQUENCY DISTRIBUTION (IN PERCENT) BY STABILITY CLASS DATA PERIOD: JANUARY 1, 1955 TO DECEMBER 31, 1964 STABILITY CLASS: PASQUILL A DATA SOURCE: CHANUTE F.S.S.. KANSAS UPPER CLASS INTERVALS SECTOR OF WIND SPEED (KNOTS) MEAN R. 5.L. 5.co_7 .jlL.Lo_c_1_R o .E..L5 . o_L7_d_2_o_._o_ > 2 0 , o T0TAL S P E E D NNE .o 3 .' 9 .o .o .o .o .o .o .o 3.9 4.0 NE .o 1.3 .o .o .o .o .o .o .o 1.3 4.0 ENE .o 1.9 .o .o .o .o .o .o .o 1.9 4.7 E .o 2.6 .o .o .o .o .o .o .3 2.6 4.0 ESE .o 6.5 .o .o .o .o .o .o .o 6.5 9.8 SE .6 1.9 .o .o .o .o .o .o .o 2.6 3.8 SSE .o 3.9 .o .o .o .o .o .o .O 3.9 4.5 S .o 3.2 .o .o .o .o .o .o .0 3.2 4.8 SSW .o 1.9 .o .o .o .o .o .o .o 1.9 4.0 SW .o 1.3 .o .o .o .o .o .o .o 1.3 4.5 , 0 WSW .o .6 .o .o .o .o .o .o .o .6 3.o W .o 1.3 .o .o .o .c .o .o .o 1.3 3.o WNW .o .6 .o .o .o .o .o .o .o .6 4.0 NW .6 3.9 .o .o .0 .o .o .o .o 4.5 4.1 NNW .o 1.3 .o .o .o .o .o .o .o 1.3 4.5 N .o 1.3 .o .o .o .0 .o .o .o 1.3 4.5 CALM 61.3 TOTAL 1.3 37.4 .o .o .o .o .o .o .o 1.00.0 1.7 NUMBER OF INVALID OBSERVATIONS = 0 4/81
WCGS-ES (OES ) [K [s_j TABLE SHEET!2 OF-6
- 2. 3-17 (CONTINUED).
JOINT WIND. SPEED, WIND DIRECTION ! -FREQUENCY DISTRIBUTION (IN PERCENT) - ic BY STABILITY CLASS DATA PERIOD: ' JANUARY'1, 1955 T0' DECEMBER'31,~1964 STABILITY' CLASS: PASQUILL B
- ' DATA SOURCES- CHANUTE F.S;S., KANSAS i
UPPER CLASS INTERVALS SECTOR OF WIND SPEED'(KNOTS) MEAN '
---- Lu5._. l u0 s% LQx0_11.,_E ljlLiO_thLlo o m> 2 0. 0 TOTAL SPEED 1 NNE~ .0 1.7 3.2 .5 .O . O' .o .O .O 5.4 5.9 NE. .1 1.9 3.3 .2- .o .o .o .o .' o 5.6 5.7 ENE .O 1.2 1.9 .7 .0 .O .0 .0 .o 3.9 6.0 E .o 2.3 2.7 .1 ' .o .o .0 .o .o 5.1 5.7
~
-ESEJ .o 3.5 2.9 .4' .o .o .o .o .o' 6.8 5.6 >
SE .1 2.4 4.0 1.5 .o .o .o . o. .o s.o 6.0- -
-# SSE .1 2.9 2.7 1.0 .o .o .0- .O .0 6.7 5.6 S .1 2.4 4.1 1.0 .0 .O .0 .0 .o- 7.7 6.0
. :SSW. .2 1.5 '3 . 2 1.1 .o .o .o .o- .o 6.o'- 6.2 , SW .1 1.0 2.1 .4 .o .o .o .o .o 3.5 6.0 WSW .2- 2 . 1- 1.2 .2 .o .o .o .o .o 3.8 5.2 W .0 1.1 .4 .1 .O .0 .0 .O .0 1.6 4.6 , i
- WNW .o 1.9 2.3 .4 .O .0 .o .0- .O 4.6 5.6 '
i I NW .2 2.1 1.1' .7 .O .O .o .O .O 4.1 5.3-
.NNW .2 2.2 2.2 .5 .o .0 .o .0 .o 5.1 5.4 i
} N .4 1.9 2 .1 - .6 .0 .0 .0 .o .o 5.0 5.4
- l. CALM 17.1
~
l 1 TOTAL 1.9 32.3 39.3 9.4 .o .O .0 .O .0 100.0 4.7 NUMBER OF INVALID OBSERVATIONS = 0 {- L Rev.-l 4/81 1 L l L u __. -. -; . _ . . . _ - - _ . . _ _ - ~ - . . . , . . - - . - . - . - . l
WCGS-ER (OLS ) TABLE 2.3-17 (CONTINUED) SHEET 3 OF 6 JOINT WIND SPEED, WIND DIRECTION FREQUENCY DISTRIBUTION (IN PERCENT) BY STABILITY CLASS DATA PERIOD: JANUARY 1, 19GS TO DECEMBER 31, 1964 STABILITY CLASS: PASQUILL C DATA SOURCE: CHANUTE F.S.S., KANSAS UPPER CLASS INTERVALS SECTOR OF WIND SPEED (KNOTS) MEAN R d __5.0 5 _7.1_10 . o _L22_1)lLto. 17 . 5_ 20 . Q_> 20 . o T_0T A L S P E E D NNE .o .7 1.3 2.9 .2 .2 .o .1 .o 5.4 8.3 NE .o 1.2 .6 2.6 .2 .2 .1 .o .o 4.9 8.o ENE .o .3 .6 1.7 .1 .1 .o .0 .o 2.8 8.4 E .o .8 .5 2.3 .2 .1 .o .o .o 4.0 7.9 ESE .o 1.2 1.7 3.6 .4 .2 .1 .o .o 7.3 8.1 SE .o 1.2 1.4 4.5 .5 .3 .o .o .o 8.0 8.2 SSE .o 1.2 1.6 5.9 1.5 .7 .2 .7 .2 12.1 9.9 S .o .8 1.3 5.6 1.0 1.5 .5 1.8 .7 13.1 11.7 SSW .o .4 .8 4.7 1.0 1.3 .7 1.5 .6 11.0 12.3 SW o .7 .4 2.1 .6 .6 .1 .1 .1 4.6 9.7 WSW .o 7 .6 1.5 .2 .o .o .o .o 3.1 7.5 W .o .2 .2 1.o .1 .o .o .o .o 1.6 8.5 WNW .0 .8 .5 1.4 .2 .1 .o .1 .o 3.1 8.o NW .o .9 1.1 2.1 .2 .2 .2 .1 .o 4.8 8.4 i NNW .o 1.1 1.3 3.4 .5 .4 .2 .1 .o 6.9 8.6 N .o .8 .6 2.5 .2 .4 .1 .o .o 4.7 8.7 1 CALM 2.6 l TOTAL .0 13.0 14.4 47.7 7.1 6.4 2.3 4.8 1.7 100.0 9.2 NUMBER OF IN'/ALID OBSERVATIONS = o l Rev. 1 4/81
i WCGS-ER(OLS)
![ m1 TABLE 2.3-17 (CONTINUED) SHEET 4 OF 6
' \j '
JOINT WIND . SPEED, WIND DIRECTION FREQUENCY DISTRIBUTION (IN PERCENT) BY STABILITY CLASS
-DATA PERIODS. JANUARY-1. 1955.T0 DECEMBER 31, 1964
-STABILITY CLASS: PASQUILL D DATA SOURCE: CHANUTE F.S.S., KANSAS UPPER CLASS INTERVALS SECTOR OF WIND SPEED (KNOTS) MEAN
" L. 5._._b.o_ _LA_Lo_ A_1.E. 5 1.5.. o 1.7_,_5_2_o_. o > 2 o , o T0T AL SP E E D. NNE .o .3 .4 1.6 1.3 1.3 .4 .4 .1 5.9 11.8 NE .o .3 .5 1.3 .9 .9 .2 .2 .o 4.3 11.0 ENE .o .2 .3 1.1 .6 .6 .1- .o .o 3.1 10.5 E .o .3 .4 1.1 .5 .7 .1 .1 .o 3.1 10.6 ESE .o .3 .8 ;2.0 1.0 .8 .1 .1 .o 5.2 10.4 SE' .o 4 .6 2.1 1.5 '1.2 .4 .3~ .o 6.5 11.2
, SSE .o .3 .6 2.4 2.8 3.8 1.3 1.7 .8 13.8 13.7 s-S .o .2 .3 2.2 3.4 5.0 1.9 3.9 2.1 19.1 15.4 SSW .o .2 .2 1.1 1.6 2.6 .9 1.5 .8 8.9 14.7 SW .o .2 .' 1 .5 5 .6 .2 .2 .2 2.5 13.2 WSW .o .1 .1 .3 .2 .2 .1 ,1 .1 1.3 12.6.
W .o .1 .1 .3 .2 .2 .o .1 .1 1. 2. 12.6 f WNW .o .2 .2 .4 .4 .6 .2 .5 .1 2.6 13.3 f NW .o. .2 .3 .9 .8 1.1 .5 .6 .2 4.5 13.4 l NNW .0 .3 .5 1.6 1.5 2.7 .9 1.6 .4 9.6 13.8 . N .o .3 .4 1.4 1.2 2.1 .5 1.0 .2 7. 2 ~ 13.1 CALM 1.1 TOTAL .1 3.9 5.9 20.4 18.4 24.6 7.9 12.5 5.2 100.0 13.1 j NUMBER OF INVALID OBSERVATIONS = 21 l- Rev. 1
. 4/81 ,
I
WCGS-ER(OLS) TABLE 2.3- 17 (CONTINUED) SHEET 5 OF 6 JOINT WIND SPEED, WIND DIRECTION FREQUENCY DISTRIBUTION (IN PERCENT) . BY STABILITY CLASS DATA PERIOD: JANUARY 1, 1955 TO DECEMBER 31, 1964 STABILITY CLASS: PASQUILL E DATA SOURCE: CHANUTE F.S.S., KANSAS UPPER CLASS INTERVALS SECTOR OF WIND SPEED (KNOTS) MEAN _LJ__5.d_ L.Llo.. o LP d.tho 12d 2 o . o > g.Lo_T_QTal SPF,ER NNE .o .7 1.2 2.8 .o .o .o .o .o 4.8 7.8 NE .o .6 1.0 2.2 .o .o .o .o .o 3.8 7.7 ENE .o .7 1.0 2.0 .o .o 0 .o .o 3.6 7.6 E .o .8 1.2 2.8 .o .o .o .o .o 4.8 7.7
.o ESE .o 1.0 2.5 5.4 .o .o .o .o 8.9 7.9 SE .o 1.0 2.7 7.4 .o .o .o .o .o 11.1 8.1 SSE .o .8 1.8 10.8 .o .o .o .o .o 13.4 8.6 S .o .6 1.7 12.3 .o .o .o .o .o 14.6 8.8 SSW .o .3 1.1 4.9 .o .o .o .o .o 6.2 8.5 l SW .o .3 .7 1.6 .o .o .o .o .o 2.6 8.2 WSW .o .4 .5 1.4- .o .o .o .o .o 2.3 7.6 W .o .2 .4 1.3 .o .o .o ~. o .o 1.9 7.9 WNW .o .4 .9 2.1 .o .o .o .o .o 3.5 8.0 NW .o .4 1.3 3.3 .o .o .o .o .o 5.0 8.1 NNW .o .7 1.8 5.3 .o .o .o .o .o 7.8 8.1 N .o .8 1.3 3.6 .o .o .0 .o .o 5.7 8.0 i l
CALM .o l TOTAL .o 9.7 21.1 69.2 .o .o .o .o .o 100.0 8.2 NUMBER OF INVALID OBSERVATIONS = 0 Rev. 1 4/81 Ol
y
..a c.~, v_ .
,tn,<" '. .. j . WCGS-ER(OLS)
-2.3-17 (CONTINUED) SHEET 6 OF 6
( ,/ ~
. TABLE JOINT WIND SPEED, WIND DIRECTION FREQUENCY DISTRIBUTION (IN PERCENT)
BY STABILITY CLASS DATA PERIOD: JANUARY _1, 1955 TO DECEMBER 31, 1964 S'TABILITY CLASS: PASQUILL F DATA SOURCE: CHANUTE F.S.S., KANSAS. UPPER CLASS INTERVALS OF WIND SPEED _(KNOTS) MEAN SECTOR 10 . O _1As. _LL_0_L7_,_5._lg.m0 > 2 O_m O __T,QT_A1 SP E E D _ h5._ 5_d _7.5 3.2 1.4 .O .O .O .O .O .O 4.7 4.9 NNE . 1 1 NE 3.3 1.1 .O .O .O .O .O .O 4.5 4.7
- . 1 3.1 1.0 .O .O .O .O .O .O 4.1 4.8 ENE . O
-E- .O 3.4 1.1 .O .O .O .O .O .O 4.5 4.8 4
ESE' .1 3.8 2.2 .O .O .O .O .O .O 6.1 5.0
.O .O 6.9 5.0
~
SE .1 4.4 2.4 .O .O .O .O
/~s
\- / SSE- .O 3.4 2.4 .0- .O .O .O .O .O 5.8 5.1 S .O 2.2 2.3 .O 9 .O .O .O .O 4.5 5.3 SSW .O 2.0 1.2 .O .O .O .O .O .O 3.2 5.1-2 2.2 .4 .O .O .O .O .O .O 2.8 4.5 SW _ 1 WSW .O 2.2 .8 .O .O .O .O .O .O 3.1 4.7 W .0- 2.7 .8 .O .O .O .O .O .O 3.5 4.6
; WID4 .1 3.5 1.4 .O .O .O .O .O .O 4.9 4.8
-tni .2 4.6 2.5 .O .O .0 .O .0 .O 7.3 4.8 NNW .O 4.5 2.2, .O .O .O .O .O .O 6.7 4.9 i
N .O 4.5 1.8 .O .O .O .O .O .O 6.2 4.9 CALM 21.1 7
. TOTAL 1.0 52.9 24.9 .O .O .O .O .O .O 100.0 3.9 h NUMBER OF INVALID OBEERVATIONS = 0 l
Rev. 1 ^ 4 /81
WCGS-ER(OLS) TABLE 2. 3-18 JOINT WIND FREQUENC'Y DISTRIBUTION (ANNUAL - 10 METERS) (li', rut.t"f:fdi'.f!!!*llCl:7. Cl:'.N3.'"2'J'!.fHi*l:M" ... n.na 1:. d'. )n. m" .n t" w"m"" '"... , e.e."=:. rxi tnLg n).*ini- . !.;,3:n.n .,,ua: n.",nn. m! utuJinu"- mn.r. :i x m - "*".".....,
. n)."S::
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P00R.0RIGINAL WCGS-ER(OLS) m TABLE 2.3- 19 (v / JOINT WIND FREQUENCY DISTRIBUTION (ANNUAL - 60 METERS)
, r
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\j JOINT 14IND FREQUENCY DISTRIBUTION (MONTHLY - 10 METERS)
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. 4/81
~
WCGS-ER(OLS)
~
- i TABLE 2.3-21 (continued) i i
(/ JOINT WIND FREQUENCY DISTRIBUION , ,
~
(MONTiiLY - 60 .4ETERS) Page 3 of 3
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U l Rev. 1! 4 /81 P00R ORIGINAL
WCGS-ER(OLS) TABLE 2. 3-22 i JOINT WIND Flu:QUENCY DISTRIBUTION DY STADILITY CLASS (10 METEl<S) l (ANNUAL) rad I of 8 mr rm.:"tsn .rm nw:t.- ~~"" "- ' sm .nn.:"esn'.tm sms:1." ~~'" "- m- ~ lL'er)h"if.ls r ir' - me - -
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t MDDS-3H)03S( l IVaI'3 Z E-gg
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WCGS-ER (OLS) m ( ) TABLE 2. 3- 2 2
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