ML19345B572
| ML19345B572 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 11/25/1980 |
| From: | KANSAS GAS & ELECTRIC CO. |
| To: | |
| Shared Package | |
| ML19345B571 | List: |
| References | |
| ENVR-801125, NUDOCS 8012020089 | |
| Download: ML19345B572 (325) | |
Text
{{#Wiki_filter:s 1 i O O WOLF CREEK GENERATING STATION l UNIT NO.1 ENVIRONMENTAL REPORT ) OPERATING LICENSE STAGE 1 O COPY NO. 801205008%
p_. WCGS-ER(OLS) i \x_)\ 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 Plannina 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
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[. 1.1.5 REFFRENCES 1.1-55 1.2 OTHER OBJECTIVES 1.2-1 1.3 CONSEOUENCES OF DELAY 1.3-1 1.3.1 EFFECTS OF DELAY ON RESERVE MARGINS 1.3-1 1.3.2 EFFECTS OF DELAY ON FUEL CONSUMPTION 1.3-2 1.3.3 EFFECTS OF DELAY ON OTHER APPLICANT COSTS 1.3-3 O 1.0-i
WCGS-ER (OLS ) TABLE OF CONTENTS (CONTINUED) k LIST OF TABLES Table Title 1.1-1 KG&E Load and Capability Data, 1965-1990 1.1-2 KCPL Load and Capability Data, 1965-1994 1.1-3 KFPCo Load and Capability Data, 1971-1994 1.1-4a KG&E Installed Capacity, 1974-1990 1.1-4b KG&E Actual and Proposed Capacity Changes, 1974-1990 1.1-Sa KCPL Installed Capacity, 1974-1990 1.1-5b KCPL Actual and Proposed Capacity Changes, 1974-1990 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, 1971-1978 1.1-8 SPP Energy and Peak Loads, 1978-1988 1.1-9 SPP Projected Capability, Maintenance, Exchange and Reserve, 1979-1988 1.1-10 SPP Long Range Peak Demand, Resources and Reserve, 1989-1998 1.1-11 MOKAN Pool Load and Capability Data, 1971-1988 1.1-12 KG&E System Loads, Annual System Energy and Peak Demand, 1968-199( 1.1-13 KCPL System Loads, Annual System Energy and Peak Demand, 1968-1990 1.1-14 KEPCo System Loads, Annual f ystem Energy and Peak Demand, 1971-1995 1.0-ii O l C Y
WCGS-ER(OLS)- [~' (,,)\ . TABLE OF CONTENTS ( CONTINUED )' LIST OF TABLES Table Title 1.1-15 Fuel Mix - Percentage Distributionoof Annual Net-Generation, 1970-1990
-l 1.1-16 Trends in Fuel Costs.by Fuel, in Cents per Million Btu, 1970-1990 l 1.1-17 Trends in Fuel Costs for System Operations in Cents per Million Btu,-1968-1990 1.1-18 . Sys tem Ope rations, Peak Hour Conditions, 1973-1979.
1.1-19 Number and Growth of Residential Customers, 1968-1988 1.1-20 Trends in-Use of Electricity - Res'dential Electric Feating, 1969-1979 1.1-21 Average Annual Consumption of Energy by -{ Residential Customers, 1970-1988 1.1-22 Distribution of Fnergy Consumption by Catagory, 1964-1984 1.1-23 Average Annual Costs by Consumer Category,.1971-1984 1.1-24 Economic Growth Indicators, Kansas and Missouri 1.1-25 KG&E Comparison of Forecast and Actual Peak Loads and Energy, 1972-1979 2_1-26 KCPL Comparison of Forecast and Actual Peak Loads and Energy, 1972-1978 1.1-27 Ku&E and KCPL Interchange Budget for 1983-1984 1.1-28 KG&E Monthly Loads and Ir.terchange, Firet Two Years with WCGS in Service 1.0-iii
- j WCGS-ER(OLS)
TABLE OF CONTENTS (CONTINUED) LIST OF TABLES P 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 WCGb 1.1-31 Projected Fuel Mix Peak Day Generation Percentage Distribution, 1980-1990 1.1-32 KG&E Actual and Projected Fuel Costs, 1979-1990 1.1-33 KCPL Actual and Projected Fuel Coses, 1979-1990 1.1-34 Fuel Costs as a Percentage of Total Operating Costs, 1968-1984 O 1.0-iv O
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- r'^ WCGS-ER(OLS)
) (\' TABLE OF CONTENTS (CONTINUED) LIST OF FIGURFS Pigure Title 1.1-1 KG&E Load Duration Curve, 1983 2 1.1-2 KC&E Load Duration Curve, 1984
- 1.1-3 KCPL Load Duration Curve, 1983-1984 1.1-4 KEPCo Load Duration Curve, 1983-1984
,' 1.1-5 KG&E Hourly Load Curve, Summer Peak Day 1978 ! 1.1-6 KG&E Hourly Load Curve, Winter Peak Day 1979 1 ,7 1.1-7 KG&E Hourly Load Curve, Typical Spring-Pall Day f 1.1-8 KCPL Hourly Load Curve, Summer Peak Day 1978 j
- 1.1-9 KCPL Hourly Load Curve, Winter Peak Day 1979 i
' b( j 1.1-10 KCPL Hourly Load Curve, Typical Spring-Fall Day
) 1.1-11 KCPL Econometric Model Forecast Diagram 1 i
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1.0-v
l l l WCGS-ER(OLS)
} CHAPTER 1.0 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 tw systems of the appli-cants. The plant is scheduled for sei, fee in time to meet the 1983 summer peak loads. Joint ownership of NCGS 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 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, 477.25 MW to KG&E, 477.25 N? to KCPL, and 195.5 to KEPCo. KG&E is the agent for the three utilitiee during the con-struction period and will continue in that r^1e during ope-rations. KEPCo was added as a co-owner subsequent to the submission of the ER(CPS). (,/ KG&E, of Wichita, Kansas, provides electrical service to approximately 220,000 customers in 25 counties of Southeast Kansas, including the Wichita Metropolitan Area. Wholesale service is provided to 25 communities and 8 rural electric cooperatives. The estimated population in the 8,100 square mile service area is 587,000 persons. KCPL, a Missouri corporation of Kansas City , Missouri, provides electrical service to about 339,000 customers in 94 communities of 23 west Missouri and east Kansas counties. Wholesale service is provided to 8 other communities, 3 electric cooperatives and two utilities. Its service area covers approximately 4,700 square miles with a population of about one million persons. 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 90 percent of the util-i ty 's revenues. KCPL also provides steam service to. 260 downtown buildings in Kansas City, Missouri. Its service area is contiguous to that of KG&E at KCPL's southwest boundary. h a 1.1-l'
WCGS-ER(OLS) KEPCo, of Topeka, Kansas, was organized in February, 1975 as a rural electric generation and transmission cooperative. All-requirement wholesale power agreements have been exe-cuted by 25 of its 26 members, rural electric distribution cooperatives located in the eastern two-thirds of Kansas. At this time KEPCo has neither generation nor transmission facilities, and the ownership of 17 percent of WCGS will represent KEPCo's first owned generating capacity. However, in the long term KEPCo intends to own and/or control all of the power resources required to neet the total power obliga-tion or its members and to meet the reserve requirements of any pool agreements. Investigations are continuing on plans for joint ownership of future load generating capacity and for participation through ownership or purchase in the existing generation capacity of major Kansas utilities. KEPCo proposes to transmit power purchased from major util-ities over the transmission lines of other utilities to interconnections with member cooperatives which will distri-bute power ove r their individually owned distribution net-works. Arrangements are being made for coordination, trans-mission and delivery of 90 MW of power purchased from the Southwestern Power Administrati.on (SPA), commenc#.ng in the Spring of 1980. In the long .erm 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 two-thirds of Kansas and includes rural commun-ities in areas that are also served by KG&E and other major utilities. KEPCo's membe rs provide electric service to an estimated population of about 355,000 in individual service areas that are predominantly rural. To meet the past and projected demand for peak power and for energy within their service areas, the three utilities have planned and implemented programs of additions to their ian-erating capacity as follows: , i l NET CAPACITY INCREASES Period KG&E KCPL KEPCo MW Percent MW Percent MW Percent 1969-1979 732 62.6 866 51.1 0 0 1979-1989 847 45.0 1186 45.5 196 *
- Represents all of KEPCo's owned capacity.
1.1-2
WCGS-ER(OLS) These additions' to capacity, shown in Tables 1.1-4a and
') '1.1-5a ~ for KG&E and KCPL, have been and will be _ made to e meet past and projected growth in peak demand and annual energy requirements as' follows:
INCREASESINPEAQEMANDANDENERGY REQUIREMENTS , 1969-1989, IN PERCENT Peak Demand Energy Requirements Period KG&E KCPL KEPCo KG&E KCPL KEPCo 1969-1979 55.3% 47.8% (b) 71.7% 57.2% (b) I 1979-1989 40.3 42.4 103.6% 29.6 48.0 102.5% I"I Based on " normalized" loads for KG&E and KCPL in 1979. (b) Not available. i~
" Normalized" loads were used for 1979 in order t.o give a more realistic impression of the changes that have occurred and are projected to occur. Relatively mild weather was 1
experienced in 1979, particularly with respect to the summer [' peak. As indicated above, the changes in peak demand and ( energy requirements follow closely the changes in net capa-
! city, 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 i
provide details on past and projected loads. Reserve mrugins both with and without WCGS are shown below for the early fears of WCGS operation. RESERVE MARGINS IN PERCENT ' f With WCGS Without WCGS j Year KG&E KCPL KG&E KCPL i I 1983 44.9 36.4 18.3 16.5 1984 38.3 31.6 12.9 12.4 . 1985 40;0 27.1 15.5 8.5
- 1986 -35.8 22.6 12.1 4.8 1987 -31.6 18.4 8.6 1.1'
- 1988 28.5 14.3 6.0 - 2.4 1989 25.5 25.7 3.6 9.6
) 1990- 22.4 20.0 1.0 4.5 l l. l
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;. y 1.1-3
WCGS-ER(OLS) Tha 477 MW increment represented by its share of WCGS capa-ci:y is a large addition to the capacity of each utility. Bh .t res of WCGS capacity in 1983 will represent 18.4 percent at KG&E's capacity, 14.6 percent of KCPL's capacity and 100 percent of KEPCo's owned capacity. Because it is a major oddition for each utility, the reserve margins as shown above will be adequate for most of the period shown, with WCGS in operation. Without WCGS, however, KG&E's margin would fa l l below the required 15 percent in 1984 and after 1985, and KCPL's margin would be below its internal planning requirement of 20% in 1983 and thereafter. 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: FUFL MIX - PERCENTAGE DISTRIBUTION OF ANNUAL NET GENERATION KG&E KCPL 1970 1980 1990 1970 1980 1990 Coal - 53.2 54.2 69.2 94.4 71.6 Oil 0.5 3.8 11.5 0.1 3.7 4.5 Gas 99.5 43.0 6.6 30.7 1.9 0.8 Nuclear - - 27.7 - - 23.1 Total 100.0 100.0 100.0 100.0 100.0 100.0 KG&E and KCPL will continue to reduce the use of natural gas and minimize the use of oil in compliance with the 1978 Puels Use Act ana 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 region by reducing their dependence on fossil fuels for gen-eration. The value of such diversification is demonstrated by the tabulation below, which shows the planned fuel mix in percentage of generation in 1983, both with and without WCGS. O 1.1-4
. . - =- - - _ _ .-
WCGS-ER(OLS) 1983 FUEL MIX, IN PERCENT With WCGS Without WCGS , Fuel KG&E KCPL KG&E KCPL 4 Coal 55.6%- 67.6% 55.6% 92.6% Oil 0.5 2.9 11.2 5.5 Gas 22.6 1.1 33.1 1.9
-Nuclear 21.3 28.4 0 0 D
'100% 100% 100% 100%
NOTE: May not add due to rounding The costs of fossil fuels are increasing rapidly, as shown , in Table 1.1-16. In the period 1970 to 1985 the costs for individual fuels are expected to have increased by factors ranging from 5 to 17. In addition, the availability of fossil fuels is questionable, although natural gas has been more abundant than was thought possible a few yea rs ago. Even so, the use of natural gas as boiler fuel must be dis-continued by.1990 in accorda:tce with the 1978 Fuels Use Act. O However, if the reduction of oil consumption continues to be stressed by the Administration, natural gas may be made available to utilities on an opportunity basis for a longer period of time. In late 1979 suppliers of gas to Kansas utilities would not make firm commitments on supply quan-tities and prices. The associations Li 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-Missouri-Kansas-Oklahoma X Interconnection Agreement 1.1-5
WCGS-ER(OLS) As indicated above, both KG&E and KCPL are members 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 members of MOKAN, an association of nine Kansas and west Missouri utilities. KEPCo intends to become a member of SPP and MOKAN once it has received its appro-priate authorizations from the Rural Electrification Admin-istration (REA) and the Kansas Corporation Commission (KCC). Details on pools and associations are provided in Table 1.1-6, and pool planning criteria are discussed in Section 1.1.2.3. Each of the Applicants is engaged in a major effort to in-crease energy conservation through programs to reduce waste, to improve e nerg y conversion processes and to reduce the growth rate in demand for peak power and total energy. None of the Applicants is conducting advertising programs that will stimulate the growth in denand. In fact, each is in-volved in public relations campaigns to encourage wise use of energy. Both KG&E and KCPL have had energy conservation advertising programs since 1972. All media have been used - enclosures to billing statements, spot radio and television announcements, newspaper and magazine adve rtisement s in their service areas, distribution of booklets and pamphlets, group meetings and advisory services and seminars on con-servation. Consumer consultants have advised hundreds of audiences on the efficient use of appliances and equipment, and energy management seminars have been held for architects and builders and for commercial and industrial customers. Both utilities encourage the use of energy efficient appli-ances and equipment , and KG&E offers a computer service for analyzing individual customers' needs and potential savings from insulation, storm windows, improved equipment, and other conservation measures. Both utilities schedule one-on-one meetings with major customers to review conservation methods. KCPL has been active in residential, commercial and indus-trial ene rgy conservation audits. The billing system has l been used at least three times to advise residential custo-mers on insulation audits that can be provided by an outside contractor for Energy Ef ficiency Systems. At least 20,000 audits have been conducted, and erorgy conservation measures have been introduced directly into 2500 homes. Other in-sta11ations have been made by homeowners and by contractors. Building energy analyses are prov.ded for the design of new residential, commercial and industrial construction. A program has been developed for all customers, emphasizing energy management techniques to control both usage and cost. The major objectives are to reduce the growth rate in peak O 1.1-6 j 1 l
WCGS-ER(OLS) o demand and to stimulate the use of of f-peak hours so as to divert energy consumption from peak load hours. Included in (V ) this program are advertising and group presentatic's that stress the use of energy efficient appliances and equa' ment, proper insulation and conservation practices. Technica' in-formation is made available to all customers, and e 'ergy management training seminars are conducted for industria) and commercial cJstomers. Homo service programs include material on energf cNse rva tion for s tudents and teacher'.. During 1979 and 1980 RcPL is testing the effectiveness of peak time interruption of air conditioning and of voluntary reduction of consumption during " peak alerts". A company group is working with builders to analyze the ef fectiveness of energy efficient designs and building materials. KCPL has also participated in Edison Electric Ins titute's
- National Energy Watch and has developed the "150 Plus Energy Conserving Program". Energy conserving home certificates are awarded to homes that meet specified standtrds. Posses-sion of such a certificate by a builder or eaner is a posi-
. tive feature in sales appeal. Studies are being conducted l by KCPL on home conservation improvements such as ceiling i insulation. 1 KG&E's program is much the same as that of KCPL in terms of public contact to stimulate an awareness of the need for a conserva tion. Energy Efficiency Awards are given to dwell-(v) ing units and commercial structures that meet high energy conse rva tion standards. The use of electric heating is discouraged in homes that are poorly insulated. KG&E has l adopted an action program to reduce energy consumption at all company facilities, and all utilities are complying with the national 65* winter - 78* summer mandate. Power is being transmitted at higher voltages in new lines, and worn l out conductors are replaced by larger conductars to reduce l line losses. The moF efficient generating units are used i for base load. l l Experiments are being conducted by KG&E on off-peak pumping l for irrigation, and both KG&E and KCPL are experimenting r with ice storage air conditioning systems in which off-peak ! generation at lower rates will be used to produce ice for use in daily air conditioning. Kansas utilities have a ! joint research and development program to analyze the j effects of voltage reduction on energy saving. j Industrial rates are designed to encourage customers to l schedule production so that the greatest load requirements l I come during off-peak months and daily off-peak perods. ! All utilities are involved in load management plans and research. The four basic areas of load management are: 1.1-7 l
WCGS-ER(OLS)
- 1. Direct control;
- 2. Passive control;
- 3. Price signals; and,
- 4. Customer education.
Each of the Applicants has initiated studies to determine dether direct control of residential central air condi-tioning will provide positive changes in the load curves and be acceptable to the customer. Radio cor. trolled eouipment is being used in the initial testc, and the results, ex-pected in 1980 or 1981, will be used to determine the justi-fication for larger scale projects. Such tests may also be conducted on other equipment such as electric heating. KEPCo's member systems are conducting load control research on irrigation under a KCC program. Passive load control involves load limiting devices owned by the customer and installed on his equipment. The results of a May, 1978 survey of industry by KCPL revealed that 51 percent of the industrial and commercial customers surveyed had installed or were considering passive control devices. It appears that customers 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 largest electric load customer. The contract provides for reduction of up to 100 MW of load, as requested by KCPL. Only one KG&E customer has taken advantage of an experi-mental off-peak rate, a customer whose major load is during the night. The area of customer education on conservation is the one in which most effort is concentrated. One promising program instituted by KCPL is " Peak Watch" . Customers of KCPL and the M'5souri Public Service Company are urged to reduce their loads on days when both utilities predict a new peak. Most of the member 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 affect peak loads. Messages advise on the rising demand for electricity in peak periods and recom-0 1.1-8
WCGF-ER(OLS) mend actions for holding the peak down. The individual co-( ]) i' operatives follow programs similar to those of KGK.E and KCPL to educate their customers on energy efficient appliances and equipment and on the need and means for reducing demand and consumption. In addition, low-interest loans have been made available to some rural electric consumers for instal-12.cion 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 price, fuel competition, changing demands for housing, and the use of more energy efficient equipment. However, all utilities believe that their load management and conserva-tion programs have been ef fective in reducing the rates of growth. Minor inconsistencies will exist be tween data previously reported *e 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, update load forecasts, and report load data for various reporting [N
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periods; 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 five out of the last eight years, the two com-panies had their peak-loads on the same day or within one to eight days of each other, commonly in July and August. For each utility the peak comes in the af ternoon when residen-tial air conditioning is turned on, regardless of cost. KEPCo, too, expe riences its peak loads in July and August. In the last ten years five peak loads have come in July and four in August. Most utilities in MOKAN and SPP are experiencing growth in demand, which reduces the opportunity for large tunsfers of energy between utilities. Because of this growth and the f lack of diversity during the summer months the option is (mv) precluded of purchasing large blocks of power. 1.1-9
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 grew by 144 percent for an average annual increase of 7.7 percent. In the same period the accredited capacity increased 169 percent for an average annual increase of 8.6 percent. (Comparable data are not available for other periods because of membership changes.) For the follcwing period, from 1978 to 1988, the summer peak load is projected to increase 79 percent for an average annual growth rate of 6 percent. Annual energy is projected to grow 82 percent at an average annual rate of 6.2 percent. In the long term frvm 1989 to 1998 a 60 percent increase in peak load is projected fo r SPP at a lower average annual growth rate of 5.4 percent. Reserve margins for SPP are projected to decline from 20 to 25 percent in the early 1980's to 17 to 18 percent in the late 1990's. In MOKAN the system peak load increased 44.9 percent from 1971 to 1979 for an average annual growth of 4.7 percent. Accredited capaci ty grew 55.7 percent for an average annual growth rate of 5.7 percent. For the period 1979 to 1988 the system peak load is projected to grow at a rate of 5.4 per-cent and accredited capaci ty at a rate of 4.3 percent. It should be noted that the annual peak in 1979 was 7.8 percent lower than had been projected, lower even than the 1978 peak by 77 MW, as a result of mild summer weather. The installed capacity balance for MOKAM, shown in Table 1.1-11 is projected to be negative in 1984 if WCGS is not in operation. SPP projects installed capaci ty margins of 15 percent or more for the period 1983-1988 (Table 1.1-9). However, because of forced outages, the actual summer ma mins at the times of peak loads, shown in Table 1.1-7b have frequently been below the required 15 percent. In 5 out of the last 8 years 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 this 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 fo r the discussion which follows, the annual peak loads and energy requirements , ar2 shown below for five year intervals over the period 1968 l to 1988, i l O' 1.1-10
. m _ .
i 1 WCGS-ER(OLS) 4
- PEAK LOAD AND ANNUAL ENEPGY 1
Peak Load in MW Annual Energy in GWH Year KG&E KCPL KFPCo KG&E KCPL KEPCo 4146 Ss52
- 1968 923 1276
- 1973 1202 1257 259 5516 7598 1160 1978 1533 2097 377- 7184 9011 1640 1983 1790 2398 583 8068 10832 2626 1988 2152 '2862 792 9613 13179 3520
- Not available i
3 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 i O 1968-1973 1973-1978 1968-1978 30.2% 27.5 66.1 5.4% 5.0 5.2 33.0% 30.2 73.3 5.9% 5.4 5.7 1978-1983 16.8 3.1 12.3 2.3 1983-1988 18.7 3.5 19.1 3.6 1978-1988 38.6 3.3 33.8 3.0 Growth in both peak demand and annual energy was relatively , high in the l' ate 1960's and early 1970's but fell off some-what in the mid 70's to an average rate of growth which is ; projected by KG&E to continue over the long term. KEPCo is i to become its own power supplier in 1980, and KG&E will no > longer report KEPCo's ceak load as a part of the KG&E peak load. This reporting change tends to distort future growth rates slightly. . In' Figures 1.1 and 1.1-2 the expected load duration curves are given for KG&E for the first two yearn of operation with WCGS. In Figures 1.1-5, 1.1-6 and l'.1-7 hourly load curves are presented for summer and winter peak days and for a typical spring / fall i ty. The follo' wing tabulation summarizes recent and anticipated growth trends for KCPL: i 1.1-11
WCGS-ER(OLS) KCPL GROWTH IN PEAK DEMAND AND ENERGY Peak Demand Energy Requirements Period Percentage Avg. Annual Percentage Avg. Annual Increase Grewth Increase Growth 1968-1973 37.7% 6.6% 36.9% 6.5% 1973-1978 19.4 3.6 18.6 3.5 1968-1978 64.3 5.1 62.3 5.0 1978-1983 14.4 2.7 20.2 3.7 1983-1988 19.3 3.6 21.7 4.0 1978-1988 36.5 3.2 46.3 3.9 As with KG&E, KCPL has experienced a decline in growth for both peak demand and annual ene rgy and projects for the future growth rates similar to those recently experienced. As shown in Table 1.1-13, annual energy requirements dropped significantly in 1974 due to the recession, which af fected the Kansas City area far more than the Wichita area and the agricultural areas served by KG&E. KCPL's expected load duration curve for 1983 and 1984 opera-tion is presented in Figure 1.1-3. Hourly load curves are presented for sunimer and winter peak days 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: KEPCO GROWTH IN PEAK DEMAND AND ENERGY Peak Demand Energy Requirements Period Percentage Avg. Annual Percentage Avg. Annual Increase Growth Increase Growth 1973-1978 45.3% 7.8% 44.0% 7.6% 1978-1983 $4.9 9.2 57.2 9.5 1983-1988 35.7 6.3 34.0 6.0 1978-1988 110.2 7.7 110.7 7.7 With the exception of 1976 and 1977 for annual energy and 1977 for surrmer peak, there has been a continning high rate of growth. Based on studies made for KEPCo, (Lee, Jan., j 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 l gains as well as increased per capita use of energy. l 1.1-12
.. . ._ .. .~ . . _ . _ . _
WCGS-ER(OLS) i n KEPCo's expected . load . duration curves for 1983 and 1984 is
;/ presented.in Figure 1.1-4.
4 C- .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 capacities as the needs develop. Historical and planned 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 1.1-5b)- 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 1968 1153 1187 1968-78 777 1373 67.4~115.7 1978 1930 -2560 1978-88 800 711 41.5 27.7 1988 2730 3271 b
- At time of Summer Peak V
~
- ! Between 1968 and 1978 KG&E's installed capacity increased by 777 MW, an increase of 67.4 percent, or. an average annual
- increase of 5.3 percent. In the same decade, KC PL~ 's capa-city increased by 1373 MW, an increase of 115.7 percent,_or
. an average' annual increase of ' 8.0 . percent. In the_ ten year 1
period from 1978 - to 1988 KG&E's capacity is scheduled to i increase by 800 MW .or -41.5 percent, for .an average annual increase of 3.5 percent. In the same period KCPL's capacity is scheduled to increase 711 MW .or 27.7 pe rce nt , - for an average-annual increase of 2.5 percent. KEPCo will-not have any owned capacity until WCGS is on line i in April 1983, when it will have 195.5 MW of generating
; capacity.
Accredited summer capacity changes for the applicants by primary fuel-from 1978 to 1988 were and are scheduled to be: { NET CAPACITY CHANGES, 1978-10P8 IN MW ! Gas Oil Coal Nuclear Total b +323 +477 +800 Q KG&E KCPL -80 O O 0 +314 +477 +711 KEPCo 0 0 0 +196 +196 1.1-13
WCGS-ER(OLS) As adjusted for weather anomalies, KG&E and KCPL anticipate slower growth rates in peak load for the decade 1978-88 than were experienced in the period 1968-78. The reasons for a slower rate of growth are primarily 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 reportint of the peak load for KEPCo, discussed above. KEPCo expects to add more customers as the move continues of populatior. from urban to the subur-ban and rural areas which its members serve. The projected growth rates for peak load for KG&E and KCPL are lower than those of SPP and NERC, while those for KEPCo are higher. A comparison follows: AVERAGE ANNUAL GROWTH RATES FOR PEAK LOAD Period KG&E KCPL KEPCo SPP NERC (US) 1978-83 3.1% 2.7% 9.2% 6.0% 5.3% 1983-88 3.5 3.6 6.3 5.9 4.5 1978-88 3.3 3.2 7.7 6.0 4.9 NOTE: These intervals were selected because comparable date are not avm ilable for others. The growth in annual energy follows a pattern similar to that for peak load for all of the Applicants. Each projects a continaing 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 of historical use; and analyses of economic condi-tions, populaticn growth, household formation, household income, industrial development, price of electricity, price and availability of competitive energy sources, and other considerations fo r each specific market category. A dis-aggregated approach to m trkets is taken, with the applica-tions of experienced judgement. The foreca s t for energy sales is prepared separately for five categories - resi-dential, commercial, industrial, streat and highway light-ing, and sales for resale. Basic assumptians are made that apply to all categories, and specific assumptions are made 1.1-14
~ . _
WCGS-ER(OLS'
- that are applicable . to indiv. .al ategories. The general assumptions relate largely to population, economic condi-v 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-l tistical data collected on population and household sizes and income, saturation trends for major appliances and
- electric heating, including heat pumps,. energy substitution, l improved appliance efficiencies, improved thermal condi-l tions, decreasing size of dwellings and increasing number of
- apartments.
Customer- growth is estimated on the basis of the trends in l population growth and the number of persons per household. As shown in Table 1.1-19, the average growth rate for residential customers has been 1.9 percent per year, substantially higher than the growth rate of 0.9 percent for population in the Wichita Metropolitan Area. The greater growth in the number of residential customers is attributed in part.to high employment but largely to a decline in the number of persons per household, which leads to increased household formation. O'/ 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 nearly 13 percent of the total customers at the l end of 1979, with steady growth in numbers over the past ten years. This important class of user consumes more than twice as much electric energy per year as is consumed in , homes without electric heating. Because of future uncer-l tainties on the availability of and the price competition , with natural gas, it is necessary to observe this customer i class very closely. It appears that penetration of the
! residential home heating ma rket is declining because of l competition from gas, which continues to be available at
[ relatively low cost, compared to other fuels. l Average annual consumption of energy by all residential cus tomers 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. Al-though consumption continues to grow, the residential share of the total energy market is projected to decline slightly. The State of Kansas has mandated that new and replacement air conditioning equipment must carry a high energy effi- I ciency rating (EER). In addition, electric heating may not T be introduced into new homes that ' do not meet prescribed [Q insulation standards. 1.1-15 l
WCGS-ER(OLS) Builders and banks are useful sources for informa6 ion on the number of housing units planned and being developed. Con-sideration of these trends along with the factors discussed above permits the development of estimates on residential energy consumption. 1.1.1.2.1.2 Industrial Forecast Major factors considered in the industrial category are production levels, the price of electricity and the prices and ava ilability of alternative energies. KG&E's major customers, accounting for 78 percent of annua' industrial ene rgy consumption, are surveyed periodically, and projec-tions of peak load and energy requirements over the next ten year period are obtained from each customer. Mest of the industrial customers are able to provide fairly accurate estimates of their anticipated load and anergy requirements over a five year period. It is recognized that the state of the economy and external events may affect 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 with regional population growth. The energy consump-tion of others, involved in petroleum refining, petroleum and gas production, pe trochemical prod uct ion , pipeline transportation and coal mining depends upon pricing and availability of energy resources, demand for products and recovery techniques. Thera could be major changes in the requirements of these in hstries for both capacity and energy, depending upon nation.'1 ene rgy pclicies and inter-national petroleun availability. Two problems involved in forecasting ene rgy demands are particularly related to industry. For many industry groups an economic recession may mean an abrupt cut-back by a major industrial facility. This may have a significant effect 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 significa.7t swings in load and energy consumption. In planning ma3er ncw plants or e).pansions, industry personnel advise a utility of their requirements several years in advance of start-uo. Depending upon the size of the plant, this may or nay not affect a ut 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 can clearly play a role in load planning is indicated in Table 1.1-24 which shows the changes that have occurred in Kansas and Missouri economic conditions in recent years. O 1.1-16
WCGS-ER(OLS)
,, The local aircraft industry is in a boom stage at this time
} but could be adversely affected if there were a deep and
[V 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 one user has adopted it, a plant that conducts most of its energy con-suming operations during these hours. New or expanded industrial operations may be 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 to provide 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 consideration of population and income growth, past trends and tN extent [mV) 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 deteruine what changes in use are likely to occur and if and when energy (f'lel) switching will take place. The greater availability of natural gas has deterred some switching to electric space heating, but any future reductions in natural gas availability will affect commercial users before residential users. Builders and banks are visited regularly to determine what construction is taking place, what is planned and what the electrical r2quirements will be. Attention is also given to the conservation ef forts 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)
,q k )
v 1.1-17
WCGS-ER(OLS) 1.1.1.2.1.4 Projection of Other Uses "Other uses" than industrial., residential and commercial accounts fo.': less than 18 percent of total consumption. The category "other uses", consists of street and highway light-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 req uirements 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 are obtained and consolidated for projection purposes. Changes in supply or in the economics of generation are also taken into account for the various units. For example, the rural electric cooperatives' requirements from KG&E will be reduced by outside supply and through ownership by KFPCo of a 17 per-cent share of WCGS. It is anticipated that all of the requircments of the distribution municipals served at whole-sale by KG&E will be met. The generating municipals are ex-pected to expand their purchases because in most cases their plants burn gas and oil which will become increasingly costly and may be unavailable. During peak periods, however, the ger. >ing 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 forecast. This procedure is based upon severcl years of observations which have shown that the daily peak loads in April arc 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 requirements. Using the April base, a ratio is established as a measurement of the weather-sensitive portion of KG&E's O 1.1-18
h WCGS-ER(OLS) G loads. Conservation . is considered in that the April base load is below the long term trend by an amount that is (V) 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 information, is added to obtain a total system peak demand. It has been recognized that the difference between a hot ara a cool summer can mean a variation of about 5 percent
'.n-the annual system peak.
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 'lodel KG&E has not believed that an econometric model would pro-vide sufficiently 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 a model s to support the existing methodology. Q 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 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 are population, real income levels, the level of industrial production activity and .the real prices of electricity, natural gas and other fuels. Other variables used are the number of residential customers, air condition-ing saturation and EERs, and weather related variables. 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 f,m the model that review, refinement and updating will.be re-quired to take into consideration events, developments and (v) policies that cannot now be accurately measured in terms of effect upon demand for electricity. Among these are: 1.1-19
WCGS-ER(OLS) (1) The uncertainty of the national and inter-national situation with respect to the supply and price of oil; (2) The potential for electro-mechanical control of customer peak use of electric equipment as a means for load management; and, (3) The effect of the Presidential order on thermostat settings for which insufficient data now exist. 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 1979-1990 will be a 3.6 percent compound growth in net system peak and a 4.0 percent com-pocnd growth in energy sales. Projected peak loads and annual energy are given in Table 1.1-13. However, in place of the actual 1979 peak summer load of 1964 MW, the figure of 2082 TAW is used in making the load projections as a " normalized load," adjusted for the mild summer. The projections also take into account the provision for an up-to-100 MW curtailment of load for Armco. The major assumptions used in simulating the econometric model are as follows:
- 1. The real price of electricity is assumed to increase at 0% annually for the demand fore-cast and decline at 1% annually for the energy scenario. The rationale behind the dichotomy in energy and demand price growth is based on the current rate making philo-sophies which are shifting more of the cost of electricity into the on-peak periods. The increase in the real price of energy is ex-pected to be less than the general rate of inflation because demand conserva t-ion will result in an improved load factor causing a downward pressure on the per unit cost of energy.
O l 1.1-20 l
WCGS-ER(OLS)
- 2. According to the Natural Gas Policy Act of
/7 1978 (H.R. 5289, P.L. 95-621), a portion of
("') 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 Fesearch Institute, it is projected that the "most likely" scenario for real natural gas price increases will be is annually for I r79-1985, 7.5% from 1985-1990, and 1.5% thereafter.
- 3. Total real income, real income per 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 de rived 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 7s growth rate of .45% in the Missouri portion
( ') 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 in Jackson County through 1990. A discussion follows of the additional factors that were considered in developing the econometric model i l The KCPL service area encompasses portions of both Missouri l and Kansas, but there are extreme differences in the social, population and economic characteristics of the two states. i , The Missouri portion of the service area can best be viewed l l 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 ! has experienced a net out-migration through population shift to the suburbs. The reduction in population levels has caused a corresponding loss of commercial customers in the central city area. To complicate matters further, the majority of the high growth areas on the Missouri side of the Kansas City SMSA are within the service areas of neigh-boring utilities. h v 1.1-21
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
" 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 conctruction 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. In contrast to Missouri, Kansas industrial development tends to be in the area of non-dt.rable production.
Because of these structural and economic differences between the two states, accurate modeling and forecast results re-guired 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 levels of population growth and economic development now being experienced and expected to continue ic Kansas. For example, in Johnson County, strong populatio. growth is projected (1.7%) throughout the fore-cast period by Johnson County Community College. Household size in all portions of the SMSA is projected to continue its decline of recent years. Household size in Jackson and Clay Counties is projected to decrease from approximately 2.6 Persons / Household in 1978 to 2.2 Persons / Household in 2010. Johnson County household size is pro-jected to decrease from 3.0 to 2.4 Persons / Household over the same period. Decreasing household size implies a great-er number of residential customers 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 variables. The growth range produced for the energy forecast is from 1.6% to 4.5% and the growth range for the demand forecast is from 1.7% to 5.5%. The table below summarizes projected energy growth rates by state, by sector, and in total over the period from 1979 to 2010. a o O 1.1-22
-- . __ .. . . , _ . . . ~. - - - .- - . _ . _ . _ _ _
4 4
'WCGS-ER(OLS)
.-PROJECTED ENERGY. GROWTH RATES BY STATE AND SECTOR r -w 1979 -'2010 i -Missouri ' Kansas Total KCPL j Residential 4.0% 4.4% 4.1%
Commercial 2.41 5.6 3.5 Indust - ial -2.5 6.5 3.1 -
- i. -Other 3.1 4.5 3.4 Average 2.-9% 5.2% 3.6%
4 The ' percentage breakdown of total.KCPL Kwh sales among- the i } various sales classifications for the past five yea rs is shown below. KCPL KWH SALES Industrial 27% Commercial 39 i Residential. 29 r other 5 Total 100% v Customers in each of these sectors use electricity for t different reasons. Industrial-customers use electricity in the manufacturing process for such things as machinery drive, _ process heating, furnaces and environmental equipment-spplications. 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., supermarkets, offices, schools, gas sta-i
~ tions, cable-TV amplif ;*.e rs , traffic signals). As a result, there are very diverst usage patterns which are different
; from those of other. sales classifications.
The - . residential sector, - though, is relatively homoc, neous, a with ' customers using electricity for the same purpose _s -- i lighting, cooking, heating, cooling,. and operating various i appliances. To the extent differences in usage levels among j households exist, they are not so extreme L as- in other ; i classes and can; be accounted for by proper model specifica-tion. i i i.
- 1.1-23
- - , _ . _ - _ , _ . . _ _ . - - , _ _ _ . ~ - . . _ . . _ _ . _ - , . _ - _ . _ _ _ _ _ . _ - - - -
WCGS-ER(OLS) Because of the differing usage patterns, each sales classi-fication has been modeled separately in order to isolate those factors that exert a level of influence on sales in one sector and a different level or no influence in other sectors. 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 off-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 o'ses from 1967-1978 were 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 Xansas City, Missouri, supplied local gas price information.
- 4. Historical and projected population estimates were provided by the U.S. Census Bureau, the Unive rsity 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 adjustments or fuel surcharge s and were calculated at fixed demand and energy levels.
1.1-24
WCGS-ER(OLS)
- 8. The (q) Wharton ciates was Econometric Forecasting Asso-the source of projections of L' national economic variables that are used as driving variables in the majority of the service area models. The March 1979 Wharton Model was usad as a source for Federal Reserve Board (FRB) production indices and income per capita projections. The FRB Production Indt .- is projected to increase at 3.3% through 19o3. Real per capita income is projected to 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 Company, and Data Resources, Inc., and assume deregulation by 1985, pursuant to the National E nergy Act. Real gas prices are projected to increase at a long-term rate of 3.1% compounded annually.
- 10. All simulations are weather normalized.
Weather normalized energy sales estimates were obtained by using long-run (41-year) averages for cooling and heating degree days in model simulations. The average cooling /N degree hours for the peak day and the pre-('~' ) vious three days used in the demand model were averaged over the historical data-base period to establish a normal level. Statistical 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 variable in question (e.g., KWH, KW, customers). 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 coefficient was strongly confirmed by theory, but the associated significance level of the coefficient was questionable, the independent variable was kept in the model.
j i l 8% l l 1.1-25
WCGS-ER(GLS)
- 2. A secondary ch eck on independent variables was undertaken to ens ne that the associated coefficients were of a proper magnitude (i.e.,
that observed by other researchers).
- 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 Industrici Forecast In order to demonstrate the principles of the econometric mode l , the methodology for the industrial category 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 customer, Armco Steel, accounts for more thar. 40 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 pdce 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 thinos 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 i electricity is price sensitive both to electric prices and i the price of energy alternatives. This price elasticity l effect will manifest itself in terms of either conservation or substitution effects and is measured in terms of its own elasticity, cross elasticity, or combined elasticity. Implicit within the industrial model described below are certain technological changes contained in the historic data and, conseguently, certain technological changes are im-plicitly incorporated within the forecast itself. The model derived for the Missouri Industrial Sales classi-fication is: O 1.1-26
WCGS-ER(OLS) .( p i
't.j DEPENDENT VARIABLE: LMIKWH Right Hand Estimated Standard "T" Variable Coefficient _Er or Statistic C 20.019 .952 21.0 LSFRB .554 .093 6.0 PZ -
.215 .050 - 4.3 SEAS .069 .009 7.6 DDCUS .034 .014 2.5 PPZ -
.006 .001 - 4.2 2
R = .963 R = .948 DW = 2.18 LMIKWH = Log (Missouri Industrial Sales Exludir~ Armco)* LSFRB = Log (FPB Production Index) PZ = Log (Real Price of Electricity / Peal Price of Gas Fuels) SEAS = Seasonal Production Variable DDCUS = Dummy to Account for Customer Peclassification p) t,
'd in 1970 PPZ = PZ Subsequent to 1973 Oil Embargo, O Otherwise (Test for changing prica elasticity)
All Log values referenced in this documentation are natural logs The variable PZ is the ratio of electric price to gas price and as such represents a combined price elasticity for both gas and electricity. Armec Steel is involved in the production of wire, wire rope, steel products and ingots. Future yearly estimates of electric usages to 1983 were obtained from Armco and reflect greater intensity of future use. Alternative modeling efforts were undertt..en to analyze the relation of Armco usage to external production indices. These models showed that there has been a historical relationship between the FRB durable index and Armco usage, but because of the nature of the large discrete Armco .'. o a d additions, the models were judged to have relatively low explanatory power. After analyzing a detailed survey guestionnaire answered by Armco, the forecast supplied by Armco, and ; applying judgment it was concluded that subscouent to 1983 ! Armco usage would increase by 2% per year. ' A f v
)
l 1.1-27 l
WCGS-EP(OLS) The independent variable assumptions described above were 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 approxiinately 34 large in-dustrial customers. Analysis of the survey indicates that a significant amount of the growth in the near foture as in the recent past, will come in the form c' environmental protection devices. To investigate further the other ef-fects environmental cons trair ts may have on industrial growtn, officials were interviewed in the Environmental Protection Agency (EPA) and the Mid-American Regional Council (MARC). The Kansas City area is presently under a new industrial construction moratorium ordered by the EPA. However, conditional approval of a plan submitted by Missouri is expected by January 1, 1980, and conditional approval for the Kansas plan is expected sometime in 198C. Conditional approval of each state's plan will allow the resumption of industrial construction activity. All indus-trial permits 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 conditional appro-val of each state's plan is given as expected. The MARC did not feel that meeting these standards would present much of a problem for industrial growth in this area 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. Within the next year, MARC will have completed a study attempting to quantify the effects on industrial growth of complying with Federal Clean Air Standards. When this is done, their findings will be incorporated in KCPL's fore-cast. 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 l and petroleum products. Anc ther important point developed by the survey is that many firms have implemented an energy conservation program. There remains potential 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. O 1.1-28
WCGS-ER(OLS). q A description of the methodology used in developing the Kansas industrial forecast is also included below. (U 3 The majority ' of the assumptions used in modeling the Fansas 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. Indus trial ' KWH sales in Kansas have accounted for approxi-mately 9.0% of total Kansas sales in recent years and have shown dramatic growth over the historical period analyzed. The industrial base was so small that the addition of new industrial customers resulted in extremely high percentage growth rates. Efforts by governmental and private sectors in Kansas to promote industrial- development are described below:
- 1) T? Kansas Pight-to-Work law guarantees all wo;kers the freedom to choose a union or non-urson shop. Only 15% of the non-agricultural labor force is union affiliated.
- 2) Tax-Exempt Industrial Revenue Bonds are icsued by municipalities for the purpose of purchasing land, constructing buildings and p)
(V equipment for lease and eventual sale. of this method of financing are exempt from Users ad valorem taxes for a period of ten years. The t of the building and all permanent fixtus 3 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-nits a credit against state income tax for ten years, based upon the number of jobs created and the amount of investment up to a maximum reduction of 50%.
- 4) The Kansas Freeport Law exempts from taxation
; all personal prope r ty , moving through the state or consigned to a warebouse from a point outside the state, which is in transit to a final destination outside Kansas. Goods manu-factured in-state, stored in a bonded ware-house are clso tax exempt if over 35% of the precedina year's shipments went out of stete.
O , 1.1-29
FCGS-FR(OLS)
- 5) Realtors 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 12% of Kansas industrial 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 #1 generating unit. For this reason, P&M electrical usage was projected independently of other Kansas industrial KWH sales. The model derived for the Kansas Industrial Sales (excluding the P&M Mining) classification is: DEPENDFNT VARIABLE: LKIKWH Right Hand Fstimated Standard "T" Variable Coefficient Frror Statistic C 17.82 1.983 9.0 LSFRB 1.02 .295 3.5 LRKP -1.13 .244 -4.6 LKGAS .55 .076 7.2 DDCUS .40 .060 6.6 F = .992 R 2= .989 DW = 2.18 l LKIKWH = Log (Kansas Industrial Sales Fxcluding Pittsburg & Midway Mining Kwh) LSFRB = Log (FRB Production Index) LRKP = Log (Real Price of Electricity) LKGAS = Log (Real Price of Gas Fuels Variable) DDCUS = Dummy Variable to Account for Customer Reclassification in 1970 O 1.1-30
KCGS-FR(OLS) l For P&M a . relationship was estimated. that related electri-(h)_ city used at the mine~to the tons of coal burned at La Cygne V No. . 1. Using KCPL's fuel budget for 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 20,000 MWF in 1979,~ growing slightly to 22,000 MWH in 1990, and remain-ing constant -thereaf ter. 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 . estinates 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 3P percent of Missouri sales and 30 percent of Kansas sales in recent years. Table 1.1-22 indicates that commercial sales are expected to decline slightly as a percentage of total sales over the next ten years. Factors specifically considered in the commercial models were: (1) Commercial activity and KWF 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 conmercial KWH consumption are implicitly considered through the use of the total real income independent variable ; (2) Price elasticities 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 commercial air conditioning loads and the fact that as tempera ture rises in-creasingly high loads are placed on the j system. Separate' statistical models were developed for Missouri and Kansas. f) 1.1-31 4
,4 , - _ _ . . - _ . , .
- - m. . , - - ,,-,,,,y'.,-,n . . , - - <---n-m-- ,-,g-,, . - .,- , - - - , - -
FCGS-ER(OLS) 1.1.1.2.2.4 Residential Forecast In recent years residential sales have accounted for about 23 percent of Missouri energy sales and over 30 percent of overall Kansas energy sales. As shown in Table 1.1-22 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-pories. 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 operating costs, and the intensity of tse and the efficiency of the appliances and eq uipme nt . For heating and cooling equipment the severity of weather largely determines inten-sity of use. Projections were weather normalized to remove this effect. Electrical appliances and equipment saturation studies have provided data on trends for various 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 otber classifications such as traffic signals, street lighting, public authorities, and sales for resale. Fach 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 1.1-14) are based on the April 1977 Power Recuirements Study (PPS) of KFPCo and its membe r systems. Each of the 26 member systems and 3 non-member cooperatives prepared an individual PRS which was based on a thorough review of the existing and potential needs of the system. KEPCo's PPS was prepared in accordance with REA Bulletin No. 120.1. l System managers developed growth projections with considera- l tion to the following factors: Ol 1.1-32
WCGS-ER(OLS)
.I x (a) Historic growth rates, as indicated by mathe-k,j) matical trends; ; (b) The effects of conservation policies, both long and short term; (c) The effect of increasing electrical rates; (d) Rising costs for and decreased -' availability of other energy sources and the ef fect these changes will have on conversion to electrical energy, particularly.for heating and irriga-tion; (e) The economy of the area served by the cooper-ative and the impact upon that economy of national economic and energy policies; (f) The nature of new commercial loads and the probability of the requirement to serve them; (g) Increased electrical loads for irrigation pumping; (h) The impact of _ load management programs; (i) The effect of extreme variables in weather i V and the impact of drought conditions; and (j) Other factors considered likely to affect growth in load and energy consumption.
Detailed irrigation requirements studies were also conducted for those EEPCo members which serve substantial irrigation loads. Further analyses were conducted in 1978 (Lee, Jan. 1978, June, 1978) on the validity of the projections made by the cooperatives. It was concluded as .a result of these analyses _ that the PPS, with some minor reductions in projected irrigation loads, presented reasonable projections for future growth in loads and energy consumption. A summary of the rationale follows, i 1.1.1.2.3.1 Projected Number of Fesidential Consumers The PRS'. projects the greatest growth in the number of residential consumers for systems that serve areas close to major industrial and conmercial centers'. These increases
- represent a-continuing pattern of development, an extension i
n v 1.1-33
. . , , - - . - - - , -e,~ - . - - - - .u -- - - - - --+g - + - , , , ,9--3,- -- ,-
WCGS-EP(OLS) of trends that have been established and are believed likely to continue. The counties in which the cooperatives operate show continued population growth in the rural and suburban areas, supported by a strong and diversified industrial, agricultural, commercial and services industry base. In addition further exploitation of the Kansas oil fields, using secondary and tertiary recovery, will add greater strength to the industrial base. Moreover, the labor force in Kansas is projected to expand at an average annual rate of 2.9 percent, largely in the industrial and services sectors. The anticipated growth in numbers of residential customers is shown in Table 1.1-19. ; 1.1.1.2.3.2 Estimated Usage hy Residential Consumers Increases in average KWH usage by residential consumers is based on the trend toward construction of all electric homes in the rural areas served by KEPCo's members. In addition, many existing homes are being converted to elec-tric heat and equipped for supplemental electric heating. l (See Table 1.1-20) Pecognition was given to a Fansas Cor-poration Commission (KCC) order on conservation and effi-cient use of energy and to the fact that higher prices are a deterent to use. Growth in average annual consumption by residential customers is shown in Table 1.1-21. 1.1.1.2.3.3 Projected Number of Large Commercial Consumers and Their Usaga The number of large commercial users is increasing, and the trend is expected to continue due to the strength of the Kansas economy. Included in the classification are agri-husiness, oil and gas production, pumping and pro.essing, small manufacturing and other commercial operations. There is expected to be a requirement for 7 to 9 MW for a coal slurry pipeline, and plans exist for other oil pumping stations. 1.1.1.2.3.4 Irrigation Estimates Natural gas is still being used as a fuel for irrigation pumping and has been given a priority by the FCC. The long-term availability of natural gas or other petroleum fuels fo r pumping is uncertain as are the costs of these fuels. Use of electricity in irrigation continues to grow however, because of the need for an assured and reliable energy source for pumping. This is a category that must be continually monitored for change. O 1.1-34
f l WCGS-ER(OLS) In the.1978 analyses'-of'the. projections made-by the coopera-
- tives-(Lee,-1978), .i t - was further concluded that deviations
, . in .197.7 from the 1976 projections were . due' to abnormal-3
. weather condition's and temporary changes in the-local econo-
- nies.
< 1.1.1. 2.'4 ' .Recent Growth' History Recent . and --projected average annual growth rates based on
- Table. 1.1-12, 1.1-13 and 1.1 are shown below. for the o
three utilities. These. growth : rates were discussed in Section 1.1.1.1. AVERAGE ANNUAL GROWTH IN PEAK DEMAND AND ENERGY e Peak Demand Energy Demand Time Period KG&E KCPL KEPCo .KG&F KCPL KEPCo - , 1968-1973 5.4% 6.6%
- 5.9% 6.5%
- r
< 1973-1978 ' 5. 0 3.6 7.8% 5.4 3.5 7.6% 1968-1978 5.2 5.1 * '5.7 5.0
- i 1978-1983 3.1 2.7 9.2 2.3 3.7 9.5 1983-1988 3.5 3.6 6.3 3.6 4.0 6.0
, 1978-1988 3.3 3.2 7.7 3.0 3.9 7.7 i
- Not availablo~
The past and projected growth rates in peak demand for both KG&E and KCPL - are below those projected by SPP and NERC. y SPP projects a growth rate of 6.0 percent and NEFC a growth of 4.9 percent for the United - States in the period 1978-1988. In December, 1978 the Department of Energy developed i a forecast of growth- in summer peak demand of 4.9 percent
- for the ~ U.S. in the period 19.79-97 (Department of. Fnergy, 1978). It is- believed that the estimates by the utilities are conservative, particularly for KG&E which is in an area -
- of low unemployment. The decline ~ in annual energy and peak
.; load growth expe rienced and projected can be attributed both to conservation ef forts and to higher prices for elec-
- trical energy. Energy consumption is more likely to be '
i affected-by price increases than peak loads. During summer ] periods of extreme heat, air conditioning is universally
- usedi r.egardless of price, ' whereas on -more moderate days j some of the air conditioning' nay not be used.- The same applies to -periods of extremely cold weather -for those who
- use electric-space heating.
4
- O L 1.1-35
.-_.,_.-.-.,,=,m.,.-,,- , - - . . . , - ,__.,..,_,,~...__..,,.-,.-,,..,,,._..-_,-,._-,-,z _,_ ,., , ... , _ ...
WCGS-ER(OLS) The effect of the Presidential Order on maximum winter and minimum summer temperature standards for heating and cooling in public buildings cannot yet be determined. It is clear, however, that it will slow some of the growth in summer and winter peak loads and in energy consumption. Customers of the Applicants have been given a negative 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 first occured and prices began to rise rapidly. In the period 1972 to 1979, average prices per KWF more than doubled for each category of user, with industrial users experiencing the largest unit increases. The escalation of rates for KG&E in the last 6 - 7 years has averaged 15.9 percent per year for industrial, 11.1 percent for commercial and 12.7 percent for recidential users. Though KCPL's unit rates haven't risen so fast, they were substantially higher than KG&E's rates in 1973 and continue to be slightly higher. KCPL's rates have risen at an average annual rate of 11.4 percent for industrial, 9.7 percent for commercial and 9.4 percent for residential users. The rates of increase over the past few years for KEPCo members have been higher than fo r KG&E and KCPL, with an Everage annual in-crease of 16.4 percent for industrial /comnercial, 19.0 per-cent for irrigation and 15.1 percent for residential. From 1972 to 1979, a period of high rater of increase in costs for boiler fuels and conseguently for electrical energy, KG&E increased the number of residential customers served by nearly 18 percent and KCPL by 11 percent. From 1974 to 1979 KEPCo's average number of customers also in-creased by 11 percent. (See Table 1.1-19) As shown in Table 1.1-21, average annual use by residential customers has increased 27 percent for KG&E and 17 percenu for KCPL over the same period. From 1974 to 1979, KEPCo's average annual use by residential customers increased 30 percent. Despite the dramatic increases in rates, customer use has continued to grow. Much of this increase in average consumption is due to the large number of homes with elec-tric space heating. But as shown in Table 1.1-20 even homes without electrical space heating showed an increase of 20 percent in ave rage annual consunption from 1972 to 197P. 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 loads and energy. O 1.1-36
WCGS-ER(OLS) 1.1.1.3 Power Exchanges ((D) Table 1.1-18 presents a statement of system operations for ' t
~
'both KG&E and KCPL at peak hour conditions for the past 7 summer peaks. Net interchanges by KG&E at the time _of peak-
' load never exceeded 10 percent ' of. the peak load, but firm and ~ emergency purchases frequently ranged from 22 to 49 percent' of the net load. Emergency sales were as high as 2 0. to 2 9 ' percent. of. the net load.
" CPL's net. interchanges 4
were as high as 20 percent of the ne load due to relatively high receipts of non-firm power, amounting t t, as much as 28 percent of the net loao. As shown in Tables ' l'.1-1 and 1.1-2 KG&E and KCPL plan to make capacity purchases and sales in the fu.ture.- 4 The purchases and sales in MW at the time of peak load for the period 1972 to.1979 (See Table 1.1-18) were as follows: PEAK LOAD PUFCHASES AND SALES (MW) KG&E KCPL Year Purchases Sales Purchases Sales 1973 260 167 290 213 1974 1 - -- 109 395 95 ! 1975 357 292 291 95 ( 1976 673 537 608 .268 l' 1977 523 642 714 95 1978 147 154 621 98 1979 345 260 465 202 i KG&E and KCPL have generally been net purchasers at the time of the peak load. As members 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 enhance the economy _and reliability of operations. KEPCo relies upon purchased power to meet all of its needs and will still be meeting most of its reauirements throuch purchases even after_FCGS is on line. I 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. ) KG&E and KCPL maintain interconnections with other utili- ! ties as follows: i O 1.1-37 i
,--,,r . ., - , _ - - ,r. - . . , . , . .--m.-,.. - , , .,.c. --. --,- ,,,~ ,.+. .
WCGS-ER(OLS) 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. 69-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 Scoperative Inc. 161-kV - Board of Public Utilities 345-kV - Iowa Public Service Co. 3 45-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 & Light Co. 161-kV - Missouri Powe" & Light Co. 345-kV - Missouri Public Service Co. (2) 161-kr - Missouri Public Service Co. 345-kV - Northern States Power Co. 345-kV - Omaha Public Power District 345-kV - St. Jcseph Light & Power Co. 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 FCPL participate in interchange agreements, but each utility is responsible for planning and arranging 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. 1.1-38
WCGS-PR (OLS )
, 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 o rder 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 factors in developing long-range plans for expansion, Units sel-ected for capacity additions are those that are judged to be the most cost-effective in meeting future needs, considering fuel constraints.
KEPCo's first capacity will be the 90 MW from SPA in 1980, and the first owned capacity will be the 196 MW from WCGS in 1983. 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 members. Tables 1.1-4a and 1.1-Sa present for KG&E and FCPL the in-stalled capacitief by plant and unit for the period 1974-1990. Actual and proposed capacity changes are shown in Tables 1.1-4b and 1.1-5b. Load and capability data for KG&E and KCPL over the period m 1965-1990 are given in Tables 1.1-1 and 1.1-2. Similar data I ) are provided over the period 1971-1994 for KEPCo in Table C/ 1.1-3. Ea ch of these three tables shows peak and system responsibili ty, accredited and system capacity and capacity balance, the latter bo?n with and 5 thout FCGS. Witnout WCGS each company will suf fer deficiencies in its capacity balance. Table 1.1-7a presents load and capability data for the SPP for tle period 1965-1977, and Table 1.1-7b pravides a com-pa rloon of forecast and actual capability for the period 1971-1978. Of particular interest in the latter table is the fact that, because of forced outages, in all but two of the eight yea rs shown, the actual operating margins at the times of summer peak loads were lower than those fo reca s t. In five of those years the actual operating margins were below the SPP nargin 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 1978-1980, and both seasonal loads and annual energy are given for 1978 and projected for 1979-1988. SPP projects a growth rate of 6.2 percent for summer peak loads and 6.0 percent for annual energy over the period 1978-1988. L 1 l 1.1-39 I 1 l
WCGS-ER(OLS) Table 1.1-9 presents projected capability maintenance, exchange and reserve data for the period 1979-1988. The margins shown for summer peaks are above 20 percent until after 1986 when they decline to 19.2 percent in 1987 and 17.1 percent in 1988. It should be noted, however, that these margins are based upon the assumption that planned capacity additions will be built on time. It is likely that many of the additions will be delayed and that some may be cancelled particularly in 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 1.8 percent of the summer net dependable capa-city of SPP in 1983. A longer term forecast for SPP is given in Table 1.1-10 for the period 1969-1998. This table shows generally declining margins over that time period, although, as projected, the margins remain above the 15 percent SPP requirement. How-ever, nearly all of the capacity additions projected for this period are to be nuclear and coal, and there is doubt that some of these facilities will be built* or that many will be completed on schedule. MOKAN load and capability data for the period 1971-1988 are shown in Table 1.1-11. The capacity balances of MOKAN will be negative after 1983, without WCGS. When KEPCo be-comes a member, the capacity balance will be negative in 1983. Peak hour conditions in the systems of KG&E and KCPL for the period 1973-1979 are given in Table 1.1-18 and discussed in Section 1.1.1.3. Over this period KG&E was generally a net purchaser of amounts ranging from 4 to 9 percent of its net 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 its net load. 1.1.2.1 Capacity ~ Planning Capacity planning by KG&E and KCPL must he closely related to the availability of fuels. Table 1.1-15 shows the major shifts that have take n 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 gas. In 1975 gas accounted for 66.8 percent of production, coal for 18.3 and oil for 14.9. By 1980 coal will account for 53.2 percent of production, gas for 43.0 and oil for 3.8 percent. By 1985 with diversification into nuclear fuel the use of gas will decline to 13.7 percent, coal will account for 57.2 percent of energy production and high-cost oil for 9 1.1-40
. _ ~ =.- .. -. .-- - - . . .. . _ . . .
WCGS-EP(OLS) , 0.3 percent. - Nuclear will provide - 2 8. 7 percent of the O annual net generation. KCPL will remain predominantly a coal fueled utility, but ' its 1980 dependence on coal for 4 94.2: percent of generation will decline to 67.9 percent in ! 1985, and gas, which provided 30.7 percent of the generation ; in 1970, will declir.e to 0.9 percent. Oil .use which was l l"
. insignificant in 1970 was 4.0 percent in 1975 and is ex-pected to be 4.2 percent in 1985 when nuclear will account for 27.0 percent of generation.
The importance of WCGS in providing for diversification of 4 fuel sources is shown in Table 1.1-30 which provides the projected fuel mix for the first three yc9rs of planned operation both with and without WCGS. Without WCGS much . greater reliance must be placed upon gas and oil by KG&F and 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 the difference. For KCPL, WCGS
- would provide 17' percent of the peak day production. With-out WCGS the difference would be made up by purchases and by additional consumption of oil. 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:
'l CAPACITY ADDITIONS 4 KG&E 1 Season or Month and Year Unit Function Fuel Capacity - MW
! Spring 1980 Jeffrey No. 2 I*I Bane Coal 136 April .1983 WCGS Bate Nuclear 477
.)
Spring-1983 Jeffrey No. 3 g,) Emse Coal 136 ! Spring 1985' Jeffrey No. 4 Base Coal 136 l Jeffrey units will be operated by Kansas Power and Light;
- KG&E will have a 20 percent share of each.
1 4 t v 1.1-41 , l
WCGS-F R ( OLS ) CAPACITY ADDITIONS KCPL Month and Yenr Unit Function Fuel Capacity MW March 1980 Iatan No. 1(*} Base Coal 455 April 1983 WCGS Base Nuclear 477 March 1989 Unspecified Base Coal 455 s The Iatan unit will be operats.d by KCPL which will retain a 70 percent ownership. As a means of increasing reliability, diversifying fuel nix and developing a gradual build-up in generating capacity, KG&E has acquired and plans to acauire a 20 percent interest in each unit of the Jeffrey Energy Center. Four 680 MW units are planned, each of which will provide KG&E with additions of 136 MW of base load generating capacity in ' i 1980, 1983 and 1985, and WCGS will provide 477 MW in 1983. KCPL will rely on larger units to meet growth in demand, with a 70 percent, 455 MW interest in Iatan No. 1 in 1980 and the possible addition of an unspecified unit to provide 455 MW in 1989. WCGS will provide 477 MW in 1983, and two additions of 30 MW each are tentatively being considered for the early 1990's, but no dates have been selected nor has a decision yet been made on fuel. Over the period 1980-1990 there will also be other reratings and retirements for both utilities, as shown in Tables 1.1-4b and 1.1-5b. 1.1.2.2 Fuel Sources And Prices , l 1.1.2.2.1 Coal In 1979 KG&E used more than 1.9 million tons of coal and KCPL used about 4.2 million tons. Most of both companies' requi rements 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 that expires in the year 2002. Approximately 1,630,000 tons are to be provided each year. In years when the entitlement amount cannot be met, additional quantities are purchased on the spot market. O 1.1-42
.WCGS-ER(OLS)
' Coal for La Cygne No. 2 ia ~ supplied by the Amax Coal Company from l Gillette, Wyoming, under a contract that expires in I i'
1996. The annual entitlement is 1,890,000 tons which is i supplemented by . spot purchase. KCPL has contracts with l
- the Peabody Coal Company in . Missouri and Oklahoma calling for deliver;' of 2,150,000 tons per year under contracts that ,
; expire in 1986 and 1996 KCPL also has a contract with the
! Arch Mineral . Corporation in Hanna, Wyoming, calling for < 500,000 tons per year, under a contract expiring in 1986. ' 2 Iatan No. 1 is being supplied with 2.4 million tons of Wyoming coal per year through October, 1982 by the Amax Coal ] Company.- KCPL's wholly-owned subsidiary, WYMO Fuels, Inc. is expected to supply Intan No. 1 after expiration of the Amax contract. KCPL's share would be about 1.7 million tons per year.
! Coal for the Jeffrey 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 share for Jeffrey No. I will be about 480 thousand tons per year. ' i Table 1.1-15 indicates the significant change that has ! occurred in the ten year period, 1970-1980, during which KG&E has converted from a gas-fueled unit to one that uses coal as its primary generetion source. KCPL's use of coal has also increased as the use of gas has declined. Fur 2her 4 n) (V fuel diversification will be provided by WCGS which will also permit KG&E and KCPL to reduce gas consumption. 1.1.2.2.2 011 ! KG&E burned 466,000 barrels of oil in 1979 and KCPL about 576,000 barrels. KG&E purchases most of its oil from local
- producers. KCPL issues annual purchase orders for its anticipated requirements and makes spot purchases when necessary. KG&E and KCPL minimize the use of oil whenever possible.
j 1.1.2.2.3 Natural Gas During 1979 about one-third of KG&E's gas was provided by the Kansas Gas Supply Company under two conn acts that expire in 1990. Much of the remaining requirement was ob-tained under month-to-month interstate interruptible - gas contracts. KG&E used about 45 billion cubic feet of natural gas in 1979. I 1.1-43 >
, , - - . _ . _ _ _ _ _ , _ - - _ ~ , . . - , _ . , - , . -
WCGS- rn g JLS } KCPL's use of natural gas 1;a s been declining; about 7 billion cubic feet were burned in 1979 Gas has been purchased from the Gas Service company on an interruptible basis to displace the more expensive oil used for startup and flame stabilization at steam stations. It is also used to provide adlitional steam prcduction for electric generation and steali sales when coal burning equipment is out of service for epair. At times it is also necessary for KCPL to burn natural gas to meet air quality regulations. 1.1.2.2.4 Nuclear Fuel KG&E and KCPL have received from Westinghouse Flectric Corporation a quantity of uranium hexafluoride equivalent to 619,000 pounds of uranium concentratea and expect to receive another 100,000 pounds. The original contractual arrangements with Westinghouse and the questions of de-liveries and prices are the subject of litigation in process. The companies have contracted to purchase another 500,000 pounds of uranium concentrates which, combined with the 719,000 pounds expected from Westinghouse, will complete the initial core load for WCGS. Contracts also exist for the conversion to uranium hexafluoride of these concen-trates and for those required for six subsequent reloads. 1.1.2.2.5 Fuel Costs Tables 1.1-32 and 1.1-33 present actual and projected fuel costs. December 1979 inventory costs for KG&E and KCPL are as follows: FUEL COSTS IN CENTS PFR MMPTU DECEMBER 1979 Fuel KG&E KCPL Coal 97.2 87.7 1 Oil 176.7 202.2 i Gas 162.0 130.8 i l System Cost 128.0 93.8 Projected 1983 fuel costs provide a comparison of fossil and nuclear fuel costs. O 1.1-44
NCGS-ER(OLS) FUEL COSTS TC CENTS PER MMPTU 1963 Fuel KG&E KCPL Coal 118.1 132.6 011 366.7 708.7 Gas 236.0 219.7 Nuclear 64.0 59.1 System Cost 132.8 132.0 The importance of nuclear fuel in providing lower cost energy is clearly demonstrated in this comparisc.1. Additional per-spective 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 FUEL COSTS CENTS PER MMPTU KG&E KCPL Fuel 1970 1980 1970 1980 Coal 26.7 92.2 25.3 103.5 Oil 25.4 196.7 76.2 542.0 Gas , , 22.3 162.6 27.5 165.0 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 1975 58.5 50.3. 1980 126.2 122.2 1985 133.2 159.2 1990 227.3 216.8 With increases in individual fuel costs ranging from factors of 3.5 to 7.7 between 1970 and 1980 and system fuel costs increasing by factors of 4.7 to 5.6. in the same period, it is clear that the impact on total operating costs has been serious. Table 1.1-34 shows that in the period. 1968-1978 fuel costs more than doubled as a percentage of total oper-ating costs. For KG&E fuel costs.were 22.6 percent of oper-ating costs in 1968 and 48.1 percent in 1979. For KCPL they p were 33.2 percent in 1968 and 66.9 percent in 1978. O 1.1-45 (
WCGS-ER(OLS) 1.1.2.3 Bulk Power Planning Both KG&E and KCPL are members of SPP, the regional rella-bility council, and of POKAN. 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 se rve as guidelines for the development of more specific criteria by each system or control area (Southwest Power Pool, 1978). Individual compa ny members of SPP have been assigned to groups as s h o w ., in Table 1.1-6. These assignments are based on individual company location, and a company can request reassignment to ancther group or to be included in more than one group. SPP has developed its criteria such ' hat 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 nornal 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, under-frequency 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 load exceeding available capacity 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 fea tu re s 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 relative to curtailments and inter-ruptions.
l 1.1-46
f WCGS-ER(OLS) Criteria are also set for the bulk system, and it is noted [s]
'V that within the SPP system there are sub-areas with natural electrical boundaries and large amounts of load which could become isolated in the event of a severe system disturbance.
These sub-areas can include portions or all of one or more companies. Criteria for planning transmission additions for the sub-areas in SPP are as follows.
- 1. Each sub-area shall maintain service con-tinuity after the loss of the single more important system component (either trans-mission line or generating unit), taking into account planned maintenance schedules.
- 2. Stability shall be maintained between the sub-area and neighboring systems when the loss of the single most important system component is caused by a three-phase fault at the worst location, cleared in 0.1 second.
- 3. A sub-area may suf fer interruption of load as a result of less probable contingencies; however, such contingencies should not result in the collapse of the SPP system. These less probable contingencies shall include, but not be limited to, the following:
fM 1 a. The loss of a complete substation or
,V switching section (all equipment of one voltage);
- b. The loss of all units in a generating station which have in common such com-ponents as transmission substation, control room, fuel supply, etc.;
- c. The loss of all transmission lines on a common right-of-way;
- d. The loss of any two generating units in the same sub-area during annual peak conditions (whether scheduled or not);
a r.d
- e. The loss of any two transmission lines in the same sub-area during annual peak con-ditions.
Planning principles have also been established on protective relaying, adequate communications systems and instrumenta-tion to ensure safe operations and to analyze outages, short circuits and protective relay performance. O m 1.1-47
WCGS-ER(OLS) It is the policy of SPP to maintain as high an interconnec-tion capability with adjoining regions as is economically feasible as a means of ensuring reliability in the event of major transmission and generation outages. MOKAN is an association of investor-owned electric utilities in Kansas and Missouri that have agreed to coordinate plan-ning and operations among their systems and to provide reserve sharing responsibilities. Each MOKAN member is also a member of SPP. MOKAN participants are required to plan their generation and transmission additions and their inter-change transactions so as to provide fo r each system a reserve capacity margin of not less than 15 percent of its estimated annual peak load responsibility. The requirement exists to pay capacity charges in the event of a reserve margin deficiency. (KCPL maintains an internal nininun rese rve margin of 20 percent, and the advisability has been discassed within the pool of raising the pool requirement to more than its present 15 percent requirement.) MOKAN en-surea greater reliability for the member companies and also for municipal and cooperative electric utilities located in or near the service area. In addition to reserve marg in requirements, other coordinating arrangements are listed below. Not all participants are included in all of the following:
- 1. Stand by service; Construction and operation of 345-kV inter-2.
connection facilities;
- 3. Economy energy transactions;
- 4. Overall system planning; and
- 5. System maintenance sch eduling.
As previously noted, KG&E and/or KCPL are signators to other coordinating agreements. (See tabulation of agreements in Section 1.1) One or both are involved in the following four agreements, as indicated: (1) The Companies - Associated - Southwestern Power Administration Agreements (KG&E and KCPL) involve the following coordinating arrangements: )
- 1. Purchase of hydro-electric peaking power from SPA by Missouri Companies and Associated; O
1.1-48
WCGS-ER(OLS):
- 2. Integrated operation and interchange of
' power between the Missouri Companies and i
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-j vice between Missouri companies and Associated, i
As of May 31, 1979 The Companies ' hydro-electric 3 peaking power entitlement under this agreement was reduced to zero. 1 } (2) The South Central Electric Companies Coordi-nation Agreement (KG&E) involves: J
- 1. The exchange of seasonal diversity;
- 2. Deferred diversity capacity; i
- 3. Firm power purchases;
- 4. Economy energy sales; j 5. Emergency service; and, l 6. Coordinated maintenance schedules.
(3) The Kansas City - Twin Cities Coordination , Agreement (KCPL) provides for: , 1. Construction and operation of 345-kV
; interconnection facilities for power 6x-changes; and
- 2. Interchange of:
- a. Emergency energy;
- b. Scheduled outage energy;
- c. Economy energy;
- d. Short term power; and,
, e. Participation power l . (4) The Missouri-Kansas-Oklahoma Interconnection i Agreement (NG&E) provides for:
- O 1.1-49
WCGS-ER(OLS)
- 1. Construction and operation of 345-kV transmission lines and interconnections for power exchanges;
- 2. Interchange of:
- a. Emergency energyj
- b. Economy energy;
- c. Excess energy;
- d. Replacement energy;
- e. Participaton power; and
- f. Firm powerr and
- 3. Direct scheduling of power transfers 1.1.3 RESERVE MARGINS 1.1.3.1 Reserve Recuirements 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 reserve margin for KG&E is 15 percent, and it is 20 percent for KCPL and up to 25 percent in the first year of operation for a new plant. Both SPP and MORAN have required minimum reserve margins of 15 percent, and MOKAt: assesses a capacity charge on a member compa ny 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 summer peak loads and the accredited summer generating capacity. Margin estimates for the ear 3 y years of WCGS operation from 1983 to 1990 both with and without WCGS follow:
O 1.1-50
4 WCGS-ER(OLS) RESERVE MARGINS Year KG&E KCPL With WCGS Without WCGS With WCGS Without WCGS MW Percent MW Percent MW Percent MW Percent 1983 804 44.9 327 18.3 873 36.4 396 16.5 1984 719 38.3 242 12.9 786 31.6 309 12.4 1985 780 40.0 303 15.5 697 27.1 220 8.5 1986 720 35.8 243 12.1 604 22.6 127 4.8 1 1987 655 31.6 178- 8.6 508 18.4 31 1.1 1988 605 28.5 128 6.0 409 14.3 - 68 - 2.4 , 1989 555 25.5 78 3.6 761 25.7 284 9.6 1990 500 22.4 23 1.0 654 21.3 177 5.8 1 With WCGS both KG&E and KCPL will be well within internal and pool requirements for the entire period with the excep-tion of 1987 when KCPL will be below its internal require-ment and 1988 when KCPL will be below both internal and pool , requirements. WCGS. represents a large block of capacity 1 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 requirements in 1984 and after 1985, declining to virtually no margin in 1990. KCPL would be below its internal requirement for the full period l /~' and below pool requirements after 1983. Data are not pre-3 sented - for KEPCo because, as shown on Table 1.1-3, KEPCo will be dependent upon firm purchases to meet its commit - ! ments for the foreseeable future. l At the time of the anticipated 1983 summer peak WCGS will represent a significant percentage of the accredited generating capacity of each of the owners, as shown below: PERCENTAGE OF CAPACITY REPRESENTED BY WCGS 1983 KG&E KCPL KEPCo 18.4% 14.6% 100.0% Upon going into service, WCGS will be the. largest generating unit for both KG&E and KCPL and the only unit for KEPCo. The next largest units will be La Cygne No. I for KG&E with 370 MW of capacity and Iatan No. 1 for KCPL with 455 MW of capacity. O U 1.1-51
WCGS-ER(OLS) In 1983, 58.6 percent of the accredited generating capacity of KG&E will consist of 4 large units, ranging from 315 to 477 MW in capacity. KCPL's 5 large units, ranging in capa-city from 315 to 47 7 MW, will constitute 63.2 percent of its accredited generating capacity. Without WCGS, the loss of production on any of these units would bring the utility involved drastically below required reserve margins. 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 owning half of each unit. 1.1.3.2 Scheduled And Forced Outages 1.1.3.2.1 Scheduled Outages KG&E develops a two-year and a ten-year overhaul 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 operated. 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 worle or repairs. Tea 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 larger 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 particular times of the year so as to optimize availability with respect to anticipated load and the operating costs of units. No outages are scheduled during the system's peak load period from mid-June to mid-August. Coal burning units are not scheduled for outages during the winter peak load period of December through February because na tu ral gas curtailments may occur in this period and there may be shortages of fuel oil. Large unit outages are scheduled for March through May and September through November, the periods of minimum system load. KCPL's general plan for scheduling outages is similar to that of KG&E. The frecuency nf scheduled maintenance is based on KCPL's experience, tid utility industry's exper-ience and the manufacturer's recommendation. Generator maintenance is planned annually for the next 5 year period. i l l 1.1-52
-- - . - -- -. . - - __= -- - . . .__
WCGS-ER(OLS)
, _s A combination of three methods is used for scheduling unit maintenance. The first is a manual method in which the
} largest units are scheduled in - the valley of the annual l load, and the smaller units are scheduled around these outages. The . second ' method uses a Power. System Simulator computer progrtm which. analyzes the costs of different maintenance schedules. An output from the program is a schedule for maintenance bcsed on KCPL load and maintenance !
cycl es . The third nethod uses the Maintenance Evaluation Program (MEVAL) An optimizing computer program which is on the Control Data Cybernet timesharing system. i The combined'results of the three nethods are used to develop an optimum schedule which is cost-effective 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. I 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 .nt jointly owned by KG&E and
! KCPL has.bcen less favorable as summarized below:
LA CYGNE OUTAGE EXPERIENCE l Outage Date Date Duration Year Unit Off On In Hours Cause 1973 La Cygne No. 1 9/1/ 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 " 7/08' 8/17 920 Immediate pressure 1 i C^ 1978 La Cygne No. 2 10/22 11/10 461 turbine repair Boiler slag removal ! 1.1-53
-- w n, w- ,. - wri s a- *+,--r - w---y+--w --t- ,r-..-,,vv.-ww-.m ------w y4 y w, -w y # -re,-.---rwy-
WCGS-ER(OLS) Some of these outages lasted for several weeks and occurred during summer peak periods. Over the past 7 years forced outages on La Cygne No. I have amounted to a high percentage of its availability. This unit is currently KG&E's larnest and KCPL's second largest. 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 No. 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 1.1.4 EXTERNAL SUPPORTING STUDIES Documents filed annually in response to a FERC request are l consolidated by SPP into the "Southwr;s t Power Pool Pegional ! Peliability Council Coordinated B ul). Power Supply Program" l which is submitted to the Economic regulatory Administration of the Department of Energy. The most recent issue is that of April 1, 1979. Data extracted from the 1979 report are presented in Tables 1.1-7a, 1.1-7b, 1.1-8, 1.1-9 and 1.1-10 on past loads, mar-gins and capability, and estimates given on future energy, loads, capacity and margins. . It is the policy of SPP to maintain as high an interconnec-tion capability with adjoining ragions as is economically feasible. Joint s tudies 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. l 1.1-54 l l l l
WCGS-ER(OLS) h Transmission load studies coordinated by SPP establish the
- s. maximum import capacity through system interconnections.
An individual member of MOKAN and SPP does not necessarily carry enough re" 'rve capacity to cover the outage of its own system's largeus unit. Rather, reliance is placed on neigh-boring member systems through interconnections for emergency and maintenance support. Implicit in the use of a 15 per-cent reserve margin (rather than the capacity of the largest i unit by each SPP member) is the interconnection capability which will provide the necessary reliability for continuity , of service. Periodic studies verify the reliabiljty of this concept.
- 1.
1.5 REFERENCES
Black & Veatch, 1979, Environmental Assessment of Wolf Creek Generating Station, Unit No. 1 for Kansas Elec-tric Power Cooperative, Inc. l Department of Ene rgy 1978, Bulk Flectric 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.
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 Pequirements Study.
National Electric Reliability Council, 1979, Annual Report for 1978 National Electric Reliability Council, 1979, 9th Annual Review of Overall Reliability and Adequacy of the North American Bulk Power System. Southern Engineering Company of Georgia, 1979, Feasibility Analysis of Participation in Wolf Creek Generating Sta-tion, Unit No. 1 with Hydro Peaking Power Purchases from the Southwestern Power Administration,- Prepared for Kansas Electric Power Cooperative, Inc. Southtc.t Power Pool, .1979, Regional Reliability Council i Coordinated Bulk Power Supply Program, A Report to the Economic Regula tory Administration, Department of Energy. O 1.1-55
[ p. G / TABLE 1.1-4b FGEF ACTUAL AND P10 POSED CAPACITY CHANGES Punctiun Nature MW Prima ry Total Annual Year Date Unit or Plant on Load of Change Change Puel Net change . 1975 June 30 Lacygne No. 1 Base Perating - 33 Coe? - 23 1976 June 30 LaCygne No. 1 Base Perating + 23 Coal June 30 Murray Gill No. 2 Intermediate Perating + 1 Gas June 30 Murray Gill No. 3 Pase Rerating + 1 Cas June 30 Gordon Evans No. 1 Base Perating + 1 Gas June 30 Ripley Peaking Perating + 1 Cas + 27 1977 May 10 LaCygne No. 2 Base Addition +315 Coal June 30 LaCygne No. 1 Base Rerating - 12 Coal June 30 LaCygne No. 2 Base Perating + 10 Coal June 30 Purray Gill No. 1 Intermediate Rerating - 5 Cas June 30 Murray Gill No. 2 Intermediate Rerating - 5 Gas June 30 Murray Gill No. 3 Base Rerating - 21 Gas , June 30 Murray Gill No. 4 Base Rerating - 21 Gas June 30 Gordon Evans No. 1 Base Rerating - 17 Gas June 30 Cordon Pvans No. 2 Base Perating - 31 Cas g i June 30 Neosho No. 1& 2 Peaking Perating - 10 Coal () June 30 Ripley Inte rmedia te Perating - 4 Gas Cl U3 June 30 Wichita No. 3&4 Peaking Perating - 4 Cas +195 M 1978 July 31 Jeffrey No. 1 Base Addition +136 Coal 32 June 30 Cordon Evans No. 1 Base Rerating + 3 Gas June 30 Gordon Fvans No. 2 Base Rerating + 9 Gas June 30 Murray Gill No. 3 Base Rera ting + 8 Cas y) June 30 Murray Gill No. 4 Bare Perating + 6 Cas June 30 'Neosho No. 1&2 Peaking Perati ng
- 9 Coal June 30 Neosho No. 3 Intermediate Rerating - 6 No. 6 Oil 4 June 30 pipley Peaking Perating + 2 Cas +167 l 1979 June 30 Neosho No. 1& 2 Peaking Retirement - 47 Coal - 47 1980 Spring Jeffrey No. 1 Base Rerating + 2 Coal Jeffrey No. 2 Base Addition +136 Coal + 98 LaCygne No. 1 Pase Perating - 30 Coal LaCygne No. 2 Base Perating - 10 Coal 1
1983 Spring Jet 'rgy No. 3 Base Addition +136 Coal April Wo1 Creek Base Addition +477 Nuclear +513
; 1985 Spring Jeffrey No. 4 Base Addition +136 Coal +136 i
1988 No Change 1990 No Change 3
- See footnotes to Table 1.1-4a for planned changes of function on load and of primary fuel for various units.
4
I WCCS-FP (OLS ) TABLE NO. 1.1-5 h ' KCPL + sm _s/ ACTUAL AND PROPOSEC CAPACITY CPANCFS 1974-198# Total l Annual Function Nature- Primary Net Chance Year Date Plant and Unit on Lead of Change FW Cha nge Fbel ;FW Summer) 1975 Northeast 1 Peaking Perating + 2 Cas Northeast 2 Peaking Perating + 1 Ca6 Northeast 4 Peaking Perating + 1 Gas Northeast 5 Peaking Perating + 3 Cas Northeast 13, 14 Peaking Addition + 116 No. 2 Oil + 110 Hawthorn 3 Int e rmediate Perating + 1 Coal i
- Montrose 1 Base Perating - 5 Coal 4
Montrose 2 Base Perating - 4 Coal Montrose 3 Pase Perating - 5 Coal 1976 Northeast 15, 16 Peaking Addition + 116 No. 2 Oil Hawthorn 1 Inte rmediate Perating - 2 Coal i Fawthorn 2 Inte rmedia te Perating - Coal + 27 Hawthorn 3 Intermediate Peratina - 14 Coal Hawthorn 4 Intermediate . Peratina - 28 Coal 3 Hawthorn 5 Pase Perating - 40 Coal i 1977 Crand Ave. 5 Intermediate Perating - 6 Coal Crand Ave. 7 Intermediate Perating - 4 Coal Grand Ave. 8 In termedia t e Deactivation - 14 Coal Northeast 1 Peaking Perating - 29 Cas Northeast 2 Peaking Deactivation - 22 Cas Northeast 4 Peaking Perating - 1 Cas + 280 Northeast 5 Peakirg Perating - 3 Cas Northeast 11, 12 Peaking Perating - C No. 2 Oil Northeast 13, 14 Peaking Peratina - 15 No. 2 Oil Og Northeast 15, Northeast 17, 16 18 Peaking Peaking Peratina Addition
- 15
+ 10),
No. 2 No. 2 Oil Oil i LaCygne 2 Base Addition + 315 Coal Hawthorn 1 Intermedia te Perating - 8 Coal Hawthorn 2 Intermediate Perating - 8 Coal ! 1978 Hawthorn 3 Intermediate Peratina - 15 Coal Hawthorn 4 Intermediate Perating - 15 Coal Hawthorn 5 Pase Perating - 30 Coal Montrose 1 Base Perating - 7 Coaa - Al
- Montrose 2 Base Perating - 4 Coal
'- Montrose 3 Base Rerating - 8 Coal Lacygne 1 Base Perating - 12 Coal Lacygns 2 Pase Perating + 10 Coal 1980 Mar Istan 1 Base Addition + 455 b Coal Lacygne 1 Base Perating - 30 Coal Lacygne 2 Base Perating - 10 Coal Montrose 1 Base Perating - 11 Coal Hawthorn 1 Intermediate Perating - 10 Coal - 264 Hawthorn 2 Intermediate Peratina - 10 Coal Hawthorn 3 Int ermediate Perating - 20 coal Hawthorn 4 Intermediate Perating -
'O Coal Northeast 1,2,4,5,7 Peaking Not Accredited - 8C Cas 1981 Northeast 1,2,4,5,7 Peaking Accredited + 00 Cas + 80 1982 Jan Crand Ave. 5 #
- Intermediate ' Deactivation - 7 Coal Jan Grand Ave. 7 Inte rmediate Deactivation -- 30 Coal - 30' 1983' Jan Northeast 1 Peaking Petirement - 7 Cas Northeast 4 - Peaking Petirenent - 30 Cas
+ 397 Northeast 5 Peaking Petirement - 30 Cas Northeast 7 Peaking Petirement - 13 Cas April Wolf Creek Base Addition + 4 77 Nuclear
( 1988 No Change 1989 Mar. Iatan 2 (b) Pase Addition + 455 Coal + 455
. 1990 Jan Grand Ave.-9 Intermediate Petirement - 40 Coal - 40
" Joint ownership: RCPL 50%
Joint Ownership NCPL 708
, Winter Capacity only 1
WCGS-ER(OLS) TABLE 1.1-6 (SHFET 1 of 4) PARTICIPATION IN POOLS AND ASSOCIATIONS SOUTHWEST POWER POOL (SPP) Southwest Power Pool Coordination Aareemc nt, dated December 17, 1969, with various anendments, the latest of which is dated November 9, 1979. Participating Parties: Group A Alexandria Light & Power Department, Louisiana Arkansas Electric Cooperative Corporation Cajun Electric Power Cooperative, Inc. Central Louisiana Electric Corp Inc. (The)(b) Gulf States Utilities Company'g9ny, Lafayette Utility Systen, Louisiana (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 Dan Authority New Mexico Electric Service Compggy(" Oklahoma Cas & Electi-ic Company Public Service Company of Oklahoma (b) Southwestern Electric Power Compag)(b) Southwestern Power Administration Southwestern Public Service Company
)
Western Farmers Electric Cooyggve West Texas Utilities Company Group C Board of Public Utilities, Kansas g y, Kansas Central Kansas Power Company, Inc. Chanute Municipal titilities, Kansas City Power & Light Department, Independence, Missouri Coffeyville Municipal Water & Light Degtment, Kansas Empire District Electric Company ge) Kansas City Power & Light Company I
^ 'Non-membe r sys tem. 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
WCGS-ER(OLS) TABLE 1.1-6 1 ,3 (SHFET 2 of 4) ( ) Kansas Gas & Electric Company (b) KansasPower&LightCompany(Tgg)(b) Missouri Public Service Company (b) St. Joseph Light & Power Company Sunflower Electric Cooperative, Inc. Western Power Division, ggyntral Telephone & Utilities Corporation Winfield Municipal Light & Water, Kansas Group D Associated Electric Cooperative, Inc.(a)(b) City Utilities, Springf Missouri Missouri Edison Company {g}d, Missouri Power & Light Congggy(a) Missouri Utilities Company Group E (Non-Members) City of Houma, Louisiana City of Monroe, Louisiana City of Fatchitoches, Louisiana City of Ruston, Louisiana f-~3 Jonesboro City Water & Light, Arkansas Morgan City Municipal Utilities, Louisiana (d) N Ottawa Water & Light, Kansas Ponca City Water & Light, Oklahoma MISSOURI KANSAS POOL (MOKAN) General Participation agreemenhch" ^"} MOKAN Coordination agreemenkc) Kansas Facilities agreement Missouri Facilities agreement (c) Missouri Coordination Agreement (c) Amendments to General Participation agreement Participating Partiesi Central Kansas :?ower Company, Inc. Empire District Electric Company (The) Kansas City Power & Light Company Kansas Gas & Flectric Company Kansas Power & Light Company (The) Missouri Public Service Company Saint Joseph Light and Power Company (Mo) I"I /N Data for these member systems of SWPP are reported by ( ) b) contiguous councils (c) Designated SWPP Control Areas These are not MOKAN-wide agreements, but they are MOKAN related
WCGS-ER(OLS) l TABLE 1.1-6 (SHEET 3 of 4) Western Power Division, Central Telephone & Utilities Corporation Sunflower Electric Cooperative, Inc. Note: Not all of the above participants are signatory to each agreement. COMPANIES - ASSOCIATED - SOUTHWESTEPN POWER ADMINISTPATION (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 Agreenent Various interconnection agreements among the men'er 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 Compa"y Louisiana Power & Light Company Mississippi Power & Light Company New Orleans Public Service, Inc. Oklahoma Gas and Electric Company ) Public Service Company of Oklahoma l Southwestern Flectric Power Company
WCGS-ER(OLS) TABLE 1.1-6 (SHEET 4 of 4)
/sT ^
l
\,,)
KANSAS CITY - TWIN CITIES Memorandum of Understanding - South Section Addendum No. 1 and No. 2 Coordinating Agreement Pacilities 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 Agreenent, dated September 22, 1971 Participating Parties: i (- g) N/ Associated Electric Cooperative, Inc. Kansas Gas and Electric Company Public Service Company of Oklahoma Union Electric Company ( LJ
WCCS-ER(OLS) TABLE 1.1-8 SOUTHWEST POWER POOL ENERGY AND PEAK LOADS [ .s}
*- 1978-1988 Monthly - 1978-1980 Seasonally 1978-1988 Month Energy (GWH) Peak Load (FW) Season Load (MW) 1978 1979 1980 1978* 1979 1980 Jan 15,609 16,446 18,003 26,922 28,325 29,349 S 78 39,191 Feb 14,113 14,285 15,750 26,051 26,903 28,414 W 78-79 28,350 Mar 13,975 14,743 15,852 24,727 25,714 27,193 S 79 41,094 Apr 13,322 14,371 15,324 23,867 26,227 27,774 W 79-80 29,349 May 15,278 16,017 16,661 30,668 32,317 34,151 S 80 43,705 Jun 17,582 18,725 19,723 36,570 38,492 41,226 W 80-81 31,292 July 20,826 21,271 22,524 38,339 40,819 43,418 S 81 46,492 Aug 19,711 20,957 22,684 38,378 40,975 43,580 W 81-82 33,290 Sep 17,627 18,210 20,380 36,249 38,220 40,640 S 82 49,468 Oct 14,297 15,819 17,458 27,499 30,038 32,081 W 82-83 35,461 Nov 13,878 15,142 16,542 25,371 27,895 29,787 S 83 52,477 Dec 15,332 16,124 17,414 26,800 29,304 31,292 W 83-84 37,867 S 84 55,679 W 84-85 39,978 Year Ene rgy (GWH) S 85 59,081 W 85-86 42,407 197P' 191,550 S 86 62,559 1979 201,889 W 86-87 44,918 1980 217,765 S 87 66,200 1981 229,545 W 87-88 47,563 1982 244,391 S 88 69,9R7 1983 259,641 W 88-89 50,330 1984 276,037 1985 293,168 1986 311,214
- s. 1987 329,657 f 1988 349,140 V
- Actual Southwest Power Pool 1979 T
~
v>
WCCS-FR(OLS) TABLE 1.1-9 SOUTHWFST POWFR POOL PPOJFCTED CAPABILITY, MAINTENANCF, EXCHANGF AND PESEPVF, 1979-19P 8 IN MW 1970 1990 1981 1982 1983 Resources S ummer ( a ) Winter (b) S umme r Winter S umme r Winter S umme r Wi nt e r S um ne r Winter Net Dependable Capability 47,802 48,822 53,020 53,462 57,268 57,152 60,289 60,743 63,196 63,097 1. 5,303 3,608 5,236 3,577 4,304 3,286 4,353 3,538 3,797 3,108
- 2. All Scheduled Purchases 4,461 3,558 3,760 3,582 3,932
- 3. All Scheduled Sales 3,377 4,516 4,238 4,731 3,698 54,018 52,308 57,874 55,987 61,084 60,521 63,411 62,273
- 4. Total Resources (1+2- 49,728 47,914
- 5. Iroperable Capability}f, 190 170 0 40 0 55,947 40 61,084 0
60,481 40 63,411 0 40 62,233
- 6. Operable Resources (4-5) 49,538 47,744 54,018 52,268 57,874 Demand 49,468 35,461 52,477 37,867 41,094 29,34a 43,705 31,292 46,492 33,290
- 7. Peak Hour Demand 115 115 115 115 Interruptible Demand 104 104 111 111 115 115 C. 35,346 52,362 37,752 Demand Pequirements (7-8) 40,990 29,245 43,594 31,181 46,377 33,175 49,353 9.
Margin 8,548 18,499 13,424 21,087 11,497 22,772 11,731 25,135 11,049 24,481
- 10. Gross Fargin 0 3,878 0 3,824 0 4,530 0 5,145 0 5,123
- 11. Scheduled Outages 11,497 18,242 11,731 19,990 11,049 19,358
- 12. ?:et Faroin (10-11) 8,548 14,621 10,424 17,263
- 13. Net Margin as Per ent of Demand (9) 20.9 50.0 23.9 55.4 24.8 55.0 23.7 56.6 21.1 51.3 laR4 1985 1986 1987 1988 Summer Winter S umne r Winter S umme r Winter Summer Winter Summer Winter Pesources 66,924 67,948 70,394 71,271 74,598 75,156 77,386 77,808 80,237 81,301
- 1. Net Dependable Capability 3,R18 3,977 3,409 4,083 3,289 4,446 3,652 4,702 3,908 4,518
- 2. All Scheduled Purchases 3,997 3,307 3,797 2,911 3,488 3,442 4,319 3,286 3,784 3,503
- 3. All Scheduled Sales 74,811 78,781 77,919 81,844 81,631 67,464 67,038 71,191 70,776 75,541
- 4. Total Resources (1+2-pfy 40 0 40 0 40 0 40 0 40 0
- 5. Inoperable capability 70,736 75,541 74,771 78,781 77,879 81,844 81,591
- 6. Operable Resources (4-5) 67,464 66,998 71,191 Demand 69,987 50,330 55,679 39,978 59,081 42,407 62,559 44,918 66,200 47,563
- 7. Peak Hour Demand 115 115 115 115
- 8. Interruptible Demand 115 115 115 115 115 115 55,564 39,863 58,966 42,292 62,444 44,803 66,085 47,448 69,872 50,215
- 9. Demand Pecuirements (7-8)
Margin 31,376 11,900 27,135 12,225 28,444 13,097 29,968 12,696 30,431 11,972
- 10. Grcss Faroin 0 0 0 0 0
- 11. Scheduled Outages 0 0 0 0 0 11,900 27,135 12,225 28,444 13,097 29,968 12,696 30,431 11,972 31,376
- 12. Ne t Fa rg in (10-11) 17.1 62.5
- 13. Net Margin as Percent of Demand (9) 21.4 68.1 20.7 67.3 21.0 66.9 19.2 64.1 I'ISummer-1979 is June throuch September, Winter-1479 is December 1979 through March 1980 (b) Unavailable due to lack of fuel, manpower, etc.
Source: Southwest Power Pool, 1979 O O O
I WCCS-ER(OLS)
/^'T TABLE 1.1-10 I
( SOUTHWEST POWPR POOL LONG RANGE PEAK DEMAND, RESOUFCES AND RESERVF 1989-1998 IN MW Peserve Increase Resources as % Peak Hour- Per Year To Serve of Peak Year Demand % Demand Reserve Demand 1989 74,144 5.9 87,952 13,708 18.5 1990 78,363 5.7 92,735 14,372 18.3 1991 82,568 5.4 97,726 15,158 18.4 1992 87,049 5.4 103,311 16,262 18.7 1993 91,776 5.4 107,821 16,045 17.5 1994' 96,748 5.4 114,564 17,816 18.4 ( 1995 102,701 6.2 120,917 1P,216 17.7 1996 107,116 4.3 126,946 19,830 18.5 1997 112,845 5.3 133,970 21,125 18.7 1998 118,911 5.4 139,208 20,297 17.1 STATEMENT OF PROJFCTED CAPABILITY ADDITIONS DURING THIS PEPIOD Unknown Hydro Nuclear Fossil or Other Total Percent 0.4 24.7 74.2 0.7 100.0 Source: Southwest Power Pool, 1979 O G 1 1
WCCS-EP (O LS ) TABLP 1.1-12 KG&E FYSTEM !.OADS, ANNUAL SYSTFM FNFPCY' AND PEAK DEMAND ACTUAT. 1968-1979 PROJECTED 1980-1990 Annual Summer
- Winter
- Annual Ene rgy Increase Peak .
_ Increase Peak System - Year (CWN) 59H t Demand (MW) MW 4 Demand (>W) 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 5,316 '358 6.9 1,202 65 5.7 829 52.4 1974 5,799 283 5.1 1,325 123 10.2 867 50.0 1975 6,199 400 6.9 1,337 12 1.0 1,003 52.9 1976 6,442 243 3.9 1,387 50 3.7 1,016 52.9 1977 6,685 243 3.8 1,423 36 2.6 1,056 53.6 1978 7,184 499 7.5 1,533 110 7.7 1,120 53.5 1979 7,189 5 0.0 1,473 3.9 1,160 55.7 1980 7,451 536 3.C 1,585 112 7.6 1,140' 53.7 1981 7,489 116 0. 5 1,645 60 3.8 1,195 52.0 1982 7,735 347 3.3 1,710 65 4.0 1,245 51.7 1983 8,068 323 4.3 1,790 80 4.7 1,300 $1.5 1984 8,417 312 4.3 1,875 85 4.7 1,355 51.3 1985 8,716 328 3.6 1,950 75 4.0 1,415 51.0 1986 8,969 403 2.9 2,010 60 3.1 1,465 51.0 1987 9,330 319 4.0 2,075 65 3.2 1,520 51.3 1988 9,613 337 3.0 2,125 50 2.4 1,585 51.6
"'N 1989 9,917 385 3.2 2,175 50 2.4 1,650 52.0 1990 10,209 405 2.4 2,230 55 2.5 1,715 52.3 i
Summer is the period from June through September Winter is December through March of the following year }
WCGS-ER(OLS) TABLE 1.1-13 FCPL SYSTEM LOADS ANNU AL SYSTEM ENFPCY AND PEAK DEM AND ACTUAL 1968-1979 PROJECTED 1980-1990 A nnua l Summer (b) Winter (b) Annual Ene rgy Increase Peak Increase Pe ak System Y3cr (CWH) GWF t Denand (FW) FW % Demand (FW) Load Factor 1968 5,552 476 4.4 1,276 60 7.6 864 49.7 1969 5,889 337 6.1 1,409 133 10.4 807 47.7 1970 6,324 435 7.4 1,499 90 6.4 96 5 48.2 1971 6,641 317 5.0 1,574 75 5.0 1,017 4R.2 1972 7,174 533 8.0 1,676 102 6.5 1,117 48.9 1973 7,598 424 6.0 1,757 81 4.8 1,091 49.4 1974 7,556 0.6 1,907 150 8.5 1,106 45.2 1973 7,857 301 4.0 1,903 -4 -0.2 1,165 4 '.1 1976 0,026 169 2.1 1,920 17 0.8 1,215 47.7 1977 8,452 426 5.3 1,980 60 3.1 1,276 48.7 1978 9,011 559 6.6 2,097 117 5.9 1,312 49.1 1979 8,851 - 160 -1.8 1,964 -133 -6.3 1,365 53.8 1580 9,630 779 8.8 2,157 193 9.8 1,418 51.0 1981 10,016 386 4.0 2,235 78 3.6 1,474 51.2 1982 10,417 401 4.0 2,315 80 3.6 1,550 51.4 1983 10,832 415 4.0 2,398 83 3.6 1,635 51.6 1984 11,267 435 4.0 2,485 87 3.6 1,720 51.8 1!83 11,717 450 4.0 2,574 89 3.6 1,810 52.0 1986 12,186 469 4.0 2,667 93 3.6 1,905 52.2 1961 12,673 487 4.0 2,763 96 3.6 2,005 52.4 1988 13,179 506 4.0 2,P62 09 3.6 2,105 52.6 1989 13,707 528 4.0 2,965 103 3.6 52.8 1990 14,225 548 4.0 3,072 107 3.6 53.0 I*I Crowth rates beyond 1990, out to 2010, are projected at 4.0 percent f r annual energy and 3.6 percent for summer peak load (b) Summer is the period from June through September Winter is December through March of the following year O
a WCCS-ER(OL3) , TABLP 1.1-14" f,_s KEPCO SYSTEM LOADS, ( ~ ANNUAL SYSTFM ENERGY AND F/AK DEMAND f- ACTUAL 1971-1979 AND PPOJFCTED 1980-1995 I Annual S ummerI
- I WinterI *'
Energy - Increase Peak Increase Peak Year (GWH) Gwn t Demand (MW) MN t Demand (NW) 1 1971 1,031.9 202.8 213.4 1972 1,108.3 76.4 7.4 219.6 16.P 8.3 222.6 1973 1,160.1 51.8 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 *17.6 8.7 318.5 25.1 8.6 252.2 l 1976 1,406.0 58.8 4.4 348.9 30.4 9.5 271.7 1977 1,491.3 85.3 6.1 337.4 305.1
~*1.5 -3.3 1
1978 1,640.2' 148.9 10.0~ 376.8 39.4 11.7 350.2 1979 1,842.1 201.9 12.3 413.3 36.5 9.7 347.5(h)
- 1980 2,198.5 356.4 19.3' 484.2 70.9 17.2 370.8 1981 2,332.0 133.5 6.1 514.4 30.2 6.2 1982 2,474.P 147,8 6.1 54P 4 34.0 6.6 i .1983 6.1 2,625.9 15. 1 583.4 35.0 6.4 1984 2,786.6 160.7 6.1 621.3 37.9 6.5 1985 2,957.2 170.6 6.1 661.5 40.2 6.5
^
1986 3,133.9 176.7 6.0 702.4 40.9 6.2 1987. 3,321.2 187.3 6.0 745.9 43.5 6.2 1998 3,520.0 198.8 6.0 792.1 46.2 6.2 ' 1989 3,730.9 210.9 6.0 841.4 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 1,004.7 60.0 6.3 Ll \ 1993 4,712.5 267.6 6.0 1,072.9 63.2 6.3 i 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 "I Summer is the period from June through' September. Winter is December through March of the I II""I"9 Y**#* (b) Estimated Note Data not available for years prior to 1971. 3 i ) 4 4 5
- 1. ,
i l 4 a.m we*
WCCS-E R (OTS ) TABLE 1.1-15 FUFL MIX - PRPCENTAGE DISTRIBUTION OF ANNUAL NET GFNEPATION 1970 1975 1980 - 1995 1990 EEin2 Conservative Nof41nal Conservative Fuel case Case Case Case KG&E coal - 18.3 53.2 57.2 57.2 54.2 54.2 011 0.5 14.9 3.8 0.3 0.3 11.5 15. Gas 99.5 66.8 43.0 13.7 15.9 6.6 6.6 Nuclear - - - 28.7 26.6 27.7 24.0 Total 100.0 100.0 100.0 100.0 100.0 100.0 100.0 KCPL coal 69.2 88.4 94.4 67.9 71.4 11.6 74.6 011 0.1 4.0 3.7 4.2 4.5 4.5 4.8 Gas 30.7 7.6 1.4 0.9 0.9 0.8 0.8 Nuclear - - - 27.0 23.2 23.1 19.8 Total 100.0 100.0 100.0 100.0 100.0 100.0 100.0 notre May not add 32e to rounding. O O
. . . - . . . . - . - ~. .. . - . . - . . . . - . . . . . . . . - . . , - . - -- . - - , -
L i ' WCGS-ER(OLS)- r e TABLE 1.1-16
'TPENDS IN~ FUEL" COSTS BY FUEL 1
.IN CENTS PER.MILLION BTU l t
i i Fuel. 1970 1975- 1980 1985' 1990 !, ! KG&E
! Coal -26.6 40.6 92.2 132.3 170.8 Oil 25.4 136.5' 196.7 ~ 443.6 712.9 !- Gas- 22.3 - 4 5.1. 162.6 280.5 429.0 ; Nuclear - - -
66.1 96.7 .i l l System 22.3 58.5' 126.2 133.2 227.3 ! KCPL Coal 25.3 42.4 103.5 148.7 187.4 Oil 76.2 209.7 542.0- 827.2 1271.2 i Gas 27.5 58.4 -165.0- 265.7 428.0 i Nuclear - - - 60.5 64.2 l System 26.1 50.3 122.2 159.2 216.8 l , 1 l i J I, t
-i f
.1 f
t
.,, ,+-,u...AJ.~.-..-_.A.,_4.-,.-,, ~.-.,,,.r~.c., ~ , - ,,-~-.....,~--e_, ...a,.-..,m,,-...-w,.,,-,.,--.,.--..~
WCGS-ER(OLS) TABLE 1.1-17 TRENDS IN FUEL COSTS FOR SYSTEM OPERATIONS IN CENTS PER MILLION BTU KG&F KCPL Nominal Conservative Nominal Conservative Year Case Case
- Case Case
- 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 96.0 1980 126.2 122.2 1981 134.7 137.5 1982 162.3 148.2 1983 132.8 132.8 132.0 136.6 1984 133.9 135.0 144.9 149.4 1985 133.2 138.2 159.2 164.5 1986 139.7 147.1 173.5 179.1
'987 149.1 157.6 186.3 192.5 1988 166.9 178.9 203.6 212.0 1989 184.1 196.6 204.1 210.5 1990 227.3 252.5 216.8 221.5
- For 1983 and later. Shows ef fect of two different assumptions on FCGS capacity: 65 percent for conservative case and 75 percent for nominal case.
O
. _ . _ m .
t WCGS-ER(OIS) . n 2
-/ '( TABLE 1.1-18 SYSTEM OPERATIONS,-PFAK HOUR CONDITIONS
, 1973-1979 (IN MW) , KGsF i j 1973 1974 1975 1076 1977 1978 1979 Peak Date Aug. 20 Jul 22 . Jul 21 Aug 10 Jul ;2:0 Aug 17 Aug 6 Peak Hour' 4-5 pm 4-5 pn 3-4 pm 4-5 pm 4-5 pm 5-6 pm 4-5 pm Net Generation 1126.5 1259.2 1268.4 1260.2 1539.4 1531.4 1361.4 Purchases Firm Contract + 150.0 + 150.0 + 140.0 + 213.0 + 248.0 + 147.0 + 115.0 Emergency + 110.0 + 40.0 + 217.0 + 460.0 + 275.0 0 + 230.0 Total + 260.0 + 190.0 + 357.0 .+ 673.0 + 525.0 + 147.0 + 345.0 Sales-Firm Contract - 80.0 - 90.0 - 40.0 - 73.0 - 269.0 - 105.0 - 15.0 Municipals - 16.6 - 3.6- - 30.0 - 59.2 - 48.0 - 48.8 - 55.0 Fme rgency - 70.0 - 15.0 - 222.0 - 405.0 - 325.0 0 - 190.0 Total - 166.6 - 108.6 - 292.0 - 537.2 - 642.0 - 153.8 - 260.0 Inadvertent - 18.0 - 16.0 + 4.0 - 9.0 + 3.0 + 8.0 + 27.0 Net Inter- + 75.4 + 65.4 + 63.0 + 126.8 - 116.0 + 1.2 + 112.0 change Net Load 1201.9 .1324.6 1337.4 1387.0 1423.4 1532.6 1473.4 KCPL s/ Peak Date Aug. 20 Jul 19 Aug 21 Aug 10 Aug 8 Aug 25 Aug 7 Peak Hour 3-4 pm 3-4 pm 3-4 pm 2-3 pm 4-5 pm 5-6 pm 4-5 pm Net Generation 1678 1558 1660 1598 1419 1635 1687 Interchange Received r Firm + 210 + 243 + 231 + 288 + 16 9 + 196 + 25 1 Non-Firm + 80 + 15 2 + 60 + 320 + 545 + 425 + 440 Total + 290 + 395 + 291 + 608 + 714 + 621 + 465 Delivered Firm - 143 - 95 - 94 - 176 -- 78 - 84 - 27 Non-Firn - 70 0 - 1 - 92 - 17 - 14 - 175 Total - 213 - 95 - 95 - 268 - 95 - 98 - 202 i i Inadve rtent + 2 + 49 + 47 - 18' - 58 - 61 + 14 Net Inter- + 79 + 349 + 243 + 322 + 561 + 4 62 + 277 change Net Load 1757 1907 1903 1920 1980 -2097 1964 v
WCCS-ER(OLS) TABLE 1.1-19 NUPPER AND GPOWTH OF RESIDENTIAL CUSTOMERS KG&E KCPL KFPCo Year End Growth _ Average Growth Average Growth No, for No. for for No. for for Yea r % 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 2.5 278,073 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 1.7 289,376 1.4 76,919 2.3 1978 194,773 2.4 293,402 1.7 77,974 1.4 1979 200,024 2.7 297,256 1.3 79,736 2.26 1980 204,497 2.2 301,686 1.5 81,540 2.26 1981 208,342 1.9 305,923 1.4 83,048 1.85 1982 212,282 1.0 310,590 1.5 84,585 1.85 1983 216,324 1.9 315,354 1.5 86,149 1.85 1984 219,657 1.5 320,221 1.5 87,743 1.85 1985 223,056 1.5 89,400 1.88 1986 226,366 1.5 01,054 1.85 1987 229,646 1.4 92,738 1-SS 1988 232,760 1.4 94,454 1.85 o KEPCo data not available for earlier years. O
l WCGS-ER(OLS) V( TABLE 1.1-20 TREffDS IN USE OF' ELECTRICITY
- i RESIDENTIAL ELECTRIC HEATING Electric Heating Customers Annual Consumption ~of Energy For Year. Number Percentage Home- with Elec. Homes without
! Ending of Total Res. Spaso deating Flec. Space
'(KWH) Heating (KWH)
Kansas Gas & Electric Company l 1 1969 4,522 2.7 18,133 6,168 1970 5,197 3.1 20,566 6,87e ; i 1971 5,814 3. 5 ' 20,455 6,835 1972 7,411 4.4 19,698 7,151 j 1973 9,155 5.3 20,066 7,554 l 1974 12,833 7.2 18,319 7,427 1975 15.293 8.5 21,136 7 ,~ 9 2 9 , 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 l p Kansas City Power and Light 1969 3,887 ~1.5 - l 1970 4,803 1.9 19,395 1971- 6.043 2.3 18,220 j 1972 6,749 2.5 18,454 1973 7.348 2.7 .18,940 1974 7,911 2.8 18,248 1975 8,633 3.1 20,709 1976 9,278 3.3 19,441 l 1977 10,286 3.6 19,726 l 1978 11,105 3.8 21,637 Kansas Electric Power Cooperatives 1974 3,741 5.2 i 1975 4,863 6.6 1976 4,749 6.3 1977 5,267 6.8
. 1978 5,474 7.0 k
- Missing data are not avail a ble.
O-i 4 g -yc . y- ,rrw y- - v- t w v'r--1= -w T- 4--== r-wt- -T-t=r-v* wrt- -'n'a'**--- dew y - + ' ' w=- t++---r--ew.= *W',Ta warve*my e * ' r% w'-~w-+-wa-tmre--w--eee-w-
WCCS-PR(OLS) TABLE 1.1-21 h AVERAGE ANNUAL CONSUMPTION OF ENFFC-Y BY RESIDENTIAL CUSTOt1EPS 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 9,573 1975 9,150 9.7 8,166 10.0 9.016 5.2 1976 9,090 - 0.7 7,717 - 5.5 9,317 3.3 1977 4.413 3.6 7,920 2.6 9,309 - 0.1 1978 10,136 7.7 8,404 6.1 10,017 7.6 1979 9,889 - 2.4 8,560 1.9 11,154 11.4 1980 10,049 1.6 8,560 0 12,420 11.4 1981 10,149 1.0 8,740 2.1 12,971 4.4 1982 10,289 1.4 8,930 2.2 13,547 4.4 1983 10,415 1.2 9,140 2.4 14,149 4.4 1984 10,542 1.2 4,350 2.3 14,777 4.4 1985 10,680 1.3 15,433 4.4 1986 10,818 1.3 16,118 4.4 1987 10,965 1.4 16,834 4.4 1988 11,133 1.5 17,582 4.4 Earlier data not available. i l 1 1 0
N WCGS-ER(OLS) I TABLE 1.1-22 !( L DISTRIBUTION OF - EFEPGY CONSUMPTION BY CATEGORY - ACTUAL.1964-1979, PROJECTED 1984 IN PFRCENT Year Category 1964 1969 1974 1979 1984 l i . Kansas Gas & Electric Company ' Residential .22.5 19.4 24.9 25.4 24.4 Commercial 17.5 14.8 18.6 19.4- 20.5-i Industrial 45.0 32.1 ~38.2 37.7 37.7 a I i Kansas City Power and Light Company ! Residential 25.9 28.2 29.7 28.7 29.9 Commercial 37.5 38.8 38.0 37.7 36.6 Industrial 32.1. 28.9 28.0 28.7 28.4 Kansas Electric Power Cooperatives I
- Residential 58.2 54.2 45.6
~7mm. & Ind. 35.9 37.4 43.2 Irrigation 4.0 7.5 9.7 4
Earlier data not available. 1984 distribution includes a that of energy sold to Sunflower Cooperative. e t i r i l' LO
TABLE 1.1-23 AVERACE ANNUAL COSTS BY CONSUMEP CATECOPY 1971-1984 IN CENTS PFP KWF*
- KG&E ~~
KCPL M(PCc Commercial & Year Residential Commercial Industriel, 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 E 1976 2.82 2.86 1.91 3.86 3.28 2.20 3.80 3.24 3.78 O 1977 3.43 3.45 2.43 4.10 3.52 2.39 4.28 3.68 4.59 O 2978 3.78 3.82 2.72 4.54 3.90 2.67 4.72 4.19 5.32 8 1979 3.99 4.05 2.93 4.94 4.21 2.96 5.10 4.!1 5.71 $ 1980 4.07 4.13 3.01 5.64 4.89 3.49 'g 1981 4.15 4.21 3.09 5.88 5.13 3.72 f 1982 4.27 4.33 3.21 5.73 5.01 3.61 1983 4.17 4.23 3.11 5.54 4.84 3.47 1984 5.57 4.89 3.51 Actual through 1978. Estimated thereafter.
- Missing data are not available .
O O O
~ q j WCCS-ER(OLS) \
TABLE 1.1-25 FG&P COMPARISON OF FORECAST AND ACTUAL PFAR LOADS AND ENERGY BY YEARS 1972-197F AND MONTHS 1977-1979 Forecast Peak Load Forecast Energy Sales r Month & Date Made Forecast Actual Difference Dato Forecast Actual Difference Year MW MW % GWH GWH % 1:72 12/21/71 1130 1137 --0.6 12/21/71 5209 5225 - 0.3 1973 *
- 1202 * *
- 5516
- 1974 1/10/74 1350 1325 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 2/18/76 1460 1387 5.0 2/18/76 6845 6442 5.9 1977 2/21/77 1495 1423 4.8 2/21/77 6776 66R5 1.3 1978 4/11/78 1540 1533 1.5 4/11/78 7231 71P4 0.4 1979 3/29/79 1585 1473 7.1 3/29/79 7629 Jan 1977 1/20/77 1020 1016 0.4
- 596
- Feb 956 934 2.3 4P2 Mar 897 872 2.8 507 j Apr 867 847 2.3 469 May 1030 943 8.6 509 ,
Jun 1300 1276 1.8 617 Jul 1495 1423 4.8 731 Aug 1495 1404 6.1 657 Sep 1375 1180 14.2 553 oct 1020 804 21.2 490 g Nos 971 906 6.7 506 De: 1047 1039 0.8 56P Total 6685 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 P12 6.5 514 475 7. 6 May 1060 1 17 - 5.4 560 527 5.9 Jun 1340 1379 - 2.9 629 623 0.3 Jul 1540 1491 3.2 767 787 - 2.6 Aug 1540 1533 0.5 737 743 - 0.R Sep 1400 1458 - 4.1 581 655 -12.3. Oct 1050 954 9.1 561 525. 6.4 Nov 2000 987 1.3 559 535 4.3 Dec 1080 1112 - 3.0 619 606 2.1 Total 7213 7184 0.4 Jan 1979 2/14/79 1120 1120 0.0 12/31/78 66 669 - 1.2 Feb 1100 1098 0.2 572 575 - 0.5 Mar 1020 940 7.8 5*6 552 7.4 i Apr 920. 915 0.5 540 502 7.0 May 1100 967 12.1 F34 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 47 Nov 1040 1032 0.8 594 557 6.6 Dec 1160 1060 9.4 643 596 7.9 Total 7629 7189 6.1
- U ,
Not available f
- - . , , - - , - - , . - - . .,~ , . , . , , . , . . .n-.-. - . ,, ., . . - - - , - , - - ,, .----..
FCCS-FR(OaE) TABLE 1.1-26 XCPL COMPARISON OF FORFCAST AND ACTUAL UAK LOADS ANQ FNFRGY BY YFARS 1472-1979 AND MONTHS 1977-1978 Forecast Peak Load Forecast Energy Cales Month & Date Made Forecast Actual D i f fe rence Date Forecast Actual Di f fe rence Year MW MW % GWH GWH % 1972 10/21/71 1700 1676 1.4 10/27/71 6573 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 1.8 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 4/26/77 8366 8359 0.1 11/09/76 11/09/76 Jan 1977 1205 1215 - 0.8 633 656 - 3.6 Feb 1215 1156 4.9 598 624 - 4.4 Mar 1140 1106 3.0 581 614 - 5.7 Apr 1175 1178 - 0.3 588 549 6.6 May 1470 1403 4.6 604 590 2.3 Jun 18$5 1670 10.0 629 655 - 4.1 Jul 2035 1956 3.9 769 801 - 4.2 Aug 2035 1980 2.7 828 820 1.0 Sep 1910 1641 14.1 876 758 13.5 Oct 1285 1108 13.R 691 647 6.4 Nov 1210 1183 2.2 641 579 9.7 Dec 1260 1255 0.4 631 607 3.8 Total 8069 7900 2.1 11/26/77 11/26/77 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 r 1215 1156 4.9 590 618 - 4.8 1530 1500 2.0 613 587 4.2 .an 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 Sp 2005 2050 - 2.2 87P 871 0.8 Oct 1325 1254 5.4 700 734 - 4.9 Ncv 1255 1243 1.0 645 637 1.2 Dec 1300 1286 1.1 646 657 - 1.7 Total 8366 0359 0.1 e Due to a strike no forecast was made for 1979 in 1978. O
i > 1 WCGS-ER(OLS) f TABLE 1.1-27 i KG&E and KCPL I
- INTERCHANGE BUDGET FOR 1983-84 1
, KG&E j- 1983 1984 Energy Capacity Energy Capacity i[ In MWH _In MW- In MWH In MW } l Purchases i i Firm 0 0 0 0
-Non-firm 400,000 0 400,000 0 1
o t h .' 400,000 0 400,000 0 1 .a Sales j Firm 240,000 55 '240,000 70 Non-firm 760,000 50 760,000 '30 i Total 1,000,000 105 1,000,000 100 4 4-i KCPL l 3 Purchases Firm 59,250 25 59,250 25 i l + Non-firm 310,739 -
'346,739 -
Total 369,989 25 405,989 25 j Sales 1 Firm 58,065 25 58,065- 25 s l Non-firm 574,600 - 572,400 - Total 632,665- 25 630,465 25'
? ! t l
I i n i
WCCS-FR(OIS) TARLr 1.1-28 KC&P MONTHLY LOADS AND INTERCHANCE, FIRST TF0 YFARS WITH FCCS IN SERVICT Year Month Peak (MW) E ne rg y (1000 MWH) Purchases (1000 MWR) Sales (1000 MWH) 1983 Jan 1250 740 60 90 Feb 1253 620 60 90 trch 1150 618 30 80 April 1040 570 20 80 May 1240 600 20 70 June 1580 705 30 80 July 1790 830 40 70 August 1790 784 40 70 Sept. 1690 670 20 80 O ct . 1130 590 20 90 Nov. 1170 645 20 100 Dec. 1300 696 40 100 1984 Jan. 1310 772 60 90 Feb. 1290 647 60 90 March 1200 645 30 80 April 1090 595 20 80 May 1300 625 20 70 June 1650 735 30 80 July 1875 865 40 70 August 1875 820 40 70 Sept. 1770 695 20 80 oct. 1180 615 20 90 Nov. 1225 675 20 100 1 i Dec. 1365 728 40 100 0
t 2 WCCS-PR(OLS) TAPtf 1.1-24 , KCPL , MONTHLY LOADS AND INTERCHANGE, FIPST TWO YFARS WITH WCCS !N SEPVICE i l par Month Peak (MW) Energy (1000 MWM) Purchases (2000 MWH) Sales (1000 MWp) {' 1983 March 1445 778 27 48 ) April 1416 743 1 48
- May 1784 784 9 50 I June .2282 960 16 46
- July 2348 1111 24 46
, A urm s t 2348 1136 30 49 i
i Sept. 2388 899 10 46 .I i Oct. 1510 796 11 50 } Nov. 1510 731 13 46 Dec. 1442 788 5 50 1 1 1 1984 Jan 1485 801 28 48 ' i l J c'eh. 1496 778 28 46 , March 1469 789 34 48 April 1478 753 29 48 ^ Pay 1827 804 17 48 I June 2:68 1002 36 48 i j July 2.85 1135 38 46 i j August 2485 1174 43 48 l Sept. 24'i4 918 30 46 Oct. 1539 815 21 50 Nov. 1456 735 16 46 ! Dec. 1466 777 30 4R l 1 i i i i I O I i , l
WCCS-EP(OLS) TABLE 1.1-30 PPOJrCTED FFEL MIY FIPST THPEE YEAPS OF PLANNFD OPERATIONS WI"H AND WITPOUT WCCS (TOTAL GENFP.ATION) IN PERCENT Nominal Case Crnse rvative Case 1983 1984 1985 19R3 1984 1985 Puel Type With Without With Without With Without With Without With RTO out With Without WCCS WCCS WCGS WCGS WCGS WCGS WCCS WCGS WCGS WCCS WCCS WCCS KG&E Coal 55.6 55.6 56.7 56.7 57.2 57.2 55.6 55.6 56.7 56.7 37.2 57.2 011 0.5 11.2 0.4 13.7 0.3 15.3 0.5 11.2 0.4 13.7 0.3 15.3 Cas 22.6 33.1 18.0 29.6 13.7 27.4 22.6 33.1 18.5 29.6 15.9 27.4 Nuclear 21.3 0 25.0 0 28.7 0 21.3 0 24.4 0 26.6 0 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 KCPL Coal 67.6 92.6 68.4 92.5 67.9 90.9 71.7 92.6 72.0 92.5 71.4 90.4 Oil 2.9 5.5 3.4 5.7 4.2 6.9 3.1 5.5 3.6 5.7 4.5 6.9 Gas 1.1 1.9 0.8 1.8 0.9 2.2 0.9 1.9 0.9 1.8 0.9 2.2 Nuclear 28.4 - 27.4 - 27.0 - 24.3 - 23.5 - 23.2 - 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. O O O
WCGS-ER(OLS) TABLE 1.1-31 PROJECTED FUEL MIX PEAK DAY GENERATION PERCENTAGE DISTRIBurluN 1985 1990 Fuel 1980 With Without with Without WCGS ..cdS WCGS WCGS 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 100 100 100 100 100 KCPL Coal 85 77 77 79 79 Oil 8 3 15 5 12 Gas 7 3 3 2 2 Nuclear - 17 0 14 0 Purchases 0 0 5 0 7 Total 100 100 100 100 100
\
WCGS-f R (O LS ) TABLE 1.1-32 KCEE ACTUAL AND PROJFCTPD PUFL COSTS 1979-1990 Month coal Oil Gas Nucle ar System & Year $/ Ton C/MMBTU $ Pb1 C/MMBTU $ /MC P C /MMBTU C/MMBTU C/MMBTU 1979 Jan 15.37 84.83 10.93 173.49 1.40 140.00 - 116.44 Feb 15.55 85.78 11.10 176.19 1.42 142.00 - 115.30 Mar 16.35 86.62 11.19 177.62 1.44 144.00 - 133.44 Apr 15.99 89.97 11.29 179.21 1.48 148.06 - 128.89 May 15.75 88.22 - - 1.49 149.30 - 112.45 Jun 16.11 89.18 11.1 176.67 1.51 151.28 - 118.53 Jul 16.14 89.70 11.11 176.35 1.52 152.52 - 122.26 Aug 16.45 91.96 11.05 175.40 1.54 153.52 - 121.61 Sep 16.44 91.26 - - 1.55 154.78 - 119.25 O ct 16.44 92.04 11.02 174.92 1.56 155.91 - 133.62 Nov 16.95 95.18 11.12 176.51 1.5R 158.25 - 124.56 Dec 17.29 97.19 11.13 176.67 1.62 162.00 - 127.96 1980 Jan 15.84 91.52 12.27 194.76 1.36 138.00 - 139.15 Feb 15.83 91.41 12.64 200.63 1.38 140.00 - 125.56 Mar 16.48 90.34 13.06 207.3G 1.57 158.83 - 132.99 Apr 16.19 90.30 - - 1.52 154.51 - 117.85 May 16.11 92.54 - - 1.58 159.95 - 125.13 Jr-a 16.21 91.75 - - 1.61 163.93 - 117.02 Jul 16.14 91.99 - - 1.66 168.29 - 121.54 Aug 16.05 91. 71 - - 1.68 170.08 - 126.83 Sep 16.20 92.20 - - 1.67 168.88 - 122.'5 Oct 16.16 94.47 - - 1.71 173.10 - 139.55 Nov 16.58 93.56 - - 1.68 170.13 - 123.48 Dec 16.38 94.28 - - 1.68 171.05 - 122.63 By Year 1979 16.17 90.18 11.12 176.41 1.50 151.64 - 122.72 1980 16.16 92.23 12.39 196.67 1.60 162.61 - 126.19 1981 16.78 95.85 15.87 251.40 1.84 186.64 - 134.73 1982 19.26 109.61 21.00 333.33 2.12 214.51 - 162.32 1983 20.70 11R.12 23.10 366.67 2.33 236.04 63.95 132.75 1984 21.91 125.85 25.41 403.33 2.53 257.05 55.09 133.89 1985 23.07 132.25 27.95 443.65 2.76 '20.49 66.07 133.16 1986 24.14 139.00 30.75 488.10 3.09 313.53 75.09 139.71 1987 25.23 145.45 33.82 536.83 2.43 348.32 84.02 149.12 1988 26.64 153.20 37.20 590.48 3.79 384.39 87.41 166.*3 1989 28.07 162.00 40.92 649.52 4.12 417.95 91.52 184,11 1990 29.68 170.82 42.10 712.93 4.23 429.00 96.70 227.35 O
FCGS-FR(OLS) [m\ TABLF 1.1-33 ('/ !
'+ KCPL ACTUAL AND PROJFCTED FUEL COSTS 1979-1990 Month Coal Oil Cas Nuclear System
& Year T/ Ton C/MMBTU $ Bb1 C/MMBTU $/MCP C/MMBTU C/MMBTU C/MMBTU 1979 Jan 15.20 77.03 15.11 264.38 4.07 642.11 88.97 Feb 15.55 78.19 15.34 268.49 1.23 132.69 94.30 Mar 16.77 33.39 14.87 263.62 0.99 130.66 93.56 Apr 16.76 il4.95 14.88 260.68 0.84 130.93 93.67 May 16.21 03.76 13.48 250.44 1.01 127.82 92.42 Jun 16.56 E4.51 15.25 268.22 1.10 131.49 98.65 Jul 16.52 85.23 15.27 268.80 1.09 131.21 98.35 Aug 16.83 83.87 15.40 268.72 1.14 130.99 97.12 Sep 16.85 8t.67 13.50 141.79 1.05 131.97 95.93 Oct 17.58 90.87 15.27 263.53 1.06 128.22 106.10 Nov 16.45 86.69 14.75 250.01 0.P1 132.65 97.54 Dec 17.02 87.67 12.50 202.19 1.00 130.77 13.84 1480 Jan 17.55 91.47 31.37 544.41 0 0 110.86 Feb 18.62 96.96 30.93 535.34 0 0 120.78 Mar 19.19 99.44 30.73 532.67 1.56 164.35 129.00 Apr 18.29 95.65 31.23 537.47 1.56 165.04 123.38 May 17.89 96.49 32.06 556.09 1.57 165.38 113.49
,~s Jun 18.20 97.86 31.76 545.23 1.57 164.90 115.91
/ \ Jul 18.37 98.51 31.80 543.77 1.57 165.10 116.09
'/ Aug 18.15 98.22 31.82 552.84 1.57 164.95 111,75
(\~ Sep 18.83 100.81 31.93 546.39 1.56 164.58 113.42 Oct 18.83 102.57 30.97 537.35 1.57 164.46 122.66 Nov 18.20 99.87 32.48 555.13 1.60 160.00 112.30 Dec 19.17 102.20 31.59 544.35 0 0 118.56 Py Year 1979 16.6 84.5 15.0 263.2 1.07 132.3 96.0 1980 19.3 103.5 31.5 542.0 1.57 165.0 122.2 1981 21.5 115.9 34.1 586.9 1.72 181.5 137.5 1982 23.1 124.1 37.2 641.5 1.90 194.6 148.2 1983 24.4 132.6 41.1 709.7 2.09 219.7 59.1 132.0 1984 26.1 141.6 44.4 765.5 2.22 241.7 59.8 144.9 1985 27.3 148.7 48.0 827.2 2.53 265.7 60.5 154.2 1986 28.7 156.4 52.0 897.1 2.78 292.3 61.2 173.5 , 1987 30.2 164.5 56.6 975.1 3.05 321.5 62.0 186.3 1988 32.0 174.2 61.2 1055.7 3.36 353.6 62.7 203.6 1989 32.3 178.6 67.6 1164.9. 3.70 389.2 63.5 204.1 1990 33.9 187.4 73.7 1271.2 4.06 428.0 64.2 216.8 o
i l I WCGS-E P (OI.S ) TABLE 1.1-34 FUEL COSTS AS A PERCENTAGF OF '"OTAI. OPEPATING COSTS 196P-1984 Year KG&F** FCPI, 1968 22.6 33.2 1969 24.8 45.6 1970 24.7 51 . 1 1971 25.6 53.6 1972 25.1 51.5 1973 27.5 50.7 1974 30.7 57.5 1975 39.8 5 4 . r. 1976 37.5 60.0 1977 45.2 67.6 1978 48.1 66.9 1979 54.3 1980 70.2 1981 74.1 198' 74.7 1983 76.1 1984 75.8 Outages caused this anonaly
** Missing data are not available O
. . - . . =-
l l O 100 - 90 80 - To -
$ 60 -
8 3 50 - a E
- s 40 -
so - 20 - 10 - 0 ' ' ' ' ' ' ' ' ' O 10 20 30 40 50 60 70 80 90 100
% TIME i
WOLF CREEK GENERATING STATION UNIT NO. I ENVIRONMENTAL REPORT 00PERATING LICENSE STAGE) FIGURE 1.1-1 KG&E LOAD DURATION CURVE 1983
.- . _ _ .- _ _ _ _ . _ - ~ _ _ . ._- _ _ _ . . _ _ . _ . . _ _ _
i t oo - O 90 80 - 70 - T 60 - 9 50 - 2 2 40 - <r s 4 o 30 - 20 - 10 -
' i i i i i i i ,
O O 10 20 30 40 50 60 70 80 90 goo
% TIME WOLF CREEK GENERATING STATION UNIT NO. I OMRONMENTAL REPORT OPERATING LICENSE STAGED l FIGURE 1.1-2 j
KGaE LOAD DURATION CURVE ' 1984
O 100 - l-90 ' 80 - kO 8 70 - cr 8 x 60 - 1 4
$ 50 -
da g 40 - 4 O 30 - t W 20 - 10 - O ' ' ' ' ' ' ' ' ' O 10 20 30 40 50 60 70 80 90 10 0 PERCENT OF TIME WOLF CREEK GENERATING STATION UNIT NO. I ENVIRONMENTAL REPORT OPERATING LICENSE STAGED FIGURE 1.1-3 O- KCPL LOAD DURATION CURVE 1983-1984 l '___. _ _- ,. _ . ,_ _ . ._ _ , __, __-___ ___ - .--~ ,- .. _. ,_... _ _ __ --_ . . - ..._.- .. ---- .._.- -__ .
O ioo - so 80 - N y 70 - b so - 5, E so - t m 40 - S < 30 - 20 - io - o ' ' ' ' ' ' ' ' ' o lo 20 3o 4o So Go 70 80 90 loo TIME AS A PERCENT OF THE YEAR l WOLF CREEK GENERATING STATION , UNIT NO. I ONIRONMENTAL REPORT OPERATING LICENSE STAGE) FIGURE 1.1-4 KEPCo LOAD DURATION CURVE 1983-1984
a- - %-a a-._--a m , ,.m-l l i l J 1800 - i 1600 - i j 1400 - I j 1200 - 5 i 2 1000-4 i 800 - l 600 - O ' ' ' ' ' ' 12M 4AM 8AM 12N 4PM 8PM 12M HOURS l 1 WOLF CREEK GENERATING STATION UNIT NO. I , ENVIRONMENTAL REPORT OPERATING LICENSE STAGO I FIGURE 1.1-5 KG&E HOURLY LOAD CURVE SUMMER PEAK DAY 1978
,m-- w--,- - , , - ,,-,,,m,. , , - ~ ,,,----~w-- ,-m-~r--,---- ,,m-e,---,,,,-w--+,r, p- --,w,w-,,,,w,-, ~., , --,m e-en-n,-,,,- , e-n,--~,> - ~ -en- m -
1600 - 1400 - 1200 - y 1000 - 3 800 - 600 - 400 -
' f 1 I e i O
12M 4AM 8AM 12N 4PM 8PM 12M HOURS WOLF CREEK GENERATING STATION UNIT NO. I ENVIRONMENTAL REPORT CPERATING LICENSE STAGE) FIGURE 1.1-6 i KG&E HOURLY LOAD CURVE l WINTER PEAK DAY 1979
,, 3 m. , 4- *d a "---
U 1200 - 1000 - 800 - 600 - 400 - 200 - O ' ' ' ' ' --J O 12M 4AM 8AM 12:! HOURS 4PM 8PM 12M WOLF CREEK GENERATING STATION UNIT NO. I ENVIRONMENTAL REPORT (OPERATING ... 4NSE ST*iE) FIGURE 1.1-7 O- KG&E HOURLY LOAD CURVE TYPICAL SPRING-FALL DAY
O 2200 - 2000 - isoo - 1600 - i4oo 3: s i2co - icoo - 800 - soo - 7, 12M 4AM 8AM 12N 4PM 8PM 12M HOURS WOLF CREEK GENERATING STATION UNIT NO. I ENVIRONMENTAL REPORT CPERATING LICENSE STAGE 0 FIGURE 1.1-8 KCPL HOURLY LOAD CURVE SUMMER PEAK DAY 1978
O 2200 - 2000 - 1800 - 1600 - 1400 - 2 1200 - 1000 800 - \ 600 - 0 7, , , , , , 12M 4AM 8AM 12N 4PM 8PM 12M HOURS WOLF CREEK GENERATING STATION UNIT NO, i ENVIRONMENTAL REPORT 10PERATING LKENSE S TAGE0 FIGURE 1.1-9 KCPL HOURLY LOAD CURVE WINTER PEAK DAY 1979
O 4 1800 - 1600 - 1400 - f2OO - 9 2 1000 - 800 600 - 6 8M (2N 4PM 8PM (2M HOURS I l l WOLF CREEK GENERATING STATION UNIT NO. I ENVIRONMENTAL REPORT CPERATING LX:ENSE STAGE) FIGURE 1.1-10 XCPL HOURLY LOAD CURVE TYPICAL SPRING-FALL DAY
O O O KCR. ; KCPL EERGY , LOAD FinCTOR DEMAM) FORECAST ANALYSIS FOECAST MlSSOURI KANSAS ENERGY ENERGY FORECAST FDRECAST I I I I I I I MISSOURI MISSOUR1 MISSOURI MISSOL t4T KANSAS KANSAS KANSAS KANSAS INDUSTRIAL :X)hSERCIAL RESIDENTIAL OTHE4 1POUSTRIAL rnasFHQAL RESDENTIAL ODet ENERGY ENERGY ENERGY ENERGY EERGY EERGY DERGY EERGY FORECAST FORECAST F0 FEAST FORECAtT FORECAST FD ECAST FCKEAST FU KCAST I I I I I I MISSOURI MISSOURI KANSAS KANSAS RESIDENTIAL RESsDENTIAL RGIDENTIAL RESIDENTIAL AVERAGE USE CUSTOMER AWRAGE USE CUS1DMER FDRECAST FORECAST FOECAST FORECAST WOLF CREEK GENERATING STATION UNIT NO. I DMRONMENTAL REPORT (PERATING LICENSE STAGE) i FIGURE 1.1-11 KCPL Econometric Model Forecast Diagram
i l ,
- s. ,
WCGS-ER(OLS) 1.2 OTHER OBJECTIVES f 9 .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. 4 l i i f i , ; ! J I I 1 1 I I f : 1 ; i i i i !,O i i i ] I i l ! l 4 i l ; i : 1 i I ! i i i l 1 . I i i l i i 1.2-1 I i i
WCGS-ER(OLS) 1.3 CONSEQUENCES OF DELAY The consequences of delay will be serious for each of the Applicants 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 MAPGINS The following table shows for KG&E and KCPL the reduced re-serve margins that will exist with a one, two, or three year delay on WCGS: RESERVE MARGINS IN PERCENT WITHOUT WCGS Year Length of Delay KG&E KCPL MOKAN SPP 1983 One year 18.3% 16.5% 14.5% 18.2% 1984 Two years 12.9 12.4 12.9 18.1 1985 Three years 15.5 8.5 14.8 17.2 With a one year delay, KG&E's margin would be within re-guirements. KCPL's would be below its internal requirement of 20 percent but within MOKAN's and _ SPP's requirements. MOKAN would fall below its margin requirement while SPP would be within its margin. However, both MOKAN and SPP are projecting capacity increases of over 30 ' percent between 1979 and 1983. It is likely that there will be delays for some of this planned capacity which means that the margins will be lower. Though not listed, KEPCo would have no owned capacity because WCGS will represent its first block of owned capacity. KEPCo will sell 60 MW of ib WCGS capacity to the Sunflower Electric Cooperative, but without WCGS the genera-tion reserve margin for the Sunflower system will drop from -49 MW to -109 MW. Sunflower plans to construct a 280 MW coal-fired unit near Holcomb, Kansas, but cons truction on that plant'has not begun, and . it is improbable that the unit will be in operation in 1983. Though power might be avail-able to KEPCo and Sunflower in the region or from adjacent regions the economic consequences would be severe since the cooperatives would have to make commitments to transmit power across the state and to purchase makeup power at rel-atively high cost. A two year delay would bring both KG&E and KCPL- below internal and pool requirements. Poth companies would be required by MOKAN to pay capacity charges because of the reserve margin deficiencies. 1.3-1
WCGS-PP(OLS) The MOKAN margin would have declined further to 12.9 per-cent, and the projected margin for S t' P would remain about the same. Of significance, though, are projected capacity increases of 37.5 percent by MOKAN and 40.0 percent by SPP in the period 1979-1984. 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 for transmission of high cost makeup power. Sunflower's position would continue to deteriorate to a -124 MW margin if the fossil plant were not on line. With a three year delay KG&E would have added capacity to bring its reserve margin within requirements, but KCPL's marg in would have declined to 8.5 percent. The MOKAN reserve margin would be below requirement, but the projected margin fo r SPP would be within requirements. Again it is noted that MOKAN and SPP margins are based on increases in capacity between 1979 and 1985 of 45 percent for MOK AN and 47 percent for SPP. It is highly unlikely that all of this capacity will be installed on schedule. KEPCo would still have no reserve margin and would have to make arrangements for purchase and transmission of high cost makeup power. By that time, it is assumed that Sunflower would have its new plant, but if not, it would have a re-serve margin of -140 MW. 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 purchase and transmission, if both are available. It is unlikely that a new coal-fired plant could be planned and constructed so as to be in operation by 1983 to 1985. The option of purchasing capacity from neighboring utilities would probably not exist. Large blocks of power would not be available; other companies in region are experiencing delays in bringing plants on line t. 't 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 cumulatives also given. l l 1 l l 1.3-2
._ .. . . . .- . . . . . . .- , .- . n. -.
4 WCGS-ER(OLS) ADDITIONAL FUEL CONFUMPTION AND COSTS WITHOUT , WCGS.AND WITH INDICATED DELAYS 1983 1984 1985 ! Fur.1 Measure One Two Cumulative Three Cumulative
- Year Year Year i Delay Delay Delav KG&E Coal (000) Bbls 1,667 2,197 3,864 2,580 6,444 Oil MMCP 10,507 12,262 22,769 14,754 37,523 Net Additional l Fuel Cost (000) $52,375 $73,927 $126,302 $96,859 $223,161 KCPL
, Coal (000) tons 1,407 1,420 2,827 1,380 4,207 5 011 (000) Bbls 574 525 1,099 607 1,076 Gas MMCP 2,035 2,046 4,081 2,792 6,873 I Net Additional l 4 Fuel Cost (000) $42,993 $46,024 $89,967 $54,760 $143,777
- l s 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 4.2 million tons of coal, 7.5 million barrels of oil and about 44.4 billion cubic fee t of gas by the two companies at a net s additionci cost of nearly $367 million. This does not include additional fuel burned by'other utilities that would supply KEPCo.
In addition, KEPCo and probably the Sunflower Electric Cooperative would be paying high costs for mah-up power 1 and transmission. , If the WCGS capacity were not added, these rates of consump-l' 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 would be incurred by the Applicants. The largest of these would be that for interest during construc-tion, or the allowance for funds used during construction
- j. (AFUDC). These costs - for plant, fuel and associated trans-mission are estimated.as follows:
1.3-3 i . __ . _ . , . -, ._, _ - - - . _ _ , , - _. . , . , _.__.___._.m. _ -
WCGS-ER(OLS) ADDITIONAL AFUDC COSTS IN MILLIONS OF DOLLARS Period of Delay Annual Cumulative One Year $115 S115 Two Years 166 281 Three Years 184 465 Property taxes would also have to be paid, amounting to more than $9 million per year. Costs for maintaining the plant in a secure condition after the completion of construction would amount to several million dollars per year. Total cumula tive costs for each year of delay are estimated as follows: COSTS INCURRED WITH WCGS DELAY Cumulative Costs Incurred Period of Lelay In Millions Of Dollars One Year $127 Two Years 306 Three Years 503 The impact of additional costs of this magnitude upon the applicants would be very serious. O 1.3-4
WCGS-ER(OLS) TABLE OF CONTLbed - CHAPTER 2.0 - THE SITE AND ENVIRONMENTAL INTERFACES Section Title Page ' l 2.1 GEOGRAPHY AND DEMOGRAPHY.................. 2.1-1 2.1.1 SITE LOCATION AND DESCRIPTION............. 2.1-1 2.1.1.1 Specification of Location................. 2.1-1 2.1.1.2 Site Area................................. 2.1-1 2.1.1.3 Boundaries for Establishing Effluent Release Limits............................ 2.1-2 2.1.2 POPULATION DISTRIBUTION................... 2.1-3 2.1.2.1 Population Within 10 Miles................ 2.1-5 4 2.1.2.2 Population Between 10 and 50 Miles........ 2.1-7 2.1.2.3 Transient Population...................... 2.1-8 2.1.2.4 Low Population Zone....................... 2.1-19 2.1.2.5 Population Center......................... 2.1-lt 2.1.2.6 Population Density........................ 2.1-11 l 2.1.3 USES OF ADJACENT LANDS AND WATERS......... 2.1-12 [ 2.1.3.1 Land Use Within 50 Miles.................. 2.1-12
- 2.1.3.1.1 General. Description....................... 2.1-12 2.1.3.1.2 Agriculture Activities.................... 2.1-13
. 2.1.3.1.3 Hunting................................... 2.1-14 2.1.3.1.4 Other uses................................ 2.1-15 2.1.3.2 Land Use Within 5 Miles................... 2.1-15 2.1.3.2.1 General Description....................... 2.1-15 2.1.3.2.2 Range 1and................................. 2.1-16 1 2.1.3.2.3 Cropland.................................. 2.1-16 2.1.3.2.4 Livestock, Dairy and Poultry l' Production................................ 2.1-16 s 2.1.3.2.5 . Woodlands................................. 2.1-17 2.1.3.2.6 Built-up Areas............................ 2.1-17 2.1.3.2.7 Recreation Areas.......................... 2.1-18 2.1.3.2.8 Wa t e r Bo d i e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 -18 2.1.3.2.9 Quarries.................................. 2.1-18 2.1.3.2.10 Zoning.................................... 2.1-18 2.1.3.2.11 -Trends and Proj ected La nd Us e . . . . . . . . . . . . . 2.1-19 2.1.3.3 Land Use'Within The Site Area............. 2.1-20 2.1.3.3.1 General Description....................... 2.1-20 2.1.3.3.2 P r ev io us Land Us e . . . . . . . . . . . . . . . . . . . . . . . . . 2.1-2 0 2.1.3.3.3 Land Use capabilities..................... 2.1-21 2.1.3.3.4 ' Projected Land Use and Visitors
] Center..................................... 2.1-22 A( i 1 2.0-i (
,-.-.%- - - -c,, _.g,,-,,, .- ,..,w. n .- . , - , - - , , - - , , , , . .,-a r - w. +-i *----*%.<-4--w 1 . . - - + -* - -
- om-.*,- -, - - - - -w a
WCGS-ER(OLS) TABLE OF CONTENTS (continued) Section Title Page O 2.1.3.4 Water Use Within 50 Miles................. 2.1-22 2.1.3.4.1 Municipal, Industrial, Irrigation and Re c rea t io n Us e s . . . . . . . . . . . . . . . . . . . . . . . 2.1-2 2 2.1.3.4.2 Commercial and Recreational Fish Harvest.............................. 2.1-23 2.1.3.5 Water Use Within 5 Miles.................. 2.1-24 2.1.3.5.1 Municipal, Industrial, Irrigation and Recreation Uses....................... 2.1-24 2.1.3.5.2 Recreational Fishing...................... 2.1-25 2.
1.4 REFERENCES
................................ 2.1-26 2.2 EC0 LOGY................................... 2.2-1 2.2.1 TERR ESTR I A L ECOLOGY . . . . . . . . . . . . . . . . . . . . . . . 2. 2-1 2.2.1.1 Vegetation................................ 2.2-1 2.2.1.1.1 Environmental Stresses.................... 2.2-1 2.2.1.1.2 Site Community Types...................... 2.2-2 2.2.1 2 Wildlife.................................. 2.2-4 2.2.1.2.1 Mammals................................... 2.2-4 2.2.1.2.2 Birds..................................... 2.2-6 2.2.1.2.3 Upland Games Species...................... 2.2-7 2.2.1.2.4 Amphibians and Reptiles................... 2.2-8 2.2.1.2.5 Terrestrial Arthropods.................... 2.2-9 2.2.1.2.6 Rare and Endangered Species............... 2.2-9 2.2.2 AQUATIC EC0 LOGY........................... 2.2-10 2.2.2.' Phytoplankton............................. 2.2-10 2.2.2.i Periphyton................................ 2.2-13 2.2.2.3 Zooplankton............................... 2.2-14 2.2.2.4 Aquatic Macroinvertebrat 18................ 2.2-18 2.2.2.5 Fish...................................... 2.2-21 2.
2.3 REFERENCES
................................ 2.2-25 l 2.3 METEOROLOGY............................... 2.3-1 2.3.1 GENERAL................................... 2.3-2 2.3.2 TEMPERATURE............................... 2.3-3 2.3.3 WATER VAP0R............................... 2.3-3 2.3.4 FOG....................................... 2.3-4 0 2.0-ii
i WCGS-ER(OLS) g-~x TABLE OF CONTENTS (continued) (v) Title Page Section 2.3.5 PRECIPITATION............................. 2.3-4 2.3.6 WIND C HARACTERISTICS . . . . . . . . . . . . . . . . . . . . . . 2. 3-5 2.3.7 C LOUD COVER AND S UNS HINE . . . . . . . . . . . . . . . . . . 2. 3-6 2.3,8 STABILITY................................. 2.3-6 2.3.9 ST0RMS.................................... 2.3-6 2.3.9.1 Thunderstorms............................. 2.3-6 2.3.9.2 Tornadoes................................. 2.3-8 2.3.9.3 Hurricanes................................ 2.3-9 2.3.9.4 Extreme Winds............................. 2.3-9 2.3.10 AIR P0LLUTION............................. 2.3-10 2.3.11 REFERENCES................................ 2.3-12 2.4 HYDR 0 LOGY................................. 2.4-1
N 1.4.1 SURFACE WATER............................. 2.4-1
\' 2.4.1.1 H y d r o s p h el e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 . 4 - 2 2 4.1.1.1 Wolf croek Watershed...................... 2.4-2 2.4.1.1.2 Neosho River Basin........................ 2.4-3 2.4.1.2 Flow Characteristics...................... 2.4-5 1.4.1.2.1 Wolf Creek................................ 2.4-5 4' . 4 .1. 2. 2 Neosho River.............................. 2.4-6 2.4.1.3 Wolf Creek Cooling Lake................... 2.4-8 2.4.1.3.1 Makeup Water Supply to Wolf Cr e e k Co ol ing La k e . . . . . . . . . . . . . . . . . . . . . . . . 2. 4-8 2.4.1.3.2 Bathymetry in the Vicinity of the Plant Intake and Discharge................ 2.4-9 2.4.2 G R O UN D-WAT E R . . . . . . . . . . . . > . . . . . . . . . . . . . . . . . 2 . 4 -10 2.4.2.1 Formational Hydrogeologic Characteristics. 2.4-10 2.4.2.1.1 Alluvium.................................. 2.4-10 2.4.2.1.2 Soil and Weathered Bedrock................ 2.4-ll 2.4.2.1.3 Consolidated Bedrock...................... 2.4-13 2.4.2.2 Ground-Water Recharge and Discharge....... 2.4-14 2.4.2.2.1 Recharge and Discharge in Alluvium and Wea ther ed Bed rock . . . . . . . . . . . . . . . . . . . . . 2. 4-14 2.4.2.2.2 Recharge and Discharge in Consolidated Bedrock Strata............................ 2.4-15 g Am _- ... 2.0-111
WCGS-ER(OLS) TABLE OF CONTENTS (continued) Section Title Page O 2.4.2.3 G round-Water Hyd raulic G radients . . . . . . . . . . 2. 4-15 2.4.2.4 Ground-Water Models - Seepage from the Cooling Lake.......................... 2.4-16 2.4.2.4.1 I n t r od u c t i o n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 . 4 -16 2.4.2.4.2 S e e pa g e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 . 4 - 1 6 2.4.2.4.3 Ground-Water Movement..................... 2.4-17 2.4.2.4.4 Total Dissolved Solids and Radionuclide Concentrations in Ground Water............ 2.4-18 2.4.3 WATER QUALITY............................. 2.4-19 2.4.3.1 S u r f a c e Wa t e r Qua l i ty . . . . . . . . . . . . . . . . . . . . . 2. 4-19 2.4.3.2 G ro undwa te r Quali ty. . . . . . . . . . . . . . . . . . . . . . . 2. 4-2 2 2.4.3.3 State Standards........................... 2.4-23 2.
4.4 REFERENCES
................................ 2.4-24 2.5 GEOLOGY................................... 2.5-1 2.5.1 REGIONAL GEOLOGIC SETTING. . . . . . . . . . . . . . . . . 2. 5-2 2.5.2 PHYSIOGRAPHY.............................. 2.5-2 2.5.3 GENERALIZED STRATIGRAPHY.................. 2.5-3 2.5.4 GEOLOGIC STRUCTURE........................ 2.5-5 2.5.5 SEISM 0 LOGY................................ 2.5-6 2.5.5.1 Seismicity................................ 2.5-7 2.5.5.2 Correlation of Earthquake Activity with Geologic Structures or Tectonic Provinces........<........................ 2.5-8 2.5.6 S ITE GEOLOGIC CONDITIONS . . . . . . . . . . . . . . . . . . 2. 5-9 2.5.6.1 Near-Surface Stratigraphy................. 2.5-9 2.5.6.1.1 overburden................................ 2.5-9 2.5.6.1.2 Rock Units................................ 2.5-10 2.5.6.2 G ro und-Wa t e r H yd ro logy . . . . . . . . . . . . . . . . . . . . 2. 5-13 2.5.7 ECONOMIC GE0 LOGY.......................... 2.5-14 2.
5.8 REFERENCES
................................ 2.5-15 2.6 REGIONAL HISTORIC, ARCHEOLOGICAL, ARCHITECTURAL, SCENIC, CULTURAL, AND NATURAL FEATURES.......................... 2.6-1 2.7 NOISE..................................... 2.7-1 2.0-iv
WCGS-ER(OLS) i
- LIST OF-TABLES CHAPTER 2.0 - THE SITE AND ENVIRONMENTAL INTERFACES Table'No. Title 2.1-1 Population of Incorporated Places Within 50 Miles j of the Site 2.1-2 Resident Population Distribution by Sector and Radial Distance up to 10 Miles
- 2.1-3 Age Distributions for the Site Area for 1970 and 2000 1
2.1-4 Resident Population Distribution by Sector and Radial Distance Between 10 and 50 Miles 2.1-5 Schools Within 10 Miles of the Site j 2.1-6 Hospitals and Nursing Homes Within 10 Miles of the Site 2.1-7 Correctional Facilities Within 10 Miles of the Site 2.1-8 Recreation Facilities Within 10 Miles of the Fite i 2.1-9 Population Distribution Within the Low Population Zone, 1970 and 1980 2.1-10 Compariuon of Population Density Distributions for 1980 for Various Fertility and Migration Patterns 2.1-11 Comparison of Population bensity Distributions for 2020 for Various Fertility a.nd Migration Patterns 1 2.1-12 Farms, Land in Farms, and Land Use Within 50 Miles of the Site 1 2.1-13 Crop Production Within 50 Miles of the Site
; 2.1-14 Livestock Within 50 Miles of the Site
- 2.1-15 Feed Consumption by Cattle in East-Central Kansas 2.1-16 ' Hunting Harvest Within 50 Miles 2.1-17 Agricultural' Data for Coffey County, Kansas
' I \ 2.1-18 Distance to Nearest Plant Boundary, Residence, k-) m Vegetable Garden and Livestock Within 5 Miles 2.0-v
,-v-- 7 g y. .w -,3 w y y- y . .-r ,3m*- -=. . -- , * - - w -- =-- - og r
WCGS-ER(OLS) LIST OF TABLES (continued) Table No. Title 2.1-19 Water Rights on the Neosho River in Kansas Down-ctream of the Site 2.1-20 Neosho River Dischargers in Kansas Downstream of the Site 2.1-21 Municipalities and Rural Water Districts (RWD) in Kansas Utilizing the Neosho River Downstream of the Site 2.1-22 Municipal Ground-Water Supplies Within 20 Miles of the Site 2.1-23 Well Inventory Within 5 Miles of the Site 2.2-1 Phylogenic Listing of Plant Species Sampled Near hCGS, 1973-78 2.2-2 Shrub Stratum Flood Susceptibility Index of the North and South Floodplain Woods Near WCGS, 1975-78 2.2-3 Year-to-Data Comparisons Expressed as Percent Similarity for Three Plant Cor'. unities Near WCGS 2.2-4 Frequency of Species in the Ground Layer and Average Ground Layer Cover on a Dry Mudflat (Community 10) on John Redmond Reservoir, Bur-lington, Kansas, June and September, 1978 2.2-5 Frequency of Species in the Ground Layer and Average Ground Layer Cover on a het Mudflat (Community 9) on John Redmond Reservoir, Bur-lington, Kansas, June and September 1978 2.2-6 Small Mammal Species Captured Near the WCGS Site 2.2-7 Number of Small Mammals Captured Per 100 Trap-nights in Five Communities Near WCGS, 1973-78 2.2-8 Summary of Small Mammal Densities (No./ha) in Two Communities Near WCGS, 1974-78 2.2-9 Species List and Relative Occurrence of Mammals Not Observed During the Study, Recognized as Inhabiting Coffey County, Kansas 2.2-10 Avian Species Observed Near WCGS, 1973-78 2.0-vi l
WCGS-ER (OLS) LIST OF TABLES (continued) (N
' table No. Title , 2.2-11 Number of Species, Birds 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 WCGS . 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 Minimum of 10 Percent of the Density of Phytoplankton Collected in the Neosho River, 1973-78 4
2.2-16 Mean Density (Units /ml) of Phytoplankton in Samples Collected, 1973-78 2.2-17 Mean Carbon Fixation Rate (mg C/m per br) 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, 197?-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 2.2-24 Mean Seasonal Abundance (No./m ) of Major Zoo-plankton Taxa Collected in the Neosho River, 1974-78 2.0-vii
" - w '%w ww y w w~
- v- _y m = w y
- m w
hCGS-ER(OLS) LIST OF TABLES (continued) Table No. Title 2.2-25 Mean Seasonal Abundance (No./m ) of Major Zoo-plankton Taxa Collected in Wolf Creek, 1974-78 2.2-26 Drift Densities (No. Organisms /100 m ) 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./m ) of Selected Families from 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 'd Relative Abundance of Fish Collected Annua 11, by All Compling 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 2.2-35 Abundance of Fish Larvae Collected From the Tail-waters of John Redmond Reservoir, 1976-78 2.3-1 Monthly and Annual Average and Extreme Temperatures for Burlington, Topeka, and Wichita, Kansas 2.3-2 Annual Statistics and Diurnal Variation of Tempera-ture Parameters at Wolf Creek Cenerating Station 2.3-3 Composite Monthly Statistics and Diurnal variation of Temperature Parameters at Wolf Creek Generating Station 2.0-viii
WCGS-ER(OLS)
/h LIST OF TABLES (continued)
Table No. Title 2 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 Annual Statistics and Diurnal Variation of Rela-tive Humidity at Wolf Creek Generating Station
<?2.3-8 Composite Monthly Statistics and Diurnal Variation
,, of Relative Humidity at Wolf Creek Generating i, Station 2.3-9 Monthly and Annual Average and Maximum Precipita-tion and Snowfall for Burlington, Topeka and Wichita, Kansas s 2.3-10 bclimum Short Period Rainf all for Topeka and Wichita, Kansas 2.3-11 Total Number of Days with Freezing Precipitation in Wichita, Kansas 2.3-12 Joint Wind Speed, Wind Direction Frequency Dis-2 tribution (In Percent) for the Month of January 2.3-13 Persistence of Wind Direction Frequency Distribu-tion (In Percent) at Chanute F.S.S., Kansas 2.3-14 Joint Wind Speed, Wind Direction Frequency Dis-tribution (In Percent) by Stability Class 2.3-15 Annual Lower Level (10.0 M) Joint Wind Frequency Distribution at Wolf Creek Generating Station 2.3-16 Annual Upper Level (60.0 M) Joint Wir.d Frequency Distribution at Wolf Creek Generating Station 2.3-17 Composite Monthly Lower Level (10.0 M) Joint Wind Frequency Distribution at Wolf Creek-Ger.erating Station 2.3-18 Composite Monthly Upper Level (60.0 M) Joint Wind Frequency Distribution at Wolf Creek Generating (f)s Station 2.0-ix
WCGS-ER(OLS) LIST OF TABLES (continued) Table No. Title O 2.3-19 Annual Lower Level (10.0 M) Joint Wind Frequency Distribution by Stability Class at Wolf Creek Generating Station 2.3-20 Annual Upper Level (60.0 M) Joint Wind Frequency Distribution by Stability Class at Wolf Creek Generating Station 2.3-21 Composite Monthly Lower Level (10. 0 M) Joint Wind Frequency Distribution by Stability Class at Wolf Creek Generating Station 2.3-22 Composite Monthly Upper Level (60.0 M) Joint Wind Frequency Distribution by Stability Class at Wolf Creek Generating Station 2.3-23 Annual Statistics and Diurnal Variation of Lower Level (10.0 M) Wind Speed and Wind Direction at holf Creek Generating Station 2.3-24 Annual Statistics and Diurnal Variation of Upper Level (60.0 M) Wind Speed and Wind Direction at Wolf Creek Generating Station 2.3-25 Compo' .te Monthly Statistics and Diurnal Variation of Iswer Level (10.0 M) Wind Speed and Wind Direc-tion at Wolf Creek Generating Station 2.3-26 Composite Monthly Statistics and Diurnal variation of Upper Level (60.0 M) Wind Speed and Wind Direc-tion at Wolf Creek Generating Station 2.3-27 Wind Direction Persistence by Stability Class at Wolf Creek Generating Station 2.3-28 Wind Direction Persistence for All Classes Com-bined at Wolf Cree.. Generating Station 2.3-29 Wind Direction Persistence for All Stable Classes at Wolf Creek Generating Station 2.3-30 Average Monthly and Annual Daylight Cloud Cover, and Sunshine for Topeka, Kansas 2.3-31 Persistence of Stability Frequency Distribution (In Percent) at Chanute F.S.S., Kansas 2.3-32 Stability Persistence Summary 2.0-x
WCGS-ER(OLS) 7g LIST-0F TABLES (continued) Table No. Title 2.3-33 Average Monthly and Annual Number of Days with Thunderstorms at Topeka and Wichita, Kansas 2.3-34 Number, Probability, and Recurrence Interval of Tornado Occurrences Per One Degree Longitude-Latitude Square in Kansas 2.3-35 Tornado Summary For Kansas 2.3-36 Fastest Mile of Wind for Eastern Kansas Using Fisher-Tippet Type I (Frechet) Distribution 2.3-37 Fastest Mile of Wind for Topeka and Wichita, Kansas
- 2.4-1 Precipitation and Snowfall Data for Burlington, Kansas 2.4-2 Natural Streamflow of the Neosho River (1948-1963) 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 hater Districts in Kansas Utilizing the Neosho River Downstream of the Site I 2.4-6 Hydrogeologic Characteristics of Bedrock Within a 5-Mile Radius 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 2.4-11 Summary of SLcface 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 2.0-xi
WCGS-ER(OLS) LIST OF TABLES (continued) l Table No. Title 2.5-1 Modified Mercalli Intensity (Damage) Scale of 1931 2.5-2 Seismic Events Significant to the Site 2.5-3 Earthquakes Perceptible at the Site O O 2.0-xii
WCGS-ER(OLS) (~' LIST OF FIGURES D) CHAPTER 2.0 - THE SITE AND' ENVIRONMENTAL INTERFACES Figure No. , Title 2.1-1 Location of Site Within the State of Kansas { 2.1-2 Location of Site Within Coffey County 2.1-3 Property Owned by Applicant 2.1-4 Plant Site Features 2.1-5 Layout of Dams, Likes, 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 4.2-9 1970 Resident Population 0 to 10 Miles
\
[d 2.1-10 2.1-11 1980 Resident Population 0 to 10 Miles 1990 Resident Population 0 to 10 Miles 2.1-12 2000 Resident Population 0 to 10 Miles f 2.1-13 2010 Resident Population 0 to 10 Miles l l 2.1-14 2020 Resident Population 0 to 10 Miles 2.1-15 1970 Resident Population 10 to 50 Milas 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 ~ 2.1-20 2020 Resident Population 10 to 50 Miles 2.1-21 Public Facilities and Institutions Within 5 Miles of the Site O s i 2.0-xiii
. , , - -- , .-w--
,w -- , 4 ~ - ---y-,w+,, e,-,-m- e- , - - - . . --- ny +, a - - , ,- , --y
WCGS-ER(OLS) LIST OF FIGURES (continued) Figure No. Title 2.1-22 Cumulative Population Density, 1970 to 2020, Within 50 Miles of the Site 2.1-23 Land Use hithin 5 Miles 2.1-24 Zoning Within 5 Miles 2.1-25 hater 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 Terrestrial 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 Repo rts, 1955-1967 2.3-8 Wind Gusts, 1955-1967 2.3-9 Wind Storms by One-Degree Squares, 1955-1967 2.3-10 hind Storms by Two-Degree Squares, 1955-1967 2.0-xiv
i WCGS-ER(OLS) i. LIST OF FIGURES (continued) Figure No. Title 2.3-11 Average Tracks of Cyclones 2.3-12 Seasonal Inversions and Isothermal Maps 2.3-13 Isopleths of Seasonal Mean Afternoon Mixing Depths 2.3-14 Isopleths of Annual Mean Maximum Depths 2.3-15 Mixing Depth Episode Days t 2.3-16 Forecast Days of High Air Pollution Potential 2.4-1 Wolf Creek Watershed l 2.4-2 Neosho River Basin in Kansas 2.4-3 Duration Curve for Daily Flow of Wolf Creek Near Burlington (Drainge Area = 35 sq mi) , 2.4-4 Generalized East-West Cross Section Through Plant Site Showing Potentiometric Water Levels 2.4-5 Discharge Frequency Curves i 2.4-6 Water Table Contours Within a 5-Mile Radius of the i Site 2.4-7 Plan, Profile, and Sections of Approach Channel - Circulating Water Screen House i 2.4-8 Plan, Profile, and Section of Discharge Channel - Circulating Water Discharge Structure 2.4-9 Generalized Potentiometric Surface Contours of Plattsmouth Member 2.4-10 Generalized Potentiometric Surface Contours of Toronto Member 2.4-11 Generalized Potentiometric Surface Contours of . Ireland Member 2.4-12 Municipal Ground-Water Supplies Within 20 Miles of Plant Site 2.4-13 Well Level Recorder Chart and Precipitation Record at Site w) 2.4-14 Location of Piezometers, B-Series 2.0-xv
WCGS-ER(OLS) LIST OF FIGURES (continued) Figure No. Title 2.4-15 Location of Piezometers, ESW , HS , and P-Series Borings 2.4-16 Variations of Water Levels in Piezometers 2.4-17 Seepage Sector Map 2.4-18 Surface Water Sampling Locations 2.4-19 Groundwater Sampling Locations 2.5-1 Regional Tectonic Map 2.5-2 Regional Geologic Map 2.5-3 Regional Geologic Cross Section 2.5-4 Regional Physiographic Map 2.5-5 Site Physiographic Map 2.5-6 Surficial Geologic Map 2.5-7 Generalized Site Stratigraphic Column 2.5-8 Earthquake Intensity and Epicenter Map 2.5-9 Detailed Site Stratig raphic Column 2.5-10 Site Geologic Cross Section 2.5-11 Location of oil and Gas Fields O 2.0-xvi
WCGS-ER(OLS) ["% CHAPTER 2.0 \ ) THE SITE AND ENVIRONMENTAL INTERFACES 2.1 GEOGRAPHY AND DEMOGRAPHY 2.1.1 SITE LOCATION AND DESCRIPTION 2.1.1.1 Specification of Location The Wolf Creek Generating Station, Unit No. 1 (WCGS) is located in eastern Kansas approximately 75 miles southwest of Kansas City, 53 miles south of Topeka, and 100 miles east-northeast of Wichita, Kansas. The plant site is near the center of Coffey County in Hampden Township, 3.5 miles northeast of the city of Burlington and 3.6 miles east of the Neosho River and the main dam at John Redmond Reser-voir. Figure 2.1-1 shows the location of the site in Kansas, and Figure 2.1-2 locates it in Coffey County. The plant site is located in Township 21 South, Range 16 East of the Sixth Principal Meridian, and Townships 20 and 21 South, Range 15 East of the Sixth Principal Meridian. The reactor is located 4,235,500 meters north and 264,600 meters east within zone 15 at Universal Transverse Mercator [} ( / Coordinates Latitude 38*14'20" North and Longitude 95 41'20" West. The WCGS is a Standardized Nuclear Unit Power Plant System (SNUPPS) plant, which locates the reactor centerline at hypothetical SNUPPS coordinates Latitude 100,000 North and Longitude 100,000 East. The Kansas State plane coordi-nates corresponding to these hypothetical coordinates are Latitude 584,670 North and Longitude 2,807,250 East. 2.1.1.2 Site Area Of the 11,882 acres owned by the applicant on and near to the WCGS site, 9,818 acres are occupied by the site, and 1,976 acres lie outside of the site boundary. The acreage beyond the site boundary is leased as farmland and pastureland. The railroad right-of-way to the site boundary occupies about 148 acres, 88 acres of which are owned by the applicant. Figure 2.1-3 shows the lands owned by the applicant. The station property lines include both the land inside the site boundary and the leased land out-side the boundary. Areas modified by construction of the plant include 135 acres for the station, 60 acres for the cooling lake dams and dikes, and 5,090 acres for the cooling lake at a normal elevation of 1,087 feet above mean sea level (MSL). Figure 2.1-4 shows the location and orienta-tion of principal plant structures, and Figure 2.1-5 shows 7-s the layout for the cooling lake, dams, dikes, and spillways. ( J V 2.1-1
WCGS-ER(OLS) The plant exclusion area, shown on Figure 2.1-6, lies within the site boundary and encompasses approximately 1,118 acres, which are owned by the applicant. This area is traversed only by the access road to the plant. There are no residential, commercial, or industrial struc-tures within either the exclusion area or the plant site area. The effects of the Wolf Creek cooling lake are dis-cussed in Section 2.8. The transportation network in the site vicinity is shown on Figure 2.1-7. The main highway artery in the plant site area is U.S. Highway 75, which runs in a north-south direction about 0.25 mile west of the site boundary and 2.8 miles west of the reactor location at its closest point. The four other major roads within a 5-mile radius of the plant are the federal-aid secondary routes 10, 149, 153, and 1472. The nearest existing railroad to the site is the Missouri Pacific Railroad located 10.1 miles southeast of the site boundary. A spur connecting the site with this track was constructed to provide rail access to the site. Another railroad (Santa Fe Railroad) running in a north-south direction through the site property was aban-doned in 1972. There is no commercial water traffic on the Neosho River or the John Redmond Reservoir. 2.1.1.3 Boundaries for Establishing Effluent Release Limits The restricted area, which is used for establishing effluent release limits, enables the applicant to fulfill their obligations with respect to the requirements of 10 CFR Part 20. This area and the distances from the station vent stack to the boundary lines of the restricted area are shown on Figure 2.1-6. The restricted area boundary closest to the gaseous effluents release point is to the west at a distance of 1,250 feet. O 2.1-2
. . . . . . -- ._ -=. - ._. .- - - . .
l l b WCGS-ER(OLS) 2.1.2 POPULATION DISTRIBUTION k The current and projected populations within 50 miles of the Wolf Creek Generating Station site have previously been described in Section 2.2.1 of the Environmental Report - Construction Permit Stage [ ER (CPS)] . Section 2.1.2 of the - ER (OLS ) presents revised population projections and updated ' information on transient population. Some of the information on methodology and populations of incorporated places, previously presented in the ER(CPS), has been repeated for continuity.
! The population projections have been revised to reflect the most recent U.S. Bureau of the Census and State of Kansas projections, which have changed since the submittal of the ER (CPS) . Information on transient population has also been updated to reflect the most recent data. As requested in the revised NRC guidelines (Revision 2), age distribution of the population has also been provided.
The updated information on population distribution is presented in revised text, tables, and figures in the format
; requested by Revision 2 to Regulatory Guide 4.2.
In general, east-central Kansas is predominantly a low-population density, rural, agricultural area. Table 2.1-1 presents the 1960 and 1970 populations of incorporated places j (Figure 2.1-8) within 50 miles of the site. The populations of both the rural areas and the communities which serve the rural economy declined during the 1960 to 1970 decade; this decline has continued into the 1970s. Population studies in support of this application were 1 directed toward estimating the distribution of current (1970) population figures and estimating the projected population
< from 1980 to 2020 (by 10-year increments) within a 50-mile l radius of the plant site. Data sources and methodology used 4
for the studies are. summarized in the following paragraphs.
, The distributions of the current and projected populations were determined by first establishing a network of geographic sectors and then apportioning the available census data.
To establish the geographic sectors, the 50-mile-radius
' area (using the plant site as the center) was divided by superimposing concentric circles and radial lines over a base map. Within 5 miles of the plant site, the concentric circles were located at 1-mile radial increments; for the area from 10 to 50 miles of the site, the circles were located at t
increments of 10 miles. These concentric circles were then divided in 16, 22.5 segments, each centered on one of the
- 2.1-3
WCGS-ER(OLS) 16 cardinal compass points. This rose format is illustrated on Figures 2.1-9 through 2.1-20. The current population distribution within 50 miles of the site was based on 1970 census data (U.S. Bureau o f Census , 1971). The population data for the area within 5 miles of the plant site were supplemented by a field survey in which each occupied house was located on a county map and the number of residents tallied. This detailed survey, which did not include the incorporated areas of Burlington and New Strawn (since actual populations of these towns were known) , was conducted to provide an accurate distribution of population among the small sectors, ranging from 0.1 to 4.5 square miles, within 5 miles of the plant site. Beyond 5 miles, the sectors formed by the concentric circles and radial lines are large enough to include both inhabited and vacant areas, and thus an area-distribution method was used. With this method the populations of all Minor Civil Divisions (MCD) were allocated to sectors by area (U.S. Bureau of Census , 1971). Where 10 percent of an MCD was within a given sector, 10 percent of the census population was allocated to that sector. The sum of MCD population portions within a sector was presented as the sector total. The population projections were based largely on federal census projections to 2020 for the nation, and state pro-jections to 2000. These projections were stepped down f rom the national and state levels to the county level (U.S. Bureau of the Census, 1977 and 1978). In addition, 1975 county projections formulateo by Dr. Cornelia Flo ra in 1975 were used (Flora, 1975). The step-down technique (Greenberg and others, 1973) was applied in extending state projections past 1990 to obtain projections at the local level. This method involves repro-portioning of state projections based on change in share of the state's overall population relative to the nation. Also, as these projections of fer a selection of fertility and migration rates, a conservative national fertility rate, of 2.1 children per woman through the year 2020, was assumed for these projections. (In 1978 the average monthly general fertility rate was 66.4 births per 1,000 women 15-44 years of age. This fertility rate is equivalent to abouc 2.0 children per woman completed fertility [ National Center for Health Statistics, 1979, page 8]). Interstate migration similar to that observed by theistate between 1965 and 1975 was chosen. Since projections for specific Minor Civil Divisions (MCD) were lacking, historic trends were investigated, and the average percent change by decade from 1940 to 1970 was 2.1-4
WCGS-ER(OLS) [ 'T
~
continued to 2020 for each MCD. County sums derived from ( ,) these divisions were then reproportioned to county totals derived from the step-down procedure (Greenberg and others, 1973). Thus, if an area had grown in the past, it was assumed it would continue to grow. The MCD projections were allocated to various segments in the 0- to 50-mile area with the area-distribution method previously described. In cases where new residential developments occurred within the 0- to 5-mile area and historic population trends were not reliable, projections were based on the number of planned home sites within each development. An occupancy f actor of 2.9 people per dwelling (determined from a field survey and verified by the 1970 census data) was used to derive a total population for each new residential area. This approach provides a conservative or high population projection for these areas. It is assumed that no permanent residents would live within 1 mile of the plant site or within the area occupied by the cooling lake beyond 1980. 2.1.2.1 Population Within 10 Miles The total 1970 population within the 10-mile aret was 4,059, which results in a density of 13 people per square mile
/'_sT and clearly depicts the area's rural nature (Table 2.1-2).
(_,) Within 5 miles of the plant site, the 2,537 residente provide a densit y of 32 people per square mile. However, when Burlington with its population of 2,099 is excluded, the area within 5 miles of the plant site then has a density of six people per square mile. The 2020 population projection for the area within 10 miles of the plant site indicates a decline in nearly all segments except in those which encompass Burlington and New Strawn. These communities are located principally in the 3- to 4- and 4- to 5-mile segments described in Table 2.1-2 and on Figure 2.1-8. However, the 2020 proj ection is not the maximum. As shown in Table 2.1-2, the 10-mile population increases very slowly from 4,059 in 1970 to 6,120 in 2000. After the year 2000 the 10-mile population declines to 5,370 in 2020. The increase and dec2ine is rela _. to the age-structure of the population and the out-migration history of the area. Figures 2.1-9 through 2.1-14 present the projected populations in the 0- to 10-mile area from 1970 to 2020. The only incorporated communities within 10 miles of the plant site are at Burlington, 3.5 miles to the southwest, and New Strawn, 3 miles to the west-northwest of the plant site (Table 2.1-1). ' O V 2.1-5
WCGS-ER(OLS) Barlington had a 1970 population of 2,099, a January 1979 po pulation o f 2,511, and is expected to undergo only mod-erate growth by 2020. New Strawn was created when the U.S. Army Corps o f Eng i-neers relocated Strawn (an unincorporated settlement) from the area to be inundated by the John Redmond Reservoir, and was incorporated in 1971 (Brown, 1979). The town did not appear in the 1970 U.S. Census. Therefore, in the absence of historic population trends, estimates for the future have been based on the number of planned lot sites. New Strawn is currently growing, and has the capability to accommodate significant new residential development. Within New Strawn 668 home and trailer lots have been subdivided, with approximately 150 single family homes and 63 trailers presently occupied within the town (Jones, 1979; Boyce, 1979). Present growth in New Strawn is estimated at 12 to 15 single family homes per year (Jones, 1979). Assuming development of an additional 30 single family residences and 22 trailers (remaining capacity in the Arrow-head Park Trailer Camp) , the 1980 population of New Strawn could be as high as 800 residents (assuming about 2.9 people per dwelling unit). As New Strawn occupies parts of two of the geographic sectors, approximately 534 of these peo ple would live in the west-northwest segment from 3 to 4 miles from the site, and 266 residents would live in the northwest segment from 3 'n 4 miles from the site. In addition to inco;porated New Strawn, there are two adjacent d ev el o pm en t s , Remer's Point and Hillview, in an unincorporated area west of New Strawn. Presently, there are a total of 11 homes and 2 mobile homes in the two developments - 7 homes and 2 trailers in Hillview, and 4 homes in Remer's Point. It is estimated that there exists space for approximately 40 addi-tional dwelling units within the two developments (Remer, 1979; Harris, 1979). Full development of these two areas would result in a total population of approximately 150 residents (assuming 2.9 persons per dwelling unit). However, this development is unlikely to occur until well after 1980 (Remer, 1979; Harris, 1979). Of this potential total of 150 residents in Remer's Point and Hillview, 10 would locate in the west-northwest segment, 5 to 10 miles f rom the plant, and the remainder would locate in west-northwest segment, 4 to 5 miles from the site. It should be noted tha t , as the historic growth trends for the region suggest decreased population growth for most communities, the above increased projections are therefore 2.1-6
WCGS-ER(OLS) l [' T likely to be conservative or high estimates of future popu-(_) lations for these communities. The midpoint of station operating life, rounded to the nearest census date, is 2000. The distribution for age categories 0 to 12, 12 to 18, and'over 18 is shown in' Table 2.1-3. The U.S. projected age distributon for 2000 was used because the 1970 age distribution for Coffey County did not dif fer signif-icantly from the 197 0 U . S . age distribution. Appendix D of Regulatory Guide 4.2 Revision 2, Preparation of Environmental Reports for Nuclear Power Stations, defines a "significant difference" as more than a 10 percent dif ference of the age distribution of the county in which the proposed station is to be located from the U.S. age distribution in the 1970 decen-nial census. The 10-percent difference criterion is to be applied to any of the three age groups. Table 2.1-3 shows the 1970 age distribution for the U.S. , Coffey County (the county in which the plant is located), and the counties in which all or a portion are located within 50 miles of the plant. None of the age categories differ significantly f rom the 1970 U.S. age distribution. The year 2000 age distributions for 0 to 10 miles from the site and 10 to 50 miles are the same. 2.1.2.2 Population Between 10 and 50 Miles Cities and towns within le
- o 50 miles of the plant site are 7- s
- ) shown on Figure 2.1-8 anu their 1960 and 1970 census popu-Ns/ 1ations are listed in Table 2.1-1. Many of these incorporated places experienced a decline in population from 1960 to 1970.
Emporia, Kansas, with 23,327 residents in 1970 and 26,145 residents in 1978 is the largest city in the 10- to 50-mile region, while the next largest is Ottawa with 11,036 people in 1970 and 10,693 people in January 1978 (Knig ht , 1979). The majority of the incorporated places contain less than 1,000 peo pl e . The population rose for the area from 10-to-50 miles is divided into 64 segments ranging in size from 59 to 177 square miles. The current and projected population distri-bution from 10 to 50 miles is listed-in Table 2.1-4. The 1970 through 2020 population distributions are compared on Figures 2.1-15 through 2.1-20. The total cumulative 1970 population within the entire 50-mile area currounding the site was 163,834 or about 21 persons per square mile. In the region within 10 to 50 mile" t the plant site, the projections clearly depict a deci me in the rural areas with moderate g rowth occurring onli o k: vicinities of major cities and towns (Figure 2.1-t aal ...)le 2.1-1). A net {"'N
2.1-7 i
1
WCGS-ER (OLS ) population decline of 4 percent over the entire 0- to 50-mile area is proj ected for the 50-year period from 1970 to 2020. The year 20C? age distribution for the 10 to 50 mile area around the site is shown in Table 2.1-3. The means by which
- his distribution was generated is discussed in Section 2.1.3.1.
2.1.2.3 Transient Population Transient population within 10 miles of the site is low. Most seaoonal or daily shifts in population are associated with public facilities such as the John Redmond Reservoir, schools, and parks. Figure 2.1-21, Public Facilities and Institutions, illus-trates the geographic location of the transient po pula tio n centers within 5 miles. Tables 2.1-5 through 2.1-8 provide a description of the facilities shown on Figure 2.1-21. The Flint Hills National Wildlife Refuge (Table 2.1-8) is pri-marily outside the 10-mile study area. By comparing the population statistics (enrollment and usage) on Tables 2.1-5 through 2.1-8 with the geog raphic locations (Figure 2.1-21), current transient concentrations can be identified in relation to the plant location. For future projections, there were no anticipated expansions to public facilities within 5 miles of the site. There is presently no commitment by the Applicants to public use of the WCGS cooling lake or surrounding land (see Section 2.8). If this commitment is made in the future, an increase in the transient population within 5 miles of the site would result. One Federa' Aid Primary highway (FAP 75) and four Federal-Aid Scaondary highways (FAS 10, FAS 149, FAS 153, and FAS 1472) occur witnin 5 miles of tne site (Figure 2.1-21). Based on the 1978 annual average daily traffic (ADT) count for FAP 75 and the 1975 ADT counts for the secondary highways, the following ranges of traffic volumes were recorded within 5 miles of the site (Ijans, 1978): Range of ADT Route Orientation (vehicles per day) FAP 75 N-S 2810 - 3800 FAS 10 E-W 465 - 875 FAS 149 N-S 95 - 110 FAS 153 E-W 75 - 225 FAS 1472 E-W 90 - 125 1 2.1-8 9
WCGb-ER (OLS ) ['") The most important source of transient seasonal population in
.the general. area is the recreational usage of John Redmond \s_) Reservoir. The' conservation pool of John Redmond Reservoir extends 3.5 to 7.2 miles west of the site. The facilities.
that attract a transient population are boat launching ramps, fishing, picnic facilities, and campgrounds. -The peak monthly usage was 79,400 during. July 1978 (Duncan, 1979). The yearly visitation at John Redmond Dam and Reservoir averages about 380,000 (yearly change in visitation is largely dependent on weather conditions [Chester, 1979]). Actual 1972 visitation was reported to be 692,300 (Kansas Park and Resources Author-ity, and Oblinger-Smith Corporation, 1975, Table IX.1). The recreational season is year round, but the peak months are during the summer. Major sources of transient or seasonal
- populations, such as that experienced during recreational use of John-Redmond Reservoir, have established visitor trends which can be utilized as- a guide for future usage of these areas.
With the exception of visitation at Kansas reserviors and
-state parks, transient populations at distances of 5 to 50 miles are minimal due.to the absence of major industrial facilities or recreational attractions.
The Pomona, Melvern, Toronto, ano Fall River reservoirs and state parks are located within 50 miles of the site. The
.[ s i \
recreational facilities available at each of these reservoirs consist of boat launching ramps, picnic shelters, sanitary facilities, campgrounds and swimming beaches. Location and actual =1978 visitation for each of these reservoirs are given below (Herndon, 1979): Reservoir and State Park Location 1978 Visitation Pomona 29 miles north 885,380 Melvern 19 miles north 896,054 1 , Toronto 34 miles south- 419,900 l southwest l Fall River 45 miles south- 433,500 j southwest The two largest cities within 50 miles are Emporia (28 miles-west-northwest) and Ottawa (32.5 miles northeast). The 1978 populations of there cities, 26,145 and 10,693, respectively, reflect the absence of a large population-industrial source in the 16-county area surrounding the' site. Transient population in the area is not expected to increase due to the projected s ("'i a' '/ 2.1-9
WCGS-ER(OLS) population decline (4 percent, Section 2.1.2.2) in the next 50 years. 2.1.2.4 Low Population Zone The low populaticn zone (LPZ) is defined as the area within 2.5 miles (4,023 meters) from the reactor center as shown on Fige es 2.1-6 and 2.1-21. The LPZ meets the requirements as st<;ed in 10 CFR Part 100. The LPZ does not include Burlington, New Str- 7, or Highway 75, nor does it contain any areas of heavy re idential use. The 1970 population of the 20-square mile area of the LPZ was 101 people. By 1980, the permanent resident population should be about 130 people. Table 2.1-9 presents the estimated distribution of population in 1970 and 1980 within the LPZ. All exit routes within the LPZ are presently unsurfaced two-lane county roads. Some of these roads may be impassable during periods of rainy weather except for tracked vehicles, four-wheel drive vehicles, and farm tractors. Detailed evacuation provisions will be addressed in the detailed emergency procedures (Section 13.3 of the Final Sa fety Anal-ysis Report) . Two improved access roads (one all-weather) will be constructed which will provide exit routes within the site property boundary and from the LPZ area. There are no sources of transient population within ths LPZ. [There is presently no commitment by the Applicants to public use of the cooling lake or surrounding land (Section 2.8)] With the exception of residential traffic, there is no transient population in the LPZ, neither during the working day nor seasonally. No data are available on the frequency of residential traffic within the LPZ. The roads are not major highways but are unsurfaced country roads which serve scattered residences. The railroad passing through the site area was abandoned, and the rails have been removed. The re are no commercial facilities within 2.5 miles of the site. 2.1.2.5 Population Center The population center or city closest to the site with a population g reater than 25,000 persons, is Emporia, Kansas, 28 miles west-northwest of the sice. In 1975 its popula-tivn was estimated to be 26,145 persons (DeMott, 1979). The next city eligible for designation as a population center is Topeka, Kansas, 53 miles north of the site. Topeka's reported populations for 1970 and 1978 were 155,322 and 144,221 persons, respectively (Schlicher, 1979). 2.1-10
WCGS-ER(OLS) (h1 2.1.2.6 Population Density 5
%/
The site is located in a very low population density area.
-Within 50 miles of WCGS the range of density variation, from 6 persons per square mile to 62 persons per square mile, is very small. This low density indicates a relatively homogeneous rural' population characteristic of an agricultural or ranching economy.
As shown on Figure 2.1-22 the projected population from 1980 to 2020 never_ exceeds 70 persons per square mile. Indeed the cumulative maximum density (62 persons per square mile) occurs in the year 2000 for the 0- to 5-mile distance. Thereafter the densities decline. Varving the fertility and migration assumptions does not influent the levels of popu-lation density significantly. Tables ' .-10 and 2.1-11 show comparisons of population distributions for various fertility and migration patterns for 1980 and 2020, respec-tively. The most conservative projection (i.e. high) is the no migration, 2.7 children per woman fertility which results in a maximum density (66 persons per square mile). (_ - (o) v 2.1-11
- - - = _
WCGS-ER(OLS) 2.1.3 USES OF ADJACENT LANDS AND WATER Information on land and water use within the site environs was presented previously in Sections 2.2.2 and 2.2.3 of the Environmental Report - Construction Permit Stage [ER (CPS) ] . Section 2.1.3 of the ER(OLS) updates some of the information previously presented, presents new information as requested in Revision 2 of the NRC guidelines, and also repeats some of the information from the ER(CPS) for continuity. The revisions and new information include the following:
- a. A summary of crop and livestock production within a 50-mile adius of the WCGS;
- b. A summary of commercial and recreational fishing and hunting harvests within 50 miles;
- c. Updated water rights and water use on the Neosho River downstream of the site;
- d. Updated municipal ground-water use within 20 miles of the site;
- e. New agriculture data fo r Co f f e y Co un ty;
- f. Estimated distances from the reactor center to the nearest milk cow, milk goat, resident, and vegetable garden in each of the 16 sectors within 5 miles;
- g. Updated well inventory within 5 miles; and
- h. A field reconnaissance and review of recent aerial photos to determine recent developments or apparent changes in land use within 5 miles since 1973.
Inclusion of any data or discussion that were presented in the ER (CPS) is repeated herein only for the sake of continuity. 2.1.3.1 _ Land Use Within 50 Miles 2.1.3.1.1 General Description The area within 50 miles of the plant site encompasses 7,854 square miles and all or portions of 21 counties (Figure 2.1-8). Farmland occupies approximately 89 percent of the 50-mile radius area (Table 2.1-12) and cropland, pasture and rangeland are the prevalent land use cover types. Urban or built-up lands occupy a very small percentage of this predominantly rural region. Farmland acreage has remained relatively stable in the region, decreasing by only 1.5 percent from 1969 to 1977. The statewide acreage of 2.1-12 9
WCGS-ER(OLS)
/) farmland decreased 1.4 percent during the same -
iod (Kansas Crop and Livestock Reporting Service, 1978a;.o.s. Bureau of ('~') -the census,=1977). Presented below in' Section 2.1. 3.1. 2 a re the annual meat, 4 milk and crop production ertimates for.the. area within 50 miles of the WCGS. Unless stated otherwise these estimates are based.on~ state and county data from the U.S. Bureau of the Census (1977) ~ and the Kansas Crop and Livestock Reporting. Service-(1978a). When only a portion of .a county was within the 50-mile. radius area, it was assumed that agriculture production was distributed evenly throughout the county, and the total county estimates were reduced accordingly. . Estimates are presented only for the total 50-mile radius area rather than for each 22-1/2 degree sector or annular i segment because of the lack of more area-specific data. 2.1.3.1.2 Agriculture Activities Cropland within 50 miles of the WCGS consists primarily of close grown field crops such as wheat, sorghum, soybeans and hay. Corn, oats and barley are less common in the region. Production of truck or row crops within 50 miles for canning purposes is negligible.(Table 2.1-13). Virtually all of the wheat sold in Kansas is used in food products for human consumption. Approximately 75 percent (j or more of the corn and sorghum raised for grain' is used for livestock feed, the remainder is principally used for seed. Approximately 10 percent of the state soybean crop is used for human food products, approximately -40 percent for livestock feed, and approximately 50 percent is exported from the United States. Oats and barley are used primarily for livestock feed or seed (Kastens, 1979). The estimated number of beef cows, milk cows and cattle on feed within 50 miles of the WCGS is presented in Table 2.1-14. Between 1973 and 1977, the annual beef production in Kansas averaged 403 pounds (183 kilograms) per head of cattle and calf on inventory (Kansas Crop and Livestock Reporting 4 Service, 1978a). Using this state average, the total beef production in 1978 within 50 miles of the.WCGS is estimated at 254 million pounds ' (ll5 million kilog rams) . Total milk production within 50 miles of the site is estimated to be 232 million pounds (102 million liters). Typical annual feed consumption per dairy cow or beef cow i' in. east-central Kansas is' presented in Table 2.1-15. The average grazing season .on native pasture is 6 months, f rom approximately April 20 to October 15. The grazing season is
. shorter on tame grass pastures of brome or fescue grass, \_/ 2.1-13
WCGS-ER(OLS) lasting for 3-1/2 to 4-1/2 months. Native pasture grass in east-central Kansas generally yields one ton per acre (0.22 kilograms per square meter) per year and tame grass pasture generally yields two tons per acre (0.45 kilograms per square meter) (Bell, 1979). Estimated silage and forage production within 50 miles is presented in Table 2.1-13. The estimated number of hogs and pigs within 50 miles of the WCGS in 1978 was approximately 249,000. Ann ual pro-duction in Kansas between 1973 and 1977 averaged approxi-mately 367 pounds (167 kilog rams) per head of hogs and pigs on inventory (Kansas Crop and Livestock Reporting Service, 1978a). Using this average, the total production in 1978 within 50 miles of the WCGS was estimated at 91.4 million pounds (41. 5 million kilog rams) . The raising of sheep and lambs is a relatively minor form of livestock production within 50 miles of the WCGS (Table 2.1-14). Annual production in Kansas between 1973 and 1977 averaged approximately 62 pounds (28 kilog rams) per head of sheep and lamb on inventory (Kansas Crop and Livestock Re-porting Service, 1978a). Using this average, the total production in 1978 within 50 miles was estimated at 797,000 pounds (362,000 kilograms) . The estimated number of chickens, excluding broilers, with-in 50 miles in 1977 was approximately 303,000 (Table 2.1-14). Annual production in Kansas in 1976 and 1977 averaged 0.80 birds per year per number on inventory (Kansas Crop and Livestock Reporting Service, 1978a). Using this average, the total production in 1977 within 50 miles was estimated at 305,000 chickens. Production data for broilers and other meat-type chickens were not available for 1977 but in 1969 and 1974 sales were 4.3 birds per year per number on in-ventory. The number of broilers and other meat-type chic-kens within 50 miles is approximately 10,300 (Table 2.1-14). Egg production within 50 miles in 1977 was estimated at 90 million. The number of turkeys within 50 miles of WCGS is approxi-mately 594 (Table 2.1-14). The most recent available an-nual comparisons cf turkey production and inventory on farms was for the year 1974. In that year turkey production was 5.7 birds per number on inventory. 2.1.3.1.3 Hunting The area within a 50-mile radius of the WCGS has a wide variety of game species. Species commonly sought by hunters include white-tailed deer, bobwhite quail, greater prairie chicken, ring-necked pheasant, gray and fox squirrel, eastern 2.1-14
WCGS-ER (OLS ) t cottontail, _ mourning dove and a variety of ducks. The p-s(i estimated annual average hunting harvest'from 1973 to 1977 e (m-) in the 50-mile radius crea is presented-in Table 2.1-16. See Section 6.1.4.2 for a. description of the methods used to estimate the regional hunting harvest. No data were available concerning the amount of game consumed locally. However, hunters residing outside the 50-mile radius area will If' ely hunt within the area and, therefore, only a_ portion of the harvest would be expected to be consumed locally. Furbearers are also abundant in the region and species commonly taken by trappers include her.ver, bobcat, muskrat, raccoon and coyote. Trapping harvest data are available
.aly for large geographical regions within Kansas .which precludes making a reliable harvest estimate for the area within 50 miles of the WCGS. Furbearers are seldom consumed by humans for food. The beaver, muskrat and raccoon are the only furbearing species that would likely be consumed as food and this consumption is probably less than 5 percent of the total harvest (Tiemann, 1979).
2.1.3.1.4 Other Usss rx ( Land uses other than agriculture within 50 miles of the
\- WCGS primarily occupy urban or built-up lands that include residential, commercial, industrial, and transportation uses. The locations of cities and towns in the region are shown on Figure 2.1-8.
2.1.3.2 Land'Use Within 5 Miles 2.1.3.2.1 General Description Land use within 5 miles of the WCGS and outside the site boundary is similar to that within 50 miles. The area is sparsely populated and characterized by the large percentage ; of agricultural land and rang eland (Figure 2.1-23). Based on 1979 aerial photos, the percentage of the area within 5 miles that is occupied by each land use type is listed below. Rang eland 40% Water Bodies 3% Cropland 40% Quarries <1% Woodland 9% Cemetery <1% 4 Built-up Area 5% Recreation Area 3%
, rs
)
_,) 2.1-15
WCGS-ER(OLS) Presented below is a description of each land use type, along with livestock production, zoning, and land use trends within 5 miles of the site. Historic, scenic, cultural, and archeological features in the vicinity are discussed in Section 2.6. 2.1.5.2.2 Rangeland Rangeland within 5 miles consists primarily of native and tame g rass but mixed grass, brushland and managed pastures are also present. Cattle are the principal livestock using the rangeland as there are few sheep or horses in the area. 2.1.3.2.3 Cropland Cropland within 5 miles of the WCGS consists primarily of wheat, corn, sorghum, soybeans and alfalfa. Minor acreages o f clover , timothy and orchards are also present. Average yields per acre for crops within 5 miles could be expected to be similiar to county-wide data presented in Tr.ble 2.1-17. Many of the residents within 5 miles of the site maintain vegetable gardens. The distance from the reactor to the nearest vegetable garden, greater than 500 square feet, for each 22-1/2 degree sector was noted during the fall of 1978 and is presented in Table 2.1-18. 2.1.3.2.4 Livestock, Dairy and Poultry Production Beef cattle and hogs are the principal livestock raised near the site. Dairy production is minimal. Presented in Section 2.2.2.3 of the ER(CPS) are the locations and numbers of beef cattle, dairy cows and hogs within 5 miles of the site as of 1973. The dairy cow nearest to the WCGS is approxmately 1.1 miles north. The mil k from all cows nearest to the plant site in each 22-1/2 degree sector is consumed raw by the family members indicated in Table 2.1-18. Dairy herds account for the majority of the remaining milk cows within 5 miles. The dairy herds produce grades B and C milk, manufacturing grades, which are primarily sold to various milk buyers for production o f butter, cheese, powder, ice cream and other frozen products. Manufacturing grade milk may also be sold to local families for liquid consumption or used on the farm where it is pro-duced. Th ro ug ho ut Kansas in 1977, milk used or sold on the farms where it was produced averaged approximately 3 percent of total production, the remainder was sold to plants and dealers (Kansas Crop and Livestock Reporting Service, 1978b) . None of the dairy herds produce grade A milk which can be sold commercially for liquid consumption (Bonewitz, 1979). 2.1-16
WCGS-ER(OLS) gs Egg production within 5 miles is limited to small family ( operations on individual farms. Egg production in Kansas sc m is approximate 3 y 230 eggs per layer per year (Kansas Crop and Livestock Reporting Service, 1978c) . The number and location of laying hens and broiler chickens within 5 miles is presented in Section 2.2.2.3 of the ER(CPS). The number of sheep and miscellaneous livestock surveyed in
'1973 within 5 miles of- the plant' site is also listed in the ER(CPS).
The numbers of livestock on farms are frequently changing due to marketings, purchases, births and deaths, therefore, the 1973 data presented in the ER(CPS) are subject to con-tinous change.- A reconnaissance of. the 5-mile radius area in 1979, however, did not . reveal any obvious significant changes in livestock practices outside the site boundary. Therefore, the 1973 survey is. expected to be fairly rep-resentive of the livestock distribution outside the site boundary in 1979. A survey was also conducted in 1978 to. determine the distance f rom the reactor to the nearest milk cow, milk goat and meat animal. These distances are presented in Table 2.1-18.
, 2.1.3.2.5 Woodlands The woodlands within 5 miles of the site consist predom-inately of deciduous hardwoods along the creek and river systems (Figure 2.1-23) but osage-orange also occurs in hedgerows -and in scattered stands in upland fields. The total estimated area of woodland within 5 miles of the site is 4,690 acres. There is little apparent commercial uti-lization of the woodlands.
2.1.3.2.6 Built-Up Areas Built-up areas occupy approximately 5 percent of the area teithin 5 miles of the WCGS. These areas include residential, commercial, industrial, and sewerage facilities; subdivisions; areas within city boundaries; a pipeline pumping facility; and
. land parcels within the site boundary that will be occupied by WCGS facilities. Outside of the WCGS site boundaries most built-up areas are concentrated in and around-the towns of Burlington and New Strawn (Figure 2.1-23). Clustered and individual rural residences, isolated commercial establish-ments and transportation systems are not indicated on Figure 2.1-23. ~ More detailed description of the land use of the built-up areas is provided in Section'2.1.2; further descrip-tion of the:WCGS site area is presented in Section 2.1.3.3.
(_,) 2.1-17
WCGS-ER(OLS) The local road system and many of the nearby facilities and institutions are shown on Figure 2.1-21. U. S. High-way 75, 2.8 miles west, is the only major highway within 5 miles. The nearest existing railroad is the Missouri Pacific Railroad, located 9.5 miles southeast of the site. A spur from this line has been constructed to the site. Presently, the Applicants have no plans to make the spur available for use by others. The Santa Fe Railroad and right-of-way located 0.3 miles west of the plant site is abandoned. 2.1.3.2.7 Recreation Areas The recreation area classification on Figure 2.1-23 includes city parks, the John Redmond Rerervoir Recreation Area, and the Outdoor Laboratory for Envirenmental Education. For further information on nearby recreation areas and public facilities see Section 2.1.2.3. 2.1.3.2.8 Water Bodies The surface waters mapped within 5 miles of the site include the John Redmond Reservoir, Mathias Lake and the Neosho River (Figure 2.1-23). Small farm ponds, oxbow lakes and small streams such as Wolf Creek and Long Creek are not indicated. Water use within 5 miles is described in Section 2.1.3.5. 2.1.3.2.9 Quarries Most of the quarries indicated on Figure 2.1-23 have been abandoned. The only operating quarry within 5 miles of the site is owned by Nelson Quarry, Inc. It is located 3 miles south-southwest of the plant site. Total acreage of all quarries within 5 miles is approximately 160 acres. 2.1.3.2.10 Zoning Indicated on Figure 2.1-24 are the zoning district bound-aries of the Coffey County Zoning Resolution (Board of Commissioners o f Co f f ey County, 1968) and the Burlington City Zoning Ordinance (Simon, 1976). There is no other type of zoning in the area. Most ef the lands zoned by the city or county within 5 miles are designated as Ag ricultural District. The cooling lake for tha WCGS will occupy approximately 700 to 800 acres of county zoned land and 2,200 to 2,300 acres of city zoned land. The remainder of the cooling lake area is not zoned. These zoned lands within the boundaries of the cooling lake are designated as Ag ricultural . l The Coffey County Commissioners passed a County Zoning Amend- l ment in 197 6 that g r anted the Applicants a conditional use zoning change that would include the electrical generating 2.1-18 l
_ WCGS-ER (OLS ) 7 ~g- -facility and its pertinent structures. The_ permitted uses ( ) within the' Agricultural District of the City Zoning Or-As/ dinance specifically include power plants and all.appur-tenances necessary for their construction.and operation, and public utility installations. Therefore, the WCGS is t- in accordance with the County Zoning Regulations and the Cit) of Burlington Zoning Regulations. Other specific permitted and. conditional uses for the zoning districts within 5 miles of the plant site are discussed in the Coffey County Zoning Resolution (Board of Commissioners of Coffey County, 1968) and the Burlington City Zoning Ordinance (Simon, 1976). 2.1.3.2.11 Trends and Projected Land Use The primary land use trend in Coffey County has been the continued decrease in the number of farms and increase in the average size of farms. The total land area in farms in Coffey County has changed little from 1969 to 1977 (Table 2.1-17). Outside of the site boundary, no new land use trends have been identified within 5 miles of the WCGS that would disturb the rural agricultural characteristics present today. This pro-
- jection is based on population forecasts (see Section 2.1.2) .
and trends observed over several years. (\/ A 1979 field reconnaissance noted only minor new develop-ments since 3 973 within 5 miles of the WCGS, not including site construction activities. The more apparent changes in recent years have been an increase ir, the number of large rural homesites on nearby agricultural-land. The residents often have a few farm animals and may cultivate large gardens but their primary source of income is expected to be from non-farm employment. New residential construction is also evident near the southwest and north boundaries of Burlington city limits. A comparison of 1979 aerial photographs and _the 1973 land use map ("igure 2.1-23) indicated the following approximate changes in land use types within 5 miles of the site: Rangeland -3,100 acres Cropland +1,850 acres Woodland - 130 acres Built-up area +1,360 acres Quarries + 30 acres , The increased acreage of built-up area is primarily due
- to the new site facilities within the WCGS site boundaries.
A ks _,) 2.1-19 _ . -_- - .-~ ._ . - - _ _2 , -. . , . , , . _ _ _
WCGS-ER(OLS) l Bu rl ing to n , the county seat and rural service center for the county, should remain about the same size as today, though there should be some additional growth due to the plant. The recreational communities of New Strawn and the subdi-visions of Hillview and Romer's Point should also undergo only moderate to no growth. The existence of the John Redmond Reservoir has not encouraged a recreational building boom of second homes and retirement housing as many other a aservoirs in the country have. This is because this lake was designed primarily as a flood-control facility, not a recreational lake. The reservoir level flue-tuates greatly between periods of high water and conservation pool level. The reservoir is also rather shallow, being an inundated floodplain of the Neosho River. As a result, the shoreline frequently fluctuates. In addition, the U.S. Army Corps of Engineers owns the land around the reservoir. 2.1.3.3 Land Use Within The Site Area 2.1.3.3.] General Description A detailed site description is presented in Section 2.1.1 2. Included in that section and on Figures 2.1-2 through 2.1-7 are descriptions of the site boundaries, exclusion area, acre-age owned by the Applicants, acreage modified for operation facilities, and nearby transportation routes. There are no commercial or industrial structures, parks , or scenic or natural designated dedicated areas within the site boundary. The only residential structures within the site boundary are located in the northwest sector; the nearest structure is located approximately 2.3 miles f rom the reactor site. Historic and archeological sites are described in Section 2.6. Trcnsmission line rights-of-way off the site are discussed in Section 3.9. 2.1.3.3.2 Previous Land Use Prior to the Applicants' purchase, the principal land use within the site boundary was for grazing livestock and crop production. In 1973, approximately 46 percent of the site area was rangeland, 38 percent was cropland, 11 percent was woodland and 3 percent was idle land. The remaining 2 percent was occupied by ponds, roads, gravel pits, ra il road , rural residences, farm buildings, and cemetery (see Figure 2.1-7 of the ER(CPS)]. The new service roads, reactor site, dams and other facilities for plant operation have since displaced portions of this agricultural land. Further discussion of the land resources required for operation of the station and facilities is presented in Section 2.8. 2.1-20
~ , . __ - _
WCGS-ER.(OLS ) 2.1.3.3.3 Land Use Capabilities ( A description of' the soils on the site and their . capabilities regarding agricultural potential, wildlife habitat and general construction characteristics are presented in Section 2.2.2.8 of the EP(CPS). Since the ER(CPS) several of the soil units mapped on the site have been. designated as prime farmland by the Soil Conservation Service (Swanson, 1979). These prime farmland soil types are listed below: 41B - Bates loam, 1 to 4 percent slopes - 41C - Bates loam, 4 to 7 percent slopes ! 428 - Dennis silt loam, I to 4 percent slopes 32 - Kenoma silt loam, 1 to 3 percent slopes 3283 - Kenoma silt loam, 1 to 4 percent slopes, eroded 15 - Lanton silty clay loam. This is a new name; previously mapped as Oakwood silty clay loam.
-~ 16 - Leanna silt loam
\- / 21(23) - Lula silt loam. This is a new designation; it includes Labette silt loams, O to 2 percent slopes that were mapped previously 18 - Osage silty clay loam.
4 l 14 - Osage silty clay 22B - Suinmit silty clay loam, 1 to 4 percent slopes 12 - Verdigris silt _ loam. This has been changed to alro include the Mason silt loam that was j mapped previously 31 - Woodson silt loam These prime farmland designations are subject to change prior to publishing the Coffey County soil Survey, which j is expected to be completed in 1981. Thure_are no designated unique farmlands or farmlands of state or local significance in Coffey county (Swanson, 1979). O
~
I 2.1-21
WCGS-ER(OLS) 2.1.3.3.4 Projected Land Use and Visitors Center A lake use study was conducted to determine the feasibility of allowing public use of the WCGS cooling lake for recreational purposes. Currently, there are no plans for public use of the cooling lake or lands within the site boundary adjacent to the cooling lake not needed during operation of the station and related facilities (see Section 2.6). At present the only area of the site which will be open for public use will be the visitor center. The location of the visitors center has not yet been finalized. 2.1.3.4 Water Use hithin 50 Miles 2.1.3.4.1 Municipal, Industrial, Irrigation and Recreation Uses This section discusses the regional ground-water use and the principal surface-water users of the Neosho River downstream of the WCGS site to the Kansas-Oklahoma state line (approx - mately 170 river miles). Reg a rd ing surface-water use, only users downstream of the plant discharge are described since these are most likely to be affected by plant effluent releases. Descriptions of the Neosho River and its major tributaries, streamflow gauging stations, major reservoirs and ground-water gradients are presented in Section 2.4. The effects of regional consumptive water use by the plant on water supplies are discussed in Sections 2.4, 3.3 and 5.7. Water and sewage treatment processes of the plant are d isc us sed in Sections 3.6, 3.7, 5.3 and 5.4. The water use estimates presented herein are based primarily on unpublished data which consisted primarily of estimated annual totals. Little information was available for monthly or seasonal variations, or for past and projected water use. The principal water withdrawal from the Neosho River down-stream of the site is for municipal use, followed by indus-trial, irrigation and recreational uses. Listed in Tables 2.1-19 and 2.1-20 are the major water ueurs and dischargers on the Neosho River downstream of the site. The loca tions o f the major water users are indicated on Figure 2.1-25. The City of LeRoy is the nearest municipal uater user downstream o f Wol f Cree) (13.5 miles). More detail regarding the incorporated municipal water supply systems downstream of the site is presented in Table l 2.1-21. These municipal systems supply water for domestic, l commercial, industrial and public-water requirements. Rural ' water dist ricts (RWD) utilizing the Neosho River, either l directly or indirectly, are also listed in Table 2.1-21. l 2.1-22 01l 1 l l
WCGS-ER(OLS) [') The RWDs have been formed in those areas where g round-water ( _/ resources are limited. Municipal ground-water supplies within a 20-mile adius of the site are listed in Table 2.1 their locations are shown on Figure 2.1-26. Many rural residences rely on individual wells for domestic needs and livestock watering. There is no commercial water traffic on either the Neosho River or on the John Redmond Reservoir. 2.1.3.4.2 Commercial and Recreational Fish Harvest The principal fishing waters that are contiguous with the WCGS discharge and that may be influenced by the station effluents include the Neosho River downstream from the John Redmond Dam and tributary streams to the Neosho River. Within 50 miles of the plant site thic includes apprrximately 100 anglable river miles of the Neosho River and approximately 24 tributaries with 240 stream miles of anglable waters. Fish cannot move upstream on the Neosho River past the John Redmond Dam. Therefore, fisheries upstream of the John Redmond Dam would no t be influenced by station effluents. Although numerous city and county lakes, farm and ranch ponds, and other small lakes may also be considered contig-fg uous with waters receiving station effluents (since their ( ) waters eventually flow into the Neosho River), they at ? \_ / not considered in the following discussion since many small dams block continuous flow during dry seasons and are also barriers to fish moving upstream. Commercial Fishing - There is no commercial fishing nor any commercial fish farms in contiguous waters within 50 miles of the WCGS (Ha r tmann , 1979; Kansas Fish and Game Commission, 1977). Mussels, however, are commercially harvested from the Neosho River, but none of the catch is used for human consumption. The shells are ex po r ted for seeding pearls in clams. The most recent annual mussel harvest estimate was for the 1969-1970 season and included both the Neosho and Verdigris rivers; total harvest was 600,000 pounds (272 metric . tons) and was valued at $21,000. The annual harvest for the three previous seasons was 32,000 pounds (14.5 metric tons) in 1966-1967, 24,000 pounds (10.9 metric tons) in 1967-1968, and 8,750 pounds (3. 9 metric tons) in 1968-1969 (Hartmann, 1979). Recreational Fishing - The Neosho River and many of its tributaries within 50 miles of the WCGS provide good sport-fishing, primarily for panfish and catfish. The species of fish caught by anglers in these waters are listed below (Ra y, 1976): r\ i ('- 2.1-23
WCGS-ER (OLS ) channel catfish bullheads walleye flathead catfish largemouth bass spotted bass carp white bass paddlefish white crappie sunfish blue catfish freshwater drum buffalo The principal fishing areas on the Neosho River are generally restricted to adjacent towns, road crossings, low water or overflow dams and reservoir tailwatt s. The most popular areas within 100 river miles downstream of the John Redmond Dam are the John Redmond Da... stilling basin area and dams at the cities of Burlington, LeRoy, Neosho Falls, Iola, Humboldt, Erie and Chanute (Jirak, 1979; Ray, 1976). Although recreational fish harvest estimates for the Neosho River 'nd its tributaries are not available, angler utiliza-tion af these waters has been reported (Ray, 1976). The estimated angler use for the 100 miles of the Neosho River below the John Redmond Dam and for the 24 anglable tributaries is estimated to be approximately 54,000 man-days per year. The catch rate from these waters is expected to be similar to the regional lake harvest objective of approximately two fise per man-day, each weighing 1/2 pound (Brunson, 1979). Based on these estimates the annual harvest from these waters was determined to be approximately 54,000 pounds (24.5 metric tons). No data were available concerning the amount of sport fish consumed locally. Fishermen residing beyond the 50-mile radius area from the WCGS will likely fish within the area and, therefore, only a portion of the harvest would be expected to be consumed locally. 2.1.3.5 Water Use Within 5 Miles 2.1.3.5.1 Municipal, Industrial, Irrigation and Recreation Uses All surface water rights within 5 miles of the site, except for two, are located on the Neosho River upstream of the confluence with Wolf Creek. Of the two remaining water rights, one is located on Long Creek, in the adjacent water-shed east of the site; the other water right is held by the Applicants for storage of natural flows on Wolf Creek. The water rights on the Neosho River between Wolf Creek and the John Redmond Dam are held for municipal, inductrial, irrigation and recreation use. The municipal water rights are for the City of Burlington and Coffey County Rural Water Districts 2 and 3; the industrial water rights are held by 2.1-24 9
WCGS-ER(OLS) A l ) the Applicants for use at the WCGS; several individuals hold
\~ / water rights for irrigation use; and, the recreation water rights are held by the Kansas Fish and Game Commission.
The only National Pollution Discharge Elimination System (NPDES) discharger identified on the Neosho River between the John Redmond Dam and the Wolf Creek is the City of Burlington. The design discharge capacity for the City of Burlington is 0.32 million ' gallons per day (mgd). However, the actual discharge is reportedly 0.25 mgd (Waldo, 2179). The City of Burlington and the Applicants also have each been issued 404 permits by the U.S. Army Corps of Engineers for construc-tion of water intake structures on the Neosho River above Wolf Creek (Houge, 1979). Related construction activities should have mincr ef fects on the water quality near Wolf Creek if the permit stipulations are satisfied Ifor 404 permit stipulations see U.S. Army Corps of Engineers (4977)). Recrea tional areas within a 5-mile radius that offer water-based ;tivities are discussed in Section 2.1.2 Within a 5-mile radius or the WCGS, numerous individuals utilize ground water for domestic supplies and livestock watering. Local streams and farm ponds are also used for livestock watering. Figure 2.1-27 shows the location of f'"3 individual wells, and Table 2.1-23 provides pertinent data (' ,j on these wells. The regional and local hydraulic gradient of ground water and typical yields in the local aquifers are discussed in Section 2. 4. 2.1.3.5.2 Recreational Fishing The closest locations to the point of discharge downstream on Wolf Creek that are publicly accessible are several small road bridges across Wolf Creek. All of the lands adjacent to Wolf Creek downstream of the discharge are privately owned. The closest bridge is on Federal-Aid Secondary Highway 10, approximately one-half mile downstream of the main dam. The species of fish caught by anglers in Wolf Creek include channel catfish, white crappie and black bullhead. There are 3.0 miles of Wolf Creek that have angling potential and estimated fisherman use is 60 man-days per year (Ray, 1976). i /~% 1 \J 2.1-25
WCGS-ER(OLS) 2.
1.4 REFERENCES
Bell, W.W., 1979, County Extension Agent, Burlington, Kansas, oral communication (January 18). Board of Commissioners of Co ffey County, 1968, Coffey County zoning resolution (January 29) .
, 1976, Amendment to Cof fey County zoning resolution (December 20), Bu rl ing ton , Kansas.
Bonewitz, R., 1979, Extension Dairy Specialist, Kansas State University, Manhattan, Kansas, personal communication (February 16). Boyce, E.M., 1979, owner, Arrowhead Hills Golf Course, Bur-ling to n , Kansas, oral communication. Brazle, F.K., 1979, Livestock Specialist, Extension Service, Chanute, Kansas, personal communication (January 26) . Brown, S., 1979, Coffey County Tax Assessor, Co f f e y Co unty Co u r tho us e , Burlington, Kansas, oral communication. Brunson, K., 1979, Stream Biologist, Kansas Fish and Game Commission, Pratt, Kansas, oral communication ( Se p-tember 12). Chester, M., 1979, Project Manager, U.S. Army Corps of Engineers, John Redmond Reservoir, Kansas, oral com-munication. DeMott, S., 1979, County Appraiser's Office, Lyon Co un ty , Kansas, oral communication. Duncan, D., 1979, Project Headquarters, John Redmond Reser-voir, Kansas, oral communication. Flickeng er , G. , 1979, Associate Engineer, Water Resources Board, Topeka, Kansas, written communication (March 9). Flora, C., 1975, Department of Administration, Division of State Planning, Topeka, Kansas. Freeman, E., 1979, Sheriff, Coffey County, Bu rl ing ton , Kansas, oral communications. Garrett, Mrs., 1979, Administrato r, Golden Age Lodge of Burlington, Bu rl ing to n , Kansas, oral communication. 2.1-26 O
i WCGS-ER(OLS)
- Gettinger, L., Records, Kansas State Board of Ag riculture, s_/. Division of Water-Resources, Topeka, Kansas, written communication (Augustz24).
1
- Greenberg , ._ M.R. , _Krueckeberg, D.A., and Mautner, R.,'1973, Long-range population projections for minor civil divisions, Computer prog rams and user's manual . Center
-for Urban Policy Research, Rutgers University, New Brunswick,' New Jersey (prog ram revised by Dames & Moore staff, Cranford, New Jersey).
! Griffith-, W., _1979, Administrator, Coffey County Hospital,
. Burling ton, Kansas, oral communication.
Harris, J.H., 1979, Hillview Development, New Strawn, Kansas, oral communication. Hartmann, R.F., 1979, Supervisor of Investigations and
- Development, Kansas Fish and Game Commission, Pratt, J
Kansas, oral communication (January 10 and 30) , and written communication (January 23) . Herndon, Wayne, 1979, State Recreation Planner, Kansas Park and Resources Authority, Topeka, oral communication 3 (October 30).
,O 1 Ho ug e , L., 1979, U.S. Army Corps of Engineers, Tulsa, Okla- ; homa, oral-communication (September 21).
- Ijans, C., 1978, Kansas Department of Transportation, Planning-and Development ' Depar tment , Topeka, Kansas, oral com-
- 'munication (December 28).
. Jirak, L., 1979, Stream Biologist, Kansas Fish and Game Commission, New Strawn, Kansas, oral communication (February 21).
Johnson, N.F., 1979, Furbearer Project Leader, Kansas Fish and Game Commission, Pratt, Kansas, written communication 4 (January) and oral communication (January 23) . Jones, 0., 1979, Mayor, New Strawn, Kansas, oral communi-cation. Kansas Crop and Livestock Reporting Service, 1978a, 61st Annual report 7and farm facts, Kansas State Board of Ag ric ul tu re , Topeka.
, 1978b, Milk-Disposition and income, fact sheet (May 9) ,
3 Kansas State Board ~ of ~ Agriculture, Topeka. v 2.1-27 L p
,.-T- -
1= -- *i se^ - - t w *r - - -m't*"w $-"t n- +-W' *- w --W- "ev -'fer-"T- M-w* +w
- e- r - t T M 7-*'s-4't-te-*'ar*=r-P-*4
- WCGS-ER (C LS )
, 1978c, Poultry monthly bulletin, Vol. 78, No. 12 Kansas State Board of Ag riculture, Topeka.
Kansas Fish and Game Commission, 1976, Population and har\ rest summary ceports: quail, prairie chicken, nheasant, cottontail, jackrabbit, tree squirrel and farbearer, Prat:, Kansas.
, 1977, Commercial fish dealers in Kansas - 1977, Pratt, Kansas.
, 1978, Small game hunter activity survey - 1977.
Job No. J-1-16, Pratt, Kansas. Kansas Park and Resources Authority, and Oblinger-Smith Cor-poration, 1975, Outdoor Recreation Plan for Kansas. Kansas State Board of Ag riculture, 1979, Open file material: Division of Water Resources, Topeka, Kansas (Ma rch) . Kastens, W., 1979, assistant State Statistician, Kansas Crop and Livestock Reporting Service, Topeka, Kansas, oral communication (August 8). Knight, Mrs., 1979, County Appraiser's Office, Franklin County, Kansas, oral communication. Kraft, M.J., 1979, Waterfowl Project Leader, Kansas Fish and Game Commission, Pratt, Kansas, written con.munica-tion (January 26). Montei, K., 1979, Head of Wildlife Research, Kansas Fish and Game Commission, Pratt, Kansas written communication (January 18) . National Center for Health Statistics, 1979, Vital Statistics Report, Births, Marriages, Divorces, and Deaths for January 1979, DHEW Publication Number (PHS) 79-1120, Vol. 28, No. 1. Ray, J., 1976, Neosho River Basin, Kansas; Preliminary stream survey. Study 010, Job 010. Kansas Fish and Game Com-mission, Pratt, Kansas. Reischick, L., 1973, Farmer's Home Administration, Bur-ling to n , Kansas, personal communication (September) . Remer, M., 1979, Remer's Point Development, New Strawn, Kansas, oral communication. Schlicher, V., 1979, County Appraiser's Office, Shawnee County,. Kansas, oral communication. 2.1-28
WCGS-ER(OLS) (A
\~ /
-i Sexon, K., 1979, Big Game Project Leader, Kansas Fish and Game Commission,.Pratt, Kansas, written communication (February 6).
Simon, S.S., 1976, Zoning ordinance for the city of Bur- l
- ling ton, Kansas.
Superintendent of Unified School District 244, 1979, Bur-ling to n , Kansas, oral communication. Swanson, D.W., 1979, Soil Scientist, Soil Conservation Service, Bu rl ing ton , Kansas, written communication (September 12) . , Tiemann, L., 1979, Regional Wildlife Supervisor, Kansts Fish and Game Commission, Chanute, Kansas, oral communication (January 23) . U.S. Army Corps o f Eng ineers , 1977, Regulatory prog ram of the Corps of Engineers, Part 323.4, Federal Register Vol. 42, No. 138. (July 19) . U.S. Bureau of the Census, 1971, Number of inhabitants, U.S. census of population--1970, U.S. Bureau of the Census, Final Report P.C. (1)-A18, Kansas.
, 1977, Projections of the population of the United i
States: 1977 to 2050, Current Population Reports, U.S. Bureau o f the Census , Series P-25, No. 704.
, 1977, 1974 census of agriculture: U.S. Government Printing Of fice, Washing ton, D.C. , vol. 1, part 16, Kansas.
, 1978, Illustrative Projections of State Populations:
1975 to 2000. . Current Population Re po r ts , .U. S. Bureau of the Census, Department of Commerce, Series P-25, No. 735. Vajne, Mrs. J., 1979, Honey Tree Preschool, New Strawn, Kansas, oral' communication. ! Waldo, D.F., 1979, Water Pollution Control Section, Kansas State Department of Health and Environment, Topeka, Kansas, written communication. Yokum, T., 1979, Bic2ogy Instructor, Burlington High School, Burlington, Kansas, oral communication. i O a 2.1-29
1 WCGS-ER(OLS)' ()
\g TABLE 2.. ( Sheet 1 of 4 POPULATION OF INCORPORATED
' PLACES WITHIN 50 MILES OF THE SITE Percent Loca tion 1960 1970 Change (miles from site)
' Allen County Basset 67 62 - 7.5 27.7 SE i Elsmore 128 116 - 9.4 42.0 SE 1
Gas 342 438 28.1 28.3 SE . Humboldt 2,285 2,249 - 1.6 32.1 SSE Iola 6 ,' 8 8 5 6,493 - 5.7 25.9 SE La Harpe 529 509 - 3.8 29.6 SE Mildred 60 42 -30.0 31.1 ESE Moran 549 550 0.2 35.4 SE Savonburg 131 109 -16.8 44. 2 SE Anderson County Colony 419 382 - 8.8 20.8 ESE l Garnett 3,034 3,169 4.4 23.3 E , Greeley 415 368- -11.3 31.8 ENE Harris 36 41 13.9 13.7 NE Kincaid 220 -189 -14.1 30.5 ESE Lone Elm 69 66 - 4.3 26.2 ESE Westphalia 249 '185 -25.7 10.6 ESE Bourbon County Bronson 354 397 12.1 41.1 SE Mapleton 127 112 -11.8 46.0 ESE Uniontown 211 286 35.5 46.6 SE Butler County (none) . Chase County Cottonwood Falls 971 987 1.6 46.4 WNW' Matfield Green 95 77 -18.9 47.3 W l Strong City 659 545 -17.3 46.9 WNW l Source: U.S.. Bureau of Census, 1971, Number of inhabitants - Kansas, U.S. census of population - 1970: U.S. Government Printing Of fice, ' Final Report PC (1)-A18.
. ,. . , .- .....,c - - , - -. , - - - - - - . ., ...,.,n_,,_ ,, ,
WCGS-ER (O LS ) TABLE 2.1-1 (continued) Sheet 2 cf 4 , Percent Lo ca tio n 1960 1970 Change (miles from site) Coffey County Burlington 2,313 2,099 - C.7 3. 5 SW Gridley El 328 2.2 14.2 SW Lebo 498 589 18.3 14.5 NW LeRoy 601 551 - 8.3 10.8 SSE New Strawn* 3.0 NW Waverly 381 510 33.9 11.1 NNE Douglas County Baldwin City 1,C77 2,520 34.3 45.8 NE Elk County (none) Franklin County Lane 282 254 - 9.9 35.0 ENE Ottawa 10,673 11,036 3.4 32.5 NE Pomo na 489 541 10.6 29.9 NNE Princeton 174 159 - 8.6 27.4 NE Rantoul 157 163 3.8 35.2 NE Richmond 352 464 31.8 25.4 ENE Wellsville 984 1,183 20.2 46.0 NE Williamsburg 255 286 12.2 19. 2 NE Greenwood County Climax 81 64 -27.0 45.9 SW Eureka 4,055 3,576 -11,0 42.9 SW Fa 1 River 226 191 -15.5 46.1 SSW Ham.lton 400 349 -12.8 31. 3 SW Madison 1,105 1,061 - 4. 0 23.6 SW Virgil 229 179 -21.8 24.2 SW Johnson County (none)
- New Strawn was incorporated in 1971.
O
a WCGS-ER (O LS ) 1 TABLE'2.1-1 (continued) Sheet 3 of 4 , sl Percent Loca tion 1960 1970 Change (miles from site) Linn Csunty Blue-Mound. 319 308 - 3.4 37.7 ESE La Cygne 810 939 22.1 48.0 E Mound. City 601 714 8.0 47.6'E Parker 181 255 40.9 37.5 E Lyon County Admire -149 '144 - 3.4 34.9 NW Allen 205 175 -14.6 38.4 NW Amerieus 300 441 47.0 35.7 WNW Bushong 51 39 -23.5 41.5 NW j Em po r ia 18,190 22,327 28.2 28.0 WNW Hartford 337 478 41.8 14.8 WNW Neosho Rapids 178 234 31.5 17.2 WNW Olpe 722 453 -37.3 25.5 W Reading 249 247 - 0.8 23.6 NW Miami County Fontana 138 160 15.9 47.0 ENE Osawantomie 4,622 4,294 -71.] 42.8 ENE Paola 1,784 4,622. - 3.4 48.2 ENE i Morris County Dunlap 134 102 -23.9 43.2 WNW Neosho County Chanute 10,849 10,341 - 4.7 40.0 SSE Earlton 104 102 - 1.9 45.6 SSE
-Stark 96 124 29.2 47.5 SE Osage County Burlingame 1,151 999 -13.2 35.7 NNW Carbondale 664 1,041 56.8 39.0 N Lyndon 953 958 0.5 24.6 N Melvern 376 455 21.0 17.7 N Olivet 116 64 -44.8 16.3 N Osage City 2,213 2,600 17.5 27.0 N
'Overbrook 509 748 47.0 37.4 N Quenemo 434 429 - 1.2 24.8 NNE Scranton 576 575 - 0.2 37.4 N l
f
, . . - --,-,n -
, - , , , - ----,n., . . , , , , - - . , , . - , , - , - ~ - - . . . , , , .
WCGS-ER(OLS) TABLE 2.1-1 (continued) Sheet 4 of 4 Percent Loca tion 1960 1970 Change (miles from site) Shawnee County Auburn - 261 - 46.2 N Wabaunsee County Eskridge 519 589 13.5 48.3 NNW Harveyville 204 279 36.8 32.4 NNW Wilson County Altoona 490 475 - 3.1 48.8 S Benedict 128 91 -28.9 41.5 S Buffalo 422 321 -23.9 35.7 S Coyville 133 93 -30.1 40.1 SSW Fredonia 3,233 3,080 - 4.7 48.2 S New Albany 104 59 -43.3 47.4 SSW Woodson County Neosho Falls 222 184 -17.1 16.8 SSE Toronto 524 431 -17.7 32.8 SSW Yates Center 2,080 1,967 - 5.4 23.9 S 1 1 01
.- ,~ _ .. . . - . . . . . - -
WCGS-ER (O LS ) e TABLE 2.1-2 Sheet 1 of 3 RESIDENT POPULATION DISTRIBUTION BY SECTOR AND RADIAL DISTANCE UP TO 10 MILESP Radial Distance from Reactor (Miles) Mile Sector Year 0-1 1-2 2-3 3-4 4-5 5-10 Total i N 1970 0 3 2 9 1 75 90 1980 0 10 10 10 10 70 110
- 1990 0 10 10 10 10 60 100 l 2000 0 10 10 10 10 60 100 2010 0 10 10 10 0 40 70 2020 0 10 10 10 0 30 60 NNE 1970 0 1 1 5 18 147 172 1980 0 10 10 10 20 150 200 I 1990 0 10 10 10 20 140 19 0 t 2000 0 10 10 10 20 140 190 2010 0 10 10 10 10 110 150 2020 0 0 0 10 10 90 110 NE 1970 0 1 4 11 6 74 96 1980 0 10 10 10 10 70 110 1990 0 10 10 10 10 70 110
, 2000 0 .10 10 10 10 60 100 2010 0 0 10 10 10 50 80 2020 0 0 10 10' 10 40 70 DIE 1970 0 0 7 3 4 77 91 1980 0 0 10 10 10 70 109 1990 0 0 10 10 10 70 100 2000 0 0 10 10 10 60 90 2010 0 0 10 10 10 50 80 2020 0 0 10 10 10 40 70 j E 1970 0 3 1 1 1 61 67 1980 0 10 10 10 10 50 90 1990 0 10 10 10 10 50 90'_
- - 2000 0 10 10 10 10 40 80 2010 0 10 0 0 0 30 40
! .2020 0 10 0 0 0 20 30 If the projected populati n is less than 10, the projections have been l rounded upward. Thus, if there are 2 persons projected, the number has been rounded to 10. l ! y n {~ _ . _ , . , . . _ . . . , - - , - . - . , . - - . . . . - _ . - . . . , , . - . - . . . . _ , . ,, , ,, ,..,..,,__m._ . .,,,, . _ _ _ _ _ . _ . , _ _
WCGS-ER(OLS) TABLE 2.1-2 (continued) Sheet 2 of 3 Radial Distance from Reactor (Miles) 10-Mile Sector Year 0-1 1-2 2-3 3-4 4-5 5-10 Total ESE 1970 0 9 7 3 18 90 127 1980 0 10 10 10 20 80 130 1990 0 10 10 10 10 80 120 2000 0 10 10 10 10 70 110 2010 0 10 10 10 10 50 90 2020 0 10 10 10 10 40 80 SE 1970 0 4 7 7 8 107 133 1980 0 10 10 10 10 100 140 1990 0 10 10 10 10 90 130 2000 0 10 10 10 10 90 130 2010 0 10 10 10 10 70 110 2020 0 10 10 10 10 50 90 SSE 1970 2 7 7 1 9 260 286 1980 0 0 0 10 10 250 270 1990 0 0 0 10 10 250 270 2000 0 0 0 0 10 240 250 2010 0 0 0 0 10 200 210 2020 0 0 0 0 10 150 160 S 1970 0 4 7 14 9 84 117 1980 0 0 0 10 10 80 100 1990 0 0 0 10 10 70 90 2000 0 0 0 10 10 60 80 2010 0 0 0 10 10 50 70 2020 0 0 0 10 10 30 50 SSW 1970 0 0 0 0 7 89 96 1980 0 0 0 0 10 90 100 1990 0 0 0 0 10 80 90 2000 0 0 0 0 10 80 90 2010 0 0 0 0 10 60 70 2020 0 0 0 0 10 50 60 SW 1970 2 0 6 652 1,4 31 211 2,302 1980 0 0 10 710 1,560 220 2,500 1990 0 0 10 790 1,730 230 2,760 2000 0 0 10 860 1,880 230 2,980 l 2010 0 0 10 780 1,700 200 2,690 I 2020 0 0 10 690 1,500 170 2,370 l l O
. . . ._. . . . . . . . - - - ~ . . .. . .-
-- . --. . . _ _ . - . . - . ~. - .-
WCGS-ER(OLS) TABLE 2.1-2 (continued) Sheet 3 of 3 Radial Distance from Reactor (Miles) i 10-Mile Sector Year 0-1 1-2 2-3 3-4 4-5 5-10 Total WSW 1970 0 0 11 29 13 66 119 .l 1980 .0 0 10 30 10 60 110 1990 0 0 10 30 10 50 100 2000 0 0 10 30 10 50 100
- 40 80 2010 0 0 10 20 10 2020 0 C 10 20 10 30 70 W 1970 1 0 13 1 0 43 58 1980 0 0 10 10 0 40 60
! 1990 0 0 10 10 0 30 50 ! 2000 0 0 10 10 0 30 30 2010 0 0 10 10 0 20 40 i 2020 0 0 10 10 0 10 30 WNW 1970 0 0 3 49 14 24 90 1980 0 0 10 5 30 80 20 640 1990 0 0 10 760 90 20 880 I 2000 0 0 10 990 100 20 1,120 2010 0 0 10 1,220 110 10 1,350 2020 0 0 10 1,240 120 10 1, 38 0 NW 1970 1 0 22 46 9 54 132 1 1980 0 0 20 270 10 50 350 , ! 1990 0 0 20 39 0 10 40 460 , 2000 0 0 20 510 10 40 580 ' 2010 0 0 10 630 10 30 680 I 2020 0 0 10 650 10 . 20 690 l NNW 1970 0 0 13 5 5 60 83 1980 0 0 10 10 10 50 80 , i 1990 0 0 10 10 10 50 80 2000 0 0 10 10 10 40 70 l 2010 0 0 10 10 10 30 60 4 2020 0 0 10 10 10 20 50 l Total 1970 6 -32 111 836 1,552 1,522 4,059 I 1980 0 60 140' 1,650 1,790 1,450 5,090 i 1990 0 60 140 2,080 1,960 1,380 -5,620 l 2000 'O 60 140 2,490 2,'120 1,310 6,120
- 2010 0 .50 120 2,740 1,920 1,040 5,870 2020 0 40 110 2,690 1,730 800 5,370 1
TABLE 2.1-3 AGE DISTRIBUTIONS FOR THE SITE AREA FOR 1970 and 2000I "I 1970 U.S. Coffey Counties Within 2000 U.S. Age Category Population Co un ty (b) 50 Miles Of Site (b) Population (c) 0 to 12 24% 19% 23% 19% 12 to 18 12% 10% 12% 9% Over 18 64% 71% 65% 72% r
^ Year 2000 is the midpoint (rounded to the nearest census date) of the @
station operating life. y m b 1970 U.S. Census of Po pula tio n , General Population Character- 3 istics, Kansas g c" Projections of the Population of the United States: 1977 to 2050", Population Estimates and Projections, Current Population Repo r ts, Series P-25, No. 704: Bureau of the Census. Note: The 0- to 10-mile 1970 distribution is represented by the "Coffey County" column, and the 10- to 50-mile 1970 distribution by the
" Counties within 50 miles of the Site" column. The projected age distribution for 2000 for 0-to-10 miles and 10-to-50 miles is found in the "2000 U.S. Population" column.
O O O
WCGS-ER (O LS ) 7-~s TABLE 2.1-4 Sheet 1 of 3 RESIDENT POPULATION DISTRIBUTION BY SECTOR AND RADIAL DISTANCE BETWEEN 10 AND 50 MILES Radial Distance from Reactor (Miles) 10-Mile 50-Mile Sector Year Total 10-20 20-30 30-40 40-50 Total N 1970 90 612 2,006 2,280 11,298 16,286 1980 110 550 1,990 2,370 13,700 18,720 1990 100 510 2,0 30 2,550 16,900 22,090 2000 100 460 2,000 2,680 20,100 25,340 2010 70 360 1,720 2,480 23,100 27,730 2020 60 270 1,440 2,260 26,100 30,1 30 NNE 1970 172 650 1,593 1,453 3,627 7,495 1980 200 600 1,460 1,380 3,200 6,840 1990 190 570 , 1,360 1,330 2,950 6,400 2000 190 530 1,240 1,260 2,710 5,930 2010 150 420 990 1,050 2,410 5,020 2020 110 330 780 860 2,100 4,180 NE 1970 96 716 1,101 12,846 4,297 19,056 1980 110 680 1,010 13,700 4,300 19,800 /'~'N 1990 110 650 940 15,000 4,4 30 21,130 ( ) 2000 2010 100 620 850 15,100 4,520 21,190 80 500 690 14,000 4,160 19,430 2020 70 400 540 12,800 3,750 17,560 FNE 1970 91 477 1,449 2,248 9,120 13,385 1980 100 39 0 1,310 2,110 10,100 14,010 1990 100 330 1,210 2,000 11,400 15,040 2000 90 270 1,100 1,880 12,700 16,040 2010 80 190 890 1,540 12,000 14,700 2020 70 140 710 1,230 11,100 13,250 E 1970 67 563 4,266 1,030 1,553 7,479 1980 30 460 4,080 910 1,470 7,010 1990 90 38 0 3,940 810 1,410 6,630 2000 80 310 3,760 730 1,350 6,230 2010 40 220 3,240 560 1,110 5,170 2020 30 160 2,730 420 890 4,230 ESE 1970 127 466 562 1,212 1,532 3,899 1980 130 38 0 460 1,020 1,400 3,390 1990 120 310 370 870 1,290 2,960 2000 110 250 300 740 1,190 2,590 2010 90 180 210 550 960 1,990 2020 80 130 150 400 750 1,510
'j v
WCGS-ER (O LS ) TABLE 2.1-4 (continued) Sheet 2 of 3 Radial Distance from Reactor (Miles) 10-Mile 50-Mile Sector Year Total 10-20 20-30 30-40 40-50 Total SE 1970 133 305 7,525 2,433 1,779 12,175 1980 140 250 7,460 2,290 1,550 11,690 1990 130 210 7,450 2,180 1,370 11,340 2000 130 170 7,370 2,060 1,190 10,920 2010 110 120 6,450 1,720 930 9, 3 30 2020 90 80 5,510 1,410 700 7,790 SSE 1970 286 754 1,176 3,810 13,388 19,414 1980 270 690 1,000 3,660 12,800 18,420 1990 270 630 850 3,550 12,300 17,600 2000 250 580 720 3,410 11,600 16,560 2010 210 450 540 2,920 10,100 14,220 2020 160 350 400 2,450 8,710 12,070 S 1970 117 152 2,798 986 4,367 8,420 1960 100 120 2,600 840 4,520 8,180 1990 90 100 2,4 30 720 4,7 30 8,070 2000 80 80 2,240 620 4,930 7,950 2010 70 60 1,860 460 4,360 6,810 2020 50 40 1,500 34 0 3,770 5,700 SSW 1970 96 336 660 290 947 2,329 1980 100 270 540 240 800 1,950 1990 90 220 450 210 680 1,650 2000 90 180 370 170 580 1,390 2010 70 130 270 130 4 30 1,0 30 2020 60 90 200 90 310 750 SW 1970 2,302 495 452 524 4,332 8,105 1980 2,500 460 310 38 0 3,930 7,580 1990 2,760 430 210 280 3,570 7,250 2000 2,980 410 140 200 3,200 6,9 30 2010 2,690 320 90 130 2,590 5,820 2020 2,370 240 50 80 2,040 4,780 WSW 1970 119 418 986 868 260 2,651 1980 110 360 740 650 180 2,040 1990 100 320 560 480 130 1,590 2000 100 280 410 350 90 1,2 30 2010 80 210 280 230 60 860 2020 70 150 180 150 40 590 0
WCGS-ER (O LS ) TABLE 2.1-4 (continued) Sheet 3 of 3 Radial Distance from Reactor (Miles) 10-Mile 50-Mile
! Sector Year Total 10-20 20- 30 30-40 40-50 Total W 1970 58 460 1,908 1,415 993 4,834 1980 60 420 1,820 1,340 920 4,560 1990 50 38 0 1,730 1,280 920 4,360 4
2000 50 340 1,620 1,220 910 4,140 2010 40 260 1,290 1,000 760 3,350 2020 30 190 1,000 800 620 2,640 WNW 1970 90 415 19,119 6, 38 2 1,491 27,497 1980 640 39 0 23,200 7,470 1,360 33,060 1990 880 370 28,200 8,800 1,320 39,570 2000 1,120 350 33,800 10,300 1,260 46,830 2010 1,350 280 34,300 10,200 1,0 30 47,160 2020 1,380 220 33,900 9,870 810 46,180 l NW 1970 132 851 783 1,056 828 3,650 l 1980 350 ~880 730 970 720 3,650 1990 460 910 670 900 650 3,590 ^ i 2000 580 9 30 620 820 580 3.5 30 2010 680 800 480 640 440 3,040 2020 690 670 36 0 480 330 2,5 30 NNW- 1970 83 252 3,168 1,314 2,342 7,159 1980 80 210 3,220 1,220 2,500 7, 2 30 1990 80 190 3,350 1,150 2,720 7,490 2000 70 160 3,380 1,070 2,930 7,610 2010 60 120 2,960 850 2,600 6,590 2020 50 90 2,520 650 2,260 5,570 Total 1970 4,059 7,922 49,552 40,147 62,154 - 163,834-1980 5,090 7,110 51,930 40,550 63,450 168,130 1990 5,620 6,510 55,750 42,110 66,770 176,760 2000 6,120 5,920 59,920 42,610 69,840 184,410 2010 5,870 4,620 56,260 38,460 67,040 172,250 l 2020 5,370 3,550 51,970- 34,290 64,280 159,460 1 1 i
~ , , .- . .__ _. . - , , . , _ - _ - . , - - . . - . - , - . . , . - - . . . . . _ , , . v
TABLE 2.1-5 SCHOOLS WITHIN 10 MILES OF THE SITE Loca tion School Grades (miles from District School Enrollment Staff Served site) 244 Elementary School 305 15 K-4 4.3 SW Middle School 236 14 5-8 4.3 SW High School 231 18 9-12 4.3 SW Outdoor Laboratory Transient Transient All 4.3-5.7 $ for Environmental from enroll- from staff WNW @ Ed uc a tio n ment listed listed i above above E o Private Honey Tree 24 4-year 1 Preschool 3.0 NW r Preschool olds 3 10 3-year olds Sources: Superintendent of Unified School District 244, 1979, Burlington, Kansas, personal communication. Vajne, Mrs. J., 1979, Honey Tree Preschool, personal communication. Yokum, T., 1979, Biology Instructor, Burlington High School, Burlington, Kansas, personal communication. Note: For locations of these facilities, see Figure 2.1-21. O O O
l WCGS-ER(OLS) TABLE'2.1-6 , . l HOSPITALS Ahu NURSING HOMES , j WITHIN 10 MILES OF THE SITE l Capacity Planned Location - (beds) Staff Expansion (miles from site) [ Coffey l County Hospital 26 80 None 3.7 SW Golden l . Age { -Lodge 115 70 None 3.7 SW 4
' Sources: Griffith, W., 1979, Administrator, Coffey County l Hospital, Burlington, Kansas, personal interview (May 22).
Garrett, Mrs., 1979, Administrator, Golden Age Lodge of Burlington, Burlington, Kansas, personal communication. l Note: For location of these facilities, see Figure 2.1-21. i l i 4 l I a l f i
,,,,-----,,.c.,., -
v---,. ,-_,,.-,r.,-mm.,. % -,e_,,r....,,..e,,. .. m-,. ,,_m.,,-,,.m., ,,,.,,..ey...._,_,-eww. _w,,,-ey..rn+,,w,,eu,-,,.,n,
i WCGS -ER (O LS ) l TABLE 2.1-7 CORRECTIONAL FACILITIES 9l ) 1 WITHIN 10 MILES OF THE SITE Maximum Capacity Loca tion Facility (prisoners) Employees (miles from site) Coffey County Jail 19 7 4.2 SW Source: Freeman, E., 1979, Sheriff, Coffey County, Kansas, personal communication. Note: For location of this facility, see Figure 2.1-21. O O
i
.0
\~-l l TABLE 2.1-8 Sheet 1 of 2 RECREATION FACILITIES WITHIN 10 MILES OF THE SITE '
Loca tion Location Activities Visitor' Statistics (miles from site) Coffey County Baseball 100-150/ game 4. 2 SW 4 Fairgrounds Football . 500-600/ game
- Tractor Pulling 1,700-2,000/ contest .;
Drake Park Fishing 25-35 3. 3 SW . Camping Picnicking
- Floral Park Band Concerts 75 4. 2 SW '%-
General Use @ l Picnicking i M' x Flint Hills _ Warmwater Fishing 4,098/ month 6.8 - 20.8 NW g l
; National Other- 3,868/ month r !
Wildlife Sightseeing 8,827/ month 3 ! Refuge 16,791/ top peak month
- i. (June 1978) i !
l John Redmond Boating 380,000/ year 3.5 W l Reservoir Fishing i Picnicking , Katy Park Tennis 4.6 SW Baseball 50-75/ game
- Swimming 300 daily ,
I Pleasant Campsites 8 permanent 3.2 WSW ;
- ' Valley 5 maximum transient j Tourist Farm I
i
.t 5
TABLE 2.1-8 (continued) Sheet 2 of 2 Location Location Activities Visitor Statistics (miles from site) Rock Creek Golf 90-120 at one time 4.8 SW Country Club Dancing Billiards Dining Arrowhead Golf 85-90/ day on 3. 5 NW Hills summer weekend Sources: Bahr, J., 1973, Vice-President of Fair Association, Burlington, Kansas, written communication. 7 Boyce, E.M., 1979, owner, Arrowhead Hills Golf Course, personal O interview (May 23).
- Chester, M., 1979, Project Manager, U.S. Army Corps of Engineers, $
John Redmond Reservoir, Kansas, personal ecmmuaication. 8 r Duncan, D., 1979, Project Headquarters, John Redmond Resevoir, U.S. m
~
Army Corps of Engineers, Tulsa, Oklahoma. Hayen, B., 1973, Co-owner of Glassco, New Strawn , Kansas, written communication. Helbert, J.R., 1973, Manager of the Rock Creek Country Club, Inc., written communication. Likes, G., 1973, owner of the Pleasant V611ey Tourist Farm, Coffey Coun ty , Kansas, written communication. Lo g a n , M . , 1973, City Clerk, Burlington, Kansas, written communi-cation. Long, M., 1979, Refuge Manager, Flint liills National hildlife Refuge, U.S. Fish & Wildlife Service, Hartford, Kansas. Note: For locations of these facilities, see Figure 2.1-21. O O O
4 WCGS-ER(OLS). TABLE ~2.1 Sheet 1 of 2 POPULATION DISTRIBUTION WITHIN THE I* LOW POPULATION ZONE, 1970 and 1980 Sector Year 0-1 1-2 2-2.5 Total N 1970 0 3 0 3 i 1980*- 0 10 5 15 NNE 1970 -0 1 0 1 1980* 0 10 5 15 { NE 1970 0 1 1 2 1980* 0 10 5 15 ENE 1970 0 0 4 4 1980*- 0 0 5 15 E 1970 0 3 0 3 1980* 0 10 5 15 ESE 1970 0 9 3 12 1980* 0 10 5 15 y SE 1970 0 4 7 11 1 1980* O 10 5 15 ' } SSE 1970 2 7 6 15 1980* 0 0 0 0 S 1970 0 4 4 8 1980* 0 0 0 0 SSW 1970 0 0 0 0 1980* 0 0 0 0 SW 1970 2 0 0 2 1980* 0 0 5 5 WSW 1970 0 0 12 12 1980* 0 0 5 5
*For the 2- to'2.5-mile area outside the cooling lake, the population was apportioned 1/2 in the LPZ l and -1/2 out of the LPZ (Table 2.1-2).
'O
WCGS-ER(OLS) TABLE 2.1-9 (continued) Sheet 2 of 2 Sector Year 0-1 1-2 2-2.5 Total W 1970 1 0 4 5 1980* 0 0 5 5 WNW 1970 0 0 3 3 1980* 0 0 5 5 NW 1970 1 0 la 16 1980* 0 0 10 10 NNW 1970 0 0 4 4 1950* 0 0 5 5 Grand 1970 6 32 63 101 Total 1980* 0 60 70 130 9 4 0
. - _ . . - . . . - -. . . . _ . _ _ ~ - . . . . - . _ . . _ . . . - - _ - . ~. - -. - _.-.-. . - . - - , . . . . = . - . , . . ..~ .....-.
4 TABLE 2.1-10 i
- COMPARISON OF POPULATION DENSITY DISTRIBUTIONS FOR 1980 FOR VARIOUS. FERTILITY AND MIGRATION PATTERNS f Cumulative Population Density 1 (Persons per Square Mile)
' Distance 2.1 Fertility I") (a) 2.7 Fertility (b) I t
from-Site' 1965 to 1975 Mig ration 2.1 FertilityI No Mig ration
} 1965 to 1975 Mig ration 2.7 Fertility ( }
No Mig ration t 4 0 - 1 0 0 0 0 0- 2 10 10 10 .10 y I O- 3 10 10 10 10 x , n .i 38 39 0- 4 38 38 @ 0- 5 47 48 48 49 $
=
0 - 10 16 16 16 16 g ; O - 20 10 10 10 10 E j' 0 - 30 23 23 23 23 i 0 - 40 21 21 21 21 i 0 - 50 21 22 22 22-1 a Replacement fertility. b Growth fertility. 1 The no-mig ration assumption m ans that continuing. out-migration trends would cease. r i i i~ i 7 a if
TABLE 2.1-11 COMPARISOl' OF POPULATION DENSITY DISTRIBUTIONS FOR 2020 FOR VARIOUS FERTILITY AND MIGRATION PATTERNS Cumulative Population Density (Persons per Square Mile) Distance 2.1 Fertility I ^ 2.7 Fertility (b) from 1965 to 1975 2.1 Fertility (a) 1965 to 1975 2.7 Fertility ((b) c) Site Mig ration No Mig ration (c) Migration No Migration 0 - 1 0 0 0 0 0 - 2 5 5 5 6 0 - 3 7 7 7 8 x 0 - 4 21 21 24 26 h 0- 5 57 59 63 66 A x 0 - 10 15 16 17 18 g 0 - 20 7 7 8 8 E 0 - 30 22 22 25 27 0 - 40 19 20 23 24 0 - 50 20 21 24 26 a Replacement fertility. b Growth fertility. c The no-mig ration assumption means that continuing out-mig ration trends would cease. O O @
d WCGS-ER(OLS) 4
. / '} . I s/ TABLE 2.1-12 1
FARMS, LAND IN FARMS, AND LAND USE ,' WITHIN 50 MILES OF THE SITE Land Use Number *
; Total Area 5,026,548 Approximate Water Area 8,900 i All Farms i All Farms 10,000 i
(total number) ; Land in Farms 4,500,000 Average Size of Farm 440 Propo rtion in Farms 89% Land in Farms According to Use Total Cropland 2,200,000 Harvested Cropland 1,500,000
- Cropland Used only for Pasture 530,000 Woodland, Including Woodland Pasture 170,000 Other Land, Including Other Pastureland 2,100,000 Irrigated Land 8,500 3
*All numbers in acres except where noted.
Sources: U.S. Bureau of-the census, 1977, 1974 census of agriculture: U.S. Government Printing
- Office, Washington, D.C., vol. 1, part 16,
-Kansas.
4 Kansas Crop and Livestock Reporting Service, > i 1978, 61st annual report and farm facts:
- Kansas State Board of Agriculture, Topeka.
I I I O i I..... . - - . ~ . _ _ . . . . . _ . . - _ .. ...._.m_....,_,_,,.,._ ..,._,,.,,,,__.,..----.m . . . . . , , . . . , ~ .
TABLE 2.1-13 CROP PRODUCTION WITHIN 50 MILES OF THE SITE U.S. Units Metric Equivalent Quantity Yield Quantity Yield Harvested Crop Acres Per Acre Harvested (kg/m2) (kg) Wheat 377,000 27 bu. 10,300,000 bu. 0.18 280,000,000 Corn for Grain 99,000 83 bu. 8,220,000 bu. 0.52 209,000,000 corn for Silage 35,300 12 tons 440,000 tons 2.79 399,000,000 Dats 39,500 46 bu. 1,830,000 bu. 0.17 26,500,000
% rley 3,500 39 bu. 138,000 bu. 0.21 3,010,000 aye 286 20 bu. 5,700 bu. 0.13 145,000 Sorghum for Grain 459,000 64 bu. 29,400,000 bu. 0.40 747,000,000 sc Sorghum for Silage 27,100 13 tons 355,000 tons 2.93 322,000,000 h!
Sorghum f or Forage 7,970 3 tons 24,200 tons 0.68 21,900,000 $' 369,000 26 bu. 9,770,000 bu. 0.13 266,000,000 Soybeans {} Pasture 2,680,000 NA NA NA NA gg Alfalfa Hay 93,400 3 tons 266,000 tons 0.64 241,000,000 t" U2 610,000 tons 0.34 554,000,000 -- Other Hay 401,000 1.5 tons Other Field Seeds 17,700 123 lbs. 2,170,000 lbs. 0.01 986,000 Apples, Peaches NA NA 1,970,000 lbs. NA 892,000 Irish Potatoes 85 85 ewt. 7,210 cwt. 0.95 327,000 Vegetables, Sweet Corn, Melons 178 NA NA NA NA Berries 24 NA NA NA NA Land in Orchards 854 NA NA NA NA Notes NA = Not Available Sources: U.S. Bureau of the Census, 1977, 1974 census of agriculture: U.S. Government Printing O2..ae, Washingtoa, D.C., vol. 1, part 16, Kansas. Kai..as Crop and Livestock Reporting Service, 1978, 61st annual report and f arm f acts: Kansas State Board of Agriculture, Topeka. O O O
k WCGS-ER(OLS) , (,,) TABLE 2.1-14 LIVESTOCK WITHIN 50 MILES OF THE SITE i i Inventory
; Type Of Animal (Number Of Animals)
- All Cattle and Calves. 630,000 Beef Cows 228,000 Milk Cows 21,000
! Cattle on Feed 35,100 1 i Hogs and Pigs 249,000 i j Sheep and Lambs 12,800 4
! Chickens- (excluding broilers) 383,000 l Broilers and Other Meat-Type Chickens 10,300 Turkeys 594-Sources: U.S. Bureau of the Census, 1977, 1974 census of agriculture: U.S. Government Printing Office, Washington, D.C., vol. 1, part 16,
- Kansas.
Kansas Crop and Livestock Reporting Service, 1978, 61st annual report and f arm f acts; Kansas State Board of Agriculture, Topeka. I l i. f l I i l' t
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TABLE 2.1-15 FEED CONSUMPTION BY CATTLE IN EAST-CENTRAL KANSAS Average Annual Consumption (Pounds Per Animal) Forage And Feed Grains Hay Silage Pasture Beef Cows and Calves 450 - 600 2,000 4,000 7,000 Milk Cows 6,000 4,000 8,000 1,500 - 2,000 Cattle on Feed 2,500 - 3,000 250 250 -- b Other Cattle 450 - 600 1,500 -- 4,000 - 4,500 @ Source: Brazle, 1979, Livestock Specialist, Extension Services, Chanute, Kansas, personal communication (January 2(i). $ O O - - O
WCGS-ER(OLS) i i TABLE 2.1-16 HUNTING HARVEST WITHIN 50 MILES Game Species Annuel Harvest Big Game White-Tailed Deer 560 Emall Game Bobwhite 220,000 Ring-Necked Pheasant 65,000 Greater Prairie Chicken 2,400 Gray and Fox Squirrel 34,000 Eastern Cottontail 45,000 Mourning Dove 170,000 Waterfowl Mallard 3,400 Pintail 320 Green-Winged Teal 1,300 Blue-Winged Teal 900 Wigeon 301 Gadwall 690 Shoveler 130 Scaup 400 Ring-Necked Duck 160 Redhead 61 9 Canvasback Wood Duck Merganser Coot Other Ducks 32 250 65 140 83 Unknown Ducks 210 Canada Goose 210 hhite-fronted Goose 41 Snow Goose 320 Unknown Geese 5 Sources: Sexon, K., 1979, Big Gama Project Leader, Kansas Fish and Game Commission, Pratt, Kansas, personal communication (February 6). Kraft, M.J., 1979, Waterfowl Project Leader, Kansas Fish and Game Commission, Pratt, Kansas, personal communication (January 26). Montet, K., 1979, Head of Wildlife Research, Kansas Fish and Game Commission, Pratt, Kansas, personal communication (January 18). Johnson, N.F., 1979, Furbearer Project Leader, Kansas Fish and Game Commission, Pratt, Kansas, personal communications (January). O l 1 l , - , _ - - - _ .
l WCGS-ER(OLS) TABLE 2.1-17 Sheet 1 of 4 AGRICULTURAL DATA FOR COFFEY COUNTY, XANSAS 1977I ") 1974 (b) 1969 (b) County Land Area (acres) 394,880 ID) 394,880 394,880 Lands in Farms (acres) 373,000 383,983 379,025 Percent of Land Area in Farms 94.5 97.2 96.0 Number of Farms 734 797 873 Ave rag e Size of Farms (acres) 508 482 434 Average Value of Land and Buildings per Farm NA(c) $138,803 S67,277 Land in Farms According to Use Total Cropland (acres) NA 208,166 210,014 Harvested Cropland (acres) 177,020 158,218 122,770 Cropland Used only For Pasture or Grazing (acres) NA 43,641 55,345 Other Cropland (acres) NA 6,307 31,899 Woodland (acres) NA 7,776 11,522 Other Land (acres) NA 168,041 157,489 Irrigated Land (acres) NA 468 189 " Kansas Crop and Livestock Reporting Service, 1978, 61st annual report and farm facts: Kansas State Board of Agriculture, Topeka. b U.S. Bureau of the Census, 1977, 1974 census of agriculture: U.S. Government Printing Office, Washington, D.C., vol. 1, part 16, Kansas. NA = Not Available O
WCGS-ER(OLS) ['O ') TABLE 2.1-17 (continued) Sheet 2 of 4 1977 (a) yg74 (b) 1969 (b) e Crops liarvosted Corn for Grain Farms Reporting NA 166 331 Acres 8,700 8,358 11,409 Bushels 734,000 259,266 643,335 Corn for Silage or Green Chop Farms Repo rting NA 155 95 Acres 1,300 7,213 2,177 Tons (green) 15,600 41,764 24,507 Corn for Dry Fodder, liogged or Grazed
/'~'} Farms Reporting NA 14 15 %) Acres NA 399 219 Sorghum for Grain Farms Reporting NA 449 414 Acres 37,100 27,678 22,362 Bushels 2,565,200 987,760 1,150,115 Sorghum for Silage, Fodder, Hay Fa rms Reporting NA 77 NA
. Acres 4,100 1,733 2,681 Wheat for Grain Farns Reporting NA 443 474 i Acres 34,200 23,309 15,397 Bushels 896,000 592,683 419,657 l l V l
WCGS-ER(OLS) TABLE 2.1-17 (continued) Sheet 3 of 4 1977 (a) yg74 (b) 1969 (b) Soybeans for Beans Farms Reporting NA 566 533 Acres 44,400 53,801 35,837 Bushels 1,095,000 877,136 790,808 Hay Farms Reporting NA 547 553 Acres 48,500 39,295 33,383 Tons (dry) 84,400 46,017 62,569 Other Small Grains for Grain Fa rms Repo r ting NA 71 39 Acres 200 876 731 Irish Potatoes Farms Reporting NA 6 NA Acres NA 6 NA Hundredweight NA 202 NA Sweet Potatoes Fa rms Repo r ting NA 1 NA Acres NA - NA Bushels NA 2 NA Vegetables, Sweet Corn, or Melons For Sale Farms Repo rting NA 1 - Acres NA 2 - Land in Orchards Farms Reporting NA 5 6 Acres NA 37 14 l O' 1
WCGS-ER(OLS) TABLE 2.1-17 (continued) Sheet 4 of 4 1977 (a) yg74 (b) 1969 (b) Berries For Sale Farms Reporting NA - 6 Acres NA - 2 Other Crops Farms Reporting NA 16 NA Acres NA 480 628 Livestock & Poultry Cattle and Calves Farms Reporting NA 609 661 Number 47,600 48,747 54,847 Hogs and Pigs Farms Repo rting 159 284 ( Number NA 13,100 11,741 20,409 Sheep and Lambs Farms Repo rting NA 13 36 Number 400 521 1,415 Chickens (3 months old or older) Farms Reporting NA 113 196
. Number 37,000 43,315 27,707 Broilers and Other Meat-Type Chickens Farms Reporting NA 12 2 Number NA 968 57 l
l l s- ) l _ _ _ _ _ . _ - , _ . ~ _. _ - . - . - _ . . . - - _ - .
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TABLE 2.1-19 Sheet 1 of 5 WATER RIGHTS CH THE N?.OSHO RIVER IN KANSAS DOWNSTREAM OF THE SITE Approximate Authorized Authorized Maziaram Application location oy Map River Maximum Diversion Rate (qpe) Annual Quantity Principal 14e Number Diversion Key Mile Nner Source (aere-feet) 6799-A E/SE/NE 1 327 K. Crotts Neosho River 1125 39 Irrigation 29-22-16 1526 SW/NW, SW/SW 2 324 M. Parmely Neosta River 1300 79 Irrigation 4-23-16 SE/SE 5-23-16 4865 SW/NW, SW/SW 2 324 M. Parmely Neosho River 2160 79 Irrigation 4-23-16 SE/SE 5-23-16 ::*. O R Code 624 NE/NW 3-23-16 3 321 City of teroy and vicinity Neosho River 160 55 Municipal h M 3495 NE/NW 3 321 City of leroy Neosho River 200 8C Municipal W 3-21-16 and vicinity g . M J 10803 SW/SW 4 306 Woodson Co. Neosho River 100 81 Municipal t/3 28-23-17 Rural Water WW/NW/NW District No. 1 33-23-17 27403 SW/SW/SW 4 306 Woodson Co. Neosho River 210 160 Municipal 28-23-17 Rural Water District No. 1 3854 N/NE 5 301 F. Isis Neosho River 1400 211 Irrigation 11-24-17 13055 SE/SE/NE, 6 300 K. Heins Neosho River 1003 233 Irrigation NE/NE/SE 12-24-17 15435 SE/SE/SW 7 298 E. Bergman Neosho River 800 34 Irrigation 7-24-18 4
*1ocations are specified by section division, section, township, and range.
See Figure 2.1-25 for locations. Mouth of Wolf Creek is approximately at Neosho River Mile 334.5, the Kansas-oklahoma state line is at river mile 164. Sources Kansas State Board of Agriculture, 1979, Open file material: Division of Water Resources, Topeka, Kansas (Marchi. I
TABLS 2.1-19 (continued) Sheet 2 of 5 Approximate Authorized Authorized Maximus Application Map Maximum Diversion Annual Quantity Nurber Incationo{ Diversion Fey Rive r Mile Owner Sriurte Mte ( gre ) (acre-feet) Principal (Jse 30383 NE/SE/SE 8 292 J. McFadden Neosho River 800 70 Irrigation 28-24-18 VR 621 SW/SW 8 292 City of Iola :leosho River 2200 982 manicipal 27-24-18 17489 SW/SW/SW 8 292 City of Iola Neosho River 3250 15 % Municipal 27-24-18 VR 624 NW/NE 9 291 Pet Milk Plant heosho River 450 301 Industrial 34-24-18 3137 SE/SW/SW/EW 10 290 C. Sutherland heosho River 1000 300 Irrigation 34-24-18 4 NE/SE/SW/NE 10 290 33-24-18 t/} NW/NW 11 289 3 3-25-18 M N 28706 NE/SW/SW 34-24-1B 10 290 J. McFadden Necsho River 800 134 Irrig2 tion 3 M U3 30382 SE/NW/SW 12 287 J. McFadden beosho River 800 82 Irrigation 9-25-18 15417 NW/NE/NE 13 282 R. Issh Neosho River 2700 275 Irrigation 31-25-18 % 85 NE/NE 14 281 R. Issh Neosho River 3000 414 Irrigation 5-26-18 15425 NE/NE/NE 14 281 R. Iesh Neosho River 4500 475 Irrigation 5-26-18 VR 622 SE/SW/NW 15 280 City of Humboldt beosha Rivet 1150 368 Municipal 4-26-18 3527 SE/SW 16 274 A. Nelson Neosho River 500 112 Irrigation 32-26-18 VR 625 SW/SE 17 273 Ash Grove 1.ime & Neosho River 500 614 Industrial 5-27-18 Port]and Cement Co. 16226 SW/SW/SE 17 273 Ash Grove Lime 6 Neosho River 4000 921 Industrial 5-27-18 Portland Cement Co. O O O -
a s_) .v TABLE 2.1-19 (continued) Sheet 3 af 5 Approximate Authori.e4 Authorized Maximum Application Incation o Map River Maximum Diversion Annual Quantity Principal Nurber Diversion Key Mile Owner Sourn Rate (ape) (acre-feet) tJse 26943 SE/WW/SW 18 26 8 h uaco, Inc. Neosho River 321 518 Industrial 11-27-18 7566 SE/NE/SE 19 267 K. Casper Neosho River 600 100 Ir rigation 15-27-18 SW/SE/NE 20 266 SW/NE/SE 22-27-18 VR 621 SW/NE 20 266 City of Chanutc Neosho River 1200 1517 Municipal 22-27-18 8660 SE/SW/NE 20 266 City of Chanute Neosho River 4200 2717 Municipal 22-27-18 Z O 2702 NW/SW/NE 21 262 L. Taylor Neosho River 1000 186 Irrigation 2-28-18 g M 25920 SW/SE/NW, SE/NW/SE 22 256 E. Smith Neosho River 700 52 Irrigation { O 9-28-19 p q tn 28487 W/E 21 249 R. Hudson Neoshc River 1500 128 Irrigation 27-28-19 24 247 Y. Hudson Neosho River 1700 140 Irrigation 28488 SW/SW 36-28-19 VR 623 NE/WW/SW 25 243 City of Erie Neosho River 500 246 Municipal 5-29-20 26 239 Hy-Grade Con- Neosho River 1000 178 Industrial 19515 NE 15-29-20 struction & NW/NW/SE Materials, Inc. 15-29-20 19514 SW 27 234 Hy-Grade Con- Neosho River 2000 1193 irrigation 23-29-20 struction 6 SW 28 233 Materials, Ir.c. 24-29-20 NW 28 232 25-29-20 NE 28 232 25-29-20
TABLE 2.1-19 (continued) Sheet 4 of 5 Approximate Authorized Authorized Maximum Application locationog Diversion Map Ite y River Mila Owner Source Maximum Diversion Rate (gpm) Annual Quantity (acre-feet) Principal Use Nurter VR 624 NW/SW/SW 28 233 City of St. Paul Neosho River 150 46 Munir. ipa) 24-29-20 23942 SW/SW 28 233 City of St. Paul Neosho River 300 156 Municipal 24-29-20 8359 S/S 29 232 Kansas Fish & Neosho River 13464 3000 Recreation 19-19-21 Game Commission 29030 SW/NE/NW, 30 217 W. Goley Alluvial Well 614 363 Irrigation NW/SW/SW, NE/SW/NW, NW/NW/SW , 8-30-21 g O 30279 SW/NE/NW, 30 217 W. Goley Neosho River 3000 551 Irrigation (f) NE/SW/NW, 1 NW/NW/SW, U NW/SW/SW 8-30-21 O t* VR 622 NW 24-30-20 31 214 City of Parsons Neosho River 6300 2306 Municipal
]
29739 NE/SE/NW 31 214 D. Goodeyon Neosho River 1000 45 Irrigation 20-30-21 18139 SE/NE/NE 32 209 Jarbse-Lackey 6w:osho River 2000 215 Irrigation 5-31-21 Feed lots, Inc. SW/SW/NW 110 Industrial 4-31-21 11562 SW/SW/NW 32 209 W. Charles Neosho River 400 313 Industrial 4-31-21 SE/NE/NE 5-31-21 25860 SE/SW/NE 34 207 W. Brunenn Neosho River 1500 156 Irrigation 8-31-21 EE/NE/NW, 33 208 SE/NW/SW 35 206 9-31-21 O O O
.m . _ . _ , . . . . _ . . _ . . _ . ___,4 - -. . . . , _ , . . . . _~ _ _.._-..m .., . -...
. ( . , y TABLE 2.1-19 (continued) Sheet 5 of 5 i
. Approximate Authorized Authorized Maximum Application ..!acation o y Map . River ' Maximum Diversion Annual Quantity Principal
! Number Diversion Key- Mile (kner Source Rate (gpm) (acre-feet) Use f VR 628 SW/SE 36 200 Kansas Ordinance Neosho River - 2225 869 Industrial 28-31-21 Plant , .NW/hE . 33-31-21 i VR 627 SE 37 199 Eansas Gas & Neosho River' 10,000 651 Industrial
~33-31-21 Electric +
I
.i j 3646 :SE 37 199 Eansas Caa & Neosho River 2600' 2000 Industrial 33-31-21 Electric j' 8432 SE.
33-31-21 37 199 Eansas Gas & Electric Neorho River 14890 2026 Industrial ,. j h- 19526 SE/SW/NE, 38 ^ 198 c. Sprague 'Neosho River 1000 -163 Irrigation 2 ai,EiSE. 4-32-21 gg. NW 39 197 tej . 1
.9-32-21 - W.
.m 19498 NE/SE .39 197 C. Sprague Neosho River 1000 198 Irrigation -
i 9-32-21 (/)
, w
}. 30,155 NW/NE/SE 38 198 R. Spriggs Neosho River 1500 360 Irrigation , 4-32-21 j NE/SE/NE 39 197 ? 9-32-21 ) NW/NW/NW 39 197 l 4~ 10-32-21 7
.29,746 SW/SW/SE 40 193 J. Sprague Neosho River 1500 285 Irrigation r I
22-32-21 f SW/NW/NE j 27 32-21 I j 29,952 NE/NE/NE 41 187 F. Sinclair Neosho River 1500 340 Irrigation 1- 15-33-21 !- .NW/SW/SW 10-33-21 l I . VR 6623 16*33-21 41 187 , City of Oswego Neosho River 600 261 Municipal k
! 25,0'J3 SE/NE/NE 41 187 City of Oswego Neosho River 800 635 Municipal 33-21 4 ;
1 j VR 624 35-34-21 42 170 City of Chetopa Neosho River 300 190 Municipal 4 4 1 i- -- -_.
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(~. \J lv) TABLE 2.1-21 Sheet 1 of 2 MJNICIFALITIES AND RURAL WATER DISTRJCTS (FWD) IN KANSAS UTILIZING THE NEOSHO RIVER DOWNSTREAM OF THE SITE 1976-1977 2000 City or Rural Population Annual Water Estimated Annual Projected Water Wter District Served Use (acre-feet) Population Served Water Use (acre-feet) Source of Water Coffey County IA Roy 653 47.6 992 93.1 Neosho River Anderson County 1,205 *
- City of Iola, Allen Co.
RWD #5 135.0
*
- RWD #5 Kincaid 350 28.0 PWD #5 to Allen Co. 240 18.1 240 22.0 City of Iola, Allen Co.
RWD #5 to coffey Co. 55 6.2 58 7.7 City of tola, Allen Co. 5* BWD #5 to Franklin Co. 90 10.6 *
- City of lola, Allen Co. O O
t/) 1 Woodson co anty M N RWD #1 360 21.9 462 34.8 Neosho River
]
RWD #1 to Allen Co. 200 15.1 200 18.3 Neosho River p t.D v Allen County Humboldt 2,444 472.7 2,610 511.8 Neosho River Iola 6,96u 1,197.9 7,500 1,309.8 Neosho River Bassett 32 0.0 28 7.0 City of lola Gas City 522 73.7 580 89.4 City of Iola LaHarpe 621 87.7 670 104.9 City of Iola RWD A1 26 3.7 22 3.2 City of Iola RWD #2 42 7.0 38 6.3 City of tola RWD #3 60 5.3 64 5.7 City of Iola RWD #4 28 5.9 24 5.3 City of Iola RWD #5 20 8.8 18 8.0 City of Iola RWD #6 54 6.9 50 6.4 City of Iola RWD #7 152 17.8 145 16.9 City of Iola RWD #8 180 27.7 352 32.4 City of Iola RWD #9 34 4.3 38 4.8 City of Humboldt RWD #10 84 11.7 164 36.2 City of Humboldt
*Present population and water use greater than year 2000; use present values for delivery.
Source: Flickenger, G., 1979, Associate Engineer, Kansas Water Resources Board, Topeka, Kansas, personal connunication (March 9).
l i TABLE 2.1-21 (continued) Sheet 2 of 2 i . t 1976-1977 2000 City or Rural Population Annual Water Estimated Annual Projected Water Water District Served Use (acre-feet) Population Served Water Use (acre-feet) Source of Water Neosho County Chanute 10,400 1,309.1 12,526 2,011.0 Neosho River l Erie 1,425 172.0 1.787 469.6 Neosho River St. Paul 713 92.1 921 110.5 Neosho R2ver i EWD #3 107 12.3 115 12.' city of Erie j RWD #4 340 30.5 360 32.5 City of Erie RWD #7 620 67.5 700 76.8 City of Chanute RWD #8 196 26.6 231 108.7 City of St. Paul j FWD #9 182 26.1 274 43.0 City of Chanute RWD 97 to Allen Co. 19 2.0 25 2.7 City of Chanute j i Chanute to Petrolia 83 18.0 100 22.7 City of Chanute (Allen Co.) i - O i 1abette County O I U) I ! Chetopa 1,663 168.9 1,997 233.3 Neosho River trj ! Oswego 2,167 456.2 2,250 437.7 Neosho River W Parsons 12,344 2,151.4 16,654 2,345.1 Neosch River Standby and In- ' perial Reservoir y) 400 20.0 City of Oswego v ) RWD #1 220 11.0 RWD #2 105 5.2 200 10.7 City of Parsons Rwo #4 141 15.4 170 21.5 City of oswego PWD #7 186 13.1 230 18.4 Neosho RWD $4 FWD #8 700 73.7 900 94.7 !abette RWD 92 l 4 i i + k i ) 1 l e -- e - - - - - - - e
WCGS-ER (OLS )
/3 $ \ TABLE 2.1-22
( v j-MUNICIPAL GROUND-WATER SUPPLIES WITHIN 20 MILES OF THE SITE Static #' Pumping Well Well Screen Water Water Test Approx Depth Diameter Interval Level Level Yield tocation Elev. (feet) (inches) (feet) (feet) (feet) Aquifer (qpm) Waverly #1 1100 280 6 170-190 950 935 Tonganoxie 20 200-230 Waverly 92 1100 260 6 165-195 970 945 Tonganoxie 22 255-265 Waverly #3 1100 228 6 199-205 NA AA Tonganoxie 10 Waverly #4 1100 270 6 142-192 958 943 Tonganoxie 20 263-268 Waverly 45 1100 300 6 NA 938 NA Tonganoxie 16 Williamsburg #1 1280 190 6 NA 1158 NA Tonganoxie 10 Williamsburg #2 1280 190 6 NA 1164 NA Taaganoxie 10 Williamsburg #3 1280 210 6 NA NA NA Tonganoxie 18 Williamsburg #4 1280 300 6 NA NA NA Tonganoxie 18 New Strawn
' 1010 32 24 NA 998 NA Alluvium 30 Melve rn # 1 1015 16 8 6 50-100 906 NA Tonganoxie 13
[7
-- Melvern #2 1015 160 6 NA NA NA h nganoxie 6 Melvern #3 1015 94 6 46-71 NA NA Tonganoxie 20 74-94 Melvern e4 1015 97 6 47-97 NA NA Tonganoxie 30 Melvern #5 1015 80 6 50-80 NA NA hnganoxie 14 Melvern 86 1015 179 NA NA NA NA Tonganoxie 10 Hartford #1 1036 30 NA NA 1004 NA Alluvium NA
'Incations of municipalities shown on Figure 2.1-26.
Approximate elevations in feet above MSL of wells taken from U.S. Geological Survey Topographic Maps. Static water level shown as elevation above stean sea level. d Pumping water level shown as elevation above mean sea level.
'Well for New Strawn located in alluvium of Neosho River about 1/2 mile downstream from John Redmond Dam (see Reischich below).
Sources Kansas Water Resources Board, 1973: Open-file Material. Gettinger, L., 1979, Records, Kansas State Board of Agriculture, Division of Water Resources, Topeka, Kansas, written communication ( August 24). Reischick. L., 1973. Farmer's Hcme Administration, Burlington, Kansass written com-munication (September). j'" % k ) v f l l
TABLE 2.1-23 Sheet 1 of 10 WELL INVENTORY WITHIN 5 MILES OF THE SITE Approx. Well Approx. Land Depth to Elev. of Estimated Name of Depth Surface Elev. Water Level Water Level Type of Pumpag e Rate Owner 5 Location, (feet) (feet, MSL) (feet) (feet, MS L) Well (qpd) Tenant Remarks Al 18 1144 Above Ground Surface 1144 Dug 250 Bennett FWD (AGS) A2 30 1164 8 1156 Dug 0 Salava RWD A4 NA(b) NA NA NA NA 0 Phillips Well to be sealed A14 30 1076 2 1074 Dug 360 Clapp None A17 35 1100 3 1007 Dug 70 Abbey Well to be sealed :C O A18 30 1100 8 1092 Dug 530 Anderson Well to be sealed ha M A19 2 1096 NA NA Dug NA Anderson None 70 O A20 18 1112 6 1106 Dug 50 Anderson RWD p to A22 14 1140 AGS 1140 Dug 0 Anderson None A23 NA 1090 NA NA NA 230 Williams RWD A23 NA 1093 NA NA NA NA Williams Well to be sealed A23 10 1089 NA NA NA NA Garrepp/ kell to Corden be sealed A24 NA 1099 NA NA NA NA Anderson Well to be sealed a Locations shown on Fig ur e 2.1-27. b NA indicates data Not Available. C lndicates property serviced by Rural Water District No. 3. d owner or tenant at time of 1973 survey. KGLE presently owns or controls all wells within the site boundary. Source: Based on field investigation, Dames & Moore, 1973 and 1979. O O O
t t .) TABt.E 2.1-23 (continued) Sheet 2 of 10 Approx. Well Approx. Land Depth to Elev. of Estimated Name of Depth Surface Elev. Water Level Water Level Type of Pumpage Rate Owner og Location, (feet) (feet, MSL) ( f ee t) (feet, MSL) Well (qpd) Tenant Remar ks - _ B2 30 1123 5 1118 Dug 500 Wayne RWD i B4 40 1C91 8 1083 Dug 310 French RWD B8 20 1091 5 1086 Dug 75 Hess RWD Bil 35 1080 15 1065 Dug 220 Hess None B12 16 NA NA NA Dug NA NA RWD B12 42 1132 15 1117 Dug 410 Mallon None B13 33 NA NA NA Dug 100 Crouch RWD q B14 18 1081 AGS 1081 Dug NA NA RWD hI B14 22 1083 35 1070 Dug NA NA None td W B14 22 1080 5 1075 Dug 830 Hoffman None $ M BIS 25 1062 9 1053 Dug 100 Crouch RWD g B16 27 1087 2 1085 Dug 840 Allen RWD l B19 13 NA 2.5 NA Dug NA NA RWD B19 31 1113 2.5 1110 Dug 200 Skillman None C1 25 1097 3 1094 Dug 350 Houser hell to
- be sealed I
C2 NA 1101 15 1086 NA 630 Levering RWD C4 NA NA NA NA NA 340 Woods RWD i C5 43 1085 11 1074 Dug NA NA hell to be sealed C5 12 1088 7 1081 Dug 500 Woods Well to , be sealed C7 15 1075 2 1073 Dug 0 Skillman Well to be sealed C8 30 NA Dry NA Drilled D Anderson RWD i i
TABLE 2.1-23 (continued) Sheet 3 of 10 Approx. Well Approx. Land Depth to Elev. of Estimated Name of Depth Surface Elev. hater Level Water Level Type of Pumpage Rate Owner 5 Location, (feet) (feet, MS L) (feet) (feet, MSL) hell (gpd) Tenant Remarks C9 20 1065 AGS 1065 Dug 0 Griffin RWD C10 20 1058 7.5 1050 Dug 410 Rhoads RWD Cll 40 1030 10 1020 Dug 410 Nelson None C17 NA 1084 10 1074 Drilled 0 Hunter Well has been sealed C18 75 1080 4 1076 Dug 700 Robinett Well to be sealed C20 22 1090 18 1072 Dug 550 Applicant RWD g O C21 22 1040 5 1035 Dug 210 Robinett None O to C23 10 1030 10 1020 Dug 230 Reinker RhD h w C24 36 1022 10 1012 Dug 660 Decker None -% O C25 12 1020 10 1010 Dug 5400 Likes None C26 31 NA NA NA Drilled 210 Allen None C27 30 1040 15 1025 Dug 200 Cranford None C28 30 1040 10 1030 Dug 320 Zschelle None C29 30 1020 10 1010 Dug 290 Decker None C30 31 1041 9 1032 Dug 390 Hess None C31 24 1044 13 1031 Drilled 210 Birkbeck None C32 31 1039 4 1035 Drilled 2630 Birkbeck None C33 30 1040 9 1031 Dug 110 Rife None C34 15 1031 5 1026 Dug 410 Thompson None C35 NA 1031 NA 1026 NA 100 Traymick None C36 33 1034 10 1024 Drilled 210 Mays None C37 28 1031 5 1026 Drilled 210 White None O O O
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l l l l i l l TABLE 2.1-23 (continued) Sheet 5 of 10 Approx. Well Approx. Land Depth to Elev, of Estimated Name of Depth Surface Elev. Water Level Water Level Tyre of Pumpage Rate Owner og Location, (feet) (feet, MS L) (feet) (feet, MSL) .. ell (gpd) Tenant Remarks C71 21 1010 5 1005 Drilled 440 Williams None C72 10 1013 1 1012 Dug 1370 Smart None C73 9 1075 NA NA Dug NA Winn None C73 28 1074 NA NA Dug NA Winn None C74 27 1087 NA NA NA NA Williams None C74 23 1087 NA NA NA NA NA None C75 10 1066 NA NA NA NA Woods None 5[ O C76 1 1083 NA NA NA NA NA None h I C77 9 1056 NA NA Dug NA Anderson None D1 N C77 16 1056 NA NA NA NA Anderson None g t* C77 NA 1060 NA NA NA NA Anderson None y) D1 100 1110 5 1105 Dug 380 Nielson RWD D1 14 NA NA NA NA NA NA NA D2 30 1115 5 1100 Dug 220 Bon RWD D2 NA NA NA NA NA NA NA NA D3 30 1070 6 1064 Dug 150 Miller None D3 NA NA NA NA NA NA NA NA D4 20 1075 4 1070 Dug 10 Wuerfele None DS 40 1060 11 1049 Dug 440 1seman None DS 25 NA 11 NA NA NA NA None D6 20 1060 12 1048 Dug 310 wuerfele None D7 16 1115 4 1111 Dug 250 Tracy None D8 16 1111 6 1105 Dug 470 Tragar RWD O O O
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TABLE 2.1-23 (continued) Sheet 10 o f 10 Approx. Well Approx. Land Depth to Elev. of Estimated Name of Depth Surface Elev. Water Level. Water Level Type of Pumpage Rate Owner og Location, (feet, MSL) (feet) (feet, MSL) Well (gpd) Tenant Remarks (feet) 1026 NA NA Dug 560 Means None D69 40 D70 32 1035 10 1025 Dug 660 Robinson None D71 25 1040 AGS 1040 Dug 800 Engel None 32 1040 4 1036 Dug 510 Reed None D72 1080 NA NA NA NA NA None D73 NA 1070 NA NA NA NA NA None D74 41 D75 NA 1070 NA NA NA NA NA None g O 19 1042 NA NA Dug NA Hamman None D76 1075 NA NA NA NA Reinker None D77 13.5 N 1094 NA NA NA NA Paxton None -% D78 25 O 1094 NA NA Dug NA Paxton None D78 9 1085 NA NA NA NA Ellen None D79 25 NA NA NA NA Mooris None D80 16 1093 1085 NA NA NA NA Reinker None D81 12 1085 NA NA NA NA Martens None DB2 25 NA NA Dug NA Martens None DB2 5 1083 NA NA NA NA Snyder None D83 20 1061 7 1061 NA NA NA NA Snyder None D83 NA NA NA NA Hess None D84 19 1060 NA NA Dug NA NA Cistern D85 10 1080 NA NA Drilled 510 Williams None E2 32 1009
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SOURCE: STATE BOARD OF ACRICULTURE,1979, OPEN FILE EATERI AL. DIVISION OF WATER RESOURCES, TOFEKA, KANSAS (MARCH)
REFERENCE:
l E ASE MAP FROM STATE HICHWAY CCMMISSION OF KANSAS, I GENERAL HIGHVAY MAP OF NEOSHO COUNTY,1969; 1 CRAWFORD CCUNTY,1975; LABETTE COUNTY,1970; AND CHERCKEE COUNTY, 1975. l t I
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