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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1993
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-3523
WESTERN RESOURCES, INC.
(Exact name of registrant as specified in its charter)
KANSAS 48-0290150
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
818 KANSAS AVENUE, TOPEKA, KANSAS 66612
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code 913/575-6300
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $5.00 par value New York Stock Exchange
(Title of each class) (Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, 4 1/2% Series, $100 par value
(Title of Class)
Indicated by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes x No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. (X)
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant. Approximately $1,871,643,000 of Common Stock and $11,545,000
of Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which
there is no readily ascertainable market value) at March 11, 1994.
Indicate the number of shares outstanding of each of the registrant's classes
of common stock.
Common Stock, $5.00 par value 61,617,873
(Class) (Outstanding at March 11, 1994)
Documents Incorporated by Reference:
Part Document
III Portions of the Company's Definitive Proxy Statement for
the Annual Meeting of Shareholders to be held May 3, 1994.
WESTERN RESOURCES, INC.
FORM 10-K
December 31, 1993
TABLE OF CONTENTS
Description Page
PART I
Item 1. Business 3
Item 2. Properties 19
Item 3. Legal Proceedings 2
Item 4. Submission of Matters to a Vote of
Security Holders 21
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 21
Item 6. Selected Financial Data 22
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 23
Item 8. Financial Statements and Supplementary Data 32
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 63
PART III
Item 10. Directors and Executive Officers of the
Registrant 63
Item 11. Executive Compensation 63
Item 12. Security Ownership of Certain Beneficial
Owners and Management 63
Item 13. Certain Relationships and Related
Transactions 63
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 64
Signatures 71
PART I
ITEM 1. BUSINESS
GENERAL
Western Resources, Inc. (formerly The Kansas Power and Light Company, KPL)
is a combination electric and natural gas public utility engaged in the
generation, transmission, distribution and sale of electric energy in Kansas
and the purchase, transmission, distribution, transportation and sale of
natural gas in Kansas, Missouri and Oklahoma. As used herein, the terms
"Company and Western Resources" include its wholly-owned subsidiaries, Astra
Resources, Inc., Kansas Gas and Electric Company (KG&E) since March 31, 1992,
and KPL Funding Corporation (KFC), unless the context otherwise requires.
KG&E owns 47 percent of Wolf Creek Nuclear Operating Corporation, the
operating company for Wolf Creek Generating Station (Wolf Creek). Corporate
headquarters of the Company is located at 818 Kansas Avenue, Topeka, Kansas
66612. At December 31, 1993, the Company had 5,192 employees.
On January 31, 1994, the Company sold substantially all of its Missouri
natural gas distribution properties and operations to Southern Union Company
(Southern Union). The Company sold the remaining Missouri properties to
United Cities Gas Company (United Cities) on February 28, 1994. The
properties sold to Southern Union and United Cities are referred to herein as
the "Missouri Properties". With the sales the Company is no longer operating
as a utility in the State of Missouri.
The portion of the Missouri Properties purchased by Southern Union, were
sold for an estimated sale price of $400 million, in cash, based on a
calculation as of December 31, 1993. The final sale price will be calculated
as of January 31, 1994, within 120 days of closing. Any difference between
the estimated and final sale price will be adjusted through a payment to or
from the Company.
United Cities purchased the Company's natural gas distribution system in
and around the City of Palmyra, Missouri, for $665,000 in cash.
The operating revenues and operating income (unaudited) related to the
Missouri Properties approximated $350 million and $21 million representing
approximately 18 percent and seven percent, respectively, of the Company's
total for 1993, and $299 million and $11 million representing approximately 19
percent and five percent, respectively, of the Company's total for 1992. Net
utility plant (unaudited) for the Missouri Properties, at December 31, 1993,
approximated $296 million and $272 million at December 31, 1992. This
represents approximately seven percent at December 31, 1993, and six percent
at December 31, 1992, of the total Company net utility plant. Separate
audited financial information was not kept by the Company for the Missouri
Properties. This unaudited financial information is based on assumptions and
allocations of expenses of the Company as a whole. For additional information
see Note 13 of the Notes to Consolidated Financial Statements.
On March 31, 1992, the Company through its wholly-owned subsidiary KCA
Corporation (KCA), acquired all of the outstanding common and preferred stock
of Kansas Gas and Electric Company for $454 million in cash and 23,479,380
shares of common stock (the Merger). The Company also paid approximately $20
million in costs to complete the Merger. Simultaneously, KCA and Kansas Gas
and Electric Company merged and adopted the name of Kansas Gas and Electric
Company (KG&E).
Additional information relating to the Merger can be found in Management's
Discussion and Analysis of Financial Condition and Results of Operations and
Note 3 of Notes to Consolidated Financial Statements.
The following information includes the operations of KG&E since March 31,
1992.
The percentages of Total Operating Revenues and Operating Income Before
Income Taxes attributable to the Company's electric and natural gas operations
for the past five years were as follows:
Total Operating Income
Operating Revenues Before Income Taxes
Year Electric Natural Gas Electric Natural Gas
1993 58% 42% 85% 15%
1992 57% 43% 89% 11%
1991 41% 59% 84% 16%
1990 40% 60% 85% 15%
1989 40% 60% 81% 19%
The difference between the percentage of electric operating revenues in
relation to the percentage of electric operating income as compared to the
same percentages for gas operations is due to the Company's level of
investment in plant and its fuel costs in each of these segments.
The amount of the Company's plant in service (net of accumulated
depreciation) at December 31, for each of the past five years was as follows:
Year Electric Natural Gas Total
(Thousands of Dollars)
1993 $3,641,154 $759,619 $4,400,773
1992 3,645,364 696,036 4,341,400
1991 1,080,579 628,751 1,709,330
1990 1,092,548 567,435 1,659,983
1989 1,092,534 511,733 1,604,267
As a regulated utility, the Company does not have direct competition for
retail electric service in its certified service area. However, there is
competition, based largely on price, from the generation, or potential
generation, of electricity by large commercial and industrial customers, and
independent power producers.
Electric utilities have been experiencing problems such as controversy
over the safety and use of coal and nuclear power plants, compliance with
changing environmental requirements, long construction periods required to
complete new generating units resulting in high fixed costs for those
facilities, difficulties in obtaining timely and adequate rate relief to
recover these high fixed costs, uncertainties in predicting future load
requirements, competition from independent power producers and cogenerators,
and the effects of changing accounting standards.
The problems which most significantly affect the Company are the use, or
potential use, of cogeneration or self-generation facilities by large
commercial and industrial customers and compliance with environmental
requirements. For additional information see Management's Discussion and
Analysis and Notes 4 and 5 of the Notes to Consolidated Financial Statements
included herein.
Discussion of other factors affecting the Company is set forth in the
Notes to Consolidated Financial Statements and Management's Discussion and
Analysis included herein.
ELECTRIC OPERATIONS
General. The Company supplies electric energy at retail to approximately
585,000 customers in 462 communities in Kansas. These include Wichita,
Topeka, Lawrence, Manhattan, Salina, and Hutchinson. On September 20 1993,
the Company completed the purchase of the electric distribution system in
DeSoto Kansas. This acquisition added approximately 880 customers to the
Company's system. The Company also supplies electric energy at wholesale to
the electric distribution systems of 67 communities and 5 rural electric
cooperatives. The Company has contracts for the sale, purchase or exchange of
electricity with other utilities. The Company also receives a limited amount
of electricity through parallel generation.
The Company's electric sales for the last five years were as follows
(includes KG&E since March 31, 1992):
1993 1992 1991 1990 1989
(Thousands of MWH)
Residential 4,960 3,842 2,556 2,403 2,248
Commercial 5,100 4,473 3,051 2,952 2,814
Industrial 5,301 4,419 1,947 1,954 1,925
Other 4,628 3,119 1,984* 1,820 2,077
Total 19,989 15,853 9,538* 9,129 9,064
* Includes cumulative effect to January 1, 1991, of change in revenue
recognition. The cumulative effect of this change increased electric
sales by 256,000 MWH.
The Company's electric revenues for the last five years were as follows
(includes KG&E since March 31, 1992):
1993 1992 1991 1990 1989
(Thousands of Dollars)
Residential $ 384,618 $296,917 $160,831 $152,509 $142,308
Commercial 319,686 271,303 149,152 146,001 139,567
Industrial 261,898 211,593 78,138 79,225 78,267
Other 138,335 103,072 83,718 85,972 92,201
Total $1,104,537 $882,885 $471,839 $463,707 $452,343
Capacity. The accredited generating capacity of the Company's system is
presently 5,184 megawatts (MW). The system comprises interests in 22 fossil
fueled steam generating units, one nuclear generating unit (47 percent
interest), seven combustion peaking turbines and one diesel generator located
at eleven generating stations. Two units of the 22 fossil fueled units have
been "mothballed" for future use (see Item 2, Properties).
The Company's 1993 peak system net load occurred on August 16, 1993 and
amounted to 3,821 MW. The Company's net generating capacity together with
power available from firm interchange and purchase contracts, provided a
capacity margin of approximately 23 percent above system peak responsibility
at the time of the peak.
The Company and ten companies in Kansas and western Missouri have agreed
to provide capacity (including margin), emergency and economy services for
each other. This arrangement is called the MOKAN Power Pool. The pool
participants also coordinate the planning of electric generating and
transmission facilities.
In January 1994, the Company entered into an agreement with Oklahoma
Municipal Power Authority (OMPA), whereby, the Company received a prepayment
of approximately $41 million for capacity and transmission charges through the
year 2013.
Future Capacity. The Company does not contemplate any significant
expenditures in connection with construction of any major generating
facilities through the turn of the century (see Management's Discussion and
Analysis, Liquidity and Capital Resources). Although the Company's management
believes, based on current load-growth projections and load management
programs, it will maintain adequate capacity margins through 2000, in view of
the lead time required to construct large operating facilities, the Company
may be required before 2000 to consider whether to reschedule the construction
of Jeffrey Energy Center (JEC) Unit 4 or alternatively either build or acquire
other capacity.
Fuel Mix. The Company's coal-fired units comprise 3,186 MW of the total
5,184 MW of generating capacity and the Company's nuclear unit provides 533 MW
of capacity. Of the remaining 1,465 MW of generating capacity, units that can
burn either natural gas or oil account for 1,373 MW, and the remaining units
which burn only oil or diesel account for 92 MW (see Item 2, Properties).
During 1993, low sulfur coal was used to produce 79 percent of the
Company's electricity. Nuclear produced 17 percent and the remainder was
produced from natural gas, oil, or diesel. Based on the Company's estimate of
the availability of fuel, coal will continue to be used to produce
approximately 78 percent of the Company's electricity and 18 percent from
nuclear.
The Company anticipates the fuel mix to fluctuate with the operation of
nuclear powered Wolf Creek which operates on an 18-month refueling and
maintenance schedule. The 18-month schedule permits uninterrupted operation
every third calendar year. Beginning March 5, 1993, Wolf Creek was taken off-
line for its sixth refueling and maintenance outage. The refueling outage
took approximately 73 days to complete, during which time electric demand was
met primarily by the Company's coal-fired generating units.
Nuclear. The owners of Wolf Creek have on hand or under contract 73
percent of the uranium required for operation of Wolf Creek through the year
2001. The balance is expected to be obtained through spot market and contract
purchases.
Contractual arrangements are in place for 100 percent of Wolf Creek's
uranium enrichment requirements for 1993-1996, 70 percent for 1997-1998 and
100 percent for 2003-2014. The balance of the 1997-2002 requirements is
expected to be obtained through a combination of spot market and contract
purchases. The decision not to contract for the full enrichment requirements
is one of cost rather than availability of service.
Contractual arrangements are in place for the conversion of uranium to
uranium hexafluoride sufficient to meet Wolf Creek's requirements through 1995
as well as the fabrication of fuel assemblies to meet Wolf Creek's
requirements through 2012. During 1994, the Company plans to begin securing
additional arrangements for uranium conversion for the post 1995 period.
The Nuclear Waste Policy Act of 1982 established schedules, guidelines and
responsibilities for the Department of Energy (DOE) to develop and construct
repositories for the ultimate disposal of spent fuel and high-level waste.
The DOE has not yet constructed a high-level waste disposal site and has
announced that a permanent storage facility may not be in operation prior to
2010 although an interim storage facility may be available earlier. Wolf
Creek contains an on-site spent fuel storage facility which, under current
regulatory guidelines, provides space for the storage of spent fuel through
2006 while still maintaining full core off-load capability. The Company
believes adequate additional storage space can be obtained, as necessary.
Coal. The Company has a long-term coal supply contract with Amax Coal
West, Inc. (AMAX) a subsidiary of Cyprus Amax Coal Company, to supply low
sulfur coal to JEC from AMAX's Eagle Butte Mine or an alternate mine source of
AMAX's Belle Ayr Mine, both located in the Powder River Basin in Cambell
County, Wyoming. The contract expires December 31, 2020. The contract
contains a schedule of minimum annual delivery quantities with deficient mmBTU
provisions applicable to deficiencies in the scheduled delivery. The coal to
be supplied is surface mined and has an average BTU content of approximately
8,300 BTU per pound and an average sulfur content of .43 lbs/mmBTU (see
Environmental Matters). The average delivered cost of coal for JEC was
approximately $1.045 per mmBTU or $17.35 per ton during 1993.
Coal is transported from Wyoming under a long-term rail transportation
contract with Burlington Northern (BN) and Union Pacific (UP) to JEC through
December 31, 2013. Rates are based on net load carrying capabilities of each
rail car. The Company provides 770 aluminum rail cars, under a 20 year lease,
to transport coal to JEC. During 1994, the Company will provide an additional
120 rail cars under a similar lease.
The two coal fired units at La Cygne generating station have an aggregate
generating capacity of 677 MW (KG&E's 50 percent share) (see Item 2.
Properties). The operator, Kansas City Power & Light Company (KCP&L),
maintains coal contracts summarized in the following paragraphs.
During 1993, La Cygne 1 was converted to use low sulfur Powder River Basin
coal which is supplied under the AMAX contract for La Cygne 2, discussed
below. Illinois or Kansas/Missouri coal is blended with the Powder River
Basin coal and is secured from time to time under spot market arrangements.
La Cygne 1 uses a blend of 85 percent Powder River Basin coal. During the
third and fourth quarters of 1993, the Company along with the operator secured
supplemental Illinois or Kansas/Missouri coal, for blending purposes, on a
short-term basis through spot market purchase orders.
La Cygne 2 and additional La Cygne 1 Powder River Basin coal was supplied,
through a contract that expired December 31, 1993, by AMAX from its mines in
Gillette, Wyoming. This low sulfur coal had an average BTU content of
approximately 8,500 BTU per pound and a maximum sulfur content of .50
lbs/mmBTU (see Environmental Matters). For 1994, the operator has secured
Powder River Basin coal, similar to the AMAX coal, from two sources; Carter
Mining Company's Caballo Mine, a subsidiary of Exxon Coal USA; and Caballo
Rojo Inc's Caballo Rojo Mine, a subsidiary of Drummond Inc. Transportation is
covered by KCP&L through its Omnibus Rail Transportation Agreement with BN and
Kansas City Southern Railroad through December 31, 1995. An alternative rail
transportation agreement with Western Railroad Property, Inc. (WRPI), a
partnership between UP and Chicago Northwestern (CNW), lasts through December
31, 1995. The WRPI/UP/CNW agreement is a supplemental access contract to
handle tonnages not covered by the Omnibus contract.
During 1993, the average delivered cost of all coal procured for La Cygne
1 was approximately $0.81 per mmBTU or $14.24 per ton and the average
delivered cost of Powder River Basin coal for La Cygne 2 was approximately
$0.84 per mmBTU or $14.18 per ton.
The coal-fired units located at the Tecumseh and Lawrence Energy Centers
have an aggregate generating capacity of 768 MW (see Item 2. Properties). The
Company contracted with ARCH Mineral Corporation (ARCH Mineral) for low sulfur
coal through December 31, 1993. The coal from ARCH Mineral was surface mined
at its mine in Hanna, Wyoming and had an average BTU content of approximately
10,400 BTU per pound and an average sulfur content of .625 lbs/mmBTU (see
Environmental Matters). During 1993, the average delivered cost of coal for
the Lawrence units was approximately $1.254 per mmBTU or $29.13 per ton and
the average delivered cost of coal for the Tecumseh units was approximately
$1.229 per mmBTU or $26.19 per ton. The Company had a supplemental spot coal
agreement, expiring December 31, 1993, with Cyprus Western Coal Company
(Cyprus) to supply low-sulfur coal from Cyprus's Foidel Creek Mine located in
Routt County, Colorado. The Company entered into a new five year coal supply
agreement, effective January 1, 1994, with Cyprus for coal from the Foidel
Creek mine. This coal will be transported under a new agreement with Southern
Pacific Lines and Atchison and Topeka Santa Fe Railway Company. The coal
supplied from Cyprus has an average BTU content of approximately 11,200 BTU
per pound and an average sulfur content of .38 lbs/mmBTU. The Company
anticipates that the Cyprus agreement will supply the minimum requirements of
the Tecumseh and Lawrence Energy Centers and supplemental coal requirements
will continue to be supplied from favorable coal markets in Wyoming, Utah,
Colorado and/or New Mexico.
Natural Gas. The Company uses natural gas as a primary fuel in its Gordon
Evans, Murray Gill, Abilene, and Hutchinson Energy Centers and in the gas
turbine units at its Tecumseh generating station. Natural gas is also used as
a supplemental fuel in the coal fired units at the Lawrence and Tecumseh
generating stations. Natural gas for Gordon Evans and Murray Gill Energy
Centers is supplied under a firm contract that runs through 1995 by Kansas Gas
Supply (KGS). Short-term economical spot market purchases from the Williams
Natural Gas (WNG) system provide the Company flexible natural gas to meet
operational needs. Natural gas for the Company's Abilene and Hutchinson
stations is supplied from the Company's main system (see Natural Gas
Operations). Natural gas for the units at the Lawrence and Tecumseh stations
is supplied through the WNG system under a short-term spot market agreement.
Oil. The Company uses oil as an alternate fuel when economical or when
interruptions to gas make it necessary. Oil is also used as a supplemental
fuel at each of the coal plants. All oil burned by the Company during the
past several years has been obtained by spot market purchases. At December
31, 1993, the Company had approximately 4 million gallons of No. 2 and 14.7
million gallons of No. 6 oil which is sufficient to meet emergency
requirements and protect against lack of availability of natural gas and/or
the loss of a large generating unit.
Other Fuel Matters. The Company's contracts to supply fuel for its coal-
and natural gas-fired generating units, with the exception of JEC, do not
provide full fuel requirements at the various stations. Supplemental fuel is
procured on the spot market to provide operational flexibility and, when the
price is favorable, to take advantage of economic opportunities.
On March 26, 1992, in connection with the Merger, the Kansas Corporation
Commission (KCC) approved the elimination of the Energy Cost Adjustment Clause
(ECA) for most Kansas retail electric customers of both the Company and KG&E
effective April 1, 1992. The provisions for fuel costs included in base rates
were established at a level intended by the KCC to equal the projected average
cost of fuel through August 1995 and to include recovery of costs provided by
previously issued orders relating to coal contract settlements. Any increase
or decrease in fuel costs from the projected average will be absorbed by the
Company.
Set forth in the table below is information relating to the weighted
average cost of fuel used by the Company.
KPL Plants 1993 1992 1991 1990 1989
Per Million BTU:
Coal $1.13 $1.30 $1.33 $1.33 $1.31
Gas 2.71 2.15 1.72 1.50 2.10
Oil 4.41 4.19 4.25 4.63 3.92
Cents per KWH Generation 1.31 1.49 1.52 1.53 1.51
KG&E Plants 1993 1992 1991 1990 1989
Per Million BTU:
Nuclear $0.35 $0.34 $0.32 $0.34 $0.34
Coal 0.96 1.25 1.32 1.32 1.38
Gas 2.37 1.95 1.74 1.96 1.91
Oil 3.15 4.28 4.13 3.01 3.30
Cents per KWH Generation 0.93 0.98 1.09 1.01 0.96
Environmental Matters. The Company currently holds all Federal and state
environmental approvals required for the operation of all its generating
units. The Company believes it is presently in substantial compliance with
all air quality regulations (including those pertaining to particulate matter,
sulfur dioxide and nitrogen oxides) promulgated by the State of Kansas and the
Environmental Protection Agency (EPA).
The Federal sulfur dioxide standards, applicable to the Company's JEC and
La Cygne 2 units, prohibit the emission of more than 1.2 pounds of sulfur
dioxide per million BTU of heat input. Federal particulate matter emission
standards applicable to these units prohibit: (1) the emission of more than
0.1 pounds of particulate matter per million BTU of heat input and (2) an
opacity greater than 20 percent. Federal nitrogen oxides emission standards
applicable to these units prohibit the emission of more than 0.7 pounds of
nitrogen oxides per million BTU of heat input.
The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards
through the use of low sulfur coal (See Coal); (2) the particulate matter
standards through the use of electrostatic precipitators; and (3) the nitrogen
oxide standards through boiler design and operating procedures. The JEC units
are also equipped with flue gas scrubbers providing additional sulfur dioxide
and particulate matter emission reduction capability.
The Kansas Department of Health and Environment regulations, applicable to
the Company's other generating facilities, prohibit the emission of more than
2.5 pounds of sulfur dioxide per million BTU of heat input at the Company's
Lawrence generating units and 3.0 pounds at all other generating units. The
Company has contracted or intends to contract to purchase low sulfur coal (see
Coal) which will allow compliance with such limits at Lawrence, Tecumseh and
La Cygne 1. All facilities burning coal are equipped with flue gas scrubbers
and/or electrostatic precipitators.
The Clean Air Act Amendments of 1990 (the Act) require a two-phase
reduction in sulfur dioxide and nitrogen oxide emissions effective in 1995 and
2000 and a probable reduction in toxic emissions. To meet the monitoring and
reporting requirements under the acid rain program, the Company is installing
continuous monitoring and reporting equipment at a total cost of approximately
$10 million. At December 31, 1993, the Company had completed approximately $4
million of these capital expenditures with the remaining $6 million of capital
expenditures to be completed in 1994 and 1995. The Company does not expect
additional equipment to reduce sulfur emissions to be necessary under Phase
II. The Company currently has no Phase I affected units.
The nitrogen oxide and toxic limits, which were not set in the law, will
be specified in future EPA regulations. The EPA has issued, for public
comment, preliminary nitrogen oxide regulations for Phase I group 1 units.
Nitrogen oxide regulations for Phase II units and Phase I group 2 units are
mandated in the Act to be promulgated by January 1, 1997. Although the
Company has no Phase I units, the final nitrogen oxide regulations for Phase 1
group 1 may allow for early compliance for Phase II group 1 units. Until
such time as the Phase I group 1 nitrogen oxide regulations are final, the
Company will be unable to determine its compliance options or related
compliance costs.
All of the Company's generating facilities are in substantial compliance
with the Best Practicable Technology and Best Available Technology regulations
issued by EPA pursuant to the Clean Water Act of 1977. Most EPA regulations
are administered in Kansas by the Kansas Department of Health and Environment.
Additional information with respect to Environmental Matters is discussed
in Note 4 of the Notes to Consolidated Financial Statements included herein.
NATURAL GAS OPERATIONS
General. At December 31, 1993, the Company supplied natural gas at retail
to approximately 1,093,000 customers in 519 communities and at wholesale to
eight communities and two utilities in Kansas, Missouri and Oklahoma. The
natural gas systems of the Company consisted of distribution systems in all
three states purchasing natural gas from interstate pipeline companies and the
main system, an integrated storage, gathering, transmission and distribution
system. The Company also transports gas for its large commercial and
industrial customers purchasing gas on the spot market. The Company earns
approximately the same margin on volume of gas transported as on volumes sold
except where limited discounting occurs in order to retain the customer's
load.
As discussed previously, on January 31, 1994, the Company sold
substantially all of its Missouri natural gas distribution properties and
operations to Southern Union and sold the remaining Missouri properties to
United Cities on February 28, 1994. Additional information with respect to
the impact of the sale of the Missouri Properties is set forth in Notes 2 and
13 of the Notes to Consolidated Financial Statements.
The percentage of total natural gas deliveries, including transportation
and operating revenues for 1993 by state were as follows:
Total Natural Total Natural Gas
Gas Deliveries Operating Revenues
Kansas 54.6% 53.9%
Missouri 43.0% 43.5%
Oklahoma 2.4% 2.6%
The Company's natural gas deliveries for the last five years were as
follows:
1993 1992 1991 1990 1989
(Thousands of MCF)
Residential 110,045 93,779 97,297 95,247 104,057
Commercial 47,536 40,556 47,075 43,973 47,339
Industrial 1,490 2,214 2,655 3,207 5,637
Other 41 94 14,960* 1,361 1,403
Transportation 73,574 68,425 78,055 72,623 58,025
Total 232,686 205,068 240,042* 216,411 216,461
* Includes cumulative effect to January 1, 1991, of change in revenue
recognition. The cumulative effect of this change increased natural
gas sales by 14,838,000 MCF.
The Company's natural gas revenues for the last five years were as
follows:
1993 1992 1991 1990 1989
(Thousands of Dollars)
Residential $529,260 $440,239 $433,871 $439,956 $430,250
Commercial 209,344 169,470 182,486 176,279 172,628
Industrial 7,294 7,804 10,546 12,994 18,021
Other 30,143 27,457 33,434 31,323 30,072
Transportation 28,781 28,393 30,002 25,496 24,309
Total $804,822 $673,363 $690,339 $686,048 $675,280
In compliance with orders of the state commissions applicable to all
natural gas utilities, the Company has established priority categories for
service to its natural gas customers. The highest priority is for residential
and small commercial customers and the lowest for large industrial customers.
Natural gas delivered by the Company from its main system for use as fuel for
electric generation is classified in the lowest priority category.
Interstate Pipeline Supply. During 1993, the Company purchased natural
gas from interstate pipelines, producers, and marketers to distribute at
retail to approximately 966,000 customers located in western Missouri, central
and eastern Kansas and northeastern Oklahoma. The principal market area at
December 31, 1993, was the seven county Kansas City metropolitan area (see
page 3 regarding the sale of the Missouri Properties), which includes Kansas
City and Independence in Missouri and Kansas City and the northeast Johnson
County suburbs in Kansas. Other larger cities which were served in 1993 are
St. Joseph and Joplin, Missouri; Wichita and Topeka, Kansas; and Bartlesville,
Oklahoma.
During 1993, as a result of FERC Order No. 636, significant changes
occurred regarding the acquisition of interstate pipeline supply and
transportation services. The FERC has issued final decisions concerning the
Company's major pipeline suppliers which authorized the implementation of
restructured services before the 1993-94 winter heating season. Appeals have
been filed in several of these cases concerning numerous issues addressed by
the restructuring orders. The Company anticipates that implementation of
restructured pipeline services will not significantly affect its ability to
provide reliable service to its customers. For additional discussion, see
Management's Discussion and Analysis included herein.
In 1993, the Company purchased approximately 56.9 billion cubic feet (BCF)
or 38.7 percent of the interstate pipeline supply compared with 48.1 BCF or
39.4 percent for 1992, from Williams Natural Gas Company (WNG), a
non-affiliated interstate pipeline transmission company. The Company had a
contract with WNG for natural gas purchases which expired on September 30,
1993. The Company's purchase contract has been superseded by transportation
agreements with WNG which have terms varying in length from one to twenty
years. The Company now purchases all the natural gas it delivers to its
customers direct from producers and marketers of natural gas. WNG transported
33.5 BCF under these agreements in 1993.
The Company has gas purchase contracts with Mobil Natural Gas, Inc., OXY
USA, Inc., Williams Gas Marketing, Kansas Pipeline Company, L.P., Mesa, Tri-
Power Fuels, Amoco, Mid-Kansas Partnership, and GPM Gas Corporation expiring
at various times. Some of the Company's gas purchase contracts extend beyond
the year 2000. The Company purchased approximately 77.8 BCF or 52.9 percent
of its natural gas supply from these sources in 1993 and 63.9 BCF or 52.3
percent during 1992. Approximately 94.4 BCF of natural gas is made available
annually under these contracts. The Company has limited rights to substitute
spot gas for this gas under contract.
Other sources of supply for the Company's distribution systems were
Panhandle Eastern Pipeline Company (Panhandle), Northern Natural Gas Company,
Natural Gas Pipeline Company of America, intrastate pipelines, and spot market
suppliers under short term contracts. These sources totalled 5.2 and 2.0 BCF
for 1993 and 1992 representing 3.5 percent and 1.6 percent of the system
requirements, respectively.
During 1993 and 1992, approximately 7.1 BCF and 8.2 BCF, respectively,
were transferred from the Company's main system to serve a portion of Wichita,
Kansas. These system transfers represent 4.9 percent and 6.7 percent,
respectively, of the interstate system supply.
The average wholesale cost per thousand cubic feet (MCF) purchased for the
distribution systems for the past five years was as follows:
Interstate Pipeline Supply
(Average Cost per MCF)
1993 1992 1991 1990 1989
WNG $3.57 $3.64 $3.61 $3.84 $3.23
Other 3.01 2.30 2.36 2.14 2.29
Total Average Cost 3.23 2.88 3.02 3.10 2.91
The increase in the total average cost per MCF in 1993 from 1992 reflects
increased prices in the spot market.
Main System. The Company serves approximately 127,000 customers in
central and north central Kansas with natural gas supplied through the main
system. The principal market areas include Salina, Manhattan, Junction City,
Great Bend, McPherson, Hutchinson and Wichita, Kansas.
Natural gas for the Company's main system is purchased from a combination
of direct wellhead production, from the outlet of natural gas processing
plants, and from interstate pipeline interconnects all within the State of
Kansas. Such purchases are transported entirely through Company owned
transmission lines in Kansas.
During 1993 the Company purchased from Mesa approximately 15.6 BCF of
natural gas (including 2.5 BCF of make-up deliveries) pursuant to a contract
expiring May 31, 1995 (the Hugoton Contract). This compares with 14.3 BCF
(including 2.1 BCF of make-up deliveries) during 1992. These purchases
represent approximately 53.7 percent and 55.2 percent, respectively, of the
Company's main system requirements during such periods.
Pursuant to the Hugoton Contract, the Company expects to purchase
approximately 16.8 BCF of natural gas constituting approximately 56.4 percent
of the Company's main system requirements during 1994. Mesa dedicated its
entire deliverability in the contract area to the Company. However, if the
Company is unable to take 100% of such deliverability, such non-takes by the
Company are released back to Mesa to sell to others. Under the terms of the
Hugoton Contract, the Company is entitled to purchase annually the volume of
natural gas the KCC allows to be produced from the Mesa wells, less gasoline
plant shrinkage and the natural gas used by Mesa in its operations.
Spivey-Grabs field in south-central Kansas supplied approximately 4.8 and
5.4 BCF of natural gas in 1993 and 1992, constituting 16.6 percent and 20.9
percent, respectively, of the main system's requirements during such periods.
Such natural gas is supplied pursuant to contracts with producers in the
Spivey-Grabs field, most of which are for the life of the field, and under
which the Company expects to receive approximately 5.2 BCF of natural gas in
1994.
Other sources of gas for the main system of 4.4 BCF or 15.2 percent of the
system requirements were purchased from or transported through interstate
pipelines during 1993. The remainder of the supply for the main system during
1993 and 1992 of 4.2 and 4.0 BCF representing 14.5 percent and 15.4 percent,
respectively, was purchased directly from producers or gathering systems.
During 1993 and 1992, approximately 7.1 and 8.2 BCF, respectively, of the
total main system supply was transferred to the Company's interstate system
(see Interstate Pipeline Supply).
The main system's average wholesale cost per MCF purchased for the past
five years was as follows:
Natural Gas Supply - Main System
(Average Cost per MCF)
1993 1992 1991 1990 1989
Mesa-Hugoton Contract $1.78(1) $1.47(2) $1.36(3) $1.47(4) $1.35
Other 2.69 2.66 2.68 2.54 2.63
Total Average Cost 2.20 2.00 1.94 1.98 1.84
(1) Includes 2.5 BCF @ $1.31/MCF of make-up deliveries.
(2) Includes 2.1 BCF @ $1.31/MCF of make-up deliveries.
(3) Includes 1.5 BCF @ $1.31/MCF of make-up deliveries.
(4) Includes 1.6 BCF @ $1.12/MCF and 1.8 BCF @ $1.31/MCF of make-up
deliveries.
The Company has determined that it controlled an estimated 448 BCF of
proved natural gas reserves as of December 31, 1993, for the main system. The
Company made this determination based on a study and estimate prepared by K&A
Energy Consultants, Inc., independent petroleum engineers and geologists, of
the natural gas reserves under contract to the Company as of December 31,
1988, and changes in contracted reserves since the date of the study. The
annual amount of natural gas available from these reserves is dependent upon
production allowables granted by the KCC to wells in specific natural gas
fields, and upon the deliverability of the wells under contract.
Production allowables for the Hugoton Field, set by the KCC, determine the
amount of natural gas available to the Company. The production allowables
granted by the KCC are reviewed in March and September of each year.
In the Company's opinion, its contracts and reserves are adequate to meet
the present annual requirements of its main system high priority customers
through 1994. The Company has contracted with various suppliers to assure
adequate supplies will continue beyond 1994.
The load characteristics of the Company's natural gas customers creates
relatively high volume demand on the main system during cold winter days. To
assure peak day service to high priority customers, the Company has developed
the Brehm natural gas storage facility near Pratt, Kansas with working storage
capacity of 1.6 BCF. The Company has an agreement with Williams Natural Gas
Company, expiring March 31, 1998, for an additional 3.3 BCF of storage in the
Alden field in Kansas. Natural gas is transferred to and displaced from Alden
through Williams's pipeline system.
Under the terms of a deferred delivery agreement between the Company and
Enron Gas Marketing (EGM), the Company will receive approximately 1.5 BCF
during the 1993-1994 heating season, which will complete the deferred delivery
agreement.
The Company owns and operates the Brehm field, an underground natural gas
storage facility in Pratt County, Kansas. This facility has a storage
capacity of approximately 1.6 BCF.
The Company has developed additional storage for the main system in the
Yaggy field near Hutchinson, Kansas. This field provides another 2 BCF of
working storage capacity when fully operational, of which approximately 1 BCF
was available for the heating season beginning November 1993.
Environmental Matters. For information with respect to Environmental
Matters see Note 4 of Notes to Consolidated Financial Statements included
herein.
SEGMENT INFORMATION
Financial information with respect to business segments as set forth in
Note 13 of Notes to Consolidated Financial Statements included herein.
FINANCING
The Company's ability to issue additional debt and equity securities is
restricted under limitations imposed by the charter and the Mortgage and Deed
of Trust of Western Resources and KG&E.
Western Resources' mortgage prohibits additional first mortgage bonds from
being issued (except in connection with certain refundings) unless the
Company's net earnings available for interest, depreciation and property
retirement for a period of 12 consecutive months within 15 months preceding
the issuance are not less than the greater of twice the annual interest
charges on, or 10% of the principal amount of, all first mortgage bonds
outstanding after giving effect to the proposed issuance. Based on the
Company's results for the 12 months ended December 31, 1993, approximately
$457 million principal amount of additional first mortgage bonds could be
issued (7.5 percent interest rate assumed).
Additional Western Resources bonds may be issued, subject to the
restrictions in the preceding paragraph, on the basis of property additions
not subject to an unfunded prior lien and on the basis of bonds which have
been retired. As of December 31, 1993, the Company had approximately $148
million of net bondable property additions not subject to an unfunded prior
lien entitling the Company to issue up to $89 million principal amount of
additional bonds. As of December 31, 1993, the Company could also issue up to
$203 million bonds on the basis of retired bonds.
With the sale of the Missouri Properties and the discharge of the Gas
Service mortgage, the Company, as of January 31, 1994, had approximately $387
million of net bondable property additions not subject to an unfunded prior
lien entitling the Company to issue up to $232 million of additional bonds.
In addition, $203 million of retired bonds were repledged to the Trustee for
the release of a portion of the gas properties sold. As of January 31, 1994,
no additional bonds could be issued on the basis of retired bonds.
KG&E's mortgage prohibits additional first mortgage bonds from being
issued (except in connection with certain refundings) unless KG&E's net
earnings before income taxes and before provision for retirement and
depreciation of property for a period of 12 consecutive months within 15
months preceding the issuance are not less than two and one-half times the
annual interest charges on, or 10% of the principal amount of, all first
mortgage bonds outstanding after giving effect to the proposed issuance.
Based on KG&E's results for the 12 months ended December 31, 1993,
approximately $1 billion principal amount of additional first mortgage bonds
could be issued (7.5 percent interest rate assumed).
Additional KG&E bonds may be issued, subject to the restrictions in the
preceding paragraph, on the basis of property additions not subject to an
unfunded prior lien and on the basis of bonds which have been retired. As of
December 31, 1993, KG&E had approximately $1.3 billion of net bondable
property additions not subject to an unfunded prior lien entitling KG&E to
issue up to $882 million principal amount of additional bonds. As of December
31, 1993, KG&E could also issue up to $115 million bonds on the basis of
retired bonds.
The most restrictive provision of the Company's charter permits the
issuance of additional shares of preferred stock without certain specified
preferred stockholder approval only if, for a period of 12 consecutive months
within 15 months preceding the issuance, net earnings available for payment of
interest exceed one and one-half times the sum of annual interest requirements
and dividend requirements on preferred stock after giving effect to the
proposed issuance. After giving effect to the annual interest and dividend
requirements on all debt and preferred stock outstanding at December 31, 1993,
such ratio was 1.94 for the 12 months ended December 31, 1993.
REGULATION AND RATES
The Company is subject as an operating electric utility to the
jurisdiction of the KCC and as a natural gas utility to the jurisdiction of
the KCC, the Missouri Public Service Commission (MPSC), and the Corporation
Commission of the State of Oklahoma (OCC), which have general regulatory
authority over the Company's rates, extensions and abandonments of service and
facilities, valuation of property, the classification of accounts and various
other matters.
The Company is subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC), KCC and MPSC with respect to the issuance of
securities. There is no state regulatory body in Oklahoma having jurisdiction
over the issuance of the Company's securities.
Additionally, the Company is subject to the jurisdiction of the FERC,
including jurisdiction as to rates with respect to sales of electricity for
resale. The Company is not engaged in the interstate transmission or sale of
natural gas which would subject it to the regulatory provisions of the Natural
Gas Act. KG&E is also subject to the jurisdiction of the Nuclear Regulatory
Commission as to nuclear plant operations and safety.
Additional information with respect to Rate Matters and Regulation as set
forth in Note 5 of Notes to Consolidated Financial Statements is included
herein.
EMPLOYEE RELATIONS
As of December 31, 1993, the Company had 5,192 employees. The Company did
not experience any strikes or work stoppages during 1993. The Company's
current contracts with its two electric unions were negotiated in 1993 and
expire June 30, 1995. The two contracts cover approximately 2,000 employees.
The Company has contracts with 5 other unions representing approximately 1,450
employees. These contracts were negotiated in 1992 and will expire June 6,
1996. Following the 1994 sale of the Missouri Properties the Company had
4,164 employees.
EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During Past Five Years
John E. Hayes, Jr. 56 Chairman of the Board, Chairman of the Board (1989)
President, and Chief Triad Capital Partners,
Executive Officer St. Louis, Missouri
(since October 1989) President and Chief Executive
Officer (1986 to 1989), Director
(1984 to 1989), and Chairman of
the Board (1986 to 1989),
Southwestern Bell Telephone
Company, St. Louis, Missouri
Director (1986 to 1989)
Southwestern Bell Corporation,
St. Louis, Missouri
William E. Brown 54 President and Chief President and Chief Operating Officer-
Executive Officer KPL KPL Division (1990)
(since October 1990) Executive Vice President and Chief
Operating Officer (1987 to 1990)
Acting President (1989)
James S. Haines, Jr. 47 Executive Vice President Group Vice President (1985 to 1992)
and Chief Administrative KG&E, Wichita, Kansas
Officer (since March 1992)
Steven L. Kitchen 48 Executive Vice President Senior Vice President, Finance
and Chief Financial and Accounting (1987 to 1990)
Officer (since March 1990)
John K. Rosenberg 48 Executive Vice President Corporate Secretary (1988 to 1992)
(since March 1990) Vice President (1987 to 1990)
and General Counsel
(since May 1987)
Carl M. Koupal, Jr. 40 Vice President, Corporate Vice President, Marketing and Economic
Communications, Marketing, Development (1992)
and Economic Development Director, Economic Development, (1985
(since September 1992) to 1992) Jefferson City, Missouri
Rayford Price 56 Vice President, Corporate President, (1990 to 1993) Rayford
Price
Development (since & Associates P.C., Austin, Texas
September 1993) Partner, (1988 to 1990) Thomas,
Winters
& Newton, Austin, Texas
Kent R. Brown 48 President and Chief Group Vice President (1982 to 1992)
Executive Officer KG&E KG&E, Wichita, Kansas
(since April 1992)
William L. Johnson(1) 51 President and Chief President and Chief Operating Officer-
Executive Officer Gas Gas Service Division (1990)
Service (since Vice President, District Operations
October 1990) (1985 to 1990) Michigan Consolidated
Gas Company, Grand Rapids, Michigan
Jerry D. Courington 48 Controller (since February
1985)
(1) Mr. Johnson left the Company on January 31, 1994.
The present term of office of each of the executive officers extends to May 3, 1994,
or until their respective successors are chosen and appointed by the Board of
Directors. There are no family relationships among any of the officers, nor any
arrangements or understandings between any officer and other persons pursuant to
which he/she was elected as an officer.
ITEM 2. PROPERTIES
The Company owns or leases and operates an electric generation,
transmission, and distribution system in Kansas, a natural gas integrated
storage, gathering, transmission and distribution system in Kansas, and a
natural gas distribution system in Kansas, Missouri and Oklahoma (see page 3
with respect to the sale of the Missouri Properties).
During the five years ended December 31, 1993, the Company's gross
property additions totalled $852,650,000 and retirements were $125,287,000.
ELECTRIC FACILITIES
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (2)
Abilene Energy Center:
Combustion Turbine 1 1973 Gas 67
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 150
2 1967 Gas--Oil 367
Hutchinson Energy Center:
Steam Turbines 1 1950 Gas 18
2 1950 Gas 20
3 1951 Gas 31
4 1965 Gas 196
Combustion Turbines 1 1974 Gas 53
2 1974 Gas 51
3 1974 Gas 55
4 1975 Oil 89
Jeffrey Energy Center (84%):
Steam Turbines 1 1978 Coal 587
2 1980 Coal 566
3 1983 Coal 588
La Cygne Station (50%):
Steam Turbines 1 1973 Coal 342
2 1977 Coal 335
Lawrence Energy Center:
Steam Turbines 2 1952 Gas 0 (1)
3 1954 Coal 56
4 1960 Coal 102
5 1971 Coal 380
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 46
2 1954 Gas--Oil 69
3 1956 Gas--Oil 107
4 1959 Gas--Oil 105
Neosho Energy Center:
Steam Turbines 3 1954 Gas--Oil 0 (1)
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (2)
Tecumseh Energy Center:
Steam Turbines 7 1957 Coal 83
8 1962 Coal 147
Combustion Turbines 1 1972 Gas 19
2 1972 Gas 19
Wichita Plant:
Diesel Generator 5 1969 Diesel 3
Wolf Creek Generating Station (47%):
Nuclear 1 1985 Uranium 533
Total 5,184
(1) These units have been "mothballed" for future use.
(2) Based on MOKAN rating.
The Company jointly-owns Jeffrey Energy Center (84%), La Cygne Station
(50%) and Wolf Creek Generating Station (47%).
NATURAL GAS COMPRESSOR STATIONS AND STORAGE FACILITIES
The Company's transmission and storage facility compressor stations, all
located in Kansas, as of December 31, 1993, are as follows:
Mfr Ratings
of MCF/Hr
Capacity at
Driving Type of Mfr hp 14.65 Psia
Location Units Year Installed Fuel Ratings at 60 F
Abilene . . . . . 4 1930 Gas 4,000 5,920
Bison . . . . . . 1 1951 Gas 440 316
Brehm Storage . . 2 1982 Gas 800 486
Calista . . . . . 3 1987 Gas 4,400 7,490
Hope. . . . . . . 1 1970 Electric 600 44
Hutchinson. . . . 2 1989 Gas 1,600 707
Manhattan . . . . 1 1963 Electric 250 313
Marysville. . . . 1 1964 Electric 250 202
McPherson . . . . 1 1972 Electric 3,000 7,040
Minneola. . . . . 5 1952 - 1978 Gas 9,650 14,018
Pratt . . . . . . 3 1963 - 1983 Gas 1,700 3,145
Spivey. . . . . . 4 1957 - 1964 Gas 7,200 1,368
Ulysses . . . . . 12 1949 - 1981 Gas 26,630 15,244
Yaggy Storage . . 3 1993 Electric 7,500 5,000
The Company owns and operates an underground natural gas storage facility,
the Brehm field in Pratt County, Kansas. This facility has a working storage
capacity of approximately 1.6 BCF. The Company withdrew up to 16,930 MCF per
day from this field to meet 1993 winter peaking requirements.
The Company owns and operates an underground natural gas storage field,
the Yaggy field in Reno County, Kansas. This facility has a working storage
capacity of approximately 0.8 BCF to be expanded to 2 BCF. The Company
withdrew up to 6,280 MCF per day from this field to meet 1993 winter peaking
requirements.
The Company has contracted with Williams Natural Gas Company for
additional underground storage in the Alden field in Kansas. The contract,
expiring March 31, 1998, enables the Company to supply customers with up to 75
million cubic feet per day of gas supply during winter peak periods. See Item
I. Business, Gas Operations for proven recoverable gas reserve information.
ITEM 3. LEGAL PROCEEDINGS
Information on legal proceedings involving the Company is set forth in
Note 15 of Notes to Consolidated Financial Statements included herein.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of the fiscal year
covered by this report to a vote of security holders, through the solicitation
of proxies or otherwise.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Stock Trading. Western Resources common stock, which is traded under the
ticker symbol WR, is listed on the New York Stock Exchange. As of March 14,
1994, there 45,317 common shareholders of record. For information regarding
quarterly common stock price ranges for 1993 and 1992, see Note 16 of Notes to
Consolidated Financial Statements included herein.
Dividend Policy. Western Resources common stock is entitled to dividends
when and as declared by the Board of Directors. At December 31, 1993, the
Company's retained earnings were restricted by $857,600 against the payment of
dividends on common stock. However, prior to the payment of common dividends,
dividends must be first paid to the holders of preferred stock and second to
the holders of preference stock based on the fixed dividend rate for each
series.
Dividends have been paid on the Company's common stock throughout the
Company's history. Quarterly dividends on common stock normally are paid on
or about the first of January, April, July, and October to shareholders of
record as of about the third day of the preceding month. Future dividends
depend upon future earnings, the financial condition of the Company and other
factors. For information regarding quarterly dividend declarations for 1993
and 1992, see Note 16 of Notes to Consolidated Financial Statements included
herein.
ITEM 6. SELECTED FINANCIAL DATA
Year Ended December 31, 1993 1992(1) 1991 1990 1989
(Dollars in Thousands)
Income Statement Data:
Operating revenues:
Electric . . . . . . . . . . . $1,104,537 $ 882,885 $ 471,839 $ 463,707 $ 452,343
Natural gas. . . . . . . . . . 804,822 673,363 690,339 686,048 675,280
Total operating revenues . . 1,909,359 1,556,248 1,162,178 1,149,755 1,127,623
Operating expenses . . . . . . . 1,617,296 1,317,079 1,032,557 1,017,765 1,002,087
Allowance for funds used during
construction . . . . . . . . . 2,631 2,002 1,070 1,181 1,503
Income before cumulative effect
of accounting change . . . . . 177,370 127,884 72,285 79,619 72,778
Cumulative effect to January 1,
1991, of change in revenue
recognition. . . . . . . . . . - - 17,360 - -
Net income . . . . . . . . . . . 177,370 127,884 89,645 79,619 72,778
Earnings applicable to common
stock. . . . . . . . . . . . . 163,864 115,133 83,268 77,875 70,921
December 31, 1993 1992(1) 1991 1990 1989
(Dollars in Thousands)
Balance Sheet Data:
Gross plant in service . . . . . $6,222,483 $6,033,023 $2,535,448 $2,421,562 $2,305,279
Construction work in progress. . 80,192 68,041 17,114 20,201 19,571
Total assets . . . . . . . . . . 5,412,048 5,438,906 2,112,513 2,016,029 1,959,044
Long-term debt and preference
stock subject to mandatory
redemption . . . . . . . . . . 1,673,988 2,077,459 690,612 595,524 552,538
Year Ended December 31, 1993 1992(1) 1991 1990 1989
Common Stock Data:
Earnings per share before
cumulative effect of
accounting change. . . . . . . $ 2.76 $ 2.20 $ 1.91 $ 2.25 $ 2.05
Cumulative effect to January 1,
1991, of change in revenue
recognition per share. . . . . - - .50 - -
Earnings per share . . . . . . . $ 2.76 $ 2.20 $ 2.41 $ 2.25 $ 2.05
Dividends per share. . . . . . . $ 1.94 $ 1.90 $ 2.04(2) $ 1.80 $ 1.76
Book value per share . . . . . . $23.08 $21.51 $18.59 $18.25 $17.80
Average shares outstanding(000's) 59,294 52,272 34,566 34,566 34,566
Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 2.79 2.27 2.69 2.86 2.96
(1) Information reflects the merger with KG&E on March 31, 1992 (Note 3).
(2) Includes special, one-time dividend of $0.18 per share paid February 28, 1991.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION
General: Earnings were $2.76 per share of common stock based on
59,294,091 average common shares for 1993, an increase from $2.20 in 1992 on
52,271,932 average common shares. The increase resulted from a return to near
normal temperatures compared to unusually mild winter and summer temperatures
in 1992, reduced interest costs, and the full twelve month effect of the
merger with Kansas Gas and Electric Company (KG&E) on March 31, 1992 (the
Merger).
Dividends per common share were $1.94 in 1993, an increase of four cents
from 1992. In January 1994, the Board of Directors declared a quarterly
dividend of 49 1/2 cents per common share, an increase of one cent over the
previous quarter.
The book value per share was $23.08 at December 31, 1993, compared to
$21.51 at December 31, 1992. The increase in book value is primarily the
result of the issuance of additional common stock and an increase in retained
earnings. The 1993 closing stock price of $34 7/8 was 151 percent of book
value. There were 61,617,873 common shares outstanding at December 31, 1993.
On January 31, 1994, the Company sold substantially all of its Missouri
natural gas distribution properties and operations to Southern Union Company
(Southern Union). The Company sold the remaining Missouri properties to
United Cities Gas Company (United Cities) on February 28, 1994. The
properties sold to Southern Union and United Cities are referred to herein as
the "Missouri Properties." With the sales the Company is no longer operating
as a utility in the State of Missouri.
The portion of the Missouri Properties purchased by Southern Union was
sold for an estimated sale price of $400 million, in cash, based on a
calculation as of December 31, 1993. The final sale price will be calculated
as of January 31, 1994, within 120 days of closing. Any difference between
the estimated and final sale price will be adjusted through a payment to or
from the Company.
United Cities purchased the Company's natural gas distribution system in
and around the City of Palmyra, Missouri, for $665,000 in cash.
The operating revenues and operating income (unaudited) related to the
Missouri Properties approximated $350 million and $21 million representing
approximately 18 percent and seven percent, respectively, of the Company's
total for 1993, and $299 million and $11 million representing approximately 19
percent and five percent, respectively, of the Company's total for 1992. Net
utility plant (unaudited) for the Missouri Properties, at December 31, 1993,
approximated $296 million and $272 million at December 31, 1992. This
represents approximately seven percent at December 31, 1993, and six percent
at December 31, 1992, of the total Company net utility plant. Separate
audited financial information was not kept by the Company for the Missouri
Properties. This unaudited financial information is based on assumptions and
allocations of expenses of the Company as a whole.
Liquidity and Capital Resources: The Company's liquidity is a function of
its ongoing construction program, designed to improve facilities which provide
electric and natural gas service and meet future customer service
requirements.
During 1993, construction expenditures for the Company's electric system
were approximately $138 million and nuclear fuel expenditures were
approximately $6 million. It is projected that adequate capacity margins will
be maintained without the addition of any major generating facilities through
the turn of the century. The construction expenditures for improvements on
the natural gas system, including the Company's service line replacement
program, were approximately $94 million during 1993, of which construction
expenditures for the Missouri Properties were approximately $39 million.
Capital expenditures for 1994 to 1996 are anticipated to be as follows:
Electric Nuclear Fuel Natural Gas
(Dollars in Thousands)
1994 $131,483 $ 20,995 $ 64,608
1995 143,391 21,469 69,482
1996 151,100 9,890 68,747
These expenditures are estimates prepared for planning purposes and are
subject to revisions from time to time (see Note 4).
The Company's net cash flow to capital expenditures was 100 percent for
1993 and during the last five years has averaged 87 percent. The Company
anticipates net cash flow to capital expenditures to be approximately 100
percent in 1994.
The Company's capital needs through 1998 are approximately $33.6 million
for bond maturities and cash sinking fund requirements for bonds and
preference stock. This capital as well as capital required for construction
will be provided from internal and external sources available under then
existing financial conditions.
The Company anticipates using the net proceeds from the sale of the
Missouri Properties to reduce the Company's outstanding debt.
The embedded cost of long-term debt was 7.7% at December 31, 1993, a
decrease from 7.9% at December 31, 1992. The decrease was primarily
accomplished through refinancing of higher cost debt.
The Company's short-term financing requirements are satisfied, as needed,
through the sale of commercial paper, short-term bank loans, and borrowings
under other unsecured lines of credit maintained with banks. At December 31,
1993, short-term borrowings amounted to $441 million, of which $126 million
was commercial paper (see Notes 8 and 9).
On September 20, 1993, KG&E terminated a long-term revolving credit
agreement which provided for borrowings of up to $150 million. The loan
agreement, which was effective through October 1994, was repaid without
penalty.
At December 31, 1993, the Company had $200 million of First Mortgage Bonds
available to be issued under a shelf registration filed August 24, 1993. Also
at December 31, 1993, KG&E had $150 million of First Mortgage Bonds available
to be issued under a shelf registration filed on August 24, 1993. On January
20, 1994, KG&E issued $100 million of First Mortgage Bonds, 6.20% Series due
January 15, 2006, under the KG&E shelf registration. The net proceeds were
used to reduce short-term debt.
On January 31, 1994, the Company redeemed the remaining $2,466,000
principal amount of Gas Service Company 8 1/2% Series First Mortgage Bonds due
1997.
KG&E has a long-term agreement that expires in 1995 which contains
provisions for the sale of accounts receivable and unbilled revenues
(receivables) and phase-in revenues up to a total of $180 million. Amounts
related to receivables are accounted for as sales while those related to
phase-in revenues are accounted for as collateralized borrowings. At December
31, 1993, KG&E had receivables amounting to $56.8 million which were
considered sold.
The issuance and retirement of long-term debt, borrowings against the cash
surrender value of corporate-owned life insurance policies (COLI), and the
issuance of common stock during 1993 are summarized in the table below.
- ------------------------------------------------------------------------------
| Date Issued Retired |
| (Dollars in Millions) |
|Long-term debt |
|----------------------------------------------------------------------------|
|7 3/8% due 2002 - KG&E | 11/22/93 | | $ 25.0|
|8 3/8% due 2006 - KG&E | | | 25.0|
|8 1/2% due 2007 - KG&E | | | 25.0|
|----------------------------------------------------------------------------|
|9.35% due 1998 | 10/15/93 | | 75.0|
|----------------------------------------------------------------------------|
|6 1/2% due 2005 - KG&E | 08/12/93 | $ 65.0| |
|8 1/8% due 2001 - KG&E | 08/20/93 | | 35.0|
|8 7/8% due 2008 - KG&E | | | 30.0|
|----------------------------------------------------------------------------|
|7.65% due 2023 | 04/27/93 | 100.0| |
|8 3/4% due 2000 | 05/12/93 | | 20.0|
|8 5/8% due 2005 | | | 35.0|
|8 3/4% due 2008 | | | 35.0|
|----------------------------------------------------------------------------|
|6% Pollution Control Revenue Refunding | | | |
| Bonds due 2033 | 02/09/93 | 58.5| |
|9 5/8% Pollution Control Refunding and | | | |
| Improvement Revenue Bonds due 2013 | | | 58.5|
|----------------------------------------------------------------------------|
|Bank term loan | 01/26/93 | | 230.0|
|----------------------------------------------------------------------------|
|Revolving credit agreements (net) | various | | 35.0|
|----------------------------------------------------------------------------|
|Other long-term debt and sinking funds | various | 4.1| |
|----------------------------------------------------------------------------|
|COLI borrowings (net) (1) | various | 183.3| |
|----------------------------------------------------------------------------|
|Common stock | | | |
| 3,425,000 shares (2) | 08/25/93 | 124.2| |
| 147,323 shares (3) | various | 5.3| |
|----------------------------------------------------------------------------|
(1) The COLI borrowings will be repaid upon receipt of proceeds from
death benefits under the contracts. See Note 1 of Notes to
Consolidated Financial Statements for additional information on
the accumulated cash surrender value of COLI policies.
(2) Issued in public offering for net proceeds of $121 million.
(3) Issued under the Dividend Reinvestment and Stock Purchase Plan
(DRIP). The net proceeds from these issues of approximately $5.3
million were added to the general corporate funds of the Company.
Shares issued under the DRIP may either be original issue shares
or shares purchased on the open market.
The Company has a Customer Stock Purchase Plan (CSPP) under which retail
electric and natural gas customers and employees of the Company may purchase
common stock through monthly installments. The initial installment period
runs from September 1993, through June 1994, with monthly installments plus
accumulated interest converted to shares in August 1994. Shares issued under
the CSPP may either be original issue shares or shares purchased on the open
market. Approximately $14.7 million has been pledged for this installment
period.
The capital structure at December 31, 1993, was 45 percent common stock
equity, 6 percent preferred and preference stock, and 49 percent long-term
debt. The capital structure at December 31, 1993, including short-term debt
and current maturities of long-term debt and preference stock, was 40 percent
common stock equity, 5 percent preferred and preference stock, and 55 percent
debt.
RESULTS OF OPERATIONS
The following is an explanation of significant variations from prior year
results in revenues, operating expenses, other income and deductions, interest
charges and preferred and preference dividend requirements. The results of
operations of the Company include the activities of KG&E since the Merger on
March 31, 1992. Additional information relating to changes between years is
provided in the Notes to Consolidated Financial Statements.
Revenues: The operating revenues of the Company are based on sales
volumes and rates, authorized by certain state regulatory commissions and the
FERC, charged for the sale and delivery of natural gas and electricity. Rates
are designed to recover the cost of service and allow investors a fair rate of
return. Future natural gas and electric sales will continue to be affected by
weather conditions, competing fuel sources, customer conservation efforts, and
the overall economy of the Company's service area.
The Kansas Corporation Commission (KCC) order approving the Merger
provided a moratorium on increases, with certain exceptions, in the Company's
jurisdictional electric and natural gas rates until August 1995. The KCC
ordered refunds totalling $32 million to the combined companies' customers to
share with customers the Merger-related cost savings achieved during the
moratorium period. The first refund of $8.5 million was made in April 1992.
A refund of the same amount was made in December 1993, and an additional
refund of $15 million will be made in September 1994 (see Note 3).
On March 26, 1992, in connection with the Merger, the KCC approved the
elimination of the Energy Cost Adjustment Clause for most Kansas retail
electric customers of both the Company and KG&E effective April 1, 1992. The
fuel costs are now included in base rates and were established at a level
intended by the KCC to equal the projected average cost of fuel through August
1995. Any increase or decrease in fuel costs from the projected average will
be absorbed by the Company.
Future natural gas revenues will be reduced as a result of the sale of the
Missouri Properties by approximately $350 million annually based on Missouri
revenues recorded in 1993 (see Note 2).
1993 COMPARED TO 1992: Electric revenues increased significantly in 1993
as a result of the Merger. Also contributing to the increase were increased
electric sales for space heating, resulting from colder winter temperatures in
the first quarter of 1993, and increased sales for cooling load, resulting
from warmer temperatures in the second and third quarters of 1993. KG&E
electric revenues of $617 million have been included in the Company's 1993
electric revenues. This compares to KG&E revenues of $424 million, from April
1, 1992, through December 31, 1992, included in the Company's 1992 electric
revenues. Partially offsetting these increases in electric revenues was the
amortization of the Merger-related customer refund.
Electric revenues for 1993 compared to pro forma revenues for 1992, giving
effect to the Merger as if it had occurred at January 1, 1992, would have
increased as a result of the warmer summer and colder winter temperatures in
1993. Retail sales of kilowatt hours on a pro forma comparative basis
increased from approximately 14.6 billion for 1992 to approximately 15.5
billion for 1993, or six percent.
Natural gas revenues increased approximately 20 percent as a result of
increased sales caused by colder winter temperatures, the full impact of
increased retail natural gas rates (see Note 5), and an eleven percent
increase in the unit cost of gas passed on to customers through the purchased
gas adjustment clauses (PGA). The colder winter temperatures are reflected in
a 17 percent increase in natural gas sales to residential customers.
1992 COMPARED TO 1991: Electric revenues increased significantly in 1992
as a result of the Merger. KG&E electric revenues for the nine months ended
December 31, 1992, of $424 million have been included in the Company's
electric revenues. Partially offsetting this increase in revenues were
reduced retail electric sales as a result of the abnormally mild summer
temperatures in 1992 and the amortization of the Merger-related customer
refund.
Electric revenues for 1992 compared to pro forma revenues for 1991, giving
effect to the Merger as if it had occurred at January 1, 1991, also would have
been lower as a result of the mild summer and winter temperatures in 1992.
Retail sales of kilowatthours on a pro forma comparative basis decreased from
approximately 15.1 billion for 1991 to approximately 14.6 billion for 1992, or
four percent.
Natural gas revenues decreased over two percent due to a nine percent
decrease in natural gas deliveries, excluding sales related to the cumulative
effect of the unbilled revenue adjustment in 1991. Also contributing to the
decrease was an approximately four percent decrease in the unit cost of
natural gas which is passed on to customers through the PGA. The decrease in
sales can be attributed to mild winter temperatures in 1992. Partially
offsetting the decreased sales were increased retail rates in Kansas and
Missouri beginning early in 1992.
Operating Expenses: 1993 COMPARED TO 1992: Operating expenses increased
for 1993 primarily as a result of the Merger. KG&E operating expenses of $470
million have been included in the Company's operating expenses for the year
ended December 31, 1993. This compares to KG&E operating expenses of $316
million, from April 1, 1992, through December 31, 1992, included in the
Company's 1992 operating expenses.
Other factors, excluding the Merger, contributing to the increase in
operating expenses were higher fuel and purchased power expenses caused by
increased electric sales to meet cooling load and increased natural gas
purchases caused by a 16 percent increase in natural gas sales and an 11
percent higher unit cost of gas which is passed on to customers through the
PGA.
Also contributing to the increase were higher general taxes due to
increases in plant, the property tax assessment ratio, and higher mill levies.
A constitutional amendment in Kansas changed the assessment on utility
property from 30 to 33 percent. As a result of this change the Company had an
increased property tax expense of approximately $6.1 million in 1993.
Partially offsetting the increases were savings as a result of the Merger
and reduced net lease expense for La Cygne 2 (see Note 10).
At December 31, 1993, KG&E completed the accelerated amortization of
deferred income tax reserves related to the allowance for borrowed funds used
during construction capitalized for Wolf Creek Generating Station. The
amortization of these deferred income tax reserves amounted to approximately
$12 million in 1993. In accordance with the provisions of the Merger order
(see Note 3), the Company is precluded from recovering the $12 million annual
amortization in rates until the next rate filing. Therefore the Company's
earnings will be impacted negatively until these income taxes are recovered in
future rates.
1992 COMPARED TO 1991: Operating expenses increased significantly for
1992 as a result of the Merger. KG&E operating expenses for the nine months
ended December 31, 1992, of $316 million have been included in the Company's
operating expenses.
Other factors, excluding the Merger, contributing to increased operating
expenses were a one-time charge for the Company's portion of the early
retirement plan and voluntary separation program of approximately $11 million;
higher depreciation and amortization expense caused by increased plant
investment and the beginning of the amortization of previously deferred
safety-related expenditures in Kansas; and increased property taxes due to
increases in plant and tax mill levies.
Partially offsetting those increases in operating expenses was the
commencement of savings as a result of the Merger. The Company also changed
the depreciable life of Jeffrey Energy Center, for book purposes, to 40 years,
resulting in a reduction to depreciation expense of approximately $5.4 million
annually. Lower natural gas purchases as a result of the mild temperatures and
a reduced unit cost also partially offset the increase in operating expenses.
As permitted under the La Cygne 2 generating station lease agreement, KG&E
requested the Trustee Lessor to refinance $341,127,000 of secured facility
bonds of the Trustee and owner of La Cygne 2. The transaction was requested
to reduce the Company's recurring future net lease expense. To accomplish
this transaction, a one-time payment of approximately $27 million was made
which will be amortized over the remaining life of the lease and will be
included in operating expense as part of the future lower lease expense. On
September 29, 1992, the Trustee Lessor refinanced bonds with a coupon rate of
approximately 11.7% with bonds having a coupon rate of approximately 7.7%.
Other Income and Deductions: Other income and deductions, net of taxes,
increased $1.3 million in 1993 compared to 1992. KG&E other income and
deductions, net of taxes, of $19 million have been included in the Company's
total for 1993 compared to $17 million in 1992 from April 1, through December
31, 1992. Income from KG&E's COLI totalled $8 million in 1993.
Other income and deductions, net of taxes, was significantly higher in
1992 compared to 1991 as a result of the Merger. KG&E contributed, for the
nine months ended December 31, 1992, $17 million to other income and
deductions, net of taxes. Significant items of other income include
approximately $9 million from KG&E's COLI and KG&E's recognition of the
recovery of approximately $4.2 million of a previously written-off investment
in commercial paper.
Interest Charges and Preferred and Preference Dividend Requirements:
Interest charges for 1993 were higher as a result of the Merger. KG&E
interest charges of $59 million for 1993 have been included in the Company's
total interest charges compared to $53 million for the nine months ended
December 31, 1992. The full twelve month effect of interest on debt to
acquire KG&E also contributed to the increase in total interest charges. The
increased interest charges have been partially offset through lower debt
balances and reduced interest charges from refinancing higher cost long-term
debt and lower interest rates on variable-rate debt. The Company's embedded
cost of long-term debt decreased to 7.7% at December 31, 1993, compared to
7.9% and 8.6% at December 31, 1992 and 1991, respectively, primarily as a
result of the refinancing of higher cost debt.
Total interest charges increased significantly for 1992 compared to 1991
as a result of the Merger. Partially offsetting this increase were lower
short-term and long-term interest rates.
Preferred and preference dividend requirements increased six percent in
1993 and significantly in 1992 compared to 1991 as a result of the issuance of
$50 million of 7.58% preference stock in the second quarter of 1992.
Merger Implementation: In accordance with the KCC Merger order,
amortization of the acquisition adjustment will commence August 1995. The
amortization will amount to approximately $19.6 million per year for 40 years.
The Company can recover the amortization of the acquisition adjustment through
cost savings under a sharing mechanism approved by the KCC as described in
Note 3 of the Notes to the Consolidated Financial Statements. While the
Company has achieved savings from the Merger, there is no assurance that the
savings achieved will be sufficient to, or the cost savings sharing mechanism
will operate as to fully offset the amortization of the acquisition
adjustment.
In 1992 the Company completed the consolidation of certain operations of
the Company and KG&E. In conjunction with these efforts the Company incurred
costs of consolidating facilities, transferring certain employees, and other
costs associated with completing the Merger. Certain of these costs related
to KG&E have been considered in purchase accounting for the Merger. Other
costs, including costs of the early retirement incentive programs and other
employee severance compensation programs for former Kansas Power and Light
Company employees were charged to expense in 1992. See Note 6 of Notes to
Consolidated Financial Statements for a discussion regarding the early
retirement and Merger severance plans.
OTHER INFORMATION
Inflation: Under the ratemaking procedures prescribed by the regulatory
commissions to which the Company is subject, only the original cost of plant
is recoverable in revenues as depreciation. Therefore, because of inflation,
present and future depreciation provisions are inadequate for purposes of
maintaining the purchasing power invested by common shareholders and the
related cash flows are inadequate for replacing property. The impact of this
ratemaking process on common shareholders is mitigated to the extent
depreciable property is financed with debt that can be repaid with dollars of
less purchasing power. While the Company has experienced relatively low
inflation in the recent past, the cumulative effect of inflation on operating
costs requires the Company to seek regulatory rate relief to recover these
higher costs.
FERC Order No. 636: On April 8, 1992, the FERC issued Order No. 636 which
the FERC intended to complete the deregulation of natural gas production and
facilitate competition in the gas transportation industry. Order No. 636 is
expected to affect the Company in several ways. The rules provide greater
protection for pipeline companies by providing for recovery of all fixed costs
through contracts with local distribution companies and other customers
choosing to transport gas on a firm (non-interruptible) basis. The order also
separates the purchase of natural gas from the transportation and storage of
natural gas, shifting additional responsibility to distribution companies for
the provision (through purchase and/or storage) of long-term gas supply and
transportation to distribution points. Under the new rules, distribution
companies elect the amount and type of services taken from pipelines. The
Company may be liable to one or more of its pipeline suppliers for costs
related to the transition from its traditional sales service to the
restructured services required by Order No. 636. The Company believes
substantially all of these costs will be recovered from its customers and any
additional transition costs will be immaterial to the Company's financial
position or results of operations.
The Company was an active participant in pipeline restructuring
negotiations and does not anticipate any material difficulty in obtaining the
pipeline services the Company needs to meet the requirements of its gas
operations.
Environmental: The Company has recognized the importance of environmental
responsibility and has taken a proactive position with respect to the
potential environmental liability associated with former manufactured gas
sites. The Company has an agreement with the Kansas Department of Health and
Environment to systematically evaluate these sites in Kansas (see Note 4).
The Company currently has no Phase I affected units under the Clean Air
Act of 1990. Until such time that additional regulations become final the
Company will be unable to determine its compliance options or related
compliance costs (see Note 4).
Energy Policy Act: The 1992 Energy Policy Act (Act) requires increased
efficiency of energy usage and will potentially change the way electricity is
marketed. The Act also provides for increased competition in the wholesale
electric market by permitting the FERC to order third party access to
utilities' transmission systems and by liberalizing the rules for ownership of
generating facilities. As part of the Merger, the Company agreed to open
access to its transmission system. Another part of the Act requires a special
assessment to be collected from utilities for a uranium enrichment,
decontamination, and decommissioning fund. KG&E's portion of the assessment
for Wolf Creek is approximately $7 million, payable over 15 years. Management
expects such costs to be recovered through the ratemaking process.
Statement of Financial Accounting Standards No. 106 (SFAS 106) and No. 112
(SFAS 112): For discussion regarding the effect of SFAS 106 and SFAS 112 on
the Company see Note 6 of Notes to the Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Independent Auditors' Report 33
Financial Statements:
Consolidated Balance Sheets, December 31, 1993 and 1992 34
Consolidated Statements of Income for the years ended
December 31, 1993, 1992 and 1991 35
Consolidated Statements of Cash Flows for the years ended
1993, 1992 and 1991 36
Consolidated Statements of Taxes for the years ended
December 31, 1993, 1992 and 1991 37
Consolidated Statements of Capitalization, December 31, 1993
and 1992 38
Consolidated Statements of Common Stock Equity for the years
ended December 31, 1993, 1992 and 1991 39
Notes to Consolidated Financial Statements 40
Financial Statement Schedules:
V- Utility Plant for the years ended December 31, 1993, 1992
and 1991 67
VI- Accumulated Depreciation of Utility Plant for the years
ended December 31, 1993, 1992 and 1991 70
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the conditions
under which they are required or the information is included in the
financial statements and schedules presented:
I, II, III, IV, VII, VIII, IX, X, XI, XII and XIII.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Western Resources, Inc.:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of Western Resources, Inc., and subsidiaries as
of December 31, 1993 and 1992, and the related consolidated statements of
income, cash flows, taxes and common stock equity for each of the three years
in the period ended December 31, 1993. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits. We did not
audit the financial statements of Kansas Gas and Electric Company, a wholly-
owned subsidiary of Western Resources, Inc., as of and for the year ended
December 31, 1992, which statements reflect assets and revenues of 61 percent
and 27 percent, respectively, of the consolidated totals for 1992. Those
statements were audited by other auditors whose report has been furnished to
us and our opinion, insofar as it relates to the amounts included for that
entity, is based solely on the report of other auditors.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits and the report of other
auditors provide a reasonable basis for our opinion.
In our opinion, based on our audit and the report of other auditors, the
financial statements referred to above present fairly, in all material
respects, the financial position of Western Resources, Inc., and subsidiaries
as of December 31, 1993 and 1992, and the results of their operations and
their cash flows for each of the three years in the period ended December 31,
1993, in conformity with generally accepted accounting principles.
As explained in Note 1 to the consolidated financial statements, effective
January 1, 1991, the Company changed to a preferred method of accounting for
revenue recognition. As explained in Note 12 to the consolidated financial
statements, effective January 1, 1992, the Company changed its method of
accounting for income taxes. As explained in Note 6 to the consolidated
financial statements, effective January 1, 1993, the Company changed its
method of accounting for postretirement benefits.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedules
listed in the table of contents on page 32 are the responsibility of the
Company's management and are presented for purposes of complying with the
Securities and Exchange Commission's rules and are not a part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion and the opinion of other auditors, fairly state in all material
respects the financial data required to be set forth therein in relation to
the basic financial statements taken as a whole.
Kansas City, Missouri, ARTHUR ANDERSEN & CO.
January 28, 1994
WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
December 31,
1993 1992
(Dollars in Thousands)
ASSETS
UTILITY PLANT (Notes 1 and 11):
Electric plant in service . . . . . . . . . . . . . . . . $5,110,617 $5,008,654
Natural gas plant in service. . . . . . . . . . . . . . . 1,111,866 1,024,369
6,222,483 6,033,023
Less - Accumulated depreciation . . . . . . . . . . . . . 1,821,710 1,691,623
4,400,773 4,341,400
Construction work in progress . . . . . . . . . . . . . . 80,192 68,041
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 29,271 33,312
Net utility plant. . . . . . . . . . . . . . . . . . . 4,510,236 4,442,753
OTHER PROPERTY AND INVESTMENTS:
Net non-utility investments . . . . . . . . . . . . . . . 61,497 47,680
Decommissioning trust (Note 4). . . . . . . . . . . . . . 13,204 9,272
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 10,658 13,855
85,359 70,807
CURRENT ASSETS:
Cash and cash equivalents (Note 1). . . . . . . . . . . . 1,217 875
Accounts receivable and unbilled revenues (net) (Note 1). 238,137 222,601
Fossil fuel, at average cost. . . . . . . . . . . . . . . 30,934 49,007
Gas stored underground, at average cost . . . . . . . . . 51,788 14,644
Materials and supplies, at average cost . . . . . . . . . 55,156 59,357
Prepayments and other current assets. . . . . . . . . . . 34,128 17,574
411,360 364,058
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 12). . . . . . . . . . 135,991 150,636
Deferred coal contract settlement costs (Note 5). . . . . 21,247 24,520
Phase-in revenues (Note 5). . . . . . . . . . . . . . . . 78,950 96,495
Corporate-owned life insurance (net) (Note 1) . . . . . . 4,743 146,713
Other deferred plant costs. . . . . . . . . . . . . . . . 32,008 32,212
Other (Note 5). . . . . . . . . . . . . . . . . . . . . . 132,154 110,712
405,093 561,288
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $5,412,048 $5,438,906
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statement). . . . . . . . . . . . . . . $3,121,021 $3,350,684
CURRENT LIABILITIES:
Short-term debt (Note 9). . . . . . . . . . . . . . . . . 440,895 222,225
Long-term debt due within one year (Note 8) . . . . . . . 3,204 1,961
Preference stock redeemable within one year (Note 14) . . - 1,300
Accounts payable. . . . . . . . . . . . . . . . . . . . . 172,338 215,507
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 46,076 38,591
Accrued interest and dividends. . . . . . . . . . . . . . 65,825 71,877
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 65,492 48,045
793,830 599,506
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Note 12) . . . . . . . . . . . . . 968,637 990,155
Deferred investment tax credits (Note 12) . . . . . . . . 150,289 149,946
Deferred gain from sale-leaseback (Note 10) . . . . . . . 261,981 271,621
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 116,290 76,994
1,497,197 1,488,716
COMMITMENTS AND CONTINGENCIES (Notes 4 and 15)
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . . . $5,412,048 $5,438,906
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
1993 1992(1) 1991
(Dollars in Thousands,
except Per Share Amounts)
OPERATING REVENUES (Notes 1 and 5):
Electric. . . . . . . . . . . . . . . . . . . . . . . $1,104,537 $ 882,885 $ 471,839
Natural gas . . . . . . . . . . . . . . . . . . . . . 804,822 673,363 690,339
Total operating revenues. . . . . . . . . . . . . . 1,909,359 1,556,248 1,162,178
OPERATING EXPENSES:
Fuel used for generation:
Fossil fuel . . . . . . . . . . . . . . . . . . . . 237,053 190,653 146,256
Nuclear fuel. . . . . . . . . . . . . . . . . . . . 13,275 10,126 -
Power purchased . . . . . . . . . . . . . . . . . . . 16,396 14,819 5,335
Natural gas purchases . . . . . . . . . . . . . . . . 500,189 403,326 439,323
Other operations. . . . . . . . . . . . . . . . . . . 349,160 296,642 193,319
Maintenance . . . . . . . . . . . . . . . . . . . . . 117,843 101,611 60,515
Depreciation and amortization . . . . . . . . . . . . 164,364 144,013 85,735
Amortization of phase-in revenues . . . . . . . . . . 17,545 13,158 -
Taxes (see statement):
Federal income. . . . . . . . . . . . . . . . . . . 62,420 34,905 24,516
State income. . . . . . . . . . . . . . . . . . . . 15,558 7,095 6,066
General . . . . . . . . . . . . . . . . . . . . . . 123,493 100,731 71,492
Total operating expenses. . . . . . . . . . . . . 1,617,296 1,317,079 1,032,557
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . 292,063 239,169 129,621
OTHER INCOME AND DEDUCTIONS (net of taxes). . . . . . . 25,482 24,186 3,351
INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 317,545 263,355 132,972
INTEREST CHARGES:
Long-term debt. . . . . . . . . . . . . . . . . . . . 123,551 117,464 51,267
Other . . . . . . . . . . . . . . . . . . . . . . . . 19,255 20,009 10,490
Allowance for borrowed funds used during
construction (credit) . . . . . . . . . . . . . . . (2,631) (2,002) (1,070)
Total interest charges. . . . . . . . . . . . . . 140,175 135,471 60,687
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE. . 177,370 127,884 72,285
Cumulative Effect to January 1, 1991, of Change in
Revenue Recognition (net of taxes) (Note 1) . . . . . - - 17,360
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . 177,370 127,884 89,645
PREFERRED AND PREFERENCE DIVIDENDS. . . . . . . . . . . 13,506 12,751 6,377
EARNINGS APPLICABLE TO COMMON STOCK . . . . . . . . . . $ 163,864 $ 115,133 $ 83,268
AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . 59,294,091 52,271,932 34,566,170
EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING
BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE . . . . $ 2.76 $ 2.20 $ 1.91
Cumulative Effect to January 1, 1991, of Change in
Revenue Recognition Per Share . . . . . . . . . . . . - - .50
EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING . . . . . $ 2.76 $ 2.20 $ 2.41
DIVIDENDS DECLARED PER COMMON SHARE . . . . . . . . . . $ 1.94 $ 1.90 $ 2.04(2)
(1) Information reflects the merger with KG&E on March 31, 1992 (Note 3).
(2) Includes special, one-time dividend of $0.18 per share paid February 28, 1991.
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1993 1992(1) 1991
(Dollars in Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 177,370 $ 127,884 $ 89,645
Depreciation and amortization . . . . . . . . . . . . . . 164,364 144,013 85,735
Other amortization (including nuclear fuel) . . . . . . . 11,254 8,930 -
Deferred taxes and investment tax credits (net) . . . . . 27,686 26,900 9,319
Amortization of phase-in revenues . . . . . . . . . . . . 17,545 13,158 -
Corporate-owned life insurance. . . . . . . . . . . . . . (21,650) (14,704) -
Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (7,231) -
Changes in other working capital items:
Accounts receivable and unbilled revenues (net)(Note 1) (15,536) (12,227) (72,879)
Fossil fuel . . . . . . . . . . . . . . . . . . . . . . 18,073 14,990 (522)
Gas stored underground. . . . . . . . . . . . . . . . . (37,144) 4,522 (2,340)
Accounts payable. . . . . . . . . . . . . . . . . . . . (43,169) (10,194) (3,125)
Accrued taxes . . . . . . . . . . . . . . . . . . . . . 7,485 (52,185) (14,130)
Other . . . . . . . . . . . . . . . . . . . . . . . . . (3,165) (19,433) 11,661
Changes in other assets and liabilities . . . . . . . . . (18,569) 21,508 31,992
Net cash flows from operating activities. . . . . . . 274,904 245,931 135,356
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant. . . . . . . . . . . . . . . . 237,631 202,493 125,675
Merger with KG&E. . . . . . . . . . . . . . . . . . . . . - 473,752 -
Utility investment. . . . . . . . . . . . . . . . . . . . 2,500 - -
Non-utility investments (net) . . . . . . . . . . . . . . 14,271 29,099 18,125
Corporate-owned life insurance policies . . . . . . . . . 27,268 20,233 -
Death proceeds of corporate-owned life insurance
policies. . . . . . . . . . . . . . . . . . . . . . . . (10,160) (6,789) -
Cash flows used in investing activities . . . . . . . . 271,510 718,788 143,800
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . 218,670 42,825 20,300
Bank term loan issued for Merger with KG&E. . . . . . . . - 480,000 -
Bank term loan retired. . . . . . . . . . . . . . . . . . (230,000) (250,000) -
Bonds issued. . . . . . . . . . . . . . . . . . . . . . . 223,500 485,000 -
Bonds retired . . . . . . . . . . . . . . . . . . . . . . (366,466) (236,966) (30,233)
Revolving credit agreements (net) . . . . . . . . . . . . (35,000) - -
Other long-term debt (net). . . . . . . . . . . . . . . . 7,043 14,498 -
Common stock issued (net) . . . . . . . . . . . . . . . . 125,991 - -
Preference stock issued (net) . . . . . . . . . . . . . . - 50,000 98,870
Preference stock redeemed . . . . . . . . . . . . . . . . (2,734) (2,600) (1,300)
Bank term loan issuance expenses. . . . . . . . . . . . . - (10,753) -
Borrowings against life insurance policies (net). . . . . 183,260 (5,649) -
Dividends on preferred, preference and common stock . . . (127,316) (99,440) (76,891)
Net cash flows from (used in) financing activities. . . (3,052) 466,915 10,746
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . 342 (5,942) 2,302
CASH AND CASH EQUIVALENTS:
BEGINNING OF THE PERIOD . . . . . . . . . . . . . . . . . 875 6,817 4,515
END OF THE PERIOD . . . . . . . . . . . . . . . . . . . . $ 1,217 $ 875 $ 6,817
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized). . . . . . . . . . . . . . . . . . . . . . $ 171,734 $ 128,505 $ 58,462
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 49,108 24,966 40,062
COMPONENTS OF MERGER WITH KG&E:
Assets acquired . . . . . . . . . . . . . . . . . . . . . $3,142,455
Liabilities assumed . . . . . . . . . . . . . . . . . . . (2,076,821)
Common stock issued . . . . . . . . . . . . . . . . . . . (589,920)
Cash paid . . . . . . . . . . . . . . . . . . . . . . . . 475,714
Less cash acquired. . . . . . . . . . . . . . . . . . . . (1,962)
Net cash paid . . . . . . . . . . . . . . . . . . . . . . $ 473,752
(1) Information reflects the merger with KG&E on March 31, 1992 (Note 3).
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF TAXES
Year Ended December 31,
1993 1992(1) 1991
(Dollars in Thousands)
FEDERAL INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . $ 41,200 $ 16,687 $ 18,479
Deferred taxes arising from:
Depreciation and other property related items . . . . . 25,552 25,163 9,662
Energy and purchased gas adjustment clauses . . . . . . (8,192) (4,180) (15,535)
Unbilled revenues . . . . . . . . . . . . . . . . . . . - 2,458 17,249
Natural gas line survey and replacement program . . . . 355 (1,106) 1,015
Other . . . . . . . . . . . . . . . . . . . . . . . . . 6,166 4,121 (1,109)
Amortization of investment tax credits. . . . . . . . . . (1,982) (4,918) (4,238)
Total Federal income taxes. . . . . . . . . . . . . . 63,099 38,225 25,523
Federal income taxes applicable to non-operating items. . (679) (3,320) (1,007)
Total Federal income taxes charged to operations. . . 62,420 34,905 24,516
STATE INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . 9,869 2,522 4,033
Deferred (net). . . . . . . . . . . . . . . . . . . . . . 5,787 5,352 2,276
Total state income taxes. . . . . . . . . . . . . . . 15,656 7,874 6,309
State income taxes applicable to non-operating items. . . (98) (779) (243)
Total state income taxes charged to operations. . . . 15,558 7,095 6,066
GENERAL TAXES:
Property and other taxes. . . . . . . . . . . . . . . . . 84,583 68,643 40,429
Franchise taxes . . . . . . . . . . . . . . . . . . . . . 22,878 19,583 20,576
Payroll taxes . . . . . . . . . . . . . . . . . . . . . . 16,032 12,505 10,566
Total general taxes . . . . . . . . . . . . . . . . . 123,493 100,731 71,571
General taxes applicable to non-operating items . . . . . - - (79)
Total general taxes charged to operations . . . . . . 123,493 100,731 71,492
TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . . . . $201,471 $142,731 $102,074
The effective income tax rates set forth below are computed by dividing total Federal and state
income taxes by the