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, 19931994
[ ] 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$1,906,866,000 of Common Stock and $11,545,000$10,335,000 of
Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which there
is no readily ascertainable market value) at March 11, 1994.23, 1995.
Indicate the number of shares outstanding of each of the registrant's classes of
common stock.
Common Stock, $5.00 par value 61,617,87361,760,853
(Class) (Outstanding at March 11, 1994)29, 1995)
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, 1994.2, 1995.
1
WESTERN RESOURCES, INC.
FORM 10-K
December 31, 19931994
TABLE OF CONTENTS
Description Page
PART I
Item 1. Business 3
Item 2. Properties 19
Item 3. Legal Proceedings 221
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 2223
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 2324
Item 8. Financial Statements and Supplementary Data 3233
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 6365
PART III
Item 10. Directors and Executive Officers of the
Registrant 6365
Item 11. Executive Compensation 6365
Item 12. Security Ownership of Certain Beneficial
Owners and Management 6365
Item 13. Certain Relationships and Related Transactions 6365
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 6466
Signatures 7170
2
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. (Astra Resources), Kansas Gas and Electric Company (KG&E)
since March 31, 1992, and KPL Funding Corporation (KFC), unless the context otherwise requires.and Mid Continent Market
Center, Inc. (Market Center). 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, 1993,1994, the Company had 5,1924,330
employees.
The Company conducts its non-regulated business through Astra Resources.
Astra Resources' non-regulated businesses include natural gas compression,
marketing, processing and gathering services, and investments in energy and
technology related businesses.
To capitalize on opportunities in the non-regulated natural gas industry,
the Company, through the Market Center, is establishing a natural gas market
center in Kansas. The Market Center will provide natural gas transportation,
storage, and gathering services, as well as balancing, and title transfer
capability. Upon approval from the
Kansas Corporation Commission (KCC), the Company intends
to transfer certain natural gas transmission assets having a value of
approximately $52.1 million to the Market Center. In addition, the Company
intends to extend credit to the Market Center enabling the Market Center to
borrow up to an aggregate principal amount of $25 million on a term basis to
construct new facilities and $5 million on a revolving credit basis for working
capital. The Market Center will provide no notice natural gas transportation
and storage services to the Company under a long-term contract.
The Company will continue to operate and maintain the Market Center's
assets under a separate contract.
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".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 werewas 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.
3
As a result of the sales of the Missouri Properties, as described in Note 2
of the Notes to Consolidated Financial Statements, the Company recognized a gain
of approximately $19.3 million, net of tax, ($0.31 per share) and ceased
recording the results of operations for the Missouri Properties during the first
quarter of 1994. Consequently, the Company's results of operations for the
twelve months ended December 31, 1994 are not comparable to the results of
operations for the same periods ending December 31, 1993 and 1992.
The following table reflects, through the dates of the sales of the
Missouri Properties, the approximate operating revenues and operating income
(unaudited)for the years ended December 31, 1994, 1993, and 1992, and net utility plant
at December 31, 1993 and 1992, related to the Missouri Properties approximated $350 million(see Notes 2
and $21 million representing
approximately 18 percent and seven percent, respectively,4 of the Company's
total forNotes to Consolidated Financial Statements included herein):
1994 1993 and $299 million and $11 million representing approximately 19
percent and five percent, respectively,1992
Percent Percent Percent
of the Company's total for 1992.Total of Total of Total
Amount Company Amount Company Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. .$ 77,008 4.8% $349,749 18.3% $299,202 19.2%
Operating income. . . 4,997 1.9% 20,748 7.1% 11,177 4.7%
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.. . - - 296,039 6.6% 272,126 6.1%
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,
1992.1992 and excludes the activities related to the Missouri Properties following
the sales of those properties in the first quarter of 1994.
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
1994 69% 31% 97% 3%
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%4
The difference between the percentage of electric operating revenues in
relation to
total operating revenues and the percentage of electric operating income to
total operating income as compared to the same percentages for natural gas
operations is due to the Company's level of investment in plant and its fuel
costs in each of these segments. The reduction in the percentages for the
natural gas operations in 1994 is due to the sales of the Missouri Properties.
The increase in the percentages for the electric operations in 1992 is due to
the Merger.
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)(Dollars in Thousands)
1994 $3,676,347 $496,753 $4,173,100
1993 $3,641,154 $759,619 $4,400,7733,641,154 759,619 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 regulatedFor discussion regarding competition in the electric utility industry and
the potential impact on 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 Item 7. Management's Discussion and
Analysis of Financial Condition and Notes 4 and 5Results 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.Operations, Other Information,
Competition.
ELECTRIC OPERATIONS
General.General
The Company supplies electric energy at retail to approximately 585,000594,000
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):
1994 1993 1992 1991 1990
1989
(Thousands of MWH)
Residential 5,003 4,960 3,842 2,556 2,403
2,248
Commercial 5,368 5,100 4,473 3,051 2,952
2,814
Industrial 5,410 5,301 4,419 1,947 1,954
1,925Wholesale and
Interchange 3,899 4,525 3,028 1,669 913
Other 4,628 3,119 1,984* 1,820 2,077106 103 91 315* 907
------ ------ ------ ----- -----
Total 19,786 19,989 15,853 9,538* 9,129 9,064
* Includes cumulative effect to January 1, 1991, of a change in revenue
recognition. The cumulative effect of this change increased electric
sales by 256,000 MWH.MWH for 1991.
5
The Company's electric revenues for the last five years were as follows
(includes KG&E since March 31, 1992):
1994 1993 1992 1991 1990
1989
(Thousands of Dollars)(Dollars in Thousands)
Residential $ 388,271 $ 384,618 $296,917 $160,831 $152,509
$142,308
Commercial 334,059 319,686 271,303 149,152 146,001
139,567
Industrial 265,838 261,898 211,593 78,138 79,225
78,267Wholesale and
Interchange 106,243 118,401 98,183 70,262 39,585
Other 138,335 103,072 83,718 85,972 92,20127,370 19,934 4,889 13,456 46,387
---------- ---------- -------- -------- --------
Total $1,121,781 $1,104,537 $882,885 $471,839 $463,707
$452,343
Capacity.Capacity
The accreditedaggregate net generating capacity of the Company's system is presently
5,1845,230 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 2,2. Properties).
The Company's 19931994 peak system net load occurred on August 16, 199325, 1994 and
amounted to 3,8213,720 MW. The Company's net generating capacity together with
power available from firm interchange and purchase contracts, provided a
capacity margin of approximately 2325 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.
The Company is one of 47 members of the Southwest Power Pool (SPP). SPP's
responsibility is to maintain system reliability on a regional basis. The
region encompasses areas within the eight states of Kansas, Missouri,
Oklahoma, New Mexico, Texas, Louisiana, Arkansas, and Mississippi.
In 1994, the Company joined the Western Systems Power Pool (WSPP). Under
this arrangement, over 50 electric utilities and marketers throughout the
western United States have agreed to market energy and to provide transmission
services. WSPP's intent is to increase the efficiency of the interconnected
power systems operations over and above existing operations. Services
available include short-term and long-term economy energy transactions, unit
commitment service, firm capacity and energy sales, energy exchanges, and
transmission service by intermediate systems.
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 (42 MW) and transmission charges
through the year 2013.
During 1994, KG&E entered into an agreement with Midwest Energy, Inc.
(MWE), whereby KG&E will provide MWE with peaking capacity of 61 MW through
6
the year 2008. KG&E also entered into an agreement with Empire District
Electric Company (Empire), whereby KG&E will provide Empire with peaking and
base load capacity (20 MW in 1994 increasing to 80 MW in 2000) through the
year 2000.
In January 1995, the Company entered into an agreement with Empire,
whereby the Company will provide Empire with peaking and base load capacity
(10 MW in 1995 increasing to 162 MW in 2000) through the year 2010. The
agreement is subject to regulatory approval and termination by Empire prior to
January 1, 1996, provided that Empire is required by the KCC or Missouri
Public Service Commission, pursuant to complaints filed by Ahlstrom
Development Corporation (Ahlstrom) before those agencies, to accept Ahlstrom's
offer to sell power to Empire from generating units to be constructed.
Future Capacity.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 Item 7. 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.Mix
The Company's coal-fired units comprise 3,1863,228 MW of the total 5,1845,230 MW of
generating capacity and the Company's nuclear unit provides 533545 MW of
capacity. Of the remaining 1,4651,457 MW of generating capacity, units that can
burn either natural gas or oil account for 1,3731,365 MW, and the remaining units
which burn only oil or diesel fuel account for 92 MW (see Item 2,2. Properties).
During 1993,1994, low sulfur coal was used to produce 7976 percent of the
Company's electricity. Nuclear produced 1718 percent and the remainder was
produced from natural gas, oil, or diesel. Baseddiesel fuel. During 1995, 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 nuclear will be used
to produce approximately 18 percent from
nuclear.
percent.
The Company anticipates theCompany's fuel mix to fluctuatefluctuates with the operation of nuclear powered
Wolf Creek which operates onhas an 18-month refueling and maintenance schedule. The 18-month18-
month schedule permits uninterrupted operation every third calendar year. Beginning March 5, 1993,In
mid-September 1994, Wolf Creek was taken off-
lineoff-line for its sixthseventh refueling
and maintenance outage. The refueling outage took approximately 7347 days to
complete, during which time electric demand was met primarily by the Company's
coal-fired generating units. Nuclear.There is no refueling outage scheduled for 1995.
Nuclear
The owners of Wolf Creek have on hand or under contract 7363 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.
7
Contractual arrangements are in place for 100 percent of Wolf Creek's
uranium enrichment requirements for 1993-1996, 701995-1997, 90 percent for 1997-19981998-1999, 95
percent for 2000-2001, and 100 percent for 2003-2014.2005-2014. The balance of the
1997-20021998-2004 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 19951996
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 along with the other co-owners of Wolf Creek are among 14
companies that filed a lawsuit on June 20, 1994, seeking an interpretation of
the DOE's obligation to begin accepting spent nuclear fuel for disposal in
1998. The DOE has filed a motion to have this case dismissed. The issue to
be decided in this case is whether DOE must begin accepting spent fuel in 1998
or at a future date.
Coal
The three coal-fired units at JEC have an aggregate capacity of 1,775 MW
(Company's 84 percent share) (see Item 2. Properties). 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 CambellCampbell 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.based on MMBtu provisions. The coal to be supplied is
surface mined and has an average BTUBtu content of approximately 8,300 BTUBtu per
pound and an average sulfur content of .43 lbs/mmBTUMMBtu (see Environmental
Matters). The average delivered cost of coal for JEC was approximately $1.045$1.13
per mmBTUMMBtu or $17.35$18.55 per ton during 1993.1994.
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 770890 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 firedcoal-fired units at La Cygne generating stationStation have an aggregate generating
capacity of 677678 MW (KG&E's 50 percent share) (see Item 2. Properties). The
operator, Kansas City Power & Light Company (KCP&L)(KCPL), maintains coal contracts
summarized in the following paragraphs.
During 1993,8
La Cygne 1 was converted to useuses low sulfur Powder River Basin coal which is supplied under
the AMAX contract for La Cygne 2,a variety of spot market transactions, 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 wasis supplied
through a contract that expired December 31, 1993, by AMAX from its mines in
Gillette, Wyoming.several contracts, expiring at various times through 1998. This low
sulfur coal had an average BTUBtu content of approximately 8,500 BTUBtu per pound
and a maximum sulfur content of .50 lbs/mmBTUMMBtu (see Environmental Matters).
For 1994, the operator hasKCPL secured Powder River Basin coal similar to the AMAX coal, from two primary 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&LKCPL 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/CNWA new five-year coal transportation agreement is
a supplemental access contractbeing negotiated to handle tonnages not covered by the Omnibus contract.provide transportation beyond 1995.
During 1993,1994, the average delivered cost of all coal procured for La Cygne
1 was approximately $0.81$0.78 per mmBTUMMBtu or $14.24$14.11 per ton and the average
delivered cost of Powder River Basin coal for La Cygne 2 was approximately
$0.84$0.73 per mmBTUMMBtu or $14.18$12.30 per ton.
The coal-fired units located at the Tecumseh and Lawrence Energy Centers
have an aggregate generating capacity of 768775 MW (see Item 2. Properties). The
Company contracted with ARCH Mineral Corporation (ARCH Mineral)Cyprus Amax Coal Company's Foidel Creek Mine located
in Routt County, Colorado 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).1998.
During 1993,1994, the average delivered cost of coal for the Lawrence units was
approximately $1.254$1.15 per mmBTUMMBtu or $29.13$25.59 per ton and the average delivered cost
of coal for the Tecumseh units was approximately $1.229$1.15 per mmBTUMMBtu or $26.19$25.64 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 beis transported under a new agreement withby Southern Pacific Lines and Atchison and
Topeka Santa Fe Railway Company. The coal supplied from Cyprus has an average
BTUBtu content of approximately 11,200 BTUBtu per pound and an average sulfur
content of .38 lbs/mmBTU.MMBtu (see Environmental Matters). 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.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 firedcoal-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 economicalAfter
1995, the Company expects to use the spot market purchases fromto purchase most of the Williams
Natural Gas (WNG) system provide the Company flexible
natural gas needed to meet
operational needs.fuel these generating stations. 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.9
Oil
The Company uses oil as an alternate fuel when economical or when
interruptions to natural 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, 1993,1994, the Company had approximately 43 million gallons of No. 2
and 14.714 million gallons of No. 6 oil which is believed to be 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.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)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 byimpact the Company.Company's earnings.
Set forth in the table below is information relating to the weighted
average cost of fuel used by the Company.
KPL Plants 1994 1993 1992 1991 1990
1989
Per Million BTU:Btu:
Coal $1.13 $1.13 $1.30 $1.33 $1.33
$1.31
Gas 2.66 2.71 2.15 1.72 1.50
2.10
Oil 4.27 4.41 4.19 4.25 4.63
3.92
Cents per KWH Generation 1.32 1.31 1.49 1.52 1.53
1.51
KG&E Plants 1994 1993 1992 1991 1990
1989
Per Million BTU:Btu:
Nuclear $0.36 $0.35 $0.34 $0.32 $0.34
$0.34
Coal 0.90 0.96 1.25 1.32 1.32
1.38
Gas 1.98 2.37 1.95 1.74 1.96
1.91
Oil 3.90 3.15 4.28 4.13 3.01
3.30
Cents per KWH Generation 0.89 0.93 0.98 1.09 1.01
0.96
Environmental Matters.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)oxides (NOx)) promulgated by the State of Kansas and the Environmental
Protection Agency (EPA).10
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 BTUBtu 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 BTUBtu of heat input and (2) an
opacity greater than 20 percent. Federal nitrogen oxidesNOx emission standards applicable to
these units prohibit the emission of more than 0.7 pounds of nitrogen oxidesNOx per million
BTUBtu 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(see Coal); (2) the particulate matter
standards through the use of electrostatic precipitators; and (3) the nitrogen
oxideNOx
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 BTUBtu 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 purchaseThere
is sufficient low sulfur coal under contract (see Coal) which willto allow compliance
with such limits at Lawrence, Tecumseh and La Cygne 1.1 for the life of the
contracts. 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 oxideoxides of NOx 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 installinginstalled
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. TheAlthough, the Company
currently has no Phase I affected units.
units, the owners have applied for an early
substitution permit to bring the co-owned La Cygne Station under the Phase I
regulations.
The nitrogen oxideNOx 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 oxideNOx regulations for Phase II units and Phase I
group 2 units are mandated in the Act to be promulgatedAct. The EPA's proposed NOx regulations
were ruled invalid by January 1, 1997. Although the Company has no Phase I units,U.S. Court of Appeals for the final nitrogen oxide regulations for Phase 1
group 1 may allow for early compliance for Phase II group 1 units. UntilDistrict of Columbia
Circuit in November, 1994 and until such time as the Phase I group 1 nitrogen oxideEPA resubmits new
proposed 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 47 of the Notes to Consolidated Financial Statements included herein.
11
NATURAL GAS OPERATIONS
General.General
At December 31, 1993,1994, the Company supplied natural gas at retail to
approximately 1,093,000643,000 customers in 519362 communities and at wholesale to eight
communities and two utilities in Kansas Missouri and Oklahoma. The natural gas systems
of the Company consistedconsist of distribution systems in all
threeboth states purchasing
natural gas from various suppliers and transported by 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 the 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 propertiesProperties to
United Cities on February 28, 1994. Additional information with respect to
the impact of the salesales of the Missouri Properties is set forth in Notes 2 and
134 of the Notes to Consolidated Financial Statements.
The percentage of total natural gas deliveries, including transportation
and operating revenues for 19931994, by state were as follows:
Total Natural Total Natural Gas
Gas DeliveriesDeliveries(1) Operating RevenuesRevenues(1)
Kansas 54.6% 53.9%84.1% 80.5%
Missouri 43.0% 43.5%12.4% 15.5%
Oklahoma 2.4% 2.6%3.5% 4.0%
The Company's natural gas deliveries for the last five years were as
follows:
1994(1) 1993 1992 1991 1990
1989
(Thousands of MCF)
Residential 64,804 110,045 93,779 97,297 95,247
104,057
Commercial 26,526 47,536 40,556 47,075 43,973
47,339
Industrial 605 1,490 2,214 2,655 3,207
5,637
Other 43 41 94 14,960*14,960(2) 1,361
1,403
Transportation 51,059 73,574 68,425 78,055 72,623
58,025------- ------- ------- ------- -------
Total 143,037 232,686 205,068 240,042*240,042(2) 216,411
216,461
*12
The Company's natural gas revenues for the last five years were as
follows:
1994(1) 1993 1992 1991 1990
(Dollars in Thousands)
Residential $332,348 $529,260 $440,239 $433,871 $439,956
Commercial 125,570 209,344 169,470 182,486 176,279
Industrial 3,472 7,294 7,804 10,546 12,994
Other 11,544 30,143 27,457 33,434 31,323
Transportation 23,228 28,781 28,393 30,002 25,496
-------- -------- -------- -------- --------
Total $496,162 $804,822 $673,363 $690,339 $686,048
(1) Information reflects the sales of the Missouri Properties effective
January 31, and February 28, 1994.
(2) Includes cumulative effect to January 1, 1991, of a change in revenue
recognition. The cumulative effect of this change increased natural
gas sales by 14,838,000 MCF.
The Company's natural gas revenuesMCF 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 $675,2801991.
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, theSystem
The Company purchaseddistributes natural gas from interstate pipelines, producers, and marketers to distribute at retail to approximately 966,000513,000
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 largerlargest cities which were served in 1993 are
St. Joseph and Joplin, Missouri;1994 were Wichita and Topeka, Kansas;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 implementationpurchases all the natural gas it delivers
to these customers direct from producers and marketers 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.natural gas. 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, a non-affiliated pipeline
transmission company, 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 marketersyears for delivery of naturalthis gas. WNG transported 33.551.6 BCF under these
agreements in 1994 and 33.5 BCF in 1993.
The Company haspurchases this gas purchasefrom various suppliers under 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 77.852.2 BCF or
52.9 percent89.3% of its natural gas supply from these sources in 19931994 and 63.977.8 BCF or
52.3
percent52.9% during 1992.1993. Approximately 94.486.3 BCF of natural gas is made available
annually under these contracts.contracts with approximately 76.0 BCF available under
contracts which extend beyond the year 2000. The Company has limited rights
to substitute spot gas for this gas under contract. Other sources ofIn October 1994, the
Company executed a long-term gas purchase contract (Base Contract) and a
peaking supply contract with Amoco Production Company for the purpose of
meeting the requirements of the customers served from the Company's distribution systemsinterstate
pipeline system. The Company anticipates that the Base Contract will supply
between 45% and 60% of the Company's demand served by the WNG pipeline system.
The Company also purchases natural gas for the interstate system from
intrastate pipelines and spot market suppliers under short-term contracts.
These sources totalled 3.8 BCF and 5.2 BCF for 1994 and 1993 representing 6.5%
and 3.5% of the system requirements, respectively. These volumes were
transported by Panhandle Eastern Pipeline Company (Panhandle), Northern
Natural Gas Company, and Natural Gas Pipeline Company of America, intrastate pipelines,America.
13
During 1994 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 7.18.0 BCF and 8.27.1 BCF, respectively,
were transferred from the Company's main system to serve a portion of Wichita,
Kansas. These system transfers represent 4.9 percent13.7% and 6.7 percent,4.9%, 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)
1994 1993 1992 1991 1990
1989
WNG $ - $3.57 $3.64 $3.61 $3.84
$3.23
Other 3.32 3.01 2.30 2.36 2.14
2.29
Total Average Cost 3.32 3.23 2.88 3.02 3.10 2.91
The increase in the total average cost per MCF in 19931994 from 19921993 reflects
increased prices in the spot market.market and increased transportation costs.
Main System.System
The Company serves approximately 127,000130,000 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,Hutchinson, 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.
As discussed under GENERAL, the Company is developing the Market Center
and intends to transfer certain natural gas transmission assets having a value
of approximately $52.1 million to the Market Center. Natural gas purchased
for the Company's main system customer requirements will be transported and/or
stored by the Market Center upon approval from the KCC. The Company retains a
priority right to capacity on the Market Center necessary to serve the main
system customers. The Company will have the opportunity to negotiate for the
purchase of natural gas with producers or marketers utilizing Market Center
services, which will increase the potential supply available to meet main
system customer demands.
During 19931994, the Company purchased approximately 17.1 BCF of natural gas
from Mesa Operating Limited Partnership (Mesa). This compares with
approximately 15.6 BCF of natural gas (including 2.5 BCF of make-up
deliveries) from Mesa 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 percent62.7% and 55.2 percent,53.7%,
respectively, of the Company's main system requirements during such periods.
Pursuant to the Hugoton Contract, the Company expects to purchase
approximately 16.89 BCF of natural gas constituting approximately 56.4 percent37% of the
Company's main system requirements during 1994.through May 31, 1995.
The Company has issued a request for proposal for natural gas contracts
ranging from one to five years, to replace the gas previously purchased under
the expiring Mesa dedicated its
entire deliverabilitycontract. The Company has received interest in serving this
14
supply requirement from multiple producers and marketers and believes it will
be able to replace the contract area to the Company. However, if the
Company is unable to take 100% of such deliverability, such non-takesrequirements previously served 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.contract
with adequate supplies at market based prices.
Spivey-Grabs field in south-central Kansas supplied approximately 4.8 and
5.4 BCF
of natural gas in both 1994 and 1993, constituting 17.6% and 1992, constituting 16.6 percent and 20.9
percent,16.6%,
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 5.25 BCF or 17% of natural gas
in 1994.1995.
Other sources of gas for the main system of 4.42.9 BCF or 15.2 percent10.5% of the system
requirements were purchased from or transported through interstate pipelines
during 1993.1994. The remainder of the supply for the main system during 1994 and
1993 of 2.5 BCF and 1992 of 4.2 and 4.0 BCF representing 14.5 percent9.2% and 15.4 percent,14.5%, respectively, was
purchased directly from producers or gathering systems.
During 1994 and 1993, approximately 8.0 BCF 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 Company believes there is adequate natural gas available under
contract or otherwise available to meet the currently anticipated needs of the
main system customers.
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)
1994 1993 1992 1991 1990
1989
Mesa-Hugoton Contract $1.81 $1.78(1) $1.47(2) $1.36(3) $1.47(4)
$1.35
Other 2.92 2.69 2.66 2.68 2.54
2.63
Total Average Cost 2.23 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 owns and
operates and has developed
the Brehmunder contract 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.
facilities (see Item 2.
Properties).
Environmental Matters.Matters
For information with respect to Environmental Matters see Note 47 of Notes
to Consolidated Financial Statements included herein.15
SEGMENT INFORMATION
Financial information with respect to business segments asis set forth in
Note 1314 of the 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%ten percent 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, 1993,1994, approximately
$457$356 million principal amount of additional first mortgage bonds could be
issued (7.5 percent(8.75% 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, 1993,1994, the Company had approximately $148$499 million of net bondable
property additions not subject to an unfunded prior lien entitling the Company
to issue up to $89$299 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 KG&E 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%ten percent of the principal amount of, all
KG&E first mortgage bonds outstanding after giving effect to the proposed
issuance. Based on KG&E's results for the 12 months ended December 31, 1993,1994,
approximately $1 billion$743 million principal amount of additional KG&E first mortgage
bonds could be issued (7.5 percent(8.75% 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,
1993,1994, 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$909
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
andplus dividend requirements on preferred stock after giving effect to the
proposed issuance. After giving effect to the annual interest and dividend
16
requirements on all debt and preferred stock outstanding at December 31, 1993,1994,
such ratio was 1.942.17 for the 12 months ended December 31, 1993.1994.
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), and 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, 1993,1994, the Company had 5,1924,330 employees. The Company did
not experience any strikes or work stoppages during 1993.1994. The Company's
current contracts with its two electric unions were negotiated in 1993 and
expire June 30, 1995. The two contracts cover approximately 2,0002,130 employees.
The Company has contracts with 5three other unions representing approximately
1,450640 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.17
EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During Past Five Years
John E. Hayes, Jr. 5657 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 5455 President and Chief President and Chief Operating Officer-
Executive Officer KPLOfficer-KPL KPL Division (1990)
(since October 1990) Executive Vice President and Chief
Operating Officer (1987 to 1990)
Acting President (1989)
James S. Haines, Jr. 4748 Executive Vice President Group Vice President (1985 to 1992)President-KG&E
and Chief Administrative KG&E, Wichita, Kansas
Officer (since March 1992)
Steven L. Kitchen 4849 Executive Vice President Senior Vice President, Finance
and Chief Financial and Accounting
(1987 to 1990)
Officer (since March 1990)
John K. Rosenberg 4849 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. 4041 Executive Vice President Vice President, Corporate
Vice President,Corporate Communications, Marketing, and Economic Communications,Development
Marketing, Development (1992)
and Economic (1992 to 1994)
Development Director, Economic Development, (1985
(since September 1992)January, 1995) 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 4849 President and Chief Group Vice President (1982 to 1992)President-KG&E
Executive Officer KGOfficer-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 4849 Controller
(since February
1985)
(1) Mr. Johnson leftExecutive officers serve at the Company on January 31, 1994.
The present termpleasure 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
electedappointed as an officer.
18
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).Oklahoma.
During the five years ended December 31, 1993,1994, the Company's gross
property additions totalled $852,650,000$923,801,000 and retirements were $125,287,000.$176,678,000.
ELECTRIC FACILITIES
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (2)
Abilene Energy Center:
Combustion Turbine 1 1973 Gas 6765
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 2017
3 1951 Gas 3128
4 1965 Gas 196
Combustion Turbines 1 1974 Gas 5351
2 1974 Gas 5149
3 1974 Gas 5554
4 1975 Oil 89
Jeffrey Energy Center (84%):
Steam Turbines 1 1978 Coal 587
2 1980 Coal 566600
3 1983 Coal 588
La Cygne Station (50%):
Steam Turbines 1 1973 Coal 342343
2 1977 Coal 335
Lawrence Energy Center:
Steam Turbines 2 1952 Gas 0 (1)
3 1954 Coal 56
4 1960 Coal 102113
5 1971 Coal 380370
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 46
2 1954 Gas--Oil 6974
3 1956 Gas--Oil 107
4 1959 Gas--Oil 105
Neosho Energy Center:
Steam Turbines 3 1954 Gas--Oil 0 (1)
19
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (2)
Neosho Energy Center:
Steam Turbines 3 1954 Gas--Oil 0 (1)
Tecumseh Energy Center:
Steam Turbines 7 1957 Coal 8388
8 1962 Coal 147148
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 533545
-----
Total 5,1845,230
(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, 1993,1994, 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 F60F
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
20
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 16,9306,230 MCF per
day from this field to meet 19931994 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 6,28052,700 MCF per
day from this field to meet 19931994 winter peaking requirements.
The Company has contracted with Williams Natural Gas CompanyWNG 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
InformationIn March, 1995, the litigation between the Company and the Bishop Group,
Ltd., and other entities affiliated with the Bishop Group, raising breach of
certain gas supply contracts as set forth in Note 4 of the Notes to
Consolidated Financial Statements, was settled with the realignment of the
commercial relationship between the parties. The resolution of this matter is
not expected to have a material adverse impact on the Company.
Additional information on legal proceedings involving the Company is set
forth in Note 154 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.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,
1994,1, 1995, there 45,317were
43,454 common shareholders of record. For information regarding quarterly
common stock price ranges for 19931994 and 1992,1993, see Note 16 of Notes to
Consolidated Financial Statements included herein.
21
Dividend Policy.Policy
Western Resources common stock is entitled to dividends when and as
declared by the Board of Directors. At December 31, 1993,1994, 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. Dividends increased
four cents per common share in 1994 to $1.98 per share. In January 1995, the
Board of Directors declared a quarterly dividend of 50 1/2 cents per common
share, an increase of one cent over the previous quarter. Based on currently
projected operating results, the Company does not anticipate a material change
in its dividend policy or payout ratio (approximately 70 percent in 1994) in
1995. Future dividends depend upon future earnings, the financial condition
of the Company and other factors. For information regarding quarterly
dividend declarations for 19931994 and 1992,1993, see Note 16 of Notes to Consolidated
Financial Statements included herein.
22
ITEM 6. SELECTED FINANCIAL DATA
Year Ended December 31, 1994(1) 1993 1992(1)1992(2) 1991 1990 1989
(Dollars in Thousands)
Income Statement Data:
Operating revenues:
Electric . . . . . . . . . . . $1,121,781 $1,104,537 $ 882,885 $ 471,839 $ 463,707 $ 452,343
Natural gas. . . . . . . . . . 496,162 804,822 673,363 690,339 686,048
675,280---------- ---------- ---------- ---------- ----------
Total operating revenues . . 1,617,943 1,909,359 1,556,248 1,162,178 1,149,755 1,127,623
Operating expenses . . . . . . . 1,348,397 1,617,296 1,317,079 1,032,557 1,017,765 1,002,087
Allowance for funds used during
construction . . . . . . . . . 2,667 2,631 2,002 1,070 1,181 1,503
Income before cumulative effect
of accounting change . . . . . 187,447 177,370 127,884 72,285 79,619 72,778
Cumulative effect to January 1,
1991, of change in revenue
recognition. . . . . . . . . . - - - 17,360 -
----------- ---------- ---------- ---------- ----------
Net income . . . . . . . . . . . 187,447 177,370 127,884 89,645 79,619 72,778
Earnings applicable to common
stock. . . . . . . . . . . . . 174,029 163,864 115,133 83,268 77,875
70,921
December 31, 1994(1) 1993 1992(1)1992(2) 1991 1990 1989
(Dollars in Thousands)
Balance Sheet Data:
Gross plant in service . . . . . $5,963,366 $6,222,483 $6,033,023 $2,535,448 $2,421,562 $2,305,279
Construction work in progress. . 85,290 80,192 68,041 17,114 20,201 19,571
Total assets . . . . . . . . . . 5,189,618 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 . . . . . . . . . . 1,507,028 1,673,988 2,077,459 690,612 595,524
552,538
Year Ended December 31, 1994(1) 1993 1992(1)1992(2) 1991 1990 1989
Common Stock Data:
Earnings per share before
cumulative effect of
accounting change. . . . . . . $ 2.82 $ 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 . . . . . . . $ 2.82 $ 2.76 $ 2.20 $ 2.41 $ 2.25 $ 2.05
Dividends per share. . . . . . . $ 1.98 $ 1.94 $ 1.90 $ 2.04(2)2.04(3) $ 1.80 $ 1.76
Book value per share . . . . . . $23.93 $23.08 $21.51 $18.59 $18.25
$17.80
Average shares outstanding(000's) 61,618 59,294 52,272 34,566 34,566 34,566
Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 3.42 2.79 2.27 2.69 2.86
2.96Ratio of Earnings to Fixed
Charges. . . . . . . . . . . . 2.65 2.36 2.02 2.98 2.74
Ratio of Earnings to Combined
Fixed Charges and Preferred
and Preference Dividend
Requirements . . . . . . . . . 2.37 2.14 1.84 2.61 2.64
(1) Information reflects the sales of the Missouri Properties (Note 2).
(2) Information reflects the merger with KG&E on March 31, 1992 (Note 3).
(2)(3) Includes special, one-time dividend of $0.18 per share paid February 28, 1991.
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION
General:GENERAL: Earnings were $2.76$2.82 per share of common stock based on
59,294,09161,617,873 average common shares for 1993,1994, an increase from $2.20$2.76 in 19921993 on
52,271,93259,294,091 average common shares. Net income for 1994 increased to $187.4
million compared to $177.4 million in 1993. The increase resulted fromin net income and
earnings per share is a return to near
normal temperatures compared to unusually mild winterresult of the gain on the sale of the Company's
natural gas distribution properties and summer temperaturesoperations in 1992,the State of Missouri,
reduced interest costs,expense, and the full twelve month effect of the
mergerhigher electric sales combined with Kansas Gas and Electric Company (KG&E) on March 31, 1992 (the
Merger).lower fuel
costs.
Dividends increased four cents per common share were $1.94 in 1993, an increase of four cents
from 1992.1994 to $1.98 per
share. In January 1994,1995, the Board of Directors declared a quarterly dividend
of 4950 1/2 cents per common share, an increase of one cent over the previous
quarter. Based on currently projected operating results, the Company does not
anticipate a material change in its dividend policy or payout ratio
(approximately 70 percent in 1994) in 1995.
The book value per share was $23.93 at December 31, 1994, compared to
$23.08 at December 31, 1993, compared to
$21.51 at December 31, 1992.1993. The increase in book value is primarily the
result of the issuance of additional common stock and an increase in retained
earnings. The 19931994 closing stock price of $34 7/$28 5/8 was 151120
percent of book value. There were 61,617,873 common shares outstanding at
December 31, 1993.1994.
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.
As a result of the sales of the Missouri Properties, as described in Note
2 of the Notes to Consolidated Financial Statements, the Company recognized a
gain of approximately $19.3 million, net of tax, ($0.31 per share) and ceased
recording the results of operations for the Missouri Properties during the
first quarter of 1994. Consequently, the Company's results of operations for
the twelve months ended December 31, 1994 are not comparable to the results of
operations for the same periods ending December 31, 1993 and 1992.
24
The following table reflects, through the dates of the sales of the
Missouri Properties, the approximate operating revenues and operating income
(unaudited)for the years ended December 31, 1994, 1993, and 1992, and net utility plant
at December 31, 1993 and 1992, related to the Missouri Properties approximated $350 million and $21 million representing
approximately 18 percent and seven percent, respectively,(see Note
2):
1994 1993 1992
Percent Percent Percent
of the Company's
total for 1993, and $299 million and $11 million representing approximately 19
percent and five percent, respectively,Total of the Company's total for 1992.Total of
Total
Amount Company Amount Company Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. .$ 77,008 4.8% $349,749 18.3% $299,202 19.2%
Operating income. . . 4,997 1.9% 20,748 7.1% 11,177 4.7%
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.. . - - 296,039 6.6% 272,126 6.1%
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.
LiquidityFor additional information regarding the sales of the Missouri Properties
and Capital Resources:the pending litigation see Notes 2 and 4 of the Notes to Consolidated
Financial Statements.
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 1993,1994, construction expenditures for the Company's electric system
were approximately $138$152 million and nuclear fuel expenditures were
approximately $6$21 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$65 million during 1993, of which construction
expenditures for the Missouri Properties were approximately $39 million.1994.
Capital expenditures for 1994 to 19961995 through 1997 are anticipated to be as
follows:
Electric Nuclear Fuel Natural Gas
(Dollars in Thousands)
1994 $131,4831995. . . . . $131,300 $ 20,99521,400 $ 64,608
1995 143,391 21,469 69,482
1996 151,100 9,890 68,74745,700
1996. . . . . 114,500 8,100 58,700
1997. . . . . 108,500 24,000 58,100
These expenditures are estimates prepared for planning purposes and are
subject to revisions from time to time (see Note 4)7).
The Company's net cash flowflows to capital expenditures was 10097 percent for
19931994 and during the last five years has averaged 8798 percent. The Company
anticipates all of its cash requirements for capital expenditures through 1997
will be provided from net cash flow to capital expenditures to be approximately 100
percent in 1994.flows.
25
The Company's capital needs through 1998 are approximately $33.6 million1999 for bond maturities and cash
sinking fund requirements for bonds and preference stock.stock are approximately
$156 million. 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%7.6% at December 31, 1993,1994, a
decrease from 7.9%8.1% at December 31, 1992.1993. 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, 1993,1994,
short-term borrowings amounted to $441$308.2 million, of which $126$157.2 million was
commercial paper (see Notes 86 and 9)11).
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, 1993,1994, the Company had
$200 millionbank credit arrangements available of First Mortgage Bonds
available to be issued under a shelf registration filed August 24, 1993. Also$145 million.
The Company's short-term debt balance at December 31, 1993, KG&E had $1501994, decreased
approximately $132.7 million from December 31, 1993. The decrease is
primarily a result of First Mortgage Bonds available
to be issued under a shelf registration filedthe use of the proceeds from the sales of the Missouri
Properties and the issuance, on August 24, 1993. On January 20, 1994, KG&E issuedof $100 million of First Mortgage Bonds,Kansas
Gas and Electric Company (KG&E) first mortgage bonds, 6.20% Series due January
15, 2006, under2006.
In January 1994, the KG&E shelf registration. The net proceeds were
usedCompany entered into an agreement with Oklahoma
Municipal Power Authority (OMPA). Under the agreement, the Company received a
prepayment of approximately $41 million for which the Company will provide
capacity and transmission services to reduce short-term debt.OMPA through the year 2013.
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.
On February 17, 1994, KG&E hasrefinanced the City of La Cygne, Kansas, 5 3/4%
Pollution Control Revenue Refunding Bonds Series 1973, $13,980,000 principal
amount, with 5.10% Pollution Control Revenue Refunding Bonds Series 1994,
$13,982,500 principal amount, due 2023.
On March 4, 1994, the Company retired the following First Mortgage Bonds:
$19 million of 7 5/8% Series due April 1, 1999, $30 million of 8 1/8% Series
due June 1, 2007, and $50 million of 8 5/8% Series due March 1, 2017.
On April 28, 1994, two series of Market-Adjusted Tax Exempt Securities
(MATES) totalling $75.5 million were sold on behalf of the Company and three
series of MATES totalling $46.4 million were sold on behalf of KG&E. The rate
on these bonds was 2.95% for the initial auction period. The interest rates
are being reset periodically via an auction process. As of December 31, 1994,
the rates on these bonds ranged from 3.94% to 4.10%. The net proceeds from
the new issues, together with available cash, were used to refund five series
of pollution control bonds totalling $121.9 million bearing interest rates
between 5 7/8% and 6.8%.
On October 5, the Company extended the term of its $350 million revolving
credit facility which will now expire on October 5, 1999.
On November 1, 1994, KG&E terminated a long-term agreement that expires in 1995 which containscontained
provisions for the sale of accounts receivable and unbilled revenues, (receivables) and
phase-in revenues up to(see Note 11).
26
The Company has 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 issuanceCustomer Stock Purchase Plan (CSPP) 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 thea 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 CSPP and
DRIP may be 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.
TheCompany's capital structure at December 31, 1993,1994, was 4549 percent
common stock equity, 6 percent preferred and preference stock, and 4945 percent
long-term debt. The capital structure at December 31, 1993,1994, including
short-term debt and current maturities of long-term debt, and preference stock, was 4045 percent
common stock equity, 5 percent preferred and preference stock, and 5550 percent
debt. As of December 31, 1994, the Company's bonds were rated "A3" by Moody's
Investors Service, "A-" by Standard & Poor's Ratings Group, and "A-" by Fitch
Investors Service.
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 Mergermerger on
March 31, 1992.1992, and exclude the activities related to the Missouri Properties
following the sales of those properties in the first quarter of 1994.
For additional information regarding the sales of the Missouri Properties
and the pending litigation, see Notes 2 and 4 of the Notes to Consolidated
Financial Statements. Additional information relating to changes between
years is provided in the Notes to Consolidated Financial Statements.
Revenues:REVENUES
The operating revenues of the Company are based on sales volumes and rates
authorized by certain state regulatory commissions and the FERC,Federal Energy
Regulatory Commission (FERC). Rates, charged for the sale and delivery of
natural gas and electricity. Rateselectricity, 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, competition from other generating
sources, competing fuel sources, customer conservation efforts, and the
overall economy of the Company's service area.
The Kansas Corporation Commission (KCC) order approving the Mergermerger with
KG&E on March 31, 1992 (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 refundRefunds of $8.5 million waswere
made in April 1992.
A refund of the same amount was made in1992 and December 1993 and an additionalthe remaining refund of $15 million
will bewas 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
27
1995. Any increase or decreasevariance in fuel costs from the projected average will be absorbed byimpact the
Company.
Company's earnings.
Future natural gas revenues will be reduced as a result of the salesales of
the Missouri Properties. The Consolidated Statements of Income include
revenues of $77 million for the portion of the first quarter of 1994 prior to
the sales of the Missouri Properties, by approximately $350 million annually based onfor 1993 and $299 million
for 1992. Following the sales of the Missouri Properties and during 1995 and
beyond, there will be no revenues recorded in 1993related to the Missouri Properties (see Note
2).
1994 Compared to 1993: Electric revenues increased two percent during
1994 primarily as a result of a four percent increase in commercial and
industrial electric sales. Residential electric sales increased one percent
despite four percent cooler temperatures during the primary air conditioning
load months of June, July, and August. Partially offsetting these increases
in electric revenues was a fourteen percent decrease in wholesale and
interchange sales as a result of higher than normal sales in 1993 COMPARED TOto other
utilities while their generating units were down due to the flooding of 1993.
Natural gas revenues and sales decreased significantly in 1994 as a result
of the sales of the Missouri Properties in the first quarter of 1994 (see Note
2). Also contributing to the decrease in natural gas revenues were reduced
natural gas sales for space heating as a result of much warmer temperatures
during the winter season of 1994 compared to 1993.
1993 Compared to 1992: Electric revenues increased significantly in 1993
as a result of the Merger. Also contributing to the increase werewas 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 for 1993 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 eleven11 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 199228
OPERATING EXPENSES
1994 Compared to 1993: Total operating expenses decreased 17 percent
during 1994 primarily 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.Missouri Properties
(Note 2). Also contributing to the decrease was an approximately four percent decrease in the unit cost ofwere lower fuel costs for
electric generation and reduced natural gas which is passed on to customers through the PGA. The decrease inpurchases as a result of lower
sales can be attributed to mildcaused by milder winter temperatures in 1992.1994 compared to 1993.
Partially offsetting the decreased sales weredecreases in operating expenses was higher income
tax expense. As of December 31, 1993, KG&E had fully amortized its deferred
income tax reserves related to the allowance for borrowed funds used during
construction capitalized for Wolf Creek Generating Station. The completion of
the amortization of these deferred income tax reserves increased retail ratesincome tax
expense and thereby reduced net income by approximately $12 million in Kansas1994,
and Missouri beginning early in 1992.
Operating Expenses:the future will reduce net income by this same amount each year.
1993 COMPARED TOCompared 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 resulting from refinancing of
secured facility bonds (see Note 10).
At December 31, 1993, KG&E completed the accelerated amortizationOTHER INCOME AND DEDUCTIONS: Other income and deductions, net 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 expenseswas higher for the ninetwelve months ended December 31, 1992, of $316 million have been included in1994 compared to 1993 due
to the Company's
operating expenses.
Other factors, excluding the Merger, contributing to increased operating
expenses were a one-time charge for the Company's portionrecognition of the early
retirement plan and voluntary separation programgain on the sales of the Missouri Properties of
approximately $11 million;
higher depreciation and amortization expense caused by increased plant
investment and the beginning$19.3 million, net of the amortization of previously deferred
safety-related expenditures in Kansas; and increased property taxes due to
increases in plant and tax, mill levies.(see Note 2). Partially offsetting
those increases in operating expensesthis increase was increased interest expense on corporate-owned life insurance
(COLI) borrowings. Also partially offsetting the increase was the commencementrecognition
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,
resultingincome 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:1993 from death proceeds from COLI policies.
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.
29
INTEREST CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS:
Total interest charges decreased 17 percent for the twelve months ended
December 31, 1994, as a result of lower debt balances and the refinancing of
higher cost debt, as well as increased COLI borrowings which interest is
reflected in Other incomeIncome and deductions, netDeductions, on the Consolidated Statements of
taxes, was significantly higher in
1992Income. The Company's embedded cost of long-term debt decreased to 7.6% at
December 31, 1994, compared to 19918.1% and 8.2% at December 31, 1993 and 1992,
respectively, primarily as a result of the Merger. KG&E contributed, for the
nine months ended December 31, 1992, $17 million to other income and
deductions, netrefinancing 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 investmenthigher cost debt.
Partially offsetting these decreases in commercial paper.
Interest Charges and Preferred and Preference Dividend Requirements:interest expense were higher
interest rates on short-term borrowings.
Interest charges for 1993 were higher than 1992 as a result of the Merger.
KG&E interest charges of $59 million for 1993 have beenwere 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 beenwere 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: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$20 million (pre-tax) 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: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 requiresmay require the Company to seek regulatory rate relief to recover these
higher costs.
FERC Order No.ORDER NO. 636: On April 8,In 1992 the FERC issued Order No. 636 (FERC 636)
which the FERC intended to complete the deregulation of natural gas production
and facilitate competition in the gas transportation industry. Order No.FERC 636 is
expected to affecthas
affected 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 natural30
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 natural gas sales service to
the restructured services required by Order No.FERC 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. For additional information regarding FERC
636 costs, see Note 5 of the Notes to Consolidated Financial Statements.
ENVIRONMENTAL: 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 Companysites and has an agreement with the Kansas Department of Health and
Environment to systematically evaluate these sites in Kansas (see Note 4)7).
TheAlthough the Company currently has no Phase I affected units under the
Clean Air Act of 1990. Until1990, the Company has applied for an early substitution
permit to bring the co-owned La Cygne Station under the Phase I guidelines.
The oxides of nitrogen (NOx) and air toxic limits, which were not set in law,
will be specified in future Environmental Protection Agency (EPA) regulations.
The EPA's proposed NOx regulations were ruled invalid by the U.S. Court of
Appeals for the District of Columbia Circuit in November, 1994 and until such
time that additionalas the EPA resubmits new proposed regulations, become final the Company will be unable
to determine its compliance options or related compliance costs (see Note 4)7).
Energy Policy Act:COMPETITION: As a regulated utility, the Company currently has limited
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.
The 1992 Energy Policy Act (Act) requires increased efficiency of energy
usage and will potentially changehas affected 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 toof its transmission system. Another partsystem for
wholesale transactions. During 1994, wholesale electric revenues represented
less than ten percent of the Act requiresCompany's total electric revenues.
Operating in this competitive environment could place pressure on utility
profit margins and credit quality. Wholesale and industrial customers may
threaten to pursue cogeneration, self-generation, retail wheeling,
municipalization or relocation to other service territories in an attempt to
obtain reduced energy costs. Increasing competition has resulted in credit
rating agencies applying more stringent guidelines when making utility credit
rating determinations.
The Company is providing reduced electric rates for industrial expansion
projects and economic development projects in an effort to maintain and
increase electric load. In 1994, The Boeing Company announced it would
31
develop its 777 jetliner in Wichita and Cessna Aircraft Company announced it
would build a special
assessmentproduction plant in Independence, Kansas along with expanding
its Wichita facilities, with an addition of 2,000 jobs.
In order to be collected from utilitiesretain its current electric load, the Company has and will
continue to negotiate with some of its larger industrial customers, who are
able to develop cogeneration facilities, for long-term contracts although some
negotiated rates may result in reduced margins for the Company. During 1996,
the Company will lose a uranium enrichment,
decontamination, and decommissioning fund. KG&E's portionmajor industrial customer to cogeneration resulting in
a reduction to pre-tax earnings of the assessment
for Wolf Creek is approximately $7 to $8 million payable over 15 years. Management
expects such costsor 7 to be recovered through8
cents per share. This customer's decision to develop its own cogeneration
project was based partially on factors other than energy cost.
To capitalize on opportunities in 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 onnon-regulated natural gas industry,
the Company, see Note 6through its wholly-owned subsidiary Mid Continent Market Center,
Inc. (Market Center), is establishing a natural gas market center in Kansas.
The Market Center will provide natural gas transportation, storage, and
gathering services, as well as balancing, and title transfer capability. Upon
approval from the KCC, the Company intends to transfer certain natural gas
transmission assets having a value of Notesapproximately $52.1 million to the
Consolidated Financial Statements.Market Center. In addition, the Company intends to extend credit to the
Market Center enabling the Market Center to borrow up to an aggregate
principal amount of $25 million on a term basis to construct new facilities
and $5 million on a revolving credit basis for working capital. The Market
Center will provide no notice natural gas transportation and storage services
to the Company under a long-term contract. The Company will continue to
operate and maintain the Market Center's assets under a separate contract.
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Auditors' Report 33Public Accountants 35
Financial Statements:
Consolidated Balance Sheets, December 31, 1994 and 1993 and 1992 3436
Consolidated Statements of Income for the years ended
December 31, 1994, 1993 and 1992 and 1991 3537
Consolidated Statements of Cash Flows for the years ended
1994, 1993 and 1992 and 1991 3638
Consolidated Statements of Taxes for the years ended
December 31, 1994, 1993 and 1992 and 1991 3739
Consolidated Statements of Capitalization, December 31, 1994
and 1993 and 1992 3840
Consolidated Statements of Common Stock Equity for the years
ended December 31, 1994, 1993 and 1992 and 1991 3941
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 7042
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.V.
33
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, 19931994 and 1992,1993, 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, 1993.1994. 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 auditaudits 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 auditaudits 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, 19931994 and 1992,1993, and the results of their operations and
their cash flows for each of the three years in the period ended December 31,
1993,1994, 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 1213 to the consolidated financial statements,
effective January 1, 1992, the Company changed its method of accounting for
income taxes. As explained in Note 68 to the consolidated financial
statements, effective January 1, 1993, the Company changed its method of
accounting for postretirement benefits. Our audit was made forAs explained in Note 8 to the
purpose of forming an opinion on the basicconsolidated financial statements, taken as a whole. The financial statement schedules
listed ineffective January 1, 1994, the tableCompany
changed its method of contents on page 32 are the responsibility of the
Company's management and are presentedaccounting 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.postemployment benefits.
ARTHUR ANDERSEN
LLP
Kansas City, Missouri,
ARTHUR ANDERSEN & CO.
January 28, 199425, 1995
34
WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
December 31,
1994(1) 1993 1992
(Dollars in Thousands)
ASSETS
UTILITY PLANT (Notes 1 and 11)9):
Electric plant in service . . . . . . . . . . . . . . . . $5,226,175 $5,110,617 $5,008,654
Natural gas plant in service. . . . . . . . . . . . . . . 737,191 1,111,866
1,024,369---------- ----------
5,963,366 6,222,483 6,033,023
Less - Accumulated depreciation . . . . . . . . . . . . . 1,790,266 1,821,710
1,691,623---------- ----------
4,173,100 4,400,773 4,341,400
Construction work in progress . . . . . . . . . . . . . . 85,290 80,192 68,041
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 39,890 29,271
33,312---------- ----------
Net utility plant. . . . . . . . . . . . . . . . . . . 4,298,280 4,510,236
4,442,753---------- ----------
OTHER PROPERTY AND INVESTMENTS:
Net non-utility investments . . . . . . . . . . . . . . . 74,017 61,497 47,680
Decommissioning trust (Note 4)7). . . . . . . . . . . . . . 16,944 13,204 9,272
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 13,556 10,658
13,855---------- ----------
104,517 85,359
70,807---------- ----------
CURRENT ASSETS:
Cash and cash equivalents (Note 1). . . . . . . . . . . . 2,715 1,217 875
Accounts receivable and unbilled revenues (net) (Note 1). 219,760 238,137 222,601
Fossil fuel, at average cost. . . . . . . . . . . . . . . 38,762 30,934 49,007
Gas stored underground, at average cost . . . . . . . . . 45,222 51,788 14,644
Materials and supplies, at average cost . . . . . . . . . 56,145 55,156
59,357
Prepayments and other current assets. . . . . . . . . . . 27,932 34,128
17,574---------- ----------
390,536 411,360
364,058---------- ----------
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 12)13). . . . . . . . . . 135,991 150,636101,886 111,159
Deferred coal contract settlement costs (Note 5). . . . . 21,247 24,52033,606 40,522
Phase-in revenues (Note 5). . . . . . . . . . . . . . . . 61,406 78,950 96,495
Corporate-owned life insurance (net) (Note 1) . . . . . . 16,967 4,743 146,713
Other deferred plant costs. . . . . . . . . . . . . . . . 31,784 32,008
32,212Unamortized debt expense. . . . . . . . . . . . . . . . . 58,237 55,999
Other (Note 5). . . . . . . . . . . . . . . . . . . . . . 132,154 110,71292,399 81,712
---------- ----------
396,285 405,093
561,288---------- ----------
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $5,189,618 $5,412,048
$5,438,906========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statement)Statements). . . . . . . . . . . . . . . $3,006,341 $3,121,021
$3,350,684---------- ----------
CURRENT LIABILITIES:
Short-term debt (Note 9)6) . . . . . . . . . . . . . . . . . 308,200 440,895 222,225
Long-term debt due within one year (Note 8)11) . . . . . . . 80 3,204 1,961
Preference stock redeemable within one year (Note 14) . . - 1,300
Accounts payable. . . . . . . . . . . . . . . . . . . . . 130,616 172,338 215,507
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 86,966 46,076 38,591
Accrued interest and dividends. . . . . . . . . . . . . . 61,069 65,825 71,877
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 69,025 65,492
48,045---------- ----------
655,956 793,830
599,506---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Note 12)13) . . . . . . . . . . . . . 971,014 968,637 990,155
Deferred investment tax credits (Note 12)13) . . . . . . . . 137,651 150,289 149,946
Deferred gain from sale-leaseback (Note 10) . . . . . . . 252,341 261,981 271,621
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 166,315 116,290
76,994---------- ----------
1,527,321 1,497,197
1,488,716---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 4 and 15)7)
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . . . $5,189,618 $5,412,048
$5,438,906========== ==========
(1) Information reflects the sales of the Missouri Properties (Note 2).
The Notes to Consolidated Financial Statements are an integral part of this statement.
35
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
1994(1) 1993 1992(1) 19911992(2)
(Dollars in Thousands
exceptExcept Per Share Amounts)
OPERATING REVENUES (Notes 1 and 5):
Electric. . . . . . . . . . . . . . . . . . . . . . . $1,121,781 $1,104,537 $ 882,885 $ 471,839
Natural gas . . . . . . . . . . . . . . . . . . . . . 496,162 804,822 673,363
690,339---------- ---------- ----------
Total operating revenues. . . . . . . . . . . . . . 1,617,943 1,909,359 1,556,248
1,162,178---------- ---------- ----------
OPERATING EXPENSES:
Fuel used for generation:
Fossil fuel . . . . . . . . . . . . . . . . . . . . 220,766 237,053 190,653 146,256
Nuclear fuel. . . . . . . . . . . . . . . . . . . . 13,562 13,275 10,126 -
Power purchased . . . . . . . . . . . . . . . . . . . 15,438 16,396 14,819 5,335
Natural gas purchases . . . . . . . . . . . . . . . . 312,576 500,189 403,326 439,323
Other operations. . . . . . . . . . . . . . . . . . . 303,391 349,160 296,642 193,319
Maintenance . . . . . . . . . . . . . . . . . . . . . 113,186 117,843 101,611 60,515
Depreciation and amortization . . . . . . . . . . . . 151,630 164,364 144,013 85,735
Amortization of phase-in revenues . . . . . . . . . . 17,544 17,545 13,158
-
Taxes (see statement)Statements):
Federal income. . . . . . . . . . . . . . . . . . . 76,477 62,420 34,905 24,516
State income. . . . . . . . . . . . . . . . . . . . 19,145 15,558 7,095 6,066
General . . . . . . . . . . . . . . . . . . . . . . 104,682 123,493 100,731
71,492---------- ---------- ----------
Total operating expenses. . . . . . . . . . . . . 1,348,397 1,617,296 1,317,079
1,032,557---------- ---------- ----------
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . 269,546 292,063 239,169
129,621---------- ---------- ----------
OTHER INCOME AND DEDUCTIONS (net of taxes)DEDUCTIONS:
Corporate-owned life insurance (net). . . . . . . . . (5,354) 7,841 9,308
Gain on sales of Missouri Properties (Note 2) . . . . 30,701 - -
Miscellaneous (net) . . . . . . . . . . . . . . . . . 12,838 18,418 18,976
Income taxes (net) (see Statements) . . . . . . . . . (4,329) (777) (4,098)
---------- ---------- ----------
Total other income and deductions . . . . . . . . 33,856 25,482 24,186
3,351---------- ---------- ----------
INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 303,402 317,545 263,355
132,972---------- ---------- ----------
INTEREST CHARGES:
Long-term debt. . . . . . . . . . . . . . . . . . . . 98,483 123,551 117,464 51,267
Other . . . . . . . . . . . . . . . . . . . . . . . . 20,139 19,255 20,009 10,490
Allowance for borrowed funds used during
construction (credit) . . . . . . . . . . . . . . . (2,667) (2,631) (2,002)
(1,070)---------- ---------- ----------
Total interest charges. . . . . . . . . . . . . . 115,955 140,175 135,471
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. . . . . . . . . . . . . . . . . . . . . . . 187,447 177,370 127,884 89,645
PREFERRED AND PREFERENCE DIVIDENDS. . . . . . . . . . . 13,418 13,506 12,751
6,377---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK . . . . . . . . . . $ 174,029 $ 163,864 $ 115,133
$ 83,268========== ========== ==========
AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . 61,617,873 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 . . . . . $ 2.82 $ 2.76 $ 2.20 $ 2.41
DIVIDENDS DECLARED PER COMMON SHARE . . . . . . . . . . $ 1.98 $ 1.94 $ 1.90
$ 2.04(2)
(1) Information reflects the sales of the Missouri Properties (Note 2).
(2) 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.
36
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1994(1) 1993 1992(1) 19911992(2)
(Dollars in Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 187,447 $ 177,370 $ 127,884 $ 89,645
Depreciation and amortization . . . . . . . . . . . . . . 151,630 164,364 144,013 85,735
Other amortization (including nuclear fuel) . . . . . . . 10,905 11,254 8,930
Gain on sales of utility plant (net of tax) . . . . . . . (19,296) - -
Deferred taxes and investment tax credits (net) . . . . . (16,555) 27,686 26,900 9,319
Amortization of phase-in revenues . . . . . . . . . . . . 17,544 17,545 13,158 -
Corporate-owned life insurance. . . . . . . . . . . . . . (17,246) (21,650) (14,704) -
Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (9,640) (7,231) -
Changes in other working capital items:items (net of effects
from the sales of the Missouri Properties):
Accounts receivable and unbilled revenues (net)(Note 1) (75,630) (15,536) (12,227) (72,879)
Fossil fuel . . . . . . . . . . . . . . . . . . . . . . (7,828) 18,073 14,990 (522)
Gas stored underground. . . . . . . . . . . . . . . . . (5,403) (37,144) 4,522 (2,340)
Accounts payable. . . . . . . . . . . . . . . . . . . . (41,682) (43,169) (10,194) (3,125)
Accrued taxes . . . . . . . . . . . . . . . . . . . . . 20,756 7,485 (52,185) (14,130)
Other . . . . . . . . . . . . . . . . . . . . . . . . . 12,813 (3,165) (19,433) 11,661
Changes in other assets and liabilities . . . . . . . . . 60,964 (18,569) 21,508
31,992---------- ---------- ----------
Net cash flows from operating activities. . . . . . . . 268,779 274,904 245,931
135,356---------- ---------- ----------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant. . . . . . . . . . . . . . . . 237,696 237,631 202,493 125,675
Merger with KG&E. . . . . . . . . . . . . . . . . . . . . - - 473,752 -
Utility investment. . . . . . . . . . . . . . . . . . . . - 2,500 -
Sales of utility plant. . . . . . . . . . . . . . . . . . (402,076) - -
Non-utility investments (net) . . . . . . . . . . . . . . 9,041 14,271 29,099 18,125
Corporate-owned life insurance policies . . . . . . . . . 26,418 27,268 20,233 -
Death proceeds of corporate-owned life insurance policies. . . . . . . . . . . . . . . . . . . . . . . .policies - (10,160) (6,789)
----------- ---------- ----------
Net Cash flows (from) used in investing activitiesactivities. . . . . . . . .(128,921) 271,510 718,788
143,800---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . (132,695) 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. . . . . . . . . . . . . . . . . . . . . . . 235,923 223,500 485,000 -
Bonds retired . . . . . . . . . . . . . . . . . . . . . . (223,906) (366,466) (236,966) (30,233)
Revolving credit agreements (net) . . . . . . . . . . . . (115,000) (35,000) - -
Other long-term debt (net). . . . . . . . . . . . . . . . (67,893) 7,043 14,498
-Borrowings against life insurance policies (net). . . . . 42,175 183,260 (5,649)
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) -(10,753)
Dividends on preferred, preference, and common stockstock. . . .(134,806) (127,316) (99,440)
(76,891)---------- ---------- ----------
Net cash flows from (used in) financing activities. . . (396,202) (3,052) 466,915
10,746---------- ---------- ----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . 1,498 342 (5,942) 2,302
CASH AND CASH EQUIVALENTS:
BEGINNING OF THE PERIODBeginning of the period . . . . . . . . . . . . . . . . . 1,217 875 6,817
4,515
END OF THE PERIOD---------- ---------- ----------
End of the period . . . . . . . . . . . . . . . . . . . . $ 2,715 $ 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 sales of the Missouri Properties (Note 2).
(2) 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.
37
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF TAXES
Year Ended December 31,
1994(1) 1993 1992(1) 19911992(2)
(Dollars in Thousands)
FEDERAL INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . $ 98,748 $ 41,200 $ 16,687 $ 18,479
Deferred taxes arising from:
Depreciation and other property related items . . . . . 29,506 25,552 25,163 9,662
Energy and purchased gas adjustment clauses . . . . . . 9,764 (8,192) (4,180) (15,535)
Unbilled revenues . . . . . . . . . . . . . . . . . . . - - 2,458 17,249
Natural gas line survey and replacement program . . . . (313) 355 (1,106)
1,015Missouri Property sales . . . . . . . . . . . . . . . . (36,343) - -
Prepaid power sale. . . . . . . . . . . . . . . . . . . (13,759) - -
Other . . . . . . . . . . . . . . . . . . . . . . . . . (800) 6,166 4,121 (1,109)
Amortization of investment tax credits. . . . . . . . . . (6,739) (1,982) (4,918)
(4,238)-------- -------- --------
Total Federal income taxes. . . . . . . . . . . . . . 80,064 63,099 38,225
25,523-------- -------- --------
Less:
Federal income taxes applicable to non-operating items.items:
Missouri Property sales . (679) (3,320) (1,007). . . . . . . . . . . . . . . 9,485 - -
Other . . . . . . . . . . . . . . . . . . . . . . . . . (5,898) 679 3,320
-------- -------- --------
Total Federal income taxes applicable to
non-operating items . . . . . . . . . . . . . . . . 3,587 679 3,320
-------- -------- --------
Total Federal income taxes charged to operations. . .76,477 62,420 34,905
24,516-------- -------- --------
STATE INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . 17,758 9,869 2,522 4,033
Deferred (net). . . . . . . . . . . . . . . . . . . . . . 2,129 5,787 5,352
2,276-------- -------- --------
Total stateState income taxes. . . . . . . . . . . . . . . 19,887 15,656 7,874
6,309-------- -------- --------
Less:
State income taxes applicable to non-operating items. . . (98) (779) (243)742 98 779
-------- -------- --------
Total stateState income taxes charged to operations. . . .19,145 15,558 7,095
6,066-------- -------- --------
GENERAL TAXES:
Property and other taxes. . . . . . . . . . . . . . . . . 86,687 84,583 68,643 40,429
Franchise taxes . . . . . . . . . . . . . . . . . . . . . 5,116 22,878 19,583 20,576
Payroll taxes . . . . . . . . . . . . . . . . . . . . . . 12,879 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 . . . . . .104,682 123,493 100,731
71,492-------- -------- --------
TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . . . . $200,304 $201,471 $142,731
$102,074======== ======== ========
The effective income tax rates set forth below are computed by dividing total Federal and stateState
income taxes by the sum of such taxes and net income. The difference between the effective rates
and the Federal statutory income tax rates are as follows:
Year Ended December 31, 1994(1) 1993 1992 19911992(2)
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . . . . 35.3% 31.0% 27.0% 32.2%
EFFECT OF:
Additional depreciation . . . . . . . . . . . . . . . . . (1.4) (2.9) (5.1) (2.7)
Accelerated amortization of certain deferred taxes. . . . .7 6.0 7.6 3.9
State income taxes. . . . . . . . . . . . . . . . . . . . (4.6) (4.0) (2.6) (4.0)
Amortization of investment tax credits. . . . . . . . . . 2.4 2.7 3.4 3.2
Corporate-owned life insurance. . . . . . . . . . . . . . 2.1 3.0 2.9 -
Other differences . . . . . . . . . . . . . . . . . . . . .5 (.8) .8
1.4---- ---- ----
STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . . . . 35.0% 35.0% 34.0%
34.0%==== ==== ====
(1) Information reflects the sales of the Missouri Properties (Note 2).
(2) 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.
38
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1994 1993 1992
(Dollars in Thousands)
COMMON STOCK EQUITY (see statement)Statements):
Common stock, par value $5 per share,
authorized 85,000,000 shares, outstanding
61,617,873 and 58,045,550 shares, respectivelyshares. . . . . . . . . . . . . . . . . $ 308,089 $ 290,228308,089
Paid-in capital. . . . . . . . . . . . . . . . . . . 667,992 667,738 559,636
Retained earnings. . . . . . . . . . . . . . . . . . 498,374 446,348
398,503---------- ----------
1,474,455 49% 1,422,175 45%
1,248,367 37%---------- ----------
CUMULATIVE PREFERRED AND PREFERENCE STOCK (Note 14)12):
Not subject to mandatory redemption,
Par value $100 per share, authorized
600,000 shares, outstanding -
4 1/2% Series, 138,576 shares . . . . . . . . 13,858 13,858
4 1/4% Series, 60,000 shares. . . . . . . . . 6,000 6,000
5% Series, 50,000 shares. . . . . . . . . . . 5,000 5,000
---------- ----------
24,858 24,858
---------- ----------
Subject to mandatory redemption,
Without par value, $100 stated value,
authorized 4,000,000 shares,
outstanding -
8.70% Series, 0 and 157,000 shares. . . . . . - 15,700
7.58% Series, 500,000 shares. . . . . . . . . 50,000 50,000
8.50% Series, 1,000,000 shares. . . . . . . . 100,000 100,000
Less: Preference stock reacquired,
135,000 shares . . . . . . . . . . . . . . - 12,967
Preference stock redeemable
within one year. . . . . . . . . . . . . . - 1,300---------- ----------
150,000 151,433150,000
---------- ----------
174,858 6% 176,291 5%174,858 6%
---------- ----------
LONG-TERM DEBT (Note 8)11):
First mortgage bonds . . . . . . . . . . . . . . . . 841,000 842,466 984,932
Pollution control bonds. . . . . . . . . . . . . . . 521,922 508,440 508,940
Other pollution control obligations. . . . . . . . . 13,980 14,205
Bank term loan . . . . . . . . . . . . . . . . . . . - 230,00013,980
Revolving credit agreements. . . . . . . . . . . . . - 115,000 150,000
Other long-term agreement. . . . . . . . . . . . . . - 53,913 46,640
Less:
Unamortized premium and discount (net) . . . . . . 5,814 6,607 6,730
Long-term debt due within one year . . . . . . . . 80 3,204
1,961---------- ----------
1,357,028 45% 1,523,988 49%
1,926,026 58%---------- ----------
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . $3,006,341 100% $3,121,021 100%
$3,350,684 100%========== ==========
The Notes to Consolidated Financial Statements are an integral part of this statement.
39
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY
Common Paid-in Retained
Stock Capital Earnings
(Dollars in Thousands)
BALANCE DECEMBER 31, 1990,1991, 34,566,170 shares. . . . . $172,831 $ 88,222 $369,772
Net income. . . . . . . . . . . . . . . . . . . . . . 89,645
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (6,377)
Common stock, $2.04(1) per share. . . . . . . . . . (70,514)
Expenses on preference stock. . . . . . . . . . . . . (1,123) (7)
BALANCE DECEMBER 31, 1991, 34,566,170 shares. . . . . 172,831 87,099 382,519$382,519
Net income. . . . . . . . . . . . . . . . . . . . . . 127,884
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (12,751)
Common stock, $1.90 per share . . . . . . . . . . . (99,135)
Expenses on preference stock. . . . . . . . . . . . . 14 (14)
Issuance of 23,479,380 shares of common stock
in the merger with KG&E . . . . . . . . . . . . . . 117,397 472,523
-------- -------- --------
BALANCE DECEMBER 31, 1992, 58,045,550 shares. . . . . 290,228 559,636 398,503
Net income. . . . . . . . . . . . . . . . . . . . . . 177,370
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,506)
Common stock, $1.94 per share . . . . . . . . . . . (116,019)
Expenses on common and preference stock . . . . . . .
(3,453)
Issuance of 3,572,323 shares of common stock. . . . . 17,861 111,555
-------- -------- --------
BALANCE DECEMBER 31, 1993, 61,617,873 shares. . . . . $308,089 $667,738 $446,348
(1) Includes special, one-time dividend of $0.18308,089 667,738 446,348
Net income. . . . . . . . . . . . . . . . . . . . . . 187,447
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,418)
Common stock, $1.98 per share paid February 28, 1991.. . . . . . . . . . . (122,003)
Expenses on common stock. . . . . . . . . . . . . . . (228)
Distribution of common stock under the Customer
Stock Purchase Plan . . . . . . . . . . . . . . . . 482
-------- -------- --------
BALANCE DECEMBER 31, 1994, 61,617,873 shares. . . . . $308,089 $667,992 $498,374
======== ======== ========
The Notes to Consolidated Financial Statements are an integral part of this statement.
40
WESTERN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: The consolidated financial statementsConsolidated Financial Statements of Western Resources, Inc.
(the Company, Western Resources), include the accounts of its wholly-owned
subsidiaries, Astra Resources, Inc. (Astra), Kansas Gas and Electric Company
(KG&E) since March 31, 1992 (see Note 3), and KPL Funding Corporation (KFC), and
Mid Continent Market Center, Inc. (Market Center). KG&E owns 47 percent of
Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for
Wolf Creek Generating Station (Wolf Creek). The Company records its
proportionate share of all transactions of WCNOC as it does other
jointly-owned facilities. All significant intercompany transactions have been
eliminated. The operations of Astra, Resources, Inc.,KFC, and KFC areMarket Center were not material
to the Company's results of operations. The Company is conducting its utility
business as KPL, Gas Service, and through its wholly-owned subsidiary, KG&E.
The Company is conducting its non-utility business through Astra.
The accounting policies of the Company are in accordance with generally
accepted accounting principles as applied to regulated public utilities. The
accounting and rates of the Company are subject to requirements of certain state regulatory commissionsthe Kansas
Corporation Commission (KCC), the Oklahoma Corporation Commission (OCC), and
the Federal Energy Regulatory Commission (FERC). The Company is doing
business as KPL, Gas Service, and, through its wholly-owned subsidiary, KG&E.
Utility Plant: Utility plant is stated at cost. For constructed plant,
cost includes contracted services, direct labor and materials, indirect
charges for engineering, supervision, general and administrative costs, and an
allowance for funds used during construction (AFUDC). The AFUDC rate was
4.08% in 1994, 4.10% in 1993, and 5.99% in 1992, and 6.25% in 1991.1992. The cost of additions to
utility plant and replacement units of property is capitalized. Maintenance
costs and replacement of minor items of property are charged to expense as
incurred. When units of depreciable property are retired, they are removed
from the plant accounts and the original cost plus removal charges less
salvage are charged to accumulated depreciation.
Depreciation: Depreciation is provided on the straight-line method based
on estimated useful lives of property. Composite provisions for book
depreciation approximated 2.87% during 1994, 3.02% during 1993, and 3.03%
during 1992 and 3.34%
during 1991 of the average original cost of depreciable property.
Consolidated Statements of Cash and Cash Equivalents:Flows: For purposes of the Consolidated
Statements of Cash Flows, cash and cash equivalents include cash on hand andthe Company considers highly liquid collateralized
debt instruments purchased with maturitiesa maturity of three months or less.less to be cash
equivalents.
Cash paid for interest and income taxes for each of the three years ended
December 31, are as follows:
1994 1993 1992
(Dollars in Thousands)
Interest on financing activities (net of
amount capitalized). . . . . . . . . . . $134,785 $171,734 $128,505
Income taxes . . . . . . . . . . . . . . . 90,229 49,108 24,966
41
Income Taxes: Income tax expense includes provisions for income taxes
currently payable and deferred income taxes calculated in conformance with
income tax laws, regulatory orders, and Statement of Financial Accounting
Standards No. 109 (SFAS 109) (see Note 12)13).
Investment tax credits previously deferred are deferred as realized andbeing amortized to income
over the life of the property which gave rise to the credits.
Revenues: Effective January 1, 1991, theThe Company changed its method of
accounting for recognizingaccrues estimated unbilled electric and natural gas
revenues. This method of recognizing revenues to provide for
the accrual of estimated unbilled revenues. The accounting change provides a
better matching ofbest matches revenues with
costs of services provided to customers and also serves to conformconforms the Company's
accounting treatment of unbilled revenues with the tax treatment of such
revenues. Unbilled revenues represent the estimated amount customers will be
billed for service provided from the time meters were last read to the end of
the accounting period. Meters are read
and services are billed on a cycle basis and, prior to the accounting change,
revenues were recognized in the accounting period during which services were
billed.
The after-tax effect of the change in accounting method for the year ended
December 31, 1991, was an increase in net income of $15.9 million or $0.46 per
share. This increase was a combination of an increase of $17.3 million or
$0.50 per share, attributable to the cumulative effect of the accounting
change prior to January 1, 1991, and a decrease of $1.4 million or $0.04 per
share in the 1991 income before cumulative effect of a change in accounting
principle. Unbilled revenues of $99$61 million and $86$99 million are
recorded as a component of accounts receivable and unbilled revenues (net) on
the consolidated balance sheetsConsolidated Balance Sheets as of December 31, 1994 and 1993,
and 1992, respectively. Certain amounts of unbilled
revenues have been sold (see Note 8).
The Company had reserves for doubtful accounts receivable of $4.3$3.4 million
and $3.3$4.3 million at December 31, 19931994 and 1992,1993, respectively.
Fuel Costs: The cost of nuclear fuel in process of refinement,conversion, enrichment, and fabrication is recorded as an asset at original
cost and is amortized to expense based upon the quantity of heat produced for
the generation of electricity. The accumulated amortization of nuclear fuel
in the reactor at December 31, 1994 and 1993, was $13.6 million and 1992, was $17.4
million, and $26.0
million, respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts
related to corporate-owned life insurance contracts (COLI), primarily with one
highly rated major insurance company, are recorded in Corporate-owned Life
Insurance (net) on the consolidated balance
sheets (millions of dollars):Consolidated Balance Sheets:
1994 1993
1992(Dollars in Millions)
Cash surrender value of contracts. . . $ 326.3408.9 $ 256.3
Prepaid COLI . . . . . . . . . . . . . 11.9 7.0326.3
Borrowings against contracts . . . . . (321.5) (109.6)(391.9) (321.6)
------- -------
COLI (net). . . . . . . . . . $ 16.717.0 $ 153.7
The decrease in COLI (net) is a result of increased borrowings against the
accumulated cash surrender value of the COLI policies.4.7
======= =======
The COLI borrowings will be repaid withupon receipt of proceeds from death
benefits. Management expects to
realizebenefits under contracts. The Company recognizes increases in the cash
surrender value of contracts, resulting from premiums and investment earnings
on a tax free basis, upon receiptand the tax deductible interest on the COLI borrowings in
Corporate-owned Life Insurance (net) on the Consolidated Statements of proceeds
from death benefits under the contracts.Income.
Interest expense included in other
income and deductions, net of taxes, related to KG&E's COLI for 1994, 1993, and the nine months
ended December 31, 1992, was $21.0 million, $11.9 million, and $5.3 million,
respectively.
As approved by the Kansas Corporation Commission (KCC) and Missouri Public
Service Commission (MPSC),KCC, the Company is using a portion of the net income
stream generated by COLI policies purchased in 1993 and 1992 by the Company
(see Note 6)8) to offset Statement of Financial Accounting Standards No. 106
(SFAS 106) and Statement of Financial Accounting Standards No. 112 (SFAS 112)
expenses.
Reclassifications: Certain amounts in prior years have been reclassified
to conform with classifications used in the current year presentation.
42
2. SALESALES OF MISSOURI NATURAL GAS DISTRIBUTION PROPERTIES
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 finalsale agreement provided for
estimated amounts in the sale price willcalculation to be calculatedadjusted to actual as of
January 31, 1994, within 120 days of closing. Any differenceDisputes with respect to
proposed adjustments based upon differences between estimates and actuals were
to be resolved within 60 days of submission of the estimated and finaldisputes by Southern Union
or submitted to arbitration by an accounting firm to be agreed to by both
parties. Southern Union proposed a number of adjustments to the purchase
price, some of which the Company has disputed. The Company maintains the
disputed adjustments are not permitted under the sale agreement. In the
opinion of the Company's management, the resolution of these purchase price
adjustments will be adjusted throughnot have a paymentmaterial impact on the Company's financial
position or results of operations. For information regarding litigation in
connection with the sale of the Missouri Properties to or from
the Company.Southern Union, see
Note 4.
United Cities purchased the Company's natural gas distribution system in
and around the City of Palmyra, Missouri for $665,000 in cash.
During the first quarter of 1994, the Company recognized a gain of
approximately $19.3 million, net of tax, on the sales of the Missouri
Properties. As of the respective dates of the sales of the Missouri
Properties, the Company ceased recording the results of operations, and
removed the assets and liabilities from the Consolidated Balance Sheet related
to the Missouri Properties. The gain is reflected in Other Income and
Deductions, on the Consolidated Statements of Income.
The following table reflects the approximate operating revenues and
operating income (unaudited) related tofor the Missouri Properties approximated $350 million and $21 million representing
approximately 18 percent and seven percent, respectively, of the Company's
total foryears ended December 31, 1994, 1993, and $299 million and$11 million representing approximately 19
percent1992, and
five percent, respectively, of the Company's total for 1992. Netnet utility plant (unaudited) for the Missouri Properties, at December 31, 1993,
approximated $296 million and $272 million at December 31, 1992. This
represents approximately seven percent at December 31, 1993 and six percent
at December 31, 1992, related to the Missouri
Properties:
1994 1993 1992
Percent Percent Percent
of the totalTotal of Total of Total
Amount Company netAmount Company Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. .$ 77,008 4.8% $349,749 18.3% $299,202 19.2%
Operating income. . . 4,997 1.9% 20,748 7.1% 11,177 4.7%
Net utility plant.plant . . - - 296,039 6.6% 272,126 6.1%
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.43
3. ACQUISITION AND MERGER
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 $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).
The Merger was accounted for as a purchase. For income tax purposes the tax
basis of the KG&E assets was not changed by the Merger.
As the Company acquired 100 percent of the common and preferred stock of
KG&E, the Company recorded an acquisition premium of $490 million on the
consolidated balance sheetConsolidated Balance Sheet for the difference in purchase price and book
value. This acquisition premium and related income tax requirement of $294$311
million under SFAS 109 have been classified as plant acquisition adjustment in
electric plantElectric Plant in serviceService on the consolidated balance sheets. The total cost
of the acquisition was $1.066 billion.Consolidated Balance Sheets. Under the
provisions of orders of the KCC, and the MPSC the acquisition premium is recorded as an
acquisition adjustment and not allocated to the other assets and liabilities
of KG&E.
In the November 1991 KCC order approving the Merger, a mechanism was
approved to share equally between the shareholders and ratepayers the cost
savings generated by the Merger in excess of the revenue requirement needed to
allow recovery of the amortization of a portion of the acquisition adjustment,
including income tax, calculated on the basis of a purchase price of KG&E's
common stock at $29.50 per share. The order provides an amortization period
for the acquisition adjustment of 40 years commencing in August 1995, at which
time the full amount of cost savings is expected to have been implemented.
Merger savings will be measured by application of an inflation index to
certain pre-merger operating and maintenance costs at the time of the next
Kansas rate case. 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. The order further provides a
moratorium on increases, with certain exceptions, in the Company's Kansas
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 wasRefunds of $8.5 million were made in April 1992 and amounted to $8.5 million.
A refund of the same amount was made in December 1993 and
an additionalthe remaining refund of $15 million will bewas made in September 1994.
The KCC order approving the Merger requiresrequired the legal reorganization of
KG&E so that it iswas no longer held as a separate subsidiary after January 1,
1995, unless good cause iswas shown why such separate existence should be
maintained. The Securities and Exchange Commission (SEC) order relating to
the Merger granted the Company an exemption under the Public UtilitiesUtility Holding
Company Act (PUHCA) until January 1, 1995. In connection with a requested ruling that
a merger of KG&E into Western Resources would not adversely affect the tax
structure of the merger, KG&E received a responseThe Company has been granted
regulatory approval from the Internal Revenue
Service thatKCC which eliminates the IRS would not issue the requested ruling. In light of the
IRS response, KG&E withdrew its request for a ruling. The Company will
consider alternative forms of combination or seek regulatory approvals to
waive the requirementsrequirement for a
combination. ThereAs a result of the sales of the Missouri Properties, the Company
is no certaintynow exempt from regulation as to whether
a combination will occur or as toholding company under Section 3(a)(1) of
the form or timing thereof.PUHCA.
As the Merger did not occur until March 31, 1992, the twelve months ended
December 31, 1992, results of operations for the Company reported in its
statements of income, cash flows, and common stock equity reflect KG&E's
results of operations for only the nine months ended December 31, 1992. The
proPro
44
forma combined revenues of $1.7 billion, operating income of $269 million, net income
of $132 million and earnings per common share of $2.03 for the Company presented belowyear ended December
31, 1992 give effect to the Merger as if it had occurred at January 1, 1991.1992.
This pro forma information is not necessarily indicative of the results of
operations that would have occurred had the Merger been consummated for the period for which it is being given
effecton January
1, 1992, nor is it necessarily indicative of future operating results.
4. LEGAL PROCEEDINGS
On June 1, 1994, Southern Union filed an action against the Company, The
Bishop Group, Ltd., and other entities affiliated with The Bishop Group, in
the Federal District Court for the Western District of Missouri (the Court)
(Southern Union Company v. Western Resources, Inc. et al., Case No. 94-509-CV-
W-1) alleging, among other things, breach of the Missouri Properties sale
agreement relating to certain gas supply contracts between the Company and
various Bishop entities that Southern Union assumed, and requesting
unspecified monetary damages as well as declaratory relief. On August 1,
1994, the Company filed its answer and counterclaim denying all claims
asserted against it by Southern Union and requesting declaratory judgment with
respect to certain adjustments in the purchase price for the Missouri
Properties proposed by Southern Union and disputed by the Company. On August
24, 1994, Southern Union filed claims against the Company for alleged purchase
price adjustments totalling $19 million. The Company subsequently agreed that
approximately $4 million of the purchase price adjustments were subject to
arbitration. On January 18, 1995, the Court held the remaining $15 million of
proposed adjustments to the purchase price were subject to arbitration under
the sale agreement. In the opinion of the Company's management, the disputed
adjustments are not proper adjustments to the purchase price. For additional
information regarding the sales of the Missouri Properties see Note 2.
On August 15, 1994, the Bishop entities filed an answer and claims against
Southern Union and the Company alleging, among other things, breach of those
certain gas supply contracts. The Bishop entities claimed damages up to $270
million against the Company and Southern Union. The Company's management
believes that through the sale agreement, Southern Union assumed all
liabilities arising out of or related to gas supply contracts associated with
the Missouri Properties. The Company's management also believes it is not
liable for any claims asserted against it by the Bishop entities and will
vigorously defend such claims.
The Company received a civil investigative demand from the U.S. Department
of Justice seeking certain information in connection with the department's
investigation "to determine whether there is, has been, or may be a violation
of the Sherman Act Sec. 1-2" with respect to the natural gas business in
Kansas and Missouri. The Company is cooperating with the Department of
Justice, but is not aware of any violation of the antitrust laws in connection
with its business operations.
The Company and its subsidiaries are involved in various other legal and
environmental proceedings. Management believes that adequate provision has
been made within the Consolidated Financial Statements for these other matters
and accordingly believes their ultimate dispositions will not have a material
adverse effect upon the business, financial position, or results of operations
of the Company.
45
5. RATE MATTERS AND REGULATION
The Company, under rate orders from the KCC, OCC and the FERC, recovers
increases in fuel and natural gas costs through fuel adjustment clauses for
wholesale and certain retail electric customers and various purchased gas
adjustment clauses (PGA) for natural gas customers. The KCC and the OCC
require the annual difference between actual gas cost incurred and cost
recovered through the application of the PGA be deferred and amortized through
rates in subsequent periods.
Elimination of the Energy Cost Adjustment Clause (ECA): On March 26,
1992, in connection with the Merger, the KCC approved the elimination of the
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 variance
in fuel costs from the projected average will impact the Company's earnings.
FERC Proceedings: On August 19, 1994, Williams Natural Gas Company (WNG)
filed a revised application with the FERC to direct bill approximately $14.7
million of FERC Order No. 636 (FERC 636) transition costs to the Company
related to natural gas sales service in Kansas and Oklahoma. These costs are
currently being recovered from the Company's current Kansas and Oklahoma
customers. The Company believes any future transition costs ultimately will
be recovered through charges to its customers, and any unrecovered transition
costs will not be material to the Company's financial position or results of
operations. For additional information with respect to FERC 636 see
Management's Discussion and Analysis.
On October 5, 1994, WNG filed an application with the FERC to direct bill
to the Company up to $30.4 million of settlement costs paid to Amoco related
to litigation between WNG and Amoco regarding the proper price to be paid for
gas purchased by WNG from Amoco. The proposed direct bill is related to
natural gas service rendered by the Company in Kansas and Oklahoma. At
December 31, 1994, $14.2 million of these costs have been billed to the
Company. The Company believes substantially all of these costs and any future
settlement costs ultimately will be recovered through charges to its Kansas
and Oklahoma customers, and any unrecovered settlement costs will not be
material to the Company's financial position or results of operations.
KCC Proceedings: On December 22, 1994, the Company, in conjunction with
the Market Center, filed an application with the KCC to form a natural gas
market center in Kansas. The Market Center will provide natural gas
transportation, storage, and gathering services, as well as balancing, and
title transfer capability. Upon approval from the KCC, the Company intends to
transfer certain natural gas transmission assets having a value of
approximately $52.1 million to the Market Center. In addition, the Company
intends to extend credit to the Market Center enabling the Market Center to
borrow up to an aggregate principal amount of $25 million on a term basis to
construct new facilities and $5 million on a revolving credit basis for
working capital. The Market Center will provide no notice natural gas
transportation and storage services to the Company under a long-term contract.
The Company will continue to operate and maintain the Market Center's assets
under a separate contract.
46
On January 24, 1992, the KCC issued an order allowing the Company to
continue the deferral of service line replacement program costs incurred since
January 1, 1992, including depreciation, property taxes, and carrying costs
for recovery in the next general rate case. At December 31, 1994,
approximately $7.2 million of these deferrals have been included in Deferred
Charges and Other Assets, Other, on the Consolidated Balance Sheet.
On December 30, 1991, the KCC approved a permanent natural gas rate
increase of $39 million annually and the Company discontinued the deferral of
accelerated line survey costs on January 1, 1992. Approximately $3.1 million
of these deferred costs remain in Deferred Charges and Other Assets, Other, on
the Consolidated Balance Sheet at December 31, 1994, with the balance being
included in rates and amortized to expense during a 43-month period,
commencing January 1, 1992.
Tight Sands: In December 1991 the KCC, and the OCC approved agreements
authorizing the Company to refund to customers approximately $40 million of
the proceeds of the Tight Sands antitrust litigation settlement to be
collected on behalf of Western Resources' natural gas customers. To secure
the refund of settlement proceeds, the Commissions authorized the
establishment of an independently administered trust to collect and maintain
cash receipts received under Tight Sands settlement agreements and provide for
the refunds made. The trust has a term of ten years.
Rate Stabilization Plan: In 1988, the KCC issued an order requiring the
accrual of phase-in revenues be discontinued by KG&E effective December 31,
1988. Effective January 1, 1989, KG&E began amortizing the phase-in revenue
asset on a straight-line basis over 9 1/2 years. At December 31, 1994,
approximately $61 million of deferred phase-in revenues remained on the
Consolidated Balance Sheet.
Coal Contract Settlements: In March 1990, the KCC issued an order
allowing KG&E to defer its share of a 1989 coal contract settlement with the
Pittsburg and Midway Coal Mining Company amounting to $22.5 million. This
amount was recorded as a deferred charge and is included in Deferred Charges
and Other Assets on the Consolidated Balance Sheet. The settlement resulted
in the termination of a long-term coal contract. The KCC permitted KG&E to
recover this settlement as follows: 76 percent of the settlement plus a return
over the remaining term of the terminated contract (through 2002) and 24
percent to be amortized to expense with a deferred return equivalent to the
carrying cost of the asset.
In February 1991, KG&E paid $8.5 million to settle a coal contract lawsuit
with AMAX Coal Company and recorded the payment as a deferred charge in
Deferred Charges and Other Assets on the Consolidated Balance Sheet. The KCC
approved the recovery of the settlement plus a return, equivalent to the
carrying cost of the asset, over the remaining term of the terminated contract
(through 1996).
FERC Order No. 528: In 1990, the FERC issued Order No. 528 which
authorized new methods for the allocation and recovery of take-or-pay
settlement costs by natural gas pipelines from their customers. Settlements
were reached between the Company's two largest gas pipelines and their
customers in FERC proceedings related to take-or-pay issues. The settlements
address the allocation of take-or-pay settlement costs between the pipelines
and their customers. However, the amount which one of the pipelines will be
47
allowed to recover is yet to be determined. Litigation continues between the
Company and a former upstream pipeline supplier to one of the Company's
pipeline suppliers concerning the amount of such costs which may ultimately be
allocated to the Company's pipeline supplier. The Company's share of any
costs allocated to the Company's pipeline supplier will be charged to the
Company. Due to the uncertainty concerning the amount to be recovered by the
Company's current suppliers and of the outcome of the litigation between the
Company and its current pipeline's upstream supplier, the Company is unable to
estimate its future liability for take-or-pay settlement costs. However, the
KCC has approved mechanisms which are designed to allow the Company to recover
these take-or-pay costs from its customers.
6. SHORT-TERM DEBT
The Company's short-term financing requirements are satisfied, through the
sale of commercial paper, short-term bank loans and borrowings under unsecured
lines of credit maintained with banks. Information concerning these
arrangements for the years ended December 31, 1994, 1993, and 1992, is set
forth below:
Year Ended December 31, 1994 1993 1992 1991
(Dollars in Thousands, except per share amounts)
Revenues.Thousands)
Lines of credit at year end. . . . $145,000(1) $145,000 $250,000(2)
Short-term debt out-
standing at year end . . . . . . 308,200 440,895 222,225
Weighted average interest rate on debt outstanding at year
end (including fees) . . . . . . 6.25% 3.67% 4.70%
Maximum amount of short-
term debt outstanding during
the period. . . .. . . . . . . . $485,395 $443,895 $263,900
Monthly average short-term debt. . 214,180 347,278 179,577
Weighted daily average interest
rates during the year
(including fees) . . . . . . . . . . . $1,684,885 $1,748,844
Operating Income. . . . . . . . 268,772 279,458
Net Income. . . . . . . . . . . 131,524 110,290(1)
Earnings Per Common . . . . . . $ 2.03 $ 1.72(1)4.63% 3.44% 4.90%
(1) Reflects information beforeDecreased to $121 million in January 1995.
(2) Decreased to $155 million in January 1993.
In connection with the cumulative effectcommitments, the Company has agreed to pay certain
fees to the banks. Available lines of credit and the unused portion of the
January 1,
1991 change in accounting method of recognizing revenues.
4.revolving credit facility are utilized to support the Company's outstanding
short-term debt.
7. COMMITMENTS AND CONTINGENCIES
As part of its ongoing operations and construction program, the Company
has commitments under purchase orders and contracts which have an unexpended
balance of approximately $86$77 million at December 31, 1993.1994. Approximately $36$32
million is attributable to modifications to upgrade the three turbines at
Jeffrey Energy Center to be completed by December 31, 1998. Plans for future
construction of utility plant are discussed in the "Management'sManagement's Discussion and
Analysis"Analysis section.
Environmental:48
In January 1994, the Company entered into an agreement with Oklahoma
Municipal Power Authority (OMPA). Under the agreement, the Company received a
prepayment of approximately $41 million for which the Company will provide
capacity and transmission services to OMPA through the year 2013.
Manufactured Gas Sites: The Company has beenwas previously associated with 28 (20 in Kansas and
8 in Missouri)20
former manufactured gas sites located in Kansas which may contain coal tar and
other potentially harmful materials. These sites were operated decades ago by
otherpredecessor companies, and were acquiredowned by the Company for a period of time
after theyoperations had ceased
operation. The Environmental Protection Agency (EPA) has performed
preliminary assessments of eleven of these sites (EPA sites), six of which are
under site investigation. The Company has not received any indication from
the EPA that further action will be taken at the EPA sites, nor does the
Company have reason to believe there will be any fines or penalties assessed
related to these sites.ceased. The Company and the Kansas Department of Health
and Environment (KDHE) entered into a consent agreement to conduct separateconducted preliminary assessments of the 20 former manufactured gas sites located in
Kansas. The preliminary assessments of these 20 sites have been completed at a total
cost of approximately $500,000. The results of the preliminary investigations
determined the Company plansdoes not have a connection to initiatefour of the sites. Of
the remaining 16 sites, the site investigation and risk assessments atassessment field work
of the two highest priority sitessite was completed in 1994 at a total cost of
approximately $500,000. Until such time that risk
assessments are completed$450,000. The Company has not received the final report so as
to determine the extent of contamination and the amount of any possible
remediation.
The Company and KDHE entered into a consent agreement governing all future
work at these orsites. The terms of the remainingconsent agreement will allow the
Company to investigate the 16 sites itand set remediation priorities based upon
the results of the investigations and risk analysis. The prioritized sites
will be impossibleinvestigated over a 10 year period. The agreement will allow the
Company to predictset mutual objectives with the cost of remediation. However, theKDHE in order to expedite effective
response activities and to control costs and environmental impact. The
Company is aware of other utilities in Region VII of the EPA (Kansas,
Missouri, Nebraska, and Iowa) which have incurred remediation costs for
suchmanufactured gas sites ranging between $500,000 and $10 million, depending on
the site. The Company is also awaresite, and that the KCC has permittedissued an accounting order which will permit
another Kansas utility to recover a portion of theits remediation costs through rates. To the
extent that such remediation costs are not recovered through rates, the costs
could be material to the Company's financial position or results of operations
depending on the degree of remediation required and number of years over which
the remediation must be completed.
Superfund Sites: The Company has been identified as one of numerous
potentially responsible parties in four hazardous waste sites listed by the
EPA as Superfund sites. One site is a groundwater contamination site in
Wichita, Kansas (Wichita site), two are soil contamination sites in Missouri
(Missouri sites), and one site is an
oil soil contamination site in Springfield, Missouri. The other two sites area solid waste land fillsland-fill located in
Edwardsville, Kansas (Edwardsville site). Settlement agreements releasing the
Company from liability for future response or costs have been entered into at
the Edwardsville site and Hutchinson, Kansas.one of the Missouri sites. The Company's obligation
at these sitesthe remaining Missouri site and the Wichita site appears to be limited
based on the Company's experience at similar sites given its limited exposure
and it issettlement costs. In the opinion of the Company's management, that the
resolution of these matters will not have a material impact on the Company's
financial position or results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a
two-phase reduction in sulfur dioxide and oxides of nitrogen (NOx) 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 installed continuous monitoring and reporting equipment at a total
cost of approximately $10 million. The Company does not expect additional
49
equipment to reduce sulfur emissions to be necessary under Phase II. Although
the Company currently has no Phase I affected units, the owners have applied
for an early substitution permit to bring the co-owned La Cygne Station under
the Phase I regulations.
The NOx and air toxic limits, which were not set in the law, will be
specified in future EPA regulations. The EPA's proposed NOx regulations were
ruled invalid by the U.S. Court of Appeals for the District of Columbia
Circuit and until such time as the EPA resubmits new proposed regulations, the
Company will be unable to determine its compliance options or related
compliance costs.
Other Environmental Matters: As part of the sale of the Company's
Missouri Properties to Southern Union, Southern Union assumed responsibility
under an agreement for any environmental matters nowrelated to the Missouri
Properties purchased by Southern Union pending at the date of the sale or that
may arise after closing. For any environmental matters now pending or discovered
within two years of the date of the agreement, and after pursuing several
other potential recovery options, the Company may be liable for up to a
maximum of $7.5 million under a sharing arrangement with Southern Union
provided for in the agreement.
Spent Nuclear Fuel Disposal: Under the Nuclear Waste Policy Act of 1982,
the U.S. Department of Energy (DOE) is responsible for the ultimate storage
and disposal of spent nuclear fuel removed from nuclear reactors. Under a
contract with the DOE for disposal of spent nuclear fuel, the Company pays a
quarterly fee to DOE of one mill per kilowatthour on net nuclear generation.
These fees are included as part of nuclear fuel expense and amounted to $3.8
million for 1994, $3.5 million for 1993, and $1.6 million for 1992.
Decommissioning: The Company's shareCompany along with the other co-owners of Wolf Creek decommissioning costs,
currently authorizedare among 14
companies that filed a lawsuit on June 20, 1994, seeking an interpretation of
the DOE's obligation to begin accepting spent nuclear fuel for disposal in
rates, was estimated1998. The Federal Nuclear Waste Policy Act requires DOE ultimately to accept
and dispose of nuclear utilities' spent fuel. The DOE has filed a motion to
have this case dismissed. The issue to be approximately $97 milliondecided in 1988 dollars. Decommissioning costs are being charged to operating
expenses. Amounts so expensed are depositedthis case is whether DOE
must begin accepting spent fuel in 1998 or at a future date. Wolf Creek
contains an external trust fund and will
be used solelyon-site spent fuel storage facility which, under current
regulatory guidelines, provides space for the physical decommissioningstorage of spent fuel through
the plant. Electric rates
charged to customers provide for recovery of these decommissioning costs over
the estimated life of Wolf Creek. At December 31, 1993, and December 31,
1992, $13.2 and $9.3 million, respectively, were on deposit in the
decommissioning fund.year 2006 while still maintaining full core off-load capability. The
Company believes adequate additional storage space can be obtained as
necessary.
Decommissioning: On September 1, 1993, WCNOC filed an application withJune 9, 1994, the KCC forissued an order approving athe
decommissioning costs of the 1993 Wolf Creek Decommissioning Cost Study which
estimates the Company's share of Wolf Creek decommissioning costs, atunder the
immediate dismantlement method, to be approximately $595 million primarily
during the period 2025 through 2033, or approximately $174 million in 1993
dollars. If approved byThese costs were calculated using an assumed inflation rate of 3.45%
over the remaining service life, in 1993, of 32 years.
Decommissioning costs are being charged to operating expenses in
accordance with the KCC management expects substantially all such cost increasesorder. Electric rates charged to be recovered
throughcustomers provide
for recovery of these decommissioning costs over the ratemaking process.life of Wolf Creek.
Amounts so expensed ($3.5 million in 1994 increasing annually to $5.5 million
in 2024) and earnings on trust fund assets are deposited in an external trust
fund. The assumed return on trust assets is 5.9%.
50
The Company's investment in the decommissioning fund, including
reinvested earnings was $16.9 million and $13.2 million at December 31, 1994
and December 31, 1993, respectively. These amounts are reflected in
Decommissioning Trust, and the related liability is included in Deferred
Credits and Other Liabilities, Other, on the Consolidated Balance Sheets.
The Company carries $164$118 million in premature decommissioning insurance in
the event of a shortfall in the trust fund.insurance.
The insurance coverage has several restrictions. One of these is that it can
only be used if Wolf Creek incurs an accident exceeding $500 million in
expenses to safely stabilize the reactor, to decontaminate the reactor and
reactor station site in accordance with a plan approved by the Nuclear
Regulatory Commission (NRC), and to pay for on-site property damages. If the
amount designated as decommissioning insurance is needed to implement the NRC-approvedNRC-
approved plan for stabilization and decontamination, it would not be available
for decommissioning purposes.
Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.4$8.9 billion for a single
nuclear incident. The Wolf Creek owners (Owners) have purchased the maximum
available private insurance of $200 million and the balance is provided by an
assessment plan mandated by the NRC. Under this plan, the Owners are jointly
and severally subject to a retrospective assessment of up to $79.3 million
($37.3 million, Company's share) in the event there is a major nuclear
incident involving any of the nation's licensed reactors. This assessment is
subject to an inflation adjustment based on the Consumer Price Index.Index and
applicable premium taxes. There is a limitation of $10 million ($4.7 million,
Company's share) in retrospective assessments per incident, per year.
The Owners carry decontamination liability, premature decommissioning
liability, and property damage insurance for Wolf Creek totalling
approximately $2.8 billion ($1.3 billion, Company's share). This insurance is
provided by a combination of "nuclear insurance pools" ($1.3 billion)500 million) and
Nuclear Electric Insurance Limited (NEIL) ($1.52.3 billion). In the event of an
accident, insurance proceeds must first be used for reactor stabilization and
site decontamination. The Company's share of any remaining proceeds from the $2.8 billion insurance
coverage ($1.3 billion, Company's share), if any, can be
used for property damage up to $1.1$1.2 billion (Company's share) and premature
decommissioning costs up to $117.5$118 million (Company's share) in excess of funds
previously collected for decommissioning (as discussed under
"Decommissioning"), with the
remaining $47 million (Company's share) available for either property damage
or premature decommissioning costs..
The Owners also carry additional insurance with NEIL to cover costs of
replacement power and other extra expenses incurred during a prolonged outage
resulting from accidental property damage at Wolf Creek. If losses incurred
at any of the nuclear plants insured under the NEIL policies exceed premiums,
reserves, and other NEIL resources, the Company may be subject to
retrospective assessments of approximately $9$13 million per year.
There can be no assurance that allAlthough the Company maintains various insurance policies to provide
coverage for potential losses and liabilities resulting from an accident or liabilities willan
extended outage, the Company's insurance coverage may not be insurable or that the amount of insurance will be sufficientadequate to cover
them.the costs that could result from a catastrophic accident or extended outage at
Wolf Creek. Any substantial losses not covered by insurance, to the extent
not recoverable through rates, couldwould have a material adverse effect on the
Company's financial condition and results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a
two-phase reduction in sulfur dioxide and nitrous 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 nitrous 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 nitrous oxide regulations for Phase I group 1 units. Nitrous
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 nitrous oxide regulations for Phase I group 1 may
allow for early compliance for Phase II group 1 units. Until such time as the
Phase I group 1 nitrous oxide regulations are final, the Company will be
unable to determine its compliance options or related compliance costs.
51
Federal Income Taxes: During 1991, the Internal Revenue Service (IRS)
completed an examination of KG&E's federal income tax returns for the years
1984 through 1988. In April 1992, KG&E received the examination report and
upon review filed a written protest in August 1992. In October 1993, KG&E
received another examination report for the years 1989 and 1990 covering the
same issues identified in the previous examination report. Upon review of
this report, KG&E filed a written protest in November 1993. The most
significant proposed adjustments reduce the depreciable basis of certain
assets and investment tax credits generated. Management believes there are
significant questions regarding the theory, computations, and sampling
techniques used by the IRS to arrive at its proposed adjustments, and also
believes any additional tax expense incurred or loss of investment tax credits
will not be material to the Company's financial position and results of
operations. Additional income tax payments, if any, are expected to be offset
by investment tax credit carryforwards, alternative minimum tax credit
carryforwards, or deferred tax provisions.
Fuel Commitments: To supply a portion of the fuel requirements for its
generating plants, the Company has entered into various commitments to obtain
nuclear fuel, coal, and natural gas. Some of these contracts contain
provisions for price escalation and minimum purchase commitments. At December
31, 1993,1994, WCNOC's nuclear fuel commitments (Company's share) were
approximately $18.0$12.6 million for uranium concentrates expiring at various times
through 1997, $123.6$122.9 million for enrichment expiring at various times through
2014, and $45.5$56.5 million for fabrication through 2012. At December 31, 1993,1994,
the Company's coal and natural gas contract commitments in 19931994 dollars under
the remaining termterms of the contracts were $2.8approximately $3 billion and $20.4$9
million, respectively. The largest coal contract was renegotiated early in 1993 and expires in 2020, with the
remaining coal contracts expiring at various times through 2013. The majority
of natural gas contracts continue through 1995 with automatic one-year
extension provisions. In the normal course of business, additional
commitments and spot market purchases will be made to obtain adequate fuel
supplies.
Energy Act: As part of the 1992 Energy Policy Act, a special assessment
is being collected from utilities for a uranium enrichment, decontamination,
and decommissioning fund. The Company'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.
5. RATE MATTERS AND REGULATION
The Company, under rate orders from certain state regulatory commissions
and the FERC, recovers increases in fuel and natural gas costs through fuel
adjustment clauses for wholesale and certain retail electric customers and
various purchased gas adjustment clauses (PGA) for natural gas customers.
Certain state regulatory commissions require the annual difference between
actual gas cost incurred and cost recovered through the application of the PGA
be deferred and amortized through rates in subsequent periods.
Elimination of the Energy Cost Adjustment Clause (ECA): On March 26,
1992, in connection with the Merger, the KCC approved the elimination of the
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.
MPSC Rate Proceedings: On October 5, 1993, the MPSC approved an agreement
among the Company, the MPSC staff, and intervenors to increase natural gas
rates $9.75 million annually, effective October 15, 1993. Also on October 15,
1993, the Company discontinued the deferral of service line replacement
program costs deferred since July 1, 1991, and began amortizing the balance to
expense over twenty years. At December 31, 1993, approximately $8.3 million
of these deferrals have been included in other deferred charges on the
consolidated balance sheet.
On January 22, 1992, the MPSC issued an order authorizing the Company to
increase natural gas rates $7.3 million annually.
KCC Rate Proceedings: On January 24, 1992, the KCC issued an order
allowing the Company to continue the deferral of service line replacement
program costs incurred since January 1, 1992, including depreciation, property
taxes, and carrying costs for recovery in the next general rate case. At
December 31, 1993, approximately $2.9 million of these deferrals have been
included in other deferred charges on the consolidated balance sheet.
On December 30, 1991, the KCC approved a permanent natural gas rate
increase of $39 million annually and the Company discontinued the deferral of
accelerated line survey costs on January 1, 1992. Approximately $8.3 million
of deferred costs remain in other deferred charges on the consolidated balance
sheet at December 31, 1993, with the balance being included in rates and
amortized to expense during a 43-month period, commencing January 1, 1992.
Gas Transportation Charges: On September 12, 1991, the KCC authorized the
Company to begin recovering, through the PGA, deferred supplier gas
transportation costs of $9.9 million incurred through December 31, 1990, based
on a three-year amortization schedule. On December 30, 1991, the KCC
authorized the Company to recover deferred transportation costs of
approximately $2.8 million incurred subsequent to December 31, 1990, through
the PGA over a 32-month period. At December 31, 1993, approximately $4.8
million of these deferrals remain in other deferred charges on the
consolidated balance sheet.
Tight Sands: In December 1991, the KCC, MPSC, and Oklahoma Corporation
Commission (OCC) approved agreements authorizing the Company to refund to
customers approximately $40 million of the proceeds of the Tight Sands
antitrust litigation settlement to be collected on behalf of Western
Resources' natural gas customers. To secure the refund of settlement
proceeds, the Commissions authorized the establishment of an independently
administered trust to collect and maintain cash receipts received under Tight
Sands settlement agreements and provide for the refunds made. The trust has a
term of ten years.
Rate Stabilization Plan: In 1988, the KCC issued an order requiring that
the accrual of phase-in revenues be discontinued by KG&E effective December
31, 1988. Effective January 1, 1989, KG&E began amortizing the phase-in
revenue asset on a straight-line basis over 9 1/2 years.
Coal Contract Settlements: In March 1990, the KCC issued an order
allowing KG&E to defer its share of a 1989 coal contract settlement with the
Pittsburgh and Midway Coal Mining Company amounting to $22.5 million. This
amount was recorded as a deferred charge on the consolidated balance sheets.
The settlement resulted in the termination of a long-term coal contract. The
KCC permitted KG&E to recover this settlement as follows: 76 percent of the
settlement plus a return over the remaining term of the terminated contract
(through 2002) and 24 percent to be amortized to expense with a deferred
return equivalent to the carrying cost of the asset.
In February 1991, KG&E paid $8.5 million to settle a coal contract lawsuit
with AMAX Coal Company and recorded the payment as a deferred charge on the
consolidated balance sheet. The KCC approved the recovery of the settlement
plus a return, equivalent to the carrying cost of the asset, over the
remaining term of the terminated contract (through 1996).
FERC Order No. 528: In 1990, the FERC issued Order No. 528 which
authorized new methods for the allocation and recovery of take-or-pay
settlement costs by natural gas pipelines from their customers. Settlements
have been reached between the Company's two largest gas pipelines and their
customers in FERC proceedings related to take-or-pay issues. The settlements
address the allocation of take-or-pay settlement costs between the pipelines
and their customers. However, the amount which one of the pipelines will be
allowed to recover is yet to be determined. Litigation continues between the
Company and a former upstream pipeline supplier to one of the Company's
pipeline suppliers concerning the amount of such costs which may ultimately be
allocated to the Company's pipeline supplier. A portion of any costs
allocated to the Company's pipeline supplier will be charged to the Company.
Due to the uncertainty concerning the amount to be recovered by the Company's
current suppliers and of the outcome of the litigation between the Company and
its current pipeline's upstream supplier, the Company is unable to estimate
its future liability for take-or-pay settlement costs. However, the KCC and
MPSC have approved mechanisms which are expected to allow the Company to
recover these take-or-pay costs from its customers.
6.8. EMPLOYEE BENEFIT PLANS
Pension: The Company maintains noncontributory defined benefit pension
plans covering substantially all employees. Pension benefits are based on
years of service and the employee's compensation during the five highest paid
consecutive years out of ten before retirement. The Company's policy is to
fund pension costs accrued, subject to limitations set by the Employee
Retirement Income Security Act of 1974 and the Internal Revenue Code.
52
The following tables provide information on the components of pension
cost, funded status, and actuarial assumptions for the Company's pension
plans:
Year Ended December 31, 1994 1993 1992 1991
(Dollars in Thousands)
Pension Cost:
Service cost...................cost. . . . . . . . . . $ 10,197 $ 9,778 $ 9,847 $ 6,589
Interest cost on projected
benefit obligation...........obligation. . . . . . 29,734 35,688 29,457
20,985
Return(Gain) loss on plan assets..........assets. . . 7,351 (64,113) (38,967)
(59,161)
Deferred investment gain on plan assets...(loss) (38,457) 29,190 7,705
38,015
Net amortization...............amortization. . . . . . . . 245 (669) (948)
(131)
Net pension cost...........cost. . . . . . $ 9,070 $ 9,874 $ 7,094
$ 6,297
December 31, 1994 1993 1992 1991
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of
benefit obligations:
Vested . . . . . . . . . . . $278,545 $353,023 $316,100 $200,435
Non-vested . . . . . . . . . 19,132 26,983 19,331 13,935
Total. . . . . . . . . . . $297,677 $380,006 $335,431 $214,370
Plan assets (principally debt
and equity securities) at
fair value . . . . . . . . . . . $375,521 $490,339 $452,372 $324,780
Projected benefit obligation . . . 378,146 468,996 424,232
282,062
Plan assets in excess of
projected benefit obligationFunded status. . . . . . . . . . . (2,625) 21,343 28,140 42,718
Unrecognized transition asset. . . (2,205) (2,756) (3,092) (1,253)
Unrecognized prior service costs . 47,796 64,217 55,886 27,216
Unrecognized net gain. . . . . . . (56,079) (108,783) (106,486) (69,494)
Accrued pension costs. . . . . . . $(13,113) $(25,979) $(25,552) $ (813)
Year Ended December 31, 1994 1993 1992 1991
Actuarial Assumptions:
Discount rate. . . . . . . . . . 8.0-8.5% 7.0-7.75% 8.0-8.5% 8.0%
Annual salary increase rate. . . 5.0 % 6.0%5.0% 5.0% 6.0%
Long-term rate of return . . . . 8.0-8.5 % 8.0-8.5% 8.0%8.0-8.5% 8.0-8.5%
Retirement and Voluntary Separation Plans: In January 1992, the Board of
Directors approved early retirement plans and voluntary separation programs.
The voluntary early retirement plans were offered to all vested participants
in the Company's defined pension plan who reached the age of 55 with 10 or
more years of service on or before May 1, 1992. Certain pension plan
improvements were made, including a waiver of the actuarial reduction factors
for early retirement and a cash incentive payable as a monthly supplement up
to 60 months or as a lump sum payment. Of the 738 employees eligible for the
early retirement option, 531, representing ten percent of the combined
Company's work force, elected to retire on or before the May 1, 1992,
deadline. Seventy-one of those electing to retire were employees of KG&E
acquired March 31, 1992 (see Note 3). Another 67 employees, with 10 or more
years of service, elected to participate in the voluntary separation program.
Of those, 29 were employees of KG&E. In addition, 68 employees received
53
Merger-related severance benefits, including 61 employees of KG&E. The
actuarial cost, based on plan provisions for early retirement and voluntary
separation programs, and Merger-related severance benefits for the KG&E
employees were considered in purchase accounting for the Merger. The
actuarial cost of the former Kansas Power and Light Company employees, of
approximately $11 million, was expensed in 1992.
Postretirement: The Company adopted the provisions of Statement of
Financial Accounting Standards No. 106 (SFAS 106) in the first quarter of
1993. This statement requires the accrual of postretirement benefits other
than pensions, primarily medical benefit costs, during the years an employee
provides service.
Based on actuarial projections and adoption of the transition method of
implementation which allows a 20-year amortization of the accumulated benefit
obligation, the annual expense under SFAS 106 expense was approximately $12.4 million and $26.5 million
infor 1994 and 1993, (as compared to approximately $9.6 million on a cash basis) and therespectively. The Company's total SFAS 106 obligation was
approximately $114.6 million and $166.5 million at December 31, 1993.1994 and 1993
respectively. The reduction in both the 1994 obligation and expense is
primarily the result of the sales of the Missouri Properties. To mitigate the
impact of SFAS 106 expense, the Company has implemented programs to reduce
health care costs. In addition, the Company has received ordersan order from the KCC and MPSC
permitting the initial deferral of SFAS 106 expense. To mitigate the impact
SFAS 106 expense will have on rate increases, the Company will include in the
future computation of cost of service the actual SFAS 106 expense and an
income stream generated from corporate-owned
life insurance (COLI).COLI. To the extent SFAS 106 expense exceeds
income from the COLI program, this excess will beis being deferred (as allowed by(in accordance
with the provisions of the FASB Emerging Issues Task Force Issue No. 92-12)
and will be offset by income generated through the deferral period by the COLI
program. The OCC is reviewing the Company's
application for similar treatment in Oklahoma. Should the OCC require
recognition of postretirement benefit costs for regulatory purposes under a
different method than that proposed
under the Company's application, the impact on earnings would not be material. Should the income stream generated by the COLI program not be
sufficient to offset the deferred SFAS 106 expense, the KCC and MPSC orders alloworder allows
recovery of such deficit through the ratemaking process.
Prior to the adoption of SFAS 106, the Company's policy was to recognize
the cost of retiree health care and life insurance benefits as expense when
claims and premiums for life insurance policies were paid. The cost of
providing health care and life insurance benefits to 2,928 retirees was $8.1
million in 1992.
The following table summarizes the status of the Company's postretirement
plans for financial statement purposes and the related amountamounts included in the
consolidated balance sheet:Consolidated Balance Sheets:
December 31, 1994 1993
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . . . . . . . . .$ 68,570 $ 111,499
Active employees fully eligible . . . . . . . .13,549 11,848
Active employees not fully eligible . . . . . .32,484 43,109
Unrecognized prior service cost . . . . . . . .9,391 18,195
Unrecognized transition obligation. . . . . . .(117,967) (160,731)
Unrecognized net loss gain (loss). . . . . . . . . . . . .14,489 (7,100)
Balance sheet liability . . . . . . . . . . . . . .$ 20,516 $ 16,82054
Year Ended December 31, 1994 1993
Assumptions:
Discount rate . . . . . . . . . . . . . . . . . 8.0-8.5 % 7.75%
Annual compensation increase rate . . . . . . . 5.0 % 5.0 %
Expected rate of return . . . . . . . . . . . . 8.5 % 8.5 %
For measurement purposes, an annual health care cost growth rate of 13%12%
was assumed for 1994, decreasing 1% per year to 6% by 20025% in 2001 and thereafter. The
accumulated post retirement benefit obligation was calculated using a
weighted-average discount rate of 7.75%, a weighted-average compensation
increase rate of 5.0%, and a weighted-average expected rate of return of 8.5%.
The health care cost trend rate has a significant effect on the projected
benefit obligation. Increasing the trend rate by 1% each year would increase
the present value of the accumulated projected benefit obligation by $11.1$4.7
million and the aggregate of the service and interest cost components by $1.5$0.3
million.
Postemployment: The FASB has issuedCompany adopted Statement of Financial Accounting
Standards No. 112 (SFAS 112), in the first quarter of 1994, which establishesestablished
accounting and reporting standards for postemployment benefits. The new statement
will requirerequires the Company to recognize the liability to provide postemployment
benefits when the liability has been incurred. The Company adoptedreceived an order
from the KCC permitting the initial deferral of SFAS 112 effective January
1, 1994.expense. To mitigate
the impact adopting SFAS 112 expense will have on rate increases, the Company will
file applications with the KCC and OCC for orders
permitting the initial deferral of SFAS 112 transition costs and expenses and
its inclusioninclude in the future computation of cost of service net ofthe actual SFAS 112
transition costs and expenses and an income stream generated from COLI. However, if the state regulatory commissions were
to recognize postemployment benefit costsThe
1994 expense under a different method, 1994
earnings could be impacted negatively.SFAS 112 was approximately $2.7 million. At December 31,
1993,1994, the Company
estimatesCompany's SFAS 112 liability to totalrecorded on the Consolidated Balance
Sheet was approximately $11$8.4 million.
Savings: The Company maintains savings plans in which substantially all
employees participate. The Company matches employees' contributions up to
specified maximum limits. The funds of the plans are deposited with a trustee
and invested at each employee's option in one or more investment funds,
including a Company stock fund. The Company's contributions were $5.4, $5.4,$5.1
million, $5.8 million, and $3.3$5.4 million for 1994, 1993, and 1992,
and 1991, respectively.
Missouri Property Sale: Effective January 31, 1994, the Company
transferred a portion of the assets and liabilities of the Company's pension
plan to a pension plan established by Southern Union. The amount of assets
transferred equal the projected benefit obligation for employees and retirees
associated with Southern Union's portion of the Missouri Properties plus an
additional $9 million.
7. FAIR VALUE55
9. JOINT OWNERSHIP OF FINANCIAL INSTRUMENTSUTILITY PLANTS
Company's Ownership at December 31, 1994
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 152,816 $ 98,124 343 50
Jeffrey 1 (b) Jul 1978 276,689 122,721 587 84
Jeffrey 2 (b) May 1980 285,579 109,743 600 84
Jeffrey 3 (b) May 1983 387,646 134,199 588 84
Wolf Creek (c) Sep 1985 1,376,335 317,311 545 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL)
(b) Jointly owned with UtiliCorp United Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
Amounts and capacity represent the Company's share. The following methodsCompany's share
of operating expenses of the plants in service above, as well as such expenses
for a 50 percent undivided interest in La Cygne 2 (representing 335 MW
capacity) sold and assumptions were usedleased back to estimate the fair valueCompany in 1987, are included in
operating expenses on the Consolidated Statements of each classIncome. The Company's
share of financial instruments for which itother transactions associated with the plants is practicable to estimate
that valueincluded in the
appropriate classification in the Company's Consolidated Financial Statements.
10. LEASES
At December 31, 1994, the Company had leases covering various property and
equipment. Certain lease agreements meet the criteria, as set forth in
Statement of Financial Accounting Standards No. 107:
Cash13, for classification as
capital leases.
Rental payments for capital and Cash Equivalents-
The carrying amount approximates the fair value because of the short-term
maturity of these investments.
Decommissioning Trust-
The fair value of the decommissioning trust is based on quoted market
prices at December 31, 1993operating leases and 1992.
Variable-rate Debt-
The carrying amount approximates the fair value because of the short-term
variable rates of these debt instruments.
Fixed-rate Debt-
The fair value of the fixed-rate debt is based on the sum of the
estimated value of each issue taking into consideration the interest
rate, maturity, and redemption provisions of each issue.
Redeemable Preference Stock-
The fair value of the redeemable preference stock is based on the sum of
the estimated value of each issue taking into consideration the dividend
rate, maturity, and redemption provisions of each issue.
The estimated fair values of the Company's financial instrumentsrental
commitments are as follows:
Carrying Value Fair ValueCapital Operating
Year Ended December 31, 1993 1992 1993 1992Leases Leases
(Dollars in Thousands)
Cash1992 $ 2,426 $ 52,701
1993 3,272 55,011
1994 2,987 55,076
Future Commitments:
1995 3,783 48,524
1996 3,627 46,211
1997 1,511 42,851
1998 - 41,464
1999 - 39,955
Thereafter - 753,062
Total $ 8,921 $972,067
Less Interest 784
Net obligation $ 8,137
In 1987, KG&E sold and cash
equivalents. . . . . . . $ 1,217 $ 875 $ 1,217 $ 875
Decommissioning trust. . . 13,204 9,272 13,929 9,500
Variable-rate debt . . . . 931,352 758,449 931,352 758,449
Fixed-rate debt. . . . . . 1,364,886 1,508,077 1,473,569 1,563,375
Redeemable preference
stock. . . . . . . . . . 150,000 152,733 160,780 161,733leased back its 50 percent undivided interest in
the La Cygne 2 generating unit. The La Cygne 2 lease has an initial term of
29 years, with various options to renew the lease or repurchase the 50 percent
undivided interest. KG&E remains responsible for its share of operation and
8.56
maintenance costs and other related operating costs of La Cygne 2. The lease
is an operating lease for financial reporting purposes.
As permitted under the La Cygne 2 lease agreement, the Company in 1992
requested the Trustee Lessor to refinance $341.1 million of secured facility
bonds of the Trustee and owner of La Cygne 2. The transaction was requested
to reduce recurring future net lease expense. In connection with the
refinancing on September 29, 1992, a one-time payment of approximately $27
million was made by the Company which has been deferred and is being amortized
over the remaining life of the lease and included in operating expense as part
of the future lease expense. At December 31, 1994, approximately $24.8
million of this deferral remained on the Consolidated Balance Sheet.
Future minimum annual lease payments, included in the table above,
required under the La Cygne 2 lease agreement are approximately $34.6 million
for each year through 1999 and $680 million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale of
La Cygne 2 has been deferred for financial reporting purposes, and is being
amortized ($9.6 million per year) over the initial lease term in proportion to
the related lease expense. KG&E's lease expense, net of amortization of the
deferred gain and a one-time payment, was approximately $22.5 million for 1994
and 1993, and $20.6 million for the nine months ended December 31, 1992.
11. LONG-TERM DEBT
The amount of first mortgage bonds authorized by the Western Resources
Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited.
The amount of first mortgage bonds authorized by the KG&E Mortgage and Deed of
Trust, dated April 1, 1940, as supplemented, is limited to a maximum of $2
billion. Amounts of additional bonds which may be issued are subject to
property, earnings, and certain restrictive provisions of each Mortgage.
On January 20, 1994, KG&E issued $100 million of First Mortgage Bonds,
6.20% Series due January 15, 2006.
On January 31, 1994, the Company redeemed the remaining $2,466,000
principal amount of Gas Service Company (GSC) 8 1/2% Series First Mortgage
Bonds due 1997. In addition, the Company took measures to havehad the GSC Mortgage and Deed of
Trust discharged.
Debt discount and expenses are being amortized over the remaining lives of
each issue. The Western Resources and KG&E improvement and maintenance fund
requirements for certain first mortgage bond series can be met by bonding
additional property. The sinking fund requirements forWith the retirement of certain Western Resources and
KG&E pollution control series bonds, can be met only through the
acquisition and retirement of outstanding bonds. Bonds maturing and
acquisition and retirementthere are no longer any bond sinking fund
requirements. During 1995, $80 thousand of bonds for sinking fund requirementswill be redeemed, during
1996, $16 million of bonds will mature and $125 million of bonds will mature
in 1999.
On November 1, 1994, the Company terminated a long-term agreement which
contained provisions for the five
years subsequentsale of accounts receivable and unbilled revenues
(receivables) and phase-in revenues up to a total of $180 million. Amounts
related to receivables were accounted for as sales while those related to
phase-in revenues were accounted for as collateralized borrowings. At
December 31, 1993, are as follows:
Maturing Retiring
Year Bonds Bonds
(Dollars in Thousands)
1994. . . . . $ 2,466 $ 738
1995. . . . . - 753
1996. . . . . 16,000 770
1997. . . . . - 1,333
1998. . . . . - 1,550outstanding receivables amounting to $56.8 million were
57
considered sold under the agreement. The weighted average interest rate,
including fees, on this agreement was 4.6% for 1994, 3.7% for 1993, and 6.6%
for the nine months ended December 31, 1992.
In January 1993, the Company renegotiated its $600 million bank term loan
and revolving credit facility used to finance the Merger into a $350 million
revolving credit facility, secured by KG&E common stock. On October 5, 1994,
the Company extended the term of this facility to expire on October 5, 1999.
The unused portion of the revolving credit facility may be used to provide
support for outstanding short-term debt. At December 31, 1994, there was no
outstanding balance under the facility.
58
Long-term debt outstanding at December 31, 19931994 and 1992,1993, was as follows:
1994 1993 1992
(Dollars in Thousands)
Western Resources
First mortgage bond series:
9.35 % due 1998. . . . . . . . . . . . . $ - $ 75,000
7 1/4% due 1999. . . . . . . . . . . . . 125,000 125,000
7 5/8% due 1999. . . . . . . . . . . . . 19,000 19,000
8 3/4% due 2000. . . . . . . . . . . . . - 20,00019,000
8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000
7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000
8 5/8% due 2005. . . . . . . . . . . . . - 35,000
8 1/8% due 2007. . . . . . . . . . . . . 30,000 30,000
8 3/4% due 2008. . . . . . . . . . . . . - 35,00030,000
8 5/8% due 2017. . . . . . . . . . . . . 50,000- 50,000
8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000
7.65% due 2023. . . . . . . . . . . . . 100,000 -100,000
525,000 624,000 689,000
Pollution control bond series:
5.90 % due 2007. . . . . . . . . . . . . - 31,000 31,500
6 3/4% due 2009. . . . . . . . . . . . . - 45,000
45,000
9 5/8%Variable due 2013. 2032 (1). . . . . . . . . . 45,000 -
Variable due 2032 (2). . . . . . . . . . 30,500 - 58,500
6% due 2033. . . . . . . . . . . . . 58,500 -58,500
134,000 134,500 135,000
KG&E
First mortgage bond series:
5 5/8% due 1996. . . . . . . . . . . . . 16,000 16,000
8 1/8% due 2001. . . . . . . . . . . . . - 35,000
7 3/8% due 2002. . . . . . . . . . . . . - 25,000
7.60%7.60 % due 2003. . . . . . . . . . . . . 135,000 135,000
6 1/2% due 2005. . . . . . . . . . . . . 65,000 -
8 3/8%65,000
6.20 % due 2006. . . . . . . . . . . . . 100,000 -
25,000
8 1/2% due 2007. . . . . . . . . . . . . - 25,000
8 7/8% due 2008. . . . . . . . . . . . . - 30,000316,000 216,000 291,000
Pollution control bond series:
6.80%6.80 % due 2004. . . . . . . . . . . . . 14,500- 14,500
5 7/8% due 2007. . . . . . . . . . . . . 21,940- 21,940
6% due 2007. . . . . . . . . . . . . - 10,000
10,000
7.0%5.10 % due 2023. . . . . . . . . . . . . 13,982 -
Variable due 2027 (3). . . . . . . . . . 21,940 -
7.0 % due 2031. . . . . . . . . . . . . 327,500 327,500
373,940Variable due 2032 (4). . . . . . . . . . 14,500 -
Variable due 2032 (5). . . . . . . . . . 10,000 -
387,922 373,940
GSC
First mortgage bond series:
8 1/2%2 % due 1997. . . . . . . . . . . . . - 2,466
4,932- 2,466 4,932
Bank term loan . . . . . . . . . . . . . . - 230,000
Other pollution control obligations. . . . - 13,980 14,205
Revolving credit agreement . . . . . . . . - 115,000
150,000
Other long termlong-term agreement. . . . . . . . . - 53,913 46,640
Less:
Unamortized debt discount. . . . . . . . 5,814 6,607 6,730
Long-term debt due within one year . . . 80 3,204
1,961$1,357,028 $1,523,988
$1,926,026
In January 1993, the Company renegotiated its $600 million bank term loanRates at December 31, 1994: (1) 3.94%, (2) 4.05%, (3) 4.10%,
(4) 4.10% and revolving credit facility used to finance the Merger into a $350 million
revolving credit facility, secured by KG&E(5) 4.10%
59
12. COMMON STOCK AND CUMULATIVE PREFERRED AND PREFERENCE STOCK
The Company's Restated Articles of Incorporation, as amended, provides for
85,000,000 authorized shares of common stock. The revolver has an
initial term of three years with options to renew for an additional two years
with the consent of the banks. The unused portion of the revolving credit
facility may be used to provide support for outstanding short-term debt. At December 31, 1993, $115 million was outstanding1994,
61,617,873 shares were outstanding.
The Company has a Customer Stock Purchase Plan (CSPP) and a Dividend
Reinvestment and Stock Purchase Plan (DRIP). Shares issued under the facility.
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.
KG&E has a long-term agreement, expiring in 1995, which contains
provisions forCSPP and
DRIP may be either original issue shares or shares purchased on 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. Additional
receivables are continually sold to replace those collected.open
market. At December 31, 1993 and 1992, outstanding receivables amounting to $56.8 and $47.7 million,
respectively,1994, 2,031,794 shares were considered sold under the agreement. The credit risk
associated with the sale of customer accounts receivable is considered
minimal. The weighted average interest rate, including fees, was 3.7% for the
year ended December 31, 1993, and 6.6% for the nine months ended December 31,
1992. At December 31, 1993, an additional $16.4 million was available under the agreement.
9. SHORT-TERM DEBTCSPP
registration statement and 1,183,323 shares were available under the DRIP
registration statement.
Not subject to mandatory redemption: The Company's short-term financing requirements are satisfied, as needed,
throughcumulative preferred stock is
redeemable in whole or in part on 30 to 60 days notice at the saleoption of commercial paper, short-term bank loans and borrowings
under other unsecured linesthe
Company.
Subject to mandatory redemption: The mandatory sinking fund provisions of
credit maintained with banks. Information
concerning these arrangements for the years ended December 31, 1993, 1992, and
1991, is set forth below:
Year Ended December 31, 1993 1992 1991
(Dollars in Thousands)
Lines of credit at year end. . . . $145,000 $250,000(1) $185,000(2)
Short-term debt out-
standing at year end . . . . . . 440,895 222,225 135,800
Weighted average interest rate
on debt outstanding at year
end (including fees) . . . . . . 3.67% 4.70% 5.07%
Maximum amount of short-
term debt outstanding during
the period. . . .. . . . . . . . $443,895 $263,900 $175,000
Monthly average short-term debt. . 347,278 179,577 125,968
Weighted daily average interest
rates during the year
(including fees) . . . . . . . . 3.44% 4.90% 6.69%
(1) Decreased to $155 million in January 1993.
(2) Increased to $200 million in January 1992.
In connection with the commitments,8.50% Series preference stock require the Company has agreed to payredeem 50,000 shares
annually beginning on July 1, 1997, at $100 per share. The Company may, at
its option, redeem up to an additional 50,000 shares on each July 1, at $100
per share. The 8.50% Series also is redeemable in whole or in part, at the
option of the Company, subject to certain feesrestrictions on refunding, at a
redemption price of $106.80, $106.23 and $105.67 per share beginning July 1,
1994, 1995 and 1996, respectively.
The mandatory sinking fund provisions of the 7.58% Series preference stock
require the Company to the banks. Available lines of creditredeem 25,000 shares annually beginning on April 1,
2002, and each April 1 through 2006 and the unused portionremaining shares on April 1, 2007,
all at $100 per share. The Company may, at its option, redeem up to an
additional 25,000 shares on each April 1 at $100 per share. The 7.58% Series
also is redeemable in whole or in part, at the option of the revolving credit facility are utilizedCompany, subject
to support the Company's outstanding
short-term debt.
10. LEASES
At December 31, 1993, the Company had leases covering various propertycertain restrictions on refunding, at a redemption price of $106.06,
$105.31, and equipment. Certain lease agreements meet the criteria, as set forth in
Statement of Financial Accounting Standards No. 13, for classification as
capital leases.
Rental payments for capital$104.55 per share beginning April 1, 1994, 1995, and operating leases and estimated rental
commitments are as follows:
Capital Operating
Year Ending December 31, Leases Leases
(Dollars in Thousands)
1991 $ 1,217 $21,501
1992 2,426 52,701
1993 3,272 55,011
Future Commitments:
1994 $ 4,002 $47,729
1995 3,752 45,825
1996,
3,627 44,176
1997 1,209 41,644
1998 - 41,019
Thereafter - 771,157
Total $12,590 $ 991,550
Less Interest 1,466
Net obligation $11,124
In 1987, KG&E sold and leased back its 50 percent undivided interest in La
Cygne 2. The lease has an initial term of 29 years, with various options to
renew the lease or repurchase the 50 percent undivided interest. KG&E remains
responsible for its share of operation and maintenance costs and other related
operating costs of La Cygne 2. The lease is an operating lease for financial
reporting purposes.
As permitted under the lease agreement, the Company in 1992 requested the
Trustee Lessor to refinance $341.1 million of secured facility bonds of the
Trustee and owner of La Cygne 2. The transaction was requested to reduce
recurring future net lease expense. In connection with the refinancing on
September 29, 1992, a one-time payment of approximately $27 million was made
by the Company which has been deferred and is being amortized over the
remaining life of the lease and included in operating expense as part of the
future
lease expense.
Future minimum annual lease payments, included in the table above,
required under the lease agreement are approximately $34.6 million for each
year through 1998 and $715 million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale
has been deferred for financial reporting purposes, and is being amortized
over the initial lease term in proportion to the related lease expense.
KG&E's lease expense, net of amortization of the deferred gain and a one-time
payment, was approximately $22.5 million for the year ended December 31, 1993,
and $20.6 million for the nine months ended December 31, 1992.
11. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1993
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 150,265 $ 91,175 342 50
Jeffrey 1 (b) Jul 1978 277,087 116,526 587 84
Jeffrey 2 (b) May 1980 274,018 106,301 566 84
Jeffrey 3 (b) May 1983 386,925 124,158 588 84
Wolf Creek (c) Sep 1985 1,366,387 281,819 533 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL)
(b) Jointly owned with UtiliCorp United Inc. and a third party
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
Amounts and capacity represent the Company's share. The Company's share
of operating expenses of the plants in service above, as well as such expenses
for a 50 percent undivided interest in La Cygne 2 (representing 335 MW
capacity) sold and leased back to the Company in 1987, are included in
operating expenses in the statements of income. The Company's share of other
transactions associated with the plants is included in the appropriate
classification in the Company's consolidated financial statements.
12.respectively.
13. INCOME TAXES
The Company adopted the provisions of SFAS 109 in the first quarter of
1992. KG&E adopted the provisions of SFAS 96 in 1987 and SFAS 109 in 1992.
These statements require the Company to establish deferred tax assets and
liabilities, as appropriate, for all temporary differences, and to adjust
deferred tax balances to reflect changes in tax rates expected to be in effect
during the periods the temporary differences reverse.
In accordance with various rate orders received from the KCC the MPSC, and the OCC,
the Company has not yet collected through rates the amounts necessary to pay a
significant portion of the net deferred income tax liabilities. As management
believes it is probable that the net future increases in income taxes payable
will be recovered from customers through future rates, it has recorded a
deferred asset for these amounts. These assets are also a temporary
difference for which deferred income tax liabilities have been provided.
Accordingly, the adoption of SFAS 109 did not have a material impact on the
Company's results of operations.
60
At December 31, 1993, KG&E has unused investment tax credits of
approximately $7.1 million available for carryforward which, if not utilized,
will expire in the years 2000 through 2002. In addition,1994, the Company has alternative minimum tax credits
generated prior to April 1, 1992, which carryforward without expiration, of
$57.2$41.2 million which may be used to offset future regular tax to the extent the
regular tax exceeds the alternative minimum tax. These credits have been
applied in determining the Company's net deferred income tax liability and
corresponding deferred future income taxes at December 31, 1993.1994.
Deferred income taxes result from temporary differences between the
financial statement and tax basis of the Company's assets and liabilities. The
sources of these differences and their cumulative tax effects are as follows:
December 31, 1994
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (661,433) $ (661,433)
Energy and purchased gas
adjustment clauses . . . . . . . - (1,441) (1,441)
Phase-in revenues. . . . . . . . . - (27,677) (27,677)
Natural gas line survey and
replacement program. . . . . . . - (4,083) (4,083)
Deferred gain on sale-leaseback. . 110,556 - 110,556
Alternative minimum tax credits. . 41,163 - 41,163
Deferred coal contract
settlements. . . . . . . . . . . - (12,966) (12,966)
Deferred compensation/pension
liability. . . . . . . . . . . . 12,284 - 12,284
Acquisition premium. . . . . . . . - (318,190) (318,190)
Deferred future income taxes . . . - (101,886) (101,886)
Loss on reacquisition of debt. . . - (10,792) (10,792)
Prepaid power sale . . . . . . . . 16,878 - 16,878
Other. . . . . . . . . . . . . . . - (13,427) (13,427)
Total Deferred Income Taxes. . . . . $ 180,881 $(1,151,895) $ (971,014)
December 31, 1993
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (647,202)(653,592) $ (647,202)(653,592)
Energy and purchased gas
adjustment clauses . . . . . . . 2,452 - 2,452
Phase-in revenues. . . . . . . . . - (35,573) (35,573)
Natural gas line survey and
replacement program. . . . . . . - (7,721) (7,721)
Deferred gain on sale-leaseback. . 116,186 - 116,186
Alternative minimum tax credits. . 39,882 - 39,882
Deferred coal contract
settlements. . . . . . . . . . . - (14,980) (14,980)
Deferred compensation/pension
liability. . . . . . . . . . . . 11,301 - 11,301
Acquisition premium. . . . . . . . - (301,394) (301,394)
Deferred future income taxes . . . - (117,549) (117,549)(111,159) (111,159)
Loss on reacquisition of debt. . . - (9,298) (9,298)
Other. . . . . . . . . . . . . . . - (14,039) (14,039)(4,741) (4,741)
Total Deferred Income Taxes. . . . . $ 169,821 $(1,138,458) $ (968,637)$(968,637)
December 31, 1992
Debits Credits Total
(Dollars in Thousands)
Sources of Deferred Income Taxes:
Accelerated depreciation and
other property items . . . . . . $ - $ (607,303) $ (607,303)
Energy and purchased gas
adjustment clauses . . . . . . . - (7,717) (7,717)
Phase-in revenues. . . . . . . . . - (37,564) (37,564)
Natural gas line survey and
replacement program. . . . . . . - (7,473) (7,473)
Deferred gain on sale-leaseback. . 104,573 - 104,573
Alternative minimum tax credits. . 39,882 - 39,882
Deferred coal contract
settlements. . . . . . . . . . . - (9,318) (9,318)
Deferred compensation/pension
liability. . . . . . . . . . . . 8,488 - 8,488
Acquisition premium. . . . . . . . - (314,241) (314,241)
Deferred future income taxes . . . - (158,102) (158,102)
Other. . . . . . . . . . . . . . . - (1,380) (1,380)
Total Deferred Income Taxes. . . . . $ 152,943 $(1,143,098) $ (990,155)
13.61
14. SEGMENTS OF BUSINESS
The Company is a public utility engaged in the generation, transmission,
distribution, and sale of electricity in Kansas and the transportation,
distribution, and sale of natural gas in Kansas Missouri, and Oklahoma.
Year Ended December 31, 1994(1) 1993 1992(1) 19911992(2)
(Dollars in Thousands)
Operating revenues:
Electric. . . . . . . . . . . $1,121,781 $1,104,537 $ 882,885 $ 471,839
Natural gas . . . . . . . . . 496,162 804,822 673,363
690,3391,617,943 1,909,359 1,556,248 1,162,178
Operating expenses excluding
income taxes:
Electric. . . . . . . . . . . 768,317 791,563 632,169 337,150
Natural gas . . . . . . . . . 484,458 747,755 642,910
664,8251,252,775 1,539,318 1,275,079 1,001,975
Income taxes:
Electric. . . . . . . . . . . 100,078 73,425 41,184 32,239
Natural gas . . . . . . . . . (4,456) 4,553 816
(1,657)95,622 77,978 42,000 30,582
Operating income:
Electric. . . . . . . . . . . 253,386 239,549 209,532 102,450
Natural gas . . . . . . . . . 16,160 52,514 29,637
27,171$ 269,546 $ 292,063 $ 239,169 $ 129,621
Identifiable assets at
December 31:
Electric. . . . . . . . . . . $4,346,312 $4,231,277 $4,390,117 $1,196,023
Natural gas . . . . . . . . . 654,483 1,040,513 918,729
840,692
Other corporate assets(2)assets(3) . . 188,823 140,258 130,060
75,798$5,189,618 $5,412,048 $5,438,906 $2,112,513
Other Information--
Depreciation and amortization:
Electric. . . . . . . . . . . $ 123,696 $ 126,034 $ 105,842 $ 53,632
Natural gas . . . . . . . . . 27,934 38,330 38,171
32,103$ 151,630 $ 164,364 $ 144,013 $ 85,735
Maintenance:
Electric. . . . . . . . . . . $ 88,162 $ 87,696 $ 73,104 $ 34,240
Natural gas . . . . . . . . . 25,024 30,147 28,507
26,275$ 113,186 $ 117,843 $ 101,611 $ 60,515
Capital expenditures:
Electric. . . . . . . . . . . $ 152,384 $ 137,874 $ 95,465 $ 43,714
Nuclear fuel. . . . . . . . . 20,590 5,702 15,839 -
Natural gas . . . . . . . . . 64,722 94,055 91,189
81,961$ 237,696 $ 237,631 $ 202,493
$ 125,675
(1)Information reflects the sales of the Missouri Properties (Note 2).
(2)Information reflects the merger with KG&E on March 31, 1992.
(2)1992 (Note 3).
(3)Principally cash, temporary cash investments, non-utility assets, and
deferred charges.
62
The portion of the table above related to the Missouri Properties is as
follows (unaudited):follows:
1994 1993 1992
(Dollars in Thousands)Thousands, Unaudited)
Natural gas revenues. . . . . . . . . . $ 349,74977,008 $349,749 $299,202
Operating expenses excluding
income taxes. . . . . . . . .69,114 326,329 288,558
Income taxes. . . . . . . . . . . . . .2,897 2,672 (533)
Operating income. . . . . . . . . . . .4,997 20,748 11,177
Identifiable assets . . . . . . . . . .- 398,464 361,612
Depreciation and amortization . . . . .1,274 12,668 13,172
Maintenance . . . . . . . . . . . . . .1,099 10,504 9,640
Capital expenditures. . . . . . . . . .3,682 38,821 14. COMMON STOCK AND CUMULATIVE PREFERRED AND PREFERENCE STOCK36,669
15. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's Restated Articlesfollowing methods and assumptions were used to estimate the fair value
of Incorporation,each class of financial instruments for which it is practicable to estimate
that value as amended, provides for
85,000,000 authorized sharesset forth in Statement of common stock. During 1993,Financial Accounting Standards No.
107:
Cash and Cash Equivalents-
The carrying amount approximates the Company issued
3,572,323 sharesfair value because of common stock andthe short-term
maturity of these investments.
Decommissioning Trust-
The fair value of the decommissioning trust is based on quoted market
prices at December 31, 1993, 61,617,873 shares
were outstanding.
Not subject to mandatory redemption:1994 and 1993.
Variable-rate Debt-
The cumulative preferredcarrying amount approximates the fair value because of the short-term
variable rates of these debt instruments.
Fixed-rate Debt-
The fair value of the fixed-rate debt is based on the sum of the
estimated value of each issue taking into consideration the interest
rate, maturity, and redemption provisions of each issue.
Redeemable Preference Stock-
The fair value of the redeemable preference stock is redeemable in whole or in partbased on 30 to 60 days notice at the optionsum of
the Company.
Subject to mandatory redemption: On October 1, 1993,estimated value of each issue taking into consideration the Company redeemed
the remaining 22,000 sharesdividend
rate, maturity, and redemption provisions of each issue.
The estimated fair values of the 8.70% SeriesCompany's financial instruments are as
follows:
Carrying Value Fair Value
December 31, 1994 1993 1994 1993
(Dollars in Thousands)
Cash and cash
equivalents. . . . . . . $ 2,715 $ 1,217 $ 2,715 $ 1,217
Decommissioning trust. . . 16,944 13,204 16,633 13,929
Variable-rate debt . . . . 822,045 931,352 822,045 931,352
Fixed-rate debt. . . . . . 1,240,982 1,364,886 1,171,866 1,473,569
Redeemable preference
stock. . . . . . . . . . 150,000 150,000 155,375 160,780
63
The mandatory sinking fund provisionsfair value estimates presented herein are based on information
available as of the 8.50% Series preference stock
require the Company to redeem 50,000 shares annually beginning on July 1,
1997, at $100 per share. The Company may, at its option, redeem up to an
additional 50,000 shares on each July 1, at $100 per share. The 8.50% Series
also is redeemable in whole or in part, at the option of the Company, subject
to certain restrictions on refunding, at a redemption price of $107.37,
$106.80, and $106.23 per share beginning July 1, 1993,December 31, 1994 and 1995,
respectively.
The mandatory sinking fund provisions1993. These fair value estimates have
not been comprehensively revalued for the purpose of the 7.58% Series preference stock
require the Company to redeem 25,000 shares annually beginning on April 1,
2002, and each April 1 through 2006 and the remaining shares on April 1, 2007,
all at $100 per share. The Company may, at its option, redeem up to an
additional 25,000 shares on each April 1 at $100 per share. The 7.58% Series
also is redeemable in whole or in part, at the option of the Company, subject
to certain restrictions on refunding, at a redemption price of $106.82,
$106.06, and $105.31 per share beginning April 1, 1993, 1994, and 1995,
respectively.
15. LEGAL PROCEEDINGS
The Company and its subsidiaries are involved in various legal and
environmental proceedings. Management believes that adequate provision has
been made within the consolidatedthese financial
statements for these matterssince that date, and accordingly believes their ultimate dispositions will not have a material
adverse effect uponcurrent estimates of fair value may differ
significantly from the business, financial position, or results of operations
of the Company.amounts presented herein.
16. QUARTERLY RESULTS (UNAUDITED)
The amounts in the table are unaudited but, in the opinion of management,
contain all adjustments (consisting only of normal recurring adjustments)
necessary for a fair presentation of the results of such periods. The
business of the Company is seasonal in nature and, in the opinion of
management, comparisons between the quarters of a year do not give a true
indication of overall trends and changes in operations.
First Second Third Fourth
(Dollars in Thousands, except Per Share Amounts)
1994(1)
Operating revenues. . . . . . . $538,372 $341,132 $379,213 $359,226
Operating income. . . . . . . . 73,782 53,899 83,884 57,981
Net income. . . . . . . . . . . 66,133 30,247 57,679 33,388
Earnings applicable to
common stock. . . . . . . . . 62,779 26,892 54,324 30,034
Earnings per share. . . . . . . $ 1.02 $ 0.44 $ 0.88 $ 0.48
Dividends per share . . . . . . $ 0.495 $ 0.495 $ 0.495 $ 0.495
Average common shares
outstanding . . . . . . . . . 61,618 61,618 61,618 61,618
Common stock price:
High. . . . . . . . . . . . . $ 34 7/8 $ 29 3/4 $ 29 5/8 $ 29 1/4
Low . . . . . . . . . . . . . $ 28 1/4 $ 26 1/8 $ 26 3/4 $ 27 3/8
1993
Operating revenues. . . . . . . $579,581 $400,411 $419,018 $510,349
Operating income. . . . . . . . 85,950 60,282 81,225 64,606
Net income. . . . . . . . . . . 54,814 30,723 56,807 35,026
Earnings applicable to
common stock. . . . . . . . . 51,468 27,320 53,405 31,671
Earnings per share. . . . . . . $ 0.89 $ 0.47 $ 0.90 $ 0.51
Dividends per share . . . . . . $ 0.485 $ 0.485 $ 0.485 $ 0.485
Average common shares
outstanding . . . . . . . . . 58,046 58,046 59,441 61,603
Common stock price:
High. . . . . . . . . . . . . $ 35 3/4 $ 36 1/8 $ 37 1/4 $ 37
Low . . . . . . . . . . . . . $ 30 3/8 $ 32 3/4 $ 35 $ 32 3/4
1992(1)
Operating revenues. . . . . . . $373,620 $341,715 $380,745 $460,168
Operating income. . . . . . . . 42,684 45,830 77,010 73,645
Net income. . . . . . . . . . . 27,984 18,434 42,185 39,281
Earnings applicable to
common stock. . . . . . . . . 25,472 15,113 38,726 35,822
Earnings per share. . . . . . . $ 0.74 $ 0.26 $ 0.67 $ 0.62
Dividends per share . . . . . . $ 0.475 $ 0.475 $ 0.475 $ 0.475
Average common shares
outstanding . . . . . . . . . 34,566 58,046 58,046 58,046
Common stock price:
High. . . . . . . . . . . . . $ 29 1/2 $ 26 7/8 $ 30 1/2 $ 32 5/8
Low . . . . . . . . . . . . . $ 25 3/8 $ 25 1/4 $ 26 3/4 $ 28 1/2
(1) Information reflects the merger with KG&E on March 31, 1992.sales of the Missouri Properties (Note 2).
64
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information relating to the Company's Directors required by Item 10 is
set forth in the Company's definitive proxy statement for its 19941995 Annual
Meeting of Shareholders to be filed with the Commission. Such information is
incorporated herein by reference to the material appearing under the caption
Election of Directors in the proxy statement to be filed by the Company with
the Commission. See EXECUTIVE OFFICERS OF THE COMPANY on page 1819 for the
information relating to the Company's Executive Officers as required by Item
10.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is set forth in the Company's
definitive proxy statement for its 19941995 Annual Meeting of Shareholders to be
filed with the Commission. Such information is incorporated herein by
reference to the material appearing under the captions Information Concerning
the Board of Directors, Executive Compensation, Compensation Plans, and Human
Resources Committee Report in the proxy statement to be filed by the Company
with the Commission.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is set forth in the Company's
definitive proxy statement for its 19941995 Annual Meeting of Shareholders to be
filed with the Commission. Such information is incorporated herein by
reference to the material appearing under the caption Beneficial Ownership of
Voting Securities in the proxy statement to be filed by the Company with the
Commission.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 is set forth in the Company's
definitive proxy statement for its 1994 Annual Meeting of Shareholders to be
filed with the Commission. Such information is incorporated herein by
reference to the material appearing under the caption Transactions with
Management in the proxy statement to be filed by the Company with the
Commission.None.
65
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
The following financial statements are included herein.
FINANCIAL STATEMENTS
Report of Independent Public Accountants
Consolidated Balance Sheets, - December 31, 1994 and 1993
Consolidated Statements of Income, for the years ended December 31, 1994,
1993 and 1992
Consolidated Statements of Income -Cash Flows, for the years ended December 31,
1993,
1992 and 1991
Consolidated Statements of Cash Flows - years ended December 31,
1993, 1992 and 1991
Consolidated Statements of Taxes - years ended December 31, 1993,
1992 and 1991
Consolidated Statements of Capitalization - December 31,1994, 1993 and 1992
Consolidated Statements of Common Stock Equity -Taxes, for the years ended December 31, 1994,
1993 and 1992
Consolidated Statements of Capitalization, December 31, 1994 and
19911993
Consolidated Statements of Common Stock Equity, for the years ended
December 31, 1994, 1993 and 1992
Notes to Consolidated Financial Statements
The following supplemental schedules are included herein.
SCHEDULES
Schedule V - Utility Plant - years ended December 31, 1993, 1992 and 1991
Schedule VI - Accumulated Depreciation of Utility Plant - years ended
December 31, 1993, 1992 and 1991
Schedules omitted as not applicable or not required under the Rules of
regulation S-X: I, II, III, IV, VII, VIII, IX, X, XI, XII, and XIIIV
REPORTS ON FORM 8-K
Form 8-K dated February 2, 1994January 25, 1995.
66
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
3(a) -Restated Articles of Incorporation of the Company, as amended I
May 25, 1988. (filed as Exhibit 4 to Registration Statement
No. 33-23022)
3(b) -Certificate of Correction to Restated Articles of Incorporation. I
(filed as Exhibit 3(b) to the December 1991 Form 10-K)
3(c) -Amendment to the Restated Articles of Incorporation, as amended
May 5, 1992 (filed electronically)
3(d) -Amendments to the Restated Articles of Incorporation of the I
Company (filed as Exhibit 3 to the June 1994 Form 10-Q)
3(e) -By-laws of the Company, as amended July 15, 1987. (filed as I
Exhibit 3(d) to the December 1987 Form 10-K)
3(d)3(f) -Certificate of Designation of Preference Stock, 8.50% Series, I
without par value. (filed electronically)
3(e)as Exhibit 3(d) to the December
1993 Form 10-K)
3(g) -Certificate of Designation of Preference Stock, 7.58% Series, I
without par value. (filed electronically)as Exhibit 3(e) to the December
1993 Form 10-K)
4(a) -Mortgage and Deed of Trust dated July 1, 1939 between the Company I
and Harris Trust and Savings Bank, Trustee. (filed as Exhibit
4(a) to Registration Statement No. 33-21739)
4(b) -First through Fifteenth Supplemental Indentures dated July 1, I
1939, April 1, 1949, July 20, 1949, October 1, 1949, December 1,
1949, October 4, 1951, December 1, 1951, May 1, 1952, October 1,
1954, September 1, 1961, April 1, 1969, September 1, 1970,
February 1, 1975, May 1, 1976 and April 1, 1977, respectively.
(filed as Exhibit 4(b) to Registration Statement No. 33-21739)
4(c) -Sixteenth Supplemental Indenture dated June 1, 1977. (filed as I
Exhibit 2-D to Registration Statement No. 2-60207)
4(d) -Seventeenth Supplemental Indenture dated February 1, 1978. I
(filed as Exhibit 2-E to Registration Statement No. 2-61310)
4(e) -Eighteenth Supplemental Indenture dated January 1, 1979. (filed I
as Exhibit (b) (1)-9 to Registration Statement No. 2-64231)
4(f) -Nineteenth Supplemental Indenture dated May 1, 1980. (filed as I
Exhibit 4(f) to Registration Statement No. 33-21739)
4(g) -Twentieth Supplemental Indenture dated November 1, 1981. (filed I
as Exhibit 4(g) to Registration Statement No. 33-21739)
4(h) -Twenty-First Supplemental Indenture dated April 1, 1982. (filed I
as Exhibit 4(h) to Registration Statement No. 33-21739)
4(i) -Twenty-Second Supplemental Indenture dated February 1, 1983. I
(filed as Exhibit 4(i) to Registration Statement No. 33-21739)
4(j) -Twenty-Third Supplemental Indenture dated July 2, 1986. (filed I
as Exhibit 4(j) to Registration Statement No. 33-12054)
4(k) -Twenty-Fourth Supplemental Indenture dated March 1, 1987. (filed I
as Exhibit 4(k) to Registration Statement No. 33-21739)
4(l) -Twenty-Fifth Supplemental Indenture dated October 15, 1988. I
(filed as Exhibit 4 to the September 1988 Form 10-Q)
4(m) -Twenty-Sixth Supplemental Indenture dated February 15, 1990. I
(filed as Exhibit 4(m) to the December 1989 Form 10-K)
67
Description
4(n) -Twenty-Seventh Supplemental Indenture dated March 12, 1992. I
(filed as exhibit 4(n) to the December 1991 Form 10-K)
4(o) -Twenty-Eighth Supplemental Indenture dated July 1, 1992. I
(filed as exhibit 4(o) to the December 1992 Form 10-K)
4(p) -Twenty-Ninth Supplemental Indenture dated August 20, 1992. I
(filed as exhibit 4(p) to the December 1992 Form 10-K)
Description
4(q) -Thirtieth Supplemental Indenture dated February 1, 1993. I
(filed as exhibit 4(q) to the December 1992 Form 10-K)
4(r) -Thirty-First Supplemental Indenture dated April 15, 1993. I
(filed as exhibit 4(r) to Form S-3, Registration Statement
No. 33-50069)
4(s) -Thirty-Second Supplemental Indenture dated April 15, 1994,
(filed electronically)
Instruments defining the rights of holders of other long-term debt not
required to be filed as exhibits will be furnished to the Commission
upon request.
10(a) -A Rail Transportation Agreement among Burlington Northern I
Railroad Company, the Union Pacific Railroad Company and the
Company (filed as Exhibit 10 to the June 1994 Form 10-Q)
10(b) -Agreement between the Company and AMAX Coal West Inc. I
effective March 31, 1993. (filed electronically)
10(b) -Agreement betweenas Exhibit 10(a) to the
Company and Williams Natural Gas Company
dated October 1, 1993. (filed electronically)December 1993 Form 10-K)
10(c) -Agreement between the Company and Williams Natural Gas Company I
dated October 1, 1993. (filed electronically)as Exhibit 10(b) to the
December 1993 Form 10-K)
10(d) -Agreement between the Company and Williams Natural Gas Company I
dated October 1, 1993. (filed electronically)as Exhibit 10(c) to the
December 1993 Form 10-K)
10(e) -Agreement between the Company and Williams Natural Gas Company I
dated October 1, 1993. (filed as Exhibit 10(d) to the
December 1993 Form 10-K)
10(f) -Executive Salary Continuation Plan of The Kansas Power and Light I
Company, as revised, effective May 3, 1988. (filed as Exhibit
10(b) to the September 1988 Form 10-Q)
10(f)10(g) -Letter of Agreement between The Kansas Power and Light Company I
and I John E. Hayes, Jr., dated November 20, 1989. (filed as
Exhibit 10(w) to the December 1989 Form 10-K)
10(g)10(h) -Amended Agreement and Plan of Merger by and among The Kansas I
Power and Light Company, KCA Corporation, and Kansas Gas and
Electric Company, dated as of October 28, 1990, as amended by
Amendment No. 1 thereto, dated as of January 18, 1991. (filed
as Annex A to Registration Statement No. 33-38967)
10(h)10(i) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I
December 1993 Form 10-K)
10(j) -Long-term Incentive Plan (filed as Exhibit 10(j) to the I
December 1993 Form 10-K)
10(k) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I
December 1993 Form 10-K)
10(l) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I
10(l) to the December 1993 Form 10-K)
68
Description
12 -Computation of Ratio of Consolidated Earnings to Fixed Charges.
(filed electronically)
16 -Letter re Change in Certifying Accountant. (filed as Exhibit 16 I
to the Current Report on Form 8-K dated March 8, 1993)
21 -Subsidiaries of the Registrant. (filed as Exhibit 22 to the I
December 1992 Form 10-K)electronically)
23(a) -Consent of Independent Public Accountants, Arthur Andersen & Co.LLP
(filed electronically)
23(b) -Consent of Independent Public Accountants, Deloitte & Touche LLP
(filed electronically))
23(c) -Consent of K&A Energy Consultants, Inc.
27 -Financial Data Schedules (filed as Exhibit 24(b) I
to the December 1988 Form 10-K)
99(a)electronically)
99 -Kansas Gas and Electric Company's Annual Report on Form 10-K
for the year ended December 31, 19931994 (filed electronically)
99(b) -Report of K&A Energy Consultants, Inc. (filed as Exhibit 28 to I
the December 1988 Form 10-K)
WESTERN RESOURCES, INC.
Schedule V - Utility Plant
For the Year Ended December 31, 1993
Balance at Transfers, Balance
Beginning Additions Retire- Reclassi- at End
Classification of Period at Cost ments fication of Period
(Thousands of Dollars)
Electric Plant:
Steam Production. . . . . . . . $1,367,730 $ 52,064 $ 7,406 $ (7,154) $1,405,234
Nuclear Production. . . . . . . 1,355,678 11,324 614 - 1,366,388
Internal Combustion
Production. . . . . . . . . . 34,273 1,374 445 - 35,202
Transmission. . . . . . . . . . 499,775 7,082 1,296 27 505,588
Distribution. . . . . . . . . . 809,617 43,216 4,859 (138) 847,836
General . . . . . . . . . . . . 111,666 15,211 2,658 13 124,232
Electric Plant Leased
to Others . . . . . . . . . . 6,984 - - - 6,984
Construction Work in Progress . 49,068 10,230 - - 59,298
Electric Plant Held for Future
Use . . . . . . . . . . . . . 25,290 5 129 7,109 32,275
Nuclear Fuel. . . . . . . . . . 59,305 6,764 19,381 - 46,688
Plant Acquisition Adjustment. . 796,265 1,347 21 (12,089) 785,502
5,115,651 148,617 36,809 (12,232) 5,215,227
Natural Gas Plant:
Production and Gathering. . . . 9,704 24 23 5 9,710
Underground Storage . . . . . . 5,951 9,135 - - 15,086
Transmission. . . . . . . . . . 97,480 6,258 967 (26) 102,745
Distribution. . . . . . . . . . 845,332 70,694 4,712 29 911,343
General . . . . . . . . . . . . 62,933 12,292 5,228 16 70,013
Gas Stored Underground. . . . . 2,969 - - - 2,969
Construction Work in Progress . 18,973 1,921 - - 20,894
1,043,342 100,324 10,930 24 1,132,760
Steam Heat Plant. . . . . . . . . 1,376 - - - 1,376
$6,160,369 $ 248,941 $ 47,739 $ (12,208) $6,349,363
WESTERN RESOURCES, INC.
Schedule V - Utility Plant
For the Year Ended December 31, 1992
Balance at Transfers, Balance
Beginning Additions Retire- Reclassi- Acquisition at End
Classification of Period at Cost ments fication of KG&E of Period
(Thousands of Dollars)
Electric Plant:
Steam Production. . . . . . . .$ 892,082 $ 10,603 $ 2,987 $ - $ 468,032 $1,367,730
Nuclear Production. . . . . . . - 3,505 6,660 - 1,358,833 1,355,678
Internal Combustion
Production. . . . . . . . . . 34,168 106 1 - - 34,273
Transmission. . . . . . . . . . 276,889 9,997 935 (74) 213,898 499,775
Distribution. . . . . . . . . . 416,027 38,636 4,343 74 359,223 809,617
General . . . . . . . . . . . . 46,075 5,578 976 (18) 61,007 111,666
Electric Plant Leased
to Others . . . . . . . . . . - - - - 6,984 6,984
Construction Work in Progress . 7,697 25,630 - (3) 15,744 49,068
Electric Plant Held for Future
Use . . . . . . . . . . . . . 9,832 - - - 15,458 25,290
Nuclear Fuel. . . . . . . . . . - 15,936 - (87) 43,456 59,305
Plant Acquisition Adjustment. . - - - 796,265 796,265
1,682,770 109,991 15,902 (108) 3,338,900 5,115,651
Natural Gas Plant:
Production and Gathering. . . . 9,711 18 12 (13) - 9,704
Underground Storage . . . . . . 5,632 319 - - - 5,951
Transmission. . . . . . . . . . 94,388 3,542 464 14 - 97,480
Distribution. . . . . . . . . . 687,148 70,913 5,120 92,391 (1) - 845,332
General . . . . . . . . . . . . 59,151 5,172 1,407 17 - 62,933
Gas Stored Underground. . . . . 2,969 - - - - 2,969
Construction Work in Progress . 9,417 9,556 - - - 18,973
868,416 89,520 7,003 92,409 - 1,043,342
Steam Heat Plant. . . . . . . . . 1,376 - - - - 1,376
$2,552,562 $199,511 $22,905 $92,301 $3,338,900 $6,160,369
(1) Includes $92,389,000 resulting from the adoption of Statement of Financial Accounting Standards
No. 109 relating to the GSC acquisition adjustment.
WESTERN RESOURCES, INC.
Schedule V - Utility Plant
For the Year Ended December 31, 1991
Balance at Transfers, Balance
Beginning Additions Retire- Reclassi- at End
Classification of Period at Cost ments fication of Period
(Thousands of Dollars)
Electric Plant:
Steam Production. . . . . . . . $ 886,296 $ 9,135 $ 3,348 $ (1) $ 892,082
Internal Combustion
Production. . . . . . . . . . 33,595 588 15 - 34,168
Transmission. . . . . . . . . . 272,772 5,185 656 (412) 276,889
Distribution. . . . . . . . . . 397,082 21,895 3,362 412 416,027
General . . . . . . . . . . . . 43,693 2,705 327 4 46,075
Construction Work in Progress . 4,721 2,976 - - 7,697
Electric Plant Held for Future
Use . . . . . . . . . . . . . 9,832 - - - 9,832
1,647,991 42,484 7,708 3 1,682,770
Natural Gas Plant:
Production and Gathering. . . . 9,847 80 216 - 9,711
Underground Storage . . . . . . 5,566 5 (61) - 5,632
Transmission. . . . . . . . . . 93,222 1,643 350 (127) 94,388
Distribution. . . . . . . . . . 618,856 69,725 8,862 7,429 687,148
General . . . . . . . . . . . . 46,455 15,223 2,792 265 59,151
Gas Stored Underground. . . . . 2,969 - - - 2,969
Construction Work in Progress . 15,481 (6,064) - - 9,417
792,396 80,612 12,159 7,567 868,416
Steam Heat Plant. . . . . . . . . 1,376 - - - 1,376
$2,441,763 $123,096 $19,867 $7,570 $2,552,562
WESTERN RESOURCES, INC.
Schedule VI - Accumulated Depreciation of Utility Plant
For the Year Ended December 31,
Additions
Balance at Charged to Acquisition Balance
Beginning Costs and Retire- Other of at End
Description of Period Expenses ments Charges(1) KG&E of Period
(Thousands of Dollars)
1993
Electric. . . . . . . . . $1,387,907 $134,658 $39,012 $ 1,951 $ - $1,485,504
Natural Gas . . . . . . . 328,333 35,702 11,788 - - 352,247
Steam Heat. . . . . . . . 1,376 - - - - 1,376
$1,717,616 $170,360 $50,800 $ 1,951 $ - $1,839,127
1992
Electric. . . . . . . . . $ 593,311 $112,631 $16,497 $ (162) $698,624 $1,387,907
Natural Gas . . . . . . . 231,431 32,918 6,315 70,299 (2) - 328,333
Steam Heat. . . . . . . . 1,376 - - - - 1,376
$ 826,118 $145,549 $22,812 $70,137 $698,624 $1,717,616
1991
Electric. . . . . . . . . $ 550,722 $ 53,384 $ 7,508 $(3,287) $ - $ 593,311
Natural Gas . . . . . . . 209,481 35,912 11,477 (2,485) - 231,431
Steam Heat. . . . . . . . 1,376 - - - - 1,376
$ 761,579 $ 89,296 $18,985 $(5,772) $ - $ 826,118
(1) Removal costs of assets retired less salvage value.
(2) Includes $71,488,000 resulting from the adoption of Statement of Financial Accounting Standards
No. 109 relating to the GSC acquisition adjustment.
69
SIGNATURE
Pursuant to the requirements of Sections 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
WESTERN RESOURCES, INC.
March 18, 199429, 1995 By JOHN E. HAYES, JR.
(JohnJohn E. Hayes, Jr., Chairman of the
Board,
President, and Chief Executive Officer)Officer
70
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
Signature Title Date
Chairman of the Board, President,
JOHN E. HAYES, JR. and Chief Executive Officer March 18, 199429, 1995
(John E. Hayes, Jr.) (Principal Executive Officer)
Executive Vice President and
S. L. KITCHEN Chief Financial Officer March 18, 199429, 1995
(S. L. Kitchen) (Principal Financial and
Accounting Officer)
FRANK J. BECKER
(Frank J. Becker)
GENE A. BUDIG
(Gene A. Budig)
C. Q. CHANDLER
(C. Q. Chandler)
THOMAS R. CLEVENGER
(Thomas R. Clevenger)
JOHN C. DICUS Directors March 18, 199429, 1995
(John C. Dicus)
DAVID H. HUGHES
(David H. Hughes)
RUSSELL W. MEYER, JR.
(Russell W. Meyer, Jr.)
JOHN H. ROBINSON
(John H. Robinson)
MARJORIE I. SETTER
(Marjorie I. Setter)
LOUIS W. SMITH
(Louis W. Smith)
KENNETH J. WAGNON
(Kenneth J. Wagnon)
71