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, 2001
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________ to _________
Commission File Number 1-7324
KANSAS GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Kansas 48-1093840
------ ----------
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification Number)
P.O. BOX 208
Wichita, Kansas 67201
(316) 261-6611
(Address, including zip code and telephone number, including area code, of
registrant's principal executive offices)
---------------------------
Securities registered pursuant to section 12(b) of the Act: None
Securities registered pursuant to section 12(g) of the Act: None
Indicate 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]
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
Class Outstanding at March 14, 2002
----- -----------------------------
Common Stock, No par value 1,000 Shares
Registrant meets the conditions of General Instruction I(1)(a) and (b) to
Form 10-K for certain wholly-owned subsidiaries and is therefore filing an
abbreviated form.
Documents Incorporated by Reference: None
TABLE OF CONTENTS
Page
----
PART I
Item 1. Business........................................................................... 4
Item 2. Properties......................................................................... 16
Item 3. Legal Proceedings.................................................................. 17
Item 4. Submission of Matters to a Vote of Security Holders................................ 17
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.............. 17
Item 6. Selected Financial Data............................................................ 17
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations ..................................................................... 18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk......................... 34
Item 8. Financial Statements and Supplementary Data........................................ 35
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure ........................................................................ 61
PART III
Item 10. Directors and Executive Officers of the Registrant................................. 61
Item 11. Executive Compensation............................................................. 61
Item 12. Security Ownership of Certain Beneficial Owners and Management..................... 61
Item 13. Certain Relationships and Related Transactions..................................... 61
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................... 62
Signatures................................................................................... 65
2
FORWARD-LOOKING STATEMENTS
Certain matters discussed in this Annual Report on Form 10-K are
"forward-looking statements." The Private Securities Litigation Reform Act of
1995 has established that these statements qualify for safe harbors from
liability. Forward-looking statements may include words like we "believe,"
"anticipate," "expect," "plan," "will," "may," "could," "estimate," "intend" or
words of similar meaning. Forward-looking statements describe our future plans,
objectives, expectations or goals. Such statements address future events and
conditions concerning:
. capital expenditures,
. earnings,
. liquidity and capital resources,
. litigation,
. possible corporate restructurings, mergers, acquisitions,
dispositions,
. compliance with debt and other restrictive covenants,
. interest and dividends,
. the financial condition of other Western Resources, Inc.'s
subsidiaries and their impact on Western Resources, Inc.'s results,
including impairment charges that may affect our liquidity,
. environmental matters,
. nuclear operations, and
. the overall economy of our service area.
What happens in each case could vary materially from what we expect
because of such things as:
. electric utility deregulation,
. ongoing municipal, state and federal activities, such as the Wichita
municipalization effort,
. future economic conditions,
. changes in accounting requirements and other accounting matters,
. changing weather,
. rate and other regulatory matters, including the impact of the order
to reduce our rates issued on July 25, 2001 by the Kansas
Corporation Commission and the impact of the Kansas Corporation
Commission's order issued July 20, 2001 and related proceedings,
with respect to the proposed separation of Western Resources, Inc.'s
electric utility businesses (including us) from Westar Industries,
Inc.,
. the impact on our service territory of the September 11, 2001
terrorist attacks,
. the impact, if any, of Enron Corp.'s bankruptcy on the market for
trading wholesale electricity,
. political, legislative and regulatory developments,
. amendments or revisions to Western Resources, Inc.'s current plans,
. the consummation of the acquisition of the electric operations of
Western Resources, Inc. (including us) by Public Service Company of
New Mexico and related litigation,
. regulatory, legislative and judicial actions,
. regulated and competitive markets, and
. other circumstances affecting anticipated operations, sales and
costs.
These lists are not all-inclusive because it is not possible to predict
all possible factors.
See "Item 1. Business -- Risk Factors" for additional information on
matters that could impact our expectations. Any forward-looking statement speaks
only as of the date such statement was made, and we do not undertake any
obligation to update any forward-looking statement to reflect events or
circumstances after the date on which such statement was made.
3
PART I
ITEM 1. BUSINESS
GENERAL
Kansas Gas and Electric Company (KGE, the company, we, us or our) is a
rate-regulated electric utility and wholly owned subsidiary of Western
Resources, Inc. (Western Resources). We provide rate-regulated electric service,
together with the electric utility operations of Western Resources, using the
name Westar Energy. We are engaged principally in the generation, purchase,
transmission, distribution and sale of electricity in southeastern Kansas,
including the Wichita metropolitan area. Our corporate headquarters are located
in Wichita, Kansas.
We own 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the
operating company for Wolf Creek Generating Station (Wolf Creek). We record our
proportionate share of all transactions of WCNOC as we do other jointly owned
facilities.
SIGNIFICANT BUSINESS DEVELOPMENTS
PNM Transaction
On November 8, 2000, Western Resources entered into an agreement with
Public Service Company of New Mexico (PNM), pursuant to which PNM would acquire
Western Resources' electric utility businesses (including us) in a tax-free
stock-for-stock merger. Under the terms of the agreement, both PNM and Western
Resources are to become subsidiaries of a new holding company, subject to
customary closing conditions including regulatory and shareholder approvals. At
the same time Western Resources entered into the agreement with PNM, Western
Resources and Westar Industries, a wholly owned subsidiary of Western Resources,
entered into an Asset Allocation and Separation Agreement, which, among other
things, provided for a split-off of Westar Industries and related matters.
On October 12, 2001, PNM filed a lawsuit against Western Resources in the
Supreme Court of the State of New York. The lawsuit seeks, among other things,
declaratory judgment that PNM is not obligated to proceed with the proposed
merger based in part upon the Kansas Corporation Commission (KCC) orders
discussed below and other KCC orders reducing rates for Western Resources'
electric utility businesses. PNM believes the orders constitute a material
adverse effect and make the condition that the split-off of Westar Industries
occur prior to closing incapable of satisfaction. PNM also seeks unspecified
monetary damages for breach of representation.
On November 19, 2001, Western Resources filed a lawsuit against PNM in the
Supreme Court of the State of New York. The lawsuit seeks substantial damages
for PNM's breach of the merger agreement providing for PNM's purchase of Western
Resources' electric utility operations and for PNM's breach of its duty of good
faith and fair dealing. In addition, Western Resources filed a motion to dismiss
or stay the declaratory judgment action previously filed by PNM seeking a
declaratory judgment that PNM has no further obligations under the merger
agreement.
On January 7, 2002, PNM sent a letter to Western Resources purporting to
terminate the merger in accordance with the terms of the merger agreement.
Western Resources has notified PNM that it believes the purported termination of
the merger agreement was ineffective and that PNM remains obligated to perform
thereunder. Western Resources intends to contest PNM's purported termination of
the merger agreement. However, based upon PNM's actions and the related
uncertainties, Western Resources believes the closing of the proposed merger is
not likely.
KCC Rate Cases
On November 27, 2000, Western Resources and we filed applications with the
KCC for an increase in retail rates. On July 25 and September 5, 2001, the KCC
issued orders that reduced our electric rates by $41.2 million.
4
Western Resources and we appealed these orders to the Kansas Court of Appeals,
but the KCC orders were upheld. We are evaluating whether to appeal the decision
to the Kansas Supreme Court. See "Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations - Summary of Significant Items
- - KCC Rate Cases" for further discussion.
KCC Proceedings and Orders
The merger with PNM contemplated the completion of a rights offering for
shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an
investigation of the proposed separation of Western Resources' electric utility
businesses (including us) from its non-utility businesses, including the rights
offering, and other aspects of its unregulated businesses. The order opening the
investigation indicated that the investigation would focus on whether the
separation and other transactions involving Western Resources' unregulated
businesses are consistent with its obligation to provide efficient and
sufficient electric service at just and reasonable rates to its electric utility
customers. The KCC staff was directed to investigate, among other matters, the
basis for and the effect of the Asset Allocation and Separation Agreement
Western Resources entered into with Westar Industries in connection with the
proposed separation and the intercompany payable owed by Western Resources to
Westar Industries, the separation of Westar Industries, the effect of the
business difficulties faced by Western Resources' unregulated businesses and
whether they should continue to be affiliated with its electric utility
business, and Western Resources' present and prospective capital structures. On
May 22, 2001, the KCC issued an order nullifying the Asset Allocation and
Separation Agreement, prohibiting Western Resources from taking any action to
complete the rights offering for common stock of Westar Industries, which was to
be a first step in the separation, and scheduling a hearing to consider whether
to make the order permanent.
On July 20, 2001, the KCC issued an order that, among other things: (1)
confirmed its May 22, 2001 order prohibiting Western Resources and Westar
Industries from taking any action to complete the proposed rights offering and
nullifying the Asset Allocation and Separation Agreement; (2) directed Western
Resources and Westar Industries not to take any action or enter into any
agreement not related to normal utility operations that would directly or
indirectly increase the share of debt in Western Resources' capital structure
applicable to its electric utility operations, which has the effect of
prohibiting it from borrowing to make a loan or capital contribution to Westar
Industries; and (3) directed Western Resources to present a financial plan
consistent with parameters established by the KCC's order to restore financial
health, achieve a balanced capital structure and protect ratepayers from the
risks of its non-utility businesses. In its order, the KCC also acknowledged
that Western Resources and we are presently operating efficiently and at
reasonable cost and stated that it was not disapproving the PNM transaction or a
split-off of Westar Industries. Western Resources appealed the orders issued by
the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002,
the District Court issued a decision finding that the KCC orders were not final
orders and that the District Court lacked jurisdiction to consider the appeal.
Accordingly, the matter was remanded to the KCC for review of the financial
plan.
On February 11, 2002, the KCC issued an order primarily related to
procedural matters for the review of the financial plan, as discussed below. In
addition, the order required that Western Resources and the KCC staff make
filings addressing whether the filing of applications by Western Resources and
us at the Federal Energy Regulatory Commission (FERC), seeking renewal of
existing borrowing authority, violated the July 20, 2001 KCC order directing
that Western Resources not increase the share of debt in its capital structure
applicable to its electric utility operations. The KCC staff subsequently filed
comments asserting that the refinancing of existing indebtedness with new
indebtedness secured by utility assets would in certain circumstances violate
the July 20, 2001 KCC order. The KCC staff filed a motion to intervene in the
proceeding at FERC asserting the same position. Western Resources is unable to
predict whether the KCC will adopt the KCC staff position, the extent to which
FERC will incorporate the KCC position in orders renewing Western Resources' and
our borrowing authority, or the impact of the adoption of the KCC staff
position, if that occurs, on Western Resources' or our ability to refinance
indebtedness maturing in the next several years. Western Resources' or our
inability to refinance existing indebtedness on a secured basis would likely
increase borrowing costs and adversely affect Western Resources' and our results
of operations.
5
The Financial Plan
The July 20, 2001 KCC order directed Western Resources to present a
financial plan to the KCC. Western Resources presented a financial plan to the
KCC on November 6, 2001, which it amended on January 29, 2002. The principal
objective of the financial plan is to reduce Western Resources' total debt as
calculated by the KCC to approximately $1.8 billion, a reduction of
approximately $1.2 billion. The financial plan contemplates that Western
Resources will proceed with the rights offering and that, in the event that the
PNM merger and related split-off do not close, Western Resources will use its
best efforts to sell its share of Westar Industries common stock, or shares of
its common stock, upon the occurrence of certain events. The KCC has scheduled a
hearing on May 31, 2002 to review the financial plan. Western Resources is
unable to predict whether or not the KCC will approve the financial plan or what
other action with respect to the financial plan the KCC may take.
Ice Storm
In late January 2002, a severe ice storm swept through our service area
causing extensive damage and loss of power to numerous customers. We estimate
storm restoration costs to be approximately $13 million. On March 13, 2002, we
filed an application for an accounting authority order with the KCC requesting
that we be allowed to accumulate and defer for future recovery costs related to
storm restoration. We cannot predict whether the KCC will approve our
application.
ELECTRIC UTILITY OPERATIONS
General
We supply electric energy at retail to approximately 293,000 customers in
Kansas. We also supply electric energy at wholesale to the electric distribution
systems of 27 Kansas cities. We have contracts for the sale, purchase or
exchange of wholesale electricity with other utilities.
Our electric sales for the years ended December 31, 2001, 2000 and 1999
were as follows:
2001 2000 1999
-------- -------- --------
(In Thousands)
Residential .................... $222,427 $246,665 $220,645
Commercial ..................... 175,899 175,686 169,427
Industrial ..................... 155,990 161,693 163,158
Wholesale ...................... 77,762 78,596 63,255
System Marketing ............... 16,077 17,660 --
Other .......................... 24,970 23,690 21,855
-------- -------- --------
Total ...................... $673,125 $703,990 $638,340
======== ======== ========
The following table reflects electric sales volumes, as measured by
megawatt hours (MWh), for the years ended December 31, 2001, 2000 and 1999. No
sales volumes are included for system marketing sales, because these sales are
not based on electricity we generate.
2001 2000 1999
------ ------ ------
(Thousands of MWh)
Residential .................... 2,734 2,950 2,601
Commercial ..................... 2,632 2,544 2,413
Industrial ..................... 3,488 3,561 3,548
Wholesale ...................... 2,479 2,407 1,832
Other .......................... 44 45 45
------ ------ ------
Total ...................... 11,377 11,507 10,439
====== ====== ======
6
Generation Capacity
The aggregate net generating capacity of our system is presently 2,616
megawatts (MW). The system has interests in 12 fossil-fuel steam generating
units, one nuclear generating unit (47% interest), one diesel generator and two
wind generators.
Our aggregate 2001 peak system net load of 2,076 MW occurred on July 30,
2001. Our net generating capacity combined with firm capacity purchases and
sales provided a capacity margin of approximately 18% above system peak
responsibility at the time of the peak. Our all time peak system net load of
2,111 MW occurred on August 11, 1999.
We have a market-based rate authority from the FERC, under which we buy
and sell energy and capacity throughout the United States.
We are a member of the Southwest Power Pool (SPP). In February 2002, SPP
and the Midwest Independent System Operator, Inc. (MISO) executed a definitive
agreement for the consolidation of the two organizations, which is expected to
occur in 2003. We anticipate that after the consolidation of SPP and MISO, we
will participate in MISO. Among other things, these organizations were formed to
maintain transmission system reliability on a regional basis. See "- Competition
and Deregulation" below for more information on these organizations.
We are also a member of the SPP transmission tariff, along with ten other
transmission providers in the region. Revenues from this tariff are divided
among the tariff members based upon calculated impacts to their respective
systems. The tariff allows for both firm and non-firm transmission access. We
will file a new transmission tariff with MISO as it becomes operational.
We have an agreement with Midwest Energy, Inc. to provide it with peaking
capacity of 60 MW through May 2008.
We forecast that we will need additional generating capacity of
approximately 150 MW by 2006 to serve our customers' expected electricity needs.
We will determine how to meet this need at a future date.
Fossil Fuel Generation
Fuel Mix:
Coal-fired units comprise 1,124 MW of our total 2,616 MW of generating
capacity and the nuclear unit provides 550 MW of capacity. Of the remaining 942
MW of generating capacity, units that can burn either natural gas or oil account
for 942 MW, one unit that burns only diesel fuel accounts for 3 MW, and wind
turbines account for approximately 0.4 MW (see "Item 2. Properties").
Based on MMBtus burned, the 2001 and estimated 2002 fuel mix (percent of
electricity produced by a specific fuel type) are as follows:
Estimated
Fuel 2001 2002
---- ---- ----
Coal.......................... 54% 58%
Nuclear....................... 37% 31%
Gas, Oil or Diesel Fuel....... 9% 11%
Our fuel mix fluctuates with the operation of the nuclear-powered Wolf
Creek (as discussed below under "-- Nuclear Generation"), fuel costs, plant
availability and power available on the wholesale market.
7
Coal:
Jeffrey Energy Center: The three coal-fired units at Jeffrey Energy Center
(JEC) have an aggregate capacity of 443 MW (our 20% share). Western Resources,
the operator of JEC, and we have a long-term coal supply contract with Amax Coal
West, Inc., a subsidiary of RAG America Coal Company, to supply coal to JEC from
mines located in the Powder River Basin in Wyoming. The contract expires
December 31, 2020. The contract contains a schedule of minimum annual MMBtu
delivery quantities. The coal supplied is surface mined and had an average Btu
content of approximately 8,407 Btu per pound and an average sulfur content of
.43 lbs/MMBtu (see "-- Environmental Matters"). The average cost of coal burned
at JEC during 2001 was approximately $1.10 per MMBtu, or $18.57 per ton.
Coal is transported from Wyoming under a long-term rail transportation
contract with Burlington Northern Santa Fe (BNSF) and Union Pacific (UP)
railroads with a term continuing through December 31, 2013.
LaCygne Generating Station: The two coal-fired units at LaCygne Station
have an aggregate generating capacity of 681 MW (KGE's 50% share). LaCygne 1
uses a blended fuel mix containing approximately 85% Powder River Basin coal and
15% Kansas/Missouri coal. LaCygne 2 uses Powder River Basin coal. The operator
of LaCygne Station, Kansas City Power and Light Company (KCPL), administers the
coal and coal transportation contracts. A portion of the LaCygne 1 and LaCygne 2
Powder River Basin coal is supplied through several fixed price and spot market
contracts that expire at various times through 2003 and is transported under
KCPL's Omnibus Rail Transportation Agreement with BNSF and Kansas City Southern
Railroad through December 31, 2010. Additional coal may be acquired on the spot
market. The LaCygne 1 Kansas/Missouri coal is purchased from time to time from
local Kansas and Missouri producers.
The Powder River Basin coal supplied during 2001 had an average Btu
content of approximately 8,527 Btu per pound and an average sulfur content of
.73 lbs/MMBtu. During 2001, the average cost of all coal burned at LaCygne 1 was
approximately $0.86 per MMBtu, or $14.88 per ton. The average cost of coal
burned at LaCygne 2 was approximately $0.79 per MMBtu, or $13.47 per ton.
General: We have entered into all of our coal contracts in the ordinary
course of business and do not believe we are substantially dependent upon these
contracts. We believe there are other suppliers with plentiful sources of coal
available at spot market prices to replace, if necessary, fuel to be supplied
pursuant to these contracts. In the event that we were required to replace our
coal agreements, we would not anticipate a substantial disruption of our
business although the cost of purchasing coal could increase.
We have entered into all of our coal transportation contracts in the
ordinary course of business. Several rail carriers are capable of serving the
coalmines from where our coal originates, but several of our generating stations
can be served by only one rail carrier. In the event the rail carrier to one of
our generating stations fails to provide reliable service, we could experience a
short-term disruption of our business. However, due to the obligation of the
rail carriers to provide service under the Interstate Commerce Act, we do not
anticipate any substantial long-term disruption of our business although the
cost of transporting coal could increase.
Natural Gas:
We use natural gas as a primary fuel in our Gordon Evans, Murray Gill and
Neosho Energy Centers. Natural gas for these facilities is purchased in the
short-term spot market, which supplies the system with the flexible natural gas
supply as necessary to meet operational needs.
We meet a portion of our natural gas transportation requirements through
firm natural gas transportation capacity agreements with Williams Gas Pipelines
Central. The firm transportation agreement that serves Gordon Evans and Murray
Gill extends through April 1, 2010, and the agreement for the Neosho facility
extends through June 1, 2016.
8
Oil:
We use oil as an alternate fuel when economical or when interruptions to
natural gas make it necessary. Oil is obtained by spot market purchases and
year-long contracts. We maintain quantities in inventory to meet emergency
requirements and protect against reduced availability of natural gas for limited
periods or when the primary fuel becomes uneconomical to burn.
Other Fuel Matters:
Our contracts to supply fuel for our coal-fired 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 to take advantage of economic
opportunities when the price is favorable. We use financial instruments to hedge
a portion of our anticipated fossil fuel needs in an attempt to offset the
volatility of the spot market. Due to the volatility of these markets, we are
unable to determine what the value of these financial instruments will be when
the agreements are actually settled. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Other Information
- -- Market Risk Disclosure" for further information.
The table below provides information relating to the weighted average cost
of fuel that we have used (which includes the commodity cost, transportation
cost to our facilities and any other associated costs).
2001 2000 1999
---- ---- ----
Per Million Btu:
Nuclear ............................... $ 0.44 $ 0.44 $ 0.45
Coal .................................. 0.95 0.91 0.87
Gas ................................... 3.75 3.34 2.31
Oil ................................... 3.84 3.12 2.11
Per MWh Generation ...................... $11.04 $11.08 $ 9.83
Nuclear Generation
Fuel Supply:
The owners of Wolf Creek have on hand or under contract 100% of their
uranium and uranium conversion needs for 2002 and 77% of the uranium and uranium
conversion required for operation of Wolf Creek through October 2006. The
balance is expected to be obtained through spot market and contract purchases.
The owners have under contract 100% of Wolf Creek's uranium enrichment
needs for 2002 and 90% of the uranium enrichment required to operate Wolf Creek
through October 2006. The balance of Wolf Creek's enrichment needs are expected
to be obtained through spot market and contract purchases.
All uranium, uranium conversion and uranium enrichment arrangements have
been entered into in the ordinary course of business, and Wolf Creek is not
substantially dependent upon these agreements. Despite contraction and
consolidation in the supply sector for these commodities and services, Wolf
Creek's management believes there are other supplies available to replace, if
necessary, these contracts. In the event these contracts were required to be
replaced, Wolf Creek's management does not anticipate a substantial disruption
of Wolf Creek's operations.
Nuclear fuel is amortized to cost of sales based on the quantity of heat
produced (MMBtus) for the generation of electricity.
9
Radioactive Waste Disposal:
Under the Nuclear Waste Policy Act of 1982 (NWPA), the Department of
Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel.
Wolf Creek pays the DOE a quarterly fee of one-tenth of a cent for each
kilowatt-hour of net nuclear generation delivered for the future disposal of
spent nuclear fuel. These disposal costs are charged to cost of sales.
In 1996 and 1997, a U.S. Court of Appeals issued decisions that (1) the
NWPA unconditionally obligated the DOE to begin accepting spent fuel for
disposal in 1998 and (2) precluded the DOE from concluding that its delay in
accepting spent fuel is "unavoidable" under its contracts with utilities due to
lack of a repository or interim storage authority.
In May 1998, the Court issued an order in response to the utilities'
petitions for remedies for DOE's failure to begin accepting spent fuel for
disposal. The Court affirmed its conclusion that the sole remedy for DOE's
breach of its statutory obligation under the NWPA is a contract remedy and
indicated that the court will not revisit the matter until the utilities have
completed their pursuit of that remedy. Wolf Creek intends to pursue its claims
against the DOE.
A permanent disposal site will not be available for the nuclear industry
until 2010 or later. Under current DOE policy, once a permanent site is
available, the DOE will accept spent nuclear fuel on a priority basis. The
owners of the oldest spent fuel will be given the highest priority. As a result,
disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek
has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek
completed replacement of spent fuel storage racks to increase its on-site
storage capacity for all spent fuel expected to be generated by Wolf Creek
through the end of its licensed life in 2025.
The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated
that the various states, individually or through interstate compacts, develop
alternative low-level radioactive waste disposal facilities. The states of
Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate
Low-Level Radioactive Waste Compact (Compact) and selected a site in Nebraska to
locate a disposal facility. WCNOC and the owners of the other five nuclear units
in the Compact have provided most of the pre-construction financing for this
project. Our net investment in the Compact through December 31, 2001 was
approximately $7.4 million.
On December 18, 1998, the Nebraska agencies responsible for considering
the developer's license application denied the application. The license
applicant has sought a hearing on the license denial, but a U.S. District Court
has indefinitely delayed proceedings related to the hearing. In December 1998,
most of the utilities that had provided the project's pre-construction financing
(including WCNOC) filed a federal court lawsuit contending Nebraska officials
acted in bad faith while handling the license application. Shortly thereafter,
the Central Interstate Low-Level Radioactive Waste Commission (Commission)
(responsible for causing a new disposal facility to be developed within the
Compact region) and US Ecology (the license applicant) filed similar claims
against Nebraska. In September 1999, the U.S. District Court partially denied
and partially granted Nebraska's motions to dismiss the utilities' and US
Ecology's cases and denied Nebraska's motions to dismiss the Compact
Commission's case. Since that time, the utilities have dismissed their remaining
claims against Nebraska for monetary damages, but their claims for equitable
relief remain. The Commission's claims for monetary damages and equitable relief
also remain, and the parties expect the case to go to trial in the second half
of 2002.
In May 1999, the Nebraska legislature passed a bill withdrawing Nebraska
from the Compact. In August 1999, the Nebraska governor gave official notice of
the withdrawal to the other member states. Withdrawal will not be effective for
five years and will not, of itself, nullify the site license proceeding.
Wolf Creek disposes of all classes of its low-level radioactive waste at
existing third-party repositories. Should disposal capability become
unavailable, Wolf Creek is able to store its low-level radioactive waste in an
on-site facility for up to five years under current regulations. Wolf Creek
believes that a temporary loss of low-level radioactive waste disposal
capability will not affect continued operation of the power plant.
10
Outages:
Wolf Creek has an 18-month refueling and maintenance schedule which
permits uninterrupted operation every third calendar year. An outage began on
March 23, 2002. During the outage, electric demand is expected to be met
primarily by our other fossil-fueled generating units and by purchased power.
An extended shut-down of Wolf Creek could have a substantial adverse
effect on our business, financial condition and results of operations because of
higher replacement power and other costs. Although not expected, reacting to
safety issues, the Nuclear Regulatory Commission (NRC) could impose an
unscheduled plant shut-down due to terrorist or other concerns.
Security and Insurance
We have increased security measures at our generation facility sites and
various offices, in part due to nationwide terrorist concerns. These measures
include, but are not limited to, increased security personnel, utilization of
armed guard services, patrolling of company property, restricting access to our
properties and implementing emergency training and response procedures.
Wolf Creek's management has increased both voluntary and
federally-mandated security measures at Wolf Creek. The NRC has required nuclear
power plants to be operated at the highest level of security since September 11,
2001. The measures implemented at Wolf Creek include, but are not limited to,
increased guard service, no unscheduled visits and emergency training and
response procedures.
The NRC has issued orders to all nuclear plants that make our current
voluntary security measures mandatory. The orders also impose new security
requirements at U.S. nuclear power plants. Wolf Creek's security costs will
increase as a result of these orders.
In addition, there are unfavorable trends in the availability and price of
property and casualty insurance primarily due to catastrophic events and the
world's financial markets. We anticipate material increases in insurance costs,
although the amount of the increase is unknown at this time. Information with
respect to insurance coverage applicable to the operations of our nuclear
generating facility is set forth in Note 11 of the "Notes to Consolidated
Financial Statements."
Competition and Deregulation
Electric utilities have historically operated in a rate-regulated
environment. Federal and state regulatory agencies having jurisdiction over our
rates and services and other utilities have initiated steps that were expected
to result in a more competitive environment for utility services. The Kansas
Legislature took no action on deregulation in 2001 or 2000.
In a deregulated environment, utility companies that are not responsive to
a competitive energy marketplace may suffer erosion in market share, revenues
and profits. Possible types of competition include cogeneration,
self-generation, retail wheeling, or municipalization. Retail wheeling is the
ability of individual customers to choose a power provider other than us and we
would provide the transmission service for this power. Kansas does not allow
retail wheeling and no such regulation is pending or being considered. However,
if retail wheeling were implemented in Kansas, increased competition for retail
electricity sales may reduce our future electric utility earnings compared to
our historical electric utility earnings. Our average retail rates are
approximately 10% below the national average for retail customers. Because of
these rates, we expect to retain a substantial part of our current volume of
sales in a competitive environment.
Increased competition for retail electricity sales may in the future
reduce our earnings, which could impact our ability to pay dividends and could
have a material adverse impact on our operations and our financial condition. A
material non-cash charge to earnings may be required should we discontinue
accounting under Statement of Financial Accounting Standard No. 71, "Accounting
for the Effects of Certain Types of Regulation."
11
The 1992 Energy Policy Act began deregulating the electricity market for
generation. The Energy Policy Act permitted FERC to order electric utilities to
allow third parties to use their transmission systems to sell electric power to
wholesale customers. In 1992, we agreed to open access of our transmission
system for wholesale transactions. FERC also requires us to provide transmission
services to others under terms comparable to those we provide ourselves. In
December 1999, FERC issued an order (FERC Order No. 2000) encouraging formation
of regional transmission organizations (RTOs). RTOs are designed to control the
wholesale transmission services of the utilities in their regions thereby
facilitating open and more competitive markets in bulk power.
After the FERC rejected several attempts by the SPP to seek RTO status,
the SPP and MISO agreed in October 2001 to consolidate and form an RTO. In
December 2001, the FERC approved this newly formed MISO as the first RTO. The
agreement to consolidate was executed in February 2002 and the transaction is
expected to close in 2003. This new organization will operate our transmission
system as part of an interconnected transmission system encompassing over
120,000 MW of generation capacity located in 20 states. MISO will collect
revenues attributable to the use of each member's transmission system, and each
member will be able to transmit power purchased, generated for sale or bought
for resale in the wholesale market throughout the entire MISO system. Although
each member will have priority over the use of its own transmission facilities
for selling power to its wholesale customers or others, each member will be
charged the same uniform transmission rate as other energy suppliers who are
able to sell power to them. We intend to file with the FERC and the KCC to
transfer control over the operation of our transmission facilities to MISO. We
anticipate that FERC Order No. 2000 and our participation in the MISO will not
have a material effect on our operations.
For further discussion regarding competition and its potential impact on
us, see "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Other Information -- Electric Utility."
Regulation and Rates
As a Kansas electric utility, we are subject to the jurisdiction of the
KCC, which has general regulatory authority over our rates, extensions, and
abandonments of service and facilities, valuation of property, the
classification of accounts and various other matters. Additionally, we are
subject to the jurisdiction of FERC, which has authority over wholesale sales of
electricity, the transmission of electric power and the issuance of certain
securities. We are also subject to the jurisdiction of the KCC and the FERC with
respect to the issuance of certain securities. We are subject to the
jurisdiction of the NRC for nuclear plant operations and safety.
On November 27, 2000, Western Resources and we filed applications with the
KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual
reduction in our electric rates of $41.2 million.
On August 9, 2001, Western Resources and we filed a petitions with the KCC
requesting reconsideration of the July 25, 2001 order. The petitions
specifically asked for reconsideration of changes in depreciation, reductions in
rate base related to deferred income taxes associated with the acquisition
premium and a deferred gain on the sale and leaseback of LaCygne 2 and several
other issues. On September 5, 2001, the KCC issued an order denying our motion
for reconsideration, which did not change our rate reduction. On November 9,
2001, we filed an appeal of the KCC decisions to the Kansas Court of Appeals in
an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company
vs. The State Corporation Commission of the State of Kansas." On March 8, 2002,
the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal
this decision to the Kansas Supreme Court.
Additional information with respect to Rate Matters and Regulation is set
forth in "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Summary of Significant Items -- KCC Rate Cases,"
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Other Information -- Electric Utility" and Note 3 of the "Notes
to Consolidated Financial Statements."
Environmental Matters
We currently hold all Federal and State environmental approvals required
for the operation of all of our generating units. We believe we are presently in
substantial compliance with all air quality regulations (including
12
those pertaining to particulate matter, sulfur dioxide and nitrogen oxides
(NOx)) promulgated by the State of Kansas and the Environmental Protection
Agency (EPA).
The JEC and LaCygne 2 units have met: (1) the Federal sulfur dioxide
standards through the use of low sulfur coal; (2) the Federal particulate matter
standards through the use of electrostatic precipitators; and (3) the federal
NOx 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 when needed to meet permit
limits.
The Kansas Department of Health and Environment (KDHE) regulations
applicable to our other generating facilities prohibit the emission of more than
3.0 pounds of sulfur dioxide per MMBtu of heat input. We meet these standards
through the use of low sulfur coal and by all coal-burning facilities being
equipped with flue gas scrubbers and/or electrostatic precipitators.
We must comply, and are currently in compliance, with the provisions of
The Clean Air Act Amendments of 1990 that require a two-phase reduction in
certain emissions. We have installed continuous monitoring and reporting
equipment to meet the acid rain requirements. We have not had to make any
material capital expenditures to meet Phase II sulfur dioxide and nitrogen oxide
requirements.
All of our generating facilities are in substantial compliance with the
Best Practicable Technology and Best Available Technology regulations issued by
the EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are
administered in Kansas by the KDHE.
Additional information with respect to Environmental Matters is discussed
in Note 11 of the "Notes to Consolidated Financial Statements."
SEGMENT INFORMATION
Financial information with respect to business segments is set forth in
Note 16 of the "Notes to Consolidated Financial Statements."
EMPLOYEES
All employees we utilize are provided by Western Resources.
RISK FACTORS
You should read the following risk factors in conjunction with discussions
of factors discussed elsewhere in this and other of our filings with the
Securities and Exchange Commission. These cautionary statements are intended to
highlight certain factors that may affect our financial condition and results of
operations and are not meant to be an exhaustive discussion of risks that apply
to public companies, such as us. Like other businesses, we are susceptible to
macroeconomic downturns in the United States or abroad that may affect the
general economic climate and our performance or that of our customers.
We Are a Public Utility Subject to Regulation Which Significantly Impacts
Our Business, Results of Operations, Financial Position and Prospects:
We are regulated by the KCC and FERC and other federal and state agencies.
See "-- Electric Utility Operations -- Regulation and Rates." This regulation
impacts most aspects of our business and operations. Throughout this Annual
Report on Form 10-K, we have described the impact of regulation and the
significant effect it has on our business, financial condition, results of
operations, liquidity and prospects. Such regulation is impacted by matters
beyond our control, such as general economic conditions, politics and
competition, and other matters
13
described under "Forward-Looking Statements." We refer you to "--Significant
Business Developments," and the other risk factors below, as well as "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations", for a further discussion of some of the more important matters
which are currently the subject of, or related to, regulatory concerns.
Municipalization Efforts by Wichita May Affect Operations and Results:
In December 1999, the City Council of Wichita, Kansas, authorized the
hiring of an outside consultant to determine the feasibility of creating a
municipal electric utility to replace us as the supplier of electricity in
Wichita. The feasibility study was released in February 2001 and estimates that
the City of Wichita would be required to pay us $145 million for our stranded
costs if it were to municipalize. However, we estimate the amount to be
substantially greater. In order to municipalize our Wichita electric facilities,
the City of Wichita would be required to purchase our facilities or build a
separate independent system and arrange for its own power supply. These costs
are in addition to the stranded costs for which the city would be required to
reimburse us. On February 2, 2001, the City of Wichita announced its intention
to proceed with its attempt to municipalize our retail electric utility business
in Wichita. We will oppose municipalization efforts by the City of Wichita.
Should the city be successful in its municipalization efforts without providing
us adequate compensation for our assets and lost revenues, the adverse effect on
our business and financial condition could be material.
Our franchise with the City of Wichita to provide retail electric service
is effective through December 1, 2002. There can be no assurance that we can
successfully renegotiate the franchise with terms similar, or as favorable, as
those in the current franchise. Under Kansas law, we will continue to have the
right to serve the customers in Wichita following the expiration of the
franchise, assuming the system is not municipalized. Customers within the
Wichita metropolitan area account for approximately 51% of our total energy
sales.
Fuel and Purchased Power Costs are Included in Retail Rates at a Fixed
Level and Increases are not Recovered Automatically:
Fuel and purchased power costs are recovered in retail rates at a fixed
test year level. Therefore, to recover fuel and purchased power costs in excess
of the costs built into retail rates, we would have to make a rate filing with
the KCC, which could be denied in whole or in part. During 2001, we entered into
a gas hedging arrangement, designed to eliminate a portion of our risk through
July 2004. Any increase in fuel and purchased power costs over the costs
recovered through rates would reduce our earnings. Increases could be material.
Purchased Power Commodity Prices are Volatile:
The wholesale power market is extremely volatile in price and supply. This
volatility impacts our costs of power purchased. If we were unable to generate
an adequate supply of electricity for our native load customers, we would
purchase power in the wholesale market to the extent it is available or
economically feasible to do so and/or implement curtailment or interruption
procedures as allowed for in our tariffs and terms and conditions of service. To
the extent open positions exist in our power marketing portfolio, we are exposed
to fluctuating market prices that may adversely impact our financial position
and results of operations. The increased expenses or loss of revenues associated
with this could be material and adverse to our consolidated results of
operations and financial condition.
Hedging and Trading Activities Involve Risks:
We are involved in hedging and trading activities primarily to minimize
risk from commodity market fluctuations, capitalize on market knowledge and
enhance system reliability. In these activities, we utilize a variety of
financial instruments, including forward contracts involving cash settlements or
physical delivery of an energy commodity, futures, options and swaps providing
for payments (or receipt of payments) from counter parties based on the
differential between the contract price and a specified index price.
Our hedging and trading activities involve risks, including commodity
price risk, interest rate risk and credit risk. Commodity price risk is the risk
that changes in commodity prices may impact the price at which we are able to
buy and sell electricity and purchase fossil fuels for our generators. These
commodities have experienced price
14
volatility in the past and can be expected to do so in the future. This
volatility may increase or decrease future earnings.
Interest rate risk is the risk of loss associated with movements in market
interest rates. Our exposure to interest rate risk is limited due to the
fixed-rate nature of most of our long-term debt.
Credit risk is the risk of loss resulting from non-performance by a
counter party of its contractual obligations. As we continue to expand our
commodity trading activities, our exposure to credit risk and counter party
default may increase. We maintain credit policies intended to minimize overall
credit risk and actively monitor these policies to reflect changes and scope of
operations. We employ additional credit risk control mechanisms when
appropriate, such as letters of credit, parental guarantees and standardized
master netting agreements that allow for offsetting of positive and negative
exposures. Credit exposure is monitored and, when necessary, the activity with a
specific counter party is limited until credit enhancement is provided. See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Other Information -- Market Risk Disclosure" for further
discussion.
Results actually achieved from these activities could vary materially from
intended results and could materially affect our financial results.
Our and Western Resources' Current Levels of Debt Could Adversely Affect
Our Business:
Western Resources and we have a large amount of indebtedness. As of
December 31, 2001, we had outstanding total indebtedness of approximately $684.4
million. A large amount of indebtedness could have a negative impact on, among
other things, Western Resources' ability to provide for our short-term cash
needs and our ability to obtain replacement financing if such event were to
occur.
The indentures governing our long-term indebtedness require us to satisfy
certain financial conditions in order to borrow additional funds. These
covenants require, among other things, that we maintain certain leverage and
interest coverage ratios. We are in compliance with these covenants. A breach of
any of the covenants could result in an event of default, which would allow the
lenders to declare all amounts outstanding immediately due and payable.
For information regarding a financial plan that was filed by Western
Resources with the KCC that details Western Resources' current plans for debt
reduction, see "--Significant Business Developments -- KCC Proceedings and
Orders" and "--Significant Business Developments -- The Financial Plan" above.
Strategic Transactions May Not Be Completed:
Western Resources and our strategic plans include the acquisition of
Western Resources' electric utility businesses (including us) by PNM and the
split-off of Westar Industries to Western Resources' shareholders. Prior to the
completion of these transactions, Westar Industries would sell a portion of its
common stock in a rights offering to Western Resources' shareholders. The
completion of these transactions is subject to the satisfaction of various
conditions including the receipt of shareholder and regulatory approvals in the
case of the PNM transaction. Western Resources and we believe the completion of
the proposed transaction with PNM is not likely. See "--Significant Business
Developments -- PNM Transaction" above for more information.
15
ITEM 2. PROPERTIES
ELECTRIC GENERATING FACILITIES
- ------------------------------------------------------------------------------------------------------------------------------
Year Principal Unit
Name Unit No. Installed Fuel Capacity (MW) Segment
- ------------------------------------------------------------------------------------------------------------------------------
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 151.0 Electric Operations
2 1967 Gas--Oil 383.0 Electric Operations
Diesel Generator 1 1969 Diesel 3.0 Electric Operations
- ------------------------------------------------------------------------------------------------------------------------------
Jeffrey Energy Center (20%):
Steam Turbines 1 (a) 1978 Coal 149.0 Electric Operations
2 (a) 1980 Coal 146.0 Electric Operations
3 (a) 1983 Coal 148.0 Electric Operations
Wind Turbines 1 (a) 1999 - 0.2 Electric Operations
2 (a) 1999 - 0.2 Electric Operations
- ------------------------------------------------------------------------------------------------------------------------------
LaCygne Station (50%):
Steam Turbines 1 (a) 1973 Coal 344.0 Electric Operations
2 (b) 1977 Coal 337.0 Electric Operations
- ------------------------------------------------------------------------------------------------------------------------------
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 43.0 Electric Operations
2 1954 Gas--Oil 74.0 Electric Operations
3 1956 Gas--Oil 112.0 Electric Operations
4 1959 Gas--Oil 107.0 Electric Operations
- ------------------------------------------------------------------------------------------------------------------------------
Neosho Energy Center:
Steam Turbine 3 1954 Gas--Oil 69.0 Electric Operations
- ------------------------------------------------------------------------------------------------------------------------------
Wolf Creek Generating Station (47%):
Nuclear 1 (a) 1985 Uranium 550.0 Nuclear Generation
- ------------------------------------------------------------------------------------------------------------------------------
Total 2,616.4
- ------------------------------------------------------------------------------------------------------------------------------
- ----------
(a) We jointly own Jeffrey Energy Center (20%), LaCygne 1 generating
unit (50%), and Wolf Creek Generating Station (47%). Western
Resources jointly owns 64% of Jeffrey Energy Center.
(b) In 1987, KGE entered into a sale-leaseback transaction involving its
50% interest in the LaCygne 2 generating unit.
We own approximately 2,400 miles of transmission lines, approximately
9,900 miles of overhead distribution lines and approximately 1,800 miles of
underground distribution lines. (These properties are part of the Electric
Operations segment.)
Substantially all of our utility properties are encumbered by first
priority mortgages pursuant to which bonds have been issued and are outstanding.
16
ITEM 3. LEGAL PROCEEDINGS
Information on our legal proceedings is set forth in Notes 3, 11, 12, and
13 of the "Notes to Consolidated Financial Statements." See also "Item 1.
Business -- Electric Utility Operations -- Regulation and Rates," and "Item 1.
Business -- Electric Utility Operations -- Environmental Matters."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Information required by Item 4 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of our common stock is owned by Western Resources and is not traded on
an established public trading market.
ITEM 6. SELECTED FINANCIAL DATA
For the Year Ended December 31,
--------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- ---------- ---------- ----------
Income Statement Data:
Sales ............................. $ 673,125 $ 703,990 $ 638,340 $ 648,379 $ 614,445
Net income before accounting change 37,301 86,708 84,261 103,765 52,128
As of December 31,
--------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- ---------- ---------- ----------
Balance Sheet Data:
Total assets ...................... $2,930,045 $2,988,573 $2,989,710 $3,057,971 $3,117,108
Long-term debt, net ............... 684,360 684,366 684,271 684,167 684,128
17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
In Management's Discussion and Analysis, we discuss the general financial
condition, significant annual changes and our operating results. We explain:
. what factors impact our business,
. what our earnings and costs were in 2001, 2000 and 1999,
. why these earnings and costs differ from year to year,
. how our earnings and costs affect our overall financial condition,
. what our capital expenditures were for 2001,
. what we expect our capital expenditures to be for the years 2002
through 2004,
. how we plan to pay for these future capital expenditures,
. critical accounting policies, and
. any other items that particularly affect our financial condition or
earnings.
As you read Management's Discussion and Analysis, please refer to our
consolidated financial statements and the notes thereto, which show our
operating results.
SUMMARY OF SIGNIFICANT ITEMS
PNM Transaction
On November 8, 2000, Western Resources entered into an agreement with
Public Service Company of New Mexico (PNM), pursuant to which PNM would acquire
Western Resources' electric utility businesses (including us) in a tax-free
stock-for-stock merger. Under the terms of the agreement, both PNM and Western
Resources are to become subsidiaries of a new holding company, subject to
customary closing conditions including regulatory and shareholder approvals. At
the same time Western Resources entered into the agreement with PNM, Western
Resources and Westar Industries, a wholly owned subsidiary of Western Resources,
entered into an Asset Allocation and Separation Agreement, which provided for a
split-off of Westar Industries and related matters.
On October 12, 2001, PNM filed a lawsuit against Western Resources in the
Supreme Court of the State of New York. The lawsuit seeks, among other things,
declaratory judgment that PNM is not obligated to proceed with the proposed
merger based in part upon the Kansas Corporation Commission (KCC) orders
discussed below and other KCC orders reducing rates for Western Resources'
electric utility businesses. PNM believes the orders constitute a material
adverse effect and make the condition that the split-off of Westar Industries
occur prior to closing incapable of satisfaction. PNM also seeks unspecified
monetary damages for breach of representation.
On November 19, 2001, Western Resources filed a lawsuit against PNM in the
Supreme Court of the State of New York. The lawsuit seeks substantial damages
for PNM's breach of the merger agreement providing for PNM's purchase of Western
Resources' electric utility operations and for PNM's breach of its duty of good
faith and fair dealing. In addition, Western Resources filed a motion to dismiss
or stay the declaratory judgment action previously filed by PNM seeking a
declaratory judgment that PNM has no further obligations under the merger
agreement.
On January 7, 2002, PNM sent a letter to Western Resources purporting to
terminate the merger in accordance with the terms of the merger agreement.
Western Resources has notified PNM that it believes the purported termination of
the merger agreement was ineffective and that PNM remains obligated to perform
thereunder. Western Resources intends to contest PNM's purported termination of
the merger agreement. However, based upon PNM's actions and the related
uncertainties, Western Resources believes the closing of the proposed merger is
not likely.
18
KCC Rate Cases
On November 27, 2000, Western Resources and we filed applications with the
KCC for an increase in retail rates. On July 25 and September 5, 2001, the KCC
issued orders that reduced our electric rates by $41.2 million. Western
Resources and we appealed these orders to the Kansas Court of Appeals, but the
KCC orders were upheld. We are evaluating whether to appeal the decision to the
Kansas Supreme Court. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Summary of Significant Items --
KCC Rate Cases" for further discussion.
KCC Proceedings and Orders
The merger with PNM contemplated the completion of a rights offering for
shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an
investigation of the proposed separation of Western Resources' electric utility
businesses (including us) from its non-utility businesses, including the rights
offering, and other aspects of its unregulated businesses. The order opening the
investigation indicated that the investigation would focus on whether the
separation and other transactions involving Western Resources' unregulated
businesses are consistent with its obligation to provide efficient and
sufficient electric service at just and reasonable rates to its electric utility
customers. The KCC staff was directed to investigate, among other matters, the
basis for and the effect of the Asset Allocation and Separation Agreement
Western Resources entered into with Westar Industries in connection with the
proposed separation and the intercompany payable owed by Western Resources to
Westar Industries, the separation of Westar Industries, the effect of the
business difficulties faced by Western Resources' unregulated businesses and
whether they should continue to be affiliated with its electric utility
business, and Western Resources' present and prospective capital structures. On
May 22, 2001, the KCC issued an order nullifying the Asset Allocation and
Separation Agreement, prohibiting Western Resources from taking any action to
complete the rights offering for common stock of Westar Industries, which was to
be a first step in the separation, and scheduling a hearing to consider whether
to make the order permanent.
On July 20, 2001, the KCC issued an order that, among other things: (1)
confirmed its May 22, 2001 order prohibiting Western Resources and Westar
Industries from taking any action to complete the proposed rights offering and
nullifying the Asset Allocation and Separation Agreement; (2) directed Western
Resources and Westar Industries not to take any action or enter into any
agreement not related to normal utility operations that would directly or
indirectly increase the share of debt in Western Resources' capital structure
applicable to its electric utility operations, which has the effect of
prohibiting it from borrowing to make a loan or capital contribution to Westar
Industries; and (3) directed Western Resources to present a financial plan
consistent with parameters established by the KCC's order to restore financial
health, achieve a balanced capital structure and protect ratepayers from the
risks of its non-utility businesses. In its order, the KCC also acknowledged
that Western Resources and we are presently operating efficiently and at
reasonable cost and stated that it was not disapproving the PNM transaction or a
split-off of Westar Industries. Western Resources appealed the orders issued by
the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002,
the District Court issued a decision finding that the KCC orders were not final
orders and that the District Court lacked jurisdiction to consider the appeal.
Accordingly, the matter was remanded to the KCC for review of the financial
plan.
On February 11, 2002, the KCC issued an order primarily related to
procedural matters for the review of the financial plan, as discussed below. In
addition, the order required that Western Resources and the KCC staff make
filings addressing whether the filing of applications by Western Resources and
us at the Federal Energy Regulatory Commission (FERC), seeking renewal of
existing borrowing authority, violated the July 20, 2001 KCC order directing
that Western Resources not increase the share of debt in its capital structure
applicable to its electric utility operations. The KCC staff subsequently filed
comments asserting that the refinancing of existing indebtedness with new
indebtedness secured by utility assets would in certain circumstances violate
the July 20, 2001 KCC order. The KCC staff filed a motion to intervene in the
proceeding at FERC asserting the same position. Western Resources is unable to
predict whether the KCC will adopt the KCC staff position, the extent to which
FERC will incorporate the KCC position in orders renewing Western Resources' and
our borrowing authority, or the impact of the adoption of the KCC staff
position, if that occurs, on Western Resources' or our ability to refinance
indebtedness maturing in the
19
next several years. Western Resources' or our inability to refinance existing
indebtedness on a secured basis would likely increase borrowing costs and
adversely affect Western Resources' and our results of operations.
The Financial Plan
The July 20, 2001 KCC order directed Western Resources to present a
financial plan to the KCC. Western Resources presented a financial plan to the
KCC on November 6, 2001, which it amended on January 29, 2002. The principal
objective of the financial plan is to reduce Western Resources' total debt as
calculated by the KCC to approximately $1.8 billion, a reduction of
approximately $1.2 billion. The financial plan contemplates that Western
Resources will proceed with the rights offering and that, in the event that the
PNM merger and related split-off do not close, Western Resources will use its
best efforts to sell its share of Westar Industries common stock, or shares of
its common stock, upon the occurrence of certain events. The KCC has scheduled a
hearing on May 31, 2002 to review the financial plan. Western Resources is
unable to predict whether or not the KCC will approve the financial plan or what
other action with respect to the financial plan the KCC may take.
Ice Storm
In late January 2002, a severe ice storm swept through our service area
causing extensive damage and loss of power to numerous customers. We estimate
storm restoration costs to be approximately $13 million. On March 13, 2002, we
filed an application for an accounting authority order with the KCC requesting
that we be allowed to accumulate and defer for future recovery costs related to
storm restoration. We cannot predict whether the KCC will approve our
application.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of results of operations and financial
condition are based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States (GAAP). The preparation of these consolidated financial statements
requires us to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses, and related disclosure of contingent
assets and liabilities. We evaluate our estimates on an on-going basis,
including those related to bad debts, inventories, goodwill, intangible assets,
income taxes, and contingencies and litigation. We base our estimates on
historical experience and on various other assumptions that are believed to be
reasonable under the circumstances, the results of which form the basis for
making judgments about the carrying values of assets and liabilities that are
not readily apparent from other sources. Actual results may differ from these
estimates under different assumptions or conditions.
Note 2 of the "Notes to Consolidated Financial Statements" includes a
summary of the significant accounting policies and methods used in the
preparation of our consolidated financial statements. The following is a brief
description of the more significant accounting policies and methods used by us.
Regulatory Accounting
We currently apply accounting standards for our regulated utility
operations that recognize the economic effects of rate regulation in accordance
with Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation" and, accordingly, have recorded
regulatory assets and liabilities when required by a regulatory order or based
on regulatory precedent.
Regulatory assets represent probable future revenue associated with
certain costs that will be recovered from customers through the rate-making
process. Regulatory liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers through the
rate-making process. If we were required to terminate application of SFAS No. 71
for all of our regulated operations, we would have to record the amounts of all
regulatory assets and liabilities in our consolidated statements of income at
that time. As of December 31, 2001, this would reduce our earnings by $239.9
million, net of applicable income taxes.
20
SFAS No. 71 affects our electric operations and nuclear generation business
segments. We do not anticipate the discontinuation of SFAS No. 71 in the
foreseeable future. See "--Competition and Deregulation" and "--Stranded Costs"
for additional discussion of the application of SFAS No. 71.
Sales Recognition
Energy sales are recognized as services are rendered and include an
estimate for energy delivered but unbilled at the end of each year, except for
energy trading activities. Power marketing activities are accounted for under
the mark-to-market method of accounting. Under this method, changes in the
portfolio value are recognized as gains or losses in the period of change. The
net mark-to-market change is included in energy sales in our consolidated
statements of income. The resulting unrealized gains and losses are recorded as
energy trading assets and liabilities on our consolidated balance sheets.
We primarily use quoted market prices to value our power marketing and
energy trading contracts. When market prices are not readily available or
determinable, we use alternative approaches, such as model pricing. The market
prices used to value these transactions reflect our best estimate considering
various factors, including closing exchange and over-the-counter quotations,
time value and volatility factors underlying the commitments. Results actually
achieved from these activities could vary materially from intended results and
could unfavorably affect our financial results. Financially settled trading
transactions are reported on a net basis, reflecting the financial nature of
these transactions. Physically settled trading transactions are recorded on a
gross basis in operating revenues and fuel and purchased power expense.
Depreciation
Utility plant is depreciated on the straight-line method at the lesser of
rates set by the KCC or rates based on the estimated remaining useful lives of
the assets, which are based on an average annual composite basis using group
rates that approximated 2.80% during 2001, 2.81% during 2000 and 2.76% during
1999. In its rate order of July 25, 2001, the KCC extended the recovery period
for our generating assets, including Wolf Creek for regulatory rate making
purposes. The impact of this decision reduced our retail electric rates by
approximately $14.3 million on an annual basis. We intend to file an application
for an accounting authority order with the KCC to allow the creation of a
regulatory asset for the difference between our book and regulatory
depreciation. We cannot predict whether the KCC will approve our application.
Depreciable lives of property, plant and equipment are as follows:
Fossil generating facilities ............ 10 to 46 years
Nuclear generating facilities ........... 38 years
Transmission facilities ................. 27 to 65 years
Distribution facilities ................. 20 to 65 years
Other ................................... 3 to 50 years
Income Taxes
Deferred tax assets and liabilities are recognized for temporary
differences in amounts recorded for financial reporting purposes and their
respective tax bases. Investment tax credits previously deferred are being
amortized to income over the life of the property that gave rise to the credits.
Cumulative Effect of Accounting Change
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and
138 (collectively, SFAS No. 133). Derivative instruments (primarily swaps,
options and futures) are used to manage interest rate exposure and the commodity
price risk inherent in fossil fuel purchases and electricity sales. Under SFAS
No. 133, all derivative instruments, including our energy trading contracts, are
recorded on our consolidated balance sheet as either an asset or liability
measured at fair value.
21
Changes in a derivative's fair value must be recognized currently in earnings
unless specific hedge accounting criteria are met. Cash flows from derivative
instruments are presented in net cash flows from operating activities.
Derivative instruments used to manage commodity price risk inherent in
fuel purchases and electricity sales are classified as energy trading contracts
on our consolidated balance sheet. Energy trading contracts representing
unrealized gain positions are reported as assets; energy trading contracts
representing unrealized loss positions are reported as liabilities.
Prior to January 1, 2001, gains and losses on our derivatives used for
managing commodity price risk were deferred until settlement. These derivatives
were not designated as hedges under SFAS No. 133. Accordingly, on January 1,
2001, we recognized an unrealized gain of $12.9 million, net of $8.5 million of
tax. This gain is presented on our consolidated statement of income as a
cumulative effect of a change in accounting principle.
After January 1, 2001, changes in fair value of all derivative instruments
used for managing commodity price risk that are not designated as hedges are
recognized currently in revenue as discussed above under "- Sales Recognition."
Accounting for derivatives under SFAS No. 133 will increase volatility of our
future earnings.
OPERATING RESULTS
We supply electric energy at retail to approximately 293,000 customers in
Kansas. These customers are classified below as residential, commercial and
industrial as defined in our tariffs. Sales classifications and the related
descriptions for our remaining electricity sales are as follows:
. Wholesale: Sales consist of electric energy supplied to the electric
distribution systems of 27 Kansas cities. It also includes contracts
for the sale, purchase or exchange of electricity with other
utilities and/or marketers.
. System Marketing: Financial transactions entered into on behalf of
system requirements.
. Other: Includes public street and highway lighting and miscellaneous
electric revenues.
Many things will affect our future sales. Our regulated electric utility
sales are significantly impacted by such things as the weather, regulation
(including rate regulation), customer conservation efforts, wholesale demand,
the overall economy of our service area, the City of Wichita's attempt to create
a municipal electric utility, and competitive forces. Our sales are impacted by
demand outside our service territory, the cost of fuel and purchased power,
price volatility and available generation capacity.
Our electric sales for the last three years ended December 31 are as
follows:
2001 2000 1999
---- ---- ----
(In Thousands)
Residential .................... $222,427 $246,665 $220,645
Commercial ..................... 175,899 175,686 169,427
Industrial ..................... 155,990 161,693 163,158
Other .......................... 24,970 23,690 21,855
-------- -------- --------
Total retail ............... $579,286 $607,734 $575,085
Wholesale ...................... 77,762 78,596 63,255
System Marketing ............... 16,077 17,660 --
-------- -------- --------
Total ...................... $673,125 $703,990 $638,340
======== ======== ========
22
The following tables reflect changes in electric sales volumes, as
measured by megawatt hours (MWh), for the years ended December 31, 2001, 2000
and 1999. No sales volumes are included for system marketing sales because these
sales are not based on electricity we generate.
2001 2000 % Change
---- ---- --------
(Thousands of MWh)
Residential .......................... 2,734 2,950 (7.3)
Commercial ........................... 2,632 2,544 3.5
Industrial ........................... 3,488 3,561 (2.0)
Other ................................ 44 45 (2.2)
------ ------
Total retail ..................... 8,898 9,100 (2.2)
Wholesale ............................ 2,479 2,407 3.0
------ ------
Total ............................ 11,377 11,507 (1.1)
====== ======
2000 1999 % Change
---- ---- --------
(Thousands of MWh)
Residential .......................... 2,950 2,601 13.4
Commercial ........................... 2,544 2,413 5.4
Industrial ........................... 3,561 3,548 0.4
Other ................................ 45 45 --
------ ------
Total retail ..................... 9,100 8,607 5.7
Wholesale ............................ 2,407 1,832 31.4
------ ------
Total ............................ 11,507 10,439 10.2
====== ======
2001 compared to 2000:
Net income before accounting change decreased $36.5 million, or 42%.
External sales decreased $30.9 million, or 4%. Residential sales revenue
declined approximately 10% and system marketing sales declined approximately
9%. Residential sales decreased due to weather conditions and our rate decrease,
while system marketing sales decreased because of lower prices.
As a result of the higher cost of sales and operating expenses discussed
below and reduced revenues, EBIT decreased $85.0 million, or 50%. Excluding the
mark-to-market adjustment on fuel derivatives, EBIT would have decreased $63.7
million. Cost of sales increased $36.5 million, or 21%, primarily due to a $21.3
million non-cash mark-to-market adjustment on fuel derivatives as prescribed by
SFAS No. 133, a $5.0 million increase in purchased power costs and a $14.2
million increase in costs associated with the dispatching of electric power.
These increases were partially offset by a decrease in fuel expenses of $4.0
million. Gross profit decreased $67.4 million, or 13%. Operating expenses
increased $16.2 million, or 5%, because of higher operating and maintenance
expenses associated with planned outages and increased selling, general and
administrative expenses.
2000 compared to 1999:
Net income before accounting change increased $2.4 million and total gross
profit increased $12.6 million, or 2%. These increases are due primarily to a
13% increase in residential sales volumes and a 31% increase in wholesale sales
volumes. The increase in residential sales is primarily due to increased demand
caused by warm weather. Cooling-degree days increased by 27%. The increase in
wholesale sales volumes was primarily due to increased wholesale market
opportunities. Items included in energy cost of sales are fuel expense and
purchased power expense (electricity we purchase from others for resale).
Partially offsetting the higher sales was an increase of $53.0 million in
cost of sales primarily due to increased fuel and purchased power expenses of
approximately $25.5 million. Fuel and purchased power expenses were higher
primarily due to increased commodity prices, increased demand from retail
customers because of warmer weather and higher wholesale sales volumes.
23
Business Segments
We have defined two business segments, electric operations and nuclear
generation, based on how management currently evaluates our business. Our
business segments are based on differences in products and services, production
processes and management responsibility.
We manage our business segments' performance based on their earnings
before interest and taxes (EBIT). EBIT does not represent cash flow from
operations as defined by GAAP, should not be construed as an alternative to
operating income and is indicative neither of operating performance nor cash
flows available to fund our cash needs. Items excluded from EBIT are significant
components in understanding and assessing our financial performance. We believe
presentation of EBIT enhances an understanding of financial condition, results
of operations and cash flows because EBIT is used by us to satisfy our debt
service obligations, capital expenditures and other operational needs, as well
as to provide funds for growth. Our computation of EBIT may not be comparable to
other similarly titled measures of other companies.
When sales are made between the segments, the internal transfer price is
determined by us using internally developed transfer pricing estimates that,
while not based on market rates, represent what we believe would be market
prices for capacity and energy.
The following table reflects key information for our two electric utility
business segments:
For the years ended December 31,
--------------------------------
2001 2000 1999
---- ---- ----
(In Thousands)
Electric Operations:
External sales ...................... $ 673,125 $ 703,990 $ 638,340
Depreciation and amortization ....... 64,090 64,242 61,531
Earnings before interest and
taxes (EBIT) (a) ............... 104,390 194,611 193,980
Additions to property, plant and
equipment ........................ 55,402 56,839 53,538
Nuclear Generation (b):
Internal sales ...................... $ 117,659 $ 107,770 $ 108,445
Depreciation and amortization ....... 41,046 40,052 39,629
Earnings (losses) before interest
and taxes (EBIT) (b) ........... (19,078) (24,323) (25,214)
Additions to property, plant and
equipment ........................ 27,349 25,877 10,036
- ----------
(a) EBIT shown above for Electric Operations for 2001 does not include the
$21.4 million unrealized gain on derivatives reported as a cumulative
effect of a change in accounting principle as discussed in Note 5 of the
"Notes to Consolidated Financial Statements". If the effect had been
included, EBIT for the Electric Operations segment for the year ended
December 31, 2001 would have been $125,808.
(b) Nuclear Generation amounts represent our 47% share of Wolf Creek's
operating results.
Electric Operations:
External sales include power produced for sale to wholesale and retail
customers and the amounts associated with the system marketing transactions
discussed above.
2001 compared to 2000: External sales decreased $30.9 million, or 4%.
Residential sales declined approximately 10% and system marketing sales declined
approximately 9%. Residential sales decreased due to weather conditions and our
rate decrease, while system marketing sales decreased because of lower prices.
24
Cost of sales increased $34.0 million, or 23%, primarily due to a $21.3
million non-cash mark-to-market adjustment on fuel derivatives as prescribed by
SFAS No. 133, a $6.5 million decrease in fuel expense, a $5.0 million increase
in purchased power costs and a $14.2 million increase in costs associated with
the dispatching of electric power. Gross profit decreased $64.9 million, or 12%.
As a result of the higher cost of sales and reduced revenues, EBIT decreased
$90.2 million. Excluding the mark-to-market adjustment on fuel derivatives, EBIT
would have decreased $68.9 million.
2000 compared to 1999: External sales increased $65.7 million primarily
due to 13% higher residential sales volumes and 31% higher wholesale sales
volumes. Approximately $17.7 million in system marketing transactions also
increased external sales.
While sales increased $65.7 million, or 10%, EBIT increased only $0.6
million primarily due to higher cost of sales of $53.6 million. Cost of sales
was higher primarily due to increased fuel and purchased power expenses of
approximately $44.3 million.
Fuel and purchased power expenses were higher primarily due to increased
commodity prices, increased demand from retail customers because of warmer
weather and higher wholesale sales volumes.
The cost of fuel in 2000 was significantly affected by increased gas costs
of $9.2 million (despite an 11.2% reduction in MMBtu of gas burned). Our average
natural gas price increased 45% during the year compared to 1999. Additionally,
coal costs increased by $8.2 million primarily due to increasing the quantities
of coal burned in our efforts to minimize gas costs and cost of oil increased
$3.3 million primarily due to increased price and increasing the quantities of
oil burned. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Other Information -- Market Risk
Disclosure" for further discussion.
Operation and maintenance expenses increased $7.0 million primarily due to
our increased sales.
Other expense increased $3.5 million primarily due to transaction costs
associated with the sale of our accounts receivable in a financing transaction
and because of a gain recorded in 1999 on the disposition of property.
Nuclear Generation:
Nuclear Generation has only internal sales because all of its power is
provided to its co-owners: Kansas City Power and Light Company (KCPL), Kansas
Electric Power Cooperative, Inc. and us. We own 47% of Wolf Creek Nuclear
Operating Corporation (WCNOC), the operating company for Wolf Creek Generating
Station (Wolf Creek). Internal sales are priced at an internal transfer price
that Nuclear Generation charges to Electric Operations.
Wolf Creek operated the entire year of 2001 without any refueling outages.
Wolf Creek shut down for 38 days beginning on September 29, 2000 for its
eleventh scheduled refueling and maintenance outage. Internal sales and EBIT
increased during 2001 since the unit operated more during 2001 than during 2000.
During 1999, there was a 36-day refueling and maintenance outage at Wolf Creek.
Since both 2000 and 1999 had refueling outages, the change in internal sales and
EBIT between 2000 and 1999 was immaterial.
Wolf Creek has a scheduled refueling and maintenance outage approximately
every 18 months. An outage began on March 23, 2002. During an outage, Wolf Creek
produces no power for its co-owners; therefore internal sales, EBIT and nuclear
fuel expense decrease.
Income Taxes
2001 compared to 2000: We recorded an income tax benefit in 2001 of $1.6
million and income tax expense in 2000 of $34.0 million. Our effective income
tax rates were a benefit of 5% for December 31, 2001 and an expense of 28% for
December 31, 2000. This change is primarily due to lower earnings before income
taxes in 2001. Earnings before income taxes decreased due to reduced sales
volumes, a reduction in retail sales and system marketing transactions,
25
and rate reductions ordered by the KCC in July 2001. Our effective tax rates are
also affected by the amortization of prior years' investment tax credits and the
tax benefit from corporate-owned life insurance.
2000 compared to 1999: The Federal statutory rate produced effective
income tax rates of 28% for 2000 and 29% for 1999. The effective income tax
rates are lower than the Federal statutory rate of 35% due to differences, such
as amortization of investment tax credits and benefits from corporate-owned life
insurance.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Most of our cash requirements consist of capital expenditures and
maintenance costs designed to improve and maintain facilities that provide
electric service and meet future customer service requirements. Our ability to
provide the cash or debt to fund our capital expenditures depends upon many
things, including available resources, our financial condition and current
market conditions.
Funds are available to us from the sale of securities we register for sale
with the Securities and Exchange Commission. As of December 31, 2001, $50.0
million of KGE first mortgage bonds were registered.
Our mortgage prohibits additional first mortgage bonds from being issued
(except in connection with certain refundings) unless our 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 either two and one-half times the annual interest charges on,
or 10% of the principal amount of, all first mortgage bonds outstanding after
giving effect to the proposed issuance. In addition, the issuance of bonds is
subject to limitations based upon the amount of bondable property additions. As
of December 31, 2001, approximately $279 million principal amount of additional
first mortgage bonds could be issued under the most restrictive tests in the
mortgage.
Our internally generated cash is generally sufficient to fund operations
and debt service payments. We do not maintain independent short-term credit
facilities and rely on Western Resources for short-term cash needs. If Western
Resources is unable to borrow under its credit facilities, we could have a short
term liquidity issue which could require us to obtain a credit facility for our
short-term cash needs and which could result in higher borrowing costs.
On June 28, 2000, Western Resources entered into a $600 million,
multi-year term loan that replaced two revolving credit facilities that matured
on June 30, 2000. The term loan is secured by our and Western Resources' first
mortgage bonds and has a final maturity date of March 17, 2003.
Western Resources also has an arrangement with certain banks to provide a
revolving credit facility on a committed basis totaling $500 million. The
facility is secured by our and Western Resources' first mortgage bonds and
matures on March 17, 2003.
The table below shows the projected future cash payments for our
contractual obligations existing at December 31, 2001:
At December 31, 2001: Payments Due by Period
------------------------------------------------------------
Total 2002 2003 - 2004 2005 - 2006 Thereafter
---------- ------- ----------- ----------- ----------
(In Thousands)
Contractual Obligations
Long-term debt ................... $ 684,360 $ -- $135,000 $165,000 $ 384,360
Operating leases ................. 672,731 41,984 86,888 91,584 452,275
Fossil fuel ...................... 485,540 56,956 69,196 48,520 310,868
Nuclear fuel ..................... 84,038 -- 27,449 10,389 46,200
---------- ------- -------- -------- ----------
Total contractual obligations $1,926,669 $98,940 $318,533 $315,493 $1,193,703
========== ======= ======== ======== ==========
26
Credit Ratings
Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and
Moody's Investors Service (Moody's) are independent credit-rating agencies that
rate Western Resources' and our debt securities. These ratings indicate the
agencies' assessment of our ability to pay interest and principal on these
securities.
On June 1, 2001, Moody's placed Western Resources' and our ratings under
review with direction uncertain. On October 19, 2001, S&P removed us from its
CreditWatch listing and changed Western Resources' and our ratings outlook to
"negative." On November 7, 2001, S&P reaffirmed its negative outlook for Western
Resources and us.
As of March 14, 2002, ratings with these agencies are as follows:
Western Western
Resources Resources
Mortgage Unsecured KGE Mortgage
Bond Rating Debt Bond Rating
----------- --------- ------------
S&P ............... BBB- BB- BB+
Fitch ............. BB+ BB BB+
Moody's ........... Ba1 Ba2 Ba1
In general, declines in Western Resources' and our credit ratings make
debt financing more costly and more difficult to obtain on terms which are
economically favorable to us.
Credit rating agencies are applying more stringent guidelines when rating
utility companies due to increasing competition and utility investment in
non-utility businesses. We do not have any credit rating conditions in any of
the agreements under which our debt has been issued.
Sale of Accounts Receivable
On July 28, 2000, Western Resources and we entered into an asset-backed
securitization agreement under which we periodically transfer an undivided
percentage ownership interest in a revolving pool of our accounts receivable
arising from the sale of electricity to a multi-seller conduit administered by
an independent financial institution through the use of a special purpose entity
(SPE). We account for this transfer as a sale in accordance with SFAS No. 140,
"Accounting for Transfers and Servicing of Financial Assets and Extinguishment
of Liabilities." The agreement was renewed on July 26, 2001 and is annually
renewable upon agreement by both parties.
Under the terms of the agreement, Western Resources and we may transfer
accounts receivable to the bankruptcy-remote SPE and the conduit must purchase
from the SPE an undivided ownership interest of up to $125 million (and upon
request, subject to certain conditions, up to $175 million), in those
receivables. The SPE has been structured to be legally separate from us, but it
is wholly owned by Western Resources and consolidated by us. The percentage
ownership interest in receivables purchased by the conduit may increase or
decrease over time, depending on the characteristics of the SPE's receivables,
including delinquency rates and debtor concentrations. Western Resources
services the receivables transferred to the SPE and receives a servicing fee,
which approximates market compensation for these services.
Under the terms of the agreement, the conduit pays the SPE the face amount
of the undivided interest at the time of purchase. Subsequent to the initial
purchase, additional interests are sold and collections applied by the SPE to
the conduit resulting in an adjustment to the outstanding conduit interest.
We record administrative expense on the undivided interest owned by the
conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the
year ended December 31, 2000. These expenses are included in other income
(expense) in our consolidated statements of income.
27
At December 31, 2001 and 2000, the outstanding balance of SPE receivables
was $43.3 million and $85.5 million, which is net of an undivided interest of
$100.0 million and $115.0 million in receivables sold by the SPE to the conduit.
Our retained interest in the SPE's receivables is reported at fair value and is
subordinate to, and provides credit enhancement for, the conduit's ownership
interest in the SPE's receivables. Our retained interest is available to the
conduit to pay any fees or expenses due to the conduit, and to absorb all credit
losses incurred on any of the SPE's receivables. The retained interest is
included in accounts receivable, net, in our consolidated balance sheets.
Cash Flows from (used in) Operating Activities
Our primary source of operating cash flows are the operations of our
electric utility. Cash flows from operating activities decreased $60.2 million
to $145.6 million in 2001, from $205.8 million in 2000. This decrease is mostly
attributable to changes in our working capital. Operating cash flows produced in
2001 also decreased because we purchased additional coal and oil to restock our
inventory from the levels that existed in December 2000.
Cash flows from operating activities decreased $4.6 million to $205.8
million in 2000, from $210.4 million in 1999. This decrease is mostly
attributable to changes in working capital.
Cash Flows from (used in) Financing Activities
Net cash used in financing activities totaled $64.4 million for the year
ended December 31, 2001 as compared to $116.1 for the same period of 2000 due
primarily to changes in net advances to Western Resources.
Future Cash Requirements
We believe that internally generated funds and borrowings from Western
Resources will be sufficient to meet our operating and capital expenditure
requirements and debt service payments through at least the year 2004.
Uncertainties affecting our ability to meet these requirements include the
factors affecting sales described above, the impact of inflation on operating
expenses, regulatory action, the impact of the rate reduction, Western
Resources' ability to consummate the financial plan furnished to the KCC and to
refinance outstanding debt discussed under "--Summary of Significant Items --
KCC Proceedings and Orders" above, compliance with future environmental
regulations and municipalization efforts by the City of Wichita.
We forecast that we will need additional capacity of approximately 150
megawatts (MW) by 2006 to serve our customer's expected electricity needs. We
will determine how to meet this need at a future date.
In 2003, $135 million of our first mortgage bonds will mature and $65
million of our first mortgage bonds will mature in 2005.
Our business requires significant capital investments. We currently expect
that through the year 2004, we will need cash mostly for ongoing utility
construction and maintenance programs designed to maintain and improve
facilities providing electric service.
Capital expenditures for 2001 and anticipated capital expenditures for
2002 through 2004 are as follows:
Electric Nuclear
Operations Generation Total
---------- ---------- -----
(In Thousands)
2001.......... $55,402 $27,349 $82,751
2002.......... 53,900 10,000 63,900
2003.......... 66,000 30,100 96,100
2004.......... 65,300 30,100 95,400
These estimates are prepared for planning purposes and will be revised
from time to time. See Note 2 of the "Notes to Consolidated Financial
Statements." Actual expenditures will differ from our estimates.
28
Capital Structure
Our capital structure at December 31, 2001 and 2000 was as follows:
2001 2000
---- ----
Shareholder's equity ...... 61% 62%
Long-term debt, net ....... 39 38
--- ---
Total ................. 100% 100%
=== ===
OTHER INFORMATION
Electric Utility
City of Wichita Municipalization Effort:
In December 1999, the City Council of Wichita, Kansas, authorized the
hiring of an outside consultant to determine the feasibility of creating a
municipal electric utility to replace us as the supplier of electricity in
Wichita. The feasibility study was released in February 2001 and estimates that
the City of Wichita would be required to pay us $145 million for our stranded
costs if it were to municipalize. However, we estimate the amount to be
substantially greater. In order to municipalize our Wichita electric facilities,
the City of Wichita would be required to purchase our facilities or build a
separate independent system and arrange for its own power supply. These costs
are in addition to the stranded costs for which the city would be required to
reimburse us. On February 2, 2001, the City of Wichita announced its intention
to proceed with its attempt to municipalize our retail electric utility business
in Wichita. We will oppose municipalization efforts by the City of Wichita.
Should the city be successful in its municipalization efforts without providing
us adequate compensation for our assets and lost revenues, the adverse effect on
our business and financial condition could be material.
Our franchise with the City of Wichita to provide retail electric service
is effective through December 1, 2002. There can be no assurance that we can
successfully renegotiate the franchise with terms similar, or as favorable, as
those in the current franchise. Under Kansas law, we will continue to have the
right to serve the customers in Wichita following the expiration of the
franchise, assuming the system is not municipalized. Customers within the
Wichita metropolitan area account for approximately 51% of our total energy
sales.
FERC Proceedings:
In September 1999, the City of Wichita filed a complaint with FERC against
us alleging improper affiliate transactions between Western Resources' KPL
division and KGE. The City of Wichita asked that FERC equalize the generation
costs between KPL and us, in addition to other matters. After hearings on the
case, a FERC administrative law judge ruled in our favor confirming that no
change in rates was required. On December 13, 2000, the City of Wichita filed a
brief with FERC asking that the Commission overturn the judge's decision. On
January 5, 2001, we filed a brief opposing the City's position. On November 23,
2001, FERC issued an order affirming the judge's decision. We anticipate no
further activity regarding this complaint because the City of Wichita's time to
appeal FERC's order has expired.
Competition and Deregulation:
Electric utilities have historically operated in a rate regulated
environment. Federal and state regulatory agencies having jurisdiction over our
rates and services and other utilities have initiated steps that were expected
to result in a more competitive environment for utility services. The Kansas
Legislature took no action on deregulation in 2001 or 2000.
29
In a deregulated environment, utility companies that are not responsive to
a competitive energy marketplace may suffer erosion in market share, revenues
and profits. Possible types of competition include cogeneration,
self-generation, retail wheeling, or municipalization. Retail wheeling is the
ability of individual customers to choose a power provider other than us and we
would provide the transmission service for this power. Kansas does not allow
retail wheeling and no such regulation is pending or being considered. However,
if retail wheeling were implemented in Kansas, increased competition for retail
electricity sales may reduce our future electric utility earnings compared to
our historical electric utility earnings. Our average retail rates are
approximately 10% below the national average for retail customers. Because of
these rates, we expect to retain a substantial part of our current volume of
sales in a competitive environment.
Increased competition for retail electricity sales may in the future
reduce our earnings, which could have a material adverse impact on our
operations and our financial condition. A material non-cash charge to earnings
may be required should we discontinue accounting under SFAS No. 71. See
"-Stranded Costs" below for additional information regarding SFAS No. 71.
The 1992 Energy Policy Act began deregulating the electricity market for
generation. The Energy Policy Act permitted the FERC to order electric utilities
to allow third parties the use of their transmission systems to sell electric
power to wholesale customers. In 1992, we agreed to open access of our
transmission system for wholesale transactions. FERC also requires us to provide
transmission services to others under terms comparable to those we provide
ourselves. In December 1999, FERC issued an order (FERC Order No. 2000)
encouraging formation of regional transmission organizations (RTOs). RTOs are
designed to control the wholesale transmission services of the utilities in
their regions thereby facilitating open and more competitive markets in bulk
power.
After the FERC rejected several attempts by the Southwest Power Pool (SPP)
to seek RTO status, the SPP and the Midwest Independent System Operator, Inc.
(MISO) agreed in October 2001 to consolidate and form an RTO. In December 2001,
the FERC approved this newly formed MISO as the first RTO. The agreement to
consolidate was executed in February 2002 and the transaction is expected to
close in 2003. This new organization will operate our transmission system as
part of an interconnected transmission system encompassing over 120,000 MW of
generation capacity located in 20 states. MISO will collect revenues
attributable to the use of each member's transmission system, and each member
will be able to transmit power purchased, generated for sale or bought for
resale in the wholesale market throughout the entire MISO system. Although each
member will have priority over the use of its own transmission facilities for
selling power to its wholesale customers or others, each member will be charged
the same uniform transmission rate as other energy suppliers who are able to
sell power to them. We intend to file with the FERC and the KCC to transfer
control over the operation of our transmission facilities to MISO. We anticipate
that FERC Order No. 2000 and our participation in the MISO will not have a
material effect on our operations.
Stranded Costs:
The definition of stranded costs for a utility business is the investment
in and carrying costs on property, plant and equipment and other regulatory
assets that exceed the amount that can be recovered in a competitive market. We
currently apply accounting standards that recognize the economic effects of rate
regulation and record regulatory assets and liabilities related to our fossil
generation, nuclear generation and power delivery operations. If we determine
that we no longer meet the criteria of SFAS No. 71, we may have a material
extraordinary non-cash charge to operations. Reasons for discontinuing SFAS No.
71 accounting treatment include increasing competition that restricts our
ability to charge prices needed to recover costs already incurred, a significant
change by regulators from a cost-based rate regulation to another form of rate
regulation and the impact should the City of Wichita municipalization efforts be
successful. We periodically review SFAS No. 71 criteria and believe our net
regulatory assets, including those related to generation, are probable of future
recovery. If we discontinue SFAS No. 71 accounting treatment based upon
competitive or other events, such as the successful municipalization efforts by
areas we serve, the value of our net regulatory assets and our utility plant
investments, particularly Wolf Creek, may be significantly impacted.
Regulatory changes, including competition or successful municipalization
efforts by the City of Wichita, could adversely impact our ability to recover
our investment in these assets. As of December 31, 2001, we have
30
recorded regulatory assets that are currently subject to recovery in future
rates of approximately $244.1 million. Of this amount, $174.4 million is a
receivable for income tax benefits previously passed on to customers. The
remainder of the regulatory assets are items that may give rise to stranded
costs and include coal contract settlement costs, deferred plant costs and debt
issuance costs.
In a competitive environment or because of such successful
municipalization efforts, we may not be able to fully recover our entire
investment in Wolf Creek. We presently own 47% of Wolf Creek. We may also have
stranded costs from an inability to recover our environmental remediation costs
and long-term fuel contract costs in a competitive environment. If we determine
that we have stranded costs and we cannot recover our investment in these
assets, our future net income will be lower than our historical net income has
been unless we compensate for the loss of such income with other measures.
Nuclear Decommissioning:
Decommissioning is a nuclear industry term for the permanent shutdown of a
nuclear power plant. The NRC will terminate a plant's license and release the
property for unrestricted use when a company has reduced the residual
radioactivity of a nuclear plant to a level mandated by the NRC. The NRC
requires companies with nuclear plants to prepare formal financial plans to fund
decommissioning. These plans are designed so that funds required for
decommissioning will be accumulated during the estimated remaining life of the
related nuclear power plant.
We accrue decommissioning costs over the expected life of the Wolf Creek
generating facility. The accrual is based on estimated unrecovered
decommissioning costs, which consider inflation over the remaining estimated
life of the generating facility and are net of expected earnings on amounts
recovered from customers and deposited in an external trust fund.
On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost
Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost
Study on April 26, 2000. Based on the study, our share of Wolf Creek's
decommissioning costs, under the immediate dismantlement method, is estimated to
be approximately $631 million during the period 2025 through 2034, or
approximately $221 million in 1999 dollars. These costs include decontamination,
dismantling and site restoration and were calculated using an assumed inflation
rate of 3.6% over the remaining service life from 1999 of 26 years. The actual
decommissioning costs may vary from the estimates because of changes in the
assumed dates of decommissioning, changes in regulatory requirements, changes in
technology and changes in costs for labor, materials and equipment. On May 26,
2000, we filed an application with the KCC requesting approval of the funding of
our decommissioning trust on this basis. Approval was granted by the KCC on
September 20, 2000.
Decommissioning costs are currently being charged to operating expense in
accordance with prior KCC orders. Electric rates charged to customers provide
for recovery of these decommissioning costs over the life of Wolf Creek. Amounts
expensed approximated $4.0 million in 2001 and will increase annually to $5.5
million in 2024. These amounts are deposited in an external trust fund. The
average after-tax expected return on trust assets is 5.8%.
Our investment in the decommissioning fund is recorded at fair value,
including reinvested earnings. It approximated $66.6 million at December 31,
2001 and $64.2 million at December 31, 2000. Trust fund earnings accumulate in
the fund balance and increase the recorded decommissioning liability.
Asset Retirement Obligations:
In August 2001, the Financial Accounting Standards Board issued SFAS No.
143, "Accounting for Asset Retirement Obligations." The standard requires
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. When it is initially recorded,
we will capitalize the estimated asset retirement obligation by increasing the
carrying amount of the related long-lived asset. The liability will be accreted
to its present value each period and the capitalized cost will be depreciated
over the life of the asset. The standard is effective for fiscal years beginning
after June 15, 2002. We expect to adopt this standard January 1, 2003. This
standard will impact the way we currently account for the decommissioning of
Wolf Creek. In addition to the
31
accounting for the Wolf Creek decommissioning, we are also reviewing what impact
this pronouncement will have on our current accounting practices and our results
of operations as it relates to other asset retirement obligations we may
identify. The impact is unknown at this time.
Related Party Transactions
Our cash management function, including cash receipts and disbursements,
is performed by Western Resources. An intercompany account is used to record net
receipts and disbursements between KGE and Western Resources and KGE and WR
Receivables Corporation. The net amount receivable from affiliates approximated
$17.3 million at December 31, 2001 and $53.1 million at December 31, 2000 as
reflected in our consolidated balance sheets.
Certain operating expenses have been allocated to us from Western
Resources. These expenses are allocated, depending on the nature of the expense,
based on allocation studies, net investment, number of customers, and/or other
appropriate factors. Management believes such allocation procedures are
reasonable. During 2001, we declared dividends to Western Resources of $100
million.
During the fourth quarter of 2001, we entered into an option agreement to
sell an office building located in downtown Wichita, Kansas, to Protection One,
a subsidiary of Westar Industries, which is a wholly owned subsidiary of Western
Resources for approximately $0.5 million. The sales price was determined by
management based on three independent appraisers' findings.
Market Risk Disclosure
Market Price Risks:
We are exposed to market risk, including market changes, changes in
commodity prices and interest rates.
Commodity Price Exposure:
We are exposed to commodity price changes and use derivatives for
non-trading purposes primarily to reduce exposure relative to the volatility of
market prices. From 2000 to 2001, we experienced an 11% decrease in the average
price per MW of electricity purchased for utility operations. However, purchased
power markets are volatile and if we were to have a 10% increase from 2001 to
2002, given the amount of power purchased for utility operations during 2001, we
would have an exposure of approximately $1.3 million of operating income. Due to
the volatility of the power market, past prices cannot be used to predict future
prices.
We use a mix of various fuel types, including coal and natural gas, to
operate our system, which helps lessen our risk associated with any one fuel
type. A significant portion of our coal requirements are under long-term
contract, which removes most of the price risk, associated with this commodity
type. However, from January 1, 2001 to December 31, 2001, we experienced a 7.3%
increase in our average cost for natural gas purchased for utility operations,
or an increase of $0.24 per MMBtu. The higher natural gas prices increased our
total cost of gas purchased during 2001 by approximately $1.8 million although
we decreased the quantity burned by 4.9 million MMBtu. If we were to have a
similar increase from 2001 to 2002, we would have an exposure of approximately
$2.0 million of operating income. Based on MMBtus of natural gas and fuel oil
burned during 2001, we had exposure of approximately $4.5 million of operating
income for a 10% change in average price paid per MMBtu. Due to the volatility
of natural gas prices, past prices cannot be used to predict future prices.
Additional factors that affect our commodity price exposure are the
quantity and availability of fuel used for generation and the quantity of
electricity customers will consume. Quantities of fossil fuel used for
generation could vary dramatically year to year based on the individual fuel's
availability, price, deliverability, unit outages and nuclear refueling. Our
customer's electricity usage could also vary dramatically year to year based on
the weather or other factors.
32
Interest Rate Exposure:
We had approximately $46.4 million of variable rate debt as of December
31, 2001. A 100 basis point change in each debt series' benchmark rate at
December 31, 2001, used to set the rate for such series would impact net income
on an annual basis by approximately $0.3 million after tax.
Hedging Activity:
In an effort to mitigate fuel commodity price market risk, Western
Resources and we jointly use hedging arrangements to minimize our exposure to
increased coal, natural gas and oil prices. Our future exposure to changes in
fossil fuel prices will be dependent upon the market prices and the extent and
effectiveness of any hedging arrangements we enter.
During the third quarter of 2001, Western Resources entered into hedging
relationships to manage commodity price risk associated with future natural gas
purchases in order to protect us and our customers from adverse price
fluctuations in the natural gas market. Western Resources is using futures and
swap contracts of which our allocated portion of the total notional volume is
26,910,000 MMBtu and terms extending through July 2004 to hedge price risk for a
portion of our anticipated natural gas fuel requirements for our generation
facilities. We are allocated our proportionate share of the benefits and costs
of Western Resources' commodity price risk management program based on fuel
forecasts for Western Resources and us. These allocated benefits and costs are
recognized in our financial statements. Based on our best estimate of generating
needs, we believe we have hedged 75% of our system requirements through this
hedge. We have designated these hedging relationships as cash flow hedges in
accordance with SFAS No. 133.
The following table summarizes the effects our natural gas hedge and our
interest rate swap had on our financial position and results of operations for
2001:
Natural gas
Hedge (a)
-----------
(Dollars in Thousands)
Fair value of derivative instruments:
Current................................................ $ (6,892)
Long-term.............................................. (6,103)
---------
Total............................................... $ (12,995)
=========
Amounts in accumulated other comprehensive income.......... $ (20,064)
Hedge ineffectiveness...................................... 1,760
Estimated income tax benefit............................... 7,281
---------
Net comprehensive loss.............................. $ (11,023)
=========
Anticipated reclassifications to earnings during 2002 (b).. $ 6,892
Duration of hedge designation as of December 31, 2001...... 31 months
- ----------
(a) Natural gas hedge liabilities are classified in the balance sheet as
energy trading contracts. Gas prices have dropped since we entered into
these hedging relationships. Due to the volatility of gas commodity
prices, it is probable that gas prices will increase and decrease over the
31 months that these relationships are in place.
(b) The actual amounts that will be reclassified to earnings could vary
materially from this estimated amount due to changes in market conditions.
Fair Value of Energy Trading Contracts
The tables below show the difference between the market value and the
notional values of energy trading contracts outstanding at December 31, 2001,
their sources and maturity periods:
33
Fair Value of Contracts (In Thousands)
Net fair value of contracts outstanding at the beginning of the period............ $ 21,418
Contracts realized or otherwise settled during the period......................... (14,354)
Fair value of new contracts entered into during the period........................ (18,277)
----------
Fair value of contracts outstanding at the end of the period...................... $ (11,213)
==========
Fair Value of Contracts at End of Period
------------------------------------------------------------------
Maturity Maturity in
Total Fair Less Than Maturity Maturity Excess of
Source of Fair Value Value 1 Year 1-3 Years 4-5 Years 5 Years
----------- --------- ---------- --------- ------------
(In Thousands)
Prices actively quoted (futures)........... $ (368) $ 33 $ (401) $ -- $ --
Prices provided by other external sources
(swaps and forwards).................... (10,968) (5,224) (5,744) -- --
Prices based on models and other valuation
models (options and other).............. 123 123 -- -- --
---------- -------- ---------- --------- --------
$ (11,213) $ (5,068) $ (6,145) $ -- $ --
========== ======== ========== ========= ========
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to market risk disclosure is set forth in "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Other Information -- Market Risk Disclosure" included herein.
34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants........................................................... 36
Financial Statements:
Consolidated Balance Sheets, December 31, 2001 and 2000....................................... 37
Consolidated Statements of Income and Comprehensive Income (Loss) for the years ended
December 31, 2001, 2000 and 1999.......................................................... 38
Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and
1999...................................................................................... 39
Consolidated Statements of Shareholder's Equity for the years ended December 31, 2001,
2000 and 1999............................................................................. 40
Notes to Consolidated Financial Statements.................................................... 41
SCHEDULE OMITTED
The following schedules are omitted because of the absence of the financial
conditions under which they are required or the information is included in the
financial statements and schedules presented:
I, II, III, IV, and V
35
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Kansas Gas and Electric Company:
We have audited the accompanying consolidated balance sheets of Kansas Gas
and Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) as
of December 31, 2001 and 2000, and the related consolidated statements of
income, comprehensive income, cash flows, and shareholder's equity for each of
the three years in the period ended December 31, 2001. 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 conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audits 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 provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Kansas Gas and Electric
Company as of December 31, 2001 and 2000, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
2001, in conformity with accounting principles generally accepted in the United
States.
As explained in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
March 27, 2002
36
KANSAS GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
December 31,
-------------------------
2001 2000
----------- ----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ......................................... $ 5,564 $ 7,101
Accounts receivable, net .......................................... 45,209 87,921
Receivable from affiliates ........................................ 17,349 53,107
Inventories and supplies, net ..................................... 65,531 46,388
Energy trading contracts .......................................... 4,887 --
Deferred tax assets ............................................... 1,002 --
Prepaid expenses and other ........................................ 23,312 20,591
----------- ----------
Total Current Assets ......................................... 162,854 215,108
----------- ----------
PROPERTY, PLANT AND EQUIPMENT, NET .................................... 2,426,875 2,450,061
----------- ----------
OTHER ASSETS:
Regulatory assets ................................................. 244,108 225,479
Other ............................................................. 96,208 97,925
----------- ----------
Total Other Assets ........................................... 340,316 323,404
----------- ----------
TOTAL ASSETS .......................................................... $ 2,930,045 $2,988,573
=========== ==========
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Accounts payable .................................................. $ 52,657 $ 51,149
Accrued liabilities ............................................... 36,580 28,245
Energy trading contracts .......................................... 9,970 --
Deferred income taxes ............................................. -- 11,980
Other ............................................................. 35,151 32,809
----------- ----------
Total Current Liabilities .................................... 134,358 124,183
----------- ----------
LONG-TERM LIABILITIES:
Long-term debt, net ............................................... 684,360 684,366
Deferred income taxes and investment tax credits .................. 726,676 724,456
Deferred gain from sale-leaseback ................................. 174,466 186,294
Energy trading contracts .......................................... 6,130 --
Other ............................................................. 155,666 160,061
----------- ----------
Total Long-Term Liabilities .................................. 1,747,298 1,755,177
----------- ----------
COMMITMENTS AND CONTINGENCIES (NOTE 11)
SHAREHOLDER'S EQUITY:
Common stock, without par value; authorized and issued 1,000 shares 1,065,634 1,065,634
Accumulated other comprehensive loss, net ......................... (11,023) --
Retained earnings ................................................. (6,222) 43,579
----------- ----------
Total Shareholder's Equity ................................... 1,048,389 1,109,213
----------- ----------
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY ............................ $ 2,930,045 $2,988,573
=========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
37
KANSAS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
AND COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
Year Ended December 31,
2001 2000 1999
--------- -------- --------
SALES .............................................................. $ 673,125 $703,990 $638,340
COST OF SALES ...................................................... 207,176 170,672 117,647
--------- -------- --------
GROSS PROFIT ....................................................... 465,949 533,318 520,693
--------- -------- --------
OPERATING EXPENSES:
Operating and maintenance expense .............................. 194,101 189,456 181,784
Depreciation and amortization .................................. 105,136 104,294 101,160
Selling, general and administrative expense .................... 73,441 62,710 65,900
--------- -------- --------
Total Operating Expenses ................................. 372,678 356,460 348,844
--------- -------- --------
INCOME FROM OPERATIONS ............................................. 93,271 176,858 171,849
OTHER EXPENSE ...................................................... 7,959 6,570 3,083
--------- -------- --------
EARNINGS BEFORE INTEREST AND TAXES ................................. 85,312 170,288 168,766
--------- -------- --------
INTEREST EXPENSE:
Interest expense on long-term debt ............................. 45,644 46,241 45,920
Interest expense on short-term debt and other .................. 3,967 3,364 3,598
--------- -------- --------
Total Interest Expense ................................... 49,611 49,605 49,518
--------- -------- --------
EARNINGS BEFORE INCOME TAXES ....................................... 35,701 120,683 119,248
Income tax (benefit) expense ....................................... (1,600) 33,975 34,987
--------- -------- --------
NET INCOME BEFORE ACCOUNTING CHANGE ................................ 37,301 86,708 84,261
Cumulative effect of accounting change, net of tax of $8,520 ....... 12,898 -- --
--------- -------- --------
NET INCOME ......................................................... $ 50,199 $ 86,708 $ 84,261
========= ======== ========
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Unrealized holding losses on cash flow hedges arising during the
period ..................................................... $ (20,064) $ -- $ --
Reclassification adjustment for activity included in net income 1,760 -- --
Income tax benefit ............................................. 7,281 -- --
--------- -------- --------
Total other comprehensive loss, net of tax ............... (11,023) -- --
--------- -------- --------
COMPREHENSIVE INCOME ............................................... $ 39,176 $ 86,708 $ 84,261
========= ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
38
KANSAS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31,
2001 2000 1999
--------- --------- ---------
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income ....................................................... $ 50,199 $ 86,708 $ 84,261
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Cumulative effect of accounting change ........................... (12,898) -- --
Depreciation and amortization .................................... 105,136 104,294 101,160
Amortization of nuclear fuel ..................................... 16,965 14,971 15,464
Amortization of deferred gain from sale-leaseback ................ (11,828) (11,828) (11,828)
Net deferred taxes ............................................... (12,001) (38,525) (10,155)
Net changes in energy trading assets and liabilities ............. 14,327 -- --
Changes in working capital items:
Accounts receivable, net ...................................... 28,026 21,187 (1,238)
Inventories and supplies, net ................................. (19,143) (209) (3,059)
Prepaid expenses and other .................................... (2,721) 5,534 (3,410)
Accounts payable .............................................. 1,508 (3,433) (1,515)
Accrued liabilities ........................................... 8,335 193 (6,147)
Changes in other assets and liabilities .......................... (20,319) 26,938 46,858
--------- --------- ---------
Cash flows from operating activities ................... 145,586 205,830 210,391
--------- --------- ---------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment, net .................. (82,751) (82,716) (63,574)
--------- --------- ---------
Cash flows used in investing activities ................ (82,751) (82,716) (63,574)
--------- --------- ---------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Advances to parent company, net .................................. 35,758 (16,020) (46,801)
Retirements of long-term debt .................................... (130) (30) (20)
Dividends to parent company ...................................... (100,000) (100,000) (100,000)
--------- --------- ---------
Cash flows used in financing activities ................ (64,372) (116,050) (146,821)
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ................. (1,537) 7,064 (4)
CASH AND CASH EQUIVALENTS:
Beginning of period .............................................. 7,101 37 41
--------- --------- ---------
End of period .................................................... $ 5,564 $ 7,101 $ 37
========= ========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
CASH PAID FOR:
Interest on financing activities, net of amount capitalized ...... $ 86,906 $ 85,308 $ 77,668
Income taxes ..................................................... -- 22,200 --
The accompanying notes are an integral part of these consolidated financial
statements.
39
KANSAS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(Dollars in Thousands)
Year Ended December 31,
-----------------------------------------
2001 2000 1999
----------- ----------- -----------
Common Stock ...................... $ 1,065,634 $ 1,065,634 $ 1,065,634
----------- ----------- -----------
Retained Earnings:
Beginning balance .............. 43,579 56,871 72,610
Comprehensive income ........... 39,176 86,708 84,261
Dividends to parent company .... (100,000) (100,000) (100,000)
----------- ----------- -----------
Ending balance ................. (17,245) 43,579 56,871
----------- ----------- -----------
Total Shareholder's Equity ........ $ 1,048,389 $ 1,109,213 $ 1,122,505
=========== =========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
40
KANSAS GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF OUR BUSINESS
Kansas Gas and Electric Company (KGE, the company, we, us or our) is a
rate-regulated electric utility incorporated in 1990 in the State of Kansas. We
are a wholly owned subsidiary of Western Resources, Inc. and we provide
rate-regulated electric service using the name Westar Energy. We are engaged
principally in the generation, purchase, transmission, distribution and sale of
electricity in southeastern Kansas, including the Wichita metropolitan area. Our
corporate headquarters are located in Wichita, Kansas.
We own 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the
operating company for Wolf Creek Generating Station (Wolf Creek). We record our
proportionate share of all transactions of WCNOC as we do other jointly owned
facilities.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
We prepare our consolidated financial statements in accordance with
accounting principles generally accepted in the United States (GAAP). Undivided
interests in jointly owned generation facilities are consolidated on a pro rata
basis. All material intercompany accounts and transactions have been eliminated
in consolidation.
Use of Management's Estimates
The preparation of consolidated financial statements requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities, and disclosure of contingent assets and liabilities at the date of
our consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
Regulatory Accounting
We currently apply accounting standards for our regulated utility
operations that recognize the economic effects of rate regulation in accordance
with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation" and, accordingly, have recorded
regulatory assets and liabilities when required by a regulatory order or based
on regulatory precedent.
Cash and Cash Equivalents
We consider highly liquid investments with a maturity of three months or
less when purchased to be cash equivalents.
Inventories and Supplies
Inventories and supplies are stated at average cost.
Property, Plant and Equipment
Property, plant and equipment is stated at cost. For utility plant, cost
includes contracted services, direct labor and materials, indirect charges for
engineering and supervision and an allowance for funds used during construction
(AFUDC). AFUDC represents the cost of borrowed funds used to finance
construction projects. The AFUDC rate was 8.57% in 2001, 7.45% in 2000 and 6.00%
in 1999. The cost of additions to utility plant and
41
replacement units of property are capitalized. Interest capitalized into
construction in progress was $1.4 million in 2001, $1.0 million in 2000 and $1.0
million in 1999.
Maintenance costs and replacement of minor items of property are charged
to expense as incurred. Incremental costs incurred during scheduled Wolf Creek
refueling and maintenance outages are deferred and amortized monthly over the
unit's operating cycle, normally about 18 months. When units of depreciable
property are retired, the original cost and removal cost, less salvage value,
are charged to accumulated depreciation.
In accordance with regulatory decisions made by the Kansas Corporation
Commission (KCC), the acquisition premium of approximately $801 million
resulting from Western Resources' acquisition of KGE in 1992 is being amortized
over 40 years. The acquisition premium is classified as electric plant in
service. Accumulated amortization totaled $128.3 million as of December 31, 2001
and $108.2 million as of December 31, 2000.
Depreciation
Utility plant is depreciated on the straight-line method at the lesser of
rates set by the KCC or rates based on the estimated remaining useful lives of
the assets, which are based on an average annual composite basis using group
rates that approximated 2.80% during 2001, 2.81% during 2000 and 2.76% during
1999. In its rate order of July 25, 2001, the KCC extended the recovery period
for our generating assets, including Wolf Creek for regulatory rate making
purposes. The impact of this decision reduced our retail electric rates by
approximately $14.3 million on an annual basis. We intend to file an application
for an accounting authority order with the KCC to allow the creation of a
regulatory asset for the difference between our book and regulatory
depreciation. We cannot predict whether the KCC will approve our application.
Depreciable lives of property, plant and equipment are as follows:
Fossil generating facilities ............... 10 to 46 years
Nuclear generating facilities .............. 38 years
Transmission facilities .................... 27 to 65 years
Distribution facilities .................... 20 to 65 years
Other ...................................... 3 to 50 years
Nuclear Fuel
Our share of the cost of nuclear fuel in process of refinement,
conversion, enrichment and fabrication is recorded as an asset in property,
plant and equipment on our consolidated balance sheets at original cost and is
amortized to cost of sales based upon the quantity of heat produced for the
generation of electricity. The accumulated amortization of nuclear fuel in the
reactor was $35.6 million at December 31, 2001 and $18.6 million at December 31,
2000. Spent fuel charged to cost of sales was $22.1 million in 2001, $19.6
million in 2000 and $20.1 million in 1999.
42
Regulatory Assets and Liabilities
Regulatory assets represent probable future revenue associated with
certain costs that will be recovered from customers through the rate-making
process. Regulatory liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers through the
rate-making process. We have recorded these regulatory assets and liabilities in
accordance with SFAS No. 71. If we were required to terminate application of
SFAS No. 71 for all of our regulated operations, we would have to record the
amounts of all regulatory assets and liabilities in our consolidated statements
of income at that time. Our earnings would be reduced by the total amount in the
table below, net of applicable income taxes. Regulatory assets and liabilities
reflected in our consolidated financial statements are as follows:
As of December 31,
----------------------
2001 2000
-------- --------
(In Thousands)
Recoverable income taxes ........... $174,354 $151,841
Debt issuance costs ................ 31,271 34,215
Deferred plant costs ............... 29,499 29,921
Other regulatory assets ............ 8,984 9,502
-------- --------
Total regulatory assets ........ $244,108 $225,479
======== ========
Total regulatory liabilities ... $ 4,247 $ 618
======== ========
. Recoverable income taxes: Recoverable income taxes represent amounts
due from customers for accelerated tax benefits which have been
previously flowed through to customers and are expected to be
recovered in the future as the accelerated tax benefits reverse.
. Debt issuance costs: Debt reacquisition expenses are amortized over
the remaining term of the reacquired debt or, if refinanced, the
term of the new debt. Debt issuance costs are amortized over the
term of the associated debt.
. Deferred plant costs: Costs related to the Wolf Creek nuclear
generating facility.
We expect to recover all of the above regulatory assets in rates charged
to customers. A return is allowed on deferred plant costs and coal contract
settlement costs (included in "Other regulatory assets" in the table above).
Cash Surrender Value of Life Insurance
The following amounts related to corporate-owned life insurance policies
(COLI) are recorded in other long-term assets on our consolidated balance sheets
at December 31:
2001 2000
-------- --------
(In Millions)
Cash surrender value of policies (a) ....... $ 656.3 $ 595.5
Borrowings against policies ................ (643.1) (584.8)
-------- --------
COLI, net ............................. $ 13.2 $ 10.7
======== ========
----------
(a) Cash surrender value of policies as presented represents the value
of the policies as of the end of the respective policy years and not
as of December 31, 2001 and 2000.
Income is recorded for increases in cash surrender value and net death
proceeds. Interest incurred on amounts borrowed is offset against policy income.
Income recognized from death proceeds is highly variable from period to period.
Death benefits recognized as other income approximated $0.3 million in 2001,
$0.2 million in 2000 and $0.1million in 1999.
43
Sales Recognition
Energy sales are recognized as services are rendered and include an
estimate for energy delivered but unbilled at the end of each year, except for
energy trading activities. Power marketing activities are accounted for under
the mark-to-market method of accounting. Under this method, changes in the
portfolio value are recognized as gains or losses in the period of change. The
net mark-to-market change is included in energy sales in our consolidated
statements of income. The resulting unrealized gains and losses are recorded as
energy trading assets and liabilities on our consolidated balance sheets.
We primarily use quoted market prices to value our power marketing and
energy trading contracts. When market prices are not readily available or
determinable, we use alternative approaches, such as model pricing. The market
prices used to value these transactions reflect our best estimate considering
various factors, including closing exchange and over-the counter quotations,
time value and volatility factors underlying the commitments. Results actually
achieved from these activities could vary materially from intended results and
could unfavorably affect our financial results. Financially settled trading
transactions are reported on a net basis, reflecting the financial nature of
these transactions. Physically settled trading transactions are recorded on a
gross basis in operating revenues and fuel and purchased power expense.
Income Taxes
Our consolidated financial statements use the liability method to reflect
income taxes. Deferred tax assets and liabilities are recognized for temporary
differences in amounts recorded for financial reporting purposes and their
respective tax bases. We amortize deferred investment tax credits over the lives
of the related properties.
Cumulative Effect of Accounting Change
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and
138 (collectively, SFAS No. 133). Western Resources uses derivative instruments
(primarily swaps, options and futures) to manage the commodity price risk
inherent in fossil fuel purchases and electricity sales. We are allocated our
proportionate share of the benefits and costs of Western Resources' commodity
price risk management program based on fuel forecasts for Western Resources and
us. These allocated benefits and costs are recognized in our financial
statements.
Under SFAS No. 133, all derivative instruments, including our energy
trading contracts, are recorded on our balance sheet as either an asset or
liability measured at fair value. Changes in a derivative's fair value must be
recognized currently in earnings unless specific hedge accounting criteria are
met. Cash flows from derivative instruments are presented in net cash flows from
operating activities.
Derivative instruments used to manage commodity price risk inherent in
fuel purchases and electricity sales are classified as energy trading contracts
on our consolidated balance sheet. Energy trading contracts representing
unrealized gain positions are reported as assets; energy trading contracts
representing unrealized loss positions are reported as liabilities.
Prior to January 1, 2001, gains and losses on derivatives used for
managing commodity price risk were deferred until settlement. These derivatives
were not designated as hedges under SFAS No. 133. Accordingly, on January 1,
2001, we recognized an unrealized gain of $12.9 million, net of $8.5 million of
tax. This gain is presented on our consolidated statement of income as a
cumulative effect of a change in accounting principle.
After January 1, 2001, changes in fair value of all derivative instruments
used for managing commodity price risk that are not designated as hedges are
recognized in sales as discussed above under "- Sales Recognition." Accounting
for derivatives under SFAS No. 133 will increase volatility of our future
earnings.
44
Reclassifications
Certain amounts in prior years have been reclassified to conform with
classifications used in the current year presentation.
3. RATE MATTERS AND REGULATION
KCC Rate Proceedings
On November 27, 2000, Western Resources and we filed applications with the
KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual
reduction in our electric rates of $41.2 million.
On August 9, 2001, Western Resources and we filed a petitions with the KCC
requesting reconsideration of the July 25, 2001 order. The petitions
specifically asked for reconsideration of changes in depreciation, reductions in
rate base related to deferred income taxes associated with the acquisition
premium and a deferred gain on the sale and leaseback of LaCygne 2 and several
other issues. On September 5, 2001, the KCC issued an order denying our motion
for reconsideration, which did not change our rate reduction. On November 9,
2001, we filed an appeal of the KCC decisions to the Kansas Court of Appeals in
an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company
vs. The State Corporation Commission of the State of Kansas." On March 8, 2002,
the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal
this decision to the Kansas Supreme Court.
KCC Investigation and Order
See Note 12 for a discussion of the order issued by the KCC on July 20,
2001 in the KCC's docket investigating the proposed separation of Western
Resources' electric utility businesses (including us) from its non-utility
businesses and other aspects of Western Resources' unregulated businesses.
FERC Proceedings
In September 1999, the City of Wichita filed a complaint with the Federal
Energy Regulatory Commission (FERC) against us alleging improper affiliate
transactions between Western Resources' KPL division and us. The City of Wichita
asked that FERC equalize the generation costs between KPL and us, in addition to
other matters. After hearings on the case, a FERC administrative law judge ruled
in our favor confirming that no change in rates was required. On December 13,
2000, the City of Wichita filed a brief with FERC asking that the Commission
overturn the judge's decision. On January 5, 2001, we filed a brief opposing the
City's position. On November 23, 2001, FERC issued an order affirming the
judge's decision. The City of Wichita's time to appeal FERC's order has expired.
4. ACCOUNTS RECEIVABLE
Our accounts receivable on our consolidated balance sheets are comprised
as follows:
December 31,
--------------------------
2001 2000
--------- ---------
(In Thousands)
Gross accounts receivable .................... $ 102,478 $ 144,683
Unbilled energy receivables .................. 42,731 58,238
Accounts receivable sale program ............. (100,000) (115,000)
--------- ---------
Accounts receivable, net ..................... $ 45,209 $ 87,921
========= =========
On July 28, 2000, Western Resources and we entered into an asset-backed
securitization agreement under which we periodically transfer an undivided
percentage ownership interest in a revolving pool of our accounts
45
receivable arising from the sale of electricity to a multi-seller conduit
administered by an independent financial institution through the use of a
special purpose entity (SPE). We account for this transfer as a sale in
accordance with SFAS No. 140, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishment of Liabilities." The agreement was renewed
on July 26, 2001 and is annually renewable upon agreement by all parties.
Under the terms of the agreement, Western Resources and we may transfer
accounts receivable to the bankruptcy-remote SPE and the conduit must purchase
from the SPE an undivided ownership interest of up to $125 million (and upon
request, subject to certain conditions, up to $175 million), in those
receivables. The SPE has been structured to be legally separate from us, but it
is wholly owned by Western Resources and consolidated by us. The percentage
ownership interest in receivables purchased by the conduit may increase or
decrease over time, depending on the characteristics of the SPE's receivables,
including delinquency rates and debtor concentrations. Western Resources
services the receivables transferred to the SPE and receives a servicing fee,
which approximates market compensation for these services.
Under the terms of the agreement, the conduit pays the SPE the face amount
of the undivided interest at the time of purchase. Subsequent to the initial
purchase, additional interests are sold and collections applied by the SPE to
the conduit resulting in an adjustment to the outstanding conduit interest.
We record administrative expense on the undivided interest owned by the
conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the
year ended December 31, 2000. These expenses are included in other income
(expense) in our consolidated statements of income.
At December 31, 2001 and 2000, the outstanding balance of SPE receivables
was $43.3 million and $85.5 million, which is net of an undivided interest of
$100.0 million and $115.0 million in receivables sold by the SPE to the conduit.
Our retained interest in the SPE's receivables is reported at fair value and is
subordinate to, and provides credit enhancement for, the conduit's ownership
interest in the SPE's receivables. Our retained interest is available to the
conduit to pay any fees or expenses due to the conduit, and to absorb all credit
losses incurred on any of the SPE's receivables. The retained interest is
included in accounts receivable, net, in our consolidated balance sheets.
5. FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value as set forth in SFAS No. 107 "Disclosures about Fair Value of
Financial Instruments."
The carrying values and estimated fair values of our financial instruments
are as follows:
Carrying Value Fair Value
--------------------- ---------------------
As of December 31,
---------------------------------------------
2001 2000 2001 2000
--------- --------- --------- ---------
(In Thousands)
Fixed-rate debt (a) .................... $ 640,993 $ 641,123 $ 639,660 $ 635,088
- ----------
(a) Fair value is estimated based on quoted market prices for the same or
similar issues or on the current rates offered for instruments of the same
remaining maturities and redemption provisions.
The recorded amounts of accounts receivable and other current financial
instruments approximate fair value. Cash and cash equivalents, short-term
borrowings and variable-rate debt are carried at cost, which approximates fair
value and are not included in the table above.
The fair value estimates presented herein are based on information
available at December 31, 2001 and 2000. These fair value estimates have not
been comprehensively revalued for the purpose of these consolidated
46
financial statements since that date and current estimates of fair value may
differ significantly from the amounts presented herein.
Derivative Instruments and Hedge Accounting
Western Resources and we jointly use derivative financial instruments
primarily to manage risk as it relates to changes in the prices of commodities
including natural gas, coal and electricity. Certain derivative instruments are
used for trading purposes in order to take advantage of favorable price
movements and market timing activities in the wholesale power and fossil fuel
markets. Derivative instruments used to mange commodity price risk inherent in
fuel purchases and electricity sales are classified as energy trading contracts
on our consolidated balance sheet. Energy trading contracts representing
unrealized gain positions are reported as assets; energy trading contracts
representing unrealized loss positions are reported as liabilities.
Energy Trading Activities:
Western Resources and we jointly trade energy commodity contracts daily.
Within the trading portfolio, Western Resources and we take certain positions to
hedge physical sale or purchase contracts and we take certain positions to take
advantage of market trends and conditions. We record most energy contracts, both
physical and financial, at fair value. Changes in value are reflected in our
consolidated statement of income. We use all forms of financial instruments,
including futures, forwards, swaps and options. Each type of financial
instrument involves different risks. We believe financial instruments help us
manage our contractual commitments, reduce our exposure to changes in cash
market prices and take advantage of selected arbitrage opportunities. We refer
to these transactions as energy trading activities.
Although we generally attempt to balance our physical and financial
contracts in terms of quantities and contract performance, net open positions
typically exist. We will at times create a net open position or allow a net open
position to continue when we believe that future price movements will increase
the portfolio's value. To the extent we have an open position, we are exposed to
fluctuating market prices that may adversely impact our financial position or
results of operations.
The prices we use to value price risk management activities reflect our
best estimate of fair values considering various factors, including closing
exchange and over-the-counter quotations, time value of money and price
volatility factors underlying the commitments. We adjust prices to reflect the
potential impact of liquidating our position in an orderly manner over a
reasonable period of time under present market conditions. We consider a number
of risks and costs associated with the future contractual commitments included
in our energy portfolio, including credit risks associated with the financial
condition of counter parties and the time value of money. We continuously
monitor the portfolio and value it daily based on present market conditions.
Future changes in our creditworthiness and the creditworthiness of our
counter parties may change the value of our portfolio. We adjust the value of
contracts and set dollar limits with counter parties based on our assessment of
their credit quality.
Non-Trading Activities - Derivative Instruments and Hedging Activities:
Western Resources and we jointly use derivative financial instruments to
reduce our exposure to adverse fluctuations in commodity prices, interest rates,
and other market risks. When we enter into a financial instrument, we formally
designate and document the instrument as a hedge of a specific underlying
exposure, as well as the risk management objectives and strategies for
undertaking the hedge transaction. Because of the high degree of correlation
between the hedging instrument and the underlying exposure being hedged,
fluctuations in the value of the derivative instruments are generally offset by
changes in the value or cash flows of the underlying exposures being hedged.
We record derivatives used for hedging commodity price risk in our
consolidated balance sheets at fair value as energy trading contracts. The
effective portion of the gain or loss on a derivative instrument designated as a
cash flow hedge is reported as a component of accumulated other comprehensive
income (loss). This amount is
47
reclassified into earnings in the period during which the hedged transaction
affects earnings. Effectiveness is the degree to which gains and losses on the
hedging instruments offset the gains and losses on the hedged item. The
ineffective portion of the hedging relationship is recognized currently in
earnings.
The fair values of derivatives used to hedge or modify our risks fluctuate
over time. These fair value amounts should not be viewed in isolation, but
rather in relation to the fair values or cash flows of the underlying hedged
transactions and the overall reduction in our risk relating to adverse
fluctuations in interest rates, commodity prices and other market factors. In
addition, the net income effect resulting from our derivative instruments is
recorded in the same line item within our consolidated statements of income as
the underlying exposure being hedged. We also formally assess, both at the
inception and at least quarterly thereafter, whether the financial instruments
that are used in hedging transactions are effective at offsetting changes in
either the fair value or cash flows of the related underlying exposures. Any
ineffective portion of a financial instrument's change in fair value is
immediately recognized in net income.
During the third quarter of 2001, we entered into hedging relationships to
manage commodity price risk associated with future natural gas purchases in
order to protect us and our customers from adverse price fluctuations in the
natural gas market. We are using futures and swap contracts with a total
notional volume of 26,910,000 MMBtu and terms extending through July 2004 to
hedge price risk for a portion of our anticipated natural gas fuel requirements
for our generation facilities. Based on our best estimate of generating needs,
we believe we have hedged 75% of our system requirements through this hedge. We
have designated these hedging relationships as cash flow hedges in accordance
with SFAS No. 133.
The following table summarizes the effects our natural gas hedge had on
our financial position and results of operations for the year ended December 31,
2001:
Natural gas
Hedge (a)
-----------
(Dollars in Thousands)
Fair value of derivative instruments:
Current............................................... $ (6,892)
Long-term............................................. (6,103)
---------
Total.............................................. $ (12,995)
=========
Amounts in accumulated other comprehensive income......... $ (20,064)
Hedge ineffectiveness..................................... 1,760
Estimated income tax benefit.............................. 7,281
---------
Net comprehensive loss............................. $ (11,023)
=========
Anticipated reclassifications to earnings during 2002 (b). $ 6,892
Duration of hedge designation as of December 31, 2001..... 31 months
- ----------
(a) Natural gas hedge liabilities are classified in the balance sheet as
energy trading contracts. Gas prices dropped after we entered into these
hedging relationships. Due to the volatility of gas commodity prices, it
is probable that gas prices will increase and decrease over the 31 months
that these relationships are in place.
(b) The actual amounts that will be reclassified to earnings could vary
materially from this estimated amount due to changes in market conditions.
48
6. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December
31:
2001 2000
---------- ----------
(In Thousands)
Electric plant in service .................... $3,738,912 $3,674,643
Less - Accumulated depreciation .............. 1,373,161 1,288,676
---------- ----------
2,365,751 2,385,967
Construction work in progress ................ 27,171 33,233
Nuclear fuel, net ............................ 33,883 30,791
---------- ----------
Net utility plant .......................... 2,426,805 2,449,991
Non-utility plant in service, net ............ 70 70
---------- ----------
Net property, plant and equipment .......... $2,426,875 $2,450,061
========== ==========
Our depreciation expense on property, plant and equipment was $85.0
million in 2001, $84.2 million in 2000 and $81.1 million in 1999.
7. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 2001
-----------------------------------------------------------------------
In-Service Accumulated Net Ownership
Dates Investment Depreciation MW Percent
-------------- ---------- ------------ ----- ---------
(Dollars in Thousands)
LaCygne 1.............. (a) June 1973 $ 188,277 $ 120,300 344.0 50
Jeffrey 1.............. (b) July 1978 72,874 34,517 149.0 20
Jeffrey 2.............. (b) May 1980 73,634 33,388 146.0 20
Jeffrey 3.............. (b) May 1983 101,585 46,387 148.0 20
Jeffrey wind 1......... (b) May 1999 208 21 0.2 20
Jeffrey wind 2......... (b) May 1999 207 21 0.2 20
Wolf Creek............. (c) Sept. 1985 1,387,391 528,268 550.0 47
- ----------
(a) Jointly owned with Kansas City Power and Light Company (KCPL)
(b) Jointly owned with Aquila, Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
Amounts and capacity presented above represent our share. Our share of
operating expenses of the plants in service above, as well as such expenses for
a 50% undivided interest in LaCygne 2 (representing 337 megawatt (MW) capacity)
sold and leased back to us in 1987, are included in operating expenses on our
consolidated statements of income. Our share of other transactions associated
with the plants is included in the appropriate classification in our
consolidated financial statements.
8. SHORT-TERM BORROWINGS
We had no short-term borrowings outstanding at December 31, 2001 and 2000.
Our short-term liquidity needs are met from cash advances by Western
Resources. Western Resources obtains funds from borrowings under its credit
facilities.
Western Resources has an arrangement with certain banks to provide a
revolving credit facility on a committed basis totaling $500 million. The
facility is secured by our and Western Resources' first mortgage bonds and
expires on March 17, 2003.
49
9. LONG-TERM DEBT
The amount of our first mortgage bonds authorized by our Mortgage and Deed
of Trust (Mortgage) dated April 1, 1940, as supplemented, is limited to a
maximum of $2 billion. Amounts of additional bonds that may be issued are
subject to property, earnings, and certain restrictive provisions of the
Mortgage. Electric plant is subject to the lien of the Mortgage except for
transportation equipment.
Long-term debt outstanding is as follows:
December 31,
--------------------
2001 2000
-------- --------
(In Thousands)
KGE
First mortgage bond series:
7.60% due 2003 ................................... $135,000 $135,000
6 1/2% due 2005 .................................. 65,000 65,000
6.20% due 2006 ................................... 100,000 100,000
-------- --------
300,000 300,000
-------- --------
Pollution control bond series:
5.10% due 2023 ................................... 13,493 13,623
Variable due 2027, 1.35% at December 31, 2001 .... 21,940 21,940
7.0% due 2031 .................................... 327,500 327,500
Variable due 2032, 1.5% at December 31, 2001 ..... 14,500 14,500
Variable due 2032, 1.53% at December 31, 2001 .... 10,000 10,000
-------- --------
387,433 387,563
-------- --------
Less:
Unamortized debt discount (a) ........................ 3,073 3,197
-------- --------
Long-term debt, net .............................. $684,360 $684,366
======== ========
- ----------
(a) Debt discount and expenses are being amortized over the remaining lives of
each issue.
Maturities of long-term debt as of December 31, 2001 are as follows:
Principal Amount
----------------
As of December 31, (In Thousands)
------------------
2002 ................... $ --
2003 ................... 135,000
2004 ................... --
2005 ................... 65,000
2006 ................... 100,000
Thereafter ............. 384,360
--------
$684,360
========
50
10. INCOME TAXES
Income tax expense is composed of the following components at December 31:
2001 2000 1999
-------- -------- --------
(In Thousands)
Currently payable:
Federal .................................. $ 26,373 $ 38,754 $ 38,710
State .................................... 6,098 9,683 9,453
Deferred:
Federal .................................. (20,376) (9,837) (8,531)
State .................................... (2,323) (1,388) (1,407)
Investment tax credit amortization ......... (2,852) (3,237) (3,238)
-------- -------- --------
Total ................................. 6,920 33,975 34,987
Less taxes classified in:
Cumulative effect of accounting change ... 8,520 -- --
-------- -------- --------
Total income tax expense ................... $ (1,600) $ 33,975 $ 34,987
======== ======== ========
Under SFAS No. 109, "Accounting for Income Taxes," temporary differences
gave rise to deferred tax assets ad deferred tax liabilities as follows at
December 31:
December 31,
----------------------
2001 2000
-------- --------
(In Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback ................. $ 76,806 $ 82,013
Disallowed plant costs .......................... 16,650 17,758
General business credit carryforward ............ 7,741 3,635
Accrued liabilities ............................. 6,606 4,749
Other ........................................... 25,914 22,084
-------- --------
Total deferred tax assets ..................... $133,717 $130,239
======== ========
Deferred tax liabilities:
Accelerated depreciation ........................ $361,945 $369,765
Acquisition premium ............................. 266,580 274,579
Deferred future income taxes .................... 174,354 151,842
Investment tax credits .......................... 53,908 56,759
Other ........................................... 2,604 13,730
-------- --------
Total deferred tax liabilities ................ $859,391 $866,675
======== ========
Deferred tax assets and liabilities are reflected on our consolidated
balance sheets as follows:
December 31,
--------------------
2001 2000
-------- ------
(In Thousands)
Current deferred tax assets, net ................... $ 1,002 $ --
Current deferred tax liabilities, net .............. -- 11,980
Non-current deferred tax liabilities, net .......... 726,676 724,456
-------- --------
Net deferred tax liabilities ....................... $725,674 $736,436
======== ========
51
In accordance with various rate orders, we have not yet collected through
rates certain accelerated tax deductions, which have been passed on to
customers. As management believes it is probable that the net future increases
in income taxes payable will be recovered from customers, 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. This liability is
classified above as deferred future income taxes.
The effective income tax rates set forth below are computed by dividing
total federal and state income taxes by the sum of such taxes and net income.
The difference between the effective tax rates and the federal statutory income
tax rates are as follows:
For the Year Ended December 31,
-------------------------------
2001 2000 1999
---- ---- ----
Effective income tax rate ..................... (5)% 28% 29%
Effect of:
State income taxes ......................... (4) (4) (4)
Amortization of investment tax credits ..... 8 3 3
Corporate-owned life insurance policies .... 35 9 7
Accelerated depreciation flow through
and amortization, net ..................... (10) (4) (2)
Other ...................................... 11 3 2
--- --- ---
Statutory federal income tax rate ............. 35% 35% 35%
=== === ===
11. COMMITMENTS AND CONTINGENCIES
Municipalization Efforts by Wichita
In December 1999, the City Council of Wichita, Kansas, authorized the
hiring of an outside consultant to determine the feasibility of creating a
municipal electric utility to replace us as the supplier of electricity in
Wichita. The feasibility study was released in February 2001 and estimates that
the City of Wichita would be required to pay us $145 million for our stranded
costs if it were to municipalize. However, we estimate the amount to be
substantially greater. In order to municipalize our Wichita electric facilities,
the City of Wichita would be required to purchase our facilities or build a
separate independent system and arrange for its own power supply. These costs
are in addition to the stranded costs for which the city would be required to
reimburse us. On February 2, 2001, the City of Wichita announced its intention
to proceed with its attempt to municipalize our retail electric utility business
in Wichita. We will oppose municipalization efforts by the City of Wichita.
Should the city be successful in its municipalization efforts without providing
us adequate compensation for our assets and lost revenues, the adverse effect on
our business and financial condition could be material.
Our franchise with the City of Wichita to provide retail electric service
is effective through December 1, 2002. There can be no assurance that we can
successfully renegotiate the franchise with terms similar, or as favorable, as
those in the current franchise. Under Kansas law, we will continue to have the
right to serve the customers in Wichita following the expiration of the
franchise, assuming the system is not municipalized. Customers within the
Wichita metropolitan area account for approximately 51% of our total energy
sales.
Purchase Orders and Contracts
As part of our ongoing operations and construction program, we have
commitments under purchase orders and contracts, excluding fuel (which is
discussed below under "- Fuel Commitments,") that have an unexpended balance of
approximately $6.0 million (our share) at December 31, 2001.
Manufactured Gas Sites
We have been associated with three former manufactured gas sites located
in Kansas that may contain coal tar and other potentially harmful materials. We
and the Kansas Department of Health and Environment (KDHE)
52
entered into a consent agreement governing all future work at these sites. The
terms of the consent agreement will allow us to investigate these sites and set
remediation priorities based on the results of the investigations and risk
analysis. At December 31, 2001, the costs incurred for preliminary site
investigation and risk assessment have been minimal.
Clean Air Act
We must comply with the provisions of The Clean Air Act Amendments of 1990
that require a two-phase reduction in certain emissions. We have installed
continuous monitoring and reporting equipment to meet the acid rain
requirements. Material capital expenditures have not been required to meet Phase
II sulfur dioxide and nitrogen oxide requirements.
Nuclear Decommissioning
We accrue decommissioning costs over the expected life of the Wolf Creek
generating facility. The accrual is based on estimated unrecovered
decommissioning costs that consider inflation over the remaining estimated life
of the generating facility and are net of expected earnings on amounts recovered
from customers and deposited in an external trust fund.
On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost
Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost
Study on April 26, 2000. Based on the study, our share of Wolf Creek's
decommissioning costs, under the immediate dismantlement method, is estimated to
be approximately $631 million during the period 2025 through 2034, or
approximately $221 million in 1999 dollars. These costs include decontamination,
dismantling and site restoration and were calculated using an assumed inflation
rate of 3.6% over the remaining service life from 1999 of 26 years. The actual
decommissioning costs may vary from the estimates because of changes in the
assumed dates of decommissioning, changes in regulatory requirements, changes in
technology and changes in costs of labor, materials and equipment. On May 26,
2000, we filed an application with the KCC requesting approval of the funding of
our decommissioning trust on this basis. Approval was granted by the KCC on
September 20, 2000.
Decommissioning costs are currently being charged to operating expense in
accordance with the prior KCC orders. Electric rates charged to customers
provide for recovery of these decommissioning costs over the life of Wolf Creek.
Amounts expensed approximated $4.0 million in 2001 and will increase annually to
$5.5 million in 2024. These amounts are deposited in an external trust fund. The
average after-tax expected return on trust assets is 5.8%.
Our investment in the decommissioning fund, including reinvested earnings,
is recorded at fair value and approximated $66.6 million at December 31, 2001
and $64.2 million at December 31, 2000. Trust fund earnings accumulate in the
fund balance and increase the recorded decommissioning liability.
Storage of Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE)
is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays
the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net
nuclear generation produced for the future disposal of spent nuclear fuel. These
disposal costs are charged to cost of sales.
A permanent disposal site will not be available for the nuclear industry
until 2010 or later. Under current DOE policy, once a permanent site is
available, the DOE will accept spent nuclear fuel on a priority basis. The
owners of the oldest spent fuel will be given the highest priority. As a result,
disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek
has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek
completed replacement of spent fuel storage racks to increase its on-site
storage capacity for all spent fuel expected to be generated by Wolf Creek
through the end of its licensed life in 2025.
53
Asset Retirement Obligations
In August 2001, the Financial Accounting Standards Board (FASB) issued
SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard
requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred. When it is
initially recorded, we will capitalize the estimated asset retirement obligation
by increasing the carrying amount of the related long-lived asset. The liability
will be accreted to its present value each period and the capitalized cost will
be depreciated over the life of the asset. The standard is effective for fiscal
years beginning after June 15, 2002. We expect to adopt this standard January 1,
2003. This standard will impact the way we currently account for the
decommissioning of Wolf Creek. In addition to the accounting for the Wolf Creek
decommissioning, we are also reviewing what impact this pronouncement will have
on our current accounting practices and our results of operations as it relates
to other asset retirement obligations we may identify. The impact is unknown at
this time.
Nuclear Insurance
The Price-Anderson Act, originally passed by Congress in 1957 and most
recently amended in 1988, requires nuclear power plants to show evidence of
financial protection in the event of a nuclear accident. This protection must
consist of two levels. The primary level provides liability insurance coverage
of $200 million. If this amount is not sufficient to cover claims arising from
an accident, the second level - Secondary Financial Protection - applies. For
the second level, each licensed nuclear unit must pay a retroactive premium
equal to its proportionate share of the excess loss, up to a maximum of $88.1
million per unit per accident.
Currently, 106 nuclear units are participating in the Secondary Financial
Protection program - 103 operating units and three closed units that still
handle used nuclear fuel. The number of units participating in the program will
be reduced as decommissioned units apply for and receive exemptions. Nuclear
power plants provide a total of $9.5 billion in insurance coverage to compensate
the public in the event of a nuclear accident. Taxpayers and the federal
government pay nothing for this coverage.
The Nuclear Regulatory Commission (NRC) was required to submit a report to
Congress, which was submitted in September 1998 and describes the benefits that
the act provides to the public. It also recommends that the act be extended for
an additional ten years. The DOE submitted a report to Congress in March 1999,
recommending renewal of the act.
Bipartisan legislation was introduced in the 106th Congress in the Senate
providing a simple renewal of Price-Anderson based on the DOE and NRC reports.
The nuclear industry supports such a legislative approach for consideration
early in the 107th Congress.
Unless Congress renews the Price-Anderson Act, it will expire in part on
August 1, 2002 as follows:
. The only part of Price-Anderson that expires on August 1, 2002, is
the authority of the NRC and the DOE to enter into new indemnity
agreements after that date. Existing indemnity agreements would
continue in full force and effect.
. Without renewal, new nuclear power plants could not be covered, nor
could new DOE contracts have the indemnity provision (including the
proposed high-level radioactive waste disposal site in Yucca
Mountain, Nevada).
The Price-Anderson Act limits the combined public liability of the owners
of nuclear power plants to $9.5 billion for a single nuclear incident. If this
liability limitation is insufficient, the United States Congress will consider
taking whatever action is necessary to compensate the public for valid claims.
However, on February 2, 2002, the United States Senate announced that it is
considering discontinuing the federal insurance provision.
The Wolf Creek owners have purchased the maximum available private
insurance of $200 million. The remaining 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 $88.1 million 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
54
on the Consumer Price Index and applicable premium taxes. There is a limitation
of $10 million in retrospective assessments per incident, per year.
The owners carry decontamination liability, premature decommissioning
liability and property damage insurance for Wolf Creek totaling approximately
$2.8 billion ($1.3 billion our share). This insurance is provided by Nuclear
Electric Insurance Limited (NEIL). In the event of an accident, insurance
proceeds must first be used for reactor stabilization and site decontamination
in accordance with a plan mandated by the NRC. Our share of any remaining
proceeds can be used to pay for property damage or decontamination expenses or,
if certain requirements are met including decommissioning the plant, toward a
shortfall in the decommissioning trust fund.
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, we may be subject to retrospective
assessments under the current policies of approximately $10.7 million per year.
Although we maintain various insurance policies to provide coverage for
potential losses and liabilities resulting from an accident or an extended
outage, our insurance coverage may not be adequate to cover 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, would have a material adverse effect on our financial condition
and results of operations.
Fuel Commitments
To supply a portion of the fuel requirements for our generating plants, we
have entered into various commitments to obtain nuclear fuel and coal. Some of
these contracts contain provisions for price escalation and minimum purchase
commitments. At December 31, 2001, WCNOC's nuclear fuel commitments (our share)
were approximately $3.2 million for uranium concentrates expiring in 2003, $0.6
million for conversion expiring in 2003, $22.7 million for enrichment expiring
at various times through 2006 and $57.5 million for fabrication through 2025.
At December 31, 2001, our coal and coal transportation contract
commitments in 2001 dollars under the remaining terms of the contracts were
approximately $484.1 million. The largest contract expires in 2020, with the
remaining contracts expiring at various times through 2013.
At December 31, 2001, our natural gas transportation commitments in 2001
dollars under the remaining terms of the contracts were approximately $1.4
million. The natural gas transportation contracts provide firm service to
several of our gas burning facilities and expire at various times through 2010,
except for one contract that expires in 2016.
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. Our portion of the assessment for Wolf Creek is
approximately $9.6 million, payable over 15 years. Such costs are recovered
through the ratemaking process.
12. PNM MERGER AND SPLIT-OFF OF WESTAR INDUSTRIES
PNM Transaction
On November 8, 2000, Western Resources entered into an agreement with
Public Service Company of New Mexico (PNM), pursuant to which PNM would acquire
Western Resources' electric utility businesses (including us) in a tax-free
stock-for-stock merger. Under the terms of the agreement, both PNM and Western
Resources are to become subsidiaries of a new holding company, subject to
customary closing conditions including regulatory and shareholder approvals. At
the same time Western Resources entered into the agreement with PNM, Western
55
Resources and Westar Industries, a wholly owned subsidiary of Western Resources,
entered into an Asset Allocation and Separation Agreement, which provided for a
split-off of Westar Industries and related matters.
On October 12, 2001, PNM filed a lawsuit against Western Resources in the
Supreme Court of the State of New York. The lawsuit seeks, among other things,
declaratory judgment that PNM is not obligated to proceed with the proposed
merger based in part upon the KCC orders discussed below and other KCC orders
reducing rates for Western Resources' electric utility businesses. PNM believes
the orders constitute a material adverse effect and make the condition that the
split-off of Westar Industries occur prior to closing incapable of satisfaction.
PNM also seeks unspecified monetary damages for breach of representation.
On November 19, 2001, Western Resources filed a lawsuit against PNM in the
Supreme Court of the State of New York. The lawsuit seeks substantial damages
for PNM's breach of the merger agreement providing for PNM's purchase of Western
Resources' electric utility operations and for PNM's breach of its duty of good
faith and fair dealing. In addition, Western Resources filed a motion to dismiss
or stay the declaratory judgment action previously filed by PNM seeking a
declaratory judgment that PNM has no further obligations under the merger
agreement.
On January 7, 2002, PNM sent a letter to Western Resources purporting to
terminate the merger in accordance with the terms of the merger agreement.
Western Resources has notified PNM that it believes the purported termination of
the merger agreement was ineffective and that PNM remains obligated to perform
thereunder. Western Resources intends to contest PNM's purported termination of
the merger agreement. However, based upon PNM's actions and the related
uncertainties, Western Resources believes the closing of the proposed merger is
not likely.
KCC Proceedings and Orders
The merger with PNM contemplated the completion of a rights offering for
shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an
investigation of the proposed separation of Western Resources' electric utility
businesses (including us) from its non-utility businesses, including the rights
offering, and other aspects of its unregulated businesses. The order opening the
investigation indicated that the investigation would focus on whether the
separation and other transactions involving Western Resources' unregulated
businesses are consistent with its obligation to provide efficient and
sufficient electric service at just and reasonable rates to its electric utility
customers. The KCC staff was directed to investigate, among other matters, the
basis for and the effect of the Asset Allocation and Separation Agreement
Western Resources entered into with Westar Industries in connection with the
proposed separation and the intercompany payable owed by Western Resources to
Westar Industries, the separation of Westar Industries, the effect of the
business difficulties faced by Western Resources' unregulated businesses and
whether they should continue to be affiliated with its electric utility
business, and Western Resources' present and prospective capital structures. On
May 22, 2001, the KCC issued an order nullifying the Asset Allocation and
Separation Agreement, prohibiting Western Resources from taking any action to
complete the rights offering for common stock of Westar Industries, which was to
be a first step in the separation, and scheduling a hearing to consider whether
to make the order permanent.
On July 20, 2001, the KCC issued an order that, among other things: (1)
confirmed its May 22, 2001 order prohibiting Western Resources and Westar
Industries from taking any action to complete the proposed rights offering and
nullifying the Asset Allocation and Separation Agreement; (2) directed Western
Resources and Westar Industries not to take any action or enter into any
agreement not related to normal utility operations that would directly or
indirectly increase the share of debt in Western Resources' capital structure
applicable to its electric utility operations, which has the effect of
prohibiting it from borrowing to make a loan or capital contribution to Westar
Industries; and (3) directed Western Resources to present a financial plan
consistent with parameters established by the KCC's order to restore financial
health, achieve a balanced capital structure and protect ratepayers from the
risks of its non-utility businesses. In its order, the KCC also acknowledged
that Western Resources and we are presently operating efficiently and at
reasonable cost and stated that it was not disapproving the PNM transaction or a
split-off of Westar Industries. Western Resources appealed the orders issued by
the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002,
the District Court issued a decision finding that the KCC orders were not
56
final orders and that the District Court lacked jurisdiction to consider the
appeal. Accordingly, the matter was remanded to the KCC for review of the
financial plan.
On February 11, 2002, the KCC issued an order primarily related to
procedural matters for the review of the financial plan, as discussed below. In
addition, the order required that Western Resources and the KCC staff make
filings addressing whether the filing of applications by Western Resources and
us at FERC, seeking renewal of existing borrowing authority, violated the July
20, 2001 KCC order directing that Western Resources not increase the share of
debt in its capital structure applicable to its electric utility operations. The
KCC staff subsequently filed comments asserting that the refinancing of existing
indebtedness with new indebtedness secured by utility assets would in certain
circumstances violate the July 20, 2001 KCC order. The KCC staff filed a motion
to intervene in the proceeding at FERC asserting the same position. Western
Resources is unable to predict whether the KCC will adopt the KCC staff
position, the extent to which FERC will incorporate the KCC position in orders
renewing Western Resources' and our borrowing authority, or the impact of the
adoption of the KCC staff position, if that occurs, on Western Resources' or our
ability to refinance indebtedness maturing in the next several years. Western
Resources' or our inability to refinance existing indebtedness on a secured
basis would likely increase borrowing costs and adversely affect liquidity and
Western Resources' and our results of operations.
The Financial Plan
The July 20, 2001 KCC order directed Western Resources to present a
financial plan to the KCC. Western Resources presented a financial plan to the
KCC on November 6, 2001, which it amended on January 29, 2002. The principal
objective of the financial plan is to reduce Western Resources' total debt as
calculated by the KCC to approximately $1.8 billion, a reduction of
approximately $1.2 billion. The financial plan contemplates that Western
Resources will proceed with the rights offering and that, in the event that the
PNM merger and related split-off do not close, Western Resources will use its
best efforts to sell its share of Westar Industries common stock, or shares of
its common stock, upon the occurrence of certain events. The KCC has scheduled a
hearing on May 31, 2002 to review the financial plan. Western Resources is
unable to predict whether or not the KCC will approve the financial plan or what
other action with respect to the financial plan the KCC may take.
13. LEGAL PROCEEDINGS
We are involved in various other legal, environmental and regulatory
proceedings. Management believes that adequate provision has been made and
accordingly believes that the ultimate disposition of such matters will not have
a material adverse effect upon our overall financial position or results of
operations. See also Notes 11 and 12 for discussion of the City of Wichita's
municipalization efforts, the PNM lawsuits and the KCC regulatory proceedings.
57
14. LEASES
At December 31, 2001, we had leases covering various property and
equipment. Rental payments for operating leases ranging from 1 to 17 years and
estimated rental commitments are as follows:
LaCygne 2 Total
Year Ended December 31, Lease (a) Leases
- ----------------------- --------- ------
(In Thousands)
Rental payments:
1999.................................... $ 34,598 $ 43,827
2000.................................... 34,598 42,559
2001.................................... 34,598 44,007
Future commitments:
2002.................................... $ 34,598 $ 41,984
2003.................................... 39,420 46,090
2004.................................... 34,598 40,798
2005.................................... 38,013 43,655
2006.................................... 42,287 47,929
Thereafter.............................. 422,318 452,275
--------- --------
Total future commitments............. $ 611,234 $672,731
========= ========
- ----------
(a) LaCygne 2 lease amounts are included in total leases.
In 1987, KGE sold and leased back its 50% undivided interest in the
LaCygne 2 generating unit. The LaCygne 2 lease has an initial term of 29 years,
with various options to renew the lease or repurchase the 50% undivided
interest. KGE remains responsible for its share of operation and maintenance
costs and other related operating costs of LaCygne 2. The lease is an operating
lease for financial reporting purposes. We recognized a gain on the sale, which
was deferred and is being amortized over the initial lease term.
In 1992, we deferred costs associated with the refinancing of the secured
facility bonds of the Trustee and owner of LaCygne 2. These costs are being
amortized over the life of the lease and are included in operating expense.
15. RELATED PARTY TRANSACTIONS
Our cash management function, including cash receipts and disbursements,
is performed by Western Resources. An intercompany account is used to record net
receipts and disbursements between KGE and Western Resources and KGE and WR
Receivables Corporation. The net amount receivable from affiliates approximated
$17.3 million at December 31, 2001 and $53.1 million at December 31, 2000 as
reflected in our consolidated balance sheets.
All employees we utilize are provided by Western Resources. Certain
operating expenses have been allocated to us from Western Resources. These
expenses are allocated, depending on the nature of the expense, based on
allocation studies, net investment, number of customers, and/or other
appropriate factors. Management believes such allocation procedures are
reasonable. During 2001, we declared dividends to Western Resources of $100
million.
During the fourth quarter of 2001, we entered into an option agreement to
sell an office building located in downtown Wichita, Kansas, to Protection One,
a subsidiary of Westar Industries, which is a wholly owned subsidiary of Western
Resources for approximately $0.5 million. The sales price was determined by
management based on three independent appraisers' findings.
58
16. SEGMENTS OF BUSINESS
In 1998, we adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information." This statement requires us to define and
report our business segments based on how management currently evaluates its
business. We have segmented our business according to differences in products
and services, production processes, and management responsibility. Based on this
approach, we have identified two reportable segments: Electric Operations and
Nuclear Generation.
Electric operations involve the production, transmission and distribution
of electric power for sale to approximately 293,000 retail and wholesale
customers in Kansas. Nuclear generation represents our 47% ownership in the Wolf
Creek nuclear generating facility. This segment has only internal sales because
it provides all of its power to its co-owners.
The accounting policies of the segments are substantially the same as
those described in Note 2, "Summary of Significant Accounting Policies." Segment
performance is based on earnings before interest and taxes (EBIT). We have no
single external customer from whom we receive ten percent or more of our
revenues.
Year Ended December 31, 2001:
- ---------------------------- Electric Nuclear Eliminating
Operations(a) Generation Items Total
------------- ---------- ----------- ----------
External sales .............................. $ 673,125 $ -- $ -- $ 673,125
Internal sales .............................. -- 117,659 (117,659) --
Depreciation and amortization ............... 64,090 41,046 -- 105,136
Earnings (loss) before interest and taxes and
cumulative effect of accounting change ... 104,390 (19,078) -- 85,312
Interest expense ............................ 49,611
Earnings before income taxes ................ 35,701
Additions to property, plant and equipment .. 55,402 27,349 -- 82,751
Identifiable assets ......................... 1,887,482 1,042,563 -- 2,930,045
Year Ended December 31, 2000:
- ---------------------------- Electric Nuclear Eliminating
Operations Generation Items Total
---------- ---------- ----------- ----------
External sales .............................. $ 703,990 $ -- $ -- $ 703,990
Internal sales .............................. -- 107,770 (107,770) --
Depreciation and amortization ............... 64,242 40,052 -- 104,294
Earnings (loss) before interest and taxes ... 194,611 (24,323) -- 170,288
Interest expense ............................ 49,605
Earnings before income taxes ................ 120,683
Additions to property, plant and equipment .. 56,839 25,877 -- 82,716
Identifiable assets ......................... 1,923,756 1,064,817 -- 2,988,573
59
Year Ended December 31, 1999:
- ---------------------------- Eliminating/
Electric Nuclear Reconciling
Operations Generation Items Total
---------- ---------- ----------- ----------
External sales .............................. $ 638,340 $ -- $ -- $ 638,340
Internal sales .............................. -- 108,445 (108,445) --
Depreciation and amortization ............... 61,531 39,629 -- 101,160
Earnings (loss) before interest and taxes ... 193,980 (25,214) -- 168,766
Interest expense ............................ 49,518
Earnings before income taxes ................ 119,248
Additions to property, plant and equipment .. 53,538 10,036 -- 63,574
Identifiable assets ......................... 1,906,366 1,083,344 -- 2,989,710
- ----------
(a) EBIT shown above for Electric Operations does not include the unrealized
gain on derivatives reported as a cumulative effect of a change in
accounting principle as discussed in Note 2. If the effect had been
included, EBIT for the Electric Operations segment for the year ended
December 31, 2001 would have been $125,808.
17. SUBSEQUENT EVENT
Ice Storm
In late January 2002, a severe ice storm swept through our service area
causing extensive damage and loss of power to numerous customers. We estimate
storm restoration costs to be approximately $13 million. On March 13, 2002, we
filed an application for an accounting authority order with the KCC requesting
that we be allowed to accumulate and defer for future recovery costs related to
storm restoration. We cannot predict whether the KCC will approve our
application.
18. 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. Our business
is seasonal in nature and, in our opinion, comparisons between the quarters of a
year do not give a true indication of overall trends and changes in operations.
First Second Third Fourth
---------- ---------- ---------- -----------
(In Thousands)
2001
Sales.................................... $ 163,993 $ 165,965 $ 206,926 $ 136,241
Income from operations................... 18,402 15,755 57,846 1,268
Net income before accounting change...... 5,097 2,928 31,845 (2,569)
Net income............................... 17,995 2,928 31,845 (2,569)
2000
Sales.................................... $ 149,913 $ 164,967 $ 229,456 $ 159,654
Income from operations................... 22,067 45,706 84,668 24,417
Net income............................... 5,968 23,007 49,395 8,338
60
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
Information required by Item 10 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by Item 12 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Item 13 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.
61
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, 2001 and 2000
Consolidated Statements of Income and Comprehensive Income, for the years
ended December 31, 2001, 2000 and 1999
Consolidated Statements of Cash Flows, for the years ended December 31,
2001, 2000 and 1999
Consolidated Statements of Shareholder's Equity, for the years ended
December 31, 2001, 2000 and 1999
Notes to Consolidated Financial Statements
REPORTS ON FORM 8-K FILED DURING THE QUARTER ENDED DECEMBER 31, 2001:
None.
62
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference. All exhibits
marked by an asterisk are management contracts or compensatory plans or
arrangements required to be identified by Item 14(a)(3) of Form 10-K.
Description
3(a) -Articles of Incorporation (Filed as Exhibit 3(a) to Form 10-K for I
the year ended December 31, 1992, File No. 1-7324)
3(b) -Certificate of Merger of Kansas Gas and Electric Company into KCA I
Corporation (Filed as Exhibit 3(b) to Form 10-K for the year ended
December 31, 1992, File No. 1-7324)
3(c) -By-laws as amended (Filed as Exhibit 3(c) to Form 10-K for the year I
ended December 31, 1992, File No. 1-7324)
4(c) -Mortgage and Deed of Trust, dated as of April 1, 1940 to Guaranty I
Trust Company of New York (now Morgan Guaranty Trust Company of
New York) and Henry A. Theis (to whom W. A. Spooner is successor),
Trustees, as supplemented by forty Supplemental Indentures, dated as
of June 1, 1942, March 1, 1948, December 1, 1949, June 1, 1952,
October 1, 1953, March 1, 1955, February 1, 1956, January 1, 1961,
May 1, 1966, March 1, 1970, May 1, 1971, March 1, 1972, May 31,
1973, July 1, 1975, December 1, 1975, September 1, 1976, March 1,
1977, May 1, 1977, August 1, 1977, March 15, 1978, January 1, 1979,
April 1, 1980, July 1, 1980, August 1, 1980, June 1, 1981, December
1, 1981, May 1, 1982, March 15, 1984, September 1, 1984
(Twenty-ninth and Thirtieth), February 1, 1985, April 15, 1986, June
1, 1991, March 31, 1992, December 17, 1992, August 24, 1993, January
15, 1994, March 1, 1994, April 15, 1994 and June 28, 2000, (Filed,
respectively, as Exhibit A-1 to Form U-1, File No. 70-23; Exhibits
7(b) and 7(c), File No. 2-7405; Exhibit 7(d), File No. 2-8242;
Exhibit 4(c), File No. 2-9626; Exhibit 4(c), File No. 2-10465;
Exhibit 4(c), File No. 2-12228; Exhibit 4(c), File No. 2-15851;
Exhibit 2(b)-1, File No. 2-24680; Exhibit 2(c), File No. 2-36170;
Exhibits 2(c) and 2(d), File No. 2-39975; Exhibit 2(d), File No.
2-43053; Exhibit 4(c)2 to Form 10-K, for December 31, 1989, File No.
1-7324; Exhibit 2(c), File No. 2-53765; Exhibit 2(e), File No.
2-55488; Exhibit 2(c), File No. 2-57013; Exhibit 2(c), File No.
2-58180; Exhibit 4(c)3 to Form 10-K for December 31, 1989, File No.
1-7324; Exhibit 2(e), File No. 2-60089; Exhibit 2(c), File No.
2-60777; Exhibit 2(g), File No. 2-64521; Exhibit 2(h), File No.
2-66758; Exhibits 2(d) and 2(e), File No. 2-69620; Exhibits 4(d) and
4(e), File No. 2-75634; Exhibit 4(d), File No. 2-78944; Exhibit
4(d), File No. 2-87532; Exhibits 4(c)4, 4(c)5 and 4(c)6 to Form 10-K
for December 31, 1989, File No. 1-7324; Exhibits 4(c)2 and 4(c)3 to
Form 10-K for December 31, 1992, File No. 1-7324; Exhibit 4(b) to
Form S-3, File No. 33-50075; Exhibits 4(c)2 and 4(c)3 to Form 10-K
for December 31, 1993, File No. 1-7324; Exhibit 4(c)2 to Form 10-K
for December 31, 1994, File No. 1-7324)
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) -LaCygne 2 Lease (Filed as Exhibit 10(a) to Form 10-K for the year I
ended December 31, 1988, File No. 1-7324)
10(a) -Amendment No. 3 to LaCygne 2 Lease Agreement dated as of September I
29, 1992 (Filed as Exhibit 10(b)1 to Form 10-K for the year ended
December 31, 1992, File No. 1-7324)
10(b) -Outside Directors' Deferred Compensation Plan (Filed as Exhibit I
10(c) to the Form 10-K for the year ended December 31, 1993, File
No. 1-7324)*
12 -Computations of Ratio of Consolidated Earnings to Fixed Charges
23 -Consent of Independent Public Accountants, Arthur Andersen LLP
99(a) -Order on Rate Applications from The Corporation Commission of the I
State of Kansas in the Matter of the Application of Kansas Gas and
Electric Company for the Approval to Make Certain Changes in its
Charges for Electric Service (Filed as Exhibit 99.1 to Form 10-Q
for the quarter ended June 30, 2001)
99(b) -Press release issued August 13, 2001 by PNM announcing that talks I
to modify Western Resources' transaction with PNM have been
discontinued (Filed as Exhibit 99.2 to Form 10-Q for the quarter
ended June 30, 2001)
99(c) -Press release issued August 13, 2001 by Western Resources I
responding to PNM's announcement of discontinued talks (Filed as
Exhibit 99.3 to Form 10-Q for the quarter ended June 30, 2001)
63
99(d) -Letter to the SEC of assurances given by Arthur Andersen LLP
regarding their audit of December 31, 2001 financial statements to
the Company
64
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.
KANSAS GAS AND ELECTRIC COMPANY
Date: April 1, 2002 By: /s/ Caroline A. Williams
---------------------- --------------------------------------
Caroline A. Williams,
President
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
--------- ----- ----
/s/ CAROLINE A. WILLIAMS President (Principal Executive April 1, 2002
- ------------------------- Officer) and Director
(Caroline A. Williams)
/s/ PAUL R. GEIST Vice President, Treasurer April 1, 2002
- ------------------------- and Director (Principal
(Paul R. Geist) Financial and Accounting
Officer)
/s/ MARILYN B. PAULY Director April 1, 2002
- -------------------------
(Marilyn B. Pauly)
/s/ RICHARD D. SMITH Director April 1, 2002
- -------------------------
(Richard D. Smith)
65