______________________________________________________________________________
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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ____________ to ____________
COMMISSION FILE NUMBER 0-346
________________
CENTRAL POWER AND LIGHT COMPANY
(Exact name of registrant as specified in its charter)
TEXAS 74-0550600
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
539 North Carancahua Street, Corpus Christi, Texas 78401-2802
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: 512/881-5300
________________
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
None None
Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock, $100 Par Value
(Title of class)
________________
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 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 the 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].
Number of shares of Common Stock outstanding at December 31, 1993: 6,755,535
(None of such shares are held by nonaffiliates.)
_____________________________________________________________________________
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TABLE OF CONTENTS
Page
DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
PART I
ITEM 1. BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . 4
REGULATION AND RATES . . . . . . . . . . . . . . . . . . . 4
STP. . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . 6
OPERATING STATISTICS . . . . . . . . . . . . . . . . . . . 8
CONSTRUCTION AND FINANCING . . . . . . . . . . . . . . . . 9
FUEL SUPPLY . . . . . . . . . . . . . . . . . . . . . . . 9
ENVIRONMENTAL MATTERS . . . . . . . . . . . . . . . . . . 11
ITEM 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . 14
ITEM 3. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . 15
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS . . . . 15
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . . . . . 15
ITEM 6. SELECTED FINANCIAL DATA . . . . . . . . . . . . . . . . . . 16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS . . . . . . . . . . . . 17
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . 24
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE . . . . . . . . . . . . 44
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT . . . . 45
ITEM 11. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . 48
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT . . . . . . . . . . . . . . . . . . . . . . 51
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . . . . 51
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . . . . 52
DEFINITIONS
The following abbreviations or acronyms used in this text are defined below:
Abbreviation
or Acronym Definition
ALJ................. Administrative Law Judge
AFUDC............... Allowance for funds used during construction
APBO................ Accumulated Postretirement Benefit Obligation
Austin.............. City of Austin, Texas
Btu................. British thermal unit
CEO................. Chief Executive Officer
CERCLA.............. Comprehensive Environmental Response, Compensation
and Liability Act of 1980
Company or CPL...... Central Power and Light Company, Corpus Christi, Texas
Court of Appeals.... Court of Appeals, Third District of Texas, Austin, Texas
CSW................. Central and South West Corporation, Dallas, Texas
CSW System.......... CSW and its subsidiaries
CSWE................ CSW Energy, Inc., Dallas, Texas
CSWS................ Central and South West Services, Inc., Dallas, Texas
CWIP................ Construction Work in Progress
DOE................. Department of Energy
District Court...... District Court of Travis County
Electric Operating
Companies......... PSO, SWEPCO, WTU and the Company
Energy Policy Act... The National Energy Policy Act of 1992
EPA................. United States Environmental Protection Agency
ERISA............... Employee Retirement Income Security Act of 1974, as
amended
ERCOT............... Electric Reliability Council of Texas
FASB................ Financial Accounting Standards Board
FERC................ Federal Energy Regulatory Commission
HLP................. Houston Lighting & Power Company
Holding Company Act. Public Utility Holding Company Act of 1935, as amended
HVdc................ High-voltage direct-current
ITC................. Investment Tax Credit
Kw.................. Kilowatt (1,000 Watts)
Kwh................. Kilowatt-hour
Mcf................. 1,000 cubic feet
Mw.................. Megawatt (1 Million Watts)
Named Executive
Officers.......... The CEO and the four most highly compensated executive
officers of the Company reflected in the Summary
Compensation Table
NRC................. Nuclear Regulatory Commission
Oklaunion........... Oklaunion Power Station Unit No. 1
OPUC................ The Office of Public Utility Counsel
PCB................. Polychlorinated biphenyl
Project Manager..... Houston Lighting & Power Company
PSO................. Public Service Company of Oklahoma, Tulsa, Oklahoma
PURA................ Public Utility Regulatory Act
RCRA................ Federal Resource Conservation and Recovery Act of 1976
PCRB................ Pollution Control Revenue Bond
SAR................. Stock Appreciation Right
San Antonio......... City of San Antonio, Texas
SEC................. Securities and Exchange Commission
SFAS................ Statement of Financial Accounting Standards
SO2................. Sulfur dioxide
STP................. South Texas Project electric generating station
SWEPCO.............. Southwestern Electric Power Company, Shreveport,
Louisiana
Texas Commission.... Public Utility Commission of Texas
TNRCC............... Texas Natural Resource Conservation Commission
TSA................. Texas State Agencies
TU.................. Texas Utilities Electric Company
Westinghouse........ Westinghouse Electric Corporation
WTU................. West Texas Utilities Company, Abilene, Texas
PART I
ITEM 1. BUSINESS.
The Company. The Company, a Texas corporation, is a public utility engaged
in generating, purchasing, transmitting, distributing and selling electricity
in south Texas. It is a wholly owned subsidiary of CSW, a registered holding
company under the Holding Company Act.
At December 31, 1993, the Company supplied electric service to
approximately 589,000 retail customers in a 44,000 square mile area with an
estimated population of 1,945,000. It supplied at wholesale all or a portion
of the electric energy requirements of two municipalities and five rural
electric cooperatives. The three largest metropolitan areas served by the
Company are Corpus Christi, Laredo and McAllen, which have estimated populations
of 265,000, 133,000 and 88,000, respectively.
The economic base of the territory served by the Company includes
manufacturing, metal refining, petroleum, petrochemical, agriculture and
tourism.
In 1993, industrial customers accounted for approximately 23% of the Company's
total operating revenues. Contracts with substantially all industrial customers
provide for both demand and energy charges. Demand charges continue under such
contracts even during periods of reduced industrial activity, thus mitigating
the effect of reduced activity on operating income.
Regulation and Rates
Regulation. The Company, as a subsidiary of CSW, is subject to the
jurisdiction of the SEC under the Holding Company Act with respect to the
issuance, acquisition and sale of securities, acquisition and sale of certain
assets or any interest in any business, including certain aspects of fuel
exploration and development programs, accounting practices and other matters.
The FERC has jurisdiction under the Federal Power Act over certain of the
Company's electric utility facilities and operations, wholesale rates and
certain other matters.
The Texas Commission has jurisdiction over accounts, certification of
utility service territories, sale or acquisition of certain utility property,
mergers and certain other matters. Neither the Texas Commission nor the
governing bodies of incorporated municipalities have jurisdiction over the
issuance of securities.
National Energy Policy Act of 1992. The Energy Policy Act, adopted in
October 1992, significantly changed U.S. energy policy, including that governing
the electric utility industry. The Energy Policy Act allows the FERC, on a
case-by-case basis and with certain restrictions, to order wholesale
transmission access and to order electric utilities to enlarge their
transmission systems. The Energy Policy Act does, however, prohibit FERC-
ordered retail wheeling, including "sham" wholesale transactions. Further,
under the Energy Policy Act a FERC transmission order requiring a transmitting
utility to provide wholesale transmission services must include provisions
generally that permit the utility to recover from the FERC applicant all of the
costs incurred in connection with the transmission services, any enlargement of
the transmission system and associated services.
In addition, the Energy Policy Act revised the Holding Company Act to
permit utilities, including registered holding companies, and non-utilities to
form exempt wholesale generators. An exempt wholesale generator is a new
category of non-utility wholesale power producer that is free from most federal
and state regulation, including the principal restrictions of the Holding
Company Act. These provisions enable broader participation in wholesale power
markets by reducing regulatory hurdles to such participation. Management
believes that this Act will make wholesale markets more competitive. However,
the Company is unable to predict the extent to which the Energy Policy Act will
affect its operations.
See ITEM 1. BUSINESS -- Environmental Matters, for information relating to
Environmental regulation.
Rates. The Texas Commission has original jurisdiction over retail rates
in the unincorporated areas of Texas. The governing bodies of incorporated
municipalities have such jurisdiction over rates within their incorporated
limits. Municipalities may elect, and some have elected, to surrender this
jurisdiction to the Texas Commission. The Texas Commission has appellate
jurisdiction over rates set by incorporated municipalities.
See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, Rate Case Filings in
ITEM 8, for further information with respect to current rate proceedings.
Electric utilities in Texas are not allowed to make automatic adjustments
to recover changes in fuel costs from retail customers. A utility is allowed
to recover its known or reasonably predictable fuel costs through a fixed fuel
factor. The Texas Commission established procedures effective May 1, 1993,
subject to certain transition rules, whereby each utility under its jurisdiction
may petition to revise its fuel factors every six months according to a
specified schedule. Fuel factors may also be revised in the case of an
emergency or in a general rate proceeding. Under the revised procedures, a
utility will remain subject to the prior rules until after its first fuel
reconciliation, or in some instances a general rate proceeding including a fuel
reconciliation, subject to the new rules. Management does not believe that the
new rules substantially change the manner in which the Company will recover
retail fuel costs.
Fuel factors are in the nature of temporary rates, and the utility's
collection of revenues by such is subject to adjustment at the time of a fuel
reconciliation proceeding. At the utility's semi-annual adjustment date, a
utility is required to petition the Texas Commission for a surcharge or to make
a refund when it has materially under- or over-collected its fuel costs and
projects that it will continue to materially under- or over-collect. Material
under- or over-collections including interest are defined as four percent of the
most recent Texas Commission adopted annual estimated fuel cost for the utility,
which is approximately $10.4 million for the Company. A utility does not have
to revise its fuel factor when requesting a surcharge or refund. An interim
emergency fuel factor order must be issued by the Texas Commission within 30
days after such petition is filed by the utility.
Final reconciliation of fuel costs are made through a reconciliation
proceeding, which may contain a maximum of three years and a minimum of one year
of reconcilable data, and must be filed with the Texas Commission no later than
six months after the end of the period to be reconciled. In addition, a utility
must include a reconciliation of fuel costs in any general rate proceeding
regardless of the time since its last fuel reconciliation proceeding. Any fuel
costs which are determined unreasonably incurred in a reconciliation proceeding
must be refunded to customers. In the event that the Company does not recover
all of its fuel costs under the above procedures, the Company could experience
an adverse impact on its results of operations.
All of the Company's contracts with its wholesale customers contain FERC
approved fuel-adjustment provisions that permit it to automatically pass actual
fuel costs through to its customers.
See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, in ITEM 8, for further
information with respect to regulation and rates.
STP
The ownership of a nuclear generating unit exposes the Company to
significant special risks. Under the Atomic Energy Act of 1954 and Energy
Reorganization Act of 1974, operation of nuclear plants is intensively regulated
by the NRC, which has broad power to impose licensing and safety-related
requirements. Along with other federal and state agencies, the NRC also has
extensive regulations pertaining to the environmental aspects of nuclear
reactors. The NRC has the authority to impose fines and/or shutdown a unit
until compliance is achieved, depending upon its assessment of the severity of
the situation.
The high degree of regulatory monitoring and controls to assure safe
operation could cause the STP units to be out of service for long periods of
time. Outages are also necessary approximately every 18 months for refueling.
Because STP's fuel costs currently are lower than any of the Company's other
units, the Company's average fuel costs are expected to be higher whenever an
STP unit is down or operates below the prior period's average capacity.
Risks of substantial liability arise from the operation of nuclear-fueled
generating units and from the use, handling, and possible radioactive emissions
associated with nuclear fuel. While the Company carries insurance, the
availability, amount and coverage thereof is limited and may become more limited
in the future. The available insurance will not cover all types or amounts of
loss expense which may be experienced in connection with the ownership of STP.
See NOTE 10, COMMITMENTS AND CONTINGENCIES - Nuclear Insurance, in ITEM 8 for
further information.
See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, in ITEM 8 for a
discussion of the STP outage.
Operations
Peak Loads and System Capabilities. The following table sets forth for the
years 1991 through 1993 the net system capabilities of the Company (including
the net amounts of contracted purchases and contracted sales) at the time of
peak demand, the maximum coincident system demand on a one-hour integrated
basis (exclusive of sales to other electric utilities) and the respective
amounts and percentages of peak demand generated by the Company and net
purchases and sales:
Percent
Increase
Maximum (Decrease) Net Purchases
Coincident In Peak Generation at (Sales) at
Net System System Demand Time of Peak Time of Peak
Capabilities(a) Demand(b) Over Prior
Year Mw Mw Period Mw % Mw %
1991 4,005 3,291 5.8 3,424 104.0 (133) (4.0)
1992 4,165 3,347 1.7 3,003 89.7 344 10.3
1993 4,480 3,518 5.1 2,943 83.7 575 16.3
___________________
(a) Does not include 452 Mw of system capability in long-term storage in 1991
and 310 Mw in 1992 and 1993 as described under "ITEM 2. PROPERTIES --
Facilities." Does include 630 Mw of STP capability that was not available
at the peak due to the outage described in NOTE 9, LITIGATION AND
REGULATORY PROCEEDINGS, in ITEM 8.
(b) Maximum coincident system demand occurred on August 21, August 11 and
August 25, in the years 1991, 1992 and 1993, respectively.
The Company is a member of ERCOT, which also includes TU, HLP, WTU, Texas
Municipal Power Agency, Texas Municipal Power Pool, Lower Colorado River
Authority, the municipal systems of San Antonio, Austin and Brownsville, the
South Texas and Medina Electric Cooperatives, and several other interconnected
systems and cooperatives. The ERCOT members interchange power and energy on
firm, economy and emergency bases. The Company also engages in economy
interchanges with the other electric operating companies in the CSW System.
The CSW System operates on an interstate basis to facilitate exchanges of
power. PSO and WTU are interconnected through the 200,000 Kw North HVdc Tie.
In August 1992, the Company entered into an agreement with SWEPCO, HLP and TU
to construct and operate an East Texas Hvdc transmission interconnection which
will facilitate exchanges of power for the CSW System. The Company has a 25.0%
ownership interest in the project. This interconnection will consist of a back-
to-back HVdc converter station and 16 miles of 345 kilovolt alternating-current
transmission line connecting transmission substations at SWEPCO's Welsh Power
Plant and TU's Monticello Power Plant. In March 1993, an application for a
Certificate of Convenience and Necessity for the transmission interconnection
was approved by the Texas Commission. This 600,000 Kw project is scheduled to
be completed in 1995.
Competition. In Texas, electric service areas are approved by the Texas
Commission. A given tract in the Company's overall service area may be singly
certificated to the Company, to one of several competing electric cooperatives
or to one of the competing municipal electric systems; it may also be dually or
triply certificated to these entities. These certificated areas have changed
only slightly since the formation of the Texas Commission in 1976, with the
Company generally singly certificated to serve inside most municipalities,
cooperatives singly certificated to serve much of the rural areas, and the
suburban areas mostly dually certificated.
Since 1990, in dually certificated areas, the Company has been higher in
cost than competitors for many applications, especially small commercial and
industrial customers. However, most business has been retained and some new
business acquired, primarily because of service reliability and other customer
service advantages. Natural gas and other alternative fuels, including those
used in cogeneration facilities, have resulted in some losses of sales,
primarily because of higher electricity costs relative to gas and oil costs.
Although there have been some losses, electricity is still the fuel of choice
for most air conditioning installations. Renewable energy such as solar and
wind is not now a feasible economic choice for customers of the Company in most
instances. The Company believes that its rates, the quality and reliability of
its service and the relatively inelastic demand for electricity for certain end
uses place it in a favorable competitive position in current retail markets.
Wholesale energy markets, including the market for wholesale electric
power, are extremely competitive, even more so after the enactment of the Energy
Act of 1992. See "National Energy Policy Act of 1992" above. The Company
competes with other public utilities, cogenerators and qualified facilities in
other forms, exempt wholesale generators and others for sales of electric power
at wholesale.
Many competitive forces currently are at work in the electric utility
industry. Various legislative and regulatory bodies are considering many
issues, including the extent of any deregulation of the electric utility
industry or of any access to an electric utility's transmission system to make
retail sales of power, the pricing of transmission service on an electric
utility's transmission system, and the role of utilities, independents and
others in the construction and operation of new generation capacity. The
Company is unable to predict the ultimate outcome or impact of these issues or
the impact of further changes in the electric utility industry on the Company.
To the extent that consumers of electric power approach electric power as a
fungible commodity and are accorded more choices in the future for their power
supplies, the principal factor determining success in retail and wholesale
markets probably would be price, and to a lesser extent, reliability,
availability of capacity, and customer service. The Company is taking steps to
enhance its marketing and customer service, reduce costs, and improve and
standardize business practices in line with the best practices in the CSW
System, in order to position itself for increased competition in the future.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS, for a discussion of the restructuring of the CSW System
and certain industry and other challenges.
Seasonality. Sales of electricity by the Company tend to increase during
warmer summer months and, to a lesser extent, cooler winter months, because of
higher demand for power for cooling and heating purposes.
Employees. At December 31, 1993, the Company had 2,299 employees. See
ITEM 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS - Restructuring, for a discussion of the recently announced
restructuring of the CSW System and associated early retirement program and work
force reduction.
Operating Statistics
Years Ended December 31,
1993 1992 1991
KILOWATT-HOUR SALES (Millions):
Residential ................... 5,612 5,408 5,476
Commercial .................... 4,278 4,181 4,215
Industrial .................... 6,406 5,800 5,354
Other retail................... 435 414 396
------ ------ ------
Sales to retail customers ..... 16,731 15,803 15,441
Sales for resale .............. 913 1,370 1,485
------ ------ ------
Total .................... 17,644 17,173 16,926
====== ====== ======
NUMBER OF ELECTRIC CUSTOMERS AT END
OF PERIOD:
Residential ................... 504,893 493,772 483,627
Commercial .................... 74,767 73,200 72,520
Industrial (a)................. 6,156 6,307 6,411
Other.......................... 3,538 3,561 3,508
------- ------- -------
Total .................... 589,354 576,840 566,066
======= ======= =======
RESIDENTIAL SALES AVERAGES:
Kwh per customer .............. 11,298 11,133 11,492
Revenue per customer .......... $955 $890 $915
Revenue per Kwh (cents)........ 8.45 7.99 7.96
REVENUES PER KWH ON TOTAL SALES
(cents)...................... 6.93 6.48 6.49
FUEL COST DATA:
Average Btu per net Kwh ....... 10,296 10,404 10,309
Cost per million Btu .......... $2.17 $1.70 $1.73
Cost per Kwh generated (cents). 2.23 1.77 1.79
Cost as a percentage of
revenue ..................... 28.6 27.6 27.6
_______________________
(a) The customer decrease in 1993 was largely due to the combining of multiple
customer accounts into single accounts.
Construction and Financing
Construction. The estimated total capital expenditures (including AFUDC)
for the years 1994-1996 are as follows:
1994 1995 1996 Total
(Millions)
Generation ........................ $ 36 $ 27 $ 20 $ 83
Transmission ...................... 72 16 41 129
Distribution ...................... 57 56 60 173
Fuel .............................. 2 8 21 31
Other ............................. 28 21 15 64
--- --- --- ---
Total $195 $128 $157 $480
=== === === ===
Information in the foregoing table is subject to change due to numerous
factors, including the rate of load growth, escalation of construction costs,
changes in lead times in manufacturing, inflation, the availability and pricing
of alternatives to construction or nuclear, environmental and other regulation,
delays from regulatory hearings, the adequacy of rate relief and the
availability of necessary external capital. Changes in these and other factors
could cause the Company to defer or accelerate construction or to sell or buy
more power, which would affect its cash position, revenues and income to an
extent that cannot now be reliably predicted. See Construction Program in
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, in ITEM 7, for additional information relating to construction.
The Company continues to study alternatives to reduce or meet future
increases in customer demand, including without limitation demand-side
management programs, new and efficient electric technologies, various
architectures for new and existing generation facilities, and methods to reduce
transmission and distribution losses. The Texas Commission considers on a
case-by-case basis mechanisms whereby costs of demand-side management programs
and some return on the related investment are recoverable from customers, either
on a current basis or through deferral to a base rate case. The Texas
Commission has not to date adopted similar mechanisms for associated revenue
reductions and performance incentives.
The CSW System facilities plan currently indicates that the Company will
not require substantial additions to its generating capacity until the year 2001
or beyond.
Financing. See, Financing and Capital Resources in MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, in ITEM 7, for
information with respect to financing and capital resources.
Fuel Supply
General. The Company's present electric generating plants showing the type
of fuel used are set forth under "ITEM 2. PROPERTIES."
During 1993, approximately 65% of Kwh generation was from gas, 33% from
coal and 2% from nuclear fuel. Nuclear generation was substantially reduced in
1993 due to the STP outage described in NOTE 9, LITIGATION AND REGULATORY
PROCEEDINGS, in ITEM 8. Natural gas consumption totaled 104 million Mcf and
coal requirements were 2 million tons.
Natural Gas. The Company's eight gas-fired electric generating plants are
supplied by 12 separate long-term natural gas purchase agreements accounting for
approximately 57% of the Company's total gas requirements in 1993. The balance
of the Company's natural gas requirements could have been supplied under
existing long-term arrangements; however, with the favorable spot market
conditions existing during the period, the Company elected to purchase these
requirements under lower cost, spot market arrangements. The Company's
principal gas supplies for 1993 were provided under agreements with Corpus
Christi Gas Marketing L.P., Enron Corporation, Onyx Pipeline Company or their
affiliates. They supplied approximately 22%, 18% and 11%, respectively, of the
Company's total natural gas purchases. Including spot market suppliers, the
Company had 31 individual suppliers of natural gas during 1993.
Coal. The Company's two coal-fired electric generating plants, Coleto
Creek and jointly owned Oklaunion, are both primarily supplied by single
long-term coal purchase agreements. At Coleto Creek, the long-term agreement
expiring in 1999 with Colowyo Coal Company provided approximately 56% of the
coal requirements of the plant for 1993. The Company's purchase obligation set
forth in the Colowyo agreement for 1994 is for approximately 60% of Coleto
Creek's requirements and 25% for 1995 through expiration. The coal is mined in
northwestern Colorado and is transported approximately 1,400 miles under
long-term rail agreements with the Denver & Rio Grande Western Railroad Company,
the Burlington Northern Railroad Company and the Southern Pacific Transportation
Company. The balance of the Coleto Creek requirements are currently being
procured on the spot market and it is anticipated that this will continue until
the expiration of the agreement in 1999. The Company owns sufficient railcars
for operation of three unit trains, and has negotiated contracts with the rail
carriers involved which have been accepted by the Interstate Commerce
Commission. At year-end 1993, the Company had approximately 140,000 tons of
coal in inventory at Coleto Creek, representing approximately 21 days supply.
Currently Oklaunion's long-term coal supply is provided under a contract
expiring in 2006 with Exxon Coal USA, Inc. This agreement is for Wyoming coal
which is transported approximately 1,100 miles to the plant by the Burlington
Northern Railroad Company. Approximately 65% of the total 1993 Oklaunion coal
requirements for the Company were supplied under the Exxon Agreement with the
balance procured on the spot market. In December 1993, a settlement was reached
with Exxon regarding disputes over certain provisions of this long-term coal
contract. The settlement is expected to result in lower fuel costs at
Oklaunion. The Company's share of the year-end 1993 coal inventory at Oklaunion
was approximately 40,000 tons, representing approximately 52 days supply.
Nuclear Fuel. The nuclear fuel cycle entails several steps, including
purchase of uranium concentrate, conversion of uranium concentrate to uranium
hexafluoride, enrichment of uranium hexafluoride into the isotope U235 and
fabrication of the enriched uranium into fuel rods and fuel assemblies. Fuel
requirements for STP are being handled by a committee comprised of
representatives of all participants in STP.
The Company and the other STP participants have entered into contracts with
suppliers for uranium concentrate sufficient for the operation of both STP units
through 1996. Enrichment contracts have been secured for a 30-year period from
the present for each unit. Contracts have been secured for conversion services
for both units through 1996. Also, fuel fabrication services have been
contracted for the initial cores and 16 years of operation of each unit from the
present. The Company believes it will be able to obtain adequate supplies of
nuclear fuel components and services required for the life of STP.
The nuclear power industry faces uncertainties with respect to the cost and
availability of long-term arrangements for disposal of spent nuclear fuel and
other radioactive waste. Disposal costs for low-level radioactive waste that
results from normal operation of nuclear units have increased significantly in
recent years and are expected to continue to rise, but adequate storage and
disposal facilities are expected to be available for STP.
The Company and the other STP participants have entered into a waste
disposal contract for spent fuel with the DOE. Under this contract, the DOE is
required to take possession of all spent fuel from the STP units by 1998. The
DOE has had difficulties in formulating and implementing its strategy for high-
level waste disposal and for any compensation to utilities if the DOE is unable
to accept such waste on schedule.
Until the federal government begins receiving such materials in accordance
with the Nuclear Waste Policy Act and DOE contracts, operating nuclear
generating plants will need to retain high-level wastes and spent fuel on-site
or make some other provisions for their storage. STP has on-site storage
facilities with the capability to store up to 40 years of spent fuel discharged
from each unit. Under NRC regulations, spent nuclear fuel from STP may be
stored under a general license provided that the licensee notifies the NRC, uses
only NRC-certified casks for storage, and stores the spent fuel under conditions
specified in the cask's certificate of compliance.
Governmental Regulation. The price and availability of each of the
foregoing fuel types are significantly affected by governmental regulation. Any
inability in the future to obtain adequate fuel supplies, or adoption of
additional regulatory measures restricting the use of such fuels for the
generation of electricity, might affect the Company's ability to meet
economically the needs of its customers and could require it to supplement or
replace, prior to normal retirement, existing generating capability with units
using other fuels. This would be impossible to accomplish quickly, would
require substantial expenditures for construction and could have a significant
adverse effect on the Company's financial position and results of operations.
Fuel Costs. Additional fuel cost data for the Company appears under
"Operating Statistics." For 1993, total average cost of fuel per million Btu
was $2.17. Average costs per million Btu by major fuel type were $2.27 for
natural gas, $2.06 for coal and $0.57 for nuclear. The Company is unable to
predict accurately the future cost of fuel.
Environmental Matters
The Company is subject to regulation with respect to air and water quality
and solid waste standards, along with other environmental matters, by various
federal, state and local authorities. These authorities have continuing
jurisdiction in most cases to require modifications in the Company's facilities
and operations. Changes in environmental statutes or regulations could require
substantial additional expenditures to modify the Company's facilities and
operations and could have a significant adverse effect on the Company's results
of operations. Violations of environmental statutes or regulations can result
in fines and other costs.
Air Quality. Air quality standards and emission limitations are subject
to the jurisdiction of the TNRCC, with oversight by the EPA. In accordance with
regulations of the TNRCC, permits are required for all generating units on which
construction is commenced or which are substantially modified after the
effective date of the applicable regulations. The Company has not received
notice from any federal or state government agency alleging that it currently
is subject to an enforcement action for a material violation of existing federal
or state air quality and emission regulations. The EPA has approved and may
enforce the air quality standards and limitations adopted by the TNRCC and has
adopted ambient air quality standards applicable nationally, as well as new
source performance standards for all new or substantially modified generating
units.
In November 1990, the United States Congress passed the Clean Air Act
Amendments of 1990, which place restrictions on the emission of SO2 and nitrogen
oxides from gas-, coal- and lignite-fired generating plants starting in the year
2000. The right to emit SO2 from existing generating plants will be established
based on historical operating conditions. These rights will be controlled
through an allowance program. Each unit of allowance is an entitlement to emit
one ton of SO2 per year. The Company, based on the CSW System facilities plan,
believes its allowances are adequate to meet its needs at least through 2008.
Public and private markets are developing for trading of excess allowances. The
Company presently has no intention of engaging in sales or purchases of
allowances, but may seek to do so in the future if market conditions warrant.
Based on the latest CSW System facilities plan, the Company estimates
making capital expenditures of $5 million to install emission monitoring
equipment for existing plants by January 1, 1995.
Water Quality. The TNRCC and the EPA have jurisdiction over all wastewater
discharges into state waters. The TNRCC has jurisdiction for establishing water
quality standards and issuing waste control permits covering discharges which
might affect the quality of state waters. The EPA has jurisdiction over "point
source" discharges through the National Pollutant Discharge Elimination System
provisions of the Clean Water Act. The Company has not received notice from any
federal or state government agency alleging that it currently is subject to an
enforcement action for a material violation of existing federal or state
wastewater discharge regulations.
Solid Waste Disposal. The RCRA and the TNRCC solid waste rules provide for
comprehensive control of all solid wastes from generation to final disposal.
The TNRCC has received authorization from the EPA to administer the RCRA solid
waste control program for Texas. The Company has not received notice from any
federal or state government agency alleging that it currently is subject to an
enforcement action for a material violation of existing federal or state solid
waste regulations.
CERCLA and Related Matters. Under CERCLA, owners or operators of
contaminated sites and, transporters and/or generators of hazardous substances
can be held liable for the cleanup of hazardous substance disposal sites.
Similar liabilities for hazardous substance disposal can arise under applicable
state law. The Company incurs costs for the handling, transportation, storage
and disposal of hazardous, toxic and non-hazardous waste materials. Unit costs
for waste classified as hazardous or toxic exceed by a substantial margin unit
costs for waste classified as non-hazardous.
The Company produces combustion and other generation by-products, such as
sludge, ash, slag, low-level radioactive waste and spent fuel. The Company owns
distribution poles treated with creosote or similar substances which are not
expected to exhibit characteristics that would cause them to be hazardous waste.
The EPA currently exempts coal combustion by-products from regulation as
hazardous wastes. In connection with its operations, the Company also has
used asbestos, PCBs and other materials classified as hazardous or toxic waste.
If additional by-products or other materials generated or used by the Company
were reclassified as hazardous or toxic wastes, or other new laws or regulations
concerning hazardous or toxic wastes or other materials were put in effect, the
Company's disposal and remedial costs could increase materially. In 1993, the
EPA made an administrative determination that coal combustion by-products are
non-hazardous. The EPA is expected in the near-term to issue new regulations
stating whether certain other non-combustion by-products will be classified as
hazardous waste.
In November 1985, the Texas Attorney General brought suit against the
Company under the Texas Solid Waste Disposal Act and Chapter 26 of the Texas
Water Code. This suit alleged that the Company was one of the parties
responsible for lead and PCB contamination at the Industrial Road and Industrial
Metals site in Corpus Christi, Texas and, therefore, should share the
responsibility for cleanup of the site. The site was used by several metal
salvage companies for the salvage of various materials allegedly purchased from
various entities including the Company and other utilities. Pursuant to an
agreement with the State of Texas, and under the direction and supervision of
the Texas Water Commission (TWC), now the TNRCC, the Company engaged independent
contractors to design and implement a closure plan for the site which was
approved by the TWC. The closure of the site was conducted and completed under
the direction and supervision of the TWC by an independent contractor
specializing in waste site closures and waste management facilities. The
Closure Certification Report was submitted to the TWC in December 1990, and was
given final approval by the TWC in August 1991. Total expenses incurred by the
Company for cleanup through December 1993 have been approximately $2 million.
No additional material costs to the Company are anticipated.
Three additional lawsuits relating to this site, naming the Company as one
of the defendants, are pending and discovery continues. The first was filed in
December 1990 and is currently pending in U. S. District Court, Southern
District, Nueces County. This suit was filed by multiple plaintiffs residing
in a neighborhood near the Industrial Metals site who now allege response costs
under CERCLA and property damages in excess of $100 million for lead
contamination allegedly resulting from closure of the site. In November 1992,
a similar suit with multiple plaintiffs, was filed in the 117th Judicial
District Court, Nueces County. This suit alleges property damage and response
costs under CERCLA in excess of $1 million for lead and PCB contamination
allegedly resulting from the closure of the site. A third lawsuit was filed in
March 1993 in the 94th Judicial District Court in Nueces County. The suit was
filed by multiple parties alleging that the closure of the site caused a
wrongful diversion of surface water under the Texas Water Code, resulting in
flooding to their property. They claim actual damages of approximately
$162,000, plus mental anguish and attorneys' fees. The Company was recently
granted summary judgment on a fourth suit arising from the site that was filed
in the spring of 1993 in the 37th Judicial District Court in Bexar County. This
suit was filed against the Company and other defendants by a widow alleging that
her husband's death was caused by exposure to PCBs at the site where he was
employed 20 years ago for a two week period. An appeal is possible, but the
limitation period for that appeal does not begin to run until the Company is
severed from the suit still pending against other defendants. Although
management cannot predict the outcome of these proceedings, based on the
defenses that management believes are available to the Company, management
believes that the ultimate resolution of these matters will not have a material
adverse effect on the Company's results of operations or financial condition.
In September 1992, the EPA conducted an inspection, of various Company
facilities, under the Toxic Substance Control Act regarding various PCB and
equipment management activities. The Company is responding to the initial
findings and it is not known when a final inspection report will be issued,
however, management does not believe that the resolution of this matter will
have a material adverse effect on the Company's results of operations or
financial condition.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - Environmental for a discussion of certain other
environmental matters.
From time to time the Company is made aware of various other environmental
issues or is a party to various other legal claims, actions, complaints and
other proceedings related to environmental matters. Management does not expect
disposition of any such environmental proceedings to have a material adverse
effect on the Company's results of operations or financial condition.
ITEM 2. PROPERTIES.
Facilities. At December 31, 1993, the Company owned the following electric
generating plants (or portions thereof in the cases of the jointly owned
plants).
(See "ITEM 1. BUSINESS -- Fuel Supply.")
Net Dependable
Type of Fuel Capability
Plant Name and Location Primary/Secondary Mw
Barney M. Davis gas/oil(a) 339
Corpus Christi, Texas gas/oil 340
Coleto Creek coal 604
Goliad, Texas
Lon C. Hill gas/oil(a) 549
Corpus Christi, Texas
Nueces Bay gas/oil(a) 512(b)
Corpus Christi, Texas
Victoria gas/oil(a) 258(b)
Victoria, Texas
La Palma gas/oil 47
San Benito, Texas gas/oil(a) 156(b)
E. S. Joslin gas/oil(a) 252
Point Comfort, Texas
J. L. Bates gas/oil(a) 182
Mission, Texas
Laredo gas/oil(a) 66
Laredo, Texas gas/oil 106
Eagle Pass
Eagle Pass, Texas hydro 6
Oklaunion coal 53(c)
Vernon, Texas
STP nuclear 630(d)
Bay City, Texas
Total 4,100
_______________________
(a) For extended periods of operation, oil can be used only in combination with
gas. Use of oil in facilities primarily designed to burn gas results in
increased maintenance expense and a reduction of approximately 15% in
capability.
(b) Excludes units in long-term storage - 34 Mw at Nueces Bay, 228 Mw at
Victoria and 48 Mw at La Palma.
(c) The Company owns 7.81% of the 676 Mw unit operated by WTU.
(d) The Company owns 25.2% of the two 1,250 Mw units operated by HLP.
All of the generating plants described above are located on land owned by
the Company or jointly with the other participants in jointly owned plants. The
Company's electric transmission and distribution facilities are for the most
part located over or under highways, streets and other public places or property
owned by others, for which permits, grants, easements or licenses (which the
Company believes to be satisfactory, but without examination of underlying land
titles) have been obtained. The principal plants and properties of the Company
are subject to the lien of the first mortgage indenture under which the
Company's first mortgage bonds are issued.
ITEM 3. LEGAL PROCEEDINGS.
See ITEM 1. BUSINESS - Environmental Matters, for information relating to
environmental and certain other proceedings.
See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, in ITEM 8, for
information relating to regulatory and legal proceedings.
The Company is party to various other legal claims, actions and complaints
arising in the normal course of business. Management does not expect
disposition of these matters to have a material adverse effect on the Company's
results of operations or financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
All of the outstanding shares of Common Stock of the Company are owned by
its parent company, CSW.
ITEM 6. SELECTED FINANCIAL DATA.
The following selected financial data are provided to highlight significant
trends in the financial condition and results of operations of the Company:
1993 1992 1991 1990 1989
(thousands, except ratios)
Electric Operating Revenues $1,223,528 $1,113,423 $1,098,730 $ 948,520 $ 836,585
Income Before Cumulative
Effect of Changes in
Accounting Principles 145,130 218,511 217,206 204,870 147,781
Preferred Stock Dividends 14,003 16,070 19,844 23,528 24,558
Income for Common Stock
Before Cumulative Effect of
Changes in Accounting Principles 131,127 202,441 197,362 181,342 123,223
Cumulative Effect of Changes
in Accounting Principles (1) 27,295 - - - -
Net Income for Common Stock 158,422 202,441 197,362 181,342 123,223
Total Assets (2) 4,781,745 4,583,660 4,458,063 4,516,375 3,913,360
Preferred Stock
Not Subject to Mandatory
Redemption 250,351 250,351 250,351 250,351 250,351
Subject to Mandatory Redemption 22,021 28,393 35,331 40,584 43,803
Long-Term Debt 1,362,799 1,347,887 1,350,854 1,346,587 1,331,349
Ratio of Earnings to Fixed
Charges (SEC Method) Before
Cumulative Effect of Changes
in Accounting Principles 2.69 3.23 3.18 3.11 2.48
Capitalization Ratios
Common Stock Equity 46.6% 46.9% 46.6% 47.0% 45.7%
Preferred Stock 8.9 9.1 9.3 9.4 9.8
Long-Term Debt 44.5 44.0 44.1 43.6 44.5
(1) The 1993 cumulative effect relates to the changes in accounting for unbilled
revenues and adoption of SFAS No. 112, Employer's Accounting for
Postemployment Benefits. See NOTE 1, SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES, in ITEM 8.
(2) The 1992-1989 total assets have been reclassified to reflect the effects of
the adoption in 1993 of SFAS No. 109, Accounting for Income Taxes. See NOTE
2, FEDERAL INCOME TAXES, in ITEM 8.
The Company changed its method of accounting for unbilled revenues in 1993.
Pro forma amounts assuming that the change in accounting for unbilled revenues
had been adopted retroactively are not materially different from amounts
previously reported for prior years.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
Reference is made to the Company's Financial Statements and related Notes and
Selected Financial Data in ITEM 8. The information contained therein should be
read in conjunction with, and is essential in understanding, the following
discussion and analysis.
Overview
Net income for common stock for the year 1993 decreased 21.7% to $158
million from $202 million in 1992. The decline was due primarily to increased
administrative and general expenses, increased STP operating and maintenance
expenses, higher taxes other than Federal income, additional employee benefits
costs, and the decline in Mirror CWIP liability amortization. Partially
offsetting the effects of the above items were increased base revenues, reduced
interest expense, lower preferred stock dividends, and the cumulative effect of
a change in accounting for unbilled revenue. Reflected in the overall earnings
reduction is a $9 million net negative effect of several one-time items
including the cost of the Company's restructuring, true-up of prior years'
federal taxes, write-down of lignite properties and environmental issues,
adoption of new accounting standards for medical costs and the accrual of
unbilled revenues.
The 1992 increase in net income for common stock over 1991 was due
primarily to higher revenues from increased Kwh sales, lower operating and
maintenance expenses and a reduction in preferred stock dividends.
Average return on common equity decreased to 11.1% in 1993 from 14.2% in
1992. The Company took advantage of lower interest rates in 1993 and refinanced
$391 million of higher cost debt which reduced the embedded cost of long-term
debt and lowered annual interest expense $11 million.
STP
In February 1993, Units 1 and 2 of STP were shut down by HLP, the Project
Manager, in an unscheduled outage resulting from mechanical problems relating
to two auxiliary feedwater pumps. HLP determined that the units would not be
restarted until the equipment failures had been corrected and the NRC was
briefed on the causes of these failures and the corrective actions that were
taken. The NRC formalized that commitment in a confirmatory action letter and
sent an Augmented Inspection Team to STP to review the matter. In March 1993,
the NRC began a diagnostic evaluation of STP. Conducted infrequently,
diagnostic evaluations are broad-based evaluations of overall plant operations
and are intended to review the strengths and weaknesses of the licensee's
performance and to identify the root cause of performance problems. During and
subsequent to the June 1993 completion of the evaluation, the NRC supplemented
its confirmatory action letter to identify additional issues to be resolved and
verified by the NRC before restart of STP. Such issues included the need to
reduce backlogs of engineering and maintenance work and to simplify work
processes which placed excessive burdens on operating and other plant personnel.
The report also identified the need to strengthen management communications,
oversight and teamwork as well as the capability to identify and correct the
root causes of problems.
The NRC announced in June 1993 that STP was placed on its "watch list" of
plants with "weaknesses that warrant increased NRC attention." Plants on the
watch list are subject to closer NRC oversight. STP will remain on the NRC's
watch list until both units return to service and a period of good performance
is demonstrated.
During the outage, the necessary improvements have been made by HLP to
address the issues in the Confirmatory action letter, as supplemented. On
February 15, 1994, the NRC agreed that the confirmatory action letter issues had
been resolved with respect to Unit 1, and that it supported HLP's recommendation
that Unit 1 was ready to restart. Unit 1 restarted in late February 1994 and
operated at low power for three days. The Project Manager then shut down Unit
1 due to a problem with a steam generator feedwater valve and a steam generator
tube leak. The Project Manager expects to make the necessary repairs and
restart Unit 1 in late March 1994, although additional delays may occur.
While many of the corrective actions taken are common to both units, HLP
must demonstrate to the NRC that these issues are also resolved with respect to
Unit 2 before it is restarted. HLP estimates that Unit 2 will restart during
the second quarter of 1994 after the completion of refueling, which began in
March 1993 but was delayed in order to focus on the issues discussed above. The
outage has not affected the Company's ability to meet customer demands because
of existing capacity and the Company's ability to purchase additional energy
from affiliates and nonaffiliates.
As discussed below, under Results of Operation, the outage resulted in an
additional $29 million of operating, maintenance and administrative and general
costs. The Company expects to continue to experience increased operation and
maintenance expenses in 1994 but at a significantly lower level than in 1993.
During the outage, the Company's fuel and purchased power costs have been,
and are expected to continue to be, increased as the power normally generated
by STP must be replaced through sources with higher costs. It is unclear how
the Texas Commission will address the reasonableness of higher costs associated
with the STP outage. At January 31, 1993, before the start of the STP outage,
the Company had an over-recovered fuel balance of $5.2 million, exclusive of
interest. At January 31, 1994, the Company's under-recovered fuel balance was
$55.7 million, exclusive of interest. This under-recovery of fuel costs, while
due primarily to the STP outage, was also affected by changes in fuel prices and
timing differences. The Company cannot accurately estimate the amount of any
future under- or over-recoveries due to the unpredictable nature of the above
factors. Although there is the potential for disallowance of fuel-related
costs, such determination cannot be made until fuel costs are reconciled with
the Texas Commission. If a significant portion of fuel costs were disallowed
by the Texas Commission, the Company could experience a material adverse effect
on its results of operations in the year of disallowance. The Company is
required by the Texas Commission's rules to file a reconciliation of its fuel
costs by May 1, 1994. However, the Texas Commission Staff is proposing a
revised filing deadline that would not require the Company to file before the
fourth quarter of 1994.
Management believes that the operating outage at STP will not have a
material effect on its financial condition or on its results of operations.
See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, in ITEM 8 for additional
information related to STP.
Restructuring
CSW recently announced a management restructuring and early retirement
program designed to consolidate and restructure its operations in order to meet
the challenges of the changing electric utility industry and to compete
effectively in the years ahead. The underlying goal of the reorganization is
to enable the Company and the other Electric Operating Companies to focus better
on and be accountable for serving customers.
The initial phase of the restructuring will involve certain changes at
CSWS, the mutual service company that serves the CSW System. CSWS will be
realigned into two primary units - Operation Services and Production Services.
Operation Services will provide administrative services that can be performed
centrally to benefit the CSW System, including the Company. Production Services
will focus on consolidated fuel and generation planning for the Electric
Operating Companies as well as certain other activities. Certain aspects of the
restructuring may require SEC approval.
To implement its restructuring program, the CSW System will consolidate and
centralize its operation services and production services, including the
Company's. The Company is expected to reduce the size of its work force. An
early retirement program has been offered to approximately 200 eligible Company
employees and 726 employees on a systemwide basis. Since the restructuring is
not expected to be completed until the end of 1994, it is not possible at this
time to predict the number of employees who will take the early retirement
program, be granted severance packages or be relocated. The Company's share of
costs associated with an early retirement program, severance packages and
relocation is estimated to be $29.4 million before taxes, and was expensed in
1993.
The Company's share of severance and relocation costs will be paid from its
general corporate funds in 1994 and early retirement costs primarily from
pension and postretirement benefit plan trusts. Savings from the restructuring
are expected to begin in the second half of 1994. By the end of 1995, initial
costs should be fully recovered through operations and maintenance cost savings.
CSW established a Business Improvement Plan (BIP) in 1991 to identify,
analyze and implement the best business practices as part of its efforts to
align the CSW System strategically to meet competitive forces. The BIP program
will be incorporated as part of the reorganization. Any additional costs to the
Company are expected to be offset by future savings from the benefits provided
through the implementation of BIP recommendations.
Rates and Regulatory Matters
Reference is made to NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, in ITEM
8, for a discussion of the Company's rates and regulatory matters.
Construction Program
The Company's need for capital results primarily from its construction of
facilities to provide reliable electric service to its customers. Construction
expenditures including AFUDC were approximately $180 million in 1993, $102
million in 1992 and $100 million in 1991. It is estimated that construction
expenditures including AFUDC during the 1994 through 1996 period will aggregate
$480 million. Such expenditures primarily will be made to improve and expand
transmission and distribution facilities. These improvements are expected to
meet the needs of new customers and to satisfy changing requirements of existing
customers. No new baseload power plants are currently planned until after the
year 2000.
The CSW System facilities plan presently includes projected coal and
lignite fired generating plants for which the Company has invested approximately
$24 million as of year-end for plant sites, engineering studies and lignite
reserves. As part of an analysis in 1993, the CSW System rejected certain
lignite leases and CPL wrote down its lignite related investment by
approximately $2.9 million. Should future plans exclude these plants for
environmental or other reasons, the Company would evaluate the probability of
recovery of these investments and record appropriate reserves.
Financing and Capital Resources
Internal Generation. Internally generated funds consisting of cash flows
from operating activities less common and preferred stock dividends, provided
approximately one-half of the capital requirements for 1993. It is anticipated
that capital requirements for the period 1994 through 1996 will generally be
provided from internal sources. The Company also anticipates that some external
financing will be required during this period; however, the nature, timing and
extent have not yet been determined.
Long-Term Financing. Long-term financing by the Company involves the sale
of first mortgage bonds, unsecured debt and preferred stock, and the receipt
of capital contributions from its parent company. The goal of the Company is
to provide a strong capital structure. At December 31, 1993, the capitalization
ratios were 47% common stock equity, 9% preferred stock and 44% long-term debt.
On September 30, 1993, the Company filed with the SEC an amendment to a
previously filed registration statement for the sale of first mortgage bonds in
an aggregate amount up to $360 million. The Company intends to offer its first
mortgage bonds subject to market conditions and other factors. The proceeds of
any such offerings will be used principally to reacquire all or a portion of one
or more series of the Company's outstanding first mortgage bonds in order to
lower the Company's embedded cost of long-term debt and to repay short-term
debt. The Company may also use the proceeds to redeem outstanding higher cost
preferred stock.
During 1993, the Company sold $325 million of first mortgage bonds and the
Matagorda County Navigation District Number One (Texas) issued on behalf of the
Company $120 million of tax-exempt PCRBs in order for the Company to refinance
high cost debt with lower cost debt. Summarized below are the Company's 1993
long-term debt activities.
Debt Debt
Issued Reacquired
Series Amount Maturity Series Amount Maturity
(millions) (millions)
(1) DD, 7 1/8% $ 25 1999 (1) K, 8 3/4% $ 25 2000
(1) EE, 7 1/2% 115 2002 (1) N, 9 3/8% 40 2004
(1) P, 8 7/8% 75 2008
(2) FF, 6 7/8% 50 2003 M, 8% 46 2003
GG, 7 1/8% 75 2008 O, 8 1/4% 75 2007
HH, 6% 100 2000 Y, 9 3/4% 150 1998
(2) II, 7 1/2% 100 2023
PCRB, Series PCRB, Series
1993, 6% 120 2028 1984, 10 1/8% 70 2014
(3) Series U
9 3/4% 50 2015
(4) Z, 9 3/8% 8 2019
--- ---
$585 $539
_________________________
(1) Reacquisition occurred in 1993 with proceeds from the issuance of debt in
1992. The funds held for these reacquisitions were reflected on the
December 31, 1992 balance sheet in special deposits.
(2) The proceeds remaining after the reacquisition of debt were used for
general company purposes.
(3) Series U is a first mortgage bond issue which collateralized PCRB, Series
1985A.
(4) Reacquisition occurred with internally generated funds.
The Company reduced its embedded cost of long-term debt from 8.94% in 1992
to 8.43% in 1993 and lowered annual interest expense by $11.0 million as a
result of its debt management activities. The Company continually monitors the
capital markets for opportunities to refund other long-term securities through
refinancings if market conditions permit.
Sale of Accounts Receivable. The Company sells its billed and unbilled
accounts receivable, without recourse, to CSW Credit, Inc., a wholly owned
subsidiary of CSW. The sales provide the Company with cash immediately, thereby
reducing working capital needs and revenue requirements. The average and year-
end amounts of accounts receivable sold were $112.3 million and $105.8 million
in 1993, as compared to $106.7 million and $95.4 million in 1992.
Short-Term Financing. The Company, together with other members of the CSW
System, has established a CSW System money pool to coordinate short-term
borrowings. These loans are unsecured demand obligations at rates approximating
the CSW System's commercial paper borrowing costs. The Company's short-term
borrowing limit from the money pool is $250 million. During 1993, the average
amount of short-term borrowings outstanding at month-end was $87.3 million at
a weighted average interest rate of 3.3%. The maximum amount of short-term
borrowings outstanding at any month-end during 1993 was $171.2 million, which
was the amount outstanding at December 31, 1993.
Accounting Changes
In 1993 the Company adopted SFAS No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions, SFAS No. 112, Employers' Accounting
for Postemployment Benefits (See NOTE 7, BENEFIT PLANS) and SFAS 109, Accounting
for Income Taxes (See NOTE 2, FEDERAL INCOME TAXES). The Company also changed
its method of accounting for unbilled revenues (See NOTE 1, SUMMARY OF
SIGNIFICANT ACCOUNTING POLICIES -- Electric Revenues and Fuel).
Results of Operations
Electric Operating Revenues. Total revenues increased 9.9% in 1993 and 1.3%
in 1992. The 1993 increase reflects higher fuel-related revenues of $88.7
million and greater base revenues of $21.4 million. Fuel-related revenues were
up because of the rise in per unit fuel and purchased power costs, as discussed
below, and because of higher fuel consumption on greater Kwh sales.
Total Kwh sales were up 2.7%, reflecting growth in retail sales of 5.9%,
partially offset by a 33.4% decline in lower margin sales for resale. All of
the Company's retail classes showed increases with residential and commercial
sales growing by 3.8% and 2.3%, respectively. Such growth was mainly due to the
continued increase in number of customers served as well as from 1993's weather,
which was warmer than the mild weather experienced last year. Industrial sales
were up 10.4% on higher demand in the petrochemical and petroleum industries,
where several companies that CPL serves had plant expansions and increased load
requirements. The off-system sales decline was a result of decreased economy
sales, attributable to less available capacity to make such sales as a result
of the outage at STP during the year.
The increase in 1992 revenues over 1991 was primarily due to higher Kwh
sales to lower-margin industrial customers mainly in the petrochemical and
petroleum industries.
Fuel and Purchased Power Expense. The 14.1% increase in fuel expense in
1993 is attributable to an increase in consumption of both gas and coal,
associated with higher generation during the STP outage and the resulting higher
average unit cost of fuel. The rise in per unit fuel costs reflects the higher
per unit cost of gas and coal, which replaced lower cost nuclear fuel during the
STP outage as discussed in LITIGATION AND REGULATORY PROCEEDINGS in ITEM 8.
Purchased power increased $46.9 million in 1993 as a result of increased
purchases to replace STP's generation.
Fuel expense increased in 1992 mainly because of higher fuel consumption
associated with increased generation from greater Kwh sales. Purchased power
was up as a result of increased economy purchases from other power companies
with lower cost generation.
Costs per million Btu by fuel source were:
1993 1992 1991
Gas $2.27 $2.13 $2.03
Coal 2.06 2.06 2.16
Nuclear .57 .54 .55
Total 2.17 1.70 1.73
Other Operating Expenses and Taxes. Other operating expenses increased
$40.5 million in 1993 primarily because of an $16.7 million increase in
operation and administrative and general costs at STP and a $19.5 million
increase in administrative and general expenses other than STP. The higher STP
related costs reflect costs associated with the outage. Administrative and
general costs other than those at STP were higher due to increased pension and
medical costs, which included implementing of SFAS No. 106 Employers' Accounting
for Postretirement Benefits Other Than Pensions. The adoption of this
accounting standard increased 1993 expenses $5.9 million over 1992. Maintenance
expense increased $20.0 million in 1993, due largely to a $17.3 million increase
in maintenance activities at STP associated with the outage. Expenses at STP
are expected to be higher in 1994 than those prior to the outage, but not as
high as experienced in 1993.
The restructuring expenses reflect the one-time cost of the Company's
restructuring as previously discussed. Such expenses include the estimated
costs associated with the early retirement program, severance packages and
relocation. These costs are expected to be recovered through lower expenses by
the end of 1995.
The 1992 decrease in other operating and maintenance expenses was primarily
the result of reduced administrative and general, customer accounting and power
station maintenance expenses.
Depreciation and amortization increased in 1993 and 1992 due mainly to the
addition of distribution facilities. Taxes, other than Federal income,
increased in 1993 mainly as a result of increasing ad valorem taxes. The
increase in 1992 is largely a result of a Texas state franchise tax refund
received in 1991 for prior year taxes and higher ad valorem taxes. For 1992 and
1993, ad valorem taxes increased due to changes in the funding system for public
schools in Texas.
Federal income taxes decreased $12.1 million in 1993 due to lower taxable
income partially offset by the increase in the statutory tax rate from 34% to
35% effective retroactive to January 1, 1993.
Annual inflation rates, as measured by the Consumer Price Index, have
averaged 3.3% for the three-year period ending December 31, 1993. The Company
believes that inflation, at these levels, does not materially affect its results
of operation or financial condition. However, under existing regulatory
practice, only the historical cost of plant is recoverable from customers. As
a result, cash flows designed to provide recovery of historical plant costs may
not be adequate to replace plant in future years.
Mirror CWIP Liability Amortization. The Company is amortizing its Mirror
CWIP liability in declining amounts over a five year period. As a result, $76
million of non-cash earnings was recognized in 1993, a decrease from the $83
million recognized in 1992. The liability will be amortized over the remaining
two years at $68 million in 1994 and $41 million in 1995.
Interest Expense and Preferred Stock Dividends. Total interest expense
decreased 6.5% in 1993. The decrease was due to the Company's refinancing of
higher cost long-term debt with lower cost debt partially offset by increases
in short-term interest and other associated with higher short-term borrowings
to meet working capital needs and increased amortization levels for debt
issuance costs and loss on reacquisition of debt. Preferred dividends decreased
in 1993 and 1992 due to lower dividend rates on money market and auction
preferred stocks and due to the retirement of $6.5 million and $7.1 million of
10.05% Series preferred stock in 1993 and 1992.
Cumulative Effect of Changes in Accounting Principles. In 1993 the
Company changes its method of accounting for unbilled revenues and recorded
unbilled revenues of $29.5 million, net of taxes of $15.9 million, for
electricity used by customers but not yet billed. The Company also adopted SFAS
No. 112, Employers' Accounting for Postemployment Benefits, recognizing $2.2
million, net of taxes of $1.2 million, in additional expense.
Other Matters
Competition and Industry Challenges. The Company's business has been, and
will continue to be affected by various challenges that confront the electric
utility industry generally. The Company currently faces competition for power
sales in the wholesale market. In the future, the Company may face similar
competition for retail sales from other utilities, independent power producers
or alternative sources of electricity or other energy. To date, the Company has
been successful in meeting the competition.
Other industry-wide issues confronting the Company include current and
proposed stringent nuclear, environmental and other regulation and deregulation
as discussed elsewhere in this report. In addition, the Company is continually
seeking to manage costs and rates and focus on new initiatives in order to
maintain its financial strength and reach its financial targets.
Environmental. The operations of the Company, like those of other electric
utilities, generally involves the use and disposal of substances subject to
environmental laws. CERCLA, the federal, "Superfund" law, addresses the cleanup
of sites contaminated by hazardous substances. Superfund requires that PRPs
fund remedial actions regardless of fault or the legality of past disposal
activities. Many states have similar laws. Theoretically, any one PRP can be
held responsible for the entire cost of a cleanup. Typically, however, cleanup
costs are allocated among PRPs.
The Company has been named as a responsible party under federal or state
remedial laws and has either resolved or expects to resolve these claims without
a material adverse effect on the Company. Although the reasons for this
expectation differ from site to site, factors that are the basis for the
expectation for specific sites are the volume and/or type of waste allegedly
contributed by the Company, the estimated amount of costs allocated to the
Company and the participation of other parties.
The Clean Air Amendments of 1990 direct the EPA to issue regulations
governing nitrogen oxide emissions. In addition, these amendments require
government studies to determine what controls, if any, should be imposed on
utilities to control air toxic emissions. The impact that the nitrogen oxide
emission regulations, and the air toxics study, will have on the Company cannot
be determined at this time.
Research is ongoing whether exposure to Electric and Magnetic Fields (EMFs)
may results in adverse health effects or damage to the environment. Although
a few of the studies to date have suggested certain associations between EMFs
and some types of adverse health effects, the research to date has not
established a cause-and-effect relationship between EMFs and adverse health
effects. The Company cannot predict the impact on the Company or the electric
utility industry if further investigations or proceedings were to establish that
the present electricity delivery system is contributing to increased risk or
incidence of health problems.
Consolidated Taxes. The Texas Commission has historically allowed recovery
in rates of an income tax component based on the Federal income tax incurred by
a utility as if it were a stand-alone company. However, in two recent rate
determinations, the Texas Commission reduced another Texas utility's cost of
service tax expense by tax losses of an unregulated affiliated and other items.
The Texas Supreme Court has agreed to review the decision of a court of appeals
which determined that the Texas Public Utility Regulatory Act requires the Texas
Commission to reduce rates by the tax benefit of losses of an unregulated
affiliate.
The Company believes that federal income taxes should be determined on a
stand-alone basis for ratemaking purposes. Presently this issue does not have
a significant effect on the Company
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Statements Of Income
CENTRAL POWER AND LIGHT COMPANY For the Years Ended December 31,
1993 1992 1991
(thousands)
Electric Operating Revenues
Residential $ 474,426 $ 432,295 $ 435,860
Commercial 369,426 342,201 343,437
Industrial 281,247 240,341 221,885
Sales for resale 45,369 50,342 48,834
Other 53,060 48,244 48,714
--------- --------- ---------
1,223,528 1,113,423 1,098,730
--------- --------- ---------
Operating Expenses and Taxes
Fuel 350,268 306,939 303,428
Purchased power 64,025 17,160 15,041
Other operating 225,034 184,514 196,817
Restructuring charges 29,365 - -
Maintenance 81,352 61,399 68,092
Depreciation and amortization 131,825 129,131 127,341
Taxes, other than Federal income 86,394 70,343 62,453
Federal income taxes 65,186 77,272 75,985
--------- --------- ---------
1,033,449 846,758 849,157
--------- --------- ---------
Operating Income 190,079 266,665 249,573
--------- --------- ---------
Other Income and Deductions
Mirror CWIP liability amortization 75,702 82,527 96,671
Other 2,737 1,298 3,590
--------- --------- ---------
78,439 83,825 100,261
--------- --------- ---------
Income Before Interest Charges 268,518 350,490 349,834
--------- --------- ---------
Interest Charges
Interest on long-term debt 112,939 125,476 124,987
Interest on short-term debt and other 10,449 6,503 7,641
--------- --------- ---------
123,388 131,979 132,628
--------- --------- ---------
Income Before Cumulative Effect of
Changes in Accounting Principles 145,130 218,511 217,206
Cumulative Effect of Changes in
Accounting Principles 27,295 - -
--------- --------- ---------
Net Income 172,425 218,511 217,206
Preferred stock dividends 14,003 16,070 19,844
--------- --------- ---------
Net Income for Common Stock $ 158,422 $ 202,441 $ 197,362
========= ========= =========
Statements Of Retained Earnings
For the Years Ended December 31,
1993 1992 1991
(thousands)
Retained Earnings at Beginning of Year $863,988 $854,659 $875,521
Net income for common stock 158,422 202,441 197,362
Deduct: Common stock dividends 172,000 193,000 215,000
Preferred stock redemption costs 103 112 3,224
-------- -------- --------
Retained Earnings at End of Year $850,307 $863,988 $854,659
======== ======== ========
The accompanying notes to financial statements are an integral part of these
statements.
Balance Sheets
CENTRAL POWER AND LIGHT COMPANY As of December 31,
1993 1992
(thousands)
ASSETS
Electric Utility Plant
Production $3,061,911 $3,051,969
Transmission 351,584 329,400
Distribution 765,266 715,633
General 209,170 210,204
Construction work in progress 168,421 94,736
Nuclear fuel 160,326 152,494
---------- ----------
4,716,678 4,554,436
Less - Accumulated depreciation 1,263,372 1,148,348
---------- ----------
3,453,306 3,406,088
---------- ----------
Current Assets
Cash and temporary cash investments 2,435 3,666
Special deposits 1,967 151,589
Accounts receivable 23,850 20,296
Materials and supplies, at average cost 64,359 58,839
Fuel inventory, at average cost 16,934 29,259
Deferred income taxes 4,831 31,289
Unrecovered fuel costs 52,959 -
Prepayments and other 2,255 2,198
---------- ----------
169,590 297,136
---------- ----------
Deferred Charges and Other Assets
Deferred STP costs 489,773 490,458
Mirror CWIP asset 331,845 341,865
Income tax related regulatory assets 266,597 -
Other 70,634 48,113
---------- ----------
1,158,849 880,436
---------- ----------
$4,781,745 $4,583,660
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock, $25 par value, authorized
12,000,000 shares, issued and outstanding
6,755,535 shares $ 168,888 $ 168,888
Paid-in capital 405,000 405,000
Retained earnings 850,307 863,988
---------- ----------
Total Common Stock Equity 1,424,195 1,437,876
---------- ----------
Preferred stock
Not subject to mandatory redemption 250,351 250,351
Subject to mandatory redemption 22,021 28,393
Long-term debt 1,362,799 1,347,887
---------- ----------
Total Capitalization 3,059,366 3,064,507
---------- ----------
Current Liabilities
Long-term debt and preferred stock due
within twelve months 3,928 143,900
Advances from affiliates 171,165 91,766
Accounts payable 79,604 60,392
Accrued taxes 33,769 27,224
Accrued interest 24,683 25,729
Accrued restructuring charges 29,365 -
Other 28,020 31,047
---------- ----------
370,534 380,058
---------- ----------
Deferred Credits
Income taxes 1,057,453 727,953
Investment tax credits 164,322 170,128
Mirror CWIP liability and other 130,070 241,014
---------- ----------
1,351,845 1,139,095
---------- ----------
$4,781,745 $4,583,660
========== ==========
The accompanying notes to financial statements are an integral part of these
statements.
Statements of Cash Flows
CENTRAL POWER AND LIGHT COMPANY For the Years Ended December 31,
1993 1992 1991
(thousands)
OPERATING ACTIVITIES
Net Income $172,425 $218,511 $217,206
Non-cash Items Included in Net Income
Depreciation and amortization 140,223 154,716 148,012
Deferred income taxes and
investment tax credits 84,714 42,773 30,990
Mirror CWIP liability amortization (75,702) (82,527) (96,671)
Restructuring charges 29,365 - -
Cumulative effect of changes in
accounting principles (27,295) - -
Changes in Assets and Liabilities
Accounts receivable (3,554) (6,415) 12,473
Fuel inventory 12,325 (3,137) 1,175
Accounts payable 19,151 6,209 7,057
Accrued taxes (9,311) (2,165) 17,065
Unrecovered fuel costs (57,386) (1,195) 5,001
Other (6,388) (23,020) (23,199)
-------- -------- --------
278,567 303,750 319,109
-------- -------- --------
INVESTING ACTIVITIES
Construction expenditures (177,120) (100,805) (98,199)
Other (1,544) (763) (1,056)
-------- -------- --------
(178,664) (101,568) (99,255)
-------- -------- --------
FINANCING ACTIVITIES
Proceeds from issuance of
long-term debt 441,131 435,497 -
Retirement of long-term debt (431) (405) (168)
Reacquisition of long-term debt (573,776) (304,650) (210)
Retirement of preferred stock (6,578) (7,050) (7,050)
Special deposits for reacquisition
of long-term debt 145,482 (145,482) -
Change in short-term debt 79,399 29,618 21,523
Payment of dividends (186,361) (209,196) (235,674)
-------- -------- --------
(101,134) (201,668) (221,579)
-------- -------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS (1,231) 514 (1,725)
CASH AND CASH EQUIVALENTS AT BEGINNING
OF YEAR 3,666 3,152 4,877
-------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 2,435 $ 3,666 $ 3,152
======== ======== ========
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized $116,664 $130,078 $125,760
Income taxes paid 3,631 45,314 35,715
======== ======== ========
The accompanying notes to financial statements are an integral part of these
statements.
Statements of Capitalization
CENTRAL POWER AND LIGHT COMPANY As of December 31,
1993 1992
(thousands)
COMMON STOCK EQUITY
$1,424,195 $1,437,876
---------- ----------
PREFERRED STOCK
Cumulative $100 Par Value, Authorized 3,035,000 Shares
Number Current
of Shares Redemption
Series Outstanding Price
Not Subject to Mandatory
Redemption
4.00% 100,000 $105.75 10,000 10,000
4.20% 75,000 103.75 7,500 7,500
7.12% 260,000 101.00 26,000 26,000
8.72% 500,000 102.91 50,000 50,000
Auction Money Market 750,000 100.00 75,000 75,000
Auction Series A 425,000 100.00 42,500 42,500
Auction Series B 425,000 100.00 42,500 42,500
Issuance Expense (3,149) (3,149)
-------- --------
250,351 250,351
-------- --------
Subject to Mandatory
Redemption
10.05% 223,750 104.76 22,375 28,850
Issuance Expense (354) (457)
-------- --------
22,021 28,393
-------- --------
LONG-TERM DEBT
First Mortgage Bonds
Series J, 6 5/8%, due January 1, 1998 28,000 28,000
Series L, 7%, due February 1, 2001 36,000 36,000
Series M, 8%, due November 1, 2003 - 46,000
Series O, 8 1/4%, due October 1, 2007 - 75,000
Series T, 7 1/2%, due December 15, 2014 111,700 111,700
Series U, 9 3/4%, due July 1, 2015 31,765 81,700
Series Y, 9 3/4%, due June 1, 1998 - 150,000
Series Z, 9 3/8%, due December 1, 2019 140,000 148,000
Series AA, 7 1/2%, due March 1, 2020 50,000 50,000
Series BB, 6%, October 1, 1997 200,000 200,000
Series CC, 7 1/4%, October 1, 2004 100,000 100,000
Series DD, 7 1/8%, December 1, 1999 25,000 25,000
Series EE, 7 1/2%, December 1, 2002 115,000 115,000
Series FF, 6 7/8%, due February 1, 2003 50,000 -
Series GG, 7 1/8%, due February 1, 2008 75,000 -
Series HH, 6%, due April 1, 2000 100,000 -
Series II, 7 1/2%, due April 1, 2023 100,000 -
Installment Sales Agreements - PCRBs
Series 1974A, 7 1/8%, due June 1, 2004 8,700 8,955
Series 1977, 6%, due November 1, 2007 34,235 34,235
Series 1984, 7 7/8%, due September 15, 2014 6,330 6,330
Series 1984, 10 1/8%, due October 15, 2014 68,870 139,200
Series 1986, 7 7/8%, due December 1, 2016 60,000 60,000
Series 1993, 6%, due July 1, 2028 120,265 -
Notes Payable, 6 1/2%, due December 8, 1995 448 651
Unamortized Discount (12,265) (17,923)
Unamortized Costs of Reacquired Debt (86,249) (49,961)
--------- ---------
1,362,799 1,347,887
--------- ---------
TOTAL CAPITALIZATION $3,059,366 $3,064,507
========= =========
The accompanying notes to financial statements are an integral part of these
statements.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Central Power and Light Company is subject to regulation by the SEC, under
the Holding Company Act, and by the FERC, under the Federal Power Act, and
follows the Uniform System of Accounts prescribed by the FERC. The Company is
subject to further regulation for rates and other matters by the Texas
Commission. The Company, as a member of the CSW System, engages in transactions
and coordinates its activities and operations with other members of the CSW
System. The most significant accounting policies are summarized below.
Electric Utility Plant. Electric utility plant is stated at the original
cost of construction which includes the cost of contracted services, direct
labor, materials, overhead items and allowances for borrowed and equity funds
used during construction.
Depreciation. Provisions for depreciation of utility plant are computed
using the straight-line method generally at individual rates applied to the
various classes of depreciable property. The annual composite rates averaged
3.0% for each of the years 1993, 1992 and 1991.
Nuclear Decommissioning. The Company's portion of the estimated costs of
decommissioning STP is $85 million in 1986 dollars based on a site specific
study completed in 1986. The Company will continue to review and update this
cost estimate and a new study will be completed in 1994. The Company is
recovering decommissioning costs through rates over the 38 year life of STP.
The $4.2 million annual cost of decommissioning is reflected on the income
statement as other operating expense. The funds received from customers
applicable to decommissioning are paid to an irrevocable external trust and as
such are not reflected on the Company's balance sheet. At December 31, 1993,
the trust balance was $15.2 million.
At the end of STP's 38 year life, decommissioning is expected to be
accomplished using the decontamination method, which is one of three techniques
acceptable by the NRC. Using this method the decontamination activities occur
as soon as possible after the end of plant operation. Contaminated equipment
is cleaned or removed to a permanent disposal location and the site is generally
returned to its pre-plant state.
Electric Revenues and Fuel. Prior to January 1, 1993, electric revenues
generally were recorded at the time billings were made to customers on a cycle-
billing basis. Electric service provided subsequent to billing dates through
the end of each calendar month became part of electric revenues of the next
month. To conform to general industry standards the Company in 1993 began
accruing unbilled base revenues for electricity used by customers but not yet
billed. This adjustment was recorded in 1993 as a cumulative effect of a change
in accounting principle. The effect of this change on the Company's net income
for 1993 was an increase of $45.4 million, or $29.5 million net of taxes. If
this change in accounting method was applied retroactively, the effect on net
income for 1992 and 1991 would have been immaterial.
The cost of fuel is charged to expense as consumed. The cost of nuclear
fuel is amortized to fuel expense based on a ratio of the estimated Btu's used
and available to generate electric energy, and includes a provision for the
disposal of spent nuclear fuel.
The Company recovers fuel costs applicable to sales to wholesale customers,
regulated by the FERC, through an automatic fuel adjustment clause.
The Company recovers fuel costs in Texas as a fixed component of base
rates. The difference between fuel revenues billed and fuel expense incurred
is recorded as an addition to or a reduction of revenues, with a corresponding
entry to unrecovered fuel cost or other current liabilities as appropriate.
Over-recoveries of fuel are payable to customers, and under-recoveries may be
billed to customers after Texas Commission approval.
Accounts Receivable. The Company sells its accounts receivable, without
recourse, to CSW Credit, Inc., a wholly owned subsidiary of CSW.
Deferred STP Costs. In accordance with Texas Commission orders, the
Company deferred plant costs for STP Units 1 and 2 incurred subsequent to their
commercial operation dates until retail rates which included the units in rate
base became effective. The deferred plant costs are amortized and recovered
through rates over the life of the plant in increasing amounts. See NOTE 9,
LITIGATION AND REGULATORY PROCEEDINGS for further discussion of the deferred
accounting proceedings.
Mirror CWIP. In accordance with Texas Commission orders, the Company
previously recorded Mirror CWIP, which is being amortized over the life of STP,
as more fully discussed in NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS.
Statements of Cash Flows. Cash equivalents are considered to be highly
liquid debt instruments purchased with a maturity of three months or less.
Accordingly, temporary cash investments and advances to affiliates are
considered cash equivalents.
Reclassification. Certain financial statement items for prior years have
been reclassified to conform to the 1993 presentation.
Accounting Changes. Effective January 1, 1993, the Company adopted SFAS
No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions,
SFAS No. 112, Employers' Accounting for Postemployment Benefits (See NOTE 8,
BENEFITS PLANS), and SFAS No. 109, Accounting for Income Taxes (See NOTE 2,
FEDERAL INCOME TAXES). The Company also changed its method of accounting for
unbilled revenues (See Electric Revenues and Fuel above).
The adoption of SFAS No. 109 had no effect on the Company's results of
operations. The adoption of SFAS No. 112 and the change in accounting for
unbilled revenues are presented as cumulative effect of changes in accounting
principles as shown below:
Pre-Tax Tax Net Income
Effect Effect Effect
(thousands)
SFAS No. 112 $(3,371) $ 1,180 $(2,191)
Unbilled revenues 45,363 (15,877) 29,486
------ ------- ------
Total $41,992 $(14,697) $27,295
====== ======= ======
Pro forma amounts, assuming that the change in accounting for unbilled
revenues had been adopted retroactively, are not materially different from
amounts previously reported for prior years.
2. FEDERAL INCOME TAXES
The Company, together with other members of the CSW System, files a
consolidated Federal income tax return and participates in a tax sharing
agreement.
The Company adopted the provisions of SFAS No. 109, effective January 1,
1993. This standard had no impact on the Company's results of operations.
SFAS No. 109 requires the recognition of deferred tax liabilities for
income customers associated with temporary differences previously passed through
to rate payers and the equity component of allowance for funds used during
construction. In addition, SFAS No. 109 requires reclassification of certain
deferred income tax liabilities to reflect the Company's obligation to reduce
revenue requirements for deferred income taxes provided at rates higher than the
current 35% Federal income tax rate.
As a result, the Company recognized additional accumulated deferred income
taxes and corresponding regulatory assets and liabilities to customers in
amounts equal to future revenues or the reduction in future revenues that will
be required when the income tax temporary differences reverse and are recovered
or settled in rates.
Components of Federal income taxes are as follows:
1993 1992 1991
(thousands)
Included in Operating Expenses
and Taxes
Current $(19,690) $ 34,336 $ 44,832
Deferred 90,682 48,773 36,984
Deferred ITC (5,806) (5,837) (5,831)
------- ------- -------
65,186 77,272 75,985
------- ------- -------
Included in Other Income and
Deductions
Current 736 390 (1,963)
Deferred (162) (163) (163)
------- ------- -------
574 227 (2,126)
------- ------- -------
Tax Effects of Cumulative Effects of
Changes in Accounting Principles 14,697 - -
------- ------- -------
$ 80,457 $ 77,499 $ 73,859
======= ======= =======
Total income taxes differ from the amounts computed by applying the statutory
income tax rates to income before taxes. The reasons for the differences are
as follows:
1993 % 1992 % 1991 %
(dollars in thousands)
Tax at statutory rates $ 88,509 35.0 $100,643 34.0 $ 98,962 34.0
Differences
Amortization of ITC (5,806) (2.3) (5,789) (2.0) (5,789) (2.0)
Mirror CWIP (22,989) (9.1) (24,652) (8.3) (29,463) (10.1)
Prior period
adjustments 19,101 7.6 - - - -
Other 1,642 .6 7,297 2.5 10,149 3.5
------- ---- ------- ---- ------- ----
$ 80,457 31.8 $ 77,499 26.2 $ 73,859 25.4
======= ==== ======= ==== ======= ====
ITC deferred in prior years are included in income over the lives of the
related properties.
The significant components of the net deferred income tax liability are as
follows:
December 31, January 1,
1993 1993
(thousands)
Deferred Tax Liabilities
Property related book/tax
basis differences $ 745,164 $ 640,275
Income tax related regulatory
assets 178,984 172,657
Mirror CWIP asset 116,146 116,234
Deferred STP costs 171,421 166,756
Other 37,989 38,061
--------- ---------
Total Deferred Tax Liabilities $1,249,704 $1,133,983
--------- ---------
Deferred Tax Assets
Income tax related regulatory
liabilities (85,675) (105,370)
Mirror CWIP liability (38,150) (62,799)
Unamortized ITC (57,513) (57,843)
Alternative minimum tax (15,744) (13,402)
--------- ---------
Total Deferred Tax Assets (197,082) (239,414)
--------- ---------
Net Accumulated Deferred Income
Taxes-Total $1,052,622 $ 894,569
========= =========
Net Accumulated Deferred Income
Taxes-Noncurrent $1,057,453 $ 925,858
Net Accumulated Deferred Income
Taxes-Current (4,831) (31,289)
--------- ---------
Net Accumulated Deferred Income
Taxes-Total $1,052,622 $ 894,569
========= =========
3. LONG-TERM DEBT
The mortgage indenture, as amended and supplemented, securing first
mortgage bonds issued by the Company, constitutes a direct first mortgage lien
on substantially all electric utility plant.
Annual Requirements. Certain series of the Company's outstanding first
mortgage bonds have annual sinking fund requirements which are generally one
percent of the greatest amount outstanding at any time of each series of first
mortgage bonds issued. These requirements may be, and have historically been,
satisfied by the application of net expenditures for bondable property in an
amount equal to 166-2/3% of the annual requirements. Series J, L, and Z first
mortgage bonds are subject to this annual sinking fund requirement.
At December 31, 1993, the annual sinking fund requirements exclusive of
maturities, and the annual aggregate maturities including sinking fund
requirements, of long-term debt are as follows:
Annual Sinking Annual Aggregate
Fund Requirements Maturities
(thousands)
1994 2,120 3,299
1995 2,120 3,563
1996 2,120 3,135
1997 2,120 203,155
1998 1,840 30,895
Dividends. The Company's mortgage indenture, as amended and supplemented,
contains certain restrictions on the payment of common stock dividends. At
December 31, 1993, $630 million of retained earnings were available for the
payment of cash dividends to CSW.
Reacquired Long-Term Debt. During 1993, the Company issued first mortgage
bonds, the proceeds of such offerings were used to refinance higher cost debt
in order to lower the embedded cost of long-term debt.
The premiums and reacquisition costs of reacquired long-term debt are
included in long-term debt on the balance sheets and are being amortized over
5 to 35 years. Reference is made to ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, for additional
information on reacquired long-term debt.
Due Within Twelve Months. In December 1992, the Company issued Series DD
and EE first mortgage bonds in the aggregate amount of $140 million to reacquire
Series K, N and P first mortgage bonds in January 1993. Accordingly, at
December 31, 1992, the Company reclassified these bonds totaling $140 million
from long-term debt on the balance sheet to current liabilities, long-term debt
and preferred stock due within twelve months.
4. PREFERRED STOCK
The dividends on the Company's $160 million auction preferred stocks are
adjusted every 49 days, based on current market rates. The dividend rate
averaged 2.7%, 3.6%, and 5.5% during 1993, 1992 and 1991.
The Company's 10.05%, $100 par value preferred stock requires a mandatory
sinking fund sufficient to retire 35,250 shares annually until January 31, 2001,
and a specified number of shares in each 12-month period thereafter. The
sinking fund redemption price is $100 per share. The portion to be retired
within twelve months is reflected as such on the balance sheet under current
liabilities.
Each series of preferred stock, with the exception of the 10.05% Series and
the auction preferred stock, is redeemable at the option of the Company upon 30
days notice at the current redemption price per share. Redemption prices of the
8.72% and 10.05% Series decline at specified intervals in future years. The
10.05% Series is redeemable as of February 1, 1994. The Company's three issues
of auction preferred stock may be redeemed at par on any dividend payment date.
The premiums and reacquisition costs of reacquired preferred stock are
treated as a reduction to retained earnings.
5. SHORT-TERM FINANCING
The Company, together with other members of the CSW System, has established
a money pool to coordinate short-term borrowings through the issuance of CSW's
commercial paper. Money pool borrowings are shown as advances from affiliates
on the balance sheet. At December 31, 1993, the CSW System had bank lines of
credit aggregating $797 million, including the Company's lines of credit, to
back up its commercial paper program. Short-term cash surpluses transferred to
the money pool receive interest income in accordance with the money pool
arrangement.
6. 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
fair value:
Cash, temporary cash investments, special deposits and short-term debt.
The carrying amount approximates fair value because of the short maturity of
those instruments.
Long-term debt. The fair value of the Company's long-term debt is
estimated based on the quoted market prices for the same or similar issues or
on the current rates offered to the Company for the debt of the same or similar
remaining maturities.
Preferred stock subject to mandatory redemption. The fair value of this
preferred stock is estimated based on the quoted market prices for the same or
similar issues or on the current rates offered to the Company for preferred
stock with the same or similar remaining redemption provisions.
The estimated fair values of the Company's financial instruments are as follows:
1993 1992
Carrying Fair Carrying Fair
Amount Value Amount Value
(thousands)
Cash and temporary
cash investments $ 2,435 $ 2,435 $ 3,666 $ 3,666
Special deposits 1,967 1,967 151,589 151,589
Short-term debt 171,165 171,165 91,766 91,766
Long-term debt 1,362,799 1,456,533 1,347,887 1,424,128
Preferred stock subject
to mandatory redemption 22,021 23,086 28,393 29,766
Long-term debt and
preferred stock due
within twelve months 3,928 4,096 143,900 149,632
7. BENEFIT PLANS
Defined Benefit Pension Plan. The Company, together with other members of
the CSW System, maintains a tax qualified, non-contributory defined benefit
pension plan covering substantially all of its employees. Participants in the
plan during 1993 included approximately 2,300 active employees, 1,200 retirees
and beneficiaries and 300 terminated employees with vested benefits. Benefits
are based on employees' years of service, age at retirement and final average
annual earnings with an offset for the participant's primary Social Security
benefit. The CSW System's funding policy is based on actuarially determined
contributions, taking into account amounts deductible for income tax purposes
and minimum contributions required by ERISA. Contributions to the plan for the
years ended December 31, 1993, 1992 and 1991 were $11.0 million, $11.7 million
and $10.1 million, respectively. Pension plan assets consist primarily of
common stocks and short- and intermediate-term fixed income investments.
The components of net periodic pension cost and the assumptions used in
accounting for pensions are as follows:
1993 1992 1991
(thousands)
Net Periodic Pension Cost
Service cost $ 5,228 $ 4,834 $ 4,324
Interest cost on projected
benefit obligation 14,878 13,686 12,072
Actual return on plan assets (18,079) (11,750) (26,785)
Net amortization and deferral 68 (5,330) 12,269
------ ------ ------
$ 2,095 $ 1,440 $ 1,880
====== ====== ======
Assumptions:
Discount rate 7.75% 8.50% 8.50%
Long-term compensation increase 5.46% 5.96% 5.96%
Return on plan assets 9.50% 9.50% 9.50%
As of December 31, 1993 and 1992, the plan's net assets exceeded the total
actuarial present value of accumulated benefit obligations.
Postretirement Benefits Other Than Pensions. The Company adopted SFAS
No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions,
January 1, 1993. The adoption resulted in an increase in operating of $5.9
million for 1993. The Company's accumulated postretirement benefit obligation
was $66.5 million. The transition obligation was $58.0 million and is being
amortized over twenty years. In prior years the Company accounted for these
benefits on a pay-as-you-go basis. Expenses for 1992 and 1991 were $3.8 million
and $3.5 million, respectively. The CSW System's funding policy is based on
actuarially determined contributions taking into account amounts which are
deductible income tax purposes. The Company contributed approximately $8.6
million in 1993.
The components of net periodic postretirement benefit cost and the
assumptions used in accounting for postretirement benefits are as follows:
1993
(thousands)
Net Periodic Postretirement Benefit Cost
Service cost $2,257
Interest cost on accumulated postretirement
benefit obligation 5,505
Actual return on plan assets (249)
Amortization of transition obligation 2,900
Net amortization and deferral (703)
-----
$9,710
=====
Assumptions:
Discount rate 7.75%
Return on plan assets 9.00%
Health Care Cost Trend Rate Assumptions:
Pre-65 Participants: 1993 Rate of 12.50% grading down .75% per year to an
ultimate rate of 6.5% in 2001.
Post-65 Participants: 1993 Rate of 12.00% grading down .75% per year to an
ultimate rate of 6.0% in 2001.
Increasing the assumed health care cost trend rates by one percentage point
in each year would increase the APBO as of December 31, 1993 by $8.8 million and
increase the aggregate of the service and interest cost components of net
postretirement benefits by $1.2 million.
Postemployment Benefits. In November 1992, the Financial Accounting
Standards Board issued SFAS No. 112, Employers' Accounting for Postemployment
Benefits. This statement requires the accrual method of accounting for certain
types of postemployment benefits provided to former or inactive employees after
employment, but before retirement. This new standard requires that the expected
costs of these benefits be accrued during the period employees render service
to qualify for benefits. The most significant costs for the Company are the
continued medical and salary benefits during long-term disability. Effective
January 1, 1993, the Company adopted SFAS No. 112 and the effect of the change
on 1993 income was $2.2 million reflected in cumulative effect of changes in
accounting principles.
Restructuring Charges. The Company recently announced an early retirement
program as a part of the Company's restructuring efforts in order to streamline
operations and reduce future costs. It is anticipated that this restructuring
will affect employee benefit costs incurred by the Company in future periods.
Due to the timing of the implementation of the program, many variables regarding
specific costs cannot be identified until mid-1994. As a result, no adjustments
have been made to the employee benefit cost data presented above.
8. JOINTLY OWNED ELECTRIC UTILITY PLANT
The Company is party to joint ownership agreements with nonaffiliated
entities. Such agreements provide for the joint ownership and operation of STP
consisting of two nuclear generating units. The Company also has a joint
ownership agreement with other members of the CSW System and nonaffiliated
entities to provide for the joint ownership and operation of Oklaunion and its
related facilities. The statements of income reflect the Company's portion
ofoperating costs associated with jointly owned plant in service. At December
31, 1993, the Company had interests in the generating stations and related
facilities as shown below:
STP Oklaunion
(dollars in thousands)
Plant in service $2,340,336 $36,045
Accumulated depreciation $318,101 $7,058
Plant capacity - mw 2,500 676
Participation 25.2% 7.8%
Share of capacity - mw 630 53
9. LITIGATION AND REGULATORY PROCEEDINGS
STP
Introduction. The Company owns 25.2% of STP, a two-unit nuclear power plant
which is located near Bay City, Texas. In addition to the Company, HLP, the
Project Manager, owns 30.8%, San Antonio owns 28.0%, and Austin owns 16.0%. STP
Unit 1 was placed in service in August 1988 and STP Unit 2 was placed in service
in June 1989.
STP Final Orders. In October 1990, the Texas Commission issued a final
order (STP Unit 1 Order) which fully implemented a stipulated agreement filed
in February 1990 to resolve dockets then pending before the Texas Commission.
In December 1990, the Texas Commission issued a final order (STP Unit 2 Order)
which fully implemented a stipulated agreement to resolve all issues regarding
the Company's investment in STP Unit 2.
The STP Unit 1 Order allowed the Company to increase retail base rates by
$144 million. This base rate increase made permanent a $105 million interim
base rate increase placed into effect in March 1990 and a $39 million interim
base rate increase placed into effect in September 1989. The STP Unit 2 Order
provided for a retail base rate increase of $120 million effective January 1,
1991. The STP Unit 1 Order also provided for the deferral of operating expenses
and carrying costs on STP Unit 2. A prior Texas Commission order (see "Deferred
Accounting" below) had authorized deferral of STP Unit 1 costs. Such costs are
being recovered through rates over the remaining life of STP. Also, the STP
Unit 1 Order authorized use of Mirror CWIP, pursuant to which the Company
recognized $360 million of carrying costs as deferred costs, and established a
corresponding liability to customers recorded in Mirror CWIP liability and other
deferred credits on the balance sheets. In compliance with the order, carrying
costs collected through rates during periods when CWIP was included in rate base
were recognized as a loan from customers. The loan is being repaid through
lower rates from 1991 through 1995, which approximates the length of time during
which the carrying costs were collected from customers. The Mirror CWIP
liability is being reduced by the recognition of non-cash income during the
period 1991 through 1995.
The STP Unit 1 and 2 Orders resolved all issues pertaining to the
reasonable original costs of STP and the appropriate amount to be included in
rate base. Pursuant to the Texas Commission orders, the original cost of the
Company's total investment in STP is included in rate base.
As part of the stipulated agreement, the Company has agreed to freeze base
rates from January 1, 1991 through 1994, subject to certain force majeure events
including double-digit inflation, major tax increases, extraordinary increases
in operating expenses or serious declines in operating revenues. The Company
may file for increases in base rates, which would be effective after 1994 and
subject to certain limitations. The fuel portion of customers' bills is subject
to adjustment following the normal review and approval by the Texas Commission.
The stipulated agreements, as discussed above, were entered into by the
Company, the Texas Commission Staff and a majority of intervenors including
major cities in the Company's service territory and major industrial customers.
These intervenors represent a significant majority of the Company's customers.
The Company and the TSA reached agreements, which were subsequently approved by
the Texas Commission Staff and other signatories, whereby TSA agreed not to
oppose the stipulated agreements in any respect, except with regard to deferred
accounting and rate design issues in the STP Unit 1 Order. OPUC and a coalition
of low-income customers declined to enter into the stipulated agreements.
In January 1991, the TSA, OPUC and the coalition of low-income
customers filed appeals of the STP Unit 1 Order in District Court requesting
reversal of the deferred accounting for STP Unit 2 and other aspects of that
order. In March 1991, the TSA, OPUC and the coalition of low-income customers
filed appeals of the STP Unit 2 Order in the District Court requesting reversal
of that order. These appeals are pending before the District Court. If these
orders are ultimately reversed on appeal, the stipulated agreements would be
nullified and the Company could experience a significant adverse effect on its
results of operations. However, the parties to the stipulated agreement, should
it be nullified, are bound to renegotiate and try to reach a revised agreement
that would achieve the same results. Management believes that the STP Unit 1
and 2 Orders will be upheld.
Deferred Accounting. The Company was granted deferred accounting for STP
Unit 1 and 2 costs by Texas Commission orders. These orders allowed the Company
to defer post-in-service operating and maintenance costs, including taxes and
depreciation, and carrying costs until these costs were reflected in retail
rates. Deferred accounting had an immediate positive effect on net income in
the years allowed, but cash earnings were not increased until rates went into
effect reflecting STP in service (see "STP Final Orders" above). The total
deferrals for the periods affected were approximately $492 million with an
after-tax net income effect of approximately $325 million. This total deferral
included approximately $270 million of pre-tax debt carrying costs. Pursuant
to the STP Unit 1 and 2 Orders, the Company's retail rates include recovery of
all STP Unit 1 and 2 deferrals over the remaining life of the plant.
In July 1989, OPUC and the TSA filed appeals of the Texas Commission's
final order in District Court requesting reversal of deferred accounting for STP
Unit 1. In September 1990, the District Court issued a judgment affirming the
Texas Commission's order for STP Unit 1, which was subsequently appealed to the
Court of Appeals by OPUC and the TSA. The hearing of the Company's STP Unit 1
deferred accounting order was combined by the Court of Appeals with similar
appeals of HLP deferred accounting orders.
In September 1992, the Court of Appeals issued a decision that allows the
Company to include STP Unit 1 deferred post-in-service operating and maintenance
costs in rate base. However, the Court of Appeals held that deferred post-in-
service carrying costs could not be included in rate base, thereby prohibiting
the Company from earning a return on such costs.
After the Court of Appeal's denial of each party's motion for rehearing of
the decision, the Company and the Texas Commission in December 1992 filed
Applications for Writ of Error petitioning the Supreme Court of Texas to review
the September 1992 decision denying rate base treatment of deferred post-in-
service carrying costs by the Court of Appeals. Additionally, the TSA and OPUC
filed Applications for Writ of Error petitioning the Supreme Court of Texas to
reverse the Court of Appeal's decision, challenging generally the legality of
deferred accounting for or rate base treatment of any deferred costs. In May
1993, the Supreme Court of Texas granted the Company's application for writ of
error. The Company's case was consolidated with the deferred accounting cases
of El Paso Electric Company and HLP. Oral arguments were heard in September
1993 and the Supreme Court's decision is pending.
If the Company's orders granting deferred accounting were ultimately
reversed and not favorably revised, the Company could experience a material
adverse effect on its results of operations. While management cannot predict
the ultimate outcome of the deferred accounting appeal, management believes the
Company will successfully receive approval of its deferred accounting orders or
will be successful in renegotiation of its rate orders, so that there will be
no material adverse effect on the Company's results of operations or financial
condition.
STP Outage. In February 1993, Units 1 and 2 of STP were shut down by HLP,
the Project Manager, in an unscheduled outage resulting from mechanical problems
relating to two auxiliary feedwater pumps. HLP determined that the units would
not be restarted until the equipment failures had been corrected and the NRC
briefed on the causes of these failures and the corrective actions that were
taken. The NRC formalized that commitment in a confirmatory action letter, and
sent an Augmented Inspection Team to STP to review the matter. In March 1993,
the NRC began a diagnostic evaluation of STP. Conducted infrequently,
diagnostic evaluations are broad-based evaluations of overall plant operations
and are intended to review the strengths and weaknesses of the licensee's
performance and to identify the root cause of performance problems. During and
subsequent to the June 1993 completion of the evaluation, the NRC supplemented
its confirmatory action letter to identify additional issues to be resolved and
verified by the NRC before restart of STP. Such issues included the need to
reduce backlogs of engineering and maintenance work and to simplify work
processes which placed excessive burdens on operating and other plant personnel.
The report also identified the need to strengthen management communications,
oversight and teamwork as well as the capability to identify and correct the
root causes of problems.
The NRC announced in June 1993 that STP was placed on its "watch list" of
plants with "weaknesses that warrant increased NRC attention." Plants on the
watch list are subject to closer NRC oversight. STP will remain on the NRC's
watch list until both units return to service and a period of good performance
is demonstrated.
During the outage, the necessary improvements have been made by HLP to
address the issues in the confirmatory action letter, as supplemented. On
February 15, 1994, the NRC agreed that the confirmatory action letter issues had
been resolved with respect to Unit 1, and that it supported HLP's recommendation
that Unit 1 was ready to restart. Unit 1 restarted in late February 1994 and
operated at low power for three days. The Project Manager then shut down Unit
1 due to a problem with a steam generator feedwater valve and a steam generator
tube leak. The Project Manager expects to make the necessary repairs and
restart Unit 1 in late March 1994, although additional delays may occur.
While many of the corrective actions taken are common to both units, HLP
must demonstrate to the NRC that these issues are also resolved with respect to
Unit 2 before it is restarted. HLP estimates that Unit 2 will restart during
the second quarter of 1994 after the completion of refueling, which began in
March 1993 but was delayed in order to focus on the issues discussed above. The
outage has not affected the Company's ability to meet customer demands because
of existing capacity and the Company's ability to purchase additional energy
from affiliates and nonaffiliates.
During 1993, the NRC imposed a total of $500,000 in fines against HLP in
connection with violations of NRC requirements that occurred prior to the
February 1993 shut down. No fines have been imposed for activities subsequent
to the shut down. The Company has paid its portion (25.2%) of the cost of
fines.
The Company's share of increased non-fuel operation and maintenance costs
in 1993, related to the outage at STP, necessary to effect the needed
improvements were approximately $29 million, and were expensed as incurred.
Included in these expenses were detailed inspections of both units' steam
generators, and the acceleration of certain maintenance activities from 1994 to
1993. This acceleration is expected to eliminate the need for any planned
outages for either unit in 1994. The 1994 budgeted STP non-fuel operation and
maintenance expenses are expected to be significantly lower than the 1993 actual
expenses; but even though lower, they are expected to be sufficient to continue
enhancements that will result in improved long-term performance of STP.
Pursuant to the substantive rules of the Texas Commission, the Company
generally is allowed to recover its fuel costs through a fixed fuel factor.
These fuel factors are in the nature of temporary rates, and the Company's
collection of revenues by such fuel factors is subject to adjustment at the time
of a fuel reconciliation proceeding before the Texas Commission. The difference
between fuel revenues billed and fuel expense incurred is recorded as an
addition to or a reduction of revenues, with a corresponding entry to
unrecovered fuel cost or other current liabilities, as appropriate. Any fuel
costs (not limited to under- or over-recoveries) which the Texas Commission
determines as unreasonable in a reconciliation proceeding are not recoverable
from customers.
During the outage, the Company's fuel and purchased power costs have been,
and are expected to continue to be, increased as the power normally generated
by STP must be replaced through sources with higher costs. It is unclear how
the Texas Commission will address the reasonableness of higher costs associated
with the outage. At January 31, 1993, before the start of the STP outage, the
Company had an over-recovered fuel balance of $5.2 million, exclusive of
interest. At January 31, 1994, the Company's under-recovered fuel balance was
$55.7 million, exclusive of interest. This under-recovery of fuel costs, while
due primarily to the STP outage, was also affected by changes in fuel prices and
timing differences. The Company cannot accurately estimate the amount of any
future under- or over-recoveries due to the unpredictable nature of the above
factors. Although there is the potential for disallowance of fuel-related
costs, such determination cannot be made until fuel costs are reconciled with
the Texas Commission. If a significant portion of fuel costs were disallowed
by the Texas Commission, the Company could experience a material adverse effect
on its results of operations in the year of any disallowance. The Company is
required by Texas Commission's rules to file a reconciliation of its fuel costs
by May 1, 1994. However, the Texas Commission Staff is proposing a revised
filing deadline that would not require the Company to file before the fourth
quarter of 1994.
In July 1993, the Company filed a fuel surcharge petition, which is
separate from a fuel reconciliation proceeding, with the Texas Commission to
comply with the mandatory provisions of the Texas Commission's fuel rules. The
petition requested approval of a customer surcharge to recover under-recovered
fuel and purchased power costs resulting from the STP outage, increased natural
gas costs and other factors. The petition also requested that the Texas
Commission postpone consideration of the surcharge until the STP outage
concluded or at the time fuel costs are next reconciled as discussed above. In
August 1993, a Texas Commission ALJ granted the Company's request to postpone
consideration of the surcharge. In January 1994, the Company updated its fuel
surcharge petition to reflect amounts of under-recovery through November 1993.
Likewise, the Company requested and was granted postponement of the updated
petition until the STP outage concluded or at the time fuel costs are next
reconciled.
Management believes that the operating outage at STP will not have a
material effect on its financial condition or on its results of operations.
Rate Case Filings. During December 1993 and January 1994, several cities
(Cities) in the Company's service territory exercised their rights to require
the Company to file rate cases to determine if its rates are fair, just and
reasonable. The Cities, together, account for approximately 40% of the
Company's base revenues. The governing bodies of these Cities have original
jurisdiction over rates only within their incorporated limits. The Cities have
ordered the Company to file rate cases by various dates from February 17 through
March 18, 1994, with hearings scheduled in February and March 1994.
The Cities have informed the Company that this rate review was precipitated
by the outage at STP leading the Cities to question whether STP should continue
to be included in the Company's rate base. Further, the Cities question whether
the Company is earning an excessive return on equity. In February 1994, a
consultant for the Cities filed its report with the Cities. The consultant
recommended that STP Unit 2 be removed from the Company's rate base, resulting
in a reduction of the Company's total base revenues of $106.5 million. The
consultant did not recommend a reduction in revenues relating to STP Unit 1, nor
did it suggest a revenue reduction for its contention that the Company's
earnings have been excessive, but it suggested that those issues be reserved for
future proceedings if circumstances warrant action. Furthermore, the consultant
made no recommendations concerning STP operation and maintenance expenses.
The Company contends that both units of STP belong in rate base because of
the long-term benefits nuclear generation provides to customers. The Company
is not aware of any Texas Commission precedent directly supporting the removal
of a nuclear plant from rate base because of outages of the duration experienced
by Unit 1 and expected for Unit 2. The Company also believes that its return
on equity is below the level specified for the rate freeze period in accordance
with the stipulated agreement entered into by the Company and parties to its
last rate order, including the Cities. This rate order does not restrict the
Cities from exercising their original jurisdiction over rates during the rate
freeze period. The Texas Commission has appellate jurisdiction over rates set
by municipalities.
In February and early March 1994, some of the Cities passed resolutions
ordering the Company to reduce rates by $73 million, if applied on a total
company basis. These Cities' revenues represent approximately 20% of the
Company's total base revenues. The orders only affect the rates of customers
who take service within these Cities' limits. The orders call for rates to be
reduced in April unless, on appeal, the Texas Commission takes action which
would stay their effectiveness. The Company has appealed these orders to the
Texas Commission seeking the actions necessary to stay their effectiveness. The
Company cannot predict if other cities acting in their capacity as regulatory
authorities will initiate similar proceedings.
In December 1993, a complaint was filed at the Texas Commission by a
customer of the Company who takes service outside of municipal limits, where the
Texas Commission has original jurisdiction. The complaint seeks a review of the
Company's rates due to the outage at STP. The Texas Commission has docketed the
proceeding, but has taken no other action in the matter. In March 1994, the
OPUC and General Counsel petitioned the Texas Commission to review the Company's
rates. Any rate orders which might ultimately be entered as a result of these
filings would affect customers served by the Company in all areas where
individual city regulatory authorities do not have original jurisdiction.
Management cannot predict the ultimate outcome of these rate filings,
although management believes that their ultimate resolution will not have a
material adverse effect on the Company's results of operations or financial
condition.
Westinghouse Litigation. The Company and other owners of STP are
plaintiffs in a lawsuit filed October 1990 in the District Court in Matagorda
County, Texas against Westinghouse, seeking damages and other relief. The suit
alleges that Westinghouse supplied STP with defective steam generator tubes that
are susceptible to stress corrosion cracking. Westinghouse filed an answer to
the suit in March 1992, denying the plaintiff's allegations. The suit is
currently in the discovery phase.
Inspections during the current STP outage have detected early signs of
stress corrosion cracking in tubes at STP Unit 1, but the resulting remedial
measures to date have not resulted in a material expense to the Company.
Management believes that any additional problems would develop gradually and
could be monitored by the operators of STP. An accurate estimate of the costs
of remedying any further problems currently is unavailable due to many
uncertainties, including among other things, the timing of repairs, which may
coincide with scheduled outages, and the recoverability of amounts from
Westinghouse and any insurers. Management believes that the ultimate resolution
of this matter will not have a material adverse effect on the Company's results
of operations.
General. The Company is party to various other legal claims, actions and
complaints arising in the normal course of business. Management does not expect
disposition of these matters to have a material adverse effect on the Company's
results of operations or financial condition.
10. COMMITMENTS AND CONTINGENT LIABILITIES
It is estimated that the Company will spend approximately $187 million for
construction purposes in 1994. Substantial commitments have been made in
connection with the construction program.
To supply a portion of the fuel requirements of its generating plants, the
Company has entered into various commitments for the procurement of fuel.
Nuclear Insurance
In connection with the licensing and operation of STP, the owners have
purchased the maximum limits of nuclear liability insurance, as required by law,
and have executed indemnification agreements with the NRC in accordance with the
financial protection requirements of the Price-Anderson Act.
The Price-Anderson Act, a comprehensive statutory arrangement providing
limitations on nuclear liability and governmental indemnities is in effect
until August 1, 2002. The limit of liability under the Price-Anderson Act for
licensees of nuclear power plants is $9.3 billion per incident effective
February 1994. The owners of STP are insured for their share of this liability
through a combination of private insurance amounting to $200 million and a
mandatory industry-wide program for self-insurance totaling $9.1 billion. The
maximum amount that each licensee may be assessed for each licensed reactor
under the industry-wide program of self-insurance following a nuclear incident
at an insured facility is $75.5 million which may be adjusted for inflation plus
a five percent charge for legal expenses, but not more than $10 million per
reactor for each nuclear incident in any one year. The Company and each of the
other STP owners are subject to such assessments, which the Company and the
other owners have agreed will be borne on the basis of their respective
ownership interests in STP. For purposes of these assessments, STP has two
licensed reactors.
The owners of STP currently maintain on-site decontamination liability and
property damage insurance in the amount of $2.7 billion provided by American
Nuclear Insurers (ANI) and the Nuclear Electric Insurance Limited (NEIL) II
program. Policies of insurance issued by ANI and NEIL II stipulate that policy
proceeds must be used first to pay decontamination and clean-up costs, before
being used to cover direct losses to property. The Company and the other owners
of STP have entered into an agreement that provides for the total cost of
decontamination liability and property insurance for STP (including premiums and
assessments) to be shared pro rata based upon each owner's respective ownership
interests in STP.
The Company purchases, for its own account, business interruption and extra
expense insurance under the NEIL I Business Interruption and/or Extra Expense
Program. This insurance will reimburse the Company for extra expenses incurred,
up to $1.7 million per week, for replacement generation or purchased power as
the result of a covered accident that shuts down production at STP for more than
21 weeks. The maximum amount recoverable for Unit 1 is $103.4 million and for
Unit 2 is $105.9 million. The Company is subject to an additional assessment
up to approximately $2.2 million for the current policy year in the event that
losses as a result of a covered accident at a nuclear facility insured under
NEIL I exceeds the accumulated funds available under the NEIL I Business
Interruption and/or Extra Expense Program.
11. QUARTERLY INFORMATION (UNAUDITED)
The following unaudited quarterly information includes, in the opinion of
management, all adjustments (consisting only of normal recurring adjustments)
necessary for a fair presentation of such amounts:
Electric
Operating Operating Net
Revenues Income Income
Quarter Ended (thousands)
1993
March 31 $240,910 $41,346 $28,598
Adjustment (2,656) (1,753) 25,962
------- ------ ------
March 31 Restated $238,254 $39,593 $54,560
======= ====== ======
June 30 298,863 55,400 42,334
Adjustment 17,190 11,345 11,345
------- ------ ------
June 30 Restated $316,053 $66,745 $53,679
======= ====== ======
September 30 383,087 85,916 75,510
Adjustment 4,103 2,522 2,102
------- ------ ------
September 30 Restated $387,190 $88,438 $77,612
======= ====== ======
December 31 (1) $282,031 $(4,697) $(13,426)
======= ====== ======
1992
March 31 $227,513 $46,838 $34,022
June 30 267,959 60,984 47,527
September 30 338,215 95,474 83,426
December 31 279,736 63,369 53,536
(1) Operating and net income includes the effect of a pre-tax charge of $29
million related to the Company's restructuring as discussed in ITEM 7.
MANAGEMENTS'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS - Restructuring.
Quarterly information for 1993 has been restated to reflect the change in
accounting for unbilled revenues and the adoption of SFAS No. 112, Employers'
Accounting for Postemployment Benefits See NOTE 1, SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES. These changes were made in December 1993, but were
effective January 1, 1993.
Information for quarterly periods is affected by seasonal variations in
sales, rate changes, timing of fuel expense recovery and other factors.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of
Central Power and Light Company:
We have audited the accompanying balance sheets and statements of
capitalization of Central Power and Light Company (a Texas corporation and
wholly owned subsidiary of Central and South West Corporation) as of December
31, 1993 and 1992, and the related statements of income, retained earnings and
cash flows for each of the three years in the period ended December 31, 1993.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits 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 Central Power and Light
Company as of December 31, 1993 and 1992, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
1993, in conformity with generally accepted accounting principles.
In 1993, as discussed in the Notes to the financial statements, the Company
changed its methods of accounting for unbilled revenues, postretirement benefits
other than pensions, income taxes and postemployment benefits.
Our audits were made for the purpose of forming an opinion on the financial
statements taken as a whole. The supplemental schedules V, VI, IX, X and
Exhibit 12 are presented for purposes of complying with the Securities and
Exchange Commission's rules and are not part of the basic financial statements.
These schedules and exhibit have been subjected to the auditing procedures
applied in the audits of the basic financial statements and, in our opinion,
fairly state in all material respects the financial data required to be set
forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen & Co.
Dallas, Texas
February 25, 1994
REPORT OF MANAGEMENT
Management is responsible for the preparation, integrity and objectivity
of the financial statements of Central Power and Light Company as well as all
other information contained in this report. The financial statements have been
prepared in conformity with generally accepted accounting principles applied on
a consistent basis and, in some cases, reflect amounts based on the best
estimates and judgments of management, giving due consideration to materiality.
Financial information contained elsewhere in this report is consistent with that
in the financial statements.
The Company maintains an adequate system of internal controls to provide
reasonable assurance that transactions are executed in accordance with
management's authorization, that financial statements are prepared in accordance
with generally accepted accounting principles and that the assets of the Company
are properly safeguarded. The system of internal controls is documented,
evaluated and tested by the Company's internal auditors on a continuing basis.
Due to the inherent limitations of the effectiveness of internal controls no
internal control system can provide absolute assurance that errors and
irregularities will not occur. However, management strives to maintain a
balance, recognizing that the cost of such a system should not exceed the
benefits derived. No material internal control weaknesses have been reported
to management.
Arthur Andersen & Co. was engaged to audit the financial statements of the
Company and issue a report thereon. Their audit was conducted in accordance
with generally accepted auditing standards. Such standards require an
examination of selected transactions and other procedures sufficient to provide
reasonable assurance that the financial statements are not misleading and do not
contain material errors. The Report of Independent Public Accountants does not
limit the responsibility of management for information contained in the
financial statements and elsewhere in the report.
Robert R. Carey
President and Chief Executive Officer
Melanie J. Richardson
Vice President and Treasurer
David P. Sartin
Controller and Secretary
REPORT OF AUDIT COMMITTEE
The Audit Committee of the Board of Directors is composed of six outside
directors. The members of the Audit Committee are: Robert A. McAllen, Chairman,
Jim L. Peterson, Ruben M. Garcia, H. Lee Richards, Pete Morales, Jr. and S. Loyd
Neal, Jr. The Committee held two meetings during 1993.
The Committee oversees the Company's financial reporting process on behalf
of the Board of Directors. The Committee discusses with the internal auditors
and the independent public accountants the overall scope and specific plans for
their respective audits. The Committee also discusses the Company's financial
statements and the adequacy of internal controls. The Committee meets regularly
with the Company's internal auditors and independent public accountants to
discuss the results of their audits, their evaluations of internal controls, and
the overall quality of the Company's financial reporting. The meetings are
designed to facilitate any private communication with the Committee desired by
the internal auditors or independent public accountants.
Robert A. McAllen
Chairman, Audit Committee
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
CSW common stock amounts in ITEM 11 and ITEM 12 reflect the two-for-one
common stock split, effected by a 100% common stock dividend paid March 6, 1992
to shareholders of record on February 10, 1992.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
(a) The following is a list of directors of the Company, together with
certain information with respect to each of them:
Name, Age, Principal Year
Occupation, Business Experience First Became
and Other Directorships Director
E. R. BROOKS. . . . . . . . . . . . . . . . . . . AGE - 56 1991
Chairman, President and CEO of CSW since February 1991.
President of CSW from September 1990 to February 1991.
President and Chief Operating Officer of CSW from
January 1990 to September 1990 and Executive Vice
President of CSW from 1987 to 1989. Director of CSW
and each of its subsidiaries. Director of Hubbell,
Electric, Inc. and of Baylor University Medical Center,
Dallas, Texas.
ROBERT R. CAREY. . . . . . . . . . . . . . . . . .AGE - 56 1989
President and CEO of the Company since January 1990.
Executive Vice President and Chief Operating Officer
of the Company from 1989 to 1990. Vice President,
Operations of the Company from 1988 to 1989. Director
of Corpus Christi National Bank, Corpus Christi, Texas.
RUBEN M. GARCIA. . . . . . . . . . . . . . . . . .AGE - 62 1981
President or principal of several firms engaged
primarily in construction and land development in the
Laredo, Texas area.
HARRY D. MATTISON (1). . . . . . . . . . . . . . .AGE - 57 1994
Executive Vice President of CSW since September 1990
and Chief Executive Officer of CSWS since December
1993. Chief Operating Officer of CSW from September
1990 to December 1993. President and Chief Executive
Officer of SWEPCO from September 1988 to September 1990.
Director of each of CSW's wholly owned subsidiaries.
ROBERT A. McALLEN. . . . . . . . . . . . . . . . .AGE - 59 1983
Robert A. McAllen Investments, Inc., Weslaco, Texas.
Consultant to First National Bank, Edinburg, Texas.
PETE MORALES, JR. . . . . . . . . . . . . . . . . AGE - 53 1990
President and General Manager of Morales Feed Lots, Inc.,
Devine, Texas. Director of Devine State Bank, Devine, Texas.
S. LOYD NEAL, JR. . . . . . . . . . . . . . . . . AGE - 56 1990
President of Hilb, Rogal and Hamilton Company of Corpus
Christi, an insurance agency, Corpus Christi, Texas.
Name, Age, Principal Year
Occupation, Business Experience First Became
and Other Directorships Director
JIM L. PETERSON. . . . . . . . . . . . . . . . . .AGE - 58 1989
President and CEO of Whataburger, Inc. from 1974 to 1993.
Director of Mercantile Bank of Corpus Christi.
H. LEE RICHARDS. . . . . . . . . . . . . . . . . .AGE - 60 1987
Chairman of the Board of Hygeia Dairy Company, Harlingen,
Texas. Director of Harlingen National Bank, Harlingen,
Texas.
MELANIE J. RICHARDSON. . . . . . . . . . . . . . .AGE - 37 1993
Vice President, Administration and Treasurer of the Company
since 1993. Vice President, Corporate Services and Treasurer
of the Company from 1992 to 1993. Treasurer of the Company
since March 1992. Director of Internal Audits of the Company
1991 to 1992. Manager of Personnel Services of the Company
1990 to 1991. Manager of Financial Audits of the Company 1986
to 1990.
J. GONZALO SANDOVAL. . . . . . . . . . . . . . . .AGE - 45 1992
Vice President, Operations/Engineering of the Company since
1993. Vice President, Regional Operations of the Company
from 1992 to 1993. Vice President, Corporate Services of
the Company from 1991 to 1992. General Manager of the
Southern Region from 1988 to 1991.
B. W. TEAGUE. . . . . . . . . . . . . . . . . . . AGE - 55 1984
Vice President, Marketing and Business Development of
the Company since 1991. Vice President, Corporate
Services of the Company from 1988 to 1991. Senior Vice
President, District Operations of the Company from 1986
to 1988.
GERALD E. VAUGHN. . . . . . . . . . . . . . . . . AGE - 51 1993
Vice President, Nuclear of CSWS since January 1994.
Vice President, Nuclear Affairs of the Company since
July 1993. Vice President for Nuclear Services of
Carolina Power and Light Company, Raleigh, North
Carolina, from 1990 to 1993. Vice President of
Nuclear Operations at HLP from 1987 to 1990.
__________________________
(1) Mr. Mattison was elected to the Board effective February 1, 1994, replacing
Dale E. Ward. Mr. Ward resigned from the Board in January 1994 upon his
transfer to CSWS as Vice President of Production Engineering.
All outside directors have engaged in their respective principal
occupations listed above for a period of more than five years, unless otherwise
indicated.
(b) The following is a list of the executive officers who are not
directors of the Company, together with certain information with respect to each
of them:
Year First
Elected to
Present
Name Age Present Position Position
David P. Sartin 37 Controller and Secretary 1991
__________________________
Each of the directors and executive officers of the Company is elected to
hold office until the first meeting of the Company's Board of Directors after
the 1994 annual meeting of stockholders, presently scheduled to be held on April
14, 1994. Each of the executive officers listed in the table above has been
employed by the Company or an affiliate in the CSW System in an executive or
managerial capacity for at least the last five years except for Mr. Vaughn.
ITEM 11. EXECUTIVE COMPENSATION.
Cash and Other Forms of Compensation
The following table sets forth the aggregate cash and other compensation for
services rendered for the fiscal years of 1993, 1992, and 1991 paid or awarded
by the Company to the Named Executive Officers.
Summary Compensation Table
Annual Compensation Long Term Compensation
Awards Payouts
CSW
Other
CSW Securities
Annual Restricted Underlying All Other
Compen- Stock Options/ LTIP Compen-
Name and Salary Bonus sation Award(s) SARs Payouts sation
Principal Position Year ($) ($)(1) ($)(1)(2) ($)(1)(4) (#) ($) ($)(2)(5)
Robert R. Carey 1993 272,893 32,943 9,548 33,608 - - 27,587
President and CEO 1992 248,384 47,150 5,718 47,151 12,431 - 27,498
1991 223,475 45,092 - 48,116 - - -
Dale E. Ward (6) 1993 143,681 8,407 4,816 8,531 - - 5,920
Vice President, 1992 134,858 10,269 1,339 10,266 3,135 - 5,838
Engineering and 1991 127,717 8,161 - 8,740 - - -
Production
B. W. Teague 1993 128,308 5,085 4,169 5,143 - - 5,309
Vice President, 1992 122,200 9,905 1,885 9,874 3,135 - 5,499
Marketing and 1991 109,665 5,542 - 5,888 - - -
Business Development
J. Gonzalo Sandoval 1993 120,327 7,878 4,963 7,986 - - 4,221
Vice President, 1992 111,107 13,583 27,649 - 2,916 - 3,333
Operations/ 1991 93,650 6,331 - - - - -
Engineering
C. Wayne Stice (7) 1993 119,628 7,664 2,279 - - - 1,049
Assistant to the 1992 112,854 8,403 2,486 - 2,295 - -
President, 1991 106,686 6,792 - - - - -
Corporate Secretary
_________________________
(1)Amounts in this column are paid or awarded in a calendar year for performance
in a preceding year.
(2)The 1991 amounts are omitted pursuant to the transitional provisions in the
revised rules on executive officer and director compensation disclosure adopted
by the SEC.
(3)Amounts of perquisites and other personal benefits are included in this
column only if they exceed the lesser of $50,000 or 10% of the total annual
salary and bonus reported. Each such item that exceeds 25% of the total amount
of perquisites and other personal benefits reported for each Named Executive
Officer is identified below.
Mr. Sandoval was reimbursed $18,745 for moving expenses in 1992.
(4)Grants of restricted stock are administered by the Executive Compensation
Committee of CSW's Board of Directors, which has the authority to determine the
individuals to whom and the terms on which restricted stock grants shall be
made. The awards reflected in this column all have four-year vesting periods
with 20% of the CSW common stock vesting on the first, second and third
anniversary dates of the award and 40% vesting on the fourth such anniversary.
Upon vesting, shares of CSW common stock are issued without restrictions. The
individuals received dividends and may vote shares of restricted stock, even
before such shares have vested. The amount reported in the table represents the
market value of the shares at the date of grant. As of the end of 1993, the
aggregate restricted stock holdings of each of the Named Executive
Officers were:
Restricted Stock Market Value
Name Held at 12/31/93 at 12/31/93
Robert R. Carey 3,963 $119,881
Dale E. Ward 948 28,677
B. W. Teague 726 21,962
J. Gonzalo Sandoval 264 7,986
C. Wayne Stice - -
(5)Amounts shown in this column consist of the annual employer matching payments
to CSW's Thrift Plus Plan. The 1993 and 1992 amounts in this column for Mr.
Carey also includes the average amounts of premiums paid per participant in
those years under CSW's memorial gift program. For 1993, this average
was $17,013. Under this program for certain executive officers, directors and
retired directors from the CSW System, CSW will make a donation in
the participant's name to up to three organizations of an aggregate of
$500,000, payable by CSW upon the participant's death and funded by term
life insurance coverage. Actual premiums paid are based on pooled risks
for groups of participants.
(6) Mr. Ward transferred to CSWS in January 1994.
(7) Mr. Stice retired from the Company in February 1994.
Option/SAR Grants
No grants of CSW common stock options or CSW SARs were made in 1993.
Option/SAR Exercises and Year-End Value Table
Shown below is information regarding CSW common stock option/SAR exercises
during 1993 and unexercised CSW common stock options/SARs at year-end for the
Named Executives Officers.
Aggregated CSW Option/SAR Exercises in 1993
and Fiscal Year-End CSW Option/SAR Value
Number of CSW Securities Value of
Underlying Unexercised Unexercised in the
Value Options/SARs at Year-End Money Options/SARs at
Shares Acquired Realized (#) Exercisable/ Year-End ($)Exercisable/
Name on Exercise (#) ($) Unexercisable Unexercisable (1)
Robert R. Carey - - 5,643 / 8,288 3,527 / 5,180
Dale E. Ward - - 1,045 / 2,090 653 / 1,306
B. W. Teague 1,045 3,004 0 / 2,090 0 / 1,306
J. Gonzalo Sandoval - - 971 / 1,945 607 / 1,216
C. Wayne Stice 500 8,375 1,015 / 1,530 634 / 956
_________________________
(1) Based on the New York Stock Exchange December 31, 1993, closing price of
CSW's common stock of $30.25/share and an exercise price of $29.625/share.
Long-term Incentive Plan Awards Table
The following table shows information concerning awards made to the Named
Executive Officers during 1993 under CSW's Long-Term Incentive Plan ("LTIP"):
Long-Term Incentive Plan Awards Made in 1993
Performance Estimated Future
or Payouts under
Number of CSW Other Period Non-Stock Price Based Plans
Until
Shares, Units or Maturation Threshold Target Maximum
Name Other Rights (#) or Payout ($) ($) ($)
Robert R. Carey 1 2 years - 137,238 205,857
Dale E. Ward 1 2 years - 28,105 42,158
B. W. Teague 1 2 years - 28,105 42,158
J. Gonzalo Sandoval 1 2 years - 28,105 42,158
C. Wayne Stice 1 - - - -
Payouts of the awards are contingent upon CSW's achieving a specified level
of total shareholder return, relative to a peer group of utility companies, for
the three-year period ended December 1995. Such return must also exceed the
average six-month treasury bill rate for the same period in order for any payout
to be made. If the Named Executive Officer's employment is terminated during
the performance period for any reason other than death, total and permanent
disability or retirement, then the award is generally canceled.
The LTIP contains a provision accelerating awards upon a change in control
of CSW. If a change in control of CSW occurs, (a) all options and SARs become
fully exercisable, (b) all restrictions, terms and conditions applicable to all
restricted stock are deemed lapsed and satisfied and (c) all performance units
are deemed to have been fully earned, as of the date of the change in control.
Awards which have been granted and outstanding for less than six months as of
the date of change in control are not then exercisable, vested or earned on an
accelerated basis. The LTIP also contains provisions designed to prevent
circumvention of the above acceleration provisions generally through coerced
termination of an employee prior to the change in control of CSW.
Retirement Plans
Pension Plan Table
Annual Benefits After
Average Compensation Specified Years of Credited Service
20 25 30 or more
$100,000 . . . . . . . . . . . . . . . $ 33,333 $ 41,667 $ 50,000
150,000 . . . . . . . . . . . . . . . 50,000 62,500 75,000
200,000 . . . . . . . . . . . . . . . 66,667 83,333 100,000
250,000 . . . . . . . . . . . . . . . 83,333 104,167 125,000
300,000 . . . . . . . . . . . . . . . 100,000 125,000 150,000
350,000 . . . . . . . . . . . . . . . 116,333 145,833 175,000
Executive officers are eligible to participate in the tax-qualified, CSW
Pension Plan like other employees of the Company. Certain executive officers,
including the Named Executive Officers, are also eligible to participate in the
CSW Special Executive Retirement Plan (SERP), a non-qualified ERISA excess
benefit plan. Such pension benefits depend upon years of credited service, age
at retirement and amount of covered compensation earned by a participant. The
annual normal retirement benefits payable under the pension and the SERP are
based on 1.67% of "average compensation" times the number of years of credited
service (reduced by (i) no more than 50% of a participant's age 55 Social
Security benefit, and (ii) certain other offset benefits).
"Average compensation" means the average covered compensation (salary as
reported in the Summary Compensation Table) during the 36 consecutive months of
highest pay during the 120 months prior to retirement. The combined benefit
levels in the table above, which include both the pension and SERP, are based
on assumed retirement at age 65, the years of credited service shown, continued
existence of the plans without substantial change, and payment in the form of
a single life annuity.
Respective years of credited service and ages, as of December 31, 1993, for
the Named Executive Officers are as follows: Mr. Carey, 26 and 56; Mr. Stice,
30 and 56; Mr. Ward, 21 and 46; Mr. Sandoval, 20 and 45, and Mr. Teague, 30 and
55.
Meetings and Compensation. The Board of Directors held four meetings
during 1993. Directors who are not also executive officers and employees of the
Company or its affiliates receive annual directors' fees of $6,000 for serving
on the Board and a fee of $300 plus expenses for each meeting of the Board or
committee attended.
Those directors who are not also officers of the Company are eligible to
participate in a deferred compensation plan. Under this plan such directors may
elect to defer payment of annual directors' and meeting fees until they retire
from the Board or as they otherwise direct.
Compensation Committee Interlocks and Insider Participation. No person
serving during 1993 as a member of the Executive Compensation Committee of the
Board of Directors of CSW served as an officer or employee of the Company during
or prior to 1993. No person serving during 1993 as an executive officer of the
Company serves or has served on the compensation committee or as a director of
another company, one of whose executive officers serves as a member of the
Executive Compensation Committee of CSW or as a director of the Company.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
All 6,755,535 shares of the Company's outstanding Common Stock, $25 par value,
per share, are owned beneficially and of record by CSW, 1616 Woodall Rodgers
Freeway, Dallas, Texas 75202.
Security Ownership of Management
The following table shows CSW common stock beneficially owned as of
December 31, 1993, by each director, the Named Executive Officers and, as a
group, all directors and executive officers of the Company. Share amounts shown
in this table include restricted stock, options exercisable within 60 days after
year-end shares of CSW common stock credited to Central and South West
Corporation Thrift plan accounts, and all other shares of CSW common stock
beneficially owned by the listed persons. Each person has a sole voting and
investment power with respect to all shares listed in the table below unless
otherwise indicated.
Beneficial Ownership as of December 31, 1993
Name CSW Common Stock
(1)(2)
E. R. Brooks 60,959
Robert R. Carey 10,734
Ruben M. Garcia -
Robert A. McAllen 2,000
Pete Morales, Jr. -
S. Loyd Neal, Jr. 323
Jim L. Peterson -
H. Lee Richards -
Melanie J. Richardson 757
J. Gonzalo Sandoval 6,225
C. Wayne Stice 4,087
B. W. Teague 2,701
Gerald E. Vaughn 500
Dale E. Ward 8,659
All of the above and other
executive officers as a group 99,192
____________________
(1) Included in these amounts for Mr. Brooks, Mr. Carey, Mr. Mattison, Mr.
Stice, Mr. Ward, Mr. Teague and Mr. Sandoval are restricted stock of 7,172,
3,963, 4,708, 0, 948, 726 and 264, respectively. These individuals have
voting power, but not investment power with respect to these shares. The
above shares also include 9,531, 5,643, 6,176, 1,015, 1,045, 0, 971, and
938 shares underlying immediately exercisable options held by Mr. Brooks,
Mr. Carey, Mr. Mattison, Mr. Stice, Mr. Ward, Mr. Teague, Mr. Sandoval and
the directors and executive officers as a group, respectively.
(2) All directors' and executive officers' shares owned as of January 1, 1994,
as indicated are owned directly and aggregate less than one percent of the
outstanding shares of such class.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
Page Reference
(a) Financial Statements (Included under
"ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA"):
Report of Independent Public Accountants. 42
Statements of Income for the years ended 24
December 31, 1993, 1992 and 1991.
Statements of Retained Earnings for the 24
years ended December 31, 1993, 1992 and
1991.
Balance Sheets as of December 31, 1993 25
and 1992.
Statements of Cash Flows for the years 26
ended December 31, 1993, 1992 and 1991.
Statements of Capitalization as of 27
December 31, 1993 and 1992.
Notes to Financial Statements. 28-41
(b) Reports on Form 8-K:
The Company filed a report on Form 8-K dated
March 10, 1994, reporting ITEM 5. OTHER EVENTS
relating to the STP outage and current rate case
proceedings.
(c) Exhibits:
3. (a) Restated Articles of Incorporation, as -
amended, of the Company (incorporated
herein by reference to Exhibit 4(a) to
the Company's Registration Statement No.
33-4897, Exhibits 5 and 7 to Form U-1
File No. 70-7171, Exhibits 5, 8.1, 8.2
and 19 to Form U-1 File No. 70-7472 and
the Company's Form 10-Q for the quarterly
period ended September 30, 1992, ITEM 6,
Exhibit 1).
(b) Bylaws, as amended, of the Company. -
(Incorporated herein by reference
to Exhibit 3(b) to the Company's 1991
Form 10-K, file No. 0-346.)
Page Reference
4. Indenture of Mortgage or Deed of -
Trust dated November 1, 1943,
executed by the Company to The First
National Bank of Chicago and Robert
L. Grinnell, as Trustees, as amended
through October 1, 1977 (incorporated
herein by reference to Exhibit 5.01 in
File No. 2-60712), and the Supplemental
Indentures of the Company dated
September 1, 1978 (incorporated herein
by reference to Exhibit 2.02 in File
No. 2-62271) and December 15, 1984,
July 1, 1985, May 1, 1986 and November 1,
1987 (incorporated herein by reference to
Exhibit 17 to Form U-1 File No. 70-7003,
Exhibit 4(b) in File No. 2-98944, Exhibit
4 to Form U-1 File No. 70-7236 and
Exhibit 4 to Form U-1 File No. 70-7249)
and June 1, 1988, December 1, 1989,
March 1, 1990, October 1, 1992,
December 1, 1992, February 1, 1993 and
April 1, 1993 (incorporated herein by
reference to Exhibit 2 to Form U-1 File
No. 70-7520, Exhibit 3 to Form U-1 File
No. 70-7721, Exhibit 10 to Form U-1 File
No. 70-7735 and Exhibit 10(a), 10(b), 10(c)
and 10(d), respectively, to Form U-1 File
No. 70-8053).
12. Statement re computation of Ratio of 61
Earnings to Fixed Charges for the five
years ended December 31, 1993.
18. Letter from Independent Public Accountants 62
for change in accounting principle.
23. Consent of Independent Public 63
Accountants.
24. (a) Powers of Attorney. 64
(b) Powers of Attorney. 65
(c) Powers of Attorney. 66
Page Reference
(d) Schedules:
Report of Independent Public 42
Accountants on Supplemental Schedules
and Exhibit.
V. Property, Plant and Equipment for the 56
years ended December 31, 1993, 1992
and 1991.
VI. Accumulated Depreciation, Depletion 57
and Amortization of Property, Plant
and Equipment for the years ended
December 31, 1993, 1992 and 1991.
IX. Short-Term Borrowings for the years 58
ended December 31, 1993, 1992 and 1991.
X. Supplementary Income Statement 59
Information for the years ended
December 31, 1993, 1992 and 1991.
All other exhibits and schedules are omitted because of the absence of the
conditions under which they are required or because the required
information is included in the financial statements and related notes to
financial statements.
SIGNATURES
Pursuant to the requirements of Section 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, on March 15, 1994.
CENTRAL POWER AND LIGHT COMPANY
By: David P. Sartin
Controller and Secretary
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 indicated on March 15, 1994.
Signature Title
Robert R. Carey President and CEO and Director
(Principal executive officer)
Melanie J. Richardson Vice President, Treasurer and Director
(Principal financial officer)
David P. Sartin Controller and Secretary
(Principal accounting officer)
*E. R. Brooks Director
*Ruben M. Garcia Director
*Harry D. Mattison Director
*Robert A. McAllen Director
*Pete Morales, Jr. Director
*S. Loyd Neal, Jr. Director
*Jim L. Peterson Director
*H. Lee Richards Director
*J. Gonzalo Sandoval Director
*B. W. Teague Director
*Gerald E. Vaughn Director
*Melanie J. Richardson, by signing her name hereto, does sign this document on
behalf of the persons indicated above pursuant to a power of attorney duly
executed by each such person.
*By: Melanie J. Richardson
Attorney-in-Fact
SCHEDULE V
CENTRAL POWER AND LIGHT COMPANY
PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31
Column A Column B Column C Column D Column E Column F
Balance Other
Beginning Additions Retirements Changes Balance
Classification of Year at Cost at Cost Add/(Deduct) End of Year
(Thousands)
Year 1993
Electric Utility Plant:
Production $3,051,969 $ 9,692 $ 1,040 $ 1,290 $3,061,911
Transmission 329,400 22,190 733 727 351,584
Distribution 715,633 57,940 7,561 (746) 765,266
General 210,204 8,400 4,061 (5,373) 209,170
Construction work
in progress 94,736 73,685 - - 168,421
Nuclear fuel 152,494 7,832 - - 160,326
$4,554,436 $179,739 $13,395 $(4,102) $4,716,678
Year 1992
Electric Utility Plant:
Production $3,043,101 $ 9,703 $ 942 $ 107 $3,051,969
Transmission 329,192 1,655 439 (1,008) 329,400
Distribution 681,905 43,190 9,590 128 715,633
General 209,932 2,769 1,957 (540) 210,204
Construction work
in progress 65,699 29,037 - - 94,736
Nuclear fuel 136,877 15,617 - - 152,494
$4,466,706 $101,971 $12,928 $(1,313) $4,554,436
Year 1991
Electric Utility Plant:
Production $3,020,266 $ 25,019 $ 2,129 $ (55) $3,043,101
Transmission 318,573 10,775 177 21 329,192
Distribution 642,529 46,391 7,013 (2) 681,905
General 206,930 5,451 838 (1,611) 209,932
Construction work
in progress 56,917 8,782 - - 65,699
Nuclear fuel 132,972 3,905 - - 136,877
$4,378,187 $100,323 $10,157 $(1,647) $4,466,706
SCHEDULE VI
CENTRAL POWER AND LIGHT COMPANY
ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31
Column A Column B Column C Column D ColumnE Column F
Additions Charged to
Costs and Expenses Other
Balance Changes Balance
Beginning Depreciation/ Other Add/ End of
Classification of Year Amortization Accounts Retirements(1) (Deduct) Year
(Thousands)
Year 1993
Electric Utility
Plant:
Production $ 638,458 $ 78,595 $ 1,093 $ 1,109 $ - $ 717,037
Transmission 130,317 9,437 - 654 - 139,100
Distribution 222,749 32,101 - 12,644 135 242,341
General 84,871 4,757 5,806 3,992 - 91,442
Nuclear fuel 71,953 - 1,499 - - 73,452
$1,148,348 $124,890 $ 8,398 $18,399 $ 135 $1,263,372
Year 1992
Electric Utility
Plant:
Production $ 559,640 $ 78,342 $ 1,093 $ 617 $ - $ 638,458
Transmission 121,976 9,206 - 815 (50) 130,317
Distribution 206,278 30,323 - 13,931 79 222,749
General 78,168 4,582 3,177 1,773 717 84,871
Nuclear fuel 50,637 - 21,316 - - 71,953
$1,016,699 $122,453 $25,586 $17,136 $ 746 $1,148,348
Year 1991
Electric Utility
Plant:
Production $ 482,524 $ 77,866 $ 1,094 $ 1,844 $ - $ 559,640
Transmission 113,216 9,059 - 299 - 121,976
Distribution 188,883 28,671 - 11,288 12 206,278
General 73,085 4,346 1,920 676 (507) 78,168
Nuclear fuel 32,980 - 17,657 - - 50,637
$ 890,688 $119,942 $20,671 $14,107 $ (495) $1,016,699
________________________
(1) Retirements are at original cost, net of removal costs and salvage.
SCHEDULE IX
CENTRAL POWER AND LIGHT COMPANY
SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31
Column A Column B Column C Column D Column E ColumnF
Maximum Average Weighted
Category of Balance Weighted Amount Amount Average
Aggregate at End Average Outstanding Outstanding Interest
Short-term of Interest at any During Rate During
Year Borrowings Period Rate Month-end the Period the Period
(Thousands)
1993 Advances
from
Affiliates $171,165 3.4% $171,165 $87,319 3.3%
1992 Advances
from
Affiliates $ 91,766 3.7% $107,425 $49,058 4.1%
1991 Advances
from
Affiliates $ 62,148 5.0% $ 69,876 $28,717 6.2%
SCHEDULE X
CENTRAL POWER AND LIGHT COMPANY
SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31
1993 1992 1991
(thousands)
Real estate and personal property taxes $55,255 $41,003 $38,817
State gross receipts taxes 14,173 13,685 13,099
Payroll taxes 8,300 7,288 7,032
Franchise taxes 6,420 6,284 1,265(a)
State utility commission assessments 1,913 1,822 1,784
Other taxes 333 261 456
$86,394 $70,343 $62,453
____________________
(a) A refund of approximately $3.6 million related to prior years was received
in 1991.
The amounts of taxes, depreciation and maintenance charged to accounts
other than income and expense accounts were not significant. Rents, royalties,
advertising and research and development costs during these years were not
significant.
INDEX TO EXHIBITS
Exhibit Transmission
Number Exhibit Method
3(a) Restated Articles of Incorporation, as Incorporated
amended, of the Company (incorporated by Reference
herein by reference to Exhibit 4(a) to
the Company's Registration Statement
No. 33-4897, Exhibits 5 and 7 to
Form U-1 File No. 70-7171, Exhibits 5,
8.1, 8.2 and 19 to Form U-1 File
No. 70-7472 and the Company's Form
10-Q for the quarterly period ended
September 30, 1992, ITEM 6, Exhibit 1).
3(b) Bylaws, as amended, of the Company. Incorporated
(Incorporated herein by reference to by Reference
Exhibit 3(b) to the Company's 1990
Form 10-k, File No. 0-346).
4 Indenture of Mortgage or Deed of Trust Incorporated
dated November 1, 1943, executed by the by Reference
Company to The First National Bank of
Chicago and Robert L. Grinnell, as
Trustees, as amended through October 1,
1977 (incorporated herein by reference
to Exhibit 5.01 in File No. 2-60712), and
the Supplemental Indentures of the
Company dated September 1, 1978
(incorporated herein by reference to
Exhibit 2.02 in File No. 2-62271) and
December 15, 1984, July 1, 1985, May 1,
1986 and November 1, 1987 (incorporated
herein by reference to Exhibit 17 to
Form U-1 File No. 70-7003, Exhibit 4(b)
in File No. 2-98944, Exhibit 4 to
Form U-1 File No. 70-7236 and Exhibit 4
to Form U-1 File No. 70-7249) and June 1,
1988, December 1, 1989, March 1, 1990,
October 1, 1992, December 1, 1992,
February 1, 1993 and April 1, 1993,
(incorporated herein by reference to
Exhibit 2 to Form U-1 File No. 70-7520
and Exhibit 3 to Form U-1 File No.
70-7721, Exhibit 10 to Form U-1 File
No. 70-7725 and Exhibit 10(a), 10(b),
10(c) and 10(d), respectively, to Form
U-1 File No. 70-8053).
12 Statement re computation of Ratio of Electronic
Earnings to Fixed Charges for the five
years ended December 31, 1992.
18 Letter from Independent Public Accountants
for change in accounting principle. Electronic
23 Consent of Independent Public Accountants. Electronic
24(a) Powers of Attorney. Electronic
24(b) Powers of Attorney. Electronic
24(c) Powers of Attorney. Electronic
EXHIBIT 12