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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[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, 1994
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 Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-1443 Central and South West Corporation 51-0007707
(A Delaware Corporation)
1616 Woodall Rodgers Freeway
Dallas, Texas 75202-1234
(214) 777-1000
0-346 Central Power and Light Company 74-0550600
(A Texas Corporation)
539 North Carancahua Street
Corpus Christi, Texas 78401-2802
(512) 881-5300
0-343 Public Service Company of Oklahoma 73-0410895
(An Oklahoma Corporation)
212 East 6th Street
Tulsa, Oklahoma 74119-1212
(918) 599-2000
1-3146 Southwestern Electric Power Company 72-0323455
(A Delaware Corporation)
428 Travis Street
Shreveport, Louisiana 71156-0001
(318) 222-2141
0-340 West Texas Utilities Company 75-0646790
(A Texas Corporation)
301 Cypress Street
Abilene, Texas 79601-5820
(915) 674-7000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
Central and South Common Stock, $3.50 Par New York Stock
West Corporation Value Exchange, Inc.
Chicago Stock
Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
Central Power and Cumulative Preferred
Light Company Stock, $100 Par Value
Public Service Cumulative Preferred
Company of Oklahoma Stock, $100 Par Value
Southwestern Cumulative Preferred
Electric Power Stock, $100 Par Value
Company
West Texas Utilities Cumulative Preferred
Company Stock, $100 Par Value
Indicate by check mark whether the registrants (1) have 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) have been subject to such filing requirements for the past 90
days. Yes X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein, and
will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K[ ].
Aggregate market value of the Common Stock of Central and South
West Corporation at January 31, 1995 held by non-affiliates was
approximately $4.6 billion. Number of shares of Common Stock
outstanding at January 31, 1995: 190,627,949. Central and South West
Corporation is the sole holder of the common stock of Central Power
and Light Company, Public Service Company of Oklahoma, Southwestern
Electric Power Company and West Texas Utilities Company.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Notice of Annual Meeting and Proxy Statement of
Central and South West Corporation dated March 13, 1995 are
incorporated by reference into Part III hereof.
This combined Form 10-K is separately filed by Central and South
West Corporation, Central Power and Light Company, Public Service
Company of Oklahoma, Southwestern Electric Power Company and West
Texas Utilities Company. Information contained herein relating to
any individual registrant is filed by such registrant on its own
behalf. Each registrant makes no representation as to information
relating to the other registrants.
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TABLE OF CONTENTS
PAGE
GLOSSARY OF TERMS.................................... 1-4
PART I
ITEM 1. BUSINESS
General...................................... 1-7
Regulation and Rates......................... 1-12
Nuclear - STP................................ 1-15
Utility Operations........................... 1-17
Operating Statistics......................... 1-24
Construction and Financing................... 1-29
Fuel Supply.................................. 1-30
Environmental Matters........................ 1-37
Non-Utility Operations....................... 1-43
ITEM 2. PROPERTIES................................... 1-47
ITEM 3. LEGAL PROCEEDINGS 1-47
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS ................................... 1-47
PART II
ITEM 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS........................ 2-1
ITEM 6. SELECTED FINANCIAL DATA...................... 2-1
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS................................. 2-2
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.. 2-3
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE..... 2-188
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANTS............................... 3-1
ITEM 11. EXECUTIVE COMPENSATION...................... 3-8
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT..................... 3-17
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS.............................. 3-22
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K....................... 4-1
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GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Form 10-K are
defined below:
Abbreviation or Acronym Definition
ADPCE........................ Arkansas Department of Pollution Control and
Ecology
AECC......................... Arkansas Electric Cooperative Corporation
AECT......................... Association of Electric Companies of Texas
AFUDC........................ Allowance for funds used during construction
ALJ.......................... Administrative Law Judge
AMAX......................... AMAX Coal Company
ANI.......................... American Nuclear Insurance
APBO......................... Accumulated Postretirement Benefit Obligation
APS.......................... Arizona Public Service Company
Arkansas Commission.......... Arkansas Public Service Commission
Austin....................... City of Austin, Texas
Bankruptcy Court............. United States Bankruptcy Court for the Western
District of Texas, Austin Division, before
which the El Paso bankruptcy reorganization
proceeding, Case No. 92-10148-FM, is pending
Bcf.......................... Billion cubic feet
BREMCO....................... Bossier Rural Electric Membership Corporation
Btu.......................... British thermal unit
Burlington Northern.......... Burlington Northern Railroad Company
Cajun........................ Cajun Electric Power Cooperative, Inc.
CEO.......................... Chief Executive Officer
CERCLA....................... Comprehensive Environmental Response,
Compensation and Liability Act of 1980
CFO.......................... Chief Financial Officer
Cimmaron..................... Cimmaron Chemical Company
Cities....................... Several cities in CPL's service territory
Clean Air Act................ Clean Air Act Amendments of 1990
CLECO........................ Central Louisiana Electric Company
Confirmation Date............ December 8, 1993, the confirmation date for the
Modified Plan
COO.......................... Chief Operating Officer
Court of Appeals............. Court of Appeals, Third District of Texas,
Austin, Texas
CPL.......................... Central Power and Light Company, Corpus
Christi, Texas
CSF.......................... Customer Supplied Fuel Program
CSW.......................... Central and South West Corporation, Dallas,
Texas
CSW Common................... CSW common stock, $3.50 par value per share
CSW Communications........... CSW Communications, Inc., Dallas, Texas
CSW Credit................... CSW Credit, Inc., Dallas, Texas
CSWE......................... CSW Energy, Inc., Dallas, Texas
CSWI......................... CSW International, Inc., Dallas, Texas
CSW Leasing.................. CSW Leasing, Inc., Dallas, Texas
CSW System................... CSW and its subsidiaries
CSWS......................... Central and South West Services, Inc., Dallas,
Texas and Tulsa, Oklahoma
CWIP......................... Construction work in progress
Delhi........................ Delhi Gas Pipeline Corporation
DET.......................... Diagnostic Evaluation Team
District Court............... State District Court of Travis County, Texas
DOE.......................... United States Department of Energy
EDE.......................... Empire District Electric Company
Effective Date............... The effective date of the Modified Plan
El Paso...................... El Paso Electric Company
El Paso Common............... El Paso common stock, no par value
Electric Operating Companies. CPL, PSO, SWEPCO and WTU
EMF.......................... Electric and magnetic fields
Energy Policy Act............ National Energy Policy Act of 1992
EPA.......................... United States Environmental Protection Agency
EPS.......................... Earnings per share
ERCOT........................ Electric Reliability Council of Texas
ERISA........................ Employee Retirement Income Security Act of
1974, as amended
EWG.......................... Exempt Wholesale Generators
Exxon........................ Exxon Coal USA, Inc.
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FASB......................... Financial Accounting Standards Board
FERC......................... Federal Energy Regulatory Commission
FMB.......................... First Mortgage Bond
FUSER........................ Fuel Supply Electricity Rider
HLP.......................... Houston Lighting & Power Company, the Project
Manager of STP
Holding Company Act.......... Public Utility Holding Company Act of 1935, as
amended
HVdc......................... High-voltage direct-current
IBEW......................... International Brotherhood of Electrical Workers
INPO......................... Institute of Nuclear Power Operations
ITC.......................... Investment tax credit
KV........................... Kilovolt
KW........................... Kilowatt
KWH.......................... Kilowatt-hour
Las Cruces................... City of Las Cruces, New Mexico
LDEQ......................... Louisiana Department of Environmental Quality
Lone Star.................... Lone Star Gas Company
Louisiana Commission......... Louisiana Public Service Commission
LTIP......................... Long-Term Incentive Plan
Mcf.......................... 1,000 cubic feet
MCPC......................... Mid-Continent Power Company, Inc.
MDEQ......................... Mississippi Department of Environmental Quality
Merger....................... The proposed merger whereby El Paso would
become a wholly owned subsidiary of CSW
Merger Agreement............. Agreement and Plan of Merger between El Paso
and CSW, dated as of May 3, 1993, as amended
MGP.......................... Manufactured gas plant or coal gasification
plant
Mirror CWIP.................. Mirror Construction Work in Progress
MMcf/d....................... Million cubic feet of gas per day
Modified Plan................ Modified Third Amended Plan of Reorganization
for the proposed merger with El Paso
MTN.......................... Medium-term note
MW........................... Megawatt
MWH.......................... Megawatt-hour
Named Executive Officers..... The CEO and the four most highly compensated
executive officers, as defined by regulation
NEIL......................... Nuclear Electric Insurance Limited
New Mexico Commission........ New Mexico Public Utility Commission
Notes........................ Notes to Financial Statements
NRC.......................... Nuclear Regulatory Commission
NTEC......................... Northeast Texas Electric Cooperative, Inc.
O&M.......................... Operations and maintenance
ODEQ......................... Oklahoma Department of Environmental Quality
Oklahoma Commission.......... Corporation Commission of the State of Oklahoma
Oklahoma Supreme Court....... Supreme Court of the State of Oklahoma
Oklaunion.................... Oklaunion Power Station Unit No. 1
OMPA......................... Oklahoma Municipal Power Authority
OPEBs........................ Other Postretirement Employee Benefits
Operating Companies.......... CPL, PSO, SWEPCO, WTU, and Transok
OPUC......................... Office of Public Utility Counsel of Texas
Palo Verde................... Palo Verde Nuclear Generating Station
PCB.......................... Polychlorinated biphenyl
PCRB......................... Pollution Control Revenue Bond
PFD.......................... Proposal for Decision
PFDs......................... Preferred Stock
Project Manager.............. HLP, the Project Manager for STP
PRP.......................... Potentially responsible party
PSO.......................... Public Service Company of Oklahoma, Tulsa,
Oklahoma
PURA......................... Public Utility Regulatory Act of the State of
Texas
Rayburn Country.............. Rayburn Country Electric Cooperative, Inc.
RCRA......................... Federal Resource Conservation and Recovery Act
of 1976.
RESCTA....................... Rural Electric Supplier Certified Territory Act
RFP.......................... Rate Filing Package
San Antonio.................. City of San Antonio, Texas
SALP......................... Systematic Appraisal of Licensee Performance
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SAR.......................... Stock appreciation right
SEC.......................... Securities and Exchange Commission
SERP......................... Special Executive Retirement Plan
SFAS......................... Statement of Financial Accounting Standards
SFAS No. 71.................. Accounting for the Effects of Certain Types of
Regulation
SFAS No. 106................. Employers' Accounting for Postretirement
Benefits Other than Pensions
SFAS No. 109................. Accounting for Income Taxes
SFAS No. 112................. Employers' Accounting for Postemployment
Benefits
SFAS No. 115................. Accounting for Certain Investments in Debt and
Equity Securities
SFAS No. 116................. Accounting for Contributions Received and
Contributions Made
SFAS No. 119................. Disclosure about Derivative Financial
Instruments and Fair Value of Financial
Instruments
SO2.......................... Sulfur dioxide
SPA.......................... Southwestern Power Administration
SPS.......................... Southwestern Public Service Company
Staff........................ The Staff of the Texas Commission
STP.......................... South Texas Project nuclear electric generating
station
STP Unit 1 Order............. October 1990 Texas Commission STP Unit 1 Final
Order
STP Unit 2 Order............. December 1990 Texas Commission STP Unit 2 Final
Order
Supreme Court................ Supreme Court of Texas
SWEPCO....................... Southwestern Electric Power Company,
Shreveport, Louisiana
Texas Commission............. Public Utility Commission of Texas
Texas Court.................. State District Court in Harris County, Texas
TEX/CON...................... TEX/CON Oil and Gas Company
TEX/CON Assets............... Gas gathering, transmission, processing and
marketing assets of TEX/CON Oil and Gas
Company
Tex-La....................... Tex-La Electric Cooperative of Texas, Inc.
TIEC......................... Texas Industrial Energy Consumers
TNRCC........................ Texas Natural Resource Conservation Commission,
formerly the Texas Water Commission
TSA.......................... Texas State Agencies
Transok...................... Transok, Inc. and subsidiaries, Tulsa, Oklahoma
TSCA......................... Toxic Substance Control Act of 1976
TU........................... Texas Utilities Electric Company
USI.......................... Utility Services, Inc.
Westinghouse................. Westinghouse Electric Corporation
WTU.......................... West Texas Utilities Company, Abilene, Texas
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PART I
ITEM 1. BUSINESS.
GENERAL
CSW, CPL, PSO, SWEPCO and WTU
CSW, incorporated under the laws of Delaware in 1925, is a
registered holding company under the Holding Company Act and owns all
of the outstanding shares of common stock of the Operating Companies,
CSWS, CSW Credit, CSWE, CSWI and CSW Communications. In addition,
CSW owns 80% of the outstanding shares of common stock of CSW
Leasing. The corporate predecessors of CSW and the Electric
Operating Companies date back to the 19th century.
The Electric Operating Companies are public utility companies
engaged in generating, purchasing, transmitting, distributing and
selling electricity. The Electric Operating Companies were
incorporated as follows:
State of
Registrant Incorporation Year
CPL Texas 1945
PSO Oklahoma 1913
SWEPCO Delaware 1912
WTU Texas 1927
CPL and WTU operate in portions of south and central west Texas,
respectively. PSO operates in portions of eastern and southwestern
Oklahoma, and SWEPCO operates in portions of northeastern Texas,
northwestern Louisiana and western Arkansas. Transok is an
intrastate natural gas gathering, transmission, processing, storage
and marketing company which transports for and sells natural gas to
the Electric Operating Companies, principally PSO, as well as
processing, transporting and selling natural gas to and for non-
affiliates. CSWS performs, at cost, various accounting, engineering,
tax, legal, financial, electronic data processing, centralized
economic dispatching of electric power and other services for the CSW
System. CSW Credit purchases accounts receivable of the Operating
Companies and unaffiliated electric and gas utilities. CSWE and CSWI
pursue cogeneration projects and other energy ventures within the
United States and internationally. CSW Communications provides
communication services to the Operating Companies and non-affiliates.
CSW Leasing invests in leveraged leases.
CPL
The economic base of the service territory served by CPL
includes manufacturing, metal refining, petroleum products,
agriculture and tourism. In 1994, industrial customers accounted for
approximately 22% of CPL'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.
PSO
The economic base of the territory served by PSO includes
mining, petroleum products, manufacturing and agriculture, which
provides a balanced economy. The principal industries in the
territory include natural gas and oil production, oil refining, steel
processing, maintenance of aircraft, the manufacture of paper and
timber products, glass, chemicals, cement and aircraft components.
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SWEPCO
The economic base of the service territory served by SWEPCO
includes chemical processing, petroleum refining and oil and gas
extraction. The primary metals and paper processing industries add
balance to SWEPCO's industrial base.
WTU
The economic base of the territory served by WTU is
predominantly agricultural, producing cattle, sheep, goats, cotton,
wool, mohair and feed crops. Significant gains have been made in
economic diversification through value added processing of these
products. The natural resources of the territory include oil,
natural gas, sulfur, gypsum and ceramic clays. Important
manufacturing and processing plants served by WTU produce cotton seed
products, oil products, electronic equipment, precision and consumer
metal products, meat products and gypsum products. The territory
also includes several military installations and state correctional
institutions.
Certain information relating to service provided by the Electric
Operating Companies at December 31, 1994 follows:
SERVICE AREA
ESTIMATED APPROXIMATE RETAIL RURAL ELECTRIC
REGISTRANT POPULATION SQUARE MILES CUSTOMERS MUNICIPALITIES COOPERATIVES
CPL 1,969,000 44,000 603,000 1 5
PSO 1,021,000 30,000 470,000 2 1
SWEPCO 887,000 25,000 403,000 2 8
WTU 410,000 53,000 185,000 2 12
CSW SYSTEM 4,287,000 152,000 1,661,000 7 26
The largest cities served by the Electric Operating Companies at
retail are shown below:
CITY CPL PSO SWEPCO WTU
Corpus Christi, Texas 265,000
Laredo, Texas 133,000
McAllen, Texas 88,000
Tulsa, Oklahoma 557,000
Lawton, Oklahoma 89,000
Bartlesville, Oklahoma 44,000
Shreveport/Bossier City,
Louisiana 278,000
Longview, Texas 79,000
Texarkana, Texas and
Arkansas 63,000
Abilene, Texas 112,000
San Angelo, Texas 88,000
In 1994, the CSW System companies contributed the following
percentages to aggregate operating revenues, operating income and net
income for common stock.
TOTAL
CPL PSO SWEPCO WTU ELECTRIC TOK OTHER TOTAL
OPERATING REVENUES 34% 20% 22% 9% 85% 14% 1% 100%
OPERATING INCOME 48% 15% 22% 8% 93% 7% --% 100%
NET INCOME FOR COMMON
STOCK 49% 17% 26% 9% 101% 6% (7)% 100%
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The relative contributions of the CSW System companies to the
aggregate operating revenues, operating income and net income for
common stock differ from year to year due to variations in weather,
fuel costs reflected in charges to customers, timing and amount of
rate changes and other factors, including changes in business
conditions and the results of non-utility businesses. In 1994,
approximately 62% of the CSW System's electric revenues were earned
in Texas, 24% in Oklahoma, 8% in Louisiana and 6% in Arkansas.
Restructuring
In November 1993, CSW undertook a restructuring 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 restructuring is a response to
two major factors, (i) a reduction in the rate of growth in the use
of electricity and (ii) increasing competition among suppliers of
electricity as a result of the Energy Policy Act. As a result of
these changes, CSW believes that the electric utility industry faces
changes in the way all electric utilities do business. The
underlying goal of the restructuring is to enable the Electric
Operating Companies to focus on and be accountable for serving the
customer.
In general, the restructuring is designed to consolidate and
centralize in CSWS certain functions which had been performed
separately by CSW's Electric Operating Companies. In part, the
restructuring shifts certain management functions relating to the
operation of power plants, certain engineering activities and certain
administrative and support functions from the Electric Operating
Companies to CSWS, thereby reducing costs and freeing the Electric
Operating Companies to focus on customer service, marketing and
economic development. The restructuring is intended to standardize
certain practices throughout the CSW System and to streamline
management.
To delineate lines more clearly at the holding company level,
the restructuring aligns CSW management into two principal units, CSW
Electric, covering the CSW System's electric utility operations, and
CSW Enterprises, covering CSW's other businesses, including Transok,
CSWE, CSWI, CSW Communications, and the mergers and acquisitions and
strategic planning departments. CSW Electric and CSW Enterprises are
functional business designations only, not new subsidiaries.
CSW expects to realize a number of benefits from the
restructuring. Beginning in 1994 and continuing into the future,
increased efficiencies and synergies have been, and are expected to
continue to be, realized with the elimination of previously
duplicated functions. This leads to enhanced communication and
efficiency, which should translate into a reduction in the rate of
growth in O&M costs and thereby reduce the need for future rate
increases.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS - Restructuring for further
discussion about the restructuring.
New Business Opportunities
CSW
CSW continues to consider new business opportunities to expand
and enhance its core electric utility business, and to expand its non-
utility business. CSW's investment strategy with respect to non-
utility businesses is to invest in businesses that are related to the
expertise utilized in the core electric utility business. CSW's
principal non-utility businesses are Transok and CSWE. During 1994,
CSW formed a new corporation, CSWI, to pursue independent power
initiatives abroad. In addition, CSW is considering investments in
telecommunications, environmental and energy services. During 1994,
CSW formed CSW Communications to provide a communications network for
the CSW System as well as third-parties. CSW expects to make
additional investments in non-regulated business during 1995. For
additional information, see NON-UTILITY OPERATIONS below.
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Proposed Acquisition of El Paso
CSW
In May 1993, CSW entered into a Merger Agreement pursuant to
which El Paso would emerge from bankruptcy as a wholly-owned
subsidiary of CSW. El Paso is an electric utility company
headquartered in El Paso, Texas, engaged principally in the
generation and distribution of electricity to approximately 262,000
retail customers in west Texas and southern New Mexico. El Paso also
sells electricity under contract to wholesale customers in a number
of locations including southern California and Mexico. El Paso had
filed a voluntary petition for reorganization under Chapter 11 of the
Bankruptcy Code on January 8, 1992.
On July 30, 1993, El Paso filed the Modified Plan and a related
proposed form of Disclosure Statement providing for the acquisition
of El Paso by CSW. On November 15, 1993, all voting classes of
creditors and shareholders of El Paso voted to approve the Modified
Plan. On December 8, 1993, the Bankruptcy Court confirmed the
Modified Plan.
Under the Modified Plan, the total value of CSW's offer to
acquire El Paso is approximately $2.2 billion. The Modified Plan
generally provides for El Paso creditors and shareholders to receive
shares of CSW Common, cash and/or securities of El Paso, or to have
their claims cured and reinstated. The Modified Plan also provides
for claims of secured creditors generally to be paid in full with
debt securities of reorganized El Paso, and for unsecured creditors
to receive a combination of debt securities of reorganized El Paso
and CSW Common equal to 95.5 percent of their claims, and for small
trade creditors to be paid in full with cash. The Modified Plan
provides for El Paso's preferred shareholders to receive preferred
shares of reorganized El Paso, or cash, and for options to purchase
El Paso Common to be converted into options to purchase a
proportionate number of shares of CSW Common. In addition, the
Modified Plan provides for certain creditor classes of El Paso to
accrue interest on their claims and to receive periodic interim
distributions of such interest through the Effective Date or the
withdrawal or revocation of the Modified Plan, subject to certain
conditions and limitations set forth in the Modified Plan. To date,
all such accrued interest payments to creditors have been made by El
Paso on a timely basis. If, under certain circumstances, the Merger
is not consummated, the Merger Agreement provides for CSW to pay El
Paso for a portion of such interim interest payments paid or accrued
prior to the termination of the Merger Agreement. The Merger
Agreement also provides for CSW to pay for a portion of fees and
expenses, including legal expenses of certain El Paso creditors under
such circumstances. CSW's potential exposure as of December 31,
1994, is estimated to be approximately $17.5 million; however, the
actual amount, if any, that CSW may be required to pay pursuant to
these provisions depends on a number of contingencies and cannot
presently be predicted.
The Merger is subject to numerous conditions set forth in the
Merger Agreement, including but not limited to (i) the receipt of
final orders with respect to all required regulatory approvals on
terms that would not cause a regulatory material adverse effect as
defined in the Merger Agreement, (ii) the receipt of all third party
consents, (iii) the absence of a material adverse effect or facts or
circumstances that could reasonably be expected to result in a
material adverse effect on El Paso or the business prospects of El
Paso, (iv) transfer to El Paso of good and marketable title to El
Paso's share of Palo Verde, (v) performance by El Paso, CSW and CSW's
acquisition subsidiary, CSW Sub, Inc., in all material respects of
all covenants contained in the Merger Agreement and (vi) the
occurrence of the Effective Date under the Modified Plan. Required
regulatory approvals and filings in connection with the Merger
include approvals of the FERC, the SEC, the Texas Commission, the New
Mexico Commission, the NRC, and filings with the Department of
Justice and the Federal Trade Commission under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976.
See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, NOTE
11 for CSW, Commitments and Contingent Liabilities, for a discussion
of regulatory approval process relating to El Paso.
CSW continues to use its best efforts to consummate the Merger.
At the same time, however, CSW continues to monitor contingencies
which may preclude the consummation of the Merger, including without
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limitation the potential loss of significant portions of El Paso's
service area and significant El Paso customers, including Las Cruces
and two military installations, Holloman Air Force Base and White
Sands Missile Range, regulatory risks principally related to approval
of the Merger and El Paso's request for a rate increase in Texas as
well as the effects of the conditions imposed by federal or state
regulatory agencies on the approval of the Merger and operating risks
associated with the ownership of an interest in Palo Verde.
Based upon El Paso's written response to the concerns identified
in a September 12 letter from CSW to El Paso and the failure of El
Paso to resolve the contingencies set forth above, CSW cannot predict
whether, or if so when, the Merger will be consummated. In the event
that the proposed Merger is not consummated, there may be ensuing
litigation between El Paso and CSW or among other parties to El
Paso's bankruptcy proceedings and either or both of El Paso and CSW.
See CSW's ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Proposed Acquisition
of El Paso, and CSW's ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA - NOTE 11, Commitments and Contingent Liabilities, for
additional information related to the proposed El Paso merger.
Competition
CSW, CPL, PSO, SWEPCO and WTU
Competitive forces at work in the electric utility industry are
impacting the CSW System and electric utilities generally. Increased
competition facing electric utilities is driven by complex economic,
political and technological factors. These factors have resulted in
legislative and regulatory initiatives that are likely to result in
even greater competition at both the wholesale and retail levels in
the future. As competition in the industry increases, the Electric
Operating Companies will have the opportunity to seek out new
customers and at the same time be at risk of losing customers to
competitors. The Electric Operating Companies believe that their
prices for electricity and the quality and reliability of their
service currently place them in a position to compete effectively in
the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly
alters the way in which electric utilities compete. The Energy
Policy Act creates exemptions from regulation under the Holding
Company Act for EWGs and permits utilities, including registered
holding companies and non-utilities, to form EWGs. EWGs are a new
category of non-utility wholesale power producers that are 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. The Energy Policy Act also
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. A FERC
order requiring a transmitting utility to provide wholesale
transmission service must include provisions generally that permit
(i) the utility to recover from the FERC applicant all of the costs
incurred in connection with the transmission services and (ii) any
enlargement of the transmission system and associated services.
While CSW believes that the Energy Policy Act will continue to make
the wholesale markets more competitive, CSW is unable to predict the
extent to which the Energy Policy Act will impact CSW System
operations.
Wholesale energy markets, including the market for wholesale
electric power, have been extremely competitive since the enactment
of the Energy Policy Act. The Electric Operating Companies compete
in the wholesale energy markets with other public utilities,
cogenerators, qualified facilities, exempt wholesale generators and
others for sales of electric power.
CSW is unable to predict the ultimate outcome or impact of
competitive forces on the electric utility industry or the CSW
System. As the wholesale and retail electricity markets become more
competitive, however, the principal factor determining success is
likely to be price, and to a lesser extent, reliability, availability
of capacity, and customer service.
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CSW, CPL, SWEPCO and WTU
PURA is the legal foundation for electric utility regulation in
Texas. PURA will expire on September 1, 1995, in accordance with the
sunset policy of the Texas Legislature, which applies to all state
agencies, unless the Texas Legislature reenacts PURA in its current
form or in modified form. Several proposals have been made to amend
PURA which, among other things, provide for a market-driven
integrated resource planning process, pricing flexibility for
utilities faced with competitive challenges, incentive regulation and
deregulation of the wholesale bulk power market in ERCOT. CSW is
unable to predict the ultimate outcome of the 1995 session of the
Texas Legislature and in particular whether amendments to PURA will
be adopted.
In Texas, electric service areas are approved by the Texas
Commission. A given tract in a utility's overall service area may be
singly certificated to a utility, to one of several competing
electric cooperatives or to one of the competing municipal electric
systems or, it may be dually or triply certificated to these
entities. These certificated areas have changed only slightly since
the formation of the Texas Commission in 1976.
CSW and CPL
CPL is generally singly certificated to serve inside most
municipalities, and cooperatives are singly certificated to serve
much of the rural areas. The suburban areas are mostly dually
certificated. Since 1990, in dually certificated areas, CPL's rates
have been higher than some competitors for some customers, 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. The
availability of low cost natural gas and other alternative fuels,
including those used in cogeneration facilities, have resulted in
some losses of sales. 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 CPL in most instances. CPL
believes that its rates, the quality and reliability of its service
and the relatively inelastic demand for electricity for certain end
uses should allow it to continue to compete in current retail
markets.
See each of the registrants' ITEM 7 - MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -
Recent Developments and Trends for a discussion of competitive issues
facing the utility industry.
REGULATION AND RATES
Regulation
CSW, CPL, PSO, SWEPCO and WTU
The CSW System is subject to the jurisdiction of the SEC under
the Holding Company Act with respect to the issuance, acquisition and
sale of securities, the acquisition and sale of certain assets or any
interest in any business and accounting practices and other matters.
The Holding Company Act generally limits the operations of a
registered holding company to a single integrated public utility
system, plus such additional businesses as are functionally related
to such system.
The Electric Operating Companies have been classified as public
utilities under the Federal Power Act and accordingly the FERC has
jurisdiction in certain respects over their electric utility
facilities and operations, wholesale rates, and in certain other
matters.
The Electric Operating Companies are subject to the jurisdiction
of various state commissions as to rates, accounting matters,
standards of service and, in some cases, issuance of securities,
certification of facilities and extensions and division of service
territory.
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CPL, SWEPCO and WTU
The Texas Commission has jurisdiction over accounts,
certification of utility service territory, sales 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.
CPL
Ownership of an interest in a nuclear generating unit exposes
CPL and indirectly CSW to regulation not common to a fossil
generating unit. Under the Atomic Energy Act of 1954 and the 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 shut down a unit until compliance is
achieved, depending upon its assessment of the severity of the
situation.
For a discussion of NRC regulation and other considerations
arising from the ownership of nuclear assets, see NUCLEAR-STP, below.
Other
See ENVIRONMENTAL MATTERS below, for information relating to
environmental regulation.
Rates
CSW, CPL, PSO, SWEPCO and WTU
The retail rates of the Electric Operating Companies are subject
to regulation by the state utility commissions in the states in which
they operate.
CPL, SWEPCO and WTU
The Texas Commission has original jurisdiction over retail rates
in the unincorporated areas of Texas. The governing bodies of
incorporated municipalities have original 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.
PSO
PSO is subject to the jurisdiction of the Oklahoma Commission
with respect to retail prices, accounts, issuance of certain
securities and certain other matters.
Pursuant to authority granted under RESCTA, the Oklahoma
Commission established service territorial boundary maps in all
unincorporated areas for all regulated retail electric suppliers
serving Oklahoma. In accordance with RESCTA, a retail electric
supplier may not extend retail electric service into the certified
territory of another supplier, except to serve its own facilities or
to serve a new customer with an initial full load of 1,000 KW or
more. RESCTA provides that when any territory certified to a retail
electric supplier or suppliers is annexed and becomes part of an
incorporated city or town, the certification becomes null and void.
However, once established in the annexed territory, a supplier may
generally continue to serve within the annexed area.
SWEPCO
In Arkansas, SWEPCO is subject to the jurisdiction of the
Arkansas Commission as to rates, accounts, standards of service, sale
or acquisition of certain utility property and issuance of securities
by liens on property located in that state. In Louisiana, SWEPCO is
subject to the jurisdiction of the Louisiana Commission as to rates,
accounts and standards of service, but not as to the issuance of
securities. In Oklahoma, SWEPCO is subject to the jurisdiction of
the Oklahoma Commission only as to the issuance of evidences of
indebtedness secured by liens on property located in that state.
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SWEPCO has agreements, which have been approved by the FERC,
with all of its wholesale customers under which rates are based upon
an agreed cost of service formula. These rates are adjusted
periodically to reflect the actual cost of providing service. All of
SWEPCO's contracts with its wholesale customers contain FERC approved
fuel-adjustment provisions that permit it to pass actual fuel costs
through to its customers.
Fuel Recovery in Texas
CSW, CPL, SWEPCO and WTU
Electric utilities in Texas, including CPL, SWEPCO and WTU, 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 that became
effective on May 1, 1993, subject to certain transition rules,
whereby each utility under its jurisdiction may petition to revise
its fuel factor every six months according to a specified schedule.
Fuel factors may also be revised in the case of emergencies 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. To date, the new fuel rule has not
significantly changed the manner in which the Electric Operating
Companies recover retail fuel costs in Texas. Fuel factors are in
the nature of temporary rates and the utility's collection of
revenues by such factors is subject to adjustments at the time of a
fuel reconciliation. Under the procedures, at the utility's semi-
annual adjustment date, a utility will be 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. 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 is 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 that
are determined unreasonably incurred in a reconciliation proceeding
are not recoverable from retail customers.
Fuel Recovery in Oklahoma
CSW and PSO
All KWH sales to PSO's retail customers for 1994 were made under
rates which include a fuel cost adjustment clause. Oklahoma law
requires that an examination of PSO's retail fuel cost adjustment
clause be performed annually by the Oklahoma Commission. The fuel
cost adjustment is computed for each month on the basis of the
average cost of fuel consumed in the month. The amount of any
difference in such cost over or under a base rate is applied on a KWH
basis and reflected in adjustments to customers' bills during the
second month subsequent to the month in which the difference
occurred.
The FUSER program for qualified commercial and industrial
customers and the CSF program, for qualified wholesale customers,
were developed to allow program participants to purchase natural gas
directly from suppliers, at negotiated prices, to be delivered to and
burned in PSO's gas-fired power plants, resulting in reduced prices
because of the low cost spot gas fuel provided. Under these programs
participants could deliver sufficient quantities of natural gas to
meet 70% of their generation requirements with the remaining 30% met
with PSO-supplied coal. The FUSER and CSF programs resulted in lower
electric costs to all classes of PSO's customers. The FUSER program
was canceled effective October 1, 1993 because changing market and
supply conditions eliminated the economic viability of the program.
The CSF program remains in place although no customers participated
in the program during 1994.
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Fuel Recovery in Louisiana and Arkansas
CSW and SWEPCO
SWEPCO's retail rates currently in effect in Louisiana are
adjusted based on SWEPCO's cost of fuel in accordance with a fuel
cost adjustment which is applied to each billing month based on the
second previous month's average cost of fuel. Provision for any over-
or under-recovery of fuel costs is allowed under an automatic fuel
clause.
Under SWEPCO's fuel adjustment rider currently in effect in
Arkansas, the fuel cost adjustment is applied for each billing month
on a basis which permits SWEPCO to recover the level of fuel cost
experienced two months earlier.
Fuel Recovery from Wholesale Customers
CSW, CPL, PSO, SWEPCO and WTU
All of the Electric Operating Companies' contracts with their
wholesale customers contain FERC approved fuel-adjustment provisions
for recovery of fuel costs.
Other
CSW, CPL, PSO, SWEPCO and WTU
In the event that the Electric Operating Companies do not
recover all of their fuel costs under the procedures described above,
such event could have a material adverse effect on the companies'
results of operations and financial condition.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS for CSW, CPL, PSO, SWEPCO and
WTU, and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - NOTE
10, for CSW, NOTE 9 for CPL, SWEPCO, and WTU and NOTE 8 for PSO,
Litigation and Regulatory Proceedings, for further information with
respect to rate proceedings including CPL's rate case and fuel
reconciliation proceedings, PSO's rate proceedings, SWEPCO's fuel
reconciliation proceedings, WTU's rate matters and fuel
reconciliation and CPL's and WTU's deferred accounting matters.
NUCLEAR - STP
CSW and CPL
CPL owns 25.2% of STP, a two-unit nuclear power plant which is
located near Bay City, Texas. In addition, 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 Outage
From February 1993 until May 1994 STP experienced an unscheduled
outage which has resulted in significant rate and regulatory
proceedings involving CPL.
Nuclear Decommissioning
At the end of STP's service life, decommissioning is expected to
be accomplished using the decontamination method, which is one of the
techniques acceptable to the NRC. Using this method the
decontamination activities occur as soon as possible after the end of
plant operations. Contaminated equipment is cleaned or removed to a
permanent disposal location and the site is generally returned to its
pre-plant state.
CPL's decommissioning costs are accrued and funded to an
external trust over the expected service life of the STP units. The
existing NRC operating licenses will allow the operation of STP Unit
1 until 2027, and Unit 2 until 2028. The accrual is an annual level
cost based on the estimated future cost to decommission STP,
including escalations for expected inflation to the expected time of
decommissioning and is net of expected earnings on the trust fund.
1-16
Deferred Accounting
CPL was granted deferred accounting for STP Unit 1 and 2 costs
by Texas Commission orders. These orders allowed CPL 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 CSW's and CPL's ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - NOTE 10 for CSW and
NOTE 9 for CPL, Litigation and Regulatory Proceedings, for further
information with respect to CPL's rate case and fuel reconciliation
proceedings, nuclear decommissioning and deferred accounting.
Other
See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - NOTE
11 for CSW and NOTE 10 for CPL, Commitments and Contingent
Liabilities for further information related to nuclear insurance for
STP.
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UTILITY OPERATIONS
Facilities
At December 31, 1994, the Electric Operating Companies owned
electric generating plants, or portions thereof in the case of
jointly-owned plants, with the following net dependable summer rating
capabilities, substantially all of which were steam electric and
which were located in the cities indicated:
Net Dependable
Capability
Plant Name and Location Principal Fuel (MW) (b)
Source (a)
CSW and CPL
Barney M. Davis, Corpus Christi, Gas 679
Texas
Coleto Creek, Goliad, Texas Coal 604
Lon C. Hill, Corpus Christi, Texas Gas 549
Nueces Bay, Corpus Christi, Texas Gas 512 (c)
Victoria, Victoria, Texas Gas 258 (c)
La Palma, San Benito, Texas Gas 203 (c)
E.S. Joslin, Point Comfort, Texas Gas 252
J. L. Bates, Mission, Texas Gas 182
Laredo, Laredo, Texas Gas 172
Eagle Pass, Eagle Pass, Texas Hydro 6
Oklaunion, Vernon, Texas (b) Coal 53 (d)
STP, Bay City, Texas (b) Nuclear 630 (e)
CPL Total 4,100 (c)
CSW and PSO
Comanche, Lawton, Oklahoma Gas 258
Oil 4
Northeastern, Oologah, Oklahoma Gas 632
Coal 924
Oil 4
Riverside, Jenks, Oklahoma Gas 922
Oil 3
Southwestern, Washita, Oklahoma Gas 475
Oil 2
Tulsa, Tulsa, Oklahoma Gas 162 (c)
Oil 8
Weleetka, Weleetka, Oklahoma Gas 151
Oil 4
Oklaunion, Vernon, Texas (b) Coal 106 (d)
PSO Total 3,655 (c)
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(Continued) Net Dependable
Capability
Plant Name and Location Principal Fuel (MW) (b)
Source (a)
CSW and SWEPCO
Arsenal Hill, Shreveport, Gas 113
Louisiana
Lieberman, Mooringsport, Louisiana Gas 276
Knox Lee, Cherokee Lake, Texas Gas 501
Lone Star, Daingerfield, Texas Gas 50
Wilkes, Jefferson, Texas Gas 879
Welsh, Cason, Texas Coal 1,584
Flint Creek, Gentry, Arkansas (b) Coal 240
Henry W. Pirkey, Hallsville,
Texas (b) Lignite 559
Dolet Hills, Mansfield, Texas (b) Lignite 262
SWEPCO Total 4,464
CSW and WTU
Abilene, Abilene, Texas Gas 18
Paint Creek, Haskell, Texas Gas 237
Lake Pauline, Quanah, Texas Gas 46
Oak Creek, Bronte, Texas Gas 87
San Angelo, San Angelo, Texas Gas 125
Rio Pecos, Girvin, Texas Gas 140
Fort Phantom, Abilene, Texas Gas (f) 362
Presidio, Presidio, Texas Oil 2
Ft. Stockton, Ft. Stockton, Texas Gas 5
Vernon, Vernon, Texas Oil 9
Oklaunion, Vernon, Texas (b) Coal 370 (d)
WTU Total 1,401
CSW 13,620
Plant in storage 557
CSW Total 14,177
Facilities Notes
CSW, CPL, PSO, SWEPCO and WTU
(a)Some plants have the capability of burning oil in combination
with gas. Use of oil in facilities primarily designed to burn
gas results in increased maintenance expense and a reduction of
approximately from 5% to 15% in capability. PSO and WTU have 25
MW and 11 MW, respectively, of facilities primarily designed to
burn oil.
(b)Data reflects only CSW System's portion of plants which are
jointly owned with non-affiliates.
(c)Excludes units in storage - 34 MW at Nueces Bay, 228 MW at
Victoria, 48 MW at La Palma for CPL and 247 MW at Tulsa for PSO.
(d)CPL owns 7.81%, PSO owns 15.62% and WTU owns 54.69% of the 676 MW
unit. The plant is operated by WTU.
(e)CPL owns 25.2% of the two 1,250 MW units operated by HLP.
(f)Although both Fort Phantom units burn primarily gas, Unit 1 is
designed to burn fuel oil for extended periods of time before
maintenance is required and Unit 2 is designed to burn fuel oil
on a continuous basis.
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Plants and Properties
CSW, CPL, PSO, SWEPCO and WTU
All of the generating plants described above are located on
land owned by the Electric Operating Companies or jointly with other
participants in the case of jointly owned plants. The Electric
Operating Companies' electric transmission and distribution
facilities are mostly located over or under highways, streets and
other public places or property owned by others, for which permits,
grants, easements or licenses (which the Electric Operating
Companies believe to be satisfactory, but without examination of
underlying land titles) have been obtained. The principal plants
and properties of the Electric Operating Companies are subject to
the liens of the first mortgage indentures under which the Electric
Operating Companies' bonds are issued.
Peak Loads and System Capabilities of the Electric Operating
Companies
CSW, CPL, PSO, SWEPCO and WTU
The following tables set forth for the last three years (i) the
net system capability, including the net amounts of contracted
purchases and contracted sales, at the time of peak demand, (ii) the
maximum coincident system demand on a one-hour integrated basis,
exclusive of sales to other electric utilities, and (iii) the
respective amounts and percentages of peak demand generated by the
Electric Operating Companies and net purchases and sales:
CSW 1994 1993 1992
NET SYSTEM CAPABILITY (MW) 13,549(3) 13,163(1)(2)(3) 13,230(1)(3)
MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 11,434 11,464 10,606
PERCENTAGE INCREASE (DECREASE) IN PEAK
DEMAND OVER PRIOR PERIOD (0.3)% 8.1% 3.9%
GENERATION AT TIME OF PEAK (MW) 11,353 10,624 10,426
PERCENT OF PEAK DEMAND GENERATED 99.3% 92.7% 98.3%
NET PURCHASES (SALES) AT TIME OF
PEAK (MW) 81 840 180
PERCENT OF NET PURCHASES (SALES) AT
TIME OF PEAK .7% 7.3% 1.7%
DATE OF MAXIMUM COINCIDENT SYSTEM
DEMAND JUNE 27 AUGUST 18 AUGUST 10
(1) CSW's 1993 net system capability at the time of peak demand was
less than 1992 net system capability due to unit outages.
(2) Does not include 630 MW of STP capability that was not available
at the 1993 peak due to the outage described in ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA - NOTE 10 for CSW, Litigation and
Regulatory Proceedings and NUCLEAR - STP, in ITEM 1.
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(3) Does not include 881 MW of system capability for 1994, 719 MW of
system capability for 1993 and 1992.
CPL 1994 1993 1992
NET SYSTEM CAPABILITY (MW) 3,969(2) 3,850(1)(2) 4,165(2)
MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 3,732 3,518 3,347
PERCENTAGE INCREASE (DECREASE) IN PEAK
DEMAND OVER PRIOR PERIOD 6.1% 5.1% 1.7%
GENERATION AT TIME OF PEAK (MW) 3,074 2,943 3,003
PERCENT OF PEAK DEMAND GENERATED 82.4% 83.7% 89.7%
NET PURCHASES (SALES) AT TIME OF PEAK (MW) 658 575 344
PERCENT OF NET PURCHASES (SALES) AT TIME
OF PEAK 17.6% 16.3% 10.3%
DATE OF MAXIMUM COINCIDENT SYSTEM DEMAND AUGUST 18 AUGUST 25 AUGUST 11
(1) Does not include 630 MW of STP capability that was not available
at the 1993 peak due to the outage described in ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA - NOTE 9 for CPL, Litigation and
Regulatory Proceedings and NUCLEAR - STP, in ITEM 1.
(2) Does not include 310 MW of system capability in storage as
described above under the heading UTILITY OPERATIONS - Facilities.
PSO 1994 1993 1992
NET SYSTEM CAPABILITY (MW) 3,664(1) 3,649(1) 3,721(1)
MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 3,167 3,147 3,010
PERCENTAGE INCREASE (DECREASE) IN PEAK
DEMAND OVER PRIOR PERIOD 0.6% 4.6% (2.3)%
GENERATION AT TIME OF PEAK (MW) 2,645 2,609 2,788
PERCENT OF PEAK DEMAND GENERATED 83.5% 82.9% 92.6%
NET PURCHASES (SALES) AT TIME OF PEAK (MW) 522 538 222
PERCENT OF NET PURCHASES (SALES) AT TIME
OF PEAK 16.5% 17.1% 7.4%
DATE OF MAXIMUM COINCIDENT SYSTEM DEMAND JUNE 27 AUGUST 18 AUGUST 10
(1) Does not include 247 MW of system capability for 1994, and 409
MW of system capability for 1993 and 1992 in storage, as described
above under the heading UTILITY OPERATIONS - Facilities.
SWEPCO 1994 1993 1992
NET SYSTEM CAPABILITY (MW) 4,464(1) 4,436 3,959
MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 3,526 3,651 3,237
PERCENTAGE INCREASE (DECREASE) IN PEAK
DEMAND OVER PRIOR PERIOD (3.4%) 12.8% 1.2%
GENERATION AT TIME OF PEAK (MW) 3,987 3,559 3,292
PERCENT OF PEAK DEMAND GENERATED 113.1% 97.5% 101.7%
NET PURCHASES (SALES) AT TIME OF PEAK (MW) (461) 92 (55)
PERCENT OF NET PURCHASES (SALES) AT TIME
OF PEAK (13.1%) 2.5% (1.7)%
DATE OF MAXIMUM COINCIDENT SYSTEM DEMAND JUNE 27 AUGUST 18 AUGUST 10
(1) Does not include 324 MW of capability that was not available at
the 1994 peak.
WTU 1994 1993 1992
NET SYSTEM CAPABILITY (MW) 1,459 1,384 1,404
MAXIMUM COINCIDENT SYSTEM DEMAND (MW) 1,262 1,201 1,118
PERCENTAGE INCREASE (DECREASE) IN PEAK
DEMAND OVER PRIOR PERIOD 5.1% 7.4% 1.9%
GENERATION AT TIME OF PEAK (MW) 1,401 1,223 1,151
PERCENT OF PEAK DEMAND GENERATED 111.0% 101.8% 102.9%
NET PURCHASES (SALES) AT TIME OF PEAK (MW) (139) (22) (33)
PERCENT OF NET PURCHASES (SALES) AT TIME
OF PEAK (11.0%) (1.8%) (2.9)%
DATE OF MAXIMUM COINCIDENT SYSTEM DEMAND JUNE 27 AUGUST 11 JULY 1
Power Purchases and Sales
CSW, CPL, PSO, SWEPCO and WTU
Various municipalities, electric cooperatives and public power
authorities are served by the Electric Operating Companies. The
Electric Operating Companies exchange power on an emergency or
economy basis with various neighboring systems and engage in economy
interchanges with each other. In addition, they contract with certain
suppliers for the purchase or sale of power on a unit capacity basis.
CSW and SWEPCO
As part of the negotiations to acquire BREMCO, SWEPCO entered
into a long-term purchased power contract with Cajun, BREMCO's
previous full-requirements wholesale supplier. The contract covered
the purchase of energy at a fixed price for 1993 and 1994, and the
purchase of capacity and energy in subsequent years. SWEPCO is a
member of the Southwest Power Pool and the Western Systems Power
Pool.
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CSW, SWEPCO and WTU
On April 4, 1994, the FERC issued an order pursuant to Section
211 of the Federal Power Act forcing a regional utility to transmit
power to Tex-La on behalf of WTU. The order was one of the first
issued by FERC under that provision, which was added by the Energy
Policy Act to increase competition in wholesale power markets. On
December 1, 1994, the FERC issued an order requiring a regional
utility to provide this transmission service at a cost which was
acceptable to Tex-La. The FERC also ordered the same regional
utility to enter into an interconnection and remote control area load
agreement with WTU within 30 days. This agreement was executed on
January 3, 1995. On January 5, 1995, WTU began selling 92 MW of
power and energy to Tex-La. Tex-La has a peak requirement of
approximately 120 MWs. WTU will serve Tex-La until facilities are
completed to connect Tex-La to SWEPCO, at which time SWEPCO will
provide 85 MW and WTU will retain 35 MW of the Tex-La electric load.
CSW and PSO
In 1989, PSO entered into certain long-term contracts with MCPC,
a cogeneration development company located in northeastern Oklahoma.
These contracts include (i) an Interconnection and Interchange
Agreement providing terms and conditions under which MCPC can connect
its electric generating facilities to PSO's transmission system and
providing for future transmission by PSO of specified amounts of
MCPC's power to an unaffiliated utility, (ii) a Stock/Asset Purchase
Agreement which allows PSO under certain conditions to acquire the
stock or assets of MCPC, and (iii) an Energy Conversion Agreement
which requires PSO to deliver natural gas to MCPC for conversion to
electrical energy to be delivered by MCPC to PSO. Under the Energy
Conversion Agreement, MCPC is required to deliver at least 394,200
MWH per year of firm energy to PSO. PSO also has the right to
dispatch up to 60 MWH per hour of quick-start capability.
PSO and MCPC filed a joint application with the Oklahoma
Commission seeking approval of a September 1992 Letter Agreement
between PSO and MCPC which provided for MCPC granting two-year
extensions to the Interconnection and Interchange Agreement and the
Energy Conversion Agreement in exchange for PSO not requiring payment
by MCPC of certain debt and charges related to the Energy Conversion
Agreement. The Oklahoma Commission Staff subsequently filed its own
application seeking a review and evaluation of the current value to
PSO of the Energy Conversion Agreement. MCPC also filed an
application with the Oklahoma Commission requesting additional relief
through the modification of the existing Energy Conversion
Agreement. An emergency order was issued under MCPC's application
which increased the payment made by PSO to MCPC for energy purchases
and decreased the amount of firm energy MCPC is required to deliver
to PSO. The emergency order is subject to a permanent ruling. The
application filed by the Oklahoma Commission Staff was subsequently
withdrawn. In December 1993, PSO filed an application with an ALJ to
dismiss the case filed by MCPC based on a recent ruling from the
Oklahoma Supreme Court. PSO's application to dismiss was denied by
the ALJ and was appealed to the Oklahoma Commission. PSO's appeal
was subsequently denied. The joint application and MCPC's
application are expected to be heard by the second quarter of 1995.
In July 1993, PSO commenced a lawsuit in the District Court of
Tulsa County, Oklahoma, seeking a declaratory judgment that PSO is
entitled to terminate the Energy Conversion Agreement as of August 1,
1993, because of a default committed by MCPC. In November 1993, the
Court granted judgment in favor of MCPC on grounds that the Oklahoma
Commission had exclusive jurisdiction of the case and also that PSO
had contractually waived its cause of action. PSO has appealed the
Court's ruling to the Oklahoma Supreme Court, where the case is
pending.
SWEPCO
SWEPCO furnishes energy at wholesale to two municipalities and
also supplies electric energy at wholesale to eight electric
cooperatives operating in its territory through NTEC, Tex-La and
Rayburn Country. SWEPCO also sells power to AECC and Cajun on an as-
available basis.
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WTU
WTU provides wholesale electricity to four electric cooperatives
and one municipality for all their electric energy requirements. WTU
also provides wholesale power to eight other electric cooperatives,
one other municipal customer and one investor owned electric utility
company. WTU's contractual obligations with thirteen of its
wholesale customers require a five year notice of termination, while
one wholesale customer has a three year notice period and another has
a fifteen year obligation.
System Interconnections
CSW, CPL, PSO, SWEPCO and WTU
The CSW System operates on an interstate basis to facilitate
exchanges of power. PSO and WTU are interconnected through the 200
MW North HVdc Tie. In August 1992, SWEPCO and CPL entered into an
agreement with HLP and TU to construct and operate an East Texas HVdc
transmission interconnection which will facilitate exchanges of power
for the CSW System. This interconnection will consist of a back-to-
back HVdc converter station and 16 miles of 345 KV 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 MW
project is scheduled to be completed in mid-1995.
CPL and WTU are members of ERCOT, which also includes TU, HLP,
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 a
firm, economy and emergency basis.
Seasonality
CSW, CPL, PSO, SWEPCO and WTU
Sales of electricity by the Electric Operating Companies 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.
Franchises
CSW, CPL, PSO, SWEPCO and WTU
The Electric Operating Companies hold franchises to provide
electric service in various municipalities in their service areas.
These franchises have varying provisions and expiration dates
including, in some cases, termination and buy-out provisions. CSW
considers the Electric Operating Companies' franchises to be adequate
for the conduct of their business.
Employees
CSW, CPL, PSO, SWEPCO and WTU
At December 31, 1994, CSW had 8,055 employees, as follows:
CSWS 1,070
CPL 1,933
PSO 1,552
SWEPCO 1,777
WTU 1,090
TRANSOK 554
CSWE 79
8,055
1-23
Approximately 600 employees at PSO and 700 employees at SWEPCO
are covered under collective bargaining agreements with the IBEW.
CSW implemented a restructuring plan in 1994 which resulted in a
reduction of approximately 7% of the CSW System work force.
Executive Officers of the
Registrant
The following information is included in Part I pursuant to
Regulation S-K, Item 401(b), Instruction 3.
CSW
Age
Name at March 16, Present Position
1995
E. R. Brooks 57 Chairman, President and CEO,
Director
Harry D. Mattison 58 Executive Vice President of CSW
and President and CEO of Central
and South West Electric, Director
T. V. Shockley, III 50 Executive Vice President of CSW
and President and CEO of Central
and South West Enterprises,
Director
Ferd. C. Meyer, Jr. 55 Senior Vice President and General
Counsel
Glenn D. Rosilier 47 Senior Vice President and CFO
Frederic L. Frawley 52 Corporate Secretary and Senior
Attorney
Stephen J. McDonnell 44 Treasurer
Wendy G. Hargus 37 Controller
Each of the executive officers of CSW is elected to hold office
until the first meeting of the CSW's Board of Directors after the
next annual meeting of stockholders. CSW's next annual meeting of
stockholders is scheduled to be held April 20, 1995. Each of the
executive officers listed in the table above has been employed by CSW
or an affiliate of CSW in an executive or managerial capacity for
more than the last five years.
1-24
OPERATING STATISTICS
CSW
CENTRAL AND SOUTH WEST CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED ELECTRIC OPERATING STATISTICS
1994 1993 1992
KILOWATT-HOUR SALES (MILLIONS)
RESIDENTIAL 16,368 15,903 14,593
COMMERCIAL 13,463 12,966 12,370
INDUSTRIAL 18,869 18,205 17,257
OTHER RETAIL 1,501 1,434 1,363
SALES TO RETAIL CUSTOMERS 50,201 48,508 45,583
SALES FOR RESALE 7,133 5,852 6,262
TOTAL 57,334 54,360 51,845
NUMBER OF ELECTRIC CUSTOMERS AT END
OF PERIOD (THOUSANDS)
RESIDENTIAL 1,417 1,396 1,366
COMMERCIAL 205 201 196
INDUSTRIAL 24 24 25
OTHER 15 12 12
TOTAL 1,661 1,633 1,599
RESIDENTIAL SALES AVERAGES
KWH PER CUSTOMER 11,665 11,541 10,786
REVENUE PER CUSTOMER(a) $824 $842 $773
REVENUE PER KWH(a)(cents) 7.06 7.29 7.17
REVENUE PER KWH ON TOTAL SALES (a)(cents) 5.35 5.62 5.38
FUEL COST DATA (a)
AVERAGE Btu PER NET KWH 10,344 10,391 10,482
COST PER MILLION Btu $1.82 $2.11 $1.92
COST PER KWH GENERATED (cents) 1.88 2.19 2.01
COST AS A PERCENTAGE OF REVENUE 37.9% 39.6% 37.1%
(a) These statistics reflect the outage at STP in 1993 and early
1994 as well as FUSER and CSF in 1993 and 1992.
1-25
CPL
CENTRAL POWER AND LIGHT COMPANY
OPERATING STATISTICS
1994 1993 1992
KILOWATT-HOUR SALES (MILLIONS)
RESIDENTIAL 5,954 5,612 5,408
COMMERCIAL 4,523 4,278 4,181
INDUSTRIAL 6,910 6,406 5,800
OTHER RETAIL 457 435 414
SALES TO RETAIL CUSTOMERS 17,844 16,731 15,803
SALES FOR RESALE 1,286 913 1,370
TOTAL 19,130 17,644 17,173
NUMBER OF ELECTRIC CUSTOMERS AT END
OF PERIOD
RESIDENTIAL 516,355 504,893 493,772
COMMERCIAL 76,739 74,767 73,200
INDUSTRIAL (a) 5,864 6,156 6,307
OTHER 3,577 3,538 3,561
TOTAL 602,535 589,354 576,840
RESIDENTIAL SALES AVERAGES
KWH PER CUSTOMER 11,729 11,298 11,133
REVENUE PER CUSTOMER (b) $935 $955 $890
REVENUE PER KWH (b) (cents) 7.97 8.45 7.99
REVENUE PER KWH ON TOTAL SALES (b)(cents) 6.37 6.93 6.48
FUEL COST DATA (b)
AVERAGE Btu PER NET KWH 10,289 10,296 10,404
COST PER MILLION Btu $1.75 $2.17 $1.70
COST PER KWH GENERATED (cents) 1.80 2.23 1.77
COST AS A PERCENTAGE OF REVENUE 27.0% 28.6% 27.6%
(a) The customer decrease in 1994 was due primarily to the combining
of multiple customer accounts into single accounts and a decline in
customers due to economic and competitive conditions. The customer
decrease in 1993 was largely due to the combining of multiple
customer accounts into single accounts.
(b) These statistics reflect the outage at STP in 1993 and early
1994.
1-26
PSO
PUBLIC SERVICE COMPANY OF OKLAHOMA
OPERATING STATISTICS
1994 1993 1992
KILOWATT-HOUR SALES (MILLIONS)
RESIDENTIAL 4,749 4,714 4,139
COMMERCIAL 4,434 4,352 4,092
INDUSTRIAL 4,360 4,445 4,420
OTHER RETAIL 89 87 85
SALES TO RETAIL CUSTOMERS 13,632 13,598 12,736
SALES FOR RESALE 1,509 563 665
TOTAL 15,141 14,161 13,401
NUMBER OF ELECTRIC CUSTOMERS AT END
OF PERIOD
RESIDENTIAL 409,675 406,847 404,170
COMMERCIAL 53,454 53,166 52,215
INDUSTRIAL 5,156 5,087 5,163
OTHER 1,287 1,008 1,009
TOTAL 469,572 466,108 462,557
RESIDENTIAL SALES AVERAGES
KWH PER CUSTOMER 11,640 11,637 10,297
REVENUE PER CUSTOMER $726 $731 $642
REVENUE PER KWH (cents) 6.24 6.28 6.24
REVENUE PER KWH ON TOTAL SALES (a)(cents) 4.89 5.00 4.64
FUEL COST DATA (a)
AVERAGE Btu PER NET KWH 10,231 10,220 10,305
COST PER MILLION Btu $1.96 $2.38 $2.34
COST PER KWH GENERATED(cents) 2.00 2.43 2.41
COST AS A PERCENTAGE OF REVENUE 39.5% 43.7% 40.3%
(a) These statistics reflect FUSER and CSF in 1993 and 1992. See
REGULATION AND RATES and FUEL SUPPLY.
1-27
SWEPCO
SOUTHWESTERN ELECTRIC POWER COMPANY
OPERATING STATISTICS
1994 1993 1992
KILOWATT-HOUR SALES (MILLIONS)
RESIDENTIAL 4,157 4,114 3,702
COMMERCIAL 3,378 3,249 3,039
INDUSTRIAL 6,357 6,122 5,862
OTHER RETAIL 400 390 373
SALES TO RETAIL CUSTOMERS 14,292 13,875 12,976
SALES FOR RESALE 5,189 4,508 3,854
TOTAL 19,481 18,383 16,830
NUMBER OF ELECTRIC CUSTOMERS AT END
OF PERIOD
RESIDENTIAL 346,227 340,379 325,301
COMMERCIAL 48,153 46,728 45,185
INDUSTRIAL 5,747 5,809 5,687
OTHER 2,609 2,605 2,636
TOTAL 402,736 395,521 378,809
RESIDENTIAL SALES AVERAGES
KWH PER CUSTOMER 12,107 12,357 11,445
REVENUE PER CUSTOMER $776 $822 $770
REVENUE PER KWH (cents) 6.41 6.65 6.73
REVENUE PER KWH ON TOTAL SALES (cents) 4.24 4.60 4.62
FUEL COST DATA
AVERAGE Btu PER NET KWH 10,489 10,582 10,717
COST PER MILLION Btu $1.75 $1.94 $1.93
COST PER KWH GENERATED (cents) 1.84 2.05 2.07
COST AS A PERCENTAGE OF REVENUE 40.6% 42.5% 43.0%
1-28
WTU
WEST TEXAS UTILITIES COMPANY
OPERATING STATISTICS
1994 1993 1992
KILOWATT-HOUR SALES (MILLIONS)
RESIDENTIAL 1,508 1,464 1,344
COMMERCIAL 1,128 1,087 1,057
INDUSTRIAL 1,241 1,231 1,175
OTHER RETAIL 556 522 491
SALES TO RETAIL CUSTOMERS 4,433 4,304 4,067
SALES FOR RESALE 2,051 2,288 1,951
TOTAL 6,484 6,592 6,018
NUMBER OF ELECTRIC CUSTOMERS AT END
OF PERIOD
RESIDENTIAL 144,966 143,453 142,270
COMMERCIAL 26,618 26,001 25,714
INDUSTRIAL 7,392 7,453 7,384
OTHER 5,533 5,361 5,254
TOTAL 184,509 182,268 180,622
RESIDENTIAL SALES AVERAGES
KWH PER CUSTOMER 10,449 10,241 9,485
REVENUE PER CUSTOMER $822 $811 $752
REVENUE PER KWH (cents) 7.86 7.92 7.93
REVENUE PER KWH ON TOTAL SALES (cents) 5.29 5.24 5.24
FUEL COST DATA
AVERAGE Btu PER NET KWH 10,424 10,491 10,445
COST PER MILLION Btu $1.88 $1.91 $1.82
COST PER KWH GENERATED (cents) 1.96 2.00 1.91
COST AS A PERCENTAGE OF REVENUE 38.3% 39.1% 38.0%
1-29
CONSTRUCTION AND FINANCING
CSW, CPL, PSO, SWEPCO and WTU
The CSW System maintains a continuing construction program, the
nature and extent of which is based upon current and estimated future
loads of the system. The estimated total capital expenditures,
including AFUDC, of the CSW System for the years 1995-1997 are as
follows:
CSW
CONSTRUCTION 1995 1996 1997 TOTAL
(MILLIONS)
GENERATION $ 47 $ 37 $ 43 $ 127
TRANSMISSION 35 85 59 179
DISTRIBUTION 146 138 131 415
FUEL 4 21 12 37
TRANSOK 63 40 40 143
OTHER 90 61 73 224
TOTAL $385 $382 $358 $1,125
CPL
CONSTRUCTION 1995 1996 1997 TOTAL
(MILLIONS)
GENERATION $ 23 $ 20 $ 19 $ 62
TRANSMISSION 16 28 11 55
DISTRIBUTION 45 59 57 161
FUEL 4 21 12 37
OTHER 23 8 11 42
TOTAL $111 $136 $110 $357
PSO
CONSTRUCTION 1995 1996 1997 TOTAL
(MILLIONS)
GENERATION $11 $ 9 $18 $ 38
TRANSMISSION 6 20 13 39
DISTRIBUTION 35 29 29 93
OTHER 19 13 11 43
TOTAL $71 $71 $71 $213
SWEPCO
CONSTRUCTION 1995 1996 1997 TOTAL
(MILLIONS)
GENERATION $12 $ 7 $ 5 $ 24
TRANSMISSION 10 34 28 72
DISTRIBUTION 48 31 27 106
OTHER 26 22 34 82
TOTAL $96 $94 $94 $284
WTU
CONSTRUCTION 1995 1996 1997 TOTAL
(MILLIONS)
GENERATION $ 1 $ 1 $ 1 $ 3
TRANSMISSION 3 3 7 13
DISTRIBUTION 18 19 18 55
OTHER 15 13 11 39
TOTAL $37 $36 $37 $110
Information in the foregoing tables is subject to change as a
result of change in the underlying assumptions from 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, and nuclear, environmental and other regulation,
delays from regulatory hearings, the adequacy of rate relief and the
1-30
availability of necessary external capital. Changes in these and
other factors could cause each respective Electric Operating 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.
In addition, increasing competition in the electric utility
industry may have an impact on the construction programs of the
Electric Operating Companies. Traditionally, the Electric Operating
Companies have made investments in their utility systems, filed a
rate case to seek recovery of their operating and other costs and
sought to earn a rate of return on their assets in rate base.
Competition in the utility industry, however, is likely to lead to
an increasing need to stabilize or reduce rates. At the same time,
the retail regulatory environment is beginning to shift from
traditional rate base regulation to incentive and performance-based
regulation which are intended to encourage efficiency and increased
productivity in lieu of traditional ratemaking formulas. In light
of the trend toward competition and away from traditional
ratemaking, the CSW System will periodically reevaluate its capital
spending policies and generally seek to fund only those construction
projects and investments that management believes will offer
satisfactory returns in the current environment. Consistent with
this strategy, the CSW System is likely to continue to make
additional investments in non-utility businesses.
CSW continues to study ways to reduce or meet future increases
in customer demand, including demand-side management programs, new
and efficient electric technologies, construction of various types
and sizes of generation facilities, increasing the availability or
efficiency of existing generation facilities, reducing transmission
and distribution losses, and where feasible and economical,
acquisition of reliable long-term capacity from other suppliers.
The public utility commissions in some of the jurisdictions served
by the Electric Operating Companies may consider on a case-by-case
basis mechanisms to permit recovery of costs of demand-side
management programs and a return on the related investment from
ratepayers.
The CSW System facilities plan indicates that CSW will not
require substantial additions of generating capacity until the year
2001 or beyond.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital
Resources, Capital Expenditures for each registrant, for additional
information with respect to construction expenditures and financing.
FUEL SUPPLY
General
The CSW System's present net dependable summer rating power
generation capabilities and the type of fuel used are set forth in
UTILITY OPERATIONS - Facilities above. Additional fuel supply data
is set forth in the tables presented below.
CSW SYSTEM AGGREGATE
CAPABILITY GENERATION
1994 (MW) 1994 (KWH)
NATURAL GAS 8,246 NATURAL GAS 47%
COAL AND LIGNITE 4,702 COAL AND LIGNITE 47%
NUCLEAR 630 NUCLEAR 6%
HYDRO and OIL 42 TOTAL 100%
SUB TOTAL 13,620
PLANT IN STORAGE 557
TOTAL 14,177
1-31
CPL AGGREGATE
CAPABILITY GENERATION
1994 (MW) 1994 (KWH)
NATURAL GAS 2,807 NATURAL GAS 56%
COAL 657 COAL 24%
NUCLEAR 630 NUCLEAR 20%
HYDRO 6 TOTAL 100%
SUB TOTAL 4,100
PLANT IN STORAGE 310
TOTAL 4,410
PSO AGGREGATE
CAPABILITY GENERATION
1994 (MW) 1994 (KWH)
NATURAL GAS 2,600 NATURAL GAS 58%
COAL 1,030 COAL 42%
OIL 25 TOTAL 100%
SUB TOTAL 3,655
PLANT IN STORAGE 247
TOTAL 3,902
SWEPCO AGGREGATE
CAPABILITY GENERATION
1994 (MW) 1994 (KWH)
NATURAL GAS 1,819 NATURAL GAS 23%
COAL 1,824 COAL 48%
LIGNITE 821 LIGNITE 29%
TOTAL 4,464 TOTAL 100%
WTU AGGREGATE
CAPABILITY GENERATION
1994 (MW) 1994 (KWH)
NATURAL GAS 1,020 NATURAL GAS 59%
COAL 370 COAL 41%
OIL 11 TOTAL 100%
TOTAL 1,401
Natural Gas
CSW
The Electric Operating Companies purchase their gas from a
number of suppliers operating in and around their service
territories. In 1994, approximately 48% of the Electric Operating
Companies' total gas purchases were made under long-term contracts
and approximately 52% came from short-term contracts and spot
purchases.
CSW and CPL
CPL's eight gas-fired electric generating plants are supplied by
a portfolio of long-term and short-term natural gas purchase
agreements through multiple natural gas pipeline systems.
Approximately 68% of CPL's total gas requirements in 1994 were
purchased under long-term arrangements representing both purchase
obligations and discretionary purchases, with the balance of CPL's
requirements being acquired under short-term arrangements from the
spot market. CPL's principal gas supplies for 1994 were provided
1-32
under agreements with Corpus Christi Gas Marketing, L.P., Onyx
Pipeline Company, Enron Corporation, or their affiliates. They
supplied approximately 25%, 13% and 10%, respectively, of CPL's total
natural gas purchases.
CSW and PSO
PSO engages in a program to maintain adequate gas supplies
necessary for operation. Natural gas for generation is provided by
purchases under a number of long-term and spot market contracts.
Approximately 60% of PSO's natural gas requirements were provided for
under firm contracts. Transok acts as an administrator with respect
to purchases of natural gas supplies. Gas is transported by Transok
to PSO facilities under agreements pursuant to which PSO pays Transok
for actual costs incurred in providing the services as determined on
an allocated cost of service basis, including a rate of return on
equity applicable between affiliates as specified by the Oklahoma
Commission in PSO's most recent Oklahoma price review. See ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - CSW's NOTE 10 and PSO's
NOTE 8, Litigation and Regulatory Proceedings, for further
information with respect to such agreements between PSO and Transok.
CSW and SWEPCO
In 1994, SWEPCO purchased approximately 99.5% of its gas
requirements pursuant to spot purchase contracts with no take-or-pay
obligations. The remaining 0.5% of SWEPCO's 1994 gas requirements
came from a long-term take-or-pay contract which was terminated in
January 1994. SWEPCO plans to continue to enter into short-term
contracts with various suppliers to provide gas for peaking purposes.
CSW and WTU
WTU has gas purchase contracts with several suppliers. The
largest long-term contract, which is with Lone Star, provided
approximately 13% of WTU's total gas requirements in 1994. Lone Star
is obligated, except during curtailments, to have gas available for
125% of the estimated annual fuel requirements of each plant served,
provided the total of all plants does not exceed 110% of the
estimated annual fuel requirement. The Lone Star contract, which
expires in 2000, allows WTU considerable flexibility to purchase gas
from other sources. Utilizing this flexibility in 1994, WTU
purchased approximately 68% of its gas requirements on the spot
market from many different suppliers. The remaining 19% of WTU's
1994 gas requirements came from supplemental firm contracts with
several suppliers. The contracts with suppliers vary in their terms,
but generally provide for periodic or other price adjustments.
Coal and Lignite
CSW
The Electric Operating Companies purchase coal from a number of
suppliers. In 1994, approximately 82% of the Electric Operating
Companies' total coal purchases were supplied under long-term
contract with the balance procured on the spot market. The coal for
the CSW System plants comes primarily from Wyoming or Colorado mines
which are located between 1,000 and 1,500 rail miles from the
generating plants.
Proposed Railroad Merger
CSW, CPL, PSO, SWEPCO and WTU
In October 1994, Burlington Northern Railroad Company and the
Atchison, Topeka and Santa Fe Railway Company filed an application
with the Interstate Commerce Commission to merge the two railroads.
These railroads currently compete for a portion of the coal
transportation traffic to CPL's Coleto Creek power plant. Because of
the potential elimination of such competition and other factors, CPL
and the other Electric Operating Companies may be adversely affected
by this merger, if approved, unless conditions mitigating the impact
are included in the merger.
Oklaunion
CSW, CPL, PSO and WTU
The jointly-owned Oklaunion plant is supplied coal under a coal
supply contract with Exxon expiring in 2006. This contract was
amended and restated in December 1993 as part of a settlement of
litigation with Exxon. In November 1994, Caballo Coal Company, an
1-33
affiliate of Peabody Holding Company, Inc., purchased Exxon's Rawhide
and Caballo mines in Wyoming, the sources of the Exxon coal. The
long-term coal supply contract has subsequently been transferred from
Exxon to Caballo Coal Company.
Approximately 67% of the total 1994 Oklaunion coal requirements
for CPL, 70% for PSO and 71% for WTU were supplied under the Exxon
contract with the balance procured on the spot market.
CPL's share of the year-end 1994 coal inventory at Oklaunion was
approximately 46,000 tons, representing approximately 60 days supply.
PSO's share was approximately 95,000 tons, representing approximately
21 days supply. WTU's share was approximately 250,000 tons,
representing approximately 55 days supply.
All coal used at the Oklaunion plant is transported
approximately 1,100 miles to the plant by the Burlington Northern
Railroad Company pursuant to a coal transportation contract which is
projected to expire during late 1995. The coal is transported under
this contract in Burlington Northern supplied rail cars. WTU has
instituted a rate proceeding at the Interstate Commerce Commission
requesting a reasonable rate for rail transportation of coal to the
Oklaunion plant, pursuant to filed tariffs, after expiration of the
Burlington Northern contract.
Coleto Creek
CSW and CPL
At Coleto Creek, the long-term agreement expiring in 1999 with
Colowyo Coal Company provided approximately 60% of the coal
requirements of the plant for 1994. CPL's purchase obligation set
forth in the Colowyo agreement for 1995 and through 1999 is for
approximately 25% of Coleto Creek's requirements. The coal is mined
in northwestern Colorado and is transported approximately 1,400 miles
under long-term rail agreements with Denver & Rio Grande Western
Railroad Company, the Burlington Northern Railroad Company and the
Southern Pacific Transportation Company. Southern Pacific
Transportation Company is currently the only rail carrier with access
to the Coleto Creek plant. The balance of the Coleto Creek
requirements are currently being procured on the spot market. CPL
owns sufficient railcars for operation of three unit trains and has
negotiated contracts with the rail carriers involved which have been
filed with the Interstate Commerce Commission. CPL's rail
transportation contracts for Coleto Creek expire December 31, 1995.
CPL has instituted a proceeding at the Interstate Commerce Commission
requesting a reasonable rate for the 16 mile movement from Coleto
Creek to Victoria, Texas, a destination served by Missouri Pacific
Railroad Company. After 1995, CPL intends to utilize coal from the
Powder River Basin of Wyoming for a portion of the Coleto Creek plant
requirements and intends to negotiate rail transportation agreements
for such coal. At year-end 1994, CPL had approximately 290,000 tons
of coal in inventory at Coleto Creek, representing approximately 43
days supply.
Northeastern Station
CSW and PSO
PSO has a contract with Kerr-McGee Coal Corporation, which
substantially covers the coal supply for PSO's Northeastern Station
coal units through at least 2007, with approximately 11% of the 1994
requirements purchased on the spot market. Coal delivery is by unit
trains from mines located in the Gillette, Wyoming vicinity, a
distance of about 1,100 rail miles from Northeastern Station. PSO
owns sufficient rail cars and spares for operation of six unit
trains. Coal is transported to Northeastern Station pursuant to long-
term contracts with Burlington Northern and the Missouri Pacific
Railroad Company which have been filed with the Interstate Commerce
Commission. In some years, including 1994, a portion of the coal has
been transported pursuant to short-term contracts with other
carriers. Burlington Northern has disputed PSO's right to transport
coal at Northeastern Station utilizing other carriers. This dispute
is the subject of pending litigation. See ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA - CSW NOTE 10 and PSO NOTE 8,
1-34
Litigation and Regulatory Proceedings for further discussion. At
year-end 1994, PSO had approximately 529,000 tons of coal in
inventory at Northeastern representing approximately 50 days supply.
CSW and SWEPCO
The long-term supply for SWEPCO's Welsh plant and its 50 percent-
owned Flint Creek plant is provided under a contract with AMAX. The
current contract, executed in December 1993, replaced a prior
contract between the parties as part of a settlement of litigation
concerning the prior contract. The settlement has resulted in lower
fuel costs to the Welsh and Flint Creek plants. Approximately 99% of
the total 1994 Flint Creek coal requirements and 94% of the total
1994 Welsh coal requirements were supplied under the AMAX contract
with the balance purchased on the spot market.
Coal under the AMAX contract is mined near Gillette, Wyoming, a
distance of about 1,500 and 1,100 miles, respectively, from the Welsh
and Flint Creek plants. This coal is delivered to the plants under
rail transportation contracts with Burlington Northern and the Kansas
City Southern Railroad Company. These contracts will expire between
2001 and 2007. SWEPCO owns or leases under long-term leases
sufficient cars and spares for operation of twelve unit trains.
SWEPCO has supplemented its railcar fleet from time to time with
short-term leases. At December 31, 1994, SWEPCO had coal inventories
of 1,199,000 tons at Welsh representing 53 days supply and 552,000
tons at Flint Creek representing 80 days supply.
SWEPCO has acquired lignite leases covering an aggregate of
about 27,000 acres near the Henry W. Pirkey power plant. Sabine
Mining Company is the contract miner of these reserves. At December
31, 1994, 322,000 tons of lignite were in inventory at the plant
representing 33 days supply.
Another 25,000 acres are jointly leased in equal portions by
SWEPCO and CLECO in the Dolet Hills area of Louisiana near Dolet
Hills Power Plant. The Dolet Hills Mining Venture is the contract
miner for these reserves. At December 31, 1994, SWEPCO had 240,000
tons of lignite in inventory at the plant representing 58 days
supply.
In the opinion of the management of SWEPCO, the acreage under
lease in these areas contains sufficient reserves to cover the
anticipated lignite requirements for the estimated useful lives of
the lignite-fired plants.
Nuclear Fuel
CSW and CPL
The supply of fuel for STP involves a complex process. This
process includes the acquisition of uranium concentrate, the
conversion of uranium concentrate to uranium hexafluoride, the
enrichment of uranium hexafluoride in the isotope U235 and the
fabrication of the enriched uranium into fuel rods and incorporation
of fuel rods into fuel assemblies. The fuel assemblies are the final
product loaded into the reactor core. The time associated with this
process requires fuel decisions be made years in advance of the
actual need to refuel the reactor. Fuel requirements for STP are
being handled by the STP Management Committee, comprised of
representatives of all participants in STP.
Outages are necessary approximately every 18 months for
refueling. Because STP's fuel costs are significantly lower than any
of the other CPL units, CPL's average fuel costs are expected to be
higher whenever an STP unit is down for refueling or maintenance.
CPL and the other STP participants have entered into contracts
with suppliers for uranium concentrate and conversion service
sufficient for the operation of both STP units through 1996. Also,
flexible uranium concentrate and uranium hexafluoride contracts are
in place to provide approximately 50% of the uranium needed for STP
from 1997 to 2000. Enrichment contracts have been secured for a 30-
year period from the initial operation of each unit with the
exception of the period from October of 2000 to September of 2002.
The STP participants canceled the enrichment requirements for such
period under a ten year no cost termination provision in the
1-35
enrichment contract. The STP participants believe that other, lower-
cost options will be available in the future. Also, fuel fabrication
services have been contracted for operation through 2005 for Unit 1
and 2006 for Unit 2. Although CPL and the other STP owners cannot
predict the availability of uranium and related services, CPL and the
other STP owners do not currently expect to have difficulty obtaining
uranium and related services required for the remaining years of STP
operations.
The Energy Policy Act has provisions for the recovery of a
portion of the costs associated with the decommissioning and
decontamination of the gaseous diffusion plants used in the
enrichment process. These costs are being recovered on the basis of
enrichment services purchased by utilities from the DOE prior to
October of 1992. The total annual assessment for all domestic
utilities is limited to $150 million per federal fiscal year and
assessable for 15 years. The STP assessment will be approximately
$2.0 million each year with CPL's share being 25.2% of the annual STP
assessment.
The Nuclear Waste Policy Act of 1982, as amended, requires the
DOE to develop a permanent high level waste disposal facility for the
storage of spent nuclear fuel by 1998. The DOE recently announced
that the permanent facility will not be available until 2010. The
DOE will be taking possession of all spent fuel generated at STP as a
result of a contract CPL and other STP participants have entered into
with the DOE. STP has on-site storage facilities with the capability
to store all the spent nuclear fuel generated by the STP units over
their life. Therefore, the DOE delay in providing the disposal
facility will not impact the operation of the STP units. Under
provisions of the Nuclear Waste Policy Act of 1992, a one-mill per
KWH assessment on electricity generated and sold from nuclear
reactors funds the DOE waste disposal program.
Risks of substantial liability could arise from the operation of
STP and from the use, handling, disposal and possible radioactive
emissions associated with nuclear fuel. While CPL carries insurance,
the availability, amount and coverage thereof is limited and may
become more limited in the future. The available insurance may not
cover all types or amounts of loss or expense which may be
experienced in connection with the ownership of STP.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS - Fuel and Purchased Power for
information relating to coal contract litigation.
Governmental Regulation
CSW, CPL, PSO, SWEPCO and WTU
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 CSW System's ability
to economically meet the needs of its customers and could require the
Electric Operating Companies 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 additional expenditures for construction and
could have a significant adverse effect on CSW's and/or the Electric
Operating Companies' financial condition and results of operations.
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Fuel Costs and Consumption
CSW, CPL, PSO, SWEPCO and WTU
Additional fuel cost data for the CSW System appears under
OPERATING STATISTICS. Average fuel costs and consumption by fuel
type follow:
1994
AVERAGE
COST PER
FUEL TYPE MILLION
Btu
CSW
NATURAL GAS $2.18
COAL 1.71
LIGNITE 1.34
NUCLEAR .51 FUEL TYPE 1994 CONSUMPTION (MILLIONS)
All fuel types 1.82 Tons Mcfs Btus
CPL CPL
NATURAL GAS $2.10 NATURAL GAS 105 107
COAL 1.98 COAL 2 43
NUCLEAR .51 NUCLEAR * * 37
All fuel types 1.75
PSO PSO
NATURAL GAS $2.38 NATURAL GAS 83 86
COAL 1.38 COAL 4 63
All fuel types 1.96
SWEPCO SWEPCO
NATURAL GAS $1.98 NATURAL GAS 43 43
COAL 1.90 COAL and 10 148
LIGNITE
LIGNITE 1.34
All fuel types 1.75
WTU WTU
NATURAL GAS $2.18 NATURAL GAS 42 42
COAL 1.42 COAL 2 28
All fuel types 1.88
* Not measured
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Future Cost of Fuel
CSW, CPL, PSO, SWEPCO and WTU
The registrants are unable to predict the future cost of fuel.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS - Rates and Regulatory Matters
for each registrant, for further information concerning fuel costs.
ENVIRONMENTAL MATTERS
CSW, CPL, PSO, SWEPCO and WTU
The Operating Companies and CSWE are subject to regulation with
respect to air and water quality and solid waste standards and other
environmental matters by various federal, state and local
authorities. These authorities have continuing jurisdiction in most
cases to require modifications in the Electric Operating Companies'
facilities and operations. Changes in environmental statutes or
regulations could require substantial additional expenditures to
modify the Electric Operating Companies' facilities and operations
and could have a significant adverse effect on CSW's and each
Electric Operating Companies' results of operations and financial
condition. Violations of environmental statutes or regulations can
result in fines and other costs.
Air Quality
Clean Air Act Amendments
CSW, CPL, PSO, SWEPCO and WTU
Air quality standards and emission limitations are subject to
the jurisdiction of state regulatory authorities in each state in
which the CSW System operates, with oversight by the EPA. In
accordance with regulations of these state authorities, 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. None of the Electric Operating Companies has
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.
In November 1990, the United States Congress passed the Clean
Air Act which places restrictions on the emission of sulfur dioxide
from gas-, coal- and lignite-fired generating plants. Beginning in
the year 2000, the Electric Operating Companies will be required to
hold allowances in order to emit sulfur dioxide. The EPA issues
allowances to owners of existing generating units based on historical
operating conditions. Based on the CSW System facilities plan, CSW
believes that the Electric Operating Companies' allowances are
adequate to meet their needs at least through 2008. Public and
private markets are developing for trading of excess allowances. CSW
and the Electric Operating Companies presently have no intention of
engaging in trading of allowances, but may seek to do so in the
future if market conditions warrant and appropriate regulatory
approvals are obtained.
The Clean Air Act also establishes a federal operating source
permit program to be administered by the states.
The Clean Air Act also directs the EPA to issue regulations
governing nitrogen oxide emissions and require government studies to
determine what controls, if any, should be imposed on utilities to
control air toxics emissions. The impact that the nitrogen oxide
emission regulations, and the air toxics study, will have on CSW and
the Electric Operating Companies cannot be determined at this time.
As a result of requirements imposed by the Clean Air Act, CSW
expects to spend $4 million for annual testing of, software
modifications to, and maintenance of continuous emission monitoring
equipment from 1995 through 1997.
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CSW, CPL and WTU
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. CPL and WTU have not received notice from any federal
or state government agency alleging that they currently are subject
to an enforcement action for a material violation of existing federal
or state air quality and emission regulations.
CSW and CPL
As a result of requirements imposed by the Clean Air Act, CPL
expects to spend approximately $1.3 million for annual testing of,
software modifications to, and maintenance of continuous emission
monitoring equipment from 1995 through 1997.
CSW and PSO
Air quality standards and emission limitations are subject to
the jurisdiction of ODEQ, with oversight by the EPA. In accordance
with regulations of ODEQ, 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. PSO
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. As a result of requirements imposed by the
Clean Air Act, PSO expects to spend approximately $1.3 million for
annual testing of, software modifications to, and maintenance of
continuous emission monitoring equipment from 1995 through 1997.
CSW and SWEPCO
Air quality standards and emission limitations are subject to
the jurisdiction of the ADPCE in Arkansas, the LDEQ in Louisiana and
the TNRCC in Texas, with oversight by the EPA. In accordance with
regulations of the ADPCE, LDEQ and 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. SWEPCO 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. As a result of
requirements imposed by the Clean Air Act, SWEPCO expects to spend
approximately $1.3 million for annual testing of, software
modifications to, and maintenance of continuous emission monitoring
equipment from 1995 through 1997.
CSW and WTU
As a result of requirements imposed by the Clean Air Act, WTU
expects to spend approximately $0.5 million for annual testing of,
software modifications to, and maintenance of continuous emission
monitoring equipment from 1995 through 1997.
Transok
Transok's compressor engines and other emission sources are
subject to air permit requirements, including monitoring. As a
result of new requirements under the Clean Air Act, seven of
Transok's facilities will be subject to additional permit
requirements. The Clean Air Act may also impose additional enhanced
monitoring requirements on these seven facilities.
Water Quality
CSW, CPL, PSO, SWEPCO and WTU
The ADPCE, LDEQ, ODEQ, TNRCC and the EPA have jurisdiction over
all wastewater discharges into state waters. These authorities have
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. CPL, PSO, SWEPCO and WTU
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have not received notice from any federal or state government agency
alleging that they currently are subject to an enforcement action for
a material violation of existing federal or state wastewater
discharge regulations.
RCRA, CERCLA and Related Matters
RCRA
CSW, CPL, PSO, SWEPCO and WTU
The RCRA and the Arkansas, Louisiana, Oklahoma and Texas solid
waste rules provide for comprehensive control of all solid wastes
from generation to final disposal. The appropriate state regulatory
authorities in the states in which the CSW System operates have
received authorization from the EPA to administer the RCRA solid
waste control program for their respective states. None of the
Electric Operating Companies has 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
The operations of the CSW System, like those of other utility
systems, generally involve 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. PRPs include
owners and operators of contaminated sites and transporters and/or
generators of hazardous substances. 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.
CSW's subsidiaries incur significant costs for the handling,
transportation, storage and disposal of hazardous and non-hazardous
waste materials. Unit costs for waste classified as hazardous exceed
by a substantial margin unit costs for waste classified as non-
hazardous waste.
The Electric Operating Companies are also subject to various
pending claims alleging that they are PRPs under federal or state
remedial laws for investigating and cleaning up contaminated
property. CSW anticipates that resolution of these claims,
individually or in the aggregate, will not have a material adverse
effect on CSW's consolidated results of operations or financial
condition. 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 Electric Operating Company, the estimated amount
of costs allocated to the Electric Operating Company and the
participation of other parties.
The Electric Operating Companies, like other electric utilities,
produce combustion and other generation by-products, such as sludge,
slag, low-level radioactive waste and spent nuclear fuel. The
Electric Operating Companies own distribution poles treated with
creosote or related substances. The EPA currently exempts coal
combustion by-products from regulation as hazardous wastes.
Distribution poles treated with creosote or similar substances are
not expected to exhibit characteristics that would cause them to be
hazardous waste. In connection with their operations, the Electric
Operating Companies also have used asbestos, PCBs and materials
classified as hazardous waste. If additional by-products or other
materials generated or used by companies in the CSW System were
reclassified as hazardous wastes, or other new laws or regulations
concerning hazardous wastes or other materials were put in effect,
CSW System disposal and remedial costs could increase materially.
The EPA is expected to issue new regulations stating whether certain
other materials will be classified as hazardous.
Sol Lynn Superfund Site
CSW and CPL
The Sol Lynn salvage yard was declared a Superfund site by the
EPA after it was found to contain a number of contaminants including
PCBs. Gulf States Utilities Company remediated the site for
approximately $2 million and is trying to recover a portion of the
remediation costs from alleged PRPs, including CPL. CPL believes its
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liability, if any, would be as a deminimus party. CPL is negotiating
with Gulf States Utilities Company to determine its share, if any, of
remediation costs.
Industrial Road and Industrial Metals Site
CSW and CPL
Several lawsuits relating to the industrial road and industrial
metal site in Corpus Christi, Texas, naming CPL as a defendant, are
currently pending in federal and state court in Texas. Plaintiffs'
claims allege property damage and clean-up activities. Although
management cannot predict the outcome of these proceedings, based on the
defenses that management believes are available to CPL, management
believes that the ultimate resolution of these matters will not have
a material adverse effect on CSW's or CPL's results of operations or
financial condition.
Rose Chemical Site
CSW, SWEPCO and WTU
SWEPCO and WTU were named PRPs in the clean-up of the Rose
Chemical Site, in Missouri, along with 750 other companies. A clean-
up fund was established through payments by PRPs who agreed to a
"buyout settlement," and the site remediation was undertaken. The
site buildings were removed and the grounds cleaned to standards
acceptable to the EPA. The site remediation is virtually completed
and the court settlement became final in July 1994. Remaining costs
are expected to be covered by the previously collected funds and
there should be no further costs to either SWEPCO or WTU.
B&B Salvage Site
CSW, SWEPCO and WTU
SWEPCO and WTU are also PRPs at the B&B Salvage site. This
site, located in Missouri, received scrap metal from the Rose
Chemical firm. The B&B site has been remediated and SWEPCO's and
WTU's share of cleaning up this site and the Rose Chemical site is
not expected to have a material effect on CSW's, SWEPCO's, or WTU's
results of operations or financial condition.
PCB Litigation
CSW and PSO
PSO has been named a defendant in complaints filed in federal and
state courts of Oklahoma in 1984, 1985, 1986 and 1993. The complaints
allege, among other things, that some of the plaintiffs and the
property of other plaintiffs were contaminated with PCBs and other
toxic by-products following certain incidents, including transformer
malfunctions in April 1982, December 1983 and May 1984. To date,
complaints representing approximately $736 million of claims, including
compensatory and punitive damages, have been dismissed,
certain of which resulted from settlements among the parties. The
settlements did not have a significant effect on CSW's or PSO's
consolidated results of operations. Remaining complaints currently
total approximately $395 million, of which approximately one-third is
for punitive damages. Discovery with regard to the remaining
complaints continues. Management cannot predict the outcome of these
proceedings. However, management believes that PSO has defenses to
these complaints and intends to pursue them vigorously. Moreover,
management has reason to believe that PSO's insurance may cover some
of the claims. Management also believes that the ultimate resolution
of the remaining complaints will not have a material adverse effect on
CSW's or PSO's consolidated results of operations or financial
condition.
PCB Storage Facilities
CSW and PSO
PSO investigated and identified PCB contamination at one of its
PCB storage facilities in Sand Springs, Oklahoma. PSO made proper
notification to the EPA of the contamination that was caused by
spills prior to PCB spill regulations. PSO negotiated a remediation
plan with the EPA. Remediation began in November 1994, and the
remediation costs are estimated to be $210,000. As part of the
remediation plan, the EPA has requested PSO to sample the land
surrounding the PCB storage building site. The land will include an
active PSO substation and an industrial area that is privately owned.
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The extent of any PCB contamination has not been determined on either
site.
Compass Industries Superfund Site
CSW and PSO
PSO has received notice from the EPA that it is a PRP under
CERCLA and may be required to share in the reimbursement of cleanup
costs for the Compass Industries Superfund site which has been
remediated. PSO has been named defendant in a lawsuit filed in
Federal District Court in Tulsa, Oklahoma on August 29, 1994, for
reimbursement of the clean-up cost. The range of PSO's degree of
responsibility, if any, as a de minimis party appears to be
insignificant. Management believes the ultimate resolution of this
matter will not have a material adverse effect on CSW's or PSO's
consolidated results of operations or financial condition.
Alleged Coal Gasification Plant in McAlester, Oklahoma
CSW and PSO
PSO has been notified by the EPA of the identification of a coal
gasification plant in McAlester, Oklahoma. The EPA requested PSO to
identify all properties owned by PSO currently and formerly in
McAlester that had been once owned by a non-affiliated company. PSO
has submitted the information to the EPA. PSO has not been able to
locate the alleged coal gasification plant in McAlester, Oklahoma.
PSO has had no further contact with the EPA regarding this issue.
USI Site
CSW and PSO
PSO has been identified by the ADPCE as a PRP at the USI site in
Pine Bluff, Arkansas. In 1993, the ADPCE asked PSO to provide it
with information regarding any transactions between USI and PSO since
1973 that involved hazardous substances. Based on a review of its
records, PSO's environmentally related transactions with USI were
limited to USI's provision of oil recycling services to PSO at
property owned by PSO, not at the USI site. As a result, PSO's
degree of responsibility, if any, at the USI site appears to be
insignificant.
Coal Mine Reclamation
CSW and PSO
In August 1994, PSO received approval from the Wyoming Department
of Environmental Quality to begin reclamation of a coal mine in
Sheridan, Wyoming owned by Ash Creek Mining Company, a wholly-owned
subsidiary of PSO. Ash Creek Mining Company recorded a $3 million
liability in 1993 for the estimated reclamation costs. Actual
reclamation work is expected to commence in mid-1995, with completion
estimated in late 1996. Surveillance monitoring will continue for
ten years after final reclamation. Management believes the ultimate
resolution of this matter will not have a material adverse effect on
CSW's or PSO's consolidated results of operations or financial
condition.
Suspected MGP Site in Marshall, Texas
CSW and SWEPCO
SWEPCO owns a suspected former MGP site in Marshall, Texas.
SWEPCO has notified the TNRCC that evidence of contamination has been
found at the site. As a result of sampling conducted at the end of
1993 and early 1994, SWEPCO is evaluating the extent, if any, to
which contamination has impacted soil, groundwater and other
conditions in the area. A final range of clean-up costs has not yet
been determined, but, based on a preliminary estimate, SWEPCO accrued
approximately $2 million as a liability for this site on SWEPCO's
books as of December 31, 1993. As more information is obtained about
the site, and SWEPCO discusses the site with the TNRCC, the
preliminary estimate may change.
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Suspected MGP Sites in Texarkana, Texas and Arkansas and Shreveport,
Louisiana
CSW and SWEPCO
SWEPCO also owns a suspected former MGP site in Texarkana, Texas
and Arkansas. The EPA ordered an initial investigation of this site,
as well as one in Shreveport, Louisiana, which is no longer owned by
SWEPCO. The contractor who performed the investigations of these two
sites recommended to the EPA that no further action be taken at this
time.
Suspected Biloxi, Mississippi MGP Site
CSW and SWEPCO
SWEPCO has been notified by Mississippi Power Company that it
may be a PRP at the former Biloxi MGP site formerly owned and
operated by a predecessor of SWEPCO. SWEPCO is working with
Mississippi Power Company to investigate the extent of contamination
at this site. The MDEQ approved a site investigation work plan and,
in January 1995, SWEPCO and Mississippi Power Company initiated
sampling pursuant to that work plan. On an interim basis, SWEPCO and
Mississippi Power Company are each paying fifty percent of the cost
of implementing the site investigation work plan. That interim
allocation is subject to a final allocation in the future. SWEPCO
and Mississippi Power Company are investigating whether there are
other PRPs at the Biloxi site. Until the extent of the contamination
at the Biloxi site is identified, it is unknown what, if any,
additional investigation or cleanup may be required.
Rochester Substation Spill
CSW and WTU
In September 1992, an automobile crashed into WTU's 69 KV
substation in Rochester, Texas, and struck a transformer containing
1,500 gallons of 25 parts per million PCB oil. WTU responded and
coordinated clean-up efforts with state officials. In December 1993,
WTU contracted with a consulting firm to ascertain the impact of the
spill on the area ground water and to help determine WTU's
effectiveness in the clean-up effort. Total costs to date have been
approximately $400,000. The consultant's report, dated June 30,
1994, concluded that the spill cleanup procedures were effective.
WTU forwarded the report to the TNRCC on July 12, 1994 and requested
the agency close the matter. Management believes the ultimate
resolution of this matter will not have a material adverse effect on
CSW's or WTU's results of operations or financial condition.
Toxic Substances Control Act of 1976
Under the TSCA, the storage, use and disposal, among other
things, of PCBs are regulated. Violations of TSCA may lead to fines
and penalties.
CSW and CPL
In an inspection of CPL by the EPA, the EPA alleged that CPL
failed to comply with the regulations governing the reporting of
leakage of PCBs from some of its equipment. The EPA has proposed a
penalty of $91,000. CPL met with EPA to negotiate a reduction in the
penalty. EPA responded on January 26, 1995, with a proposed
potential reduced penalty of $61,000 dependent upon filing additional
information with the EPA. Based on the information currently
available to it, CPL expects the final penalty to be between $61,000
and $91,000.
See ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, CSW
NOTE 10, and PSO NOTE 8, Litigation and Regulatory Proceedings for
additional information related to PCB matters.
Other Environmental
CSW, CPL, PSO, SWEPCO and WTU
From time to time the registrants are made aware of various
other environmental issues or are named as a party to various other
legal claims, actions, complaints or other proceedings related to
environmental matters. Management does not expect disposition of
any such pending environmental proceedings to have a material
adverse effect on the registrants' results of operations or
financial condition.
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See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS - Environmental for each
registrant and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA,
CSW NOTE 10 and PSO NOTE 8, Litigation and Regulatory Proceedings
and CSW NOTE 11 and SWEPCO NOTE 10, Commitments and Contingent
Liabilities, for additional information relating to environmental
matters.
NON-UTILITY OPERATIONS
CSW
Transok
Transok, a wholly-owned subsidiary of CSW, is an intrastate
natural gas gathering, transmission, processing, storage and
marketing company. Transok, incorporated in Oklahoma in 1955, was
acquired by CSW in 1961 to supply natural gas to PSO's power
stations. While Transok's operations in recent years have included
the marketing and transportation of natural gas for third parties, it
functions within the CSW System to insure reliable and economic
natural gas service to the Electric Operating Companies and CSWE.
Transok provides a variety of services to the Electric Operating
Companies including acquiring and transporting natural gas to meet
certain of their power generation needs. Transok's largest customer
is PSO. The contract between PSO and Transok provides (i) for the
transportation of PSO's natural gas fuel supply through Transok's
pipeline system and (ii) for Transok to act as PSO's supply
administrator in acquiring natural gas and negotiating and
administering supply contracts. PSO pays Transok for such services
at cost, including a return on equity applicable between affiliates
as specified by the Oklahoma Commission in PSO's most recent Oklahoma
price review. The contract expires on January 1, 2003, but continues
for consecutive five-year terms thereafter unless either party
provides two years' notice of cancellation. Under the contract, PSO
has the right to require delivery of up to 546 MMcf/d of natural gas
through Transok's pipeline system. Effective January 1, 1998, PSO
may adjust the transportation capacity available to it under the
contract based on its projected needs. Delivery of natural gas to
PSO is currently about 86 Bcf annually and is projected to increase.
Natural Gas Transportation and Gathering
Transok provides natural gas suppliers and shippers with
pipeline interconnects for access to the Electric Operating Companies
and other end-users throughout the United States. At December 31,
1994, Transok's pipeline system consisted of approximately 6,436
miles of gathering and transmission lines which include approximately
3,973 miles of gathering lines in Oklahoma, 275 miles in Louisiana
and 214 miles in Texas. At December 31, 1994, Transok's pipeline
system consisted of 200 compressors with 197,900 horsepower to
provide both gathering and transmission line compression. Transok's
pipeline facilities are located in the major natural gas producing
basins in Oklahoma, including the Anadarko and Arkoma basins, and in
the major Louisiana corridor of pipelines transporting natural gas to
the northeast from the Gulf Coast and mid-continent areas. The
Transok pipeline system has numerous connections with major
interstate pipelines through which natural gas is transported to
markets throughout the United States. In 1994, the Transok pipeline
system had a throughput of 506 Bcf of natural gas.
Transok transported more than 86 Bcf per year of natural gas for
PSO in 1994 and provided administrative services to PSO to manage its
supply of natural gas. Transok has been active in the development of
joint gas purchase arrangements with its other CSW affiliates as
well. Transok's access to diverse natural gas markets combined with
the natural gas fuel needs of the Electric Operating Companies allow
for natural gas opportunities at high load factors, reducing the cost
of natural gas fuel for the CSW System.
Natural Gas Processing
Transok also owns and operates seven natural gas processing
plants for the production of natural gas liquids. The plants have an
aggregate capacity of 444 MMcf/d. Transok is the second largest
natural gas processor in Oklahoma and ranks seventeenth among natural
gas liquids producers nationwide. In 1994, Transok's plants produced
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399.4 million gallons of natural gas liquids while revenue from the
sale of natural gas liquids amounted to $117.9 million for the year.
Natural Gas Storage
Transok owns and operates an underground natural gas storage
reservoir in Oklahoma with an aggregate storage capacity of
approximately 26 billion cubic feet. Operational capabilities
include injection into storage at a rate of 130 MMcf/d and a
withdrawal rate in excess of 210 MMcf/d. In 1993, the FERC issued an
order approving market-based storage rates for Transok which enables
it to sell storage services to interstate customers at negotiated
fees based on the value of those services in the competitive
marketplace. Transok's gas storage field also allows Transok to
offer peaking services, accommodate volume swings on its pipeline
system, and support the natural gas requirements of the Electric
Operating Companies.
Natural Gas Marketing
In 1989, Transok began its natural gas marketing program and
sold 26 Bcf to a variety of customers including local distribution
companies, end-users and other pipelines. In 1994, Transok's natural
gas sales volumes were 257 Bcf with a sales revenue of $484.4
million. Off-system sales of natural gas accounted for 111 Bcf of
the natural gas sold in 1994. This increase was the result of
pipeline acquisition and construction activities combined with new
customers. Transok aggregates natural gas supply into various supply
pools, which provide Transok with reliable sources of natural gas at
market sensitive prices, allowing Transok to meet its natural gas
supply needs. Transok offers various gas supply services to provide
customers with peaking and balancing alternatives utilizing Transok's
gas supplies and facilities. In addition, Transok's customers have
the opportunity to select various pricing options including (i) fixed
or variable pricing, (ii) indexed to New York Mercantile Exchange
pricing or (iii) cash quotes.
Transok uses natural gas futures, options and basis swaps to
reduce its price risk exposure arising from the purchase and sale of
natural gas. Natural gas futures and options allow Transok to
protect against volatility in supply costs in fulfilling fixed price
contracts, meeting storage requirements and purchasing natural gas
for processing operations. Natural gas futures and options are also
used to protect Transok against price exposure on sales of natural
gas from storage or anticipated purchases. In addition, basis swaps
protect Transok against volatility in price differentials between
geographic areas in matching anticipated supply and demand prices.
In 1992, FERC Order 636 went into effect to deregulate the
natural gas industry and increase competition. Although Transok
operations were not directly affected by Order 636, Transok has
developed tariff services, flexible contracts and other natural gas
related services in order to meet customers' needs and take advantage
of new competitive opportunities.
Services for CSWE
Transok provides natural gas fuel planning and management
services for CSWE. Transok assists CSWE in developing natural gas
supply and transportation strategies for CSWE's non-utility electric
generation projects.
Regulation
As a subsidiary of CSW, Transok is subject to regulation under
the Holding Company Act. The Holding Company Act, among other
things, requires that regulated companies seek prior SEC approval
before entering into certain transactions including the acquisition
or issuance of securities.
Transok's pipelines are considered gathering systems or
intrastate pipelines. Transok is therefore exempt from regulation by
the FERC under the Natural Gas Act. However, Transok's rates for
transporting gas in interstate commerce are subject to FERC
regulation under the Natural Gas Policy Act of 1978. The FERC
approves Transok's rates for transportation of gas in interstate
commerce through Transok's pipelines in Oklahoma and Louisiana and
the Texas Railroad Commission approves the rates for such
transportation through pipelines in Texas. The FERC also has given
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Transok approval to charge market-based rates for storage of gas
using Transok's storage facility in Oklahoma.
While Transok is not subject to direct regulation by any state
public utility commission, the costs that result from transactions
with its affiliated Electric Operating Companies are subject to
review by the state commissions regulating such affiliates and are
required to meet standards for affiliate transactions to be
recoverable by the Electric Operating Companies.
CSWE
CSWE, a wholly-owned subsidiary of CSW, is authorized to
develop various independent power and cogeneration facilities and to
own and operate such non-utility projects, subject to further
regulatory approvals. CSWE has an approximate 50% interest in the
Brush, Fort Lupton and Mulberry facilities which achieved commercial
operation in 1994.
Brush
The 68 MW Brush project, located in Brush, Colorado, achieved
commercial operation in January 1994 and provides steam and hot
water to a 15-acre greenhouse and sells electricity to Public
Service Company of Colorado.
Ft. Lupton
The Ft. Lupton project provides steam and hot water to a 20-
acre greenhouse and also sells electricity to Public Service Company
of Colorado. Phase I of the Ft. Lupton project, representing 122
MWs, achieved commercial operation in June 1994. Phase II of the
project commenced operations in July 1994 bringing total on-line
capacity of the project to 272 MWs.
Mulberry
The Mulberry facility, a 117 MW gas-fired cogeneration plant in
Polk County, Florida achieved commercial operation in August 1994
and provides steam to a combined distilled water and ethanol
facility and sells electricity to Florida Power Corporation and
Tampa Electric Company. CSWS is providing engineering, procurement
and construction management services for the Mulberry project.
CSWE's operating and maintenance division is operating the plant.
On December 30, 1994, the borrower, Polk Power Partners, L.P., in
which CSWE is indirectly a 50% owner, was notified it was in
technical default under the third party financing documents since
substantial completion of the Mulberry Ethanol facility had not
occurred by December 30, 1994. CSWE is in the process of discussing
with the lender means of curing the technical default. Management
does not expect this matter to have a material effect on CSW's
consolidated results of operations or financial condition.
Orange Cogen
The Orange Cogen facility, in which CSWE holds a 50% interest,
is expected to commence operation in June 1995. The 103 MW, gas
fired plant in Florida will provide thermal energy to an orange
juice processor and will sell electricity to Florida Power
Corporation and Tampa Electric Company. CSWE's O&M division plans
to operate the plant.
Oildale
In November 1994, CSWE transferred its 50% interest in the 40
MW Oildale cogeneration facility to two non-affiliated third
parties, Oildale Holdings, Inc. and Oildale Holdings II, Inc. The
Oildale project, which was financed with third-party non-recourse
project financing, had been in default of certain provisions of its
loan agreement since December 1993. Under the terms of the project
transfer, CSWE contributed $3 million in equity in exchange for the
return of a letter of credit in the same amount in favor of a third
party lender. CSWE had reserved for this liability in 1993,
therefore, this transaction has no material adverse effect on CSW's
or CSWE's 1994 results of operations or financial condition.
1-46
Other Projects
In addition to these projects, CSWE has another 19 projects
totaling more than 5,000 MW in various stages of development, mostly
in affiliation with other developers. CSWE can provide no
assurances that these projects, which are subject to further
negotiations and regulatory approvals, will be commenced or
completed and, if they are completed, that they will provide the
anticipated return on investment.
As a result of its participation in these projects, CSWE has
contractual commitments to provide certain services and support.
These commitments provide that the potential maximum liability of
CSWE will be limited to $215 million. Management believes the
likelihood of material liabilities under these contracts is remote.
The following table sets forth information about cogeneration
projects CSWE is currently operating or bringing to operation:
Capacity Commercial Ownership CSWE
Project Location (in MW) Capital Cost Fuel Operation Date Interest Role(1)
(millions)
Brush II Brush, CO 68 $ 82 Gas January 1994 47% OS
Thermo Ft. Lupton, CO 272 $226 Gas June 1994 50% OS
Mulberry Polk County, FL 117 $170 Gas August 1994 50% E,OS,O
Orange Cogen Polk County, FL 103 $121 Gas June 1995(2) 50% OS,O
(1) E=Engineering, Procurement and Construction; OS=Owner Support; O=O&M.
(2) No assurances can be given as to the actual commercial operation
date.
CSWI
In November 1994, CSWI, a wholly-owned subsidiary of CSW, was
formed to engage in international activities including developing,
acquiring, financing and owning the securities of exempt wholesale
generators and foreign utility companies.
In 1994, CSWI continued the Mexico initiative that CSW began in
1992. CSWI's goal is to participate in providing for Mexico's
future electric power needs. The geographical location of the CSW
System offers opportunities to provide bulk power sales to Mexico.
The Mexico City office of CSW allows CSWI greater access to key
Mexican markets, permitting CSWI to more readily evaluate
opportunities as they become available. However, the recent
devaluation of the Mexican peso will slow previously projected power
demand for the near-term.
CSWI is also evaluating energy-related projects in other
international markets.
CSW Communications
In July 1994, CSW Communications, a wholly-owned subsidiary of
CSW, was formed to provide communication services to the Operating
Companies and non-affiliates. One important goal of CSW
Communications is to enhance services to CSW System customers
through fiber optics and other telecommunications technologies. CSW
Communications will consolidate the future design, construction,
maintenance and ownership of the CSW System's telecommunications
networks. In 1994, CSW announced a $9 million project in Laredo,
Texas, to install fiber optic lines and coaxial cable to CPL
residential customers who have volunteered to take part in this
pilot program. This project involving CSW Communications and CPL
will demonstrate the energy efficiency and cost savings that result
from giving customers greater choice and control over their electric
service. These energy-efficiency services will use only a portion
of the capacity of the telecommunications lines CSW Communications
is installing. In the future, CSW Communications may, subject to
any required regulatory approvals, seek to lease or otherwise use
the remaining capacity for other services including possibly
telephone service, cable television and home security systems.
1-47
ITEM 2. PROPERTIES.
CSW, CPL, PSO, SWEPCO and WTU
See ITEM 1. BUSINESS - UTILITY OPERATIONS - Facilities for a
description of properties used in utility operations.
See ITEM 1. BUSINESS - Transok and CSWE for a description of
properties used in non-utility operations.
ITEM 3. LEGAL PROCEEDINGS.
CSW, CPL, PSO, SWEPCO and WTU
The registrants are 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 registrants' results of operations or financial
condition.
See ITEM 1. BUSINESS - REGULATION AND RATES, ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS and ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA - CSW NOTE 10, CPL NOTE 9, PSO NOTE 8, SWEPCO NOTE
9, and WTU NOTE 9, Litigation and Regulatory Proceedings, for
information relating to legal and regulatory proceedings.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS for each of the registrants, for
information related to fuel settlements.
See ITEM 1. BUSINESS - ENVIRONMENTAL MATTERS and ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - Recent Developments and Trends for each of
the registrants, for information relating to environmental
proceedings.
CSW and CPL
See ITEM 1. BUSINESS - NUCLEAR - STP, ITEM 7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -
CSW NOTE 10 and CPL NOTE 9, Litigation and Regulatory Proceedings,
for information as to pending legal proceedings relating to STP.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
CSW, CPL, PSO, SWEPCO and WTU
None.
2-1
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
CSW
Common Stock Price Range and Dividends Paid per Share
1994 1993
Market Price Dividends Market Price Dividends
High Low Paid High Low Paid
(cents) (cents)
First Quarter $30 7/8 $24 1/8 42.5 $33 1/4 $28 5/8 40.5
Second Quarter 26 1/4 20 1/8 42.5 34 1/4 28 3/4 40.5
Third Quarter 23 1/4 20 7/8 42.5 33 7/8 32 1/4 40.5
Fourth Quarter 23 3/4 20 1/8 42.5 33 28 1/4 40.5
Common Stock Listing
CSW's common stock is traded under the ticker symbol CSR and
listed on the New York Stock Exchange, Inc. and Chicago Stock
Exchange, Inc.
Common Stock Dividends
Dividends of 42.5 cents a share were paid in each quarter of
1994. All dividends paid by CSW represent taxable income to
stockholders for federal income tax purposes.
In January 1995, CSW's board of directors increased the quarterly
dividend to 43 cents per share, payable on February 28, 1995, to
stockholders of record on February 8, 1995. Traditionally, the CSW
board of directors has declared dividends to be payable on the last
business day of February, May, August, and November. CSW has stated
that it is committed to achieving a 75% payout ratio in the long-term
as a key component of its corporate strategy to maximize stockholder
value.
Stockholders
There were approximately 74,000 record holders of CSW's common
stock as of December 31, 1994.
CPL, PSO, SWEPCO and WTU
All of the outstanding shares of common stock of CPL, PSO, SWEPCO
and WTU are owned by CSW.
ITEM 6. SELECTED FINANCIAL DATA.
Reference is made to the page numbers noted in the following table for
the location of ITEM 6. SELECTED FINANCIAL DATA, which is included in
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page Number
CSW CPL PSO SWEPCO WTU
Selected Financial Data 2-6 2-70 2-106 2-132 2-160
2-2
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Reference is made to the page numbers noted in the following table for
the location of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS which is included in
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page Number
CSW CPL PSO SWEPCO WTU
Management's Discussion and
Analysis of Financial Condition 2-7 2-71 2-107 2-133 2-161
2-3
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page
CSW
Central and South West Corporation 2-5
Selected Financial Data 2-6
Management's Discussion and Analysis of Financial
Condition and Results of Operations 2-7
Consolidated Statements of Income 2-26
Consolidated Statements of Retained Earnings 2-27
Consolidated Balance Sheets 2-28
Consolidated Statements of Cash Flows 2-30
Notes to Consolidated Financial Statements 2-31
Report of Independent Public Accountants 2-67
Report of Management 2-68
CPL
Central Power and Light Company 2-69
Selected Financial Data 2-70
Management's Discussion and Analysis of Financial
Condition and Results of Operations 2-71
Statements of Income 2-81
Statements of Retained Earnings 2-82
Balance Sheets 2-83
Statements of Cash Flows 2-85
Statements of Capitalization 2-86
Notes to Financial Statements 2-87
Report of Independent Public Accountants 2-103
Report of Management 2-104
PSO
Public Service Company of Oklahoma 2-105
Selected Financial Data 2-106
Management's Discussion and Analysis of Financial
Condition and Results of Operations 2-107
Consolidated Statements of Income 2-113
Consolidated Statements of Retained Earnings 2-114
Consolidated Balance Sheets 2-115
Consolidated Statements of Cash Flows 2-117
Consolidated Statements of Capitalization 2-118
Notes to Consolidated Financial Statements 2-119
Report of Independent Public Accountants 2-129
Report of Management 2-130
2-4
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. (continued)
SWEPCO
Southwestern Electric Power Company 2-131
Selected Financial Data 2-132
Management's Discussion and Analysis of Financial
Condition and Results of Operations 2-133
Statements of Income 2-141
Statements of Retained Earnings 2-142
Balance Sheets 2-143
Statements of Cash Flows 2-145
Statements of Capitalization 2-146
Notes to Financial Statements 2-147
Report of Independent Public Accountants 2-157
Report of Management 2-158
WTU
West Texas Utilities Company 2-159
Selected Financial Data 2-160
Management's Discussion and Analysis of Financial
Condition and Results of Operations 2-161
Statements of Income 2-169
Statements of Retained Earnings 2-170
Balance Sheets 2-171
Statements of Cash Flows 2-173
Statements of Capitalization 2-174
Notes to Financial Statements 2-175
Report of Independent Public Accountants 2-186
Report of Management 2-187
2-5
CSW
CENTRAL AND SOUTH WEST CORPORATION
2-6
Selected Financial Data
CSW
The following selected financial data for each of the five years
ended December 31 are provided to highlight significant trends in the
financial condition and results of operations for CSW.
1994 1993 1992 1991 1990
(millions, except per share amounts and ratios)
Operating Revenues $ 3,623 $ 3,687 $ 3,289 $ 3,047 $2,744
Income Before Cumulative Effect
of Changes in Accounting Principles 412 281 404 401 386
Cumulative Effect of
Changes in Accounting Principlies (1) -- 46 -- -- --
Net Income 412 327 404 401 386
Preferred Stock Dividends 18 19 22 26 30
Dividends
Net Income for Common Stock 394 308 382 375 356
Total Assets (2) 10,909 10,604 9,829 9,396 9,074
Common Stock Equity 3,052 2,930 2,927 2,834 2,743
Preferred Stock
Not Subject to Mandatory
Redemption 292 292 292 292 291
Subject to Mandatory Redemption 35 58 75 97 103
Long-term Debt 2,940 2,749 2,647 2,518 2,513
Capitalization Ratios
Common Stock Equity 48.3% 48.6% 49.3% 49.4% 48.5%
Preferred Stock 5.2 5.8 6.2 6.8 7.0
Long-term Debt 46.5 45.6 44.5 43.8 44.5
Earnings per Share of Common Stock $2.08 $1.63 $2.03 $1.99 $1.89
Dividends Paid per Share of
Common Stock $1.70 $1.62 $1.54 $1.46 $1.38
(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 and the
adoption of SFAS No. 109, Accounting for Income Taxes. See NOTE 1.
Summary of Significant Accounting Policies.
(2) The 1992 - 1990 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.
All common stock data have been adjusted to reflect the two-for-one
common stock split, effected by a 100% stock dividend paid on March 6,
1992, to stockholders of record on February 10, 1992.
CSW 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 reported for prior years and therefore have not been
restated.
2-7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
CENTRAL AND SOUTH WEST CORPORATION
Reference is made to CSW's Consolidated Financial Statements and
related Notes and Selected Financial Data. The information contained
therein should be read in conjunction with, and is essential in
understanding, the following discussion and analysis.
Overview
The electric utility industry is changing rapidly and becoming
more competitive. Several years ago, in anticipation of increasing
competition and fundamental changes in the industry, CSW's management
developed a four-part strategic plan. This plan is designed to help
position CSW to be competitive in the rapidly changing environment
that the CSW System currently faces. The four-part strategy is:
Enhance CSW's core electric utility business.
Expand CSW's core electric utility business.
Expand CSW's non-utility business.
Pursue financial initiatives.
Since the introduction of CSW's strategic plan in 1990, CSW has
undertaken initiatives in each of these areas that are important steps
in the implementation of the overall strategy. These initiatives were
marked by the efforts in the proposed acquisition of El Paso and the
continued restructuring of CSW's core business. In addition, CSW has
faced some operational challenges during the past two years with the
outage and 1994 restart of STP. These events are discussed below and
elsewhere in this report.
CSW and the Electric Operating Companies believe that, compared
to other electric utilities, the CSW System is well positioned to meet
future competition. The CSW System benefits from economies of scale
and scope by virtue of its size and is a relatively low-cost producer
of electric power. Moreover, CSW is taking steps to enhance its
marketing and customer service, reduce costs, improve and standardize
business practices, and grow through strategic acquisitions, in order
to position itself for increased competition in the future.
Proposed Acquisition of El Paso
El Paso filed a voluntary petition for reorganization under
Chapter 11 of the Bankruptcy Code on January 8, 1992. In May 1993,
CSW entered into a Merger Agreement pursuant to which El Paso would
emerge from bankruptcy as a wholly-owned subsidiary of CSW. El Paso
is an electric utility company headquartered in El Paso, Texas,
engaged principally in the generation and distribution of electricity
to approximately 262,000 retail customers in west Texas and southern
New Mexico. El Paso also sells electricity under contract to
wholesale customers in a number of locations including southern
California and Mexico.
On July 30, 1993, El Paso filed the Modified Plan and a related
proposed form of disclosure statement providing for the acquisition
of El Paso by CSW. On November 15, 1993, all voting classes of
creditors and shareholders of El Paso voted to approve the Modified
Plan. On December 8, 1993, the Bankruptcy Court confirmed the
Modified Plan.
Under the Modified Plan, the total value of CSW's offer to
acquire El Paso is approximately $2.2 billion. The Modified Plan
generally provides for El Paso creditors and shareholders to receive
shares of CSW Common, cash and/or securities of El Paso, or to have
2-8
their claims cured and reinstated. The Modified Plan also provides
for claims of secured creditors generally to be paid in full with
debt securities of reorganized El Paso, and for unsecured creditors
to receive a combination of debt securities of reorganized El Paso
and CSW Common equal to 95.5 percent of their claims, and for small
trade creditors to be paid in full with cash. The Modified Plan
provides for El Paso's preferred shareholders to receive preferred
shares of reorganized El Paso, or cash, and for options to purchase
El Paso Common to be converted into options to purchase a
proportionate number of shares of CSW Common.
Based on information provided by El Paso, 35,544,330 shares of
El Paso Common were outstanding as of the Confirmation Date. The
Modified Plan provides for El Paso's common shareholders to receive
between $3.00 and $4.50, plus dividends, per share of El Paso Common
to be paid in CSW Common as described below. The Merger Agreement
provides for each share of El Paso Common to be converted on the
Effective Date into the number of shares of CSW Common with a value
(based on a value of $29.4583 per share of CSW Common) equal to the
sum of (i) $3.00 per share of El Paso Common outstanding on the
Confirmation Date, (ii) any proceeds received by El Paso prior to the
Effective Date from certain contingent claims based on a value of CSW
Common equal to the closing price on the New York Stock Exchange on
the day such proceeds are received by El Paso, and (iii) the
dividends that would be deemed to have been paid on the amounts
described in items (i) and (ii) above from the Confirmation Date, or
the date upon which such contingent claims are converted into cash,
as the case may be, through and including the Effective Date, as well
as dividends that would have been paid on such dividends under (iii)
above; provided, however, that the sum of (i) and (ii) above will not
exceed $4.50 multiplied by the number of shares of El Paso Common
outstanding on the Confirmation Date. If $4.50 per share of El Paso
Common has not been realized under items (i) and (ii) above and any
of the contingent claims are remaining on the Effective Date, the
Modified Plan and Merger Agreement provide for a liquidation trust to
be established pursuant to the Modified Plan and for El Paso's rights
in those contingent claims to be assigned to the trust. The Modified
Plan provides for proceeds resulting from disposition of the assets
in the liquidation trust, if any, to be distributed pro rata to the
holders of El Paso Common up to $4.50 per share under items (i) and
(ii) above, with any net proceeds thereafter to be returned to El
Paso. El Paso has stated publicly that it has realized sufficient
proceeds from the contingent claims referred to in item (ii) above so
that no liquidation trust would be required.
The aggregate number of shares of CSW Common that would be
issued in connection with the Merger cannot be determined at this
time due to certain contingencies, including the future price of CSW
Common, future dividend rates on CSW Common and the occurrence and
timing of the Effective Date of the Merger. CSW has estimated the
value of the shares to be issued to El Paso stakeholders at
approximately $569 million based on an assumed Effective Date in the
first half of 1995. In addition, CSW expects to make payments in
cash of approximately $335 million in connection with the
consummation of the Merger, a portion of which would be funded by
cash in the El Paso estate and an estimated $200 million of which
would be funded from other internal or external sources which may
include a new issuance of CSW Common or debt securities. Depending
on the number of shares issued and the outcome of other matters
discussed below, existing holders of CSW Common could experience
short-term dilution in earnings if the Merger is consummated. As of
December 31, 1994, the price per share of CSW Common had declined by
approximately 31% since May 3, 1993, the date of the Merger
Agreement. Because the number of shares of CSW Common and the
interest rates of the debt securities that would be issued to the
creditor groups in connection with the Merger are to be set on or
about the Effective Date, changes in the price of CSW Common and the
level of interest rates would affect the economic impact of the
proposed acquisition to CSW.
The Merger is subject to numerous conditions set forth in the
Merger Agreement, including but not limited to (i) the receipt of
final orders with respect to all required regulatory approvals on
terms that would not cause a regulatory material adverse effect as
defined in the Merger Agreement, (ii) the receipt of all third party
consents, (iii) the absence of a material adverse effect or facts or
circumstances that could reasonably be expected to result in a
material adverse effect on El Paso or the business prospects of El
Paso, (iv) transfer to El Paso of good and marketable title to the
leased portion of El Paso's share of Palo Verde, (v) performance by
2-9
El Paso, CSW and CSW's acquisition subsidiary, CSW Sub, Inc., in all
material respects of all covenants contained in the Merger Agreement
and (vi) the occurrence of the Effective Date under the Modified
Plan. Required regulatory approvals and filings in connection with
the Merger include approvals of the FERC, the SEC, the Texas
Commission, the New Mexico Commission, the NRC, and filings with the
Department of Justice and the Federal Trade Commission under the Hart-
Scott-Rodino Antitrust Improvements Act of 1976.
The Merger Agreement also provides that CSW and El Paso have the
right to terminate the Merger Agreement under specified circumstances
including without limitation, (i) the filing of a stand-alone rate
plan by El Paso, (ii) the failure of the Effective Date to occur
within 18 months after the Confirmation Date (i.e., by June 8, 1995),
or , if extended by mutual consent of CSW and El Paso, within 24
months of the Confirmation Date (i.e., by December 8, 1995), or (iii)
the entering of any order denying any of the required regulatory
approvals. In the event the Merger Agreement is terminated, a
termination fee is payable in limited circumstances. El Paso is
required to pay a termination fee of $50 million to CSW if El Paso
terminates the Merger Agreement under certain circumstances and
subsequently consummates a merger with another party. CSW and El
Paso would be required to pay a $25 million termination fee to the
other party in the case of termination based upon a material breach
of the Merger Agreement or failure to approve an extension of time
permitted to consummate the Merger under specified circumstances. If
the Merger Agreement is terminated, whether or not any termination
fee is payable, CSW could be required, in most cases, to recognize as
an expense deferred costs associated with the Merger, which amounted
to approximately $36 million at December 31, 1994. Additionally,
under certain circumstances, if the Merger is not consummated, the
Merger Agreement provides for CSW to pay El Paso a portion of certain
interest costs and certain fees and expenses. CSW's potential
exposure as of December 31, 1994 is estimated to be approximately
$17.5 million; however, the actual amount, if any, that CSW may be
required to pay pursuant to these provisions depends on a number of
contingencies and cannot presently be predicted.
CSW continues to use its best efforts to consummate the Merger.
At the same time, however, CSW continues to monitor contingencies
which may preclude the consummation of the Merger, including without
limitation the potential loss of significant portions of El Paso's
service area and significant El Paso customers, including Las Cruces
and two military installations, Holloman Air Force Base and White
Sands Missile Range, regulatory risks principally related to approval
of the Merger and El Paso's request for a rate increase in Texas as
well as the effects of the conditions imposed by federal or state
regulatory agencies on the approval of the Merger, and operating
risks associated with the ownership of an interest in Palo Verde.
Based upon El Paso's written response to the concerns identified
in a September 12 letter from CSW to El Paso and the failure of El
Paso to resolve the contingencies set forth above, CSW cannot predict
whether, or if so when, the Merger will be consummated. In the event
that the proposed Merger is not consummated, there may be ensuing
litigation between El Paso and CSW or among other parties to El
Paso's bankruptcy proceedings and either or both of El Paso and CSW.
Management is unable to predict the ultimate outcome of the
proposed Merger. In the event that recognition of any or all of
these expenses is required, it could have a material adverse impact
on CSW's consolidated results of operations in the period they are
recognized, but would not be expected to have a material adverse
impact on CSW's consolidated results of operations or financial
condition.
See NOTE 11, Commitments and Contingent Liabilities - Proposed
Acquisition of El Paso, for additional information related to the
proposed El Paso merger.
Restructuring
As previously reported, the CSW System has taken steps to
implement a 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
2-10
restructuring is to enable the Electric Operating Companies to focus
on and be accountable for serving the customer. The restructuring
costs were initially estimated to be $97 million and were expensed in
1993. The final costs of the restructuring were approximately $88
million. Approximately $84 million of the restructuring expenditures
were incurred during 1994, with the remaining $4 million expected to
be incurred during 1995. Approximately $12 million of the
restructuring expenses relate to employee termination benefits, $45
million relate to enhanced benefit costs and $31 million relate to
employees that will not be terminated. Approximately $60 million of
the restructuring costs were paid from or will be paid from general
corporate funds. The remaining $28 million represents the present
value of enhanced benefit amounts to be paid from the benefit plan
trusts to participants over future years in accordance with the early
retirement program. The cost of these enhanced benefit amounts will
be paid from general corporate funds to the benefit plan trusts over
future years. The restructuring is substantially completed, with the
remaining activity to take place during 1995. Certain aspects of the
restructuring are pending SEC approval under the Holding Company Act.
CSW expects to realize a number of benefits from the
restructuring. Beginning in 1994 and continuing into the future,
increased efficiencies and synergies are expected to be realized with
the elimination of previously duplicated functions. This leads to
enhanced communication and efficiency, which should translate into a
reduction in the rate of growth in O&M costs. All restructuring
costs are expected to be recovered by early 1996 with reductions in
the rate of growth of O&M costs continuing thereafter.
STP
Introduction
CPL owns 25.2% of STP, a two-unit nuclear power plant which is
located near Bay City, Texas. In addition to CPL, 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.
From February 1993 until May 1994, STP experienced an
unscheduled outage which has resulted in significant rate and
regulatory proceedings involving CPL. These matters, including a
base rate case and fuel reconciliation proceedings, are discussed
immediately below.
STP Outage
In February 1993, Units 1 and 2 of STP were shut down by HLP in
an unscheduled outage resulting from mechanical problems. 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 that it
supplemented to identify additional issues to be resolved and
verified by the NRC before STP could be restarted.
During the outage, the necessary improvements were 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 agreed with HLP's recommendation that Unit 1 was
ready to restart. Unit 1 restarted on February 25, 1994 and reached
100% power on April 8, 1994. Subsequently, the issues with respect
to Unit 2 were resolved and the NRC on May 17, 1994 agreed with HLP's
recommendation to restart Unit 2. Unit 2 resumed operation on May
30, 1994 and reached 100% power on June 16, 1994. During 1994, Unit
1 and Unit 2 achieved annual net capacity factors of 75.3% and 54.7%,
respectively. During the last six months of 1994, the STP units
operated at capacity factors of 98.6% for Unit 1 and 99.2% for Unit
2.
In June 1993, the NRC placed STP on its "watch list" of plants
with "weaknesses that warrant increased NRC attention." The decision
to place STP on the watch list followed the June 1993 issuance of a
report by an NRC Diagnostic Evaluation Team which conducted a review
of STP operations.
On February 3, 1995, the NRC removed STP from the "watch list".
The NRC noted that the four key areas for their decision were
sustained improvement throughout 1994, high standards of performance
exhibited by the plant, effective maintenance and engineering support
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resulting in reduced equipment repair backlogs and improved plant
reliability, and the open and positive employee climate at the plant.
With the NRC reviewing the "watch list" status every 6 months and
with Unit 2 achieving 100% power in June of 1994, the February review
was the first realistic opportunity for STP to be considered for a
change in status. On average, plants previously placed on the "watch
list" have stayed on the list for 29 months.
Rates and Regulatory Matters
CPL Rate Inquiry
Several Cities, the Texas Commission General Counsel and others
initiated actions in late 1993 and early 1994 which, if approved by
the Texas Commission, would lower CPL's base rates. The requests for
a review of CPL's rates arose out of the unscheduled outage at STP
which began in February 1993. The STP outage did not affect CPL's
ability to meet customer demand because of existing capacity and
CPL's purchase of additional energy.
CPL submitted a filing package on July 1, 1994, to the Texas
Commission justifying its current base rate structure. Parties to
CPL's base rate case have filed testimony with the Texas Commission
recommending reductions in CPL's retail base rates of up to $147
million annually, resulting from a combination of proposed rate base
and cost of service reductions, as well as a rate base disallowance
of up to $400 million.
The Texas Commission held hearings in November and December
1994, and all parties have filed briefs in the case. The ALJ is
expected to issue a recommended order for consideration by the Texas
Commission in April 1995 with a final order from the Texas Commission
expected in May 1995. Testimony filed by parties to the rate case,
including the Staff, is not binding on either the ALJ or the Texas
Commission.
CPL continues to maintain that its rates are reasonable and that
its earnings are within established regulatory guidelines. In
addition, CPL strongly believes that 100 percent of its investment in
both units of STP belongs in rate base. This belief is based on,
among other factors, Units 1 and 2 providing output at high capacity
factors since April and June 1994, respectively. In addition, the
long-term benefits nuclear generation provides to customers further
support their inclusion in rate base. Furthermore, there are no
Texas Commission precedents addressing the removal of a nuclear plant
from rate base as a performance disallowance. Assuming both units of
STP are included in rate base, CPL believes it is not collecting
excessive revenues, notwithstanding that market rates of return on
common equity are generally lower today than they were in 1990 and
1991, when CPL's base rates were last set.
CPL Fuel
Pursuant to the substantive rules of the Texas Commission, CPL
generally is allowed to recover its fuel costs through a fixed fuel
factor. These fuel factors are in the nature of temporary rates, and
CPL'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
from revenues, with a corresponding entry to unrecovered fuel costs
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.
CPL is currently involved in two proceedings before the Texas
Commission relating to the recovery of fuel and purchased power
costs. CPL originally filed Docket No. 12154 seeking approval of a
customer surcharge to recover fuel and purchased power costs,
including those resulting from the STP outage. In Docket No. 13126,
the Texas Commission General Counsel and others are reviewing the
prudence of management activities at STP. In November 1994, CPL
filed a fuel reconciliation case in Docket No. 13650 with the Texas
Commission seeking to reconcile fuel costs since March 1, 1990,
including the period during which CPL's fuel and purchased power
costs were increased due to the STP outage. At December 31, 1994,
CPL's under-recovered fuel balance was $54.1 million, exclusive of
interest, which was due primarily to the STP outage. If a
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significant portion of the fuel costs were disallowed by the Texas
Commission, CSW could experience a material adverse effect on its
consolidated results of operations in the year of disallowance but
not on its financial condition. Finally, in Docket No. 13126, the
Texas Commission General Counsel is reviewing the prudence of
management activities at STP. On January 4, 1995, Docket No. 12154
was consolidated into Docket No. 13650. The results of the prudence
inquiry in Docket No. 13126 are expected to be incorporated into the
fuel reconciliation proceedings in Docket No. 13650.
CPL continues to negotiate with the intervening parties to
resolve these matters through settlement. However, no settlement has
been reached to date.
Management cannot predict the ultimate outcome of these
regulatory proceedings. However, management believes that the
ultimate resolution of the various issues will not have a material
adverse effect on CSW's consolidated results of operations or
financial condition.
See NOTE 10, Litigation and Regulatory Proceedings - CPL, STP,
for a discussion of regulatory proceedings arising out of the STP
outage and background on STP rate orders and deferred accounting.
Nuclear Decommissioning
CPL's decommissioning costs are accrued and funded to an
external trust over the expected service life of the STP units. The
existing NRC operating licenses will allow the operation of STP Unit
1 until 2027, and Unit 2 until 2028. The accrual is an annual level
cost based on the estimated future cost to decommission STP,
including escalations for expected inflation to the expected time of
decommissioning and is net of expected earnings on the trust fund.
The staff of the SEC has questioned certain of the current
accounting practices of the electric utility industry regarding the
recognition, measurement and classification of decommissioning costs
for nuclear generating stations. In response to these questions, FASB
has agreed to review the accounting for removal costs, including
decommissioning. If current electric utility industry accounting
practices for such decommissioning are changed, (i) annual provisions
for decommissioning could increase, (ii) the estimated cost for
decommissioning could be recorded as a liability rather than as
accumulated depreciation, and (iii) trust fund income from the
external decommissioning trusts could be reported as investment income
rather than as a reduction to decommissioning expense.
See NOTE 1, Summary of Significant Accounting Policies - Nuclear
Decommissioning, for further information regarding CPL's
decommissioning of STP.
See NOTE 10, Litigation and Regulatory Proceedings, for
information regarding other rate and regulatory matters, including the
PSO rate case, the SWEPCO fuel reconciliation, and WTU's fuel and rate
proceedings.
New Accounting Standards
SFAS No. 115, was effective for fiscal years beginning after
December 15, 1993. CSW adopted SFAS No. 115 in 1994. The adoption of
SFAS No. 115 did not have a material effect on CSW's consolidated
results of operations or financial condition.
In June 1993 the FASB issued SFAS No. 116. The statement,
effective for fiscal years beginning after December 15, 1994, will be
adopted by CSW for 1995. The statement establishes accounting
standards for contributions and applies to all entities that receive
or make contributions. Management does not believe the adoption of
SFAS No. 116 will have a material impact on CSW's consolidated results
of operations or financial condition.
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SFAS No. 119 was effective for fiscal years ending after December
15, 1994. Transok, which is the only subsidiary of CSW currently
using derivative financial instruments, uses derivatives to manage
price and market risks for gas purchases and sales. The Electric
Operating Companies may use these instruments in the future to manage
the increased market risks associated with greater competition in the
electric utility industry. The adoption of this new statement had no
material effect on CSW's consolidated results of operations or
financial condition.
Liquidity and Capital Resources
Overview
The historical capital requirements of the CSW System have been
primarily for the construction of electric utility plant. Large
capital expenditures for the construction of new generating capacity
are not planned through the end of this decade. Accordingly,
internally generated funds should meet most of the capital
requirements of the Electric Operating Companies. However, CSW's
strategic initiatives, including expanding CSW's core electric utility
and non-utility businesses, may require additional capital. Primary
sources of capital are long-term debt and preferred stock issued by
the Electric Operating Companies, common stock issued by CSW and
internally generated funds. In addition, CSWE uses various forms of
non-recourse project financing. CSW, in order to strengthen its
capital structure and support growth from time to time, may issue
additional shares of its common stock.
Productive investment of net funds from operations in excess of
capital expenditures and dividend payments are necessary to enhance
the long-term value of CSW for its investors. CSW is continually
evaluating the best use of these funds. CSW is required to obtain
authorization from various regulators in order to invest in any
additional business activities.
Capital Expenditures
Construction expenditures for the CSW System totaled $578 million
in 1994. Based on projections of growth in peak demand, the CSW
System will not require significant additional generating capability
through the end of this decade. Planned construction expenditures for
the Electric Operating Companies for the next three years are
primarily to improve and expand distribution facilities. These
improvements will be required to meet the needs of new customers and
the growth in the requirements of existing customers. Construction
expenditures, excluding capital required for acquisitions by CSW or
its subsidiaries, if any, are expected to be approximately $385
million, $382 million and $358 million during 1995, 1996, and 1997,
respectively. Not included in the 1995 amount is approximately $61
million of equity investments by CSWE.
The construction program continues to be monitored, reviewed and
adjusted to reflect changes in estimated load growth in the Electric
Operating Companies' service areas, variations in prices of
alternative fuel sources, the cost of labor, materials, equipment and
capital, and other external factors.
The CSW System facilities plan presently includes projected coal
and lignite-fired generating plants for which the CSW System has
invested approximately $140 million in prior years for plant sites,
engineering studies and lignite reserves. Should future plans exclude
these plants for environmental or other reasons, CSW would evaluate
the probability of recovery of these investments and may record
appropriate reserves.
Long-Term Financing
As of December 31, 1994, the capitalization ratios of CSW were:
common stock equity 48%, preferred stock 5% and long-term debt 47%.
The CSW System's embedded cost of long-term debt was 7.7% at the end
of 1994. The CSW System continually monitors the capital markets for
opportunities to lower its cost of capital through refinancing. The
CSW System continues to be committed to maintaining financial
flexibility by maintaining a strong capital structure and favorable
securities ratings which should allow funds to be obtained from the
capital markets when required.
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The CSW System's significant long-term financing activity for
1994 and 1995 to date is summarized as follows:
Security Issued Security Reacquired
Security Amount Rate Maturity Security Amount Rate Maturity
(millions) (millions)
CPL FMB(1) $100.0 7-1/2% 1999 PFDs $22.4 10.05% --
FMB 0.6 9-3/8% 2019
SWEPCO Term Term
Loan 50.0 Floating 2000 Loan 50.0 Floating 1997
FMB 5.8 9-1/8% 2019
WTU FMB(2) 40.0 6-1/8% 2004 FMB 12.0 7-1/4% 1999
FMB(3) 40.0 7-1/2% 2000 FMB 7.8 9-1/4% 2019
PFDs 4.7 7-1/4% --
CSWS Term(4)
Loan 60.0 Floating 2001
(1) Net proceeds were used to repay a portion of CPL's short-term
borrowings.
(2) Net proceeds were used to reimburse WTU's treasury for (i) $12
million aggregate principal amount of 7-1/4% FMBs, Series G, due
January 1, 1999, redeemed on January 1, 1994, and (ii) $23 million
aggregate principal amount of 7-7/8% FMBs, Series H, due July 1,
2003, redeemed on December 30, 1993. The balance of the proceeds
were used to repay outstanding short-term borrowings.
(3) Issuance occurred in 1995 and is not reflected in the 1994
financial statements. Net proceeds were used to repay a portion of
WTU's short-term debt, to provide working capital and for other
general corporate purposes.
(4) Proceeds were used to repay short-term debt, which had been
previously used to finance certain assets, including the CSW
headquarters building in Dallas, Texas.
Shelf Registration Statements
The Electric Operating Companies expect to obtain a majority of
their 1995 capital requirements from internal sources, but may issue
additional securities subject to market conditions and other factors.
CPL and WTU have filed shelf registration statements with the SEC for
the sale of securities. The amount available for issuance by company
and the date filed with the SEC follow:
First Mortgage Bonds Preferred Stock
Amount Date Filed Amount Date Filed
Available Available
(millions) (millions)
CPL $260 1993 $75 1994
WTU $20 1993
The Operating Companies may issue additional debt securities
subject to market conditions and other factors. The proceeds of any
such offerings will be used principally to redeem higher cost FMBs, to
lower the embedded cost of debt, to repay short-term debt, to provide
working capital and for other general corporate purposes.
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The Electric Operating Companies may issue additional preferred
stock subject to market conditions and other factors. The proceeds of
any such offerings will be used principally to redeem higher cost
preferred stock and to repay short-term debt.
Short-Term Financing
The Electric Operating Companies utilize short-term debt to meet
fluctuations in working capital requirements due to the seasonal
nature of electric sales. The CSW System has established a money pool
to coordinate short-term borrowings and to make borrowings outside the
money pool through CSW's issuance of commercial paper. At December
31, 1994, the CSW System had bank lines of credit aggregating $930
million to back up the CSW commercial paper program.
The maximum amount of consolidated short-term debt outstanding in
1994 was $1,618 million in September 1994, which represented 26% of
the total capitalization at December 31, 1994. The average amount of
short-term debt during 1994 was $1,455 million, of which $694 million
was attributable to CSW Credit. The weighted average cost of short-
term debt was 4.5% in 1994. Short-term debt outstanding increased due
to continued expenditures for corporate initiatives, including
investments in CSWE.
Acquisitions
To meet its strategic goals, CSW will continue to search for
electric utility companies or other electric utility properties to
acquire and will continue evaluating opportunities to pursue energy
related non-utility businesses. For any major acquisition, additional
funds from the capital markets, including the issuance of CSW Common
in underwritten public offerings, in the acquisition transaction
itself, or otherwise, may be required.
For a discussion of circumstances under which CSW may issue
additional shares of common stock in connection with the proposed
acquisition of El Paso, see Proposed Acquisition of El Paso, above.
Dividend Reinvestment Plan
The PowerShare dividend reinvestment plan is available to all CSW
stockholders, employees, eligible retirees, utility customers and
other residents of the four states where the Electric Operating
Companies operate. Plan participants are able to make optional cash
payments and reinvest all or any portion of their dividends in CSW
Common. During 1994 CSW raised approximately $50 million in new
equity through the PowerShare plan.
Internally Generated Funds
Internally generated funds consist of cash flows from operating
activities less common and preferred stock dividends. The Electric
Operating Companies utilize short-term debt to meet fluctuations in
working capital requirements due to the seasonal nature of energy
sales. Information concerning internally generated funds follows:
1994 1993 1992
(millions)
Internally Generated Funds $424 $369 $374
Capital expenditures, Acquisitions, CSWE
Equity Investments Provided by Internally
Generated Funds 63% 58% 82%
CSWE and CSWI
At December 31, 1994, CSW had loaned $221 million to CSWE on an
interim basis for the purpose of developing and constructing
independent power and cogeneration facilities. Repayment of these
amounts to CSW is expected to be made through funds obtained from
third party non-recourse project financing. In late February 1994,
CSWE closed permanent project financing for its 50% owned Mulberry
facility, which is described below, and repaid $94 million of the
interim financing provided by CSW. In March 1995, CSWE closed
permanent project financing for its Ft. Lupton facility, which is
described below, and repaid $102 million of the interim financing
provided by CSW. In addition to the amounts already expended in 1994
for the development of projects, CSWE and CSWI have general authority
from the SEC to expend up to $242 million and $399 million,
respectively, on future projects.
CSW Credit
CSW Credit purchases, without recourse, the accounts receivable
of the Operating Companies and certain non-affiliated electric
companies. CSW Credit's capital structure contains greater leverage
than that of the Operating Companies, consequently lowering CSW's cost
of capital.
CSW Credit issues commercial paper, secured by the assignment of
its receivables, to meet its financing needs. CSW Credit maintains a
secured revolving credit agreement which aggregated $900 million at
December 31, 1994 to back up its commercial paper program.
The sale of these accounts receivables provides the Operating
Companies with cash immediately, thereby reducing working capital
needs and revenue requirements.
Recent Developments and Trends
Competition and Industry Challenges
Competitive forces at work in the electric utility industry are
impacting the CSW System and electric utilities generally. Increased
competition facing electric utilities is driven by complex economic,
political and technological factors. These factors have resulted in
legislative and regulatory initiatives that are likely to result in
even greater competition at both the wholesale and retail level in the
future. As competition in the industry increases, the Electric
Operating Companies will have the opportunity to seek new customers
and at the same time be at risk of losing customers to other
competitors. The Electric Operating Companies believe that their
prices for electricity and the quality and reliability of their
service currently place them in a position to compete effectively in
the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly
alters the way in which electric utilities compete. The Energy Policy
Act creates exemptions from regulation under the Holding Company Act
and permits utilities, including registered utility holding companies
and non-utility companies, to form EWGs. EWGs are a new category of
non-utility wholesale power producer that are 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. The Energy Policy Act also 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. A FERC order requiring a transmitting utility
to provide wholesale transmission service must include provisions
generally that permit (i) the utility to recover from the FERC
applicant all of the costs incurred in connection with the
transmission services and (ii) any enlargement of the transmission
system and associated services. While CSW believes that the Energy
Policy Act will continue to make the wholesale markets more
competitive, CSW is unable to predict the extent to which the Energy
Policy Act will impact CSW System operations.
Increasing competition in the utility industry brings an
increased need to stabilize or reduce rates. The retail regulatory
environment is beginning to shift from traditional rate base
regulation to incentive regulation. Incentive rate and performance-
based plans encourage efficiencies and increased productivity while
permitting utilities to share in the results. Retail wheeling, a
major industry issue which may require utilities to "wheel" or move
power from third parties to their own retail customer, is evolving
gradually.
The Electric Operating Companies also compete with suppliers of
alternative forms of energy, such as natural gas, fuel oil and coal,
some of which may be cheaper than electricity. The Electric Operating
Companies believe that their prices and the quality and reliability of
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their service currently places them in a position to compete
effectively in the marketplace.
Wholesale energy markets, including the market for wholesale
electric power, have been extremely competitive since the enactment of
the Energy Policy Act. The Electric Operating Companies compete in
the wholesale energy markets with other public utilities,
cogenerators, qualified facilities, exempt wholesale generators and
others for sales of electric power.
Under the Energy Policy Act, the FERC has approved several
proposals by utility companies to sell wholesale power at market-based
rates and provide to electric utilities "open access" to transmission
systems, subject to certain requirements. The adoption of these
proposals increases marketing opportunities for electric utilities,
but also exposes them to the risk of loss of load or reduced revenues
due to competition with alternative suppliers. In 1993, PSO and
SWEPCO filed with the FERC tariffs under which they make available
firm and non-firm transmission services for other electric utilities
on the combined PSO and SWEPCO transmission systems in the Southwest
Power Pool. The FERC accepted the tariffs for filing on November 9,
1993. In the event the FERC approves the Merger between CSW and El
Paso and denies CSW's request for rehearing wherein CSW asked FERC to
reconsider the imposition of a comparable service requirement, these
tariffs could be superseded by a set of compliance tariffs which offer
point-to-point and network transmission service on terms and
conditions comparable to CSW's and El Paso's use of their own
transmission systems. As discussed, compliance tariffs could expose
the merged CSW System to additional risks of loss of load from current
requirements wholesale customers purchasing power from alternative
suppliers or reduced revenue resulting from competition with
alternative suppliers of electric power.
CSW and the Electric Operating Companies believe that, compared
to other electric utilities, the CSW System is well positioned to meet
future competition. The CSW System benefits from economies of scale
and scope by virtue of its size and is a relatively low-cost producer
of electric power. Moreover, CSW is taking steps to enhance its
marketing and customer service, reduce costs, improve and standardize
business practices, and grow through strategic acquisitions, in order
to position itself for increased competition in the future.
CSW is unable to predict the ultimate outcome or impact of
competitive forces on the electric utility industry or the CSW System.
As the wholesale and retail electricity markets become more
competitive, however, the principal factor determining success is
likely to be price, and to a lesser extent, reliability, availability
of capacity, and customer service.
Public Utility Regulatory Act
PURA is the legal foundation for electric utility regulation in
Texas. PURA will expire on September 1, 1995, in accordance with the
sunset policy of the Texas Legislature, which applies to all state
agencies, unless the Texas Legislature reenacts PURA in its current
form or in modified form. Several proposals have been made to amend
PURA which, among other things, provide for a market-driven integrated
resource planning process, pricing flexibility for utilities faced
with competitive challenges, incentive regulation and deregulation of
the wholesale bulk power market in ERCOT. CSW is unable to predict
the ultimate outcome of the 1995 session of the Texas Legislature and
in particular whether amendments to PURA will be adopted. If,
however, the Texas Legislature passes legislation permitting any form
of retail wheeling, such legislation could have an adverse impact on
CPL and CPL's sales to its retail customers.
Regulatory Accounting
Consistent with industry practice and the provisions of SFAS No.
71, which allows for the recognition and recovery of regulatory
assets, the Electric Operating Companies have recognized significant
regulatory assets and liabilities. Management believes that the
Electric Operating Companies will continue to meet the criteria for
following SFAS No. 71. However, in the event the Electric Operating
Companies no longer meet the criteria for following SFAS No. 71, a
write-off of regulatory assets and liabilities would be required. For
additional information regarding SFAS No. 71 reference is made to NOTE
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1, Summary of Significant Accounting Policies - Regulatory Assets and
Liabilities.
Holding Company Act
The Holding Company Act generally has been construed to limit the
operations of a registered holding company to a single integrated
public utility system, plus such additional businesses as are
functionally related to such system. Among other things, the Holding
Company Act requires CSW and its subsidiaries to seek prior SEC
approval before effecting mergers and acquisitions or pursuing other
types of non-utility initiatives. Pervasive regulation under the
Holding Company Act may impede or delay CSW's efforts to achieve its
strategic and operating objectives, including its pursuit of non-
utility initiatives. CSW is continuing its efforts to repeal or
modify the Holding Company Act in order to provide the flexibility to
compete within the changing environment.
Consolidated Taxes
The Texas Commission before 1992 allowed income taxes to be
recovered in rates based on the federal income tax incurred by a
utility as if it were a stand-alone company. This stand-alone
approach treated the regulated activities of a utility as a separate
entity and considered only those revenues and expenses that are
included in the utility's cost of service to calculate the federal
income tax liability for ratemaking purposes.
Beginning in 1992, the Texas Commission changed its method of
calculating the federal income tax component of rates to the "actual
tax approach." The actual tax approach is an evolving concept but
generally seeks to reflect in rates the actual tax liability of the
utility irrespective of its relationship to the utility's cost of
service. The approach reduces rates by the tax benefits of deductions
which are not considered for or included in setting rates for the
utility.
The Texas Commission is expected to use the actual tax approach
for calculating the recovery of federal income tax in the pending rate
cases for CPL and WTU. The impact of the actual tax approach on the
prospective rates for CPL and WTU cannot be determined since the
application of the concept is unsettled.
CSW believes that the recovery of federal income taxes in rates
should be determined on the stand-alone approach for ratemaking
purposes, but there is no assurance this approach will be adopted in
the pending CPL or WTU rate cases or the pending El Paso rate and
Merger cases.
Environmental Matters
CERCLA and Related Matters
The operations of the CSW System, like those of other utility
systems, generally involve the use and disposal of substances subject
to environmental laws. The 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. PRPs include owners and
operators of contaminated sites and transporters and/or generators of
hazardous substances. 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 Electric Operating Companies are subject to various pending
claims alleging that they are PRPs under federal or state remedial
laws for investigating and cleaning up contaminated property. CSW
anticipates that resolution of these claims, individually or in the
aggregate, will not have a material adverse effect on CSW's
consolidated results of operations or financial condition. Although
the reasons for this expectation differ from site to site, factors
that are the basis for the expectation for specific sites include the
volume and/or type of waste allegedly contributed by the Electric
Operating Company, the estimated amount of costs allocated to the
Electric Operating Company and the participation of other parties.
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MGPs
Contaminated former MGPs are a type of site which utilities, and
others, may have to remediate in the future under Superfund or other
federal or state remedial programs. Gas was manufactured at MGPs from
the mid-1800s to the mid-1900s. In some cases, utilities and others
have faced potential liability for MGPs because they, or their alleged
predecessors, owned or operated the plants. In other cases, utilities
or others may have been subjected to such liability for MGPs because
they acquired MGP sites after gas production ceased.
Suspected MGP Site in Marshall, Texas
SWEPCO owns a suspected former MGP site in Marshall, Texas.
SWEPCO has notified the TNRCC that evidence of contamination has been
found at the site. As a result of sampling conducted at the end of
1993 and early 1994, SWEPCO is evaluating the extent, if any, to which
contamination has impacted soil, groundwater and other conditions in
the area. A final range of clean-up costs has not yet been
determined, but, based on a preliminary estimate, SWEPCO has accrued
approximately $2 million as a liability for this site on SWEPCO's
books as of December 31, 1993. As more information is obtained about
the site, and SWEPCO discusses the site with the TNRCC, the
preliminary estimate may change.
Suspected MGP Site in Texarkana, Texas and Arkansas and Shreveport,
Louisiana
SWEPCO also owns a suspected former MGP site in Texarkana, Texas
and Arkansas. The EPA ordered an initial investigation of this site,
as well as one in Shreveport, Louisiana, which is no longer owned by
SWEPCO. The contractor who performed the investigations of these two
sites recommended to the EPA that no further action be taken at this
time.
Biloxi, Mississippi MGP Site
SWEPCO has been notified by Mississippi Power Company that it may
be a PRP at the former Biloxi MGP site formerly owned and operated by
a predecessor of SWEPCO. SWEPCO is working with Mississippi Power
Company to investigate the extent of contamination at this site. The
MDEQ approved a site investigation work plan and, in January 1995,
SWEPCO and Mississippi Power Company initiated sampling pursuant to
that work plan. On an interim basis, SWEPCO and Mississippi Power
Company are each paying fifty percent of the cost of implementing the
site investigation work plan. That interim allocation is subject to a
final allocation in the future. SWEPCO and Mississippi Power Company
are investigating whether there are other PRPs at the Biloxi site.
Until the extent of the contamination at the Biloxi site is
identified, it is unknown what, if any, additional investigation or
cleanup may be required.
Management does not expect these matters to have a material
effect on CSW's consolidated results of operations or financial
condition.
Clean Air Act Amendments
In November 1990, the United States Congress passed the Clean
Air Act which places restrictions on the emission of sulfur dioxide
from gas-, coal- and lignite-fired generating plants. Beginning in
the year 2000, the Electric Operating Companies will be required to
hold allowances in order to emit sulfur dioxide. EPA issues
allowances to owners of existing generating units based on historical
operating conditions. Based on the CSW System facilities plan, CSW
believes that the Electric Operating Companies' allowances will be
adequate to meet their needs at least through 2008. Public and
private markets are developing for trading of excess allowances. CSW
presently has no intention of engaging in trading of allowances, but
may seek to do so in the future if market conditions warrant and
appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source
permit program to be administered by the states. CSW estimates that
it and the Electric Operating Companies will incur approximately
$500,000 to prepare permit applications for the program.
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The Clean Air Act also directs the EPA to issue regulations
governing nitrogen oxide emissions and requires government studies to
determine what controls, if any, should be imposed on utilities to
control air toxics emissions. The impact that the nitrogen oxide
emission regulations and the air toxics study will have on CSW cannot
be determined at this time.
As a result of requirements imposed by the Clean Air Act, CSW
expects to spend an additional $4 million for annual testing of,
software modifications to, and maintenance of continuous emission
monitoring equipment from 1995 through 1997.
EMFs
Research is ongoing whether exposure to EMFs may result 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. CSW cannot predict the impact on the CSW
System 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.
See NOTE 10, Litigation and Regulatory Proceedings, for
additional discussion of environmental issues.
Non-Utility Initiatives
As indicated above, one component of CSW's four-part strategy to
meet the increasing competition and fundamental changes in the
electric utility industry is to expand CSW's non-utility business.
CSW continues to consider new business opportunities to expand its
energy related business. CSW's principal non-utility businesses are
Transok and CSWE. As discussed below, CSW recently formed CSWI to
seek opportunities internationally for investment in non-utility
generation. CSW Communications was formed to provide a communications
network for the CSW System as well as third parties. While CSW
believes that non-utility initiatives are necessary to maintain its
competitiveness and to grow in the future, there can be no assurance
as to the level of success that will be attained in these initiatives.
Transok
Transok is an intrastate natural gas gathering, transmission,
marketing and processing company that provides natural gas services to
CSW System companies, predominately PSO, and to non-affiliated gas
customers throughout the United States. Transok's natural gas
facilities are located in Oklahoma, Louisiana and Texas. It operates
gas processing plants and markets natural gas liquids produced from
those plants to various markets.
CSWE
CSWE, a wholly-owned subsidiary of CSW, is authorized to develop
various independent power and cogeneration facilities and to own and
operate such non-utility projects, subject to further regulatory
approvals. CSWE has an approximate 50% interest in the Brush, Ft.
Lupton and Mulberry facilities which achieved commercial operation in
1994.
Brush
The 68 MW Brush project, located in Brush, Colorado, achieved
commercial operation in January 1994, and provides steam and hot water
to a 15-acre greenhouse and sells electricity to Public Service
Company of Colorado.
Ft. Lupton
The Ft. Lupton project, located in Colorado, provides steam and
hot water to a 20-acre greenhouse and also sells electricity to Public
Service Company of Colorado. Phase I of the Ft. Lupton project,
representing 122 MWs, achieved commercial operation in June 1994.
Phase II of the project commenced operations in July 1994 bringing
total on-line capacity of the project to 272 MWs.
2-21
Mulberry
The Mulberry facility, a 117 MW gas-fired cogeneration plant in
Polk County, Florida achieved commercial operation in August 1994 and
provides steam to a combined distilled water and ethanol facility and
sells electricity to Florida Power Corporation and Tampa Electric
Company.
Orange Cogen
The Orange Cogen facility, in which CSWE holds a 50% interest, is
expected to commence operation in June 1995. The 103 MW, gas-fired
plant in Florida will provide thermal energy to an orange juice
processor and will sell electricity to Florida Power Corporation and
Tampa Electric Company. CSWE's O&M division plans to operate the
plant.
Other Projects
In addition to these projects, CSWE has 19 other projects
totaling more than 5,000 MW in various stages of development, mostly
in affiliation with other developers. CSWE can provide no assurances
that these projects, which are subject to further negotiations and
regulatory approvals, will be commenced or completed and, if they are
completed, that they will provide the anticipated return on
investment.
CSWI
In November 1994, CSWI, a wholly-owned subsidiary of CSW, was
formed to engage in international activities including developing,
acquiring, financing and owning the securities of exempt wholesale
generators and foreign utility companies.
In 1994, CSWI continued with the Mexico initiative that began in
1992. CSWI's goal is to participate in providing Mexico's future
electricity needs. The geographical location of the CSW System offers
opportunities to provide bulk power sales to Mexico. The Mexico City
office of CSW, opened in 1993, allows CSWI greater access to key
Mexican markets, permitting CSWI to more readily evaluate
opportunities as they become available. However, the recent
devaluation of the Mexican peso will slow previously projected power
demand for the near-term.
CSW Communications
In July 1994, CSW Communications, a wholly-owned subsidiary, of
CSW, was formed to provide communication services to the CSW System
and non-affiliates. One important goal of CSW Communications is to
enhance services to CSW System customers through fiber optics and
other telecommunications technologies. CSW Communications will
consolidate the future design, construction, maintenance and ownership
of the CSW System's telecommunications networks. In 1994, CSW
announced a $9 million project in Laredo, Texas, to install fiber
optic lines and coaxial cable to CPL residential customers who have
volunteered to take part in this pilot program. This project
involving CSW Communications and CPL will demonstrate the energy
efficiency and cost savings that result from giving customers greater
choice and control over their electric service. These energy-
efficiency services will use only a portion of the capacity of the
telecommunications lines CSW Communications is installing. In the
future, CSW Communications may, subject to any required regulatory
approvals, seek to lease the remaining capacity for other services
including possibly telephone service, cable television and home
security systems.
Results of Operations
Overview Of Results
CSW's earnings increased to $394 million or $2.08 per share in
1994 as compared to $308 million or $1.63 per share in 1993 and $382
million or $2.03 per share in 1992. The return on average common
stock equity was 13.4% in 1994 compared to 10.6% in 1993 and 13.5% in
1992. Electric operations contributed approximately 100% of total
earnings in 1994 and 1993, and 95% in 1992. In 1994, earnings at
Transok, CSWE, and CSW Credit totaling $34 million, were offset by
corporate expenditures including merger and acquisition activities and
the formation of two new subsidiaries.
2-22
Earnings increased in 1994 compared to 1993 due primarily to
higher KWH sales and natural gas operations and decreased costs
associated with the end of the outage at STP. In addition, CSWE,
which had three projects become operational during 1994, contributed
$2 million to earnings. These items were partially offset by
increased interest and depreciation and amortization expense.
Earnings in 1993 were significantly affected by several items
described below:
(millions,after-tax)
Restructuring charges $(63)
Recognition of unbilled revenues 49
Early adoption of SFAS No. 112 (9)
Adoption of SFAS No. 109 6
Establishment of reserves for
fuel and other properties (11)
Prior year tax adjustments (18)
In addition to the aforementioned items, earnings in 1993 were
below 1992 levels due to additional costs primarily associated with
the outage at STP, higher benefit costs as a result of the adoption of
SFAS No. 106, higher taxes other than income as a result of school
funding tax increases in Texas, and the increase in the federal income
tax rate from 34% to 35%. These items were partially offset by higher
KWH sales in 1993 due primarily to more normal weather than was
experienced in 1992.
Operating Revenues
Revenues decreased 2% in 1994, after increasing 12% in 1993 and
8% in 1992 from the previous years due to the following items:
Revenue Increase (Decrease)
From Prior Year
1994 1993 1992
(millions)
Base rate changes $ 7 $ 8 $ --
Fuel costs (49) 168 --
KWH sales 61 93 (25)
Natural gas (85) 107 255
Other electric and 2 22 12
diversified $(64) $398 $242
Electric Revenues
Electric revenues increased $10 million in 1994 compared to 1993.
Total KWH sales increased approximately 6%, with increases in sales
among all customer classes. During 1994, the average number of
customers increased approximately 2%. In addition to customer growth,
there was slightly more favorable weather during 1994 as compared to
1993. However, offsetting much of the increases in revenue due to KWH
sales, fuel revenues were down substantially during 1994 compared to
1993. Fuel costs incurred in the generation of electricity are
typically passed through to the customers, so decreases in fuel costs
will cause a corresponding decrease in fuel revenues. Fuel costs,
which decreased during 1994, are more fully discussed below under Fuel
and Purchased Power. Fuel revenues increased in 1993 compared to 1992
due to higher per unit costs of fuel and purchased power.
2-23
Base rates increased slightly at PSO because of changes in retail
customers' rates, and decreased due to a 3.2% interim rate reduction
at WTU implemented during the fourth quarter of 1994. Because PSO's
increased base rates, finalized in December 1993, were not
significantly higher than the interim rates that had been in effect
throughout the year, base rates had little overall change from 1993.
As part of a stipulated agreement reflecting its rate increase, PSO
agreed that it will not file for an increase in base rates until after
June 30, 1995. During late 1993 and early 1994, several parties
initiated actions, which, if approved, would lower CPL's base rates.
The review of CPL's rates arose out of the unscheduled outage at STP
as discussed above under the heading Rates and Regulatory Matters, CPL
Rate Inquiry.
For additional information on these proceedings and others, see
NOTE 10, Litigation and Regulatory Proceedings.
The percentage changes in KWH sales for the three years were as
follows:
KWH Sales Increase (Decrease)
From Prior Year
1994 1993 1992
Residential 2.9% 9.0% (4.2)%
Commercial 3.8 4.8 (1.1)
Industrial 3.6 5.5 3.1
Sales for resale 21.9 (6.6) 5.4
Total sales 5.5 4.9 0.1
KWH sales to retail customers increased in 1994 and 1993 as a
result of more favorable weather and increased residential customers.
In addition, KWH sales grew in all of the other customer classes.
SWEPCO acquired BREMCO in July 1993, and accordingly, there were
twelve months of KWH sales to these customers in 1994 compared to only
six months in 1993. Weather was more favorable in 1994 than in 1993,
while extremely mild weather was experienced in 1992. The continued
increases in industrial sales over the last three years reflect the
increased marketing efforts by the Electric Operating Companies and
the continued improvement in the economy throughout their service
areas. Sales for resale increased in 1994 because STP was operational
for most of the year, whereas in 1993, plants in the CSW System were
producing power to replace the power normally produced at STP.
The Electric Operating Companies have maintained competitive
rates in an increasingly competitive marketplace. Efforts have
increased at each of the Electric Operating Companies to attract new
customers while efficiently serving all customers. Economic
conditions in the service areas of the Electric Operating Companies
are expected to continue to improve in 1995.
Natural Gas Revenues
Revenues from natural gas decreased 14% in 1994 due primarily to
a decrease in the price of gas, even though total natural gas volumes
increased 4% from 1994 to 1993. However, lower gas sales prices were
mitigated by lower gas purchase prices, which are described below
under Gas Purchased for Resale. The lower gas sales revenues were
partially offset by both increased gathering and transportation
revenues and increased natural gas liquids processing revenues.
Gathering and transportation sales volumes increased 12% primarily as
a result of a pipeline extension completed during 1994, and gas
liquids processing volumes increased 12% during 1994. Revenues from
natural gas increased 22% in 1993 from 1992 due primarily to an
increase in sales volumes and to a lesser extent an increase in sales
prices. A portion of this increase is attributable to the acquisition
of the NGC Anadarko Gathering System in 1993. Revenue increases in
1993 from natural gas liquids are due to increased sales volumes
combined with slightly higher prices.
2-24
Other Diversified Revenues
Other diversified revenues increased 38% from 1994 as compared to
1993 due to the reclassification of CSWE's operating revenues more
fully discussed below under Other Income and Deductions. Other
diversified revenues increased substantially in 1993 as compared to
1992 because CSW Credit began factoring the receivables of a
significant non-affiliated utility in January 1993.
Fuel and Purchased Power Expense
During 1994, the Electric Operating Companies generated
approximately 95% of their electric energy requirements. During 1993
and 1992, they generated 92% and 94%, respectively. Total fuel and
purchased power expenses decreased 4% during 1994 due to a decrease in
fossil fuel costs and increased usage of lower cost nuclear fuel. The
average unit cost of fuel was $1.82 during 1994, compared to $2.11 and
$1.92 for 1993 and 1992, respectively. Several contracts with major
fuel suppliers and carriers have been recently renegotiated. These
settlements have contributed to the lower cost of fuel. In addition,
because STP restarted and Units 1 and 2 reached 100% capacity in April
and June of 1994, respectively, lower cost nuclear fuel was utilized,
whereas the 1993 outage required higher cost energy purchases to
replace STP's nuclear power. The increase in fuel and purchased power
expense in 1993 compared to 1992 is attributable to higher natural gas
costs as well as the cost of STP replacement power.
Gas Purchased for Resale/Gas Extraction and Marketing
Gas purchased for resale decreased 30% in 1994 from 1993, while
it increased 29% in 1993 from 1992. Lower gas prices caused the
decrease in 1994, including a significant portion attributable to
sales made on natural gas drawn from storage. Increased natural gas
prices and increased pipeline capacity from Transok's recent
acquisitions caused the 1993 increase. Gas extraction and marketing
expenses increased 14% in 1994 from 1993 and 19% in 1993 from 1992 due
to higher input costs associated with higher natural gas liquids
processing volumes.
Other Operating and Maintenance Expenses and Taxes
Other operating and maintenance expenses decreased 8% in 1994
compared to 1993, due primarily to the absence of expenses that were
incurred during the 1993 STP outages. In 1993, in addition to $29
million in maintenance costs associated with the STP outage, operating
expenses increased compared to 1992 due to expenses associated with
the adoption of SFAS 106, reserves taken on lignite and other
property, corporate expenditures, and other administrative and general
expenses. Federal income taxes were higher in 1994 than 1993 due to
higher pre-tax income. Federal income taxes were lower in 1993 than
1992 due to lower pre-tax income offset in part by tax adjustments and
the increase in the corporate tax rate from 34% to 35%, which was
effective retroactive to January 1, 1993. Taxes other than federal
income remained comparable in 1994 from 1993, while they increased in
1993 compared to 1992 due to school funding tax increases in Texas.
Restructuring Charges
In 1994, the original restructuring accrual of $97 million that
had been recorded in 1993 was reduced by $9 million. Accordingly, the
final costs associated with the CSW System's restructuring totaled $88
million over the two year period. For additional information on CSW's
restructuring, see Restructuring, above.
Depreciation and Amortization
Depreciation and amortization expense increased in 1994 compared
to 1993 and also 1993 compared to 1992 as a result of increases in
depreciable plant.
Inflation
Annual inflation rates, as measured by the national Consumer
Price Index, have averaged about 2.7% during the three years ended
December 31, 1994. Management believes that inflation, at these
levels, does not materially affect CSW's consolidated results of
operations or financial position. However, under existing regulatory
practice, only the historical cost of plant is recoverable from
2-25
customers. As a result, cash flows designed to provide recovery of
historical plant costs may not be adequate to replace plant in future
years.
Other Income and Deductions
Other income and deductions increased $18 million or 19% in 1994
compared to 1993, as a result of the reclassification of CSWE's
operating activities offset partially by decreased Mirror CWIP
liability amortization and the absence of adjustments recorded in 1993
associated with Transok's 1991 acquisition of TEX/CON. Prior to 1994,
CSWE was in the developmental stage of its business, so its operating
activities were classified in CSW's Other Income and Deductions.
However, in conjunction with the completion of three projects in 1994,
CSWE's revenues and expenses were classified as operating activities
in CSW's Other Diversified Revenues and Other Operating Expenses.
Both of these components had negative earnings impacts classified in
Other Income and Deductions in 1993. Other Income and Deductions
increased $11 million or 13% in 1993 from 1992 due in part to
Transok's aforementioned TEX/CON acquisition adjustments and slightly
higher Allowance for Equity Funds Used During Construction partially
offset by decreased Mirror CWIP liability amortization.
Interest Expense
Interest expense on long-term debt in 1994 was comparable to
1993, whereas 1993 interest expense was substantially lower than 1992
due to long-term debt refinancings, which lowered CSW's embedded cost
of long-term debt from 8.3% in 1992 to 7.8% in 1993. CSW's embedded
cost of long-term debt decreased slightly to 7.7% in 1994. Short-term
interest expense increased in 1994 due primarily to higher short-term
interest rates combined with higher general corporate borrowings, and
in 1993 because of increased borrowings attributable to the expansion
of CSW Credit's business, interim financing of CSWE's projects, and
various corporate initiatives.
Cumulative Effect of Changes in Accounting Principles
In 1993, CSW implemented SFAS No. 112, SFAS No. 109, and changed
the method of accounting for unbilled revenues. These changes had a
cumulative effect of increasing net income approximately $46 million.
2-26
Consolidated Statements of Income
Central and South West Corporation
For the Years Ended December 31,
1994 1993 1992
Operating Revenues (millions, except per share amounts)
Electric
Residential $1,156 $1,160 $1,046
Commercial 836 832 773
Industrial 733 736 659
Sales for resale 204 179 177
Other 136 148 135
Total Electric 3,065 3,055 2,790
Gas 518 603 496
Other diversified 40 29 3
3,623 3,687 3,289
Operating Expenses and Taxes
Fuel and purchased power 1,161 1,209 1,035
Gas purchased for resale 276 396 306
Gas extraction and marketing 98 86 72
Other operating 596 593 490
Restructuring charges (9) 97 --
Maintenance 176 197 170
Depreciation and amortization 356 330 311
Taxes, other than federal income 196 197 175
Federal income taxes 179 125 142
3,029 3,230 2,701
Operating Income 594 457 588
Other Income and Deductions
Mirror CWIP liability amortization 68 76 83
Other 43 17 (1)
111 93 82
Income Before Interest Charges 705 550 670
Interest Charges
Interest on long-term debt 218 219 230
Interest on short-term debt and
other 75 50 36
293 269 266
Income Before Cumulative Effect of
Changes in Accounting Principles 412 281 404
Cumulative Effect of Changes in -- 46 --
Accounting Principles
Net Income 412 327 404
Preferred stock dividends 18 19 22
Net Income for Common Stock $394 $308 $382
Average Common Shares Outstanding 189.3 188.4 188.3
Earnings per Share of Common Stock
before Cumulative Effect of
Changes in Accounting Principles $ 2.08 $ 1.39 $ 2.03
Cumulative Effect of Changes in
Accounting Principles -- .24 --
Earnings per Share of Common Stock $ 2.08 $ 1.63 $ 2.03
Dividends Paid per Share of Common
Stock $ 1.70 $ 1.62 $ 1.54
The accompanying notes to consolidated financial statements are an
integral part of these statements.
Consolidated Statements of Retained Earnings
Central and South West Corporation
For the Years Ended December 31,
1994 1993 1992
(millions)
Retained Earnings at Beginning of Year $1,753 $1,751 $1,659
Net income for common stock 394 308 382
Deduct: Common stock dividends 323 306 290
Retained Earnings at End of Year $1,824 $1,753 $1,751
The accompanying notes to consolidated financial statements are an
integral part of these statements.
2-28
Consolidated Balance Sheets
Central and South West Corporation
As of December 31,
1994 1993
(millions)
ASSETS
Plant
Electric utility
Production $ 5,802 $ 5,775
Transmission 1,377 1,228
Distribution 2,539 2,362
General 764 709
Construction work in progress 412 361
Nuclear fuel 161 160
Total Electric 11,055 10,595
Gas 798 738
Other diversified 15 10
11,868 11,343
Less - Accumulated depreciation 3,870 3,550
7,998 7,793
Current Assets
Cash and temporary cash investments 27 62
Special deposits -- 2
Accounts receivable 761 801
Materials and supplies, at average cost 162 149
Electric utility fuel inventory,
substantially at average cost 118 102
Gas inventory/products for resale 23 24
Unrecovered fuel costs 54 70
Prepayments and other 44 44
1,189 1,254
Deferred Charges and Other Assets
Deferred plant costs 516 518
Mirror CWIP asset 322 332
Other non-utility investments 394 266
Income tax related regulatory assets, net 216 182
Other 274 259
1,722 1,557
$10,909 $10,604
The accompanying notes to consolidated financial statements are an
integral part of these statements.
2-29
Consolidated Balance Sheets
Central and South West Corporation
As of December 31,
1994 1993
(millions)
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock: $3.50 par value
Authorized: 350 million shares
Issued and outstanding: 190.6 million
shares in 1994 and 188.4 million shares
in 1993 $ 667 $ 659
Paid-in capital 561 518
Retained earnings 1,824 1,753
Total Common Stock Equity 3,052 2,930
Preferred stock
Not subject to mandatory redemption 292 292
Subject to mandatory redemption 35 58
Long-term debt 2,940 2,749
Total Capitalization 6,319 6,029
Current Liabilities
Long-term debt and preferred stock due
within twelve months 7 26
Short-term debt 910 769
Short-term debt - CSW Credit 573 641
Accounts payable 286 313
Accrued taxes 111 90
Accrued interest 61 55
Accrued restructuring charges 4 97
Other 155 152
2,107 2,143
Deferred Credits
Income taxes 2,048 1,935
Investment tax credits 320 335
Mirror CWIP liability and other 115 162
2,483 2,432
$10,909 $10,604
The accompanying notes to consolidated financial statements are an
integral part of these statements.
2-30
Consolidated Statements of Cash Flows
Central and South West Corporation
For the Years Ended December 31,
1994 1993 1992
(millions)
OPERATING ACTIVITIES
Net Income $ 412 $ 327 $ 404
Non-cash Items Included in Net Income
Depreciation and amortization 402 366 351
Deferred income taxes and
investment tax credits 87 94 71
Mirror CWIP liability amortization (68) (76) (83)
Restructuring charges (9) 97 --
Cumulative effect of changes in
accounting principles -- (46) --
Changes in Assets and Liabilities
Accounts receivable 29 (52) (52)
Unrecovered fuel costs 16 (63) (4)
Accounts payable (27) 34 53
Accrued taxes 21 37 (41)
Accrued restructuring charges (57) -- --
Other (42) (24) (13)
764 694 686
INVESTING ACTIVITIES
Capital expenditures (578) (508) (422)
Acquisitions (21) (106) (27)
Non-affiliated accounts receivable
collections (purchases), net 11 (314) 11
CSW Energy projects (includes $73, $19 and
$8 of equity investments for 1994, 1993
and 1992, respectively) (115) (127) (37)
Other (14) (14) (8)
(717) (1,069) (483)
FINANCING ACTIVITIES
Common stock sold 50 1 2
Proceeds from issuance of
long-term debt 199 904 1,009
Retirement of long-term debt (4) (50) (4)
Reacquisition of long-term debt (27) (987) (652)
Special deposits for reacquisition
of long-term debt -- 199 (199)
Redemption of preferred stock (33) (17) (13)
Change in short-term debt 73 602 17
Payment of dividends (340) (325) (312)
(82) 327 (152)
Net Change in Cash and Cash Equivalents (35) (48) 51
Cash and Cash Equivalents at Beginning of
Year 62 110 59
Cash and Cash Equivalents at End of Year $ 27 $ 62 $ 110
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized $ 280 $ 260 $ 268
Income taxes paid $ 93 $ 53 $ 108
The accompanying notes to consolidated financial statements integral part
of these statements.
2-31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies
Public Utility Regulation
CSW is subject to regulation by the SEC as a registered holding
company under the Holding Company Act. CSW's Operating Companies
are also regulated by the SEC under the Holding Company Act.
CSW's four Electric Operating Companies, Central Power and Light
Company, Public Service Company of Oklahoma, Southwestern Electric
Power Company, and West Texas Utilities Company, are subject to
regulation by the FERC under the Federal Power Act and follow the
Uniform System of Accounts prescribed by the FERC. The Operating
Companies are subject to further regulation with regard to rates
and other matters by state regulatory commissions.
CSW Credit
CSW Credit, as a wholly-owned subsidiary of CSW, purchases,
without recourse, the billed and unbilled accounts receivable of
the Operating Companies and certain non-affiliated companies.
The more significant accounting policies of CSW and its
subsidiaries are summarized below:
Principles of Consolidation
The consolidated financial statements include the accounts of CSW
and its subsidiary companies. All significant intercompany items
and transactions have been eliminated.
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. Transok's gas
plant acquisitions are stated at fair market value based on the
purchase price while other gas plant is stated at original cost of
construction, which includes the cost of contracted services,
direct labor, materials, overhead items and capitalized interest.
Depreciation
Provisions for depreciation of plant are computed using the
straight-line method, generally at individual rates applied to the
various classes of depreciable property. The annual average
consolidated composite rate was 3.2% for 1994, 1993 and 1992.
Nuclear Decommissioning
At the end of STP's service life, decommissioning is expected to
be accomplished using the decontamination method, which is one of
the techniques acceptable to the NRC. Using this method, the
decontamination activities occur as soon as possible after the end
of plant operations. Contaminated equipment is cleaned or removed
to a permanent disposal location and the site is generally
returned to its pre-plant state.
CPL's decommissioning costs are accrued and funded to an external
trust over the expected service life of the STP units. The
existing NRC operating licenses will allow the operation of STP
Unit 1 until 2027, and Unit 2 until 2028. The accrual is an
annual level cost based on the estimated future cost to
decommission STP, including escalations for expected inflation to
the expected time of decommissioning, and is net of expected
earnings on the trust fund.
CPL's portion of the costs of decommissioning STP were estimated
to be $85 million in 1986 dollars based on a site specific study
completed in 1986. CPL is recovering these decommissioning costs
through rates based on the service life of STP at a rate of $4.2
million per year. The $4.2 million annual cost of decommissioning
is reflected on the income statement in other operating expense.
Decommissioning costs are paid to an irrevocable external trust
2-32
and as such are not reflected on CPL's balance sheet. At December
31, 1994, the trust balance was $19.3 million.
In May 1994, CPL received a new decommissioning study updating the
cost estimates to decommission STP that indicated that CPL's share
of such costs would increase from $85 million, as stated in 1986
dollars, to $251 million, as stated in 1994 dollars. The increase
in costs occurred primarily as a result of extended on-site
storage of high level waste, much higher estimates of low-level
waste disposal costs and increased labor costs since the prior
study. These costs are expected to be incurred during the years
2027 through 2062. While this is the best estimate available at
this time, these costs may change between now and when the funds
are actually expended because of changes in the assumptions used
to derive the estimates, including the prices of the goods and
services required to accomplish the decommissioning. Additional
studies will be completed periodically to update this information.
Based on this projected cost to decommission STP, CPL estimates
that its annual funding level should increase to $10.0 million.
CPL has requested this amount as part of its cost of service in
its current rate filing. Other parties to the rate proceeding have
filed their projections of the annual amount, which have ranged
from $4.5 million to $8.1 million. CPL expects to fund at the
level ultimately ordered by the Texas Commission although CPL
cannot predict what that level will be. Historically, the Texas
Commission has allowed full recovery of nuclear decommissioning
costs. For further information on CPL's current rate filing, see
NOTE 10, Litigation and Regulatory Proceedings - Texas Commission
Proceedings, below.
Electric Revenues and Fuel
Prior to January 1, 1993, electric revenues 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 operating revenues of
the next month. To conform to general industry standards, the
Electric Operating Companies changed their method of accounting to
accrue for estimated unbilled revenues. The effect of this change
on 1993 net income was pre-tax increase of $75 million, and an
after-tax increase of $49 million, included in cumulative effect
of changes in accounting principles.
CPL, SWEPCO and WTU recover fuel costs in Texas as a fixed
component of base rates whereby over-recoveries of fuel are
payable to customers and under-recoveries may be billed to
customers after Texas Commission approval. The cost of fuel is
charged to expense as consumed. See NOTE 10, Litigation and
Regulatory Proceedings, for further information about fuel
recovery.
PSO recovers fuel costs in Oklahoma and SWEPCO recovers fuel costs
in Arkansas and Louisiana through automatic fuel recovery
mechanisms. The application of these mechanisms varies by
jurisdiction.
Each of the Electric Operating Companies recovers fuel costs
applicable to wholesale customers, which are regulated by the
FERC, through an automatic fuel adjustment clause.
CPL amortizes the costs of nuclear fuel 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.
Accounts Receivable
Each of the Operating Companies sells its billed and unbilled
accounts receivable, without recourse, to CSW Credit.
Regulatory Assets and Liabilities
For their regulated activities, each of the Electric Operating
Companies follows SFAS No. 71 which defines the criteria for
establishing regulatory assets and regulatory liabilities.
Regulatory assets represent probable future revenue to the company
associated with certain costs which will be recovered from
customers through the ratemaking process. Regulatory liabilities
2-33
represent probable future refunds to customers. At December 31,
1994 and 1993, the CSW System had recorded the following
significant regulatory assets and liabilities:
1994 1993
(millions)
Regulatory Assets
Deferred plant costs $516 $518
Mirror CWIP asset 322 332
Income tax related
regulatory assets, net 216 182
Unrecovered fuel costs 54 70
Other 33 34
Regulatory Liabilities
Mirror CWIP liability 41 109
Deferred Plant Costs
In accordance with orders of the Texas Commission, WTU and CPL
deferred operating, depreciation and tax costs incurred for
Oklaunion Power Station Unit 1 and STP, respectively. These
deferrals were for the period beginning on the date when the
plants began commercial operation until the date the plants were
included in rate base. The deferred costs are being amortized and
recovered through rates over the lives of the respective plants.
See NOTE 10, Litigation and Regulatory Proceedings, for further
discussion of WTU's and CPL's deferred accounting proceedings.
Mirror CWIP
In accordance with Texas Commission orders, CPL previously
recorded a Mirror CWIP asset, which is being amortized over the
life of STP. For more information regarding Mirror CWIP, reference
is made to NOTE 10, 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 are considered cash
equivalents.
Reclassification
Certain financial statement items for prior years have been
reclassified to conform to the 1994 presentation.
Accounting Changes
Effective January 1, 1993, the CSW System adopted SFAS No. 106,
SFAS No. 112 and SFAS No. 109. See NOTE 2, Federal Income Taxes,
for further information regarding SFAS No. 109. In addition, the
Electric Operating Companies also changed their method of
accounting for unbilled revenues. See Electric Revenues and Fuel
above for further information.
The adoption of SFAS No. 106 resulted in an increase in 1993
operating expenses of $16 million. The adoption of SFAS No. 109,
SFAS No. 112 and the change in accounting for unbilled revenues
are presented as a cumulative effect of changes in accounting
principles as shown below:
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Pre-Tax Tax Net Income EPS
CSW Effect Effect Effect Effect
(millions, except EPS)
SFAS No. 109 $ -- $ 6 $ 6 $0.03
SFAS No. 112 (13) 4 (9) (0.05)
Unbilled revenues 75 (26) 49 0.26
Total $62 $(16) $46 $0.24
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 CSW System adopted the provisions of SFAS No. 109 effective
January 1, 1993. The net effect on CSW's earnings was a one-time
adjustment to increase net income by $6 million or $0.03 per
share. This adjustment was recorded as a cumulative effect of
change in accounting principle. The benefit was attributable to
the reduction in deferred taxes associated with CSW's non-utility
operations previously recorded at rates higher than current rates.
For utility operations, there were no material effects of SFAS No.
109 on CSW's earnings. As a result of this change, CSW recognized
additional accumulated deferred income taxes from its utility
operations and corresponding regulatory assets and liabilities to
ratepayers in amounts equal to future revenues or the reduction in
future revenues required when the income tax temporary differences
reverse and are recovered or settled in rates. As a result of a
favorable earnings history, the CSW System did not record any
valuation allowance against deferred tax assets at December 31,
1994 and 1993.
CSW files a consolidated federal income tax return and
participates in a tax sharing agreement with its subsidiaries.
The components of income taxes follow:
1994 1993 1992
Included in Operating Expenses and Taxes (millions)
Current $ 88 $ 28 $ 64
Deferred 105 112 95
Deferred ITC (14) (15) (17)
179 125 142
Included in Other Income and Deductions
Current (14) (3) (7)
Deferred (4) (5) 7
(18) (8) --
Tax effects of cumulative effect of changes
in Accounting Principles -- 14 --
-- 14 --
$161 $131 $142
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Investment tax credits deferred in prior years are included in
income over the lives of the related properties.
Total income taxes differ from the amounts computed by applying
the statutory income tax rates to income before taxes. The
reasons for the differences follow:
1994 % 1993 % 1992 %
(dollars in millions)
Tax at statutory rates $201 35 $160 35 $186 34
Differences
Amortization of ITC (14) (2) (15) (3) (15) (3)
Mirror CWIP (20) (4) (23) (5) (25) (4)
Prior period adjustments -- -- 18 4 (10) (2)
Cumulative effect of change in
method of accounting for
income taxes
Other -- -- (8) (2) -- --
(6) (1) (1) -- 6 1
$161 28 $131 29 $142 26
The significant components of the net deferred income tax
liability follow:
December 31, December 31,
1994 1993
(millions)
Deferred Income Tax Liabilities
Depreciable utility plant $ 1,683 $ 1,589
Deferred plant costs 181 181
Mirror CWIP asset 113 116
Income tax related regulatory assets 229 239
Other 262 234
Total Deferred Income Tax Liabilities 2,468 2,359
Deferred Income Tax Assets
Income tax related regulatory liability (155) (177)
Unamortized ITC (115) (120)
Alternative minimum tax carryforward (96) (68)
Other (56) (65)
Total Deferred Income Tax Assets (422) (430)
Net Accumulated Deferred Income Taxes - Total $ 2,046 $ 1,929
Net Accumulated Deferred Income Taxes - Noncurrent $ 2,048 $ 1,935
Net Accumulated Deferred Income Taxes - Current (2) (6)
Net Accumulated Deferred Income Taxes - Total $ 2,046 $ 1,929
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3.Long-Term Debt
The long-term debt of the Operating Companies outstanding as of
the end of the last two years follow:
Maturities Interest Rates December 31,
From To From To 1994 1993
(millions)
First mortgage
bonds
1995 1999 5.25% 7.50% $443 $343
2000 2004 5.25% 7.75% 836 796
2005 2009 6.20% 7.75% 247 248
2010 2014 7.50% 7.50% 112 112
2015 2019 9.125% 9.75% 226 240
2020 2024 7.25% 7.50% 295 295
2025 2029 6.875% 6.875% 80 80
Pollution control bonds
2000 2004 6.90% 7.125% 21 21
2005 2009 5.90% 6.00% 83 83
2010 2014 7.875% 10.125% 231 231
2015 2019 7.60% 7.875% 114 114
2025 2029 6.00% 6.00% 120 120
Notes and lease obligations
1996 2023 6.25% 9.75% 328 273
Unamortized discount (21) (22)
Unamortized cost of reacquired debt (175) (185)
$2,940 $2,749
The mortgage indentures, as amended and supplemented, securing
first mortgage bonds issued by the Electric Operating Companies,
constitute a direct first mortgage lien on substantially all
electric utility plant.
The Operating Companies may offer additional first mortgage bonds
and medium-term notes subject to market conditions and other
factors.
Annual Requirements
Certain series of outstanding first mortgage bonds have annual
sinking fund requirements, which are generally 1% of the amount of
each such series issued. These requirements may be, and generally
have been, satisfied by the application of net expenditures for
bondable property in an amount equal to 166-2/3% of the annual
requirements. Certain series of pollution control bonds also have
sinking fund requirements. At December 31, 1994, the annual
sinking fund requirements and annual maturities for first mortgage
bonds and pollution control bonds for the next five years follow:
Sinking Fund
Requirements Maturities
(millions)
1995 $ 4 $ 9
1996 4 33
1997 4 207
1998 4 34
1999 4 98
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Dividends
The subsidiary companies' mortgage indentures, as amended and
supplemented, contain certain restrictions on the use of their
retained earnings for cash dividends on their common stock. These
restrictions do not limit the ability of CSW to pay dividends to
its stockholders. At December 31, 1994, $1,375 million of the
subsidiary companies' retained earnings were available for payment
of cash dividends to CSW.
Reacquired Long-term Debt
During 1994, 1993 and 1992, the Electric Operating Companies
reacquired $27 million, $987 million and $652 million of long-term
debt, respectively, including reacquisition premiums, prior to
maturity. The premiums and related reacquisition costs and
discounts are included in long-term debt on the consolidated
balance sheets and are being amortized over 5 to 35 years,
consistent with its expected ratemaking treatment.
The weighted average cost of long-term debt was 7.7% for 1994,
7.8% for 1993 and 8.3% for 1992.
Reference is made to MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and
Capital Resources, for further information related to long-term
debt, including new issues and reacquisition.
4.Preferred Stock
The outstanding preferred stock of the Electric Operating
Companies as of the end of the last two years follow:
Current
1994 Dividend Rate December 31, Redemption Prices
Shares Outstanding From To 1994 1993 From To
(millions)
Not subject to mandatory redemption
592,900 4.00% 5.00% 59 59 102.75 107.00
760,000 7.12% 8.72% 76 76 100.00 101.00
1,600,000 auction 160 160 100.00 100.00
Issuance expenses and unamortized
redemption costs (3) (3)
$292 $292
Subject to mandatory redemption
352,000 6.95% 6.95% $ 35 $ 37 104.64 104.64
-- 10.05% 10.05% -- 22 -- --
Issuance expenses and unamortized
redemption costs -- (1)
$ 35 $ 58
The outstanding preferred stock not subject to mandatory
redemption is redeemable at the option of the Electric Operating
Companies upon 30 days notice at the current redemption price per
share. CPL's auction preferred stock totaling $160 million also
may be redeemed at par on any dividend payment date. The CSW
System's authorized number of shares of preferred stock totaled
6.4 million at December 31, 1994 and 1993.
Redemption prices of certain preferred stock decline at specified
intervals in future periods. The preferred stock issues subject
to mandatory redemption are refundable at various times during the
period 1995 through 1999. The minimum annual sinking fund
requirements of the preferred stock are $1.2 million for the years
1995 through 1999. During 1994 and 1993, the Electric Operating
Companies redeemed $33 million and $17 million, respectively, of
preferred stock, including redemption premiums.
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CPL
The dividends on CPL's $160 million auction and money market
preferred stocks are adjusted every 49 days, based on current
market rates. The dividend rates averaged 3.5%, 2.7%, and 3.6%
during 1994, 1993 and 1992.
CPL retired its remaining 10.05% preferred stock during August
1994.
WTU
In July 1993, WTU redeemed 100,000 shares of its 7.25% Series,
$100 par value, Preferred Stock, for $10 million, in accordance
with mandatory and optional sinking fund provisions. The capital
required for this transaction was provided by short-term
borrowings from the CSW System money pool and internal sources.
In July 1994, WTU redeemed the remaining 47,000 shares of its
7.25% Series, $100 par value, Preferred Stock.
5.Common Stock
On March 6, 1992, CSW effected a two-for-one split of CSW's common
stock by means of a 100% stock dividend paid to stockholders of
record on February 10, 1992. All references to number of shares
outstanding, to per share information in the Consolidated
Financial Statements, and to the notes thereto have been adjusted
to reflect the stock split on a retroactive basis.
CSW has a restricted stock plan and a stock option plan. Under
the stock option plan, 3,833,000 shares of common stock are
available for grant and 491,000 shares are reserved for exercise
of options which were outstanding at December 31, 1994.
The PowerShare dividend reinvestment plan is available to all CSW
stockholders, employees, eligible retirees, utility customers and
other residents of the four states where the Electric Operating
Companies operate. Plan participants are able to make optional
cash payments and reinvest all or any portion of their dividends
in CSW common shares. During 1994, CSW raised approximately $50
million in common stock equity through PowerShare.
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 and temporary cash investments
The carrying amount approximates fair value because of the short
maturity of those instruments.
Short-term investments
The carrying amount approximates fair value because of the short
maturity of those instruments. Short-term investments are
classified in accounts receivable on the consolidated balance
sheets.
Long-term debt
The fair value of the CSW System'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 CSW for debt of the same
remaining maturities.
Preferred stock subject to mandatory redemption
The fair value of the Electric Operating Companies' preferred
stock subject to mandatory redemption is estimated based on
quoted market prices for the same or similar issues or on the
current rates offered to CSW for preferred stock with the same or
similar remaining redemption provision.
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Long-term debt and preferred stock due within 12 months
The fair value of current maturities of long-term debt and
preferred stock due within 12 months are estimated based on quoted
market prices for the same or similar issues or on the current
rates offered for long-term debt or preferred stock with the same
or similar remaining redemption provisions.
Short-term debt
The carrying amount approximates fair value because of the short
maturity of those instruments.
The fair value does not affect CSW's liabilities unless the issues
are redeemed prior to their maturity dates.
The estimated fair values of CSW's financial instruments follow:
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(millions)
Cash and temporary cash
investments $27 $27 $62 $62
Short-term investments -- -- 13 13
Long-term debt 2,940 2,795 2,749 2,947
Preferred stock subject to
mandatory redemption 35 32 58 61
Long-term debt and preferred stock
due within 12 months 7 7 26 26
Short-term debt 1,483 1,483 1,410 1,410
7.Short-Term Financing
The CSW System has established a money pool to coordinate short-
term borrowings and to make borrowings outside the money pool
through CSW's issuance of commercial paper. At December 31, 1994,
the CSW System had bank lines of credit aggregating $930 million
to back up its commercial paper program.
CSW Credit, which does not participate in the money pool, issues
commercial paper that is secured by the assignment of its
receivables. CSW Credit maintains a secured revolving credit
agreement which aggregated $900 million at December 31, 1994, to
back up its commercial paper program.
8.Benefit Plans
Defined Benefit Pension Plan
The CSW System maintains a tax qualified, non-contributory defined
benefit pension plan covering substantially all employees.
Benefits are based on employees' years of credited 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 which are deductible
for income tax purposes and minimum contributions required by the
ERISA. Pension plan assets consist primarily of common stocks and
short-term and intermediate-term fixed income investments.
Contributions to the plan for the years ended December 31, 1994,
1993 and 1992 were $28 million, $32 million and $29 million,
respectively.
The approximate maximum number of participants in the plan during
1994 were 8,500 active participants, 3,600 retirees and
beneficiaries and 1,000 terminated employees.
2-40
The components of net periodic pension cost and the assumptions
used in accounting for pensions follow:
1994 1993 1992
(dollars in millions)
Net Periodic Pension Cost
Service cost $22 $20 $18
Interest cost on projected
benefit obligation 62 56 50
Actual return on plan assets (4) (68) (43)
Net amortization and deferral (70) -- (20)
$10 $ 8 $ 5
Discount rate 8.25% 7.75% 8.50%
Long-term compensation increase 5.46% 5.46% 5.96%
Return on plan assets 9.50% 9.50% 9.50%
A reconciliation of the funded status of the plan to the amounts
recognized on the balance sheets is shown below:
December 31,
1994 1993
(millions)
Plan assets, at fair value $794 $790
Actuarial present value of
Accumulated benefit obligation
for service rendered to date 685 649
Additional benefit for future
salary levels 112 133
Projected benefit obligation 797 782
Plan assets in excess/(below) the
projected benefit obligation (3) 8
Unrecognized net gain 60 62
Unrecognized prior service cost (8) (8)
Unrecognized net obligation 15 17
Prepaid pension cost $ 64 $ 79
The vested portion of the accumulated benefit obligations at
December 31, 1994 and 1993 was $626 million and $586 million,
respectively. The unrecognized net obligation is being amortized
over the average remaining service life of employees or 16 years.
Prepaid pension cost is included in other deferred charges on the
consolidated balance sheets.
In addition to the amounts shown in the above table, the CSW
System has a non-qualified excess benefit plan. This plan is
available to all pension plan participants who are entitled to
receive a pension benefit from CSW which is in excess of the
limitations imposed on benefits by the Internal Revenue Code
through the qualified plan. CSW's net periodic cost for this non-
qualified plan for the years ended December 31, 1994, 1993 and
1992 was $1.8 million, $1.8 million and $0.5 million,
respectively.
Health and Welfare Plans
The CSW System had medical, dental, group life insurance,
dependent life insurance, and accidental death and dismemberment
plans for substantially all active CSW System employees during
1994. The contributions, recorded on a pay-as-you-go basis, for
the years ended December 31, 1994 and 1993 were approximately $17
2-41
million and $23 million, respectively. Effective January 1993,
the CSW System's method of providing health benefits was modified
to include such benefits as a health maintenance organization,
preferred provider options, managed prescription drug and mail-
order program and a mental health and substance abuse program in
addition to the self-insured indemnity plans.
Postretirement Benefits Other Than Pensions
The CSW System adopted SFAS No. 106 effective January 1, 1993. The
effect on operating expense in 1993 was an increase of $16
million. The transition obligation is being amortized over twenty
years, with eighteen years remaining. In prior years, these
benefits were accounted for on a pay-as-you-go basis.
The components of net periodic postretirement benefit cost follow:
1994 1993
(millions)
Net Periodic Postretirement Benefit Cost
Service cost $ 9 $ 8
Interest cost on APBO 19 17
Actual return on plan assets (1) (1)
Amortization of transition obligation 9 9
Net amortization and deferral (4) (2)
$32 $31
A reconciliation of the funded status of the plan to the amounts
recognized on the consolidated balance sheets follow:
December 31,
1994 1993
APBO (millions)
Retirees $141 $146
Other fully eligible participants 31 30
Other active participants 55 64
Total APBO 227 240
Plan assets at fair value (69) (51)
APBO in excess of plant assets 158 189
Unrecognized transition obligation (162) (171)
Unrecognized gain or (loss) 4 (18)
(Accrued)/Prepaid Cost $ -- $ --
The following assumptions were used in accounting for SFAS No.
106.
1994 1993
Discount rate 8.25% 7.75%
Return on plan assets 9.50% 9.00%
Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions
Pre-65 Participants: 1994 rate of 11.75% grading down .75% per
year to an ultimate rate of 6.5% in 2001.
Post-65 Participants: 1994 rate of 11.25% grading down .75% per
year to an ultimate rate of 6.0% in 2001.
2-42
Increasing the assumed health care cost trend rates by one
percentage point in each year would increase the APBO by $26
million and increase the aggregate of the service and interest
costs components by $4 million as of December 31, 1994.
9.Jointly Owned Electric Utility Plant
The Electric Operating Companies are parties to various joint
ownership agreements with other non-affiliated entities. Such
agreements provide for the joint ownership and operation of
generating stations and related facilities, whereby each
participant bears its share of the project costs. At December 31,
1994, the companies have undivided interests in five such
generating stations and related facilities as shown below:
CPL SWEPCO SWEPCO SWEPCO CSW
South Flint Dolet System
Texas Creek Pirkey Hills Oklaunion
Nuclear Coal Lignite Lignite Coal
Plant Plant Plant Plant Plant
(dollars in millions)
Plant in service $2,343 $ 79 $ 431 $ 226 $ 397
Accumulated
depreciation $ 380 $ 39 $ 135 $ 62 $ 91
Plant capacity-MW 2,500 480 650 650 676
Participation 25.2% 50.0% 85.9% 40.2% 78.1%
Share of capacity-MW 630 240 559 262 528
10. Litigation and Regulatory Proceedings
CPL
STP
From February 1993 until May 1994, STP experienced an unscheduled
outage which has resulted in significant rate and regulatory
proceedings involving CPL. These matters, including a base rate
case and fuel reconciliation proceedings, are discussed
immediately below.
Texas Commission Proceedings
Base Rates
Rate Inquiry - Docket No. 12820
Several Cities, the Texas Commission General Counsel and others
initiated actions in late 1993 and early 1994 which, if approved
by the Texas Commission, would lower CPL's base rates. The
requests for a review of CPL's rates arose out of the unscheduled
outage at STP which began in February 1993. The STP outage did
not affect CPL's ability to meet customer demand because of
existing capacity and CPL's purchase of additional energy.
Pursuant to a scheduling and procedural settlement agreement among
the parties challenging CPL's rates, which was approved by a Texas
Commission ALJ on April 1, 1994, CPL submitted a rate filing
package on July 1, 1994 to the Texas Commission justifying its
current base rate structure. In that filing, CPL stated that it
had a $111 million retail revenue deficiency and would be
justified in seeking a base rate increase. However, consistent
with the procedural settlement agreement, CPL has not sought to
increase base rates as a part of this docket but seeks to maintain
its rates at the same levels agreed to in the settlement of its
last two rate cases in 1990 and 1991. As part of the 1990 and
1991 settlements, CPL 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. On October 31, 1994, CPL filed rebuttal
testimony that revised its retail revenue deficiency to
approximately $103 million. CPL continues to maintain that its
rates are reasonable and that its earnings are within established
regulatory guidelines.
2-43
Parties to CPL's base rate case have filed testimony with the
Texas Commission recommending reductions in CPL's base rates.
Among the parties that filed testimony were OPUC which initially
recommended an annual $100 million retail rate reduction. After
hearings on the rate case, OPUC claimed that CPL did not meet its
burden of proof concerning deferred accounting and as a result
OPUC changed its proposed reduction to $147 million. The Cities,
which are parties to the rate case, have recommended an annual $75
million retail rate reduction and the write-off of $219 million of
CPL's Mirror CWIP asset. See Deferred Accounting below.
The Staff filed testimony recommending an annual reduction in
retail rates of $99.6 million resulting from a combination of
proposed rate base and cost of service reductions, which it
subsequently revised during the hearings to $83.9 million. In its
final brief to the ALJ, the Texas Commission's Staff withdrew its
recommendation that short-term debt be included in the calculation
of CPL's weighted cost of capital. CPL estimates that this change
in the Staff's position will lower its revised proposed retail
rate reduction by approximately $6 million. The Staff recommended
a rate base disallowance of $407 million, or approximately 17% of
CPL's investment in STP, based upon the Staff's calculation of
historical performance for STP compared to a peer group of other
nuclear facilities. The Staff also recommended that accumulated
depreciation and accumulated deferred federal income taxes related
to the disallowed portion of STP be adjusted to reflect a net
reduction to rate base of $325 million. Additionally, the Staff
proposed to disallow depreciation expense related to the
recommended STP disallowed plant.
In its testimony, the Staff argued that its proposed STP rate base
reduction was a historical performance-based disallowance that
could be temporary in nature and would not have to result in a
permanent disallowance. The Staff indicated that, in the future,
CPL could seek recovery in rates of the proposed STP rate base
disallowance, subject to the performance of STP.
The Texas Commission held hearings in November and December 1994,
and all parties have filed briefs in the case. The ALJ is
expected to issue a recommended order for consideration by the
Texas Commission in April 1995, with a final order from the Texas
Commission expected in May 1995. Testimony filed by parties to
the rate case, including the Staff, is not binding on either the
ALJ or the Texas Commission.
CPL strongly believes that 100 percent of its investment in both
units of STP belong in rate base. This belief is based on, among
other factors, Units 1 and 2 providing output at high capacity
factors since April and June 1994, respectively. In addition, the
long-term benefits nuclear generation provides to customers
supports their inclusion in rate base. Furthermore, there are no
Texas Commission precedents addressing the removal of a nuclear
plant from rate base as a performance-based disallowance.
Assuming both units of STP are included in rate base, CPL believes
it is not collecting excessive revenues, notwithstanding that
market rates of return on common equity are generally lower today
than they were in 1990 and 1991, when CPL's base rates were last
set.
Fuel
Introduction
Pursuant to the substantive rules of the Texas Commission, CPL
generally is allowed to recover its fuel costs through a fixed
fuel factor. These fuel factors are in the nature of temporary
rates, and CPL'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 costs 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.
Fuel Surcharge - Docket No. 12154
In July 1993, CPL 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
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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 CPL's request to postpone consideration of the surcharge.
In January and July of 1994, CPL updated its fuel surcharge
petition to reflect amounts of under-recovery through November
1993 and May 1994, respectively. Also, CPL further updated its
petition in January 1995 to reflect amounts of under-recovery
through November 1994. Likewise, CPL requested and was granted
postponement of the updated petitions until the STP outage
concluded or at the time fuel costs are next reconciled. On
January 4, 1995, Docket No. 12154 was consolidated into Docket No.
13650.
Prudence Inquiry - Docket No. 13126
In April 1994, the Texas Commission's General Counsel and Staff
issued a Request for Proposal for an audit of the STP outage, and
in July 1994 a consultant was selected to perform the audit. The
purpose of the audit is to evaluate the prudence of management
activities at STP, including the actions of HLP and the STP
management committee, of which CPL is a participant. Such review
will include the time from original commercial operation of each
unit until they were returned to service from the outage. The
findings of this audit are expected to be incorporated into this
proceeding. CPL and HLP will pay the costs of the audit but will
have no control over the ultimate work product of the consultant.
In June 1994, the Texas Commission's General Counsel initiated an
inquiry into the operation and management of STP which resulted in
the establishment of this proceeding. As part of the inquiry, CPL
presented certain information concerning the prudence of
management activities at STP relating to the STP outage.
Testimony filed by CPL stated that the cause of the STP outage was
the result of an accidental equipment failure rather than
imprudent management activities at STP. Based on this
information, CPL will seek full recovery in its fuel
reconciliation case of incremental energy costs related to the STP
outage.
As a part of this proceeding, CPL was required to reconstruct its
production costs assuming STP was available 100% of the time
during the actual outage. Testimony filed by CPL stated that it
is unrealistic to expect any generating unit to operate all the
time. The testimony provided calculations of STP replacement
power cost estimates for availability factor scenarios at (i)
100%, (ii) 75% and (iii) 65% average availability. Based on these
average availability factors, STP net replacement power costs for
the entire outage period were estimated to be (i) $104.5 million
at 100%, (ii) $79.0 million at 75% and (iii) $68.2 million at 65%
average availability.
The results of this prudence inquiry are expected to be used in
CPL's pending fuel reconciliation proceeding in Docket No. 13650,
as discussed below, and possibly CPL's next base rate proceeding
should a return on equity penalty be ordered by the Texas
Commission. Such penalty could lower CPL's allowed return on
equity in its next base rate case from what it otherwise would be
permitted to earn.
Fuel Reconciliation - Docket No. 13650
On November 15, 1994, CPL filed a fuel reconciliation case with
the Texas Commission seeking to reconcile approximately $1.2
billion of fuel costs from March 1, 1990 through June 30, 1994.
This period includes the STP outage where CPL's fuel and purchased
power costs were increased as the power normally generated by STP
was replaced through sources with higher costs. At December 31,
1994, CPL's under-recovered fuel balance was $54.1 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. CPL cannot accurately
estimate the amount of any future under- or over-recoveries due to
the nature of the above factors. CPL cannot predict how the Texas
Commission will ultimately resolve the reasonableness of higher
replacement energy costs associated with the STP outage. Although
the Texas Commission could disallow all or a portion of the STP
replacement energy costs, such determination cannot be made until
a final order is issued by the Texas Commission in this docket.
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If a significant portion of the fuel costs were disallowed by the
Texas Commission, CSW could experience a material adverse effect
on its consolidated results of operations in the year of
disallowance but not on its financial condition.
CPL continues to negotiate with the intervening parties to resolve
Docket Nos. 12820, 13126 and the STP portions of Docket No. 13650
through settlement. However, no settlement has been reached.
Management cannot predict the ultimate outcome of these regulatory
proceedings. However, management believes that the ultimate
resolution of the various issues will not have a material adverse
effect on CSW's consolidated results of operations or financial
condition.
STP Background
Final Orders
In October 1990, the Texas Commission issued the 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 the STP Unit 2 Order
which fully implemented a stipulated agreement to resolve all
issues regarding CPL's investment in STP Unit 2.
The STP Unit 1 Order allowed CPL 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 had authorized deferral of STP Unit 1
costs. See Deferred Accounting below. 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
CPL 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. The Mirror
CWIP liability is being reduced by the recognition of non-cash
income during the period 1991 through 1995. The Mirror CWIP asset
is being amortized to expense over the life of the plant.
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 costs of CPL's total investment in STP is included in
rate base. As indicated under the heading Texas Commission
Proceedings above, however, CPL is currently involved in base rate
and fuel proceedings which challenge CPL's right to recover
certain costs associated with the STP outage.
As part of the stipulated agreement, CPL 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. CPL 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 CPL, the Staff and a majority of intervenors including major
cities in CPL's service territory and major industrial customers.
These intervenors represent a significant majority of CPL's
customers. CPL and the TSA reached agreements, which were
subsequently approved by the 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
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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 CSW could experience a
significant adverse effect on its consolidated results of
operations and financial condition. 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 economic results. Management believes that the
STP Unit 1 and 2 Orders will be upheld.
Deferred Accounting
CPL was granted deferred accounting for STP Unit 1 and 2 costs by
Texas Commission orders. These orders allowed CPL 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 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, CPL's
retail rates include recovery of 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 CPL'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 CPL 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 CPL from earning
a return on such costs.
After the Court of Appeals' denial of each party's motion for
rehearing of the decision, CPL 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 Appeals' decision, challenging
generally the legality of deferred accounting for rate base
treatment of any deferred costs. In May 1993, the Supreme Court
of Texas granted CPL's Application for Writ of Error. CPL's case
was consolidated with the deferred accounting cases of El Paso and
HLP. In June 1994, the Supreme Court of Texas sustained deferred
accounting as an appropriate mechanism for the Texas Commission to
use in preserving the financial integrity of utilities. The
Supreme Court of Texas held that the Texas Commission can
authorize utilities to defer those costs that are incurred between
the in-service date of a plant and the effectiveness of new rates,
which include such costs. On October 6, 1994, the Supreme Court
of Texas denied a motion for rehearing CPL's deferred accounting
matter filed by the State of Texas. The language of the Supreme
Court of Texas opinion suggests that the appropriateness of
allowing deferred accounting may need to again be reviewed under a
financial integrity standard at the time the costs begin being
recovered through rates. For CPL, that would be the STP Unit 1
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and Unit 2 Orders discussed above. To the extent that additional
review is required, it should occur in those dockets.
If these deferred accounting matters are not favorably resolved,
CSW could experience a material adverse effect on its consolidated
results of operations and financial condition. While CPL's
management cannot predict the ultimate outcome of these matters,
management believes CPL will 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
CSW's consolidated results of operations or financial condition.
Westinghouse Litigation
CPL and other owners of STP are plaintiffs in a lawsuit filed in
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 set for trial in July
1995.
Inspections during the STP outage have detected early signs of
stress corrosion cracking in tubes at STP Unit 1. Management
believes additional problems would develop gradually and will be
monitored by the Project Manager 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.
Management believes that the ultimate resolution of this matter
will not have a material adverse effect on CSW's consolidated
results of operations or financial condition.
Civil Penalties
In October 1994, the NRC staff advised HLP that it proposes to
fine HLP $100,000 for what the NRC believes was discrimination
against a contractor employee at STP who brought complaints of
possible safety problems to the NRC's attention. These actions
resulted from the findings of a NRC investigation of alleged
violations of STP security and work process procedures in 1992.
The incident cited by the NRC is the subject of a contested
hearing that is scheduled to be held in the spring of 1995 before
a United States Department of Labor judge. Until the Department
of Labor issues a final decision in this matter, the NRC is not
requiring HLP to respond to its notice of violation.
PSO
Rate Review
In December 1993, the Oklahoma Commission issued an order
unanimously approving a joint stipulation between PSO, the
Oklahoma Commission Staff, and the Office of the Attorney General
of the State of Oklahoma, as recommended by the ALJ. The order
allowed PSO an increase in retail prices of $14.4 million on an
annual basis which represents a $4.3 million increase above those
authorized by the March 1993 interim order. In January 1994, the
Oklahoma Commission issued an order unanimously approving PSO's
price schedules reflecting the $14.4 million price increase. The
new prices became effective beginning with the billing month of
February 1994.
The December 1993 order addresses, among other things, the
following issues. PSO will recover $4.5 million annually in
expenses associated with OPEBs, which, for PSO, are primarily
health care related benefits. Such expenses will be recovered
along with amortization of the deferred 1993 OPEBs at a rate of
$0.5 million per year for 10 years. PSO will amortize deferred
storm expenses associated with both a 1987 ice storm and a 1992
wind storm, amounting to $1.2 million per year for five years. In
addition, the order recognizes the increase in federal income tax
expenses resulting from the recent increase in the federal
corporate income tax rate from 34 percent to 35 percent. PSO will
continue to use the depreciation rates previously approved by the
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Oklahoma Commission. PSO agreed that it will not file another
retail price increase application until after June 30, 1995.
Gas Transportation and Fuel Management Fees
An order issued by the Oklahoma Commission in 1991 required that
the level of gas transportation and fuel management fees, paid to
Transok by PSO, permitted for recovery through the fuel adjustment
clause be reviewed in the aforementioned price proceeding. This
portion of the price review was bifurcated. In February 1995, an
agreement was reached which allows PSO to recover approximately
$28.4 million of transportation and fuel management fees in base
rates using 1991 determinants and approximately $1 million through
the fuel adjustment clause. The agreement also requires the phase-
in of competitive bidding of natural gas transportation
requirements in excess of 165 MMcf/d per day. An ALJ has
recommended approval of the agreement to the Oklahoma Commission.
A final order is expected in the first quarter of 1995.
Gas Purchase Contracts
PSO has been named defendant in complaints filed in federal and
state courts of Oklahoma and Texas in 1984 through February 1995
by gas suppliers alleging claims arising out of certain gas
purchase contracts. Cases currently pending seek approximately
$29 million in actual damages, together with claims for punitive
damages which, in compliance with pleading code requirements, are
alleged to be in excess of $10,000. The plaintiffs seek relief
through the filing dates as well as attorney fees. As a result of
settlements among the parties, certain plaintiffs dismissed their
claims with prejudice to further action. The settlements did not
have a significant effect on CSW's consolidated results of
operations. The remaining suits are in the preliminary stages.
Management cannot predict the outcome of these proceedings.
However, management believes that PSO has defenses to these
complaints and intends to pursue them vigorously. Management also
believes that the ultimate resolution of the remaining complaints
will not have a material adverse effect on CSW's consolidated
results of operations or financial condition.
PCB Cases
PSO has been named a defendant in complaints filed in state court
in Oklahoma alleging, among other things, that some of the
plaintiffs were contaminated with PCBs and other toxic by-products
following transformer malfunctions. The complaints currently
total approximately $383 million of which approximately one-third
represents punitive damages. Some claims have been dismissed,
certain of which resulted in settlements among the parties. The
settlements did not have a significant effect on CSW's
consolidated results of operations. Although management cannot
predict the outcome of these proceedings, management believes that
PSO has defenses to these claims and intends to pursue them
vigorously. Moreover, management has reason to believe that PSO's
insurance may cover some of the claims. Management also believes
that the ultimate resolution of these cases will not have a
material adverse effect on CSW's consolidated results of
operations or financial condition.
Burlington Northern Transportation Contract
In June 1992, PSO filed suit in Federal District Court in Tulsa,
Oklahoma, against Burlington Northern seeking declaratory relief
under a long-term contract for the transportation of coal. In
July 1992, Burlington Northern asserted counterclaims against PSO
alleging that PSO breached the contract. The counterclaims sought
damages in an unspecified amount. In December 1993, PSO amended
its suit against Burlington Northern seeking damages and
declaratory relief under federal and state anti-trust laws. PSO
and Burlington Northern filed motions for summary judgment on
certain dispositive issues in the litigation. In March 1994, the
court issued an order granting PSO's motions for summary judgment
and denying Burlington Northern's motion. It was not necessary
for the court to decide the federal and state anti-trust claims
raised by PSO. Judgment was rendered in favor of PSO by the
United States District Court in May 1994. In June 1994,
Burlington Northern appealed this judgment to the United States
Court of Appeals for the Tenth Circuit. This appeal is now
pending.
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Burlington Northern Arbitration
In May 1994, in a related arbitration, an arbitration panel made
an award favorable to PSO concerning basic transportation rates
under the coal transportation contract described above, and
concerning the contract mechanism for adjustment of future
transportation rates. These arbitrated issues were not involved
in the related lawsuit described above. Burlington Northern filed
an action to vacate the arbitrated award in the District Court for
Dallas County, Texas. PSO removed this action to the United
States District Court for the Northern District of Texas, and
filed a motion to either dismiss this action or have it
transferred to the United States District Court for the Northern
District of Oklahoma. Burlington Northern moved to remand the
action to state court. In September 1994, the United States
District Court for the Northern District of Texas denied
Burlington Northern's motion to remand, and granted PSO's motion
to transfer the action to the United States District Court for the
Northern District of Oklahoma. Separately, PSO filed an action to
confirm the arbitration award in the United States District Court
for the Northern District of Oklahoma, and Burlington Northern
filed a motion to dismiss this confirmation action. On December
6, 1994, the District Court entered an order denying the
Burlington Northern's motion to vacate the arbitration award, and
granting PSO's motion to confirm the arbitration award. On
December 29, 1994, the District Court entered judgment confirming
the arbitration award, including a money judgment in PSO's favor
for $16.4 million, with interest at 7.2% per annum compounded
annually from December 21, 1994 until paid. On January 6, 1995,
Burlington Northern appealed the District Court's judgment to the
United States Court of Appeals for the Tenth Circuit. This appeal
is now pending.
SWEPCO
Fuel Reconciliation
On March 17, 1994, SWEPCO filed a petition with the Texas
Commission to reconcile fuel costs for the period November 1989
through December 1993. Total Texas jurisdictional fuel expenses
subject to reconciliation for this 50-month period were
approximately $559 million. SWEPCO's net under-recovery for the
reconciliation period was approximately $0.9 million. SWEPCO and
the intervening parties in this proceeding were able to negotiate
a stipulated agreement providing a $3.2 million fuel cost
disallowance and settling all issues except one. That issue
involved the recovery of certain fuel related litigation and
settlement negotiation expenses. The Texas Commission, at its
Final Order hearing on January 18, 1995, approved the stipulated
disallowance and granted SWEPCO recovery of the fuel related
litigation expense. The $3.2 million disallowance is included in
SWEPCO's 1994 results of operations. SWEPCO recognized the
litigation costs as expenses in prior periods.
Burlington Northern Transportation Contract
On January 20, 1995, a state district court in Bowie County,
Texas, entered judgment in favor of SWEPCO against Burlington
Northern in a lawsuit between the parties regarding rates charged
under two rail transportation contracts for delivery of coal to
SWEPCO's Welsh and Flint Creek power plants. The court awarded
SWEPCO approximately $72 million covering damages for the period
from April 27, 1989 through September 26, 1994 and prejudgment
interest fees and grant certain declaratory relief requested by
SWEPCO.
Kansas City Southern Railway Company Transportation Contracts
In March 1994, SWEPCO entered into a settlement with the Kansas
City Southern Railway Company of litigation between parties
regarding two coal transportation contracts. Pursuant to the
settlement, SWEPCO and the Kansas City Southern Railway Company
executed a new coal transportation agreement. The settlement is
expected to result in a reduction of SWEPCO's coal transportation
costs now and in the future. Burlington Northern, another party
to the prior contracts and to the litigation, did not participate
in the settlement and the litigation is still pending between
SWEPCO and Burlington Northern.
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WTU
Rate Proceeding - Docket No. 13369
On August 25, 1994, WTU filed a petition with the Texas Commission
and with cities with original jurisdiction to review WTU's rates,
proposed an interim across-the-board base rate reduction of 3.25%
or, approximately $5.7 million, effective October 1, 1994, and
sought until February 28, 1995, the time to develop and file a
RFP. WTU also requested the ability to "true-up", back to October
1, 1994, any difference in revenue requirements upon final order
of the Texas Commission, and proposed that any increases over the
pre-October 1, 1994, base rates be implemented prospectively on
the effective date of the final order.
As discussed below, WTU's fuel reconciliation was consolidated
with this proceeding in September 1994. Reconcilable fuel costs
during the reconciliation period were approximately $300 million.
At June 30, 1994, the fuel cost under-recovery totaled
approximately $5.1 million, including interest. At December 31,
1994, this amount had become an over-recovery of approximately
$0.2 million. WTU is not seeking a change in fuel factors.
On February 28, 1995, WTU filed with the Texas Commission and
cities with original jurisdiction the rate filing package which
indicates a revenue deficiency of approximately $14.5 million.
However, WTU simultaneously filed with the parties a settlement
proposal to reduce overall base rate revenue by 3.25%, effective
October 1, 1994, an annual impact in the rate year beginning
January 1, 1996 of approximately $5.9 million. The settlement
proposal reflects WTU's desire to maintain competitive rates,
recognizes the importance of competitive rates in the changing
electric service marketplace, and demonstrates WTU's strong
commitment to the long-term success of WTU and its customers.
Unless a settlement accelerates the schedule, WTU anticipates
hearings in mid-1995 with a final order in the fourth quarter of
1995. Management cannot predict the outcome of the rate
proceeding, the fuel reconciliation, or the settlement proposal,
but believes that the ultimate resolution of these matters will
not have a material adverse effect on CSW's consolidated results
of operations or financial condition.
Fuel Reconciliation - Docket No. 13172
On June 30, 1994, WTU filed a petition with the Texas Commission
to reconcile fuel costs for the period January 1991 through
February 1994. Subsequently, in September 1994, this fuel
reconciliation proceeding was consolidated into Docket No. 13369
described above, and the reconciliation period was extended
through June 1994.
Rate Case Proceeding - Docket No. 7510
In November 1987, the Texas Commission issued a final order in
WTU's retail rate case providing for WTU to receive an annual
increase in base retail revenues of $34.9 million. Rates
reflecting the final order were implemented in December 1987.
WTU, along with certain intervenors in the retail rate proceeding,
appealed the Texas Commission's final order to the District Court
seeking reversal of various provisions of the final order,
including the inclusion of deferred accounting in rate base.
The appeals were consolidated and in September 1988, the District
Court affirmed the final order of the Texas Commission. In
November 1988, certain intervenors filed appeals of the District
Court's judgment with the Court of Appeals. In February 1990, the
Court of Appeals ruled that an intervenor had improperly been
excluded from presenting its appeal to the District Court,
reversed the District Court's judgment and remanded the case to
the District Court for further proceedings.
In October 1992, the District Court heard the remanded appeals of
the final order of the Texas Commission and in March 1993 issued
an order affirming the Texas Commission's order in all material
respects with the single exception of the inclusion of deferred
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Oklaunion carrying costs in rate base. In its treatment of
deferred costs, the District Court followed a then-current opinion
of the Court of Appeals which precluded recovery of deferred post-
in-service carrying costs. In April 1993, WTU and other parties
filed appeals, and oral argument was held on the appeals in
December 1993 on the non-deferred accounting issues. With respect
to the deferred accounting issues, the parties recognized certain
Supreme Court of Texas decisions regarding other deferred
accounting cases would be influential in WTU's case.
In June 1994, the Supreme Court of Texas issued its opinion in the
three other cases involving deferred accounting holding that the
Texas Commission has the authority to allow deferred accounting
treatment during the deferral period, including deferred post-in-
service carrying costs. The Supreme Court of Texas upheld the
Court of Appeals in all respects except it reversed the Court of
Appeals to the extent it disallowed carrying costs deferrals and
remanded to the Court of Appeals for consideration of the
unresolved arguments of the improperly excluded intervenor.
Motions for rehearing were filed by certain parties which were
denied by the Supreme Court of Texas. These rulings influenced
the Court of Appeals' decision in WTU's rate case appeals, as
described below.
On February 15, 1995, the Court of Appeals affirmed all aspects of
the District Court judgment relating to the Texas Commission's
allowance of non-Oklaunion depreciation rates and the surcharge of
rate case expenses, reversed the District Court's judgment
relating to the exclusion of deferred Oklaunion carrying costs in
rate base, and remanded the cause to the Texas Commission to
reexamine the issue of deferred costs in light of the remand of
Docket No. 7289, as described above. However, on March 3, 1995,
WTU filed a motion for rehearing at the Court of Appeals seeking
clarification of certain aspects of its order and arguing that the
Court of Appeals erred in remanding the case to the Texas
Commission for it to determine to what extent deferred costs are
necessary to preserve WTU's financial integrity because the issue
has been waived since it was not briefed or argued to the Court of
Appeals. WTU expects other parties may also file motions for
rehearing.
WTU's motion for rehearing may, if granted, prevent further review
of financial integrity issues with respect to deferred accounting
in any remand of Docket No. 7510. If a broader remand is
permitted and if the Texas Commission concludes in Docket No. 7289
that deferred accounting was necessary to preserve WTU's financial
integrity during the deferral period, the Texas Commission must
decide to what extent the deferred Oklaunion costs, including
carrying costs, were necessary to preserve WTU's financial
integrity. If WTU's deferred accounting treatment is ultimately
reversed or is substantially reduced, WTU could experience a
material adverse impact on its results of operations. While
management can give no assurances as to the outcome of the
remanded proceeding or the motion for rehearing, management
believes that 100 percent of the Oklaunion deferred costs will be
determined by the Texas Commission to have been necessary to
preserve WTU's financial integrity during the deferral period so
that there will be no material adverse effect on CSW's
consolidated results of operations or financial condition.
Deferred Accounting - Docket No. 7289
WTU received approval from the Texas Commission in September 1987
to defer operating expenses and carrying costs associated with
Oklaunion incurred subsequent to its December 1986 commercial
operation date until December 1987 (the deferral period) when
retail rates including Oklaunion in WTU's rate base became
effective. WTU has recorded approximately $32 million of
Oklaunion deferred costs, of which $25 million are carrying costs.
The deferred costs are being recovered and amortized over the
remaining life of the plant. In November 1987, OPUC filed an
appeal in the District Court challenging the Texas Commission's
final order authorizing WTU to defer the costs associated with
Oklaunion. In October 1988, the District Court affirmed the final
order of the Texas Commission. In December 1988, OPUC filed an
appeal of the District Court judgment in the Court of Appeals. In
September 1990, the Court of Appeals upheld the District Court's
affirmance of the Texas Commission's final order and in October
1990, OPUC filed a motion for rehearing of the Court of Appeals'
decision, which was denied in November 1990. On further appeal,
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the Supreme Court heard oral argument in September 1993, in WTU's
case as well as three other cases involving deferred accounting
and in June 1994 issued its opinions in these cases affirming the
Texas Commission's authority to allow deferred accounting
treatment, but establishing a financial integrity standard rather
than the measurable harm standard used by the Texas Commission.
In October 1994, the Supreme Court of Texas issued a mandate
remanding WTU's deferred accounting case to the Texas Commission.
While no schedule has yet been established for the proceedings on
remand at the Texas Commission, this remand may be considered in
tandem with WTU's pending rate case, Docket No. 13369. In the
remanded proceeding, the Texas Commission must make a formal
finding that the deferral of Oklaunion costs was necessary to
prevent WTU's financial integrity during the deferral period from
being jeopardized.
If WTU's deferred accounting treatment is ultimately reversed and
not favorably resolved, WTU could experience a material adverse
impact on its results of operations. While management cannot
predict the ultimate outcome of these proceedings, management
believes that WTU's deferred accounting will be ultimately
sustained by the Texas Commission on the basis of the financial
integrity standard set forth by the Supreme Court of Texas, so
that there will be no material adverse effect on CSW's
consolidated results of operations or financial condition.
WTU FERC Order
On April 4, 1994, the FERC issued an order pursuant to section 211
of the Federal Power Act forcing a regional utility to transmit
power to Tex-La on behalf of WTU. The order was one of the first
issued by FERC under that provision, which was added by the Energy
Policy Act to increase competition in wholesale power markets.
WTU began serving Tex-La, which has requirements of approximately
120 MW of electric power. WTU will serve Tex-La until facilities
are completed to connect Tex-La to SWEPCO, an affiliated system,
at which time SWEPCO will provide 85 MW and WTU will retain 35 MW
of the Tex-La electric load.
Other
Cimmaron
On January 12, 1994, Cimmaron brought suit against CSW and its
wholly-owned subsidiary, CSWE, in the 125th District Court of
Houston, Harris County, Texas. Cimmaron alleges that CSW and CSWE
breached commitments to participant with Cimmaron in the failed
BioTech Cogeneration project located in Colorado. Cimmaron claims
breach of contract, fraud and negligent misrepresentation with
alleged damages totaling $250 million, punitive damages of an
unspecified amount, as well as attorney's fees.
CSWE filed a counterclaim against Cimmaron and third-party claims
against the principals of Cimmaron on December 22, 1994, alleging
that they misrepresented and omitted material facts about their
experience and background and about the proposed cogeneration
project. CSWE seeks damages of $500,000, the earnest money paid
when the letter of intent was executed, the costs associated with
due diligence and punitive damages. On January 10, 1995, Cimmaron
filed a first amended original petition suing CSWE board members
at the time, personally.
Pre-trial discovery on the case is presently underway with
depositions of the parties being taken during March, 1995. Trial
was originally set for the week of April 10, 1995, but the parties
have filed a joint motion for continuance which is set for hearing
on March 20, 1995. Management of CSW cannot predict the outcome
of this litigation, but believes that CSW and CSWE have defenses
to these complaints and are pursuing them vigorously and that the
ultimate resolution will not have a material adverse effect on
CSW's consolidated results of operations or financial condition.
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General Matters
CSW and the Operating Companies are 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 CSW's consolidated results of
operations or financial condition.
11. Commitments and Contingent Liabilities
Proposed Acquisition of El Paso
Background
In May 1993, CSW entered into a Merger Agreement pursuant to which
El Paso would emerge from bankruptcy as a wholly-owned subsidiary
of CSW. El Paso is an electric utility company headquartered in
El Paso, Texas, engaged principally in the generation and
distribution of electricity to approximately 262,000 retail
customers in west Texas and southern New Mexico. El Paso also
sells electricity under contract to wholesale customers in a
number of locations including southern California and Mexico. El
Paso had filed a voluntary petition for reorganization under
Chapter 11 of the Bankruptcy Code on January 8, 1992.
On July 30, 1993, El Paso filed the Modified Plan and a related
proposed form of Disclosure Statement providing for the
acquisition of El Paso by CSW. On November 15, 1993, all voting
classes of creditors and shareholders of El Paso voted to approve
the Modified Plan. On December 8, 1993, the Bankruptcy Court
confirmed the Modified Plan.
Under the Modified Plan, the total value of CSW's offer to acquire
El Paso is approximately $2.2 billion. The Modified Plan
generally provides for El Paso creditors and shareholders to
receive shares of CSW Common, cash and/or securities of El Paso,
or to have their claims cured and reinstated. The Modified Plan
also provides for claims of secured creditors generally to be paid
in full with debt securities of reorganized El Paso, and for
unsecured creditors to receive a combination of debt securities of
reorganized El Paso and CSW Common equal to 95.5 percent of their
claims, and for small trade creditors to be paid in full with
cash. The Modified Plan provides for El Paso's preferred
shareholders to receive preferred shares of reorganized El Paso,
or cash, and for options to purchase El Paso Common to be
converted into options to purchase a proportionate number of
shares of CSW Common. In addition, the Modified Plan provides for
certain creditor classes of El Paso to accrue interest on their
claims and to receive periodic interim distributions of such
interest through the Effective Date or the withdrawal or
revocation of the Modified Plan, subject to certain conditions and
limitations set forth in the Modified Plan. To date, all such
accrued interest payments to creditors have been made by El Paso
on a timely basis. If, under certain circumstances, the Merger is
not consummated, the Merger Agreement provides for CSW to pay El
Paso for a portion of such interim interest payments paid or
accrued prior to the termination of the Merger Agreement. The
Merger Agreement also provides for CSW to pay for a portion of
fees and expenses, including legal expenses of certain El Paso
creditors under such circumstances. CSW's potential exposure as
of December 31, 1994 is estimated to be approximately $17.5
million; however, the actual amount, if any, that CSW may be
required to pay pursuant to these provisions depends on a number
of contingencies and cannot presently be predicted.
On June 14, 1994, Las Cruces filed a motion with the Bankruptcy
Court to lift the automatic stay imposed by the bankruptcy filing
to allow it to (i) commence action against El Paso for failure to
pay franchise fees after the expiration of its franchise agreement
with Las Cruces in March 1994, (ii) enter El Paso's property to
conduct an appraisal of the electric distribution system and any
suitability studies, (iii) give notice of intent to file a
condemnation action and (iv) commence state court condemnation
proceedings against El Paso to condemn El Paso's distribution
system within Las Cruces' city limits.
On June 29 and July 1, 1994, El Paso and CSW filed responses in
the Bankruptcy Court opposing the Las Cruces motion. On August 1,
1994, CSW filed an amended response to the Las Cruces motion which
states that the threat or actual commencement of condemnation
proceedings by Las Cruces or the elimination of El Paso's service
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to Las Cruces by condemnation or otherwise may constitute an El
Paso material adverse effect, as defined in the Merger Agreement,
the absence of which is a condition of CSW's obligation to
consummate the Merger. The existence of an El Paso material
adverse effect would preclude consummation of the Merger and the
Modified Plan, unless CSW waives this condition in writing. CSW's
amended response concludes that Las Cruces' intention to file a
condemnation proceeding creates a situation that must be favorably
resolved before the closing of the Merger.
By letter dated August 5, 1994, El Paso protested CSW's filing of
the amended response and asserted its disagreement with CSW's
position regarding Las Cruces as summarized above. In addition,
El Paso asserted that CSW's filing of the amended response over El
Paso's objection was contrary to the terms of the Merger
Agreement.
On August 22, 1994, Las Cruces entered into a wholesale full
requirements power contract with SPS to supply power to a
municipal utility proposed to be established by Las Cruces. On
August 30, 1994, voters in Las Cruces approved by nearly a two-to-
one margin a referendum authorizing Las Cruces to proceed with
efforts to acquire from El Paso, through negotiated purchase or
condemnation proceedings, the electric utility system of El Paso
within Las Cruces, including certain distribution, substation and
associated transmission facilities.
On September 12, 1994, CSW delivered a response to El Paso's
August 5 letter. In its September 12 letter, CSW reiterated its
position that Las Cruces is a material element of CSW's bargain
with El Paso and advised El Paso that the municipalization efforts
in Las Cruces and other matters, including (i) the potential loss
of other customers in El Paso's service area, including the
Holloman Air Force Base and the White Sands Missile Range in New
Mexico, (ii) cracking in steam generator tubes at Palo Verde,
(iii) intense political and regulatory opposition to the Merger,
and (iv) a new "comparable transmission service" standard being
imposed on the Merger by the FERC, place the completion of the
Merger in jeopardy. CSW's September 12 letter further advised El
Paso that the foregoing matters, individually and cumulatively,
constitute a material adverse effect or failure of other closing
conditions under the Merger Agreement which, unless timely
resolved in accordance with the Merger Agreement, will preclude
closing of the proposed Merger.
Since CSW's September 12 letter, CSW has exchanged letters with El
Paso and others regarding the interpretation of the Merger
Agreement and the legal significance of the matters cited by CSW
in its September 12 letter. Most of these letters are summarized
below.
On September 14, 1994, CSW filed a second amended response to Las
Cruces' motion to lift the stay in bankruptcy. In its second
amended response, CSW stated that the intent and plan of Las
Cruces to file a condemnation proceeding creates a situation that
must be timely and favorably resolved by El Paso before the
consummation of the Merger, whether or not the stay is modified or
maintained. Further, CSW supported the maintenance of the stay as
a means of avoiding disruption pending resolution of the Las
Cruces dispute and because El Paso had taken the position that
maintenance of the stay was in the best interests of the Merger
and the El Paso estate and put El Paso in a better position to
resolve the Las Cruces dispute.
By letter dated September 16, 1994, El Paso disagreed with the
positions set forth by CSW in its September 12 letter and asserted
that CSW's September 12 letter "had inflicted irreparable harm on
El Paso and the Merger process."
On September 20, 1994, following a hearing on the June 14, 1994
motion of Las Cruces discussed above, the Bankruptcy Court judge
indicated orally that, effective January 1, 1995, he would lift
the bankruptcy stay on certain actions against El Paso and allow
Las Cruces to pursue condemnation proceedings against El Paso with
respect to the electric distribution system within Las Cruces
under applicable New Mexico law. El Paso filed a motion seeking
clarification of this oral ruling as to whether Las Cruces may
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take immediate possession of the El Paso distribution system under
the New Mexico condemnation statutes. On November 22, 1994, the
Bankruptcy Court judge orally ruled that Las Cruces can commence
condemnation proceedings but can not take possession of the
distribution system when the stay is lifted until returning to the
Bankruptcy Court and obtaining an order which permits that action.
By letter dated September 23, 1994, El Paso requested CSW's
consent to meet with the City of Las Cruces to discuss the
possibility of a resolution of El Paso's dispute with Las Cruces.
By letter dated October 3, 1994, CSW responded to El Paso's
September 16 letter and reaffirmed the positions set forth in
CSW's September 12 letter. In addition, CSW consented to El
Paso's meeting with Las Cruces, but advised El Paso that CSW would
not participate directly in negotiations between Las Cruces and El
Paso.
By letter dated October 5, 1994, counsel to the El Paso Unsecured
Creditors Committee, with the concurrence of certain other
creditor groups, advised CSW that the committee disagreed with
certain positions set forth in CSW's September 12 letter to El
Paso. By letter dated October 27, 1994, CSW responded to and
stated its disagreement with various statements set forth in the
Unsecured Creditors Committee's letter.
By letter dated October 5, 1994, El Paso's New Mexico regulatory
counsel asserted that CSW's September 12 letter had "adversely
affected proceedings before the New Mexico Commission" relating to
the Merger and that the letter "is being widely interpreted as a
statement from CSW that the Merger will not close." By letter
dated October 7, 1994, CSW's New Mexico regulatory counsel set
forth CSW's disagreement with statements made in El Paso's New
Mexico regulatory counsel's October 5 letter. The New Mexico
Commission had delayed the New Mexico proceedings prior to
September 12, 1994. On October 12, 1994, a New Mexico Commission
hearing examiner held a prehearing conference covering scheduling
and other matters. On October 14, 1994, CSW filed a Statement of
Position and Request for Procedural Schedule in the New Mexico
proceeding. El Paso filed a separate position statement in the New
Mexico proceeding and advised CSW, by letter dated October 14,
1994, that CSW's statement of position did not "state a
sufficiently clear and strong commitment by CSW to closing the
Merger." By letter dated October 25, 1994, CSW's New Mexico
regulatory counsel stated that the filing by El Paso of a separate
position statement "impairs our ability to obtain necessary
regulatory approvals from the New Mexico Commission on a timely
basis by implying that there are severe problems in the
relationship between El Paso and CSW." CSW's October 25 letter
also stated that "the lack of a favorable resolution of Las Cruces
municipalization efforts continues to not only prevent the closing
of the Merger, but is also hindering our ability to obtain New
Mexico regulatory approvals."
By letter dated October 18, 1994, El Paso reasserted its position
that the Merger Agreement does not condition CSW's obligation to
consummate the Merger on a favorable resolution of the Las Cruces
situation. El Paso asserted it was not clear from CSW's October 3
letter whether CSW consented to El Paso's proposed discussion with
Las Cruces and again requested CSW's consent to a meeting between
El Paso and Las Cruces.
By letter dated October 27, 1994, CSW reaffirmed the positions
taken in its September 12 and October 3 letters, and again
consented to El Paso's meeting with Las Cruces and reiterated
CSW's willingness to discuss with El Paso possible resolutions of
the Las Cruces situation.
On October 11, 1994, the Bankruptcy Court granted an application
by El Paso to employ special litigation counsel to advise El Paso
as to ongoing activities with CSW and to assist El Paso as to the
best means of preserving its rights. El Paso's application stated
that special litigation counsel was needed to evaluate El Paso's
rights, remedies and obligations with respect to CSW, the Plan and
the Merger Agreement and to advise key officers of El Paso on a
course of action to preserve and enforce El Paso's rights and
remedies. The application also stated that special litigation
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counsel "should also be in a position to conduct any litigation
which may be necessary," and noted that another law firm then
representing El Paso "would not be in a position to represent the
Debtor in litigation against CSW." On October 28, 1994, CSW filed
a response to El Paso's application, in which CSW stated that
while it did not oppose El Paso's motion to employ special
litigation counsel, the hiring and future use of litigation
counsel may be incongruous with the goal of consummating the
Merger. The response also stated that El Paso's Disclosure
Statement, pursuant to which it obtained confirmation of its Plan
of Reorganization, contained projections that explicitly assume
the continuation of service to Las Cruces and two military
installations in New Mexico.
By letter dated December 21, 1994, El Paso objected to CSW's
motion filed with the New Mexico Commission to extend the
procedural schedule by two-weeks. CSW responded to El Paso in a
letter dated January 11, 1995, that CSW considered the short two
week extension to be in the best interest of obtaining favorable
and timely regulatory approval in New Mexico. The two weeks were
to be used to facilitate efforts to narrow and resolve outstanding
issues in the proceedings and thereby expedite the progress of
those proceedings. El Paso restated its disagreement to CSW's
motion for extension in a letter dated January 16, 1995.
By letter dated January 13, 1995, CSW recommended that El Paso
object to a request by the Equity Committee to renew its
engagement of Salomon Brothers as financial advisor to said
committee. CSW stated that the Merger Agreement requires the
parties to cooperate in limiting professional fees and that the
cost and timing of the reengagement is inappropriate. By letter
dated January 20, 1995, El Paso responded to CSW that the Equity
Committee's request to reemploy Salomon is a direct consequence of
CSW's September 12 letter to El Paso and that it supports the
Equity Committee's application. El Paso subsequently filed a
statement of support of the Equity Committee's request in the
Bankruptcy Court. On February 6, 1995, the Equity Committee of El
Paso filed a response in the Bankruptcy Court to objections made
by other parties to its rehiring of financial advisors in which
the committee accused CSW of taking moves to back out of the
Merger Agreement, thereby causing harm to the equity holders.
On January 3, 1995, a PFD was issued by the presiding officers in
the proceedings pending before the Texas Commission relating to
the Merger. On January 17, 1995, CSW and El Paso filed joint
exceptions to the proposed decision, stating, among other things,
that, "in CSW's view, the rate relief recommended . . . falls far
short of what is necessary for the consummation of the merger."
That same day, CSW issued a press release describing the filing of
the exceptions and repeating CSW's view that the terms of the
proposed interim decision failed to provide sufficient revenue and
adequate rate-making treatment for CSW to consummate the proposed
Merger.
In a letter dated January 19, 1995, El Paso objected to the tenor
of CSW's January 17 press release and claimed that CSW's press
release harmed El Paso, its creditors, and shareholders and
poisoned the regulatory approval process. CSW responded in a
letter dated January 31 that it is El Paso's actions that have
hindered obtaining the regulatory approvals necessary to
consummate the Merger and that these actions were contrary to El
Paso's obligations under the Merger Agreement. Further, CSW
called on El Paso again to detail the steps it proposes to take to
solve the problems identified by CSW in its September 12 letter
cited in the PFD by the hearing examiners of the Texas Commission,
and to desist from further actions which undercut CSW's efforts to
obtain the rate relief, asset treatment and required regulatory
approvals necessary to consummate the Merger.
On February 17, 1995, El Paso responded to CSW's January 31, 1995
letter stating that CSW's assertion that El Paso has breached the
Merger Agreement are unfounded. El Paso further accused CSW of
searching for a "viable contractual excuse" not to close the
Merger.
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On February 20, 1995, El Paso sent a letter to CSW inquiring
whether CSW would consent to the sale of the Las Cruces service
territory by El Paso and, if so, on what terms and at what price.
In addition, the letter inquired whether CSW would consent to a
rate reduction in New Mexico and, if so, at what percentage
reduction over what period of time. CSW responded in a February
27, 1995 letter that CSW is unwilling to give up any more of the
value it bargained for in the Merger Agreement, or to accept the
risk of a litigated outcome with Las Cruces. However, CSW
encouraged dialogue between El Paso and Las Cruces and stated it
continues to support El Paso's efforts to resolve its dispute with
Las Cruces. CSW stated it is amenable to considering any
alternatives negotiated between Las Cruces and El Paso that would
not deprive the Merger of further value and that would enable El
Paso to continue to serve the Las Cruces service area or provide
El Paso with full compensation for the loss of Las Cruces. CSW
looks to El Paso to resolve this situation prior to consummation
of the proposed Merger.
Texas Commission Applications
On January 10, 1994, CSW and El Paso filed a joint application
with the Texas Commission requesting a determination that the
Merger is consistent with the public interest. As a part of the
application, CSW proposed a three-step rate settlement plan,
contingent upon the Texas Commission's approval of the Merger,
that seeks to limit El Paso's proposed $41.4 million initial base
rate increase for Texas customers, discussed below, to $25
million. In addition, the settlement rate plan proposed to reduce
El Paso's fixed fuel factors by $12.8 million and refund $16.4
million from a one-time fuel reconciliation. As a result of the
proposed annual reductions in fuel cost, El Paso's rates would not
increase during the first year of the settlement plan. The
settlement plan also provided for a three-year freeze on
additional base rate increases, a limitation on the frequency of
base rate increases following the rate freeze period through 2001
to not more than once every other year (i.e., 1997, 1999, and
2001), and a limitation on the amount of the 1997, 1999 and 2001
base rate increases to an amount not to exceed eight percent of
total revenues. No party to the proceedings accepted CSW's rate
settlement plan.
On January 10, 1994, El Paso separately filed with the Texas
Commission for a base rate increase, exclusive of fuel, of
approximately $41.4 million. The proposed rate increase
represents what El Paso has stated it believes is supported under
Texas law and prior Texas Commission orders, adjusted to reflect
El Paso's proposed Merger with CSW. If the Texas Commission were
to approve El Paso's request, the net effect would be to raise
rates significantly higher than those proposed in the settlement
plan.
On June 23, 1994, the El Paso City Council voted to reduce El
Paso's rates $15.7 million following a recommendation from the
City of El Paso's Public Utility Regulation Board. The City of El
Paso's decision was appealed to the Texas Commission and
consolidated with the rate case pending before that commission.
On June 24, 1994, the Staff filed testimony in the case before the
Texas Commission recommending an increase in base rates of $17.1
million and taking the position that the proposed Merger is not in
the public interest because of the possible cost increases to
CSW's subsidiaries, which the Staff attributed to increased
financial risk associated with the proposed acquisition of El
Paso. The Staff's recommendation was revised and increased to a
$21.5 million increase in base rates for El Paso in October 1994.
In addition, the Staff determined that the proposed purchase price
for El Paso is too high by $300 to $500 million and disagreed with
the estimates of the Merger-related savings presented by CSW and
El Paso in the case. Hearings at the Texas Commission began on
July 20, 1994 and were completed in early November 1994.
Effective July 16, 1994, El Paso implemented under bond, a base
rate increase of approximately $25 million annually for its Texas
jurisdiction, which is subject to refund depending on the outcome
of the rate case. The bonded increase in rates is authorized
under PURA. Because of the current uncertainty as to the final
outcome of the rate proceeding, El Paso has stated that it is
deferring on its books the recognition of the revenues resulting
from the increased rates.
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On January 3, 1995, the Texas Commission presiding officers who
heard El Paso's pending rate case and the CSW and El Paso Merger
case filed their proposed interim decision with the Texas
Commission. The presiding officers proposed an initial base-rate
increase for El Paso of $21.2 million. The PFD recommends a
determination by the Texas Commission that the Merger and the
reacquisition of the leased Paso Verde assets are in the public
interest and that the purchase price to be paid to El Paso's
creditors and equity holders is fair, subject to satisfactory
resolution of the Las Cruces and Palo Verde problems. The
presiding officers found Merger related benefits ranging from $309
million to $379.4 million over the first ten years of the Merger
which the presiding officers allocated to El Paso's customers
under the PFD.
In addition to recommending the imposition of conditions in the
determination that the Merger is in the public interest, the PFD
failed to provide sufficient revenue and adequate rate-making
treatment for CSW to consummate the proposed Merger.
Specifically, the presiding officers propose to reduce El Paso's
rates by allocating to customers certain potential tax benefits
related to the payment of lease rejection damages on the leased
Palo Verde assets. Reallocation of these tax benefits to
customers effectively increases the acquisition cost to CSW by
$133 million. The presiding officers attempted to mitigate the
economic effect of their allocation of these tax benefits by
allowing recovery through rates of an acquisition adjustment over
the remaining 33 year life of Palo Verde. However, CSW believes
that the proposed recovery through rates of an acquisition
adjustment has considerably less economic value than the tax
deductions. The presiding officers also recommended a reduction
in El Paso's rate moderation plan and disallowance of El Paso's
Palo Verde Unit 3 deferred accounting assets. CSW believes that,
in recommending these rate treatments, the PFD fails to recognize
rate relief to which El Paso is entitled under previous Texas
Commission decisions in El Paso rate cases. Additionally, the PFD
proposed an 11.5% return on equity rather than a 12.5% return
which CSW believes is necessary for El Paso to have the
opportunity to earn a reasonable return on its equity. Finally,
the presiding officers proposed that the Texas Commission's
interim order be conditioned on the successful resolution of the
loss of Las Cruces as a customer of El Paso and on the successful
resolution of the Palo Verde steam generator problems.
On March 3, 1995, the Texas Commission issued an interim order in
the El Paso rate case and proposed Merger with CSW. The interim
order found the proposed Merger to be in the public interest and
provides for a $24.9 million base rate increase for El Paso. The
interim order adopted most of the recommendations of the presiding
officers. The most significant revision to the presiding officers
recommendations was an increase in the allowed return on equity
from 11.5% to 12%. The presiding officers' recommendations were
adopted in the interim decision for several significant issues
even though agreement was not reached by the Texas Commission.
The interim decision allows for motions for reconsideration to be
filed on these issues. The Texas Commission has indicated that
the motions for reconsideration will be granted to allow for a
consensus of the Texas Commission to be reached on these issues
prior to the effective date of the merger. These issues included
conditioning approval of the merger on resolution of the Las
Cruces and Palo Verde issues, the rate treatment of the tax
effects of lease rejection damages, recovery of any acquisition
adjustment and deferred costs associated with the regulatory lag
period prior to the rate treatment of Palo Verde Unit 3. Pending
resolution of these issues, the Texas Commission allowed El Paso's
bonded rates to remain in effect until a subsequent interim
decision is issued.
The Texas Commission severed fuel related issues from the El Paso
rate case and issued a final order which allows for El Paso to
lower fixed fuel factors by $14.3 million annually and to refund
$13.7 million in fuel costs over a twelve month period.
New Mexico Commission Application
On March 14, 1994, CSW and El Paso filed an application with the
New Mexico Commission seeking approval of the pending Merger, the
reacquisition of the leased Palo Verde assets and certain
accounting treatments. On February 10, 1995, the New Mexico
Commission Staff filed testimony recommending approval of each of
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these requests. El Paso plans to seek approval for the issuance
of securities in connection with the Merger.
On October 27, 1994, the hearing examiner assigned to hear CSW and
El Paso's Merger application before the New Mexico Commission
issued an order amending the procedural schedule to provide for
hearings beginning February 13, 1995. On December 21, 1994, the
hearing examiner issued an order granting a two week extension to
the procedural schedule, resulting in hearings beginning February
27, 1995. Hearings in New Mexico were completed on March 2, 1995.
This revised schedule allows for the issuance of a final order by
the New Mexico Commission by June 1995. However, CSW cannot
predict when a final order may be issued by the New Mexico
Commission.
FERC Applications
On November 4, 1993, CSWS, as agent for the Electric Operating
Companies and El Paso, filed an application with the FERC under
Section 211 of the Federal Power Act seeking an order of the FERC
and requiring SPS to provide firm and non-firm transmission
services in connection with the transfers of power between PSO and
El Paso in connection with the post-Merger coordinated operations
of the Electric Operating Companies and El Paso. The intent of
the transmission services is to obtain the benefits of integrated
operations and thereby meet the requirement of the Holding Company
Act that the Electric Operating Companies and El Paso be
physically interconnected or capable of physical interconnection
and economically operated as a single interconnected and
coordinated electric system. SPS subsequently requested that the
application be dismissed or, in the alternative, be set for
hearing.
On January 10, 1994, as supplemented on January 13, 1994, CSWS, on
behalf of the Electric Operating Companies and El Paso, filed a
joint application with the FERC under Sections 203 and 205 of the
Federal Power Act requesting approval by the FERC of the Merger.
CSWS and El Paso have requested expedited consideration of the
joint application. However, CSW cannot predict at this time when
the FERC will issue a final decision on the joint application.
On August 1, 1994, the FERC issued orders in two proceedings that
relate to the Merger. In an order issued under Section 211 of the
Federal Power Act, the FERC preliminarily found that "a final
order requiring SPS to provide the transmission service requested
by the Applicants would comply with the statutory standards, once
reliability concerns have been met." The FERC's order rejects
assertions made by SPS that the FERC has no authority under
Section 211 to order transmission service where the purpose of the
service is to allow coordination of merging utilities' operations.
The order directed SPS to perform studies so that the FERC can
determine whether provision of the requested transmission service
will unreasonably impair reliability. Such studies and
supplemental pleadings analyzing the studies were filed with the
FERC in early October and November 1994. If, after reviewing the
studies and comments filed by SPS, CSWS and El Paso, the FERC
concludes that reliability will not be unreasonably impaired, the
FERC will issue a further "proposed order" requiring El Paso, CSWS
and SPS to negotiate the rates, terms and conditions on which the
requested transmission service will be provided.
The FERC also issued an order under Section 203 of the FPA in
which the FERC ruled that it will require merging utilities to
offer transmission service to others on a basis that is comparable
to their own uses of their transmission systems. On August 10,
1994, CSW and El Paso notified the FERC that they will accept, as
a condition to the FERC's approval of CSW's acquisition of El
Paso, the requirement to amend their non-ERCOT transmission
tariffs to offer "comparable service." On August 31, 1994, CSW
and El Paso filed with the FERC a request for rehearing that,
among other things, asks the FERC to reconsider the imposition of
the comparable service requirement. On August 31, 1994, CSW and
El Paso also filed the form of transmission tariffs they would
propose to file with the FERC in order to meet the comparable
service requirement if the requirement is upheld and the Merger is
consummated. In agreeing to accept, as a condition to the Merger,
the requirement that comparable service be provided over CSW's and
El Paso's non-ERCOT transmission facilities, both CSW and El Paso
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do not intend to waive or otherwise prejudice any of their rights,
including but not limited to the right to seek rehearing of the
order or any other order the FERC later enters in these
proceedings. In addition, both CSW and El Paso do not intend to
waive or otherwise prejudice their right under the FPA to seek
judicial review of the order or any subsequent order or orders, if
and to the extent CSW and El Paso deem such action necessary or
advisable.
The FERC has not yet determined what "comparable service" is.
However, the FERC said it will establish what uses PSO, SWEPCO and
El Paso make of their own systems. The FERC will also examine
likely costs and benefits of the Merger and determine whether the
Merger is consistent with the public interest. The FERC has
instructed one of its administrative law judges to issue an
initial decision by April 14, 1995. A FERC administrative law
judge established a procedural schedule whereby hearings began
January 3, 1995. Hearings ended January 25, 1995, and the judge's
initial decision is expected to be issued on or before April 5,
1995.
On November 15, 1994, the FERC trial staff filed its testimony in
the Merger proceeding. The FERC staff determined that the
proposed Merger will result in total savings of $414 million, $265
million in net present value for the period 1995 through 2004 of
post-Merger operations. This compares to Merger savings projected
by CSW for the same period of $420 million, or $280 million in net
present value. The staff found $140.7 million in non-fuel O&M
expense savings, $109.0 million in financial savings, and $15.3
million in production cost savings.
The FERC staff has recommended that approval of the Merger be made
subject to two conditions. As required in the FERC's August 1,
1994 order, the merged companies must offer the use of their non-
ERCOT transmission system to others under rates, terms and
conditions comparable to the rates, terms and conditions under
which CSW will use their non-ERCOT transmission system. The FERC
staff has also recommended that the Merger be approved,
conditioned on the existing CSW Operating Companies not being
allocated any transmission costs associated with firm transmission
service across SPS's system in excess of $24.6 million, which is
the amount CSW projects through 2004.
The FERC staff also determined that "hold harmless conditions"
proposed by various state utility commissions and other
intervenors to protect CSW Operating Companies from certain
potential effects of the Merger are unnecessary to assure that the
Merger is in the public interest. The FERC staff concluded that:
As proposed, the Merger is beneficial to El Paso and is
roughly neutral with respect to the four present CSW
Operating Companies. If enacted as proposed, with the
Applicants' voluntary offer to exclude Merger-related
transmission expenses of non-affiliates from the
transmission customers of CSW's four current Operating
Companies, the Merger should not substantially harm any
class of wholesale customers.
SEC Application
On January 10, 1994, CSW filed with the SEC an application under
the Holding Company Act seeking authorization of (i) the Merger
and reacquisition of the Palo Verde leased assets, (ii) the
issuance of securities by CSW and El Paso in connection with the
Modified Plan and Merger and certain related transactions, and
(iii) to engage in certain hedging transactions in connection with
the Merger. CSW subsequently amended the application to eliminate
the request for authorization to engage in certain hedging
transactions, at the request of the SEC staff. CSW has
subsequently amended and supplemented the application and has
filed a brief in response to intervention petitions. CSW cannot
predict what action the SEC will take with respect to the
application, or when such action will be taken.
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NRC Application
On January 13, 1994, APS, as operating agent for Palo Verde,
joined by El Paso, filed a request with the NRC for (i) consent to
the indirect transfer of El Paso's interest in the operating
licenses for Palo Verde Units 1, 2, and 3 that will occur as a
result of the Merger, and (ii) to amend the operating licenses for
Units 2 and 3 to delete provisions of those licenses related to El
Paso's sale and leaseback transactions involving those units. The
request to the NRC specifies that the proposed amendments to the
operating licenses and consent become effective on the Effective
Date, but CSW cannot predict at this time whether and, if so, when
the approvals and consent will be granted.
Palo Verde
The operating agent of Palo Verde, APS, discovered axial cracking
in steam generator tubes in Unit 2 following a tube rupture in
March 1993. APS began an ongoing examination and analysis of the
tubes in each of the two steam generators in each unit of Palo
Verde and, as a result, has identified axial cracking in Unit 3
and another more common type of cracking in the steam generator
tubes of all three units. APS has indicated that it believes the
axial cracking in Units 2 and 3 is due to the susceptibility of
tube materials to a combination of deposits on the tubes and the
relatively high temperatures at which all three units at Palo
Verde are designed to operate. According to statements by APS and
El Paso, the form of the degradation experienced in the steam
generators is uncommon in the nuclear industry. APS has stated
that it believes it can retard further tube degradation to
acceptable levels by remedial actions, which include chemically
cleaning the steam generators and performing analyses and
adjustments that will allow the units to be operated at lower
temperatures without appreciably reducing their power output.
These analyses and adjustments have been performed on all three
units, with each unit operating at 100% of capability. All
remedial actions have been completed on each of the three units,
except for chemically cleaning Unit 1 which is scheduled for April
1995. El Paso has stated that it is incurring increased
maintenance costs related to the mid-cycle inspections of the
steam generator tubes and the remedial actions being undertaken to
retard tube degradation. El Paso also incurs additional costs for
fuel and/or purchased power during periods in which one or more
units are removed from service every 6 months for inspections. In
its September 12, 1994 letter to El Paso, CSW stated that the
significance of the tube cracking problems will have to be
determined before CSW will close the Merger.
Other
El Paso is subject to the informational requirements of the
Securities and Exchange Act of 1934, as amended, and in accordance
therewith files reports and other information with the SEC. See
El Paso's Quarterly Reports on Form 10-Q, its Current Reports on
Form 8-K and its Annual Report on Form 10-K and the documents
referenced therein.
CSW continues to use its best efforts to consummate the Merger.
At the same time, however, CSW continues to monitor contingencies
which may preclude the consummation of the Merger, including
without limitation the potential loss of significant portions of
El Paso's service area and significant El Paso customers,
including Las Cruces and two military installations, Holloman Air
Force Base and White Sands Missile Range, regulatory risks
principally related to approval of the Merger and El Paso's
request for a rate increase in Texas as well as the effects of the
conditions imposed by federal or state regulatory agencies on the
approval of the Merger, and operating risks associated with the
ownership of an interest in Palo Verde.
Based upon El Paso's written response to the concerns identified
in CSW's September 12 letter and the failure of El Paso to resolve
items set forth in the preceding paragraph, CSW cannot predict
whether, and if so when, the Merger will be consummated. In the
event that the proposed Merger is not consummated, there may be
ensuing litigation between El Paso and CSW or among other parties
to El Paso's bankruptcy proceedings and either or both of El Paso
and CSW.
2-62
See MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - Proposed Acquisition of El Paso, for
further information.
Other Commitments and Contingencies
Construction
It is estimated that the CSW System will spend approximately $385
million in construction expenditures during 1995. Substantial
commitments have been made in connection with this construction
expenditure program.
Fuel
To supply a portion of the fuel requirements of the CSW System,
the subsidiary companies have entered into various commitments for
the procurement of fuel.
SWEPCO
Henry W. Pirkey Power Plant
In connection with the South Hallsville lignite mining contract
for its Henry W. Pirkey Power Plant, SWEPCO has agreed, under
certain conditions, to assume the obligations of the mining
contractor. As of December 31, 1994, the maximum amount SWEPCO
would have to assume was $73.7 million. The maximum amount may
vary as the mining contractor's need for funds fluctuates. The
contractor's actual obligation outstanding at December 31, 1994
was $60.9 million.
South Hallsville Lignite Mine
As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining at the South Hallsville
lignite mine, SWEPCO has agreed to provide bond guarantees on mine
reclamation in the amount of $70 million. Since SWEPCO uses self-
bonding, the guarantee provides for SWEPCO to commit to use its
resources to complete the reclamation in the event the work is not
completed by the third party miner. The current estimate of cost
to reclaim the mine is estimated to be approximately $25 million.
Coal Transportation
SWEPCO has entered into various financing arrangements primarily
with respect to coal transportation and related equipment, which
are treated as operating leases for rate-making purposes. At
December 31, 1994, leased assets of $46 million, net of
accumulated amortization of $30.1 million, were included in
electric plant on the balance sheet and at December 31, 1993,
leased assets were $46 million, net of accumulated amortization of
$26.8 million. Total charges to operating expenses for leases
were $6.8 million, $7.1 million, and $6.9 million for the years
1994, 1993, and 1992.
Suspected MGP Site in Marshall, Texas
SWEPCO owns a suspected former MGP site in Marshall, Texas.
SWEPCO has notified the TNRCC that evidence of contamination has
been found at the site. As a result of sampling conducted at the
end of 1993 and early 1994, SWEPCO is evaluating the extent, if
any, to which contamination has impacted soil, groundwater and
other conditions in the area. A final range of clean-up costs has
not yet been determined, but, based on a preliminary estimate,
SWEPCO has accrued approximately $2 million as a liability for
this site on SWEPCO's books as of December 31, 1993. As more
information is obtained about the site, and SWEPCO discusses the
site with the TNRCC, the preliminary estimate may change.
Suspected MGP Site in Texarkana, Texas and Arkansas and
Shreveport, Louisiana
SWEPCO also owns a suspected former MGP site in Texarkana, Texas
and Arkansas. The EPA ordered an initial investigation of this
site, as well as one in Shreveport, Louisiana, which is no longer
owned by SWEPCO. The contractor who performed the investigations
of these two sites recommended to the EPA that no further action
be taken at this time.
2-63
Biloxi, Mississippi MGP Site
SWEPCO has been notified by Mississippi Power Company that it may
be a PRP at the former Biloxi MGP site formerly owned and operated
by a predecessor of SWEPCO. SWEPCO is working with Mississippi
Power Company to investigate the extent of contamination at this
site. The MDEQ approved a site investigation work plan and, in
January 1995, SWEPCO and Mississippi Power Company initiated
sampling pursuant to that work plan. On an interim basis, SWEPCO
and Mississippi Power Company are each paying fifty percent of the
cost of implementing the site investigation work plan. That
interim allocation is subject to a final allocation in the future.
SWEPCO and Mississippi Power Company are investigating whether
there are other PRPs at the Biloxi site. Until the extent of the
contamination at the Biloxi site is identified, it is unknown
what, if any, additional investigation or cleanup may be required.
Management does not expect these matters to have a material effect
on CSW's consolidated results of operations or financial position.
WTU
WTU has a sale/leaseback agreement with Transok for full capacity
use of a natural gas pipeline to WTU's Ft. Phantom generating
plant. The lease agreement also provides for full capacity use of
Transok's natural gas pipelines serving WTU's San Angelo and Oak
Creek generating plants. The initial terms of the agreement are
for twelve years with renewable options thereafter.
CPL
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 $8.92 billion per incident, effective as of
January 1995. 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 $8.72 billion. The maximum amount
that each licensee may be assessed under the industry-wide program
of self-insurance following a nuclear incident at an insured
facility is $75.5 million per reactor, 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. CPL and each of the other STP owners are subject to
such assessments, which CPL and other owners have agreed will be
allocated 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 $2.75
billion provided by ANI and NEIL. Policies of insurance issued by
ANI and NEIL stipulate that policy proceeds must be used first to
pay decontamination and clean-up costs before being used to cover
direct losses to property. Under project agreements, CPL and the
other owners of STP will share the total cost of decontamination
liability and property insurance for STP, including premiums and
assessments, on a pro rata basis, according to each owner's
respective ownership interest in STP.
CPL purchases, for its own account, a NEIL I Business Interruption
and/or Extra Expense policy. This insurance will reimburse CPL
for extra expenses incurred, up to $1.65 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 $111.3
million and for Unit 2 is $111.8 million. CPL is subject to an
additional assessment up to $2.1 million for the current policy
2-64
year in the event that losses as a result of a covered accident at
a nuclear facility insured under the NEIL I policy exceeds the
accumulated funds available under the policy.
On August 28, 1994, CPL filed a claim under the NEIL I policy
related to the outage at STP Units 1 and 2. NEIL is currently
reviewing the claim. CPL management is unable to predict the
ultimate outcome of this matter.
CSWE
CSWE has provided construction services to the Mulberry
cogeneration facility through a wholly-owned subsidiary, CSW
Development-I, Inc. The project achieved commercial operation in
August 1994 and added 117 MWs of on-line capacity of which CSWE
owns 50%. CSWE's maximum potential liability under the fixed
price contract is $83 million and will decrease to zero over the
next two years as contractual standards are met. Additionally,
CSW Development-I, Inc. has entered into a fixed price contract to
construct the Mulberry thermal host facility. The maximum
potential liability under this fixed price contract is $14
million. The thermal host facility is expected to be completed by
the first quarter of 1995. CSW has provided additional guarantees
to the project totaling approximately $57 million.
CSWE has entered into a purchase agreement on the Ft. Lupton
project to provide $79.5 million of equity upon the occurrence of
certain events. As of January 9, 1995, $43 million has been paid.
CSWE has provided three letters of credit to the project totaling
$14.3 million. During March 1995, CSWE closed permanent project
financing on the Ft. Lupton facility in the amount of $208
million.
CSWE has committed to provide up to $125 million of construction
financing to the Orange cogeneration project in which CSWE owns a
50% interest. Of this total, CSWE has provided $62 million at
December 31, 1994. CSWE expects to obtain third party permanent
financing for this project in 1995.
In November 1994, CSWE transferred its 50% interest in the 40 MW
Oildale cogeneration facility to two non-affiliated third parties,
Oildale Holdings, Inc. and Oildale Holdings II, Inc. The Oildale
project, which was financed with third party non-recourse project
financing, had been in default of certain provisions of its loan
agreement since December 1993. Under the terms of the project
transfer, CSWE contributed $3 million in equity in exchange for
the return of a letter of credit in the same amount in favor of a
third party lender.
In addition, CSWE has posted security deposits and other security
instruments of approximately $14 million on six additional
projects in various stages of development, construction, and
operation.
2-65
12. Business Segments
CSW's business segments include electric utility operations (CPL,
PSO, SWEPCO, WTU), and gas operations (Transok). Seven non-
utility companies are included in corporate items (CSWE, CSWI, CSW
Communications, CSW Credit, CSW Leasing, CSWS and CSW).
CSW's business segment information follows:
1994 1993 1992
(millions)
Operating Revenues
Electric $ 3,065 $ 3,055 $ 2,790
Gas 518 603 496
Corporate items and other 40 29 3
$ 3,623 $ 3,687 $ 3,289
Operating Income
Electric $ 728 $ 559 $ 694
Gas 49 25 42
Corporate items and other 6 5 1
Total operating income before taxes 783 589 737
Income taxes 189 132 149
$ 594 $ 457 $ 588
Depreciation and Amortization
Electric $ 316 $ 296 $ 284
Gas 32 29 22
Corporate items and other 8 5 5
$ 356 $ 330 $ 311
Identifiable Assets
Electric $ 9,066 $ 8,927 $ 8,575
Gas 724 684 674
Corporate items and other 1,119 993 580
$10,909 $10,604 $ 9,829
Capital expenditures and acquisitions
Electric $ 493 $ 481 $ 325
Gas 65 88 101
Corporate items and other (1) 114 64 31
$ 672 $ 633 $ 457
(1) Includes CSWE Equity Investments.
2-66
13. Quarterly Information (Unaudited)
The following unaudited quarterly information includes, in the
opinion of management, all adjustments necessary for a fair
presentation of such amounts.
Earnings
per Share
Operating Operating Net of Common
Quarter Ended Revenues Income Income Stock
(millions)
1994
March 31 $ 850 $ 93 $ 48 $0.23
June 30 908 157 107 0.55
September 30 1,070 239 189 0.97
December 31 795 105 68 0.33
$3,623 $ 594 $ 412 $2.08
1993
March 31 $ 810 $ 97 $ 92 $0.47
June 30 894 144 96 0.48
September 30 1,140 219 181 0.93
December 31 843 (3) (42) (0.25)
$3,687 $ 457 $ 327 $1.63
Information for quarterly periods is affected by seasonal
variations in sales, rate changes, timing of fuel expense recovery
and other factors.
2-67
Report of Independent Public Accountants
To the Stockholders and Board of Directors of Central and South West
Corporation:
We have audited the accompanying consolidated balance sheets of
Central and South West Corporation (a Delaware corporation) and
subsidiary companies, as of December 31, 1994 and 1993, and the
related consolidated statements of income, retained earnings and
cash flows, for each of the three years in the period ended December
31, 1994. These financial statements are the responsibility of the
Corporation'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 and South West Corporation and subsidiary companies as of
December 31, 1994 and 1993, and the results of their operations and
their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting
principles.
In 1993, as discussed in NOTE 1, Central and South West
Corporation and subsidiary companies changed their 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
Schedule II is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the
basic financial statements. This schedule has been subjected to the
auditing procedures applied in the audits of the basic financial
statements and, in our opinion, fairly states 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 LLP
Dallas, Texas
February 13, 1995
2-68
Report of Management
Management is responsible for the preparation, integrity and
objectivity of the consolidated financial statements of Central and
South West Corporation and subsidiary companies as well as other
information contained in this Annual Report. The consolidated
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 Annual Report is consistent
with that in the consolidated financial statements.
The consolidated financial statements have been audited by the
independent accounting firm, Arthur Andersen LLP, which was given
unrestricted access to all financial records and related data,
including minutes of all meetings of stockholders, the board of
directors and committees of the board. CSW and its subsidiaries
believe that representations made to the independent auditors during
their audit were valid and appropriate. Arthur Andersen LLP's audit
report is presented elsewhere in this report.
CSW, together with its subsidiary companies, maintains a system
of internal controls to provide reasonable assurance that
transactions are executed in accordance with management's
authorization, that the consolidated financial statements are
prepared in accordance with generally accepted accounting principles
and that the assets of CSW and its subsidiaries are properly
safeguarded against unauthorized acquisition, use or disposition. The
system includes a documented organizational structure and division of
responsibility, established policies and procedures including a
policy on ethical standards which provides that the companies will
maintain the highest legal and ethical standards, and the careful
selection, training and development of our employees.
Internal auditors continuously monitor the effectiveness of the
internal control system following standards established by the
Institute of Internal Auditors. Actions are taken by management to
respond to deficiencies as they are identified. The board, operating
through its audit committee, which is comprised entirely of directors
who are not officers or employees of CSW or its subsidiaries,
provides oversight to the financial reporting process.
Due to the inherent limitations in the effectiveness of internal
controls, no internal control system can provide absolute assurance
that errors will not occur. However, management strives to maintain
a balance, recognizing that the cost of such a system should not
exceed the benefits derived.
CSW and its subsidiaries believe that, in all material respects,
its system of internal controls over financial reporting and over
safeguarding of assets against unauthorized acquisition, use or
disposition functioned effectively during 1994.
E. R. Brooks Glenn D. Rosilier Wendy G. Hargus
Chairman, President and Senior Vice President and Controller
Chief Executive Officer Chief Financial Officer
2-70
CPL
CENTRAL POWER AND LIGHT COMPANY
Selected Financial Data
CPL
The following selected financial data for each of the five years
ended December 31 are provided to highlight significant trends in the
financial condition and results of operations for CPL.
1994 1993 1992 1991 1990
(thousands, except ratios)
Electric Operating
Revenues $1,217,979 $1,223,528 $1,113,423 $1,098,730 $ 948,520
Income Before
Cumulative Effect
of Changes in
Accounting
Principles 205,439 145,130 218,511 217,206 204,870
Cumulative Effect
of Changes in
Accounting
Principles (1) -- 27,295 -- -- --
Net Income 205,439 172,425 218,511 217,206 204,870
Preferred Stock
Dividends 13,804 14,003 16,070 19,844 23,528
Net Income for Common
Stock 191,635 158,422 202,441 197,362 181,342
Total Assets (2) 4,822,699 4,781,745 4,583,660 4,458,063 4,516,375
Common Stock Equity 1,431,354 1,424,195 1,437,876 1,428,547 1,449,409
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
Long-term Debt 1,466,393 1,362,799 1,347,887 1,350,854 1,346,587
Ratio of Earnings
to Fixed Charges
(SEC Method)
Before
Cumulative Effect
of Changes in
Accounting
Principles 3.24 2.69 3.23 3.18 3.11
Capitalization Ratios
Common Stock Equity 45.5% 46.6% 46.9% 46.6% 47.0%
Preferred Stock 7.9 8.9 9.1 9.3 9.4
Long-term Debt 46.6 44.5 44.0 44.1 43.6
(1) The 1993 cumulative effect relates to the changes in accounting
for unbilled revenues and adoption of SFAS No. 112. See NOTE 1,
Summary of Significant Accounting Policies.
(2) The 1992-1990 total assets have been reclassified to reflect the
effects of the adoption in 1993 of SFAS No. 109. See NOTE 2,
Federal Income Taxes.
CPL 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 reported for prior years and therefore has not
been restated.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
CENTRAL POWER AND LIGHT COMPANY
Reference is made to CPL's Financial Statements and related
Notes and Selected Financial Data. 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 1994 increased 21% to $192
million from $158 million in 1993. The increase was due primarily
to an increase in base revenues, a decrease in restructuring costs
and a decrease in maintenance expense. Such increases were
partially offset by the cumulative effect of changes in accounting
principles recorded in 1993.
Restructuring
As previously reported, CPL has taken steps to implement a
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 restructuring is to enable
CPL to focus on and be accountable for serving the customer. The
restructuring costs were initially estimated to be $29 million and
were expensed in 1993. The final costs of the restructuring were
approximately $29 million. Approximately $28 million of the
restructuring expenditures were incurred during 1994, with the
remaining $1 million expected to be incurred during 1995.
Approximately $4 million of the restructuring expenses relate to
employee termination benefits, $15 million relate to enhanced benefit
costs and $10 million relate to employees that will not be
terminated. Approximately $21 million of the restructuring costs
were paid from or will be paid from general corporate funds. The
remaining $8 million represents the present value of enhanced benefit
amounts to be paid from the benefit plan trusts to participants over
future years in accordance with the early retirement program. The
cost of these enhanced benefit amounts will be paid from general
corporate funds to the benefit plan trusts over future years. The
restructuring is substantially completed, with the remaining activity
to take place during 1995. Certain aspects of the restructuring are
pending SEC approval under the Holding Company Act.
CPL expects to realize a number of benefits from the
restructuring. Beginning in 1994 and continuing into the future,
increased efficiencies and synergies are expected to be realized with
the elimination of previously duplicated functions. This leads to
enhanced communication and efficiency, which should translate into a
reduction in the rate of growth in O&M costs. The CSW System expects
that all restructuring costs will be recovered by early 1996 with
reductions in the rate of growth of O&M costs continuing thereafter.
STP
Introduction
CPL owns 25.2% of STP, a two-unit nuclear power plant which is
located near Bay City, Texas. In addition to CPL, 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.
From February 1993 until May 1994, STP experienced an
unscheduled outage which has resulted in significant rate and
regulatory proceedings involving CPL. These matters, including a
base rate case and fuel reconciliation proceedings, are discussed
immediately below.
STP Outage
In February 1993, Units 1 and 2 of STP were shut down by HLP in
an unscheduled outage resulting from mechanical problems. 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
2-72
these failures and the corrective actions that were taken. The NRC
formalized that commitment in a confirmatory action letter that it
supplemented to identify additional issues to be resolved and
verified by the NRC before STP could be restarted.
During the outage, the necessary improvements were 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 agreed with HLP's recommendation that Unit 1 was
ready to restart. Unit 1 restarted on February 25, 1994 and reached
100% power on April 8, 1994. Subsequently, the issues with respect
to Unit 2 were resolved and the NRC on May 17, 1994 agreed with HLP's
recommendation to restart Unit 2. Unit 2 resumed operation on May
30, 1994 and reached 100% power on June 16, 1994. During 1994, Unit
1 and Unit 2 achieved annual net capacity factors of 75.3% and 54.7%,
respectively. During the last six months of 1994, the STP units
operated at capacity factors of 98.6% for Unit 1 and 99.2% for Unit
2.
In June 1993, the NRC placed STP on its "watch list" of plants
with "weaknesses that warrant increased NRC attention." The decision
to place STP on the watch list followed the June 1993 issuance of a
report by an NRC Diagnostic Evaluation Team which conducted a review
of STP operations.
On February 3, 1995, the NRC removed STP from the "watch list".
The NRC noted that the four key areas for their decision were
sustained improvement throughout 1994, high standards of performance
exhibited by the plant, effective maintenance and engineering support
resulting in reduced equipment repair backlogs and improved plant
reliability, and the open and positive employee climate at the plant.
With the NRC reviewing the "watch list" status every 6 months and
with Unit 2 achieving 100% power in June of 1994, the February review
was the first realistic opportunity for STP to be considered for a
change in status. On average, plants previously placed on the "watch
list" have stayed on the list for 29 months.
Rates and Regulatory Matters
CPL Rate Inquiry
Several Cities, the Texas Commission General Counsel and others
initiated actions in late 1993 and early 1994 which, if approved by
the Texas Commission, would lower CPL's base rates. The requests for
a review of CPL's rates arose out of the unscheduled outage at STP
which began in February 1993. The STP outage did not affect CPL's
ability to meet customer demand because of existing capacity and
CPL's purchase of additional energy.
CPL submitted an RFP on July 1, 1994, to the Texas Commission
justifying its current base rate structure. Parties to CPL's base
rate case have filed testimony with the Texas Commission recommending
reductions in CPL's retail base rates of up to $147 million annually,
resulting from a combination of proposed rate base and cost of
service reductions, as well as a rate base disallowance of up to $400
million.
The Texas Commission held hearings in November and December
1994, and all parties have filed briefs in the case. The ALJ is
expected to issue a recommended order for consideration by the Texas
Commission in April 1995 with a final order from the Texas Commission
expected in May 1995. Testimony filed by parties to the rate case,
including the Staff, is not binding on either the ALJ or the Texas
Commission.
CPL continues to maintain that its rates are reasonable and that
its earnings are within established regulatory guidelines. In
addition, CPL strongly believes that 100 percent of its investment in
both units of STP belongs in rate base. This belief is based on,
among other factors, Units 1 and 2 providing output at high capacity
factors since April and June 1994, respectively. In addition, the
long-term benefits nuclear generation provides to customers further
support their inclusion in rate base. Furthermore, there are no
Texas Commission precedents addressing the removal of a nuclear plant
from rate base as a performance disallowance. Assuming both units of
STP are included in rate base, CPL believes it is not collecting
excessive revenues, notwithstanding that market rates of return on
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common equity are generally lower today than they were in 1990 and
1991, when CPL's base rates were last set.
CPL Fuel
Pursuant to the substantive rules of the Texas Commission, CPL
generally is allowed to recover its fuel costs through a fixed fuel
factor. These fuel factors are in the nature of temporary rates, and
CPL'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
from revenues, with a corresponding entry to unrecovered fuel costs
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.
CPL is currently involved in two proceedings before the Texas
Commission relating to the recovery of fuel and purchased power
costs. CPL originally filed Docket No. 12154 seeking approval of a
customer surcharge to recover fuel and purchased power costs,
including those resulting from the STP outage. In Docket No. 13126,
the Texas Commission General Counsel and others are reviewing the
prudence of management activities at STP. In November 1994, CPL
filed a fuel reconciliation case in Docket No. 13650 with the Texas
Commission seeking to reconcile fuel costs since March 1, 1990,
including the period during which CPL's fuel and purchased power
costs were increased due to the STP outage. At December 31, 1994,
CPL's under-recovered fuel balance was $54.1 million, exclusive of
interest, which was due primarily to the STP outage. If a
significant portion of the fuel costs were disallowed by the Texas
Commission, CPL could experience a material adverse effect on its
results of operations in the year of disallowance but not on its
financial condition. Finally, in Docket No. 13126, the Texas
Commission General Counsel is reviewing the prudence of management
activities at STP. On January 4, 1995, Docket No. 12154 was
consolidated into Docket No. 13650. The results of the prudence
inquiry in Docket No. 13126 are expected to be incorporated into the
fuel reconciliation proceedings in Docket No. 13650.
CPL continues to negotiate with the intervening parties to
resolve these matters through settlement. However, no settlement has
been reached to date.
Management cannot predict the ultimate outcome of the CPL rate
inquiry and CPL fuel regulatory proceedings. However, management
believes that the ultimate resolution of the various issues will not
have a material adverse effect on CPL's results of operations or
financial condition.
See NOTE 9, Litigation and Regulatory Proceedings - STP, for a
discussion of regulatory proceedings arising out of the STP outage
and background on STP rate orders and deferred accounting.
Nuclear Decommissioning
CPL's decommissioning costs are accrued and funded to an
external trust over the expected service life of the STP units. The
existing NRC operating licenses will allow the operation of STP Unit
1 until 2027, and Unit 2 until 2028. The accrual is an annual level
cost based on the estimated future cost to decommission STP,
including escalations for expected inflation to the expected time of
decommissioning and is net of expected earnings on the trust fund.
The staff of the SEC has questioned certain of the current
accounting practices of the electric utility industry regarding the
recognition, measurement and classification of decommissioning costs
for nuclear generating stations. In response to these questions, FASB
has agreed to review the accounting for removal costs, including
decommissioning. If current electric utility industry accounting
practices for such decommissioning are changed, (i) annual provisions
for decommissioning could increase, (ii) the estimated cost for
decommissioning could be recorded as a liability rather than as
accumulated depreciation, and (iii) trust fund income from the
external decommissioning trusts could be reported as investment income
rather than as a reduction to decommissioning expense.
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See NOTE 1, Summary of Significant Accounting Policies - Nuclear
Decommissioning, for further information regarding CPL's
decommissioning of STP.
New Accounting Standards
SFAS No. 115 was effective for fiscal years beginning after
December 15, 1993. CPL adopted SFAS No. 115 in 1994. The adoption of
SFAS No. 115 did not have a material effect on CPL's results of
operations or financial condition.
In June 1993 the FASB issued SFAS No. 116. The statement,
effective for fiscal years beginning after December 15, 1994, will be
adopted by CPL for 1995. The statement establishes accounting
standards for contributions and applies to all entities that receive
or make contributions. Management does not believe the adoption of
SFAS No. 116 will have a material impact on CPL's results of
operations or financial condition.
SFAS No. 119 was effective for fiscal years ending after December
15, 1994. CPL does not currently use derivative instruments, but may
use these instruments in the future to manage the increased market
risks associated with greater competition in the electric utility
industry. The adoption of this new statement had no material effect
on CPL's results of operations or financial condition.
Liquidity and Capital Resources
Overview
CPL's need for capital results primarily from its construction of
facilities to provide reliable electric service to its customers.
Accordingly, internally generated funds should meet most of the
capital requirements. However, if internally generated funds are not
sufficient, CPL's financial condition should allow it access to the
capital markets.
Capital Expenditures
Construction expenditures, including AFUDC, were approximately
$178 million in 1994, $180 million in 1993, and $102 million in 1992.
It is estimated that construction expenditures, including AFUDC,
during the 1995 through 1997 period will aggregate $357 million. Such
expenditures primarily will be made to improve and expand 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 year
2000.
The construction program continues to be monitored, reviewed and
adjusted to reflect changes in estimated load growth in CPL's service
area, variations in prices of alternative fuel sources, the cost of
labor, materials, equipment and capital, and other external factors.
The CSW System facilities plan presently includes projected coal-
and lignite-fired generating plants for which CPL has invested
approximately $21 million in prior years for plant sites, engineering
studies and lignite reserves. Should future plans exclude these
plants for environmental or other reasons, CPL would evaluate the
probability of recovery of these investments and may record
appropriate reserves.
Long-Term Financing
As of December 31, 1994, the capitalization ratios of CPL were
45% common stock equity, 8% preferred stock and 47% long-term debt.
CPL continually monitors the capital markets for opportunities to
lower its cost of capital through refinancing. CPL continues to be
committed to maintaining financial flexibility by maintaining a strong
capital structure and favorable securities ratings which should allow
funds to be obtained from the capital markets when required.
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CPL's long-term financing activity for 1994 is summarized as
follows:
In May, CPL issued $100 million of 7-1/2% First Mortgage Bonds,
Series JJ, due May 1, 1999. Net proceeds were used to repay a portion
of CPL's short-term borrowings.
In July and August, CPL reacquired $0.6 million of 9-3/8% First
Mortgage Bonds, Series Z, due December 1, 2019. The funds required
for this transaction were provided from internal sources.
In August, CPL retired $22.4 million, all remaining shares
outstanding, of its 10.05% Series Preferred Stock. The funds required
for this transaction were provided from internal sources and short-
term borrowings.
CPL has $260 million remaining for the issuance of first mortgage
bonds under a shelf registration statement filed with the SEC in 1993.
CPL may offer additional first mortgage bonds subject to market
conditions and other factors. The proceeds of any such offerings will
be used principally to redeem higher cost first mortgage bonds in
order to lower CPL's embedded cost of debt.
CPL has $75 million available for issuance of preferred stock
under a shelf registration statement filed with the SEC in March 1994.
CPL may offer preferred stock subject to market conditions and other
factors. The proceeds of any such offerings will be used principally
to redeem higher cost preferred stock and to repay short-term debt.
Short-Term Financing
CPL, together with other members of 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. CPL's short-term borrowing
limit from the money pool is $300 million. During 1994, the annual
weighted average interest rate was 4.5% and the average amount of
short- term month-end borrowings outstanding was $129 million. The
maximum amount of short-term borrowings outstanding at any month-end
during 1994 was $232 million, which was the amount outstanding at
February 28, 1994.
Internally Generated Funds
Internally generated funds consist of cash flows from operating
activities less common and preferred stock dividends. CPL uses short-
term debt to meet fluctuations in working capital requirements due to
the seasonal nature of energy sales. CPL anticipates that capital
requirements for the period 1995 to 1997 will be met, in large part,
from internal sources. CPL also anticipates that some external
financing will be required during the period, but the nature, timing
and extent have not yet been determined. Information concerning
internally generated funds follows:
1994 1993 1992
(millions)
Internally Generated Funds $114 $92 $95
Construction Expenditures
Provided by Internally
Generated Funds 65% 52% 94%
Sales of Accounts Receivable
CPL sells its billed and unbilled accounts receivable, without
recourse, to CSW Credit. The sales provided CPL with cash
immediately, thereby reducing working capital needs and revenue
requirements. The average and year end amounts of accounts receivable
sold were $121.9 million and $113.5 million in 1994, as compared to
$112.3 million and $105.8 million in 1993.
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Recent Developments and Trends
Competition and Industry Challenges
Competitive forces at work in the electric utility industry are
impacting CPL and electric utilities generally. Increased competition
facing electric utilities is driven by complex economic, political and
technological factors. These factors have resulted in legislative and
regulatory initiatives that are likely to result in even greater
competition at both the wholesale and retail level in the future. As
competition in the industry increases, CPL will have the opportunity
to seek new customers and at the same time be at risk of losing
customers to other competitors. CPL believes that its prices for
electricity and the quality and reliability of its service currently
places it in a position to compete effectively in the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly
alters the way in which electric utilities compete. The Energy Policy
Act creates exemptions from regulation under the Holding Company Act
and permits utilities, including registered utility holding companies
and non-utility companies, to form EWGs. EWGs are a new category of
non-utility wholesale power producer that are 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. The Energy Policy Act also 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. A FERC order requiring a transmitting utility
to provide wholesale transmission service must include provisions
generally that permit (i) the utility to recover from the FERC
applicant all of the costs incurred in connection with the
transmission services and (ii) any enlargement of the transmission
system and associated services. While CPL believes that the Energy
Policy Act will continue to make the wholesale markets more
competitive, CPL is unable to predict the extent to which the Energy
Policy Act will impact its operations.
Increasing competition in the utility industry brings an
increased need to stabilize or reduce rates. The retail regulatory
environment is beginning to shift from traditional rate base
regulation to incentive regulation. Incentive rate and performance-
based plans encourage efficiencies and increased productivity while
permitting utilities to share in the results. Retail wheeling, a
major industry issue which may require utilities to "wheel" or move
power from third parties to their own retail customer, is evolving
gradually.
Wholesale energy markets, including the market for wholesale
electric power, have been extremely competitive since the enactment of
the Energy Policy Act. CPL competes in the wholesale energy markets
with other public utilities, cogenerators, qualified facilities,
exempt wholesale generators and others for sales of electric power.
Under the Energy Policy Act, the FERC has approved several
proposals by utility companies to sell wholesale power at market-based
rates and provide to electric utilities "open access" to transmission
systems, subject to certain requirements. The adoption of these
proposals increases marketing opportunities for electric utilities,
but also exposes them to the risk of loss of load or reduced revenues
due to competition with alternative suppliers.
CPL believes that, compared to other electric utilities, it is
well positioned to meet future competition. CPL benefits from
economies of scale and scope by virtue of its size and its
relationship to the CSW System. Moreover, CPL is taking steps to
enhance its marketing and customer service, reduce costs, improve and
standardize business practices, and grow through strategic
acquisitions, in order to position itself for increased competition in
the future.
CPL is unable to predict the ultimate outcome or impact of
competitive forces on the electric utility industry or on CPL. As the
wholesale and retail electricity markets become more competitive,
however, the principal factor determining success is likely to be
price, and to a lesser extent, reliability, availability of capacity,
and customer service.
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Public Utility Regulatory Act
PURA is the legal foundation for electric utility regulation in
Texas. PURA will expire on September 1, 1995, in accordance with the
sunset policy of the Texas Legislature, which applies to all state
agencies, unless the Texas Legislature reenacts PURA in its current
form or in modified form. Several proposals have been made to amend
PURA which, among other things, provide for a market-driven integrated
resource planning process, pricing flexibility for utilities faced
with competitive challenges, incentive regulation and deregulation of
the wholesale bulk power market in ERCOT. CPL is unable to predict
the ultimate outcome of the 1995 session of the Texas Legislature and
in particular whether amendments to PURA will be adopted. If,
however, the Texas Legislature passes legislation permitting any form
of retail wheeling, such legislation could have an adverse impact on
CPL and CPL's sales to its retail customers.
Regulatory Accounting
Consistent with industry practice and the provisions of SFAS No.
71, which allows for the recognition and recovery of regulatory
assets, CPL has recognized significant regulatory assets and
liabilities. Management believes that CPL will continue to meet the
criteria for following SFAS No. 71. However, in the event CPL no
longer meets the criteria for following SFAS No. 71, a write-off of
regulatory assets and liabilities would be required. For additional
information regarding SFAS No. 71 reference is made to NOTE 1,
Summary of Significant Accounting Policies - Regulatory Assets and
Liabilities.
Consolidated Taxes
The Texas Commission before 1992 allowed income taxes to be
recovered in rates based on the federal income tax incurred by a
utility as if it were a stand-alone company. This stand-alone
approach treated the regulated activities of a utility as a separate
entity and considered only those revenues and expenses that are
included in the utility's cost of service to calculate the federal
income tax liability for ratemaking purposes.
Beginning in 1992, the Texas Commission changed its method of
calculating the federal income tax component of rates to the "actual
tax approach." The actual tax approach is an evolving concept but
generally seeks to reflect in rates the actual tax liability of the
utility irrespective of its relationship to the utility's cost of
service. The approach reduces rates by the tax benefits of deductions
which are not considered for or included in setting rates for the
utility.
The Texas Commission is expected to use the actual tax approach
for calculating the recovery of federal income tax in the pending rate
case for CPL. The impact of the actual tax approach on the
prospective rates for CPL cannot be determined since the application
of the concept is unsettled.
CPL believes that the recovery of federal income taxes in rates
should be determined on the stand-alone approach for ratemaking
purposes, but there is no assurance this approach will be adopted in
the pending CPL rate case.
Environmental Matters
CERCLA and Related Matters
The operations of CPL, like those of other utilities, generally
involve the use and disposal of substances subject to environmental
laws. The 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. PRPs include owners and operators of
contaminated sites and transporters and/or generators of hazardous
substances. 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.
CPL is subject to various pending claims alleging it is a PRP
under federal or state remedial laws for investigating and cleaning up
contaminated property. CPL anticipates that resolution of these
claims, individually or in the aggregate, will not have a material
adverse effect on CPL's results of operations or financial condition.
2-78
Although the reasons for this expectation differ from site to site,
factors that are the basis for the expectation for specific sites
include the volume and/or type of waste allegedly contributed by CPL,
the estimated amount of costs allocated to CPL and the participation
of other parties.
Clean Air Act Amendments
In November 1990, the United States Congress passed the Clean
Air Act which places restrictions on the emission of sulfur dioxide
from gas-, coal- and lignite-fired generating plants. Beginning in
the year 2000, CPL will be required to hold allowances in order to
emit sulfur dioxide. The EPA issues allowances to owners of existing
generating units based on historical operating conditions. Based on
the CSW System facilities plan, CPL believes that its allowances will
be adequate to meet its needs at least through 2008. Public and
private markets are developing for trading of excess allowances. CPL
presently has no intention of engaging in trading of allowances, but
may seek to do so in the future if market conditions warrant and
appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source
permit program to be administered by the states.
The Clean Air Act also directs the EPA to issue regulations
governing nitrogen oxide emissions and requires government studies to
determine what controls, if any, should be imposed on utilities to
control air toxics emissions. The impact that the nitrogen oxide
emission regulations and the air toxics study will have on CPL cannot
be determined at this time.
As a result of requirements imposed by the Clean Air Act, CPL
expects to spend $1.3 million for annual testing of, software
modifications to, and maintenance of continuous emission monitoring
equipment from 1995 through 1997.
EMFs
Research is ongoing whether exposure to EMFs may result in
adverse health effects. Although a few of the studies to date have
suggested certain associations between EMFs and some types of effects,
the research to date has not established a cause-and-effect
relationship between EMFs and adverse health effects. CPL cannot
predict the impact on CPL 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.
Results of Operations
Electric Operating Revenues
Total revenues decreased $5.5 million in 1994 and increased
$110.1 million in 1993. The 1994 decrease reflects lower fuel-
related revenues of $41.5 million partially offset by higher base
revenues of $35.9 million. Fuel-related revenues declined as a
result of lower per unit fuel and purchased power costs, as
discussed below.
Total KWH sales were up 8%, reflecting growth of 7% in retail
sales and 41% in lower margin sales for resale. All of CPL's retail
classes showed KWH growth with increases of 6% in both residential
and commercial sales. An increase in the number of residential and
commercial customers served and warmer spring as well as summer
weather also contributed to this growth. Industrial sales were up
8% as a result of higher demand in the petrochemical and petroleum
industries, where several companies CPL serves had plant expansions
and increased load requirements. The rise in sales for resale is
attributable to warmer summer and spring weather and lower cost STP
generation.
The increase in revenues in 1993 over 1992 reflects higher fuel-
related revenues and greater base revenues. Fuel-related revenues
were up because of the rise in per unit fuel and purchased power
costs, as discussed below, and higher fuel consumption on greater
KWH sales.
2-79
Fuel and Purchased Power
Fuel expense decreased $21.8 million or 6% due primarily to a
decrease in the average unit cost of fuel from $2.17 in 1993 to $1.75
in 1994 partially offset by a 16% increase in generation. The lower
average unit cost of fuel reflects increased usage of lower unit cost
nuclear fuel since STP Units 1 and 2 restarted and reached 100
percent output level in April and June of 1994, respectively, and
lower unit costs of gas and coal in 1994. STP Units 1 and 2 had not
operated at full capacity since February 1993 as discussed in
Litigation and Regulatory Proceedings in NOTE 9.
Fuel expense increased in 1993 due primarily to higher fuel
consumption in both gas and coal as a result of the STP outage and an
increase in the average unit cost of fuel from $1.70 in 1992 to $2.17
in 1993.
Purchased power decreased $21.7 million during 1994 and
increased $46.9 million in 1993 when compared to the prior year due
to the outage at STP.
Other Operating and Maintenance Expenses and Taxes
Other operating expenses were relatively stable in 1994 and
increased $40.5 million or 22% in 1993 when compared to the prior
year.
The 1993 increase in other operating expenses was due primarily
to the higher costs associated with the STP outage and increased
pension and medical costs, which included implementation of SFAS No.
106.
Restructuring charges reflect the initial estimated cost of $29
million as previously discussed. Such expenses include the estimated
costs associated with the early retirement program, severance
packages and relocation.
Maintenance expense decreased $12.8 million during 1994 and
increased $20.0 million in 1993 when compared to the prior year due
primarily to maintenance activities at STP associated with the
outage.
Depreciation and amortization increased in 1994 and 1993 as a
result of increases in depreciable plant. The increase in 1994 is
also attributable to a decline in amortization credits related to
power plant investment.
Taxes, other than federal income, decreased in 1994 mainly as a
result of a franchise tax refund. The increase in 1993 is largely a
result of increased ad valorem taxes.
Federal income taxes increased $10.2 million in 1994 due to
higher pre-tax income. Federal income taxes decreased $12.1 million
in 1993 due to lower pre-tax income partially offset by the increase
in the statutory tax rate from 34% to 35% effective retroactive to
January 1, 1993.
Inflation
Annual inflation rates, as measured by the Consumer Price Index,
have averaged 2.7% during the three years ended December 31, 1994.
CPL 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
CPL is amortizing its Mirror CWIP liability in declining amounts
over the years 1991 through 1995. Non-cash earnings of $68 million
were recognized in 1994, a decrease from the $75.7 million recognized
in 1993. The remaining liability to be amortized for 1995 is $41
million, which will fully amortize the Mirror CWIP liability.
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Cumulative Effect of Changes in Accounting Principles
In 1993, CPL changed its method of accounting for unbilled
revenues and implemented SFAS No. 112. These accounting changes had
a cumulative effect of increasing net income by $27.3 million.
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Statements of Income
Central Power and Light Company
For the Years Ended December 31,
1994 1993 1992
(thousands)
Electric Operating Revenues
Residential $ 474,480 $ 474,426 $ 432,295
Commercial 368,405 369,426 342,201
Industrial 271,738 281,247 240,341
Sales for resale 50,777 45,369 50,342
Other 52,579 53,060 48,244
1,217,979 1,223,528 1,113,423
Operating Expenses and Taxes
Fuel 328,460 350,268 306,939
Purchased power 42,342 64,025 17,160
Other operating 224,852 225,034 184,514
Restructuring charges 98 29,365 --
Maintenance 68,537 81,352 61,399
Depreciation and amortization 141,622 131,825 129,131
Taxes, other than federal income 80,461 86,394 70,343
Federal income taxes 75,356 65,186 77,272
961,728 1,033,449 846,758
Operating Income 256,251 190,079 266,665
Other Income and Deductions
Allowance for equity funds
used during construction 1,215 1,074 408
Mirror CWIP liability
amortization 68,000 75,702 82,527
Other 1,272 1,663 890
70,487 78,439 83,825
Income Before Interest Charges 326,738 268,518 350,490
Interest Charges
Interest on long-term debt 111,408 112,939 125,476
Interest on short-term debt
and other 12,365 11,993 7,266
Allowance for borrowed funds
used during construction (2,474) (1,544) (763)
121,299 123,388 131,979
Income Before Cumulative Effect
of Changes in Accounting
Principles 205,439 145,130 218,511
Cumulative Effect of Changes in
Accounting Principles -- 27,295 --
Net Income 205,439 172,425 218,511
Preferred stock dividends 13,804 14,003 16,070
Net Income for Common Stock $ 191,635 $ 158,422 $ 202,441
The accompanying notes to financial statements are an integral part of
these statements.
2-82
Statements of Retained Earnings
Central Power and Light Company
For the Years Ended December 31,
1994 1993 1992
(thousands)
Retained Earnings at Beginning of Year $850,307 $863,988 $854,659
Net income for common stock 191,635 158,422 202,441
Deduct: Common stock dividends 183,000 172,000 193,000
Preferred stock redemption costs 1,476 103 112
Retained Earnings at End of Year $857,466 $850,307 $863,988
The accompanying notes to financial statements are an integral part of
these statements.
2-83
Balance Sheets
Central Power and Light Company
As of December 31,
1994 1993
(thousands)
ASSETS
Electric Utility Plant
Production $3,070,005 $3,061,911
Transmission 451,050 351,584
Distribution 828,350 765,266
General 216,888 209,170
Construction work in progress 142,724 168,421
Nuclear fuel 161,152 160,326
4,870,169 4,716,678
Less - Accumulated depreciation 1,400,343 1,263,372
3,469,826 3,453,306
Current Assets
Cash and temporary cash investments 642 2,435
Special deposits 668 1,967
Accounts receivable 29,865 23,850
Materials and supplies, at average cost 66,209 64,359
Fuel inventory, at average cost 22,916 16,934
Accumulated deferred income taxes -- 4,831
Unrecovered fuel costs 54,126 52,959
Prepayments and other 2,316 2,255
176,742 169,590
Deferred Charges and Other Assets
Deferred STP costs 488,987 489,773
Mirror CWIP asset 321,825 331,845
Income tax related regulatory assets, net 288,444 266,597
Other 76,875 70,634
1,176,131 1,158,849
$4,822,699 $4,781,745
The accompanying notes to financial statements are an integral part of
these statements.
2-84
Balance Sheets
Central Power and Light Company
As of December 31,
1994 1993
(thousands)
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 857,466 850,307
Total Common Stock Equity 1,431,354 1,424,195
Preferred stock
Not subject to mandatory redemption 250,351 250,351
Subject to mandatory redemption -- 22,021
Long-term debt 1,466,393 1,362,799
Total Capitalization 3,148,098 3,059,366
Current Liabilities
Long-term debt and preferred stock due
within twelve months 723 3,928
Advances from affiliates 161,320 171,165
Accounts payable 75,051 79,604
Accrued taxes 59,386 33,769
Accumulated deferred income taxes 13,812 --
Accrued interest 24,681 24,683
Accrued restructuring charges 1,325 29,365
Other 30,151 28,020
366,449 370,534
Deferred Credits
Income taxes 1,087,317 1,057,453
Investment tax credits 158,533 164,322
Mirror CWIP liability and other 62,302 130,070
1,308,152 1,351,845
$4,822,699 $4,781,745
The accompanying notes to financial statements are an integral part of
these statements.
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Statements of Cash Flows
Central Power and Light Company
For the Years Ended December 31,
1994 1993 1992
(thousands)
OPERATING ACTIVITIES
Net Income $205,439 $172,425 $218,511
Non-cash Items Included in Net Income
Depreciation and amortization 170,971 140,223 154,716
Deferred income taxes and
investment tax credits 20,870 84,714 42,773
Mirror CWIP liability amortization (68,000) (75,702) (82,527)
Restructuring charges 98 29,365 --
Allowance for equity funds
used during construction (1,215) (1,074) (408)
Cumulative effect of changes in
accounting principles -- (27,295) --
Changes in Assets and Liabilities
Accounts receivable (6,015) (3,554) (6,415)
Fuel inventory (5,982) 12,325 (3,137)
Accounts payable (4,553) 19,151 6,209
Accrued taxes 25,617 (9,311) (2,165)
Unrecovered fuel costs (1,167) (57,386) (1,195)
Accrued restructuring charges (20,245) -- --
Other deferred credits 232 (35,242) (4,133)
Other (4,575) 29,928 (18,479)
311,475 278,567 303,750
INVESTING ACTIVITIES
Construction expenditures (174,993) (177,120) (100,805)
Allowance for borrowed funds
used during construction (2,474) (1,544) (763)
(177,467) (178,664) (101,568)
FINANCING ACTIVITIES
Proceeds from issuance of
long-term debt 99,190 441,131 435,497
Retirement of long-term debt (459) (431) (405)
Reacquisition of long-term debt (618) (573,776) (304,650)
Retirement of preferred stock (27,021) (6,578) (7,050)
Special deposits for reacquisition
of long-term debt -- 145,482 (145,482)
Change in advances from affiliates (9,845) 79,399 29,618
Payment of dividends (197,048) (186,361) (209,196)
(135,801) (101,134) (201,668)
Net Change in Cash and Cash Equivalents (1,793) (1,231) 514
Cash and Cash Equivalents at Beginning of
Year 2,435 3,666 3,152
Cash and Cash Equivalents at End of Year $ 642 $ 2,435 $ 3,666
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized $114,980 $116,664 $130,078
Income taxes paid $ 28,166 $ 3,631 $ 45,314
The accompanying notes to financial statements are an integral part of
these statements.
2-86
Statements of Capitalization
Central Power and Light Company
As of December 31,
1994 1993
(thousands)
COMMON STOCK EQUITY $1,431,354 $1,424,195
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% 500,000 100.00 50,000 50,000
Auction Money
Market 750,000 100.00 75,000 75,000
Auction SeriesA 425,000 100.00 42,500 42,500
Auction SeriesB 425,000 100.00 42,500 42,500
Issuance Expense (3,149) (3,149)
250,351 250,351
Subject to Mandatory Redemption
10.05% -- 25,900
Issuance Expense -- (410)
Amount to be Redeemed Within One Year -- (3,469)
-- 22,021
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 T, 7 1/2%, due December 15, 2014 * 111,700 111,700
Series U, 9 3/4%, due July 1, 2015 * 31,765 31,765
Series Z, 9 3/8%, due December 1, 2019 139,405 140,000
Series AA, 7 1/2%, due March 1, 2020 * 50,000 50,000
Series BB, 6%, due October 1, 1997 200,000 200,000
Series CC, 7 1/4%, due October 1, 2004 100,000 100,000
Series DD, 7 1/8%, due December 1, 1999 25,000 25,000
Series EE, 7 1/2%, due December 1, 2002 115,000 115,000
Series FF, 6 7/8% due February 1, 2003 50,000 50,000
Series GG, 7 1/8%, due February 1, 2008 75,000 75,000
Series HH, 6%, due April 1, 2000 100,000 100,000
Series II, 7 1/2%, due April 1, 2023 100,000 100,000
Series JJ, 7 1/2%, due May 1, 1999 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 68,870
Series 1986, 7 7/8%, due December 1, 2016 60,000 60,000
Series 1993, 6%, due July 1, 2028 120,265 120,265
Notes Payable, 6 1/2%, due December 8, 1995 448 652
Unamortized Discount (11,655) (12,265)
Unamortized Costs of Reacquired Debt (81,947) (86,249)
Amount to be Redeemed Within One Year (723) (459)
1,466,393 1,362,799
TOTAL CAPITALIZATION $3,148,098 $3,059,366
*Obligations incurred in connection with the sale by public authorities of
tax-exempt PCRBs.
The accompanying notes to financial statements are an integral part
of these statements.
2-87
NOTES TO FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies
Public Utility Regulation
CPL is subject to regulation by the SEC under the Holding Company
Act and the FERC under the Federal Power Act, and follows the
Uniform System of Accounts prescribed by the FERC. CPL is subject
to further regulation with regard to rates and other matters by
the Texas Commission. CPL, as a member of the CSW System, engages
in transactions and coordinates its activities and operations with
other members of the CSW System.
The more significant accounting policies of CPL 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 average
consolidated composite rates were 3.0% for 1994, 1993 and 1992.
Nuclear Decommissioning
At the end of STP's service life, decommissioning is expected to
be accomplished using the decontamination method, which is one of
the techniques acceptable to the NRC. Using this method the
decontamination activities occur as soon as possible after the end
of plant operations. Contaminated equipment is cleaned or removed
to a permanent disposal location and the site is generally
returned to its pre-plant state.
CPL's decommissioning costs are accrued and funded to an external
trust over the expected service life of the STP units. The
existing NRC operating licenses will allow the operation of STP
Unit 1 until 2027, and Unit 2 until 2028. The accrual is an
annual level cost based on the estimated future cost to
decommission STP, including escalations for expected inflation to
the expected time of decommissioning, and is net of expected
earnings on the trust fund.
CPL's portion of the costs of decommissioning STP were estimated
to be $85 million in 1986 dollars based on a site specific study
completed in 1986. CPL is recovering these decommissioning costs
through rates based on the service life of STP at a rate of $4.2
million per year. The $4.2 million annual cost of decommissioning
is reflected on the income statement in other operating expense.
Decommissioning costs are paid to an irrevocable external trust
and as such are not reflected on CPL's balance sheet. At December
31, 1994, the trust balance was $19.3 million.
In May 1994, CPL received a new decommissioning study updating the
cost estimates to decommission STP that indicated that CPL's share
of such costs would increase from $85 million, as stated in 1986
dollars, to $251 million, as stated in 1994 dollars. The increase
in costs occurred primarily as a result of extended on-site
storage of high level waste, much higher estimates of low-level
waste disposal costs and increased labor costs since the prior
study. These costs are expected to be incurred during the years
2027 through 2062. While this is the best estimate available at
this time, these costs may change between now and when the funds
are actually expended because of changes in the assumptions used
to derive the estimates, including the prices of the goods and
services required to accomplish the decommissioning. Additional
studies will be completed periodically to update this information.
2-88
Based on this projected cost to decommission STP, CPL estimates
that its annual funding level should increase to $10.0 million.
CPL has requested this amount as part of its cost of service in
its current rate filing. Other parties to the rate proceeding have
filed their projections of the annual amount, which have ranged
from $4.5 million to $8.1 million. CPL expects to fund at the
level ultimately ordered by the Texas Commission although CPL
cannot predict what that level will be. Historically, the Texas
Commission has allowed full recovery of nuclear decommissioning
costs. For further information on CPL's current rate filing see
NOTE 9, Litigation and Regulatory Proceedings - Texas Commission
Proceedings.
Electric Revenues and Fuel
Prior to January 1, 1993, electric revenues 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 operating revenues of
the next month. To conform to general industry standards, CPL
changed its method of accounting to accrue for estimated unbilled
revenues. The effect of this change on 1993 net income was an
increase of $29.5 million included in cumulative effect of changes
in accounting principles.
CPL recovers fuel costs in Texas as a fixed component of base
rates whereby over-recoveries of fuel are payable to customers and
under-recoveries may be billed to customers after Texas Commission
approval. The cost of fuel is charged to expense as consumed.
See NOTE 9, Litigation and Regulatory Proceedings, for further
information about fuel recoveries. CPL recovers fuel costs
applicable to wholesale customers, which are regulated by the
FERC, through an automatic fuel adjustment clause. CPL amortizes
direct nuclear fuel costs to fuel expense on the basis of a ratio
of the estimated energy used in the core to the energy expected to
be derived from such fuel assembly over its life in the core. In
addition to fuel amortization, CPL also incurs nuclear fuel
expense as a result of other items, including spent fuel disposal
fees assessed on the basis of net KWHs sold from STP, and DOE
special assessment fees for decontamination and decommissioning of
the enrichment facilities on the basis of prior usage of
enrichment services.
Accounts Receivable
CPL sells its billed and unbilled accounts receivable, without
recourse, to CSW Credit.
Regulatory Assets and Liabilities
For its regulated activities, CPL follows SFAS No. 71, which
defines the criteria for establishing regulatory assets and
regulatory liabilities. Regulatory assets represent probable
future revenue to CPL associated with certain costs which will be
recovered from customers through the ratemaking process.
Regulatory liabilities represent probable future refunds to
customers. At December 31, 1994 and 1993, CPL had recorded the
following significant regulatory assets and liabilities:
1994 1993
(thousands)
Regulatory Assets
Deferred plant costs $488,987 $489,773
Mirror CWIP asset 321,825 331,845
Income tax related regulatory
assets, net 288,444 266,597
Unrecovered fuel costs 54,126 52,959
Regulatory Liabilities
Mirror CWIP liability $ 41,000 $109,000
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Deferred Plant Costs
In accordance with orders of the Texas Commission, CPL deferred
operating, depreciation and tax costs incurred for STP. This
deferral was for the period beginning on the date when the plant
began commercial operation until the date the plant was included
in rate base. The deferred costs are being amortized and
recovered through rates over the life of the plant. See NOTE 9,
Litigation and Regulatory Proceedings, for further discussion of
CPL's deferred accounting proceedings.
Mirror CWIP
In accordance with Texas Commission orders, CPL previously
recorded Mirror CWIP, which is being amortized over the life of
STP. For more information regarding Mirror CWIP, reference is made
to 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 are considered cash
equivalents.
Reclassification
Certain financial statement items for prior years have been
reclassified to conform to the 1994 presentation.
Accounting Changes
Effective January 1, 1993, CPL adopted SFAS Nos. 106, 112 and 109.
See NOTE 2, Federal Income Taxes, for further information
regarding SFAS No. 109. In addition, CPL also changed its method
of accounting for unbilled revenues. See Electric Revenues and
Fuel above for further information.
The adoption of SFAS No. 106 resulted in an increase in 1993
operating expenses of $5.9 million. The adoption of SFAS No. 112
and the change in accounting for unbilled revenues are presented
as a 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
CPL adopted the provisions of SFAS No. 109 effective January 1,
1993. The implementation of SFAS No. 109 had no material effect
on CPL's earnings. As a result of this change, CPL recognized
additional accumulated deferred income taxes from its utility
operations, and corresponding regulatory assets and liabilities to
ratepayers in amounts equal to future revenues or the reduction in
future revenues required when the income tax temporary differences
reverse and are recovered or settled in rates. As a result of a
favorable earnings history, CPL did not record any valuation
allowance against deferred tax assets at December 31, 1994 and
1993.
CPL, together with other members of the CSW System, files a
consolidated federal income tax return and participates in a tax
sharing agreement.
90
Components of income taxes follow:
1994 1993 1992
Included in Operating Expenses and Taxes (thousands)
Current $54,486 $(19,690) $ 34,336
Deferred 26,659 90,682 48,773
Deferred ITC (5,789) (5,806) (5,831)
75,356 65,186 77,272
Included in Other Income and Deductions
Current (3,157) 736 390
Deferred -- (162) (163)
(3,157) 574 227
Tax Effects of Cumulative Effect of
Changes in Accounting Principles -- 14,697 --
$72,199 $80,457 $77,499
Investment tax credits deferred in prior years are included in
income over the lives of the related properties.
Total income taxes differ from the amounts computed by applying
the statutory income tax rates to income before taxes. The
reasons for the differences follow:
1994 % 1993 % 1992 %
(dollars in thousands)
Tax at statutory $97,174 35.0 $88,509 35.0 $100,643 34.0
Differences
Amortization of ITC (5,789) (2.1) (5,806) (3) (5,789) (2.0)
Mirror CWIP (20,293) (7.3) (22,989) (9.1) (24,652) (8.3)
Prior period adjustments (1,955) (0.7) 19,101 7.6 -- --
Other 3,062 1.1 1,642 .6 7,297 2.5
$72,199 26.0 $80,457 31.8 $77,499 26.2
2-91
The significant components of the net deferred income tax
liability follow:
1994 1993
(thousands)
Deferred Income Tax Liabilities
Depreciable utility plant $ 755,437 $ 745,164
Deferred plant costs 171,145 171,421
Mirror CWIP asset 112,639 116,146
Income tax related regulatory asset 169,104 178,984
Other 49,800 37,989
Total Deferred Income Tax Liabilities 1,258,125 1,249,704
Deferred Income Tax Assets
Income tax related regulatory liability (68,149) (85,675)
Unamortized ITC (55,486) (57,513)
Alternative minimum tax credit - carryforward (26,138) (15,744)
Other (7,223) (38,150)
Total Deferred Income Tax Assets (156,996) (197,082)
Net Accumulated Deferred Income Taxes - Total $1,101,129 $1,052,622
Net Accumulated Deferred Income Taxes - Noncurrent $1,087,317 $1,057,453
Net Accumulated Deferred Income Taxes - Current 13,812 (4,831)
Net Accumulated Deferred Income Taxes - Total $1,101,129 $1,052,622
3.Long-Term Debt
The mortgage indenture, as amended and supplemented, securing
first mortgage bonds issued by CPL, constitutes a direct first
mortgage lien on substantially all electric utility plant. CPL
may offer additional first mortgage bonds subject to market
conditions and other factors.
Annual Requirements
Certain series of outstanding first mortgage bonds have annual
sinking fund requirements, which are generally 1% of the amount of
each such series issued. These requirements may be, and generally
have been, satisfied by the application of net expenditures for
bondable property in an amount equal to 166-2/3% of the annual
requirements. In addition, one series of CPL's pollution control
bonds, has a sinking fund requirement. At December 31, 1994, the
annual sinking fund requirements and annual maturities for CPL's
first mortgage bonds and pollution control bonds for the next five
years follow:
Sinking Fund
Requirements Maturities
(thousands)
1995 $ 2,840 $ 2,840
1996 2,840 2,840
1997 2,585 202,840
1998 2,560 30,560
1999 2,560 27,560
Dividends
CPL's mortgage indenture, as amended and supplemented, contains
certain restrictions on the use of their retained earnings for
cash dividends on their common stock. These restrictions do not
2-92
limit the ability of CSW to pay dividends to its stockholders. At
December 31, 1994, the amount of retained earnings available for
payment of cash dividends to CSW by CPL was $684 million.
Reacquired Long-term Debt
Reference is made to MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and
Capital Resources, for further information related to long-term
debt, including new issues and reacquisitions.
4.Preferred Stock
The dividends on CPL's $160 million auction preferred stocks are
adjusted every 49 days, based on current market rates. The
dividend rates averaged 3.5%, 2.7%, and 3.6% during 1994, 1993 and
1992.
CPL retired the remaining shares of its 10.05% Series preferred
stock during August 1994.
Each series of preferred stock, with the exception of the auction
preferred stock, is redeemable at the option of CPL upon 30 days
notice at the current redemption price per share. Redemption
prices of the 8.72% Series decline at specified intervals in
future years. CPL's two issues of auction preferred stock and one
issue of money market preferred stock may be redeemed at par on
any dividend payment date.
5.Short-Term Financing
CPL, together with other members of the CSW System, has
established a money pool to coordinate short-term borrowings and
to make borrowings outside the money pool through CSW's issuance
of commercial paper. Money pool balances are shown as advances to
or from affiliates on the Balance Sheets. At December 31, 1994,
the CSW System had bank lines of credit aggregating $930 million
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, special deposits and temporary cash investments
The carrying amount approximates fair value because of the short
maturity of those instruments.
Advances from affiliates
The carrying amount approximates fair value because of the short
maturity of those instruments.
Long-term debt
The fair value CPL'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 CPL for debt of the same or similar
remaining maturities.
Preferred stock
The fair value of CPL's preferred stock subject to mandatory
redemption is estimated based on quoted market prices for the same
or similar issues or on the current rates offered to CPL for
preferred stock with the same or similar remaining redemption
provisions.
Long-term debt and preferred stock due within twelve months
The fair values of CPL's current maturities of long-term debt and
preferred stock are estimated based on current rates offered to
CPL for long-term debt and preferred stock.
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The estimated fair values of CPL's financial instruments follow:
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(thousands)
Cash and temporary cash
investments $ 642 $ 642 $ 2,435 $ 2,435
Special Deposits 668 668 1,967 1,967
Advances from affiliates 161,320 161,320 171,165 171,165
Long-term debt 1,466,393 1,395,590 1,362,799 1,456,533
Preferred stock subject to
mandatory redemption -- -- 22,021 23,086
Long-term debt and preferred
stock due within 12 months 723 725 3,928 4,096
The fair value does not affect CPL's liabilities unless the issues
are redeemed prior to their maturity dates.
7.Benefit Plans
Defined Benefit Pension Plan
CPL, together with the other members of the CSW System, maintains
a tax qualified, non-contributory defined benefit pension plan
covering substantially all employees. Benefits are based on
employees' years of credited 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 which are deductible for income tax purposes and
minimum contributions required by the ERISA. Pension plan assets
consist primarily of common stocks and short-term and intermediate-
term fixed income investments.
Contributions to the plan for the years ended December 31, 1994,
1993 and 1992 were $7.1 million, $11.0 million and $11.7 million,
respectively.
The approximate maximum number of participants in the plan during
1994 were 2,300 active employees, 1,200 retirees and beneficiaries
and 300 terminated employees.
The components of net periodic pension cost and the assumptions
used in accounting for pension follow:
1994 1993 1992
(thousands)
Net Periodic Pension Cost
Service cost $ 5,796 $ 5,228 $ 4,834
Interest cost on projected
benefit obligation 15,989 14,878 13,686
Actual return on plan assets (1,131) (18,079) (11,750)
Net amortization and deferral (17,972) 68 (5,330)
$ 2,682 $ 2,095 $ 1,440
Discount rate 8.25% 7.75% 8.50%
Long-term compensation increase 5.46% 5.46% 5.96%
Return on plan assets 9.50% 9.50% 9.50%
2-94
At December 31, 1994, the plan's net assets were approximately
equal to the total actuarial present value of the accumulated
benefit obligation. At December 31, 1993 the plan's net
assets exceeded the total actuarial present value of the
accumulated benefit obligation. No reconciliation of the funding
status of the plan is presented because such information is
unavailable.
Health and Welfare Plans
CPL had medical, dental, group life insurance, dependent life
insurance, and accidental death and dismemberment plans for
substantially all active CPL employees during 1994. The
contributions, recorded on a pay-as-you-go basis, for the years
ended December 31, 1994 and 1993 were approximately $4.6 million
and $6.1 million, respectively. Effective January 1993, CPL's
method of providing health benefits was modified to include such
benefits as a health maintenance organization, preferred provider
options, managed prescription drug and mail-order program and a
mental health and substance abuse program in addition to the self-
insured indemnity plans.
Postretirement Benefits Other Than Pensions
CPL adopted SFAS No. 106 effective January 1, 1993. The effect on
operating expense in 1993 was $5.9 million. CPL is amortizing the
transition obligation over twenty years, with eighteen years
remaining. In prior years, these benefits were accounted for on
a pay-as-you-go basis.
The components of net periodic postretirement benefit cost follow:
1994 1993
(thousands)
Net Periodic Postretirement Benefit Cost
Service cost $ 2,435 $ 2,257
Interest cost on APBO 6,061 5,505
Actual return on plan assets (285) (249)
Amortization of transition obligation 2,900 2,900
Net amortization and deferral (913) (703)
$10,198 $9,710
A reconciliation of the funded status of the plan to the amounts
recognized on the balance sheets follow:
1994 1993
APBO (thousands)
Retirees $49,852 $50,032
Other fully eligible participants 9,278 9,147
Other active participants 15,017 17,353
Total APBO 74,147 76,353
Plan assets at fair value (21,457) (14,185)
APBO in excess of plan assets 52,690 62,347
Unrecognized transition obligation (52,208) (55,108)
Unrecognized gain or (loss) 577 (6,180)
Accrued/(Prepaid) Cost $ 1,059 $ 1,059
2-95
The following assumptions were used in accounting for SFAS No.
106.
1994 1993
Discount rate 8.25% 7.75%
Return on plan assets 9.50% 9.00%
Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions
Pre-65 Participants: 1994 Rate of 11.75% grading down .75% per
year to an ultimate rate of 6.5% in 2001.
Post-65 Participants: 1994 Rate of 11.25% 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 by $8.0
million as of December 31, 1994 and increase the aggregate of the
service and interest costs components on net postretirement
benefits by $1.1 million.
8.Jointly Owned Electric Utility Plant
CPL has a joint ownership agreement with other members of the CSW
System and other non-affiliated entities. Such agreements provide
for the joint ownership and operation of STP and Oklaunion power
plants. The statements of income reflect CPL's portion of
operating costs associated with jointly owned plants. At December
31, 1994, CPL had interests as shown below:
South
Texas Oklaunion
Nuclear Coal
Plant Plant
(dollars in millions)
Plant in service $2,343 $36
Accumulated
depreciation 380 8
Plant capacity-MW 2,500 676
Participation 25.2% 7.8%
Share of capacity-MW 630 53
9.Litigation and Regulatory Proceedings
STP
From February 1993 until May 1994, STP experienced an unscheduled
outage which has resulted in significant rate and regulatory
proceedings involving CPL. These matters, including a base rate
case and fuel reconciliation proceedings, are discussed
immediately below.
Texas Commission Proceedings
Base Rates
Rate Inquiry - Docket No. 12820
Several Cities, the Texas Commission General Counsel and others
initiated actions in late 1993 and early 1994 which, if approved
by the Texas Commission, would lower CPL's base rates. The
requests for a review of CPL's rates arose out of the unscheduled
outage at STP which began in February 1993. The STP outage did
not affect CPL's ability to meet customer demand because of
existing capacity and CPL's purchase of additional energy.
Pursuant to a scheduling and procedural settlement agreement among
the parties challenging CPL's rates, which was approved by a Texas
Commission ALJ on April 1, 1994, CPL submitted a rate filing
package on July 1, 1994 to the Texas Commission justifying its
current base rate structure. In that filing, CPL stated that it
2-96
had a $111 million retail revenue deficiency and would be
justified in seeking a base rate increase. However, consistent
with the procedural settlement agreement, CPL has not sought to
increase base rates as a part of this docket but seeks to maintain
its rates at the same levels agreed to in the settlement of its
last two rate cases in 1990 and 1991. As part of the 1990 and
1991 settlements, CPL 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. On October 31, 1994, CPL filed rebuttal
testimony that revised its retail revenue deficiency to
approximately $103 million. CPL continues to maintain that its
rates are reasonable and that its earnings are within established
regulatory guidelines.
Parties to CPL's base rate case have filed testimony with the
Texas Commission recommending reductions in CPL's base rates.
Among the parties that filed testimony were OPUC which initially
recommended an annual $100 million retail rate reduction. After
hearings on the rate case, OPUC claimed that CPL did not meet its
burden of proof concerning deferred accounting and as a result
OPUC changed its proposed reduction to $147 million. The Cities,
which are parties to the rate case, have recommended an annual $75
million retail rate reduction and the write-off of $219 million of
CPL's Mirror CWIP asset. See Deferred Accounting below.
The Staff filed testimony recommending an annual reduction in
retail rates of $99.6 million resulting from a combination of
proposed rate base and cost of service reductions, which it
subsequently revised during the hearings to $83.9 million. In its
final brief to the ALJ, the Staff withdrew its recommendation that
short-term debt be included in the calculation of CPL's weighted
cost of capital. CPL estimates that this change in the Staff's
position will lower its revised proposed retail rate reduction by
approximately $6 million. The Staff recommended a rate base
disallowance of $407 million, or approximately 17% of CPL's
investment in STP, based upon the Staff's calculation of
historical performance for STP compared to a peer group of other
nuclear facilities. The Staff also recommended that accumulated
depreciation and accumulated deferred federal income taxes related
to the disallowed portion of STP be adjusted to reflect a net
reduction to rate base of $325 million. Additionally, the Staff
proposed to disallow depreciation expense related to the
recommended STP disallowed plant.
In its testimony, the Staff argued that its proposed STP rate base
reduction was a historical performance-based disallowance that
could be temporary in nature and would not have to result in a
permanent disallowance. The Staff indicated that, in the future,
CPL could seek recovery in rates of the proposed STP rate base
disallowance, subject to the performance of STP.
The Texas Commission held hearings in November and December 1994,
and all parties have filed briefs in the case. The ALJ is
expected to issue a recommended order for consideration by the
Texas Commission in April 1995, with a final order from the Texas
Commission expected in May 1995. Testimony filed by parties to
the rate case, including the Staff, is not binding on either the
ALJ or the Texas Commission.
CPL strongly believes that 100 percent of its investment in both
units of STP belong in rate base. This belief is based on, among
other factors, Units 1 and 2 providing output at high capacity
factors since April and June 1994, respectively. In addition, the
long-term benefits nuclear generation provides to customers
supports their inclusion in rate base. Furthermore, there are no
Texas Commission precedents addressing the removal of a nuclear
plant from rate base as a performance-based disallowance.
Assuming both units of STP are included in rate base, CPL believes
it is not collecting excessive revenues, notwithstanding that
market rates of return on common equity are generally lower today
than they were in 1990 and 1991, when CPL's base rates were last
set.
2-97
Fuel
Introduction
Pursuant to the substantive rules of the Texas Commission, CPL
generally is allowed to recover its fuel costs through a fixed
fuel factor. These fuel factors are in the nature of temporary
rates, and CPL'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 costs 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.
Fuel Surcharge - Docket No. 12154
In July 1993, CPL 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 CPL's request to postpone consideration of the surcharge.
In January and July of 1994, CPL updated its fuel surcharge
petition to reflect amounts of under-recovery through November
1993 and May 1994, respectively. Also, CPL updated its petition
in January 1995 to reflect amounts of under-recovery through
November 1994. Likewise, CPL requested and was granted
postponement of the updated petitions until the STP outage
concluded or at the time fuel costs are next reconciled. On
January 4, 1995, Docket No. 12154 was consolidated into Docket No.
13650.
Prudence Inquiry - Docket No. 13126
In April 1994, the Texas Commission's General Counsel and Staff
issued a Request for Proposal for an audit of the STP outage, and
in July 1994 a consultant was selected to perform the audit. The
purpose of the audit is to evaluate the prudence of management
activities at STP, including the actions of HLP and the STP
management committee, of which CPL is a participant. Such review
will include the time from original commercial operation of each
unit until they were returned to service from the outage. The
findings of this audit are expected to be incorporated into this
proceeding. CPL and HLP will pay the costs of the audit but will
have no control over the ultimate work product of the consultant.
In June 1994, the Texas Commission's General Counsel initiated an
inquiry into the operation and management of STP which resulted in
the establishment of this proceeding. As part of the inquiry, CPL
presented certain information concerning the prudence of
management activities at STP relating to the STP outage.
Testimony filed by CPL stated that the cause of the STP outage was
the result of an accidental equipment failure rather than
imprudent management activities at STP. Based on this
information, CPL will seek full recovery in its fuel
reconciliation case of incremental energy costs related to the STP
outage.
As a part of this proceeding, CPL was required to reconstruct its
production costs assuming STP was available 100% of the time
during the actual outage. Testimony filed by CPL stated that it
is unrealistic to expect any generating unit to operate all the
time. The testimony provided calculations of STP replacement
power cost estimates for availability factor scenarios at (i)
100%, (ii) 75% and (iii) 65% average availability. Based on these
average availability factors, STP net replacement power costs for
the entire outage period were estimated to be (i) $104.5 million
at 100%, (ii) $79.0 million at 75% and (iii) $68.2 million at 65%
average availability.
The results of this prudence inquiry are expected to be used in
CPL's pending fuel reconciliation proceeding in Docket No. 13650,
as discussed below, and possibly CPL's next base rate proceeding
should a return on equity penalty be ordered by the Texas
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Commission. Such penalty could lower CPL's allowed return on
equity in its next base rate case from what it otherwise would be
permitted to earn.
Fuel Reconciliation - Docket No. 13650
On November 15, 1994, CPL filed a fuel reconciliation case with
the Texas Commission seeking to reconcile approximately $1.2
billion of fuel costs from March 1, 1990 through June 30, 1994.
This period includes the STP outage where CPL's fuel and purchased
power costs were increased as the power normally generated by STP
was replaced through sources with higher costs. At December 31,
1994, CPL's under-recovered fuel balance was $54.1 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. CPL cannot accurately
estimate the amount of any future under- or over-recoveries due to
the nature of the above factors. CPL cannot predict how the Texas
Commission will ultimately resolve the reasonableness of higher
replacement energy costs associated with the STP outage. Although
the Texas Commission could disallow all or a portion of the STP
replacement energy costs, such determination cannot be made until
a final order is issued by the Texas Commission in this docket.
If a significant portion of the fuel costs were disallowed by the
Texas Commission, CPL could experience a material adverse effect
on its results of operations in the year of disallowance but not
on its financial condition.
CPL continues to negotiate with the intervening parties to resolve
Docket Nos. 12820, 13126 and the STP portions of Docket No. 13650
through settlement. However, no settlement has been reached.
Management cannot predict the ultimate outcome of the CPL rate
inquiry and fuel regulatory proceedings. However, management
believes that the ultimate resolution of the various issues will
not have a material adverse effect on CPL's results of operations
or financial condition.
STP Background
Final Orders
In October 1990, the Texas Commission issued the 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 the STP Unit 2 Order
which fully implemented a stipulated agreement to resolve all
issues regarding CPL's investment in STP Unit 2.
The STP Unit 1 Order allowed CPL 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 had authorized deferral of STP Unit 1
costs. See Deferred Accounting below. 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
CPL 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. The Mirror
CWIP liability is being reduced by the recognition of non-cash
income during the period 1991 through 1995. The Mirror CWIP asset
is being amortized to expense over the life of the plant.
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,
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the original costs of CPL's total investment in STP is included in
rate base. As indicated under the heading Texas Commission
Proceedings above, however, CPL is currently involved in base rate
and fuel proceedings which challenge CPL's right to recover
certain costs associated with the STP outage.
As part of the stipulated agreement, CPL 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. CPL 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 CPL, the Staff and a majority of intervenors including major
cities in CPL's service territory and major industrial customers.
These intervenors represent a significant majority of CPL's
customers. CPL and the TSA reached agreements, which were
subsequently approved by the 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 CPL could experience a
significant adverse effect on its results of operations and
financial condition. 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
economic results. Management believes that the STP Unit 1 and 2
Orders will be upheld.
Deferred Accounting
CPL was granted deferred accounting for STP Unit 1 and 2 costs by
Texas Commission orders. These orders allowed CPL 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 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, CPL's
retail rates include recovery of 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 CPL'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 CPL 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 CPL from earning
a return on such costs.
After the Court of Appeals' denial of each party's motion for
rehearing of the decision, CPL and the Texas Commission in
December 1992 filed Applications for Writ of Error petitioning the
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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 Appeals' decision, challenging
generally the legality of deferred accounting for rate base
treatment of any deferred costs. In May 1993, the Supreme Court
of Texas granted CPL's Application for Writ of Error. CPL's case
was consolidated with the deferred accounting cases of El Paso and
HLP. In June 1994, the Supreme Court of Texas sustained deferred
accounting as an appropriate mechanism for the Texas Commission to
use in preserving the financial integrity of utilities. The
Supreme Court of Texas held that the Texas Commission can
authorize utilities to defer those costs that are incurred between
the in-service date of a plant and the effectiveness of new rates,
which include such costs. On October 6, 1994, the Supreme Court
of Texas denied a motion for rehearing CPL's deferred accounting
matter filed by the State of Texas. The language of the Supreme
Court of Texas opinion suggests that the appropriateness of
allowing deferred accounting may need to again be reviewed under a
financial integrity standard at the time the costs begin being
recovered through rates. For CPL, that would be the STP Unit 1
and Unit 2 Orders discussed above. To the extent that additional
review is required, it should occur in those dockets.
If these deferred accounting matters are not favorably resolved,
CPL could experience a material adverse effect on its results of
operations and financial condition. While CPL's management cannot
predict the ultimate outcome of these matters, management believes
CPL will 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 CPL's results of
operations or financial condition.
Westinghouse Litigation
CPL and other owners of STP are plaintiffs in a lawsuit filed in
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 set for trial in July
1995.
Inspections during the STP outage have detected early signs of
stress corrosion cracking in tubes at STP Unit 1. Management
believes additional problems would develop gradually and will be
monitored by the Project Manager 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.
Management believes that the ultimate resolution of this matter
will not have a material adverse effect on CPL's results of
operations or financial condition.
Industrial Road and Industrial Metals Site
Several lawsuits relating to the industrial road and industrial
metals site in Corpus Christi, Texas, naming CPL as a defendant,
are currently pending in federal and state court in Texas.
Plaintiffs' claims allege property damage and health impairment as
a result of operations on the site and clean-up activities.
Although management cannot predict the outcome of these
proceedings, based on the defenses that management believes are
available to CPL, management believes that the ultimate resolution
of these matters will not have a material adverse effect on CPL's
results of operations or financial condition.
Civil Penalties
In October 1994, the NRC staff advised HLP that it proposes to
fine HLP $100,000 for what the NRC believes was discrimination
against a contractor employee at STP who brought complaints of
possible safety problems to the NRC's attention. These actions
resulted from the findings of a NRC investigation of alleged
violations of STP security and work process procedures in 1992.
The incident cited by the NRC is the subject of a contested
hearing that is scheduled to be held in the spring of 1995 before
a United States Department of Labor judge. Until the Department
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of Labor issues a final decision in this matter, the NRC is not
requiring HLP to respond to its notice of violation.
Other
CPL 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 CPL's results of operations or financial condition.
10. Commitments and Contingent Liabilities
It is estimated that CPL will spend approximately $108 million in
construction expenditures during 1995. Substantial commitments
have been made in connection with this capital expenditure
program.
To supply a portion of its fuel requirements CPL 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 $8.92 billion per incident, effective as of
January 1995. 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 $8.72 billion. The maximum amount
that each licensee may be assessed under the industry-wide program
of self-insurance following a nuclear incident at an insured
facility is $75.5 million per reactor, 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. CPL and each of the other STP owners are subject to
such assessments, which CPL and other owners have agreed will be
allocated 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 $2.75
billion provided by ANI and NEIL. Policies of insurance issued by
ANI and NEIL stipulate that policy proceeds must be used first to
pay decontamination and clean-up costs before being used to cover
direct losses to property. Under project agreements, CPL and the
other owners of STP will share the total cost of decontamination
liability and property insurance for STP, including premiums and
assessments, on a pro rata basis, according to each owner's
respective ownership interest in STP.
CPL purchases, for its own account, a NEIL I Business Interruption
and/or Extra Expense policy. This insurance will reimburse CPL
for extra expenses incurred, up to $1.65 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 $111.3
million and for Unit 2 is $111.8 million. CPL is subject to an
additional assessment up to $2.1 million for the current policy
year in the event that losses as a result of a covered accident at
a nuclear facility insured under the NEIL I policy exceeds the
accumulated funds available under the policy.
On August 28, 1994, CPL filed a claim under the NEIL I policy
related to the outage at STP Units 1 and 2. NEIL is currently
reviewing the claim. CPL management is unable to predict the
ultimate outcome of this matter.
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11. Quarterly Information (Unaudited)
The following unaudited quarterly information includes, in the
opinion of management, all adjustments necessary for a fair
presentation of such amounts.
Operating Operating Net
Quarter Ended Revenues Income Income
1994 (thousands)
March 31 $ 263,229 $ 36,943 $ 24,986
June 30 333,169 75,070 62,470
September 30 364,044 96,062 82,877
December 31 257,537 48,176 35,106
$1,217,979 $ 256,251 $ 205,439
1993
March 31 $ 238,254 $ 39,593 $ 54,560
June 30 316,053 66,745 53,679
September 30 387,190 88,438 77,612
December 31 282,031 (4,697) (13,426)
$1,223,528 $ 190,079 $ 172,425
Information for quarterly periods is affected by seasonal
variations in sales, rate changes, timing of fuel expense recovery
and other factors.
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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 a wholly-owned subsidiary of Central and South West
Corporation) as of December 31, 1994 and 1993, and the related
statements of income, retained earnings and cash flows for each of
the three years in the period ended December 31, 1994. These
financial statements are the responsibility of CPL'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, 1994 and 1993,
and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1994, in conformity
with generally accepted accounting principles.
In 1993, as discussed in NOTE 1, CPL 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
Schedule II 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. This schedule 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 LLP
Dallas, Texas
February 13, 1995
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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 other information contained in this Annual 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 Annual Report is
consistent with that in the financial statements.
The financial statements have been audited by the independent
accounting firm, Arthur Andersen LLP, which was given unrestricted
access to all financial records and related data, including minutes
of all meetings of shareholders, the board of directors and
committees of the board. CPL believes that representations made to
the independent auditors during its audit were valid and appropriate.
Arthur Andersen LLP's audit report is presented elsewhere in this
report.
CPL maintains a system of internal controls to provide
reasonable assurance that transactions are executed in accordance
with management's authorization, that the financial statements are
prepared in accordance with generally accepted accounting principles
and that the assets of CPL are properly safeguarded against
unauthorized acquisition, use or disposition. The system includes a
documented organizational structure and division of responsibility,
established policies and procedures including a policy on ethical
standards which provides that CPL will maintain the highest legal and
ethical standards, and the careful selection, training and
development of our employees.
Internal auditors continuously monitor the effectiveness of the
internal control system following standards established by the
Institute of Internal Auditors. Actions are taken by management to
respond to deficiencies as they are identified. The board, operating
through its audit committee, which is comprised entirely of directors
who are not officers or employees of CPL provides oversight to the
financial reporting process.
Due to the inherent limitations in the effectiveness of internal
controls, no internal control system can provide absolute assurance
that errors will not occur. However, management strives to maintain
a balance, recognizing that the cost of such a system should not
exceed the benefits derived.
CPL believes that, in all material respects, its system of
internal controls over financial reporting and over safeguarding of
assets against unauthorized acquisition, use or disposition
functioned effectively during 1994.
Robert R. Carey R. Russell Davis
President and CEO - CPL Controller - CPL
2-105
PSO
PUBLIC SERVICE COMPANY OF OKLAHOMA
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Selected Financial Data
PSO
The following selected financial data for each of the five years
ended December 31 are provided to highlight significant trends in the
financial condition and results of operations for PSO.
1994 1993 1992 1991 1990
(thousands, except ratios)
Operating Revenues $740,496 $707,536 $622,092 $650,942 $620,132
Income Before Cumulative
Effect of Changes in
Accounting Principles 68,266 40,496 45,562 53,229 55,082
Cumulative Effect of Changes
in Accounting Principles (1) -- 6,223 -- -- --
Net Income 68,266 46,719 45,562 53,229 55,082
Preferred Stock Dividends 816 816 816 816 816
Net Income for Common Stock 67,450 45,903 44,746 52,413 54,266
Total Assets 1,465,114 1,420,379 1,351,201 1,308,075 1,283,915
Common Stock Equity 461,499 435,049 429,146 419,400 386,987
Preferred Stock 19,826 19,826 19,826 19,826 19,826
Long-term Debt 402,752 401,255 408,731 368,219 367,727
Ratio of Earnings to Fixed
Charges (SEC Method) Before
Cumulative Effect of Changes
in Accounting Principles 4.03 2.78 2.95 3.33 2.93
Capitalization Ratios
Common Stock Equity 52.2% 50.8% 50.0% 51.9% 50.0%
Preferred Stock 2.2 2.3 2.3 2.5 2.5
Long-term Debt 45.6 46.9 47.7 45.6 47.5
(1)The 1993 cumulative effect relates to the changes in accounting
for unbilled revenues, adoption of SFAS Nos. 112 and 109. See
NOTE 1, Summary of Significant Accounting Policies.
PSO 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 reported for prior years and therefore have not
been restated.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
PUBLIC SERVICE COMPANY OF OKLAHOMA
Reference is made to PSO's Consolidated Financial Statements and
related Notes and Selected Financial Data. The information contained
therein should be read in conjunction with, and is essential to
understanding, the following discussion and analysis.
Overview
Net income for common stock for 1994 was $67 million, a 47%
increase from 1993. The increase was due primarily to increased
energy sales to retail customers and sales for resale to other
electric utilities due to increased market place demand and the 1993
restructuring charges of $25 million.
Restructuring
As previously reported, PSO has taken steps to implement a
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 restructuring is to enable
PSO to focus on and be accountable for serving the customer. The
restructuring costs were initially estimated to be $25 million and
were expensed in 1993. The final costs of the restructuring were
approximately $25 million. Approximately $24 million of the
restructuring expenditures were incurred during 1994, with the
remaining $1 million expected to be incurred during 1995.
Approximately $4 million of the restructuring expenses relate to
employee termination benefits, $12 million relate to enhanced benefit
costs and $9 million relate to employees that will not be terminated.
Approximately $17 million of the restructuring costs were paid from
or will be paid from general corporate funds. The remaining $8
million represents the present value of enhanced benefit amounts to
be paid from the benefit plan trusts to participants over future
years in accordance with the early retirement program. The cost of
these enhanced benefit amounts will be paid from general corporate
funds to the benefit plan trusts over future years. The
restructuring is substantially completed, with the remaining activity
to take place during 1995. Certain aspects of the restructuring are
pending SEC approval under the Holding Company Act.
PSO expects to realize a number of benefits from the
restructuring. Beginning in 1994 and continuing into the future,
increased efficiencies and synergies are expected to be realized with
the elimination of previously duplicated functions. This leads to
enhanced communication and efficiency, which should translate into a
reduction in the rate of growth in O&M costs. The CSW System expects
that all restructuring costs will be recovered by early 1996 with
reductions in the rate of growth of O&M costs continuing thereafter.
Rates and Regulatory Matters
See NOTE 8, Litigation and Regulatory Proceedings, for
information regarding the PSO rate case.
New Accounting Standards
SFAS No. 115 was effective for fiscal years beginning after
December 15, 1993. PSO adopted SFAS No. 115 in 1994. The adoption of
SFAS No. 115 did not have a material effect on PSO's consolidated
results of operations or financial condition.
In June 1993 the FASB issued SFAS No. 116. The statement,
effective for fiscal years beginning after December 15, 1994, will be
adopted by PSO for 1995. The statement establishes accounting
standards for contributions and applies to all entities that receive
or make contributions. Management does not believe the adoption of
SFAS No. 116 will have a material impact on PSO's consolidated results
of operations or financial condition.
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SFAS No. 119 was effective for fiscal years ending after December
15, 1994. PSO does not currently uses derivative instruments, but may
use these instruments in the future to manage the increased market
risks associated with greater competition in the electric utility
industry. The adoption of this new statement had no material effect
on PSO's consolidated results of operations or financial condition.
Liquidity and Capital Resources
Overview
PSO's need for capital results primarily from the construction of
facilities to provide reliable electric service to its customers.
Accordingly, internally generated funds should meet most of the
capital requirements. However, if internally generated funds are not
sufficient, PSO's financial condition should allow it access to the
capital markets.
Capital Expenditures
Construction expenditures, including AFUDC, were approximately
$131 million in 1994, $95 million in 1993, and $100 million in 1992.
It is estimated that construction expenditures, including AFUDC,
during the 1995 through 1997 period will aggregate $213 million. Such
expenditures primarily will be made to improve and expand 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 construction program continues to be monitored, reviewed and
adjusted to reflect changes in estimated load growth in PSO's service
area, variations in prices of alternative fuel sources, the cost of
labor, materials, equipment and capital, and other external factors.
The CSW System facilities plan presently includes projected
lignite-fired generating plants for which PSO has invested
approximately $15 million in prior years for plant sites, engineering
studies and lignite reserves. Should future plans exclude these
plants for environmental or other reasons, PSO would evaluate the
probability of recovery of these investments and may record
appropriate reserves.
Long-Term Financing
As of December 31, 1994, the capitalization ratios of PSO were
52% common stock equity, 2% preferred stock and 46% long-term debt.
PSO's embedded cost of long-term debt was 7.4% at the end of 1994.
PSO continually monitors the capital markets for opportunities to
lower its cost of capital through refinancing. PSO continues to be
committed to maintaining financial flexibility by maintaining a strong
capital structure and favorable securities ratings which should allow
funds to be obtained from the capital markets when required.
Short-Term Financing
PSO, together with other members of 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. PSO's short-term borrowing
limit from the money pool is $100 million. During 1994, the annual
weighted average interest rate was 4.5% and the average amount of
short-term month-end borrowings outstanding was $42 million. The
maximum amount of short-term borrowings outstanding at any month-end
during 1994 was $73 million, which was the amount outstanding at May
31, 1994.
Internally Generated Funds
Internally generated funds consist of cash flows from operating
activities less common and preferred stock dividends. PSO utilizes
short-term debt to meet fluctuations in working capital requirements
due to the seasonal nature of energy sales. PSO anticipates that
capital requirements for the period 1995 to 1997 will be met in large
part from internal sources. PSO also anticipates that some external
financing will be required during the period, but the nature, timing
and extent have not yet been determined. Information concerning
internally generated funds follows:
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1994 1993 1992
(millions)
Internally Generated Funds $110 $93 $63
Construction Expenditures Provided
by Internally Generated Funds 85% 99% 63%
Sales of Accounts Receivable
PSO sells its billed and unbilled accounts receivable, without
recourse, to CSW Credit. The sales provided PSO with cash
immediately, thereby reducing working capital needs and revenue
requirements. The average and year end amounts of accounts receivable
sold were $88 million and $75 million in 1994, as compared to $85
million and $80 million in 1993.
Recent Developments and Trends
Competition and Industry Challenges
Competitive forces at work in the electric utility industry are
impacting PSO and electric utilities generally. Increased competition
facing electric utilities is driven by complex economic, political and
technological factors. These factors have resulted in legislative and
regulatory initiatives that are likely to result in even greater
competition at both the wholesale and retail level in the future. As
competition in the industry increases, PSO will have the opportunity
to seek new customers and at the same time be at risk of losing
customers to other competitors. PSO believes that its prices for
electricity and the quality and reliability of its service currently
place it in a position to compete effectively in the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly
alters the way in which electric utilities compete. The Energy Policy
Act creates exemptions from regulation under the Holding Company Act
and permits utilities, including registered utility holding companies
and non-utility companies, to form EWGs. EWGs are a new category of
non-utility wholesale power producer that are 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. The Energy Policy Act also 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. A FERC order requiring a transmitting utility
to provide wholesale transmission service must include provisions
generally that permit (i) the utility to recover from the FERC
applicant all of the costs incurred in connection with the
transmission services and (ii) any enlargement of the transmission
system and associated services. While PSO believes that the Energy
Policy Act will continue to make the wholesale markets more
competitive, PSO is unable to predict the extent to which the Energy
Policy Act will impact on its operations.
Increasing competition in the utility industry brings an
increased need to stabilize or reduce rates. The retail regulatory
environment is beginning to shift from traditional rate base
regulation to incentive regulation. Incentive rate and performance-
based plans encourage efficiencies and increased productivity while
permitting utilities to share in the results. Retail wheeling, a
major industry issue which may require utilities to "wheel" or move
power from third parties to their own retail customer, is evolving
gradually.
Wholesale energy markets, including the market for wholesale
electric power, have been extremely competitive since the enactment of
the Energy Policy Act. PSO competes in the wholesale energy markets
with other public utilities, cogenerators, qualified facilities,
exempt wholesale generators and others for sales of electric power.
Under the Energy Policy Act, the FERC has approved several
proposals by utility companies to sell wholesale power at market-based
rates and provide to electric utilities "open access" to transmission
systems, subject to certain requirements. The adoption of these
proposals increases marketing opportunities for electric utilities,
2-110
but also exposes them to the risk of loss of load or reduced revenues
due to competition with alternative suppliers.
PSO believes that, compared to other electric utilities, it is
well positioned to meet future competition. PSO benefits from
economies of scale and scope by virtue of its size and its
relationship to the CSW System. PSO is also a relatively low-cost
producer of electric power. Moreover, PSO is taking steps to enhance
its marketing and customer service, reduce costs, improve and
standardize business practices, and grow through strategic
acquisitions, in order to position itself for increased competition in
the future.
PSO is unable to predict the ultimate outcome or impact of
competitive forces on the electric utility industry or on PSO. As the
wholesale and retail electricity markets become more competitive,
however, the principal factor determining success is likely to be
price, and to a lesser extent, reliability, availability of capacity,
and customer service.
Regulatory Accounting
Consistent with industry practice and the provisions of SFAS No.
71, which allows for the recognition and recovery of regulatory
assets, PSO has recognized significant regulatory assets and
liabilities. Management believes that PSO will continue to meet the
criteria for following SFAS No. 71. However, in the event PSO no
longer meets the criteria for following SFAS No. 71, a write-off of
regulatory assets and liabilities would be required. For additional
information regarding SFAS No. 71 reference is made to NOTE 1,
Summary of Significant Accounting Policies - Regulatory Assets and
Liabilities.
Environmental Matters
CERCLA and Related Matters
The operations of PSO, like those of other utilities, generally
involve the use and disposal of substances subject to environmental
laws. The 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. PRPs include owners and operators of
contaminated sites and transporters and/or generators of hazardous
substances. 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.
PSO is subject to various pending claims alleging it is a PRP
under federal or state remedial laws for investigating and cleaning up
contaminated property. PSO anticipates that resolution of these
claims, individually or in the aggregate, will not have a material
adverse effect on PSO's consolidated results of operations or
financial condition. Although the reasons for this expectation differ
from site to site, factors that are the basis for the expectation for
specific sites include the volume and/or type of waste allegedly
contributed by PSO, the estimated amount of costs allocated to PSO and
the participation of other parties.
Clean Air Act Amendments
In November 1990, the United States Congress passed the Clean
Air Act which places restrictions on the emission of sulfur dioxide
from gas-, coal- and lignite-fired generating plants. Beginning in
the year 2000, PSO will be required to hold allowances in order to
emit sulfur dioxide. The EPA issues allowances to owners of existing
generating units based on historical operating conditions. Based on
the CSW System facilities plan, PSO believes that its allowances will
be adequate to meet its needs at least through 2008. Public and
private markets are developing for trading of excess allowances. PSO
presently has no intention of engaging in trading of allowances, but
may seek to do so in the future if market conditions warrant and
appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source
permit program to be administered by the states.
2-111
The Clean Air Act also directs the EPA to issue regulations
governing nitrogen oxide emissions and requires government studies to
determine what controls, if any, should be imposed on utilities to
control air toxics emissions. The impact that the nitrogen oxide
emission regulations and the air toxics study will have on PSO cannot
be determined at this time.
As a result of requirements imposed by the Clean Air Act, PSO
expects to spend an additional $1.3 million for annual testing of,
software modifications to, and maintenance of continuous emission
monitoring equipment from 1995 through 1997.
EMFs
Research is ongoing whether exposure to EMFs may result in
adverse health effects. Although a few of the studies to date have
suggested certain associations between EMFs and some types of effects,
the research to date has not established a cause-and-effect
relationship between EMFs and adverse health effects. PSO cannot
predict the impact on it 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.
See ITEM 1. BUSINESS - Environmental Matters and NOTE 8,
Litigation and Regulatory Proceedings, for additional discussion of
environmental issues.
Results of Operations
Electric Operating Revenues
Revenues for 1994 increased approximately $33 million or 5% when
compared to 1993. Revenues for 1993 increased approximately $85.4
million or 14% when compared to 1992. The increase in 1994 reflected
an increase of approximately 8% in KWH sales resulting from increased
sales for resale to other electric utilities due to increased
marketplace demand, partially offset by lower unit fuel costs as
described below. Approximately $7.9 million of the 1993 increase was
due to an increase in retail prices. Retail kilowatt-hour sales
increased 7% as a result of warmer weather in 1993 compared to the
substantially milder than normal weather in 1992. Additionally, 1994
and 1993 were affected by increased fuel recovery as discussed below.
The Company recovers its monthly fuel and purchased power expenses
currently in its revenues and therefore the increase in these costs
resulted in higher revenues.
Fuel and Purchased Power Expenses
Fuel expense for 1994 increased approximately $17.6 million or
6% when compared to 1993. During 1993, fuel expense increased
approximately $64 million or 27% when compared to 1992. Fuel expense
for 1994 and 1993 increased primarily as a result of fewer customers
participating in the FUSER Program, which terminated effective
October 1993. See ITEM 1. BUSINESS -- REGULATION AND RATES for
additional information relating to FUSER. In 1994, fuel expense was
also affected by a 17% increase in KWH generation and an over-
recovery of fuel costs from customers, which was previously recorded
as deferred fuel, offset in part by a reduction in average unit fuel
costs. The average unit fuel cost for 1994 was $1.96 per million BTU,
a decrease of approximately 18% from the same period last year. The
decrease in per unit fuel cost reflects the reversal of prior years
accruals for potential liabilities related to coal transportation, as
well as lower costs for natural gas and coal. The increase in fuel
expense during 1993 was due primarily to an increase in KWH
generation and an increase in unit fuel costs. KWH generation
increased 10% due primarily to increased weather-related customer
usage and unscheduled 1992 power station maintenance which did not
recur in 1993. The average unit fuel cost for 1993 was $2.38 per
million Btu, an increase of approximately 2% from 1992 of $2.34 per
million Btu. The increase in unit fuel costs was primarily due to an
accrual for potential liabilities related to coal transportation,
partially offset by lower costs of natural gas and coal.
Purchased power expenses for 1994 increased approximately $2.2
million or 7% as a result of additional economy energy purchases.
Purchased power expenses for 1993 decreased approximately $10.4
million or 24% as a result of additional purchases of firm energy in
2-112
1992 due to unscheduled power station maintenance which did not recur
in 1993.
Operating Expenses and Taxes
Changes in operating expenses in 1994 and 1993 were affected by
1993 restructuring charges of approximately $25 million, which
includes approximately $18 million for an early retirement and
voluntary severance program. Changes in operating expenses for both
years were also affected by the 1993 write-off of certain lignite
properties of approximately $5 million and accrued mine reclamation
expenses of approximately $3 million. Maintenance in 1993 decreased
as a result of unscheduled power station maintenance in 1992.
Depreciation and amortization expense increased approximately $4
million or 7% in 1994 and $3 million or 5% in 1993 due to increases
in depreciable property.
Taxes, other than federal income increased approximately $3.6
million or 13% in 1994 and decreased approximately $.5 million or 2%
in 1993 primarily as a result of changes in state income taxes.
Federal income tax expense increased approximately $11.3 million
or 56% in 1994 and $5.2 million or 35% in 1993 primarily as a result
of increased pre-tax income. Additionally, 1993 tax expense
increased as a result of an increase in the federal statutory rate
from 34% in 1992 to 35% in 1993.
Inflation
Annual inflation rates, as measured by the national Consumer
Price Index, have averaged 2.7% during the three years ended December
31, 1994. PSO believes that inflation, at this level, does not
materially affect its consolidated results of operations 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.
Interest Charges
Interest charges for 1994 decreased approximately $1.3 million
or 4% as a result of the refinancing in 1993 of higher cost debt.
This decrease is offset in part by increases in short-term
borrowings. In 1993, charges increased approximately $1.3 million or
4% as a result of higher principal amounts of long-term debt
outstanding, offset in part by the reacquisition of higher cost debt.
In 1993, interest on short-term debt and other was affected by
interest accruals associated with the settlement of federal income
tax audit issues partially offset by decreased short-term borrowings
at lower rates.
Cumulative Effect of Changes in Accounting Principles
PSO implemented a number of accounting changes in 1993. These
included the adoption of SFAS No. 112 and SFAS No. 109. PSO also
changed its method of accounting for unbilled revenues. These
accounting changes had a cumulative effect of increasing net income
approximately $6 million.
2-113
Consolidated Statements of Income
Public Service Company of Oklahoma
For the Years Ended December 31,
1994 1993 1992
(thousands)
Electric Operating Revenues
Residential $296,159 $296,027 $258,259
Commercial 227,488 222,598 203,176
Industrial 165,200 149,762 122,180
Sales for resale 35,458 18,248 17,782
Other 16,191 20,901 20,695
740,496 707,536 622,092
Operating Expenses and Taxes
Fuel 316,470 298,905 234,884
Purchased power 34,906 32,711 43,134
Other operating 120,233 125,830 117,450
Restructuring charges (197) 24,995 --
Maintenance 44,847 45,777 49,027
Depreciation and amortization 63,096 59,133 56,103
Taxes, other than federal
income 31,637 28,060 28,639
Federal income taxes 31,246 19,969 14,759
642,238 635,380 543,996
Operating Income 98,258 72,156 78,096
Other Income and Deductions
Allowance for equity funds used
during construction 1,094 1,096 349
Other 933 531 (940)
2,027 1,627 (591)
Income Before Interest Charges 100,285 73,783 77,505
Interest Charges
Interest on long-term debt 29,594 31,410 30,688
Interest on short-term debt
and other 3,844 2,729 1,646
Allowance for borrowed funds
used during construction (1,419) (852) (391)
32,019 33,287 31,943
Income Before Cumulative Effect
of Changes in Accounting
Principles 68,266 40,496 45,562
Cumulative Effect of Changes in
Accounting Principles -- 6,223 --
Net Income 68,266 46,719 45,562
Preferred stock dividends 816 816 816
Net Income for Common Stock $ 67,450 $ 45,903 $ 44,746
The accompanying notes to consolidated financial statements are an
integral part of these statements.
2-114
Consolidated Statements of Retained Earnings
Public Service Company of Oklahoma
For the Years Ended December 31,
1994 1993 1992
(thousands)
Retained Earnings at Beginning of Year $97,819 $91,916 $82,170
Net income for common stock 67,450 45,903 44,746
Deduct: Common stock dividends 41,000 40,000 35,000
Retained Earnings at End of Year $124,269 $97,819 $91,916
The accompanying notes to consolidated financial statements are an
integral part of these statements.
2-115
Consolidated Balance Sheets
Public Service Company of Oklahoma
As of December 31,
1994 1993
(thousands)
ASSETS
Electric Utility Plant
Production $ 902,602 $ 895,315
Transmission 346,433 335,405
Distribution 668,346 626,519
General 150,898 143,834
Construction work in progress 96,133 51,931
2,164,412 2,053,004
Less - Accumulated depreciation 859,894 806,066
1,304,518 1,246,938
Current Assets
Cash and temporary cash investments 5,453 2,429
Accounts receivable 21,531 36,612
Materials and supplies, at average cost 39,888 38,212
Fuel inventory, at LIFO cost 17,820 21,273
Accumulated deferred income taxes 6,670 --
Prepayments 7,889 2,755
99,251 101,281
Deferred Charges and Other Assets 61,345 72,160
$1,465,114 $1,420,379
The accompanying notes to consolidated financial statements are an
integral part of these statements.
2-116
Consolidated Balance Sheets
Public Service Company of Oklahoma
As of December 31,
1994 1993
(thousands)
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock: $15 par value
Authorized: 11,000,000 shares
Issued 10,482,000 shares and
outstanding 9,013,000 shares $ 157,230 $ 157,230
Paid-in capital 180,000 180,000
Retained earnings 124,269 97,819
Total Common Stock Equity 461,499 435,049
Preferred stock 19,826 19,826
Long-term debt 402,752 401,255
Total Capitalization 884,077 856,130
Current Liabilities
Advances from affiliates 55,160 31,744
Payables to affiliates 27,876 18,218
Accounts payable 59,899 55,606
Payables to customers 22,655 13,932
Accrued taxes 17,356 15,191
Accrued interest 8,867 5,382
Accumulated deferred income taxes -- 3,633
Accrued restructuring charges 1,046 24,995
Other 14,111 20,140
206,970 188,841
Deferred Credits
Accumulated deferred income taxes 281,139 260,490
Investment tax credits 49,011 51,800
Income tax related regulatory
liabilities, net 18,611 21,178
Other 25,306 41,940
374,067 375,408
$1,465,114 $1,420,379
The accompanying notes to consolidated financial statements are an
integral part of these statements.
2-117
Consolidated Statements of Cash Flows
Public Service Company of Oklahoma
For the Years Ended December 31,
1994 1993 1992
(thousands)
OPERATING ACTIVITIES
Net Income $ 68,266 $ 46,719 $ 45,562
Non-cash Items Included in Net Income
Depreciation and amortization 67,452 65,242 61,821
Restructuring charges (197) 24,995 --
Deferred income taxes and
investment tax credits 4,990 6,700 18,446
Cumulative effect of changes in
accounting principles -- (6,223) --
Allowance for equity funds used
during construction (1,094) (1,096) (349)
Changes in Assets and Liabilities
Accounts receivable 15,081 (17,299) (8,793)
Materials and supplies 1,777 2,872 (5,743)
Accounts payable 26,375 10,332 9,540
Accrued taxes 2,165 4,240 (17,195)
Accrued restructuring charges (15,626) -- --
Other deferred credits (16,634) (3,712) (13,762)
Other (754) 1,322 8,955
151,801 134,092 98,482
INVESTING ACTIVITIES
Construction expenditures (128,625) (92,648) (99,079)
Allowance for borrowed funds used
during construction (1,419) (852) (391)
Other (335) (6,125) (2,419)
(130,379) (99,625) (101,889)
FINANCING ACTIVITIES
Proceeds from issuance of
long-term debt -- 181,194 113,886
Retirement of long-term debt -- (10,000) --
Reacquisition of long-term debt -- (189,685) (63,933)
Change in advances from affiliates 23,416 26,454 (11,575)
Payment of dividends (41,814) (40,816) (35,817)
(18,398) (32,853) 2,561
Net Change in Cash and Cash Equivalents 3,024 1,614 (846)
Cash and Cash Equivalents at Beginning of
Year 2,429 815 1,661
Cash and Cash Equivalents at End of Year $ 5,453 $ 2,429 $ 815
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized $ 31,459 $ 34,844 $ 27,708
Income taxes paid $ 28,910 $ 9,232 $ 8,718
The accompanying notes to consolidated financial statements are an
integral part of these statements
2-118
Consolidated Statements of Capitalization
Public Service Company of Oklahoma
As of December 31,
1994 1993
(thousands)
COMMON STOCK EQUITY $461,499 $435,049
PREFERRED STOCK
(Cumulative $100 par value, authorized 700,000
shares, redeemable at the option of PSO
upon 30 days notice)
Number Current
of Shares Redemption
Series Outstanding Price
4.00% 97,900 $105.75 9,790 9,790
4.24% 100,000 103.19 10,000 10,000
Premium 36 36
19,826 19,826
LONG-TERM DEBT
First Mortgage Bonds
Series J, 5 1/4%, due March 1, 1996 25,000 25,000
Series K, 7 1/4%, due January 1, 1999 25,000 25,000
Series L, 7 3/8%, due March 1, 2002 30,000 30,000
Series S, 7 1/4%, due July 1, 2003 65,000 65,000
Series T, 7 3/8%, due December 1, 2004 50,000 50,000
Series U, 6 1/4%, due April 1, 2003 35,000 35,000
Series V, 7 3/8%, due April 1, 2023 100,000 100,000
Series W, 6 1/2%, due June 1, 2005 50,000 50,000
Installment sales agreement - Pollution
Control
Bonds
Series A, 5.9%, due December 1, 2007 34,700 34,700
Series 1984, 7 7/8%, due September 15, 2014 12,660 12,660
Unamortized discount (4,756) (5,097)
Unamortized costs of reacquired debt (19,852) (21,008)
402,752 401,255
TOTAL CAPITALIZATION $884,077 $856,130
The accompanying notes to consolidated financial statements are an
integral part of these statements.
2-119
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies
Public Utility Regulation
PSO is subject to regulation by the SEC under the Holding Company
Act and the FERC under the Federal Power Act, and follows the
Uniform System of Accounts prescribed by the FERC. PSO is subject
to further regulation with regard to rates and other matters by
the Oklahoma Commission. PSO, as a member of the CSW System,
engages in transactions and coordinates its activities and
operations with other members of the CSW System.
The more significant accounting policies of PSO and its subsidiary
are summarized below:
Principles of Consolidation
The consolidated financial statements include the accounts of PSO
and its wholly-owned subsidiary, Ash Creek Mining Company. All
significant intercompany items and transactions have been
eliminated.
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 electric utility plant are computed
using the straight-line method, generally at individual rates
applied to the various classes of depreciable property. The
annual average consolidated composite rates were 3.5% in 1994,
1993 and 1992.
Electric Revenues and Fuel
Prior to January 1, 1993, electric revenues 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 operating revenues of
the next month. To conform to general industry standards, PSO
changed its method of accounting to accrue for estimated unbilled
revenues. The effect of this change on 1993 net income was an
increase of $8.4 million included in cumulative effect of changes
in accounting principles.
PSO recovers fuel costs in Oklahoma through automatic fuel
recovery mechanisms. PSO recovers fuel costs applicable to
wholesale customers, which are regulated by the FERC, through an
automatic fuel adjustment clause. Under rules established by the
Oklahoma Commission, PSO uses a method of deferred fuel
accounting. The difference between fuel revenues billed and fuel
expense incurred is recorded as a reduction of or an addition to
fuel expense, with a corresponding entry to accounts receivable or
payables to customers as appropriate. Deferred fuel costs are
applied to the customers' billings as a portion of the fuel
adjustment clause the second month subsequent to the month in
which the under-recoveries or over-recoveries occurred.
Accounts Receivable
PSO sells its billed and unbilled accounts receivable, without
recourse, to CSW Credit.
Regulatory Assets and Liabilities
For its regulated activities, PSO follows SFAS No. 71, which
defines the criteria for establishing regulatory assets and
regulatory liabilities. Regulatory assets represent probable
future revenue to PSO associated with certain costs which will be
recovered from customers through the ratemaking process.
Regulatory liabilities represent probable future refunds to
customers At December 31, 1994 and 1993, PSO had recorded the
following significant regulatory assets and liabilities:
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1994 1993
(thousands)
Regulatory Assets
(Included in Deferred Charges and
Other Assets on the Balance Sheets)
Deferred Storm Costs $ 4,798 $ 5,876
Demand Side Management Costs 5,411 4,198
OPEBs 4,504 5,895
Other 4,945 5,621
Regulatory Liabilities
Income tax related
regulatory liabilities, net $18,611 $21,178
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 are considered cash
equivalents.
Reclassification
Certain financial statement items for prior years have been
reclassified to conform to the 1994 presentation.
Accounting Changes
Effective January 1, 1993, PSO adopted SFAS Nos. 106, 112 and 109.
See NOTE 2, Federal Income Taxes, for further information
regarding SFAS No. 109. In addition, PSO also changed their
method of accounting for unbilled revenues. See Electric Revenues
and Fuel above for further information.
The adoption of SFAS No. 106 resulted in an increase in the
establishment of a regulatory asset of approximately $5 million.
See Note 8, Litigation and Regulatory Proceedings-Rate Review for
further information. The adoption of SFAS No. 109, SFAS No. 112
and the change in accounting for unbilled revenues are presented
as a cumulative effect of changes in accounting principles as
shown below:
Pre-Tax Tax Net Income
Effect Effect Effect
SFAS No. 109 $ -- $ (268) $ (268)
SFAS No. 112 (3,173) 1,227 (1,946)
Unbilled revenues 13,758 (5,321) 8,437
Total $10,585 $(4,362) $6,223
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
PSO adopted the provisions of SFAS No. 109 effective January 1,
1993. The implementation of SFAS No. 109 had no material effect
on PSO's earnings. As a result of this change, PSO recognized
additional accumulated deferred income taxes and corresponding
regulatory assets and liabilities to ratepayers in amounts equal
to future revenues or the reduction in future revenues required
when the income tax temporary differences reverse and are
recovered or settled in rates. As a result of a favorable
earnings history, PSO did not record any valuation allowance
against deferred tax assets at December 31, 1994 and 1993.
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PSO, together with other members of the CSW System, files a
consolidated Federal income tax return and participates in a tax
sharing agreement.
Components of income taxes follow:
1994 1993 1992
Included in Operating Expenses and Taxes (thousands)
Current $27,529 $13,165 $ (790)
Deferred 6,506 9,595 18,260
Deferred ITC (2,789) (2,791) (2,711)
31,246 19,969 14,759
Included in Other Income and Deductions
Current (4,080) (1,977) (314)
Deferred 89 (1,082) (149)
(3,991) (3,059) (463)
Tax Effects of Cumulative Effect of Changes
in Accounting Principles -- 3,954 --
$27,255 $20,864 $14,296
Investment tax credits deferred in prior years are included in
income over the lives of the related properties.
Total income taxes differ from the amounts computed by applying
the statutory income tax rates to income before taxes. The
reasons for the differences follow:
1994 % 1993 % 1992 %
(dollars in thousands)
Tax at statutory rates $ 33,432 35.0 $ 23,654 35.0 $ 20,351 34.0
Differences
Amortization of ITC (2,789) (2.9) (2,791) (4.1) (2,799) (4.7)
Flowback of tax rate
differential (1,541) (1.6) (1,629) (2.4) (1,627) (2.7)
Tax effect from prior
period flow through
and permanent
differences -- -- 1,167 1.7 1,018 1.7
Prior period adjustments (1,348) (1.4) 486 .7 (3,712) (6.2)
Other (499) (0.6) (23) -- 1,065 1.8
$27,255 28.5 $20,864 30.9 $14,296 23.9
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The significant components of the net deferred income tax
liability follow:
1994 1993
(thousands)
Deferred Income Tax Liabilities
Depreciable utility plant $292,127 $287,217
Income tax related regulatory assets 15,061 15,885
Other 25,309 19,156
Total Deferred Income Tax Liabilities 332,497 322,258
Deferred Income Tax Assets
Income tax related regulatory liability (22,260) (24,076)
Unamortized ITC (18,957) (20,036)
Other (16,811) (14,023)
Total Deferred Income Tax Assets (58,028) (58,135)
Net Accumulated Deferred Income Taxes - Total $274,469 $264,123
Net Accumulated Deferred Income Taxes - Noncurrent $281,139 $260,490
Net Accumulated Deferred Income Taxes - Current (6,670) 3,633
Net Accumulated Deferred Income Taxes - Total $274,469 $264,123
3.Long-Term Debt
The mortgage indenture, as amended and supplemented, securing
first mortgage bonds issued by PSO constitutes a direct first
mortgage lien on substantially all electric utility plant. PSO
may offer additional first mortgage bonds subject to market
conditions and other factors.
Annual Requirements
Certain series of outstanding first mortgage bonds have annual
sinking fund requirements, which are generally 1% of the amount of
each such series issued. These requirements may be, and generally
have been, satisfied by the application of net expenditures for
bondable property in an amount equal to 166-2/3% of the annual
requirements. At December 31, 1994, the annual sinking fund
requirements and annual maturities for the next five years follow:
Sinking Fund
Requirements Maturities
(thousands)
1995 $800 $ 800
1996 550 25,550
1997 550 550
1998 550 550
1999 300 25,300
Dividends
PSO's mortgage indenture, as amended and supplemented, contains
certain restrictions on the payment of common stock dividends. At
December 31, 1994, $124 million of retained earnings were
available for payment of cash dividends to its parent, CSW.
4.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.
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Cash and temporary cash investments
The carrying amount approximates fair value because of the short
maturity of those instruments.
Long-term debt
The fair value of PSO'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 PSO for debt of the same or similar
remaining maturities.
Advances from affiliates
The carrying amount approximates fair value because of the short
maturity of those instruments.
The estimated fair values of PSO's financial instruments follow:
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(thousands)
Cash and temporary cash
investments $ 5,453 $ 5,453 $ 2,429 $ 2,429
Long-term debt 402,752 364,585 401,255 413,218
Advances from affiliates 55,160 55,160 31,744 31,744
The fair value does not affect PSO's liabilities unless the issues
are redeemed prior to their maturity dates.
5.Short Term Financing
PSO, together with other members of the CSW System, has
established a money pool to coordinate short-term borrowings and
to make borrowings outside the money pool through CSW's issuance
of commercial paper. Money pool balances are shown as advances to
or from affiliates on the Consolidated Balance Sheets. At
December 31, 1994, the CSW System had bank lines of credit
aggregating $930 million 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.Benefit Plans
Defined Benefit Pension Plan
PSO, together with other members of the CSW System, maintains a
tax qualified, non-contributory defined benefit pension plan
covering substantially all employees. Benefits are based on
employees' years of credited 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 which are deductible for income tax purposes and
minimum contributions required by the ERISA. Pension plan assets
consist primarily of common stocks and short-term and intermediate-
term fixed income investments.
Contributions to the plan for the years ended December 31, 1994,
1993 and 1992 were $6.3 million, $6.7 million and $5.9 million,
respectively.
The approximate maximum number of participants in the plan during
1994, were 2,000 active employees, 1,100 retirees and
beneficiaries and 300 terminated employees.
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The components of net periodic pension cost and the assumptions
used in accounting for pensions follows:
1994 1993 1992
(thousands)
Net Periodic Pension Cost
Service cost $ 5,181 $ 4,642 $ 4,307
Interest cost on projected
benefit obligation 14,292 13,209 12,193
Actual return on plan assets (1,011) (16,051) (10,469)
Net amortization and deferral (16,064) 60 (4,748)
$ 2,398 $ 1,860 $ 1,283
Discount rate 8.25% 7.75% 8.50%
Long-term compensation increase 5.46% 5.46% 5.96%
Return on plan assets 9.50% 9.50% 9.50%
At December 31, 1994, the plan's net assets were approximately
equal to the total actuarial present value of the accumulated
benefit obligation. At December 31, 1993 the plan's net
assets exceeded the total actuarial present value of the
accumulated benefit obligation. No reconciliation of the funding
status of the plan is presented because such information is
unavailable.
Health and Welfare Plans
PSO had medical, dental, group life insurance, dependent life
insurance, and accidental death and dismemberment plans for
substantially all active PSO employees during 1994. The
contributions recorded on a pay-as-you-go basis, for the years
ended December 31, 1994 and 1993 were approximately $3.6 million
and $5.0 million, respectively. Effective January 1993, the PSO's
method of providing health benefits was modified to include such
benefits as a health maintenance organization, preferred provider
options, managed prescription drug and mail-order program and a
mental health and substance abuse program in addition to the self-
insured indemnity plans.
Postretirement Benefits Other Than Pensions
PSO adopted SFAS No. 106 January 1, 1993. PSO is amortizing their
transition obligation over twenty years, with eighteen years
remaining. In prior years, these benefits were accounted for on a
pay-as-you-go basis.
The components of net periodic postretirement benefit cost follow:
1994 1993
(thousands)
Net Periodic Postretirement Benefit Cost
Service cost $ 2,350 $ 2,175
Interest cost on APBO 5,317 4,811
Actual return on plan assets (495) (264)
Amortization of transition obligation 2,528 2,528
Net amortization and deferral (917) (564)
$ 8,783 $ 8,686
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A reconciliation of the funded status of the plan to the amounts
recognized on the consolidated balance sheets follow:
December 31,
1994 1993
APBO (thousands)
Retirees $ 42,233 $ 41,854
Other fully eligible participants 8,077 7,904
Other active participants 14,372 17,186
Total APBO 64,682 66,944
Plan assets at fair value (21,649) (15,066)
APBO in excess of plan 43,033 51,878
Unrecognized transition obligation (45,512) (48,040)
Unrecognized gain or (loss) 1,903 (4,414)
Accrued/(Prepaid) Cost $ (576) $ (576)
The following assumptions were used in accounting for SFAS No.
106:
1994 1993
Discount rate 8.25% 7.75%
Return on plan assets 9.50% 9.00%
Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions
Pre-65 Participants: 1994 Rate of 11.75% grading down .75% per
year to an ultimate rate of 6.5% in 2001.
Post-65 Participants: 1994 Rate of 11.25% 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, 1994 by $7 million and increase the aggregate of the
service and interest costs components on net postretirement
benefits by $1 million.
7.Jointly Owned Electric Plant
PSO has a joint ownership agreement with other members of the CSW
System and non-affiliated entities. Such agreements provide for
the joint ownership and operation of the 676 MW, coal-fired
Oklaunion Power Station and its related facilities. Each
participant provided financing for its share of the project, which
was placed in service in December 1986. The consolidated
statements of income reflect PSO's portion of operating costs
associated with plant in service. PSO's share is 106 MW or a
15.6% interest in the generating station. PSO's total investment,
including allowance for funds used during construction, is $80
million and accumulated depreciation at December 31, 1994 was $24
million.
8.Litigation and Regulatory Proceedings
Rate Review
In December 1993, the Oklahoma Commission issued an order
unanimously approving a joint stipulation between PSO, the
Oklahoma Commission Staff, and the Office of the Attorney General
of the State of Oklahoma, as recommended by the ALJ. The order
allowed PSO an increase in retail prices of $14.4 million on an
annual basis which represents a $4.3 million increase above those
authorized by the March 1993 interim order. In January 1994, the
Oklahoma Commission issued an order unanimously approving PSO's
price schedules reflecting the $14.4 million price increase. The
new prices became effective beginning with the billing month of
February 1994.
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The December 1993 order addresses, among other things, the
following issues. PSO will recover $4.5 million annually in
expenses associated with OPEBs, which, for PSO, are primarily
health care related benefits. Such expenses will be recovered
along with amortization of the deferred 1993 OPEBs at a rate of
$0.5 million per year for 10 years. PSO will amortize deferred
storm expenses associated with both a 1987 ice storm and a 1992
wind storm, amounting to $1.2 million per year for five years. In
addition, the order recognizes the increase in federal income tax
expenses resulting from the recent increase in the federal
corporate income tax rate from 34 percent to 35 percent. PSO will
continue to use the depreciation rates previously approved by the
Oklahoma Commission. PSO agreed that it will not file another
retail price increase application until after June 30, 1995.
Gas Transportation and Fuel Management Fees
An order issued by the Oklahoma Commission in 1991 required that
the level of gas transportation and fuel management fees, paid to
Transok by PSO, permitted for recovery through the fuel adjustment
clause be reviewed in the aforementioned price proceeding. This
portion of the price review was bifurcated. In March 1995, an
order was issued by the Oklahoma Commission approving an agreement
which allows PSO to recover approximately $28.4 million of
transportation and fuel management fees in base rates using 1991
determinants and approximately $1 million through the fuel
adjustment clause. The agreement also requires the phase-in of
competitive bidding of natural gas transportation requirements in
excess of 165 MMcf/d.
Gas Purchase Contracts
PSO has been named defendant in complaints filed in federal and
state courts of Oklahoma and Texas in 1984 through February 1995
by gas suppliers alleging claims arising out of certain gas
purchase contracts. Cases currently pending seek approximately
$29 million in actual damages, together with claims for punitive
damages which, in compliance with pleading code requirements, are
alleged to be in excess of $10,000. The plaintiffs seek relief
through the filing dates as well as attorney fees. As a result of
settlements among the parties, certain plaintiffs dismissed their
claims with prejudice to further action. The settlements did not
have a significant effect on PSO's consolidated results of
operations. The remaining suits are in the preliminary stages.
Management cannot predict the outcome of these proceedings.
However, management believes that PSO has defenses to these
complaints and intends to pursue them vigorously. Management also
believes that the ultimate resolution of the remaining complaints
will not have a material adverse effect on PSO's consolidated
results of operations or financial condition.
PCB Cases
PSO has been named defendant in complaints filed in federal and
state court in Oklahoma in 1984, 1985, 1986 and 1993. The
complaints allege, among other things, that some of the plaintiffs
and the property of other plaintiffs were contaminated with PCBs
and other toxic by-products following certain incidents, including
transformer malfunctions in April 1982, December 1983 and May
1984. To date, complaints represent approximately $736 million,
including compensatory and punitive damages of claims have been
dismissed, certain of which resulted from settlements among the
parties. The settlements did not have a significant effect on
PSO's consolidated results of operations. Remaining complaints
currently total approximately $395 million, of which approximately
one-third is for punitive damages. Discovery with regard to the
remaining complaints continues. Management cannot predict the
outcome of these proceedings. However, management believes that
PSO has defenses to these complaints and intends to pursue them
vigorously. Moreover, management has reason to believe that PSO's
insurance may cover some of the claims. Management also believes
that the ultimate resolution of the remaining complaints will not
have a material adverse effect on PSO's consolidated results of
operations or financial condition.
Burlington Northern Transportation Contract
In June 1992, PSO filed suit in Federal District Court in Tulsa,
Oklahoma, against Burlington Northern seeking declaratory relief
under a long-term contract for the transportation of coal. In
July 1992, Burlington Northern asserted counterclaims against PSO
alleging that PSO breached the contract. The counterclaims sought
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damages in an unspecified amount. In December 1993, PSO amended
its suit against Burlington Northern seeking damages and
declaratory relief under federal and state anti-trust laws. PSO
and Burlington Northern filed motions for summary judgment on
certain dispositive issues in the litigation. In March 1994, the
court issued an order granting PSO's motions for summary judgment
and denying Burlington Northern's motion. It was not necessary
for the court to decide the federal and state anti-trust claims
raised by PSO. Judgment was rendered in favor of PSO by the
United States District Court in May 1994. In June 1994,
Burlington Northern appealed this judgment to the United States
Court of Appeals for the Tenth Circuit. This appeal is now
pending.
Burlington Northern Arbitration
In May 1994, in a related arbitration, an arbitration panel made
an award favorable to PSO concerning basic transportation rates
under the coal transportation contract described above, and
concerning the contract mechanism for adjustment of future
transportation rates. These arbitrated issues were not involved
in the related lawsuit described above. Burlington Northern filed
an action to vacate the arbitrated award in the District Court for
Dallas County, Texas. PSO removed this action to the United
States District Court for the Northern District of Texas, and
filed a motion to either dismiss this action or have it
transferred to the United States District Court for the Northern
District of Oklahoma. Burlington Northern moved to remand the
action to state court. In September 1994, the United States
District Court for the Northern District of Texas denied
Burlington Northern's motion to remand, and granted PSO's motion
to transfer the action to the United States District Court for the
Northern District of Oklahoma. Separately, PSO filed an action to
confirm the arbitration award in the United States District Court
for the Northern District of Oklahoma, and Burlington Northern
filed a motion to dismiss this confirmation action. On December
6, 1994, the District Court entered an order denying Burlington
Northern's motion to vacate the arbitration award, and granting
PSO's motion to confirm the arbitration award. On December 29,
1994, the District Court entered judgment confirming the
arbitration award, including a money judgment in PSO's favor for
$16.4 million, with interest at 7.2% per annum compounded annually
from December 21, 1994 until paid. On January 6, 1995, Burlington
Northern appealed the District Court's judgment to the United
States Court of Appeals for the Tenth Circuit. This appeal is now
pending.
Coal Mine Reclamation
In August 1994, PSO received approval from the Wyoming Department
of Environmental Quality to begin reclamation of a coal mine in
Sheridan, Wyoming owned by Ash Creek Mining Company, a wholly-
owned subsidiary of PSO. Ash Creek Mining Company recorded a $3
million liability in 1993 for the estimated reclamation costs.
Actual reclamation work is expected to commence in mid-1995, with
completion estimated in late 1996. Surveillance monitoring will
continue for ten years after final reclamation. Management
believes the ultimate resolution of this matter will not have a
material adverse effect on PSO's consolidated results of
operations or financial condition.
Other
PSO 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 PSO's consolidated results of operations or financial
condition.
9. Commitments and Contingent Liabilities
It is estimated that PSO will spend approximately $71 million in
capital expenditures during 1995. Substantial commitments have
been made in connection with the 1995 construction program
To supply the fuel requirements of its generating plants, PSO has
entered into various commitments for the procurement of fuel.
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10. Quarterly Information (Unaudited)
The following unaudited quarterly information includes, in the
opinion of management, all adjustments necessary for a fair
presentation of such amounts.
Operating Operating Net
Quarter Ended Revenues Income Income
1994 (thousands)
March 31 $ 157,509 $ 12,427 $ 4,307
June 30 174,631 23,808 15,927
September 30 246,378 47,196 40,003
December 31 161,978 14,827 8,029
$ 740,496 $ 98,258 $ 68,266
1993
March 31 $ 145,110 $ 12,312 $ 10,113
June 30 161,237 23,935 15,605
September 30 242,871 46,221 38,641
December 31 158,318 (10,312) (17,640)
$ 707,536 $ 72,156 $ 46,719
Information for quarterly periods is affected by seasonal
variations in sales, rate changes, timing of fuel expense recovery
and other factors.
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Report of Independent Public Accountants
To the Stockholders and Board of Directors of Public Service Company
of Oklahoma:
We have audited the accompanying consolidated balance sheets
and consolidated statements of capitalization of Public Service
Company of Oklahoma (an Oklahoma corporation and a wholly-owned
subsidiary of Central and South West Corporation) and subsidiary
company, as of December 31, 1994 and 1993, and the related
consolidated statements of income, retained earnings and cash flows,
for each of the three years in the period ended December 31, 1994.
These financial statements are the responsibility of PSO'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
Public Service Company of Oklahoma and subsidiary company as of
December 31, 1994 and 1993, and the results of their operations and
their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting
principles.
In 1993, as discussed in NOTE 1, PSO 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
Schedule II 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. This schedule 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 LLP
Tulsa, Oklahoma
February 13, 1995
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Report of Management
Management is responsible for the preparation, integrity and
objectivity of the consolidated financial statements of Public
Service Company of Oklahoma and its subsidiary company as well as
other information contained in this Annual Report. The consolidated
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 Annual Report is consistent
with that in the consolidated financial statements.
The consolidated financial statements have been audited by the
independent accounting firm, Arthur Andersen LLP, which was given
unrestricted access to all financial records and related data,
including minutes of all meetings of shareholders, the board of
directors and committees of the board. PSO and its subsidiary
believe that representations made to the independent auditors during
their audit were valid and appropriate. Arthur Andersen LLP's audit
report is presented elsewhere in this report.
PSO, together with its subsidiary company, maintains a system of
internal controls to provide reasonable assurance that transactions
are executed in accordance with management's authorization, that the
consolidated financial statements are prepared in accordance with
generally accepted accounting principles and that the assets of the
companies are properly safeguarded against unauthorized acquisition,
use or disposition. The system includes a documented organizational
structure and division of responsibility, established policies and
procedures including a policy on ethical standards which provides
that PSO will maintain the highest legal and ethical standards, and
the careful selection, training and development of our employees.
Internal auditors continuously monitor the effectiveness of the
internal control system following standards established by the
Institute of Internal Auditors. Actions are taken by management to
respond to deficiencies as they are identified. The board, operating
through its audit committee, which is comprised entirely of directors
who are not officers or employees of PSO or its subsidiary, provides
oversight to the financial reporting process.
Due to the inherent limitations in the effectiveness of internal
controls, no internal control system can provide absolute assurance
that errors will not occur. However, management strives to maintain
a balance, recognizing that the cost of such a system should not
exceed the benefits derived.
PSO and its subsidiary believe that, in all material respects,
its system of internal controls over financial reporting and over
safeguarding of assets against unauthorized acquisition, use or
disposition functioned effectively during 1994.
Robert L. Zemanek R. Russell Davis
President and CEO - PSO Controller - PSO
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SWEPCO
SOUTHWESTERN ELECTRIC POWER COMPANY
Selected Financial Data
SWEPCO
The following selected financial data for each of the five years
ended December 31 are provided to highlight significant trends in the
financial condition and results of operations for SWEPCO.
1994 1993 1992 1991 1990
(thousands, except ratios)
Operating Revenues $825,296 $837,192 $778,303 $760,694 $735,217
Income Before Cumulative
Effect of Changes in
Accounting Principles 105,712 78,471 94,883 96,624 89,713
Cumulative Effect of
Changes in Accounting
Principles (1) -- 3,405 -- -- --
Net Income 105,712 81,876 94,883 96,624 89,713
Preferred Stock Dividends 3,361 3,362 3,445 3,465 3,528
Net Income for Common
Stock 102,351 78,514 91,438 93,159 86,185
Total Assets 2,079,207 1,968,285 1,927,320 1,851,108 1,869,340
Common Stock Equity 678,122 645,731 647,217 645,780 641,554
Preferred Stock
Not Subject to
Mandatory Redemption 16,032 16,032 16,032 16,033 14,358
Subject to
Mandatory Redemption 34,828 36,028 37,228 38,416 36,422
Long-term Debt 595,833 602,065 532,860 573,626 576,095
Ratio of Earnings to Fixed
Charges (SEC Method)
Before Cumulative
Effect of Changes
in Accounting
Principles 3.70 3.27 3.39 3.51 3.03
Capitalization Ratios
Common Stock Equity 51.2% 49.7% 52.5% 50.7% 50.6%
Preferred Stock 3.8 4.0 4.3 4.3 4.0
Long-term Debt 45.0 46.3 43.2 45.0 45.4
(1) The 1993 cumulative effect relates to the changes in accounting
for unbilled revenues and adoption of SFAS No. 112. See NOTE 1,
Summary of Significant Accounting Policies.
SWEPCO 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 reported for prior years and therefore have not
been restated.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
SOUTHWESTERN ELECTRIC POWER COMPANY
Reference is made to SWEPCO's Financial Statements and related
Notes and Selected Financial Data. 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 increased 30% during 1994 to
approximately $102.4 million from approximately $78.5 million in
1993, due primarily to the effects of restructuring costs recorded
during 1993.
Restructuring
As previously reported, SWEPCO has taken steps to implement a
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 restructuring is to enable
SWEPCO to focus on and be accountable for serving the customer. The
restructuring costs were initially estimated to be $25 million and
were expensed in 1993. The final costs of the restructuring were
approximately $20 million. Approximately $19 million of the
restructuring expenditures were incurred during 1994, with the
remaining $1 million expected to be incurred during 1995.
Approximately $1 million of the restructuring expenses relate to
employee termination benefits, $12 million relate to enhanced benefit
costs and $7 million relate to employees that will not be terminated.
Approximately $13 million of the restructuring costs were paid from
or will be paid from general corporate funds. The remaining $7
million represents the present value of enhanced benefit amounts to
be paid from the benefit plan trusts to participants over future
years in accordance with the early retirement program. The cost of
these enhanced benefit amounts will be paid from general corporate
funds to the benefit plan trusts over future years. The
restructuring is substantially completed, with the remaining activity
to take place during 1995. Certain aspects of the restructuring are
pending SEC approval under the Holding Company Act.
SWEPCO expects to realize a number of benefits from the
restructuring. Beginning in 1994 and continuing into the future,
increased efficiencies and synergies are expected to be realized with
the elimination of previously duplicated functions. This leads to
enhanced communication and efficiency, which should translate into a
reduction in the rate of growth in O&M costs. The CSW System expects
that all restructuring costs will be recovered by early 1996 with
reductions in the rate of growth of O&M costs continuing thereafter.
Rates and Regulatory Matters
See NOTE 9, Litigation and Regulatory Proceedings, for
information regarding the SWEPCO fuel reconciliation proceeding.
New Accounting Standards
SFAS No. 115 was effective for fiscal years beginning after
December 15, 1993. SWEPCO adopted SFAS No. 115 in 1994. The adoption
of SFAS No. 115 did not have a material effect on SWEPCO's results of
operations or financial condition.
In June 1993 the FASB issued SFAS No. 116. The statement,
effective for fiscal years beginning after December 15, 1994, will be
adopted by SWEPCO for 1995. The statement establishes accounting
standards for contributions and applies to all entities that receive
or make contributions. Management does not believe the adoption of
SFAS No. 116 will have a material impact on SWEPCO's results of
operations or financial condition.
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SFAS No. 119 was effective for fiscal years ending after December
15, 1994. SWEPCO does not currently use derivative financial
instruments, but may use these instruments in the future to manage the
increased market risks associated with greater competition in the
electric utility industry. The adoption of this new statement had no
material effect on SWEPCO's results of operations or financial
condition.
Liquidity and Capital Resources
Overview
SWEPCO's need for capital results primarily from its construction
of facilities to provide reliable electric service to its customers.
Accordingly, internally generated funds should meet most of the
capital requirements. However, if internally generated funds are not
sufficient, SWEPCO's financial condition should allow it access to the
capital markets.
Capital Expenditures
Construction expenditures, including AFUDC, were approximately
$153 million in 1994, $176 million in 1993 and $97 million in 1992.
Included in the expenditures for 1993 was approximately $35 million
for the acquisition of BREMCO, a rural electric cooperative with
service territory adjacent to SWEPCO's service territory in Louisiana.
Construction expenditures during the period 1995-1997 are estimated at
$286 million. These expenditures will consist primarily of expansion
and improvements to distribution facilities. No new baseload power
plants are currently planned until after the year 2000.
The construction program continues to be monitored, reviewed and
adjusted to reflect changes in estimated load growth in SWEPCO's
service area, variations in prices of alternative fuel sources, the
cost of labor, materials, equipment and capital, and other external
factors.
The CSW System facilities plan presently includes projected coal-
and lignite-fired generating plants for which SWEPCO has invested
approximately $34 million in prior years for plant sites, engineering
studies and lignite reserves. Should future plans exclude these
plants for environmental or other reasons, SWEPCO would evaluate the
probability of recovery of these investments and may record
appropriate reserves.
Long-Term Financing
As of December 31, 1994, the capitalization ratios of SWEPCO were
51% common stock equity, 4% preferred stock and 45% long-term debt.
SWEPCO's embedded cost of long-term debt was 7.6% at the end of 1994.
SWEPCO continually monitors the capital markets for opportunities to
lower its cost of capital through refinancing. SWEPCO continues to be
committed to maintaining financial flexibility by maintaining a strong
capital structure and favorable securities rating which should allow
funds to be obtained from the capital markets when required.
SWEPCO's long-term financing activity for 1994 is summarized
below:
In June 1994, SWEPCO renegotiated a $50 million term loan due
June 1997, changing certain terms, including an extension of the
maturity to June 2000.
In several transactions during 1994, SWEPCO redeemed $5.8
million, which represented all remaining bonds outstanding of its 9-
1/8% First Mortgage Bonds, Series U, due November 1, 2019. The funds
required for these transactions were provided from short-term
borrowings and internal sources. Redemption premiums are included in
long-term debt on the balance sheets and are being amortized over 5 to
30 years, in accordance with anticipated regulatory treatment.
Short-Term Financing
SWEPCO, together with other members of 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.
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SWEPCO's short-term borrowing limit from the money pool is $150
million. During 1994, the annual weighted average interest rate was
4.5% and the average amount of short-term borrowings outstanding at
month-end was $25 million. The maximum amount of short-term
borrowings outstanding at any month-end during 1994 was $82 million,
which was the amount outstanding at December 31, 1994.
Internally Generated Funds
Internally generated funds consist of cash flows from operating
activities less common and preferred stock dividends. SWEPCO utilizes
short-term debt to meet fluctuations in working capital requirements
due to the seasonal nature of energy sales. SWEPCO anticipates that
capital requirements for the period 1995 to 1997 will be met, in large
part, from internal sources. SWEPCO also anticipates that some
external financing will be required during the period, however the
nature, timing and extent have not yet been determined. Information
concerning internally generated funds follows:
1994 1993 1992
(millions)
Internally Generated Funds $105 $149 $75
Construction Expenditures Provided
by Internally Generated Funds 71% 85% 78%
Sales of Accounts Receivable
SWEPCO sells its billed and unbilled accounts receivable, without
recourse, to CSW Credit. The sales provide SWEPCO with cash
immediately, thereby reducing working capital needs and revenue
requirements. The average and year end amounts of accounts receivable
sold were $69 million and $62 million in 1994, as compared to $64
million and $57 million in 1993.
Recent Developments and Trends
Competition and Industry Challenges
Competitive forces at work in the electric utility industry are
impacting SWEPCO and electric utilities generally. Increased
competition facing electric utilities is driven by complex economic,
political and technological factors. These factors have resulted in
legislative and regulatory initiatives that are likely to result in
even greater competition at both the wholesale and retail level in the
future. As competition in the industry increases, SWEPCO will have
the opportunity to seek new customers and at the same time be at risk
of losing customers to other competitors. SWEPCO believes that its
prices for electricity and the quality and reliability of its service
currently place it in a position to compete effectively in the
marketplace.
The Energy Policy Act, which was enacted in 1992, significantly
alters the way in which electric utilities compete. The Energy Policy
Act creates exemptions from regulation under the Holding Company Act
and permits utilities, including registered utility holding companies
and non-utility companies, to form EWGs. EWGs are a new category of
non-utility wholesale power producer that are 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. The Energy Policy Act also 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. A FERC order requiring a transmitting utility
to provide wholesale transmission service must include provisions
generally that permit (i) the utility to recover from the FERC
applicant all of the costs incurred in connection with the
transmission services and (ii) any enlargement of the transmission
system and associated services. While SWEPCO believes that the Energy
Policy Act will continue to make the wholesale markets more
competitive, SWEPCO is unable to predict the extent to which the
Energy Policy Act will impact its operations.
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Increasing competition in the utility industry brings an
increased need to stabilize or reduce rates. The retail regulatory
environment is beginning to shift from traditional rate base
regulation to incentive regulation. Incentive rate and performance-
based plans encourage efficiencies and increased productivity while
permitting utilities to share in the results. Retail wheeling, a
major industry issue which may require utilities to "wheel" or move
power from third parties to their own retail customer, is evolving
gradually.
Wholesale energy markets, including the market for wholesale
electric power, have been extremely competitive since the enactment of
the Energy Policy Act. SWEPCO competes in the wholesale energy
markets with other public utilities, cogenerators, qualified
facilities, exempt wholesale generators and others for sales of
electric power.
Under the Energy Policy Act, the FERC has approved several
proposals by utility companies to sell wholesale power at market-based
rates and provide to electric utilities "open access" to transmission
systems, subject to certain requirements. The adoption of these
proposals increases marketing opportunities for electric utilities,
but also exposes them to the risk of loss of load or reduced revenues
due to competition with alternative suppliers.
SWEPCO believes that, compared to other electric utilities, it is
well positioned to meet future competition. SWEPCO benefits from
economies of scale and scope by virtue of its size and its
relationship to the CSW System. SWEPCO is also a relatively low-cost
producer of electric power. Moreover, SWEPCO is taking steps to
enhance its marketing and customer service, reduce costs, improve and
standardize business practices, and grow through strategic
acquisitions, in order to position itself for increased competition in
the future.
SWEPCO is unable to predict the ultimate outcome or impact of
competitive forces on the electric utility industry or on SWEPCO. As
the wholesale and retail electricity markets become more competitive,
however, the principal factor determining success is likely to be
price, and to a lesser extent, reliability, availability of capacity,
and customer service.
Public Utility Regulatory Act
PURA is the legal foundation for electric utility regulation in
Texas. PURA will expire on September 1, 1995, in accordance with the
sunset policy of the Texas Legislature, which applies to all state
agencies, unless the Texas Legislature reenacts PURA in its current
form or in modified form. Several proposals have been made to amend
PURA which, among other things, provide for a market-driven integrated
resource planning process, pricing flexibility for utilities faced
with competitive challenges, incentive regulation and deregulation of
the wholesale bulk power market in ERCOT. SWEPCO is unable to predict
the ultimate outcome of the 1995 session of the Texas Legislature and
in particular whether amendments to PURA will be adopted.
Regulatory Accounting
Consistent with industry practice and the provisions of SFAS No.
71, which allows for the recognition and recovery of regulatory
assets, SWEPCO has recognized regulatory assets and liabilities.
Management believes that SWEPCO will continue to meet the criteria for
following SFAS No. 71. However, in the event the SWEPCO no longer
meets the criteria for following SFAS No. 71, a write-off of
regulatory assets and liabilities would be required. For additional
information regarding SFAS No. 71 reference is made to NOTE 1,
Summary of Significant Accounting Policies - Regulatory Assets and
Liabilities.
Consolidated Taxes
The Texas Commission before 1992 allowed income taxes to be
recovered in rates based on the federal income tax incurred by a
utility as if it were a stand-alone company. This stand-alone
approach treated the regulated activities of a utility as a separate
entity and considered only those revenues and expenses that are
included in the utility's cost of service to calculate the federal
income tax liability for ratemaking purposes.
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Beginning in 1992, the Texas Commission changed its method of
calculating the federal income tax component of rates to the "actual
tax approach." The actual tax approach is an evolving concept but
generally seeks to reflect in rates the actual tax liability of the
utility irrespective of its relationship to the utility's cost of
service. The approach reduces rates by the tax benefits of deductions
which are not considered for or included in setting rates for the
utility.
SWEPCO believes that the recovery of federal income taxes in
rates should be determined on the stand-alone approach for ratemaking
purposes, but there is no assurance this approach will be adopted.
Environmental Matters
CERCLA and Related Matters
The operations of SWEPCO, like those of other utilities,
generally involve the use and disposal of substances subject to
environmental laws. The 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. PRPs include owners and
operators of contaminated sites and transporters and/or generators of
hazardous substances. 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.
SWEPCO is subject to various pending claims alleging that it is a
PRP under federal or state remedial laws for investigating and
cleaning up contaminated property. SWEPCO anticipates that resolution
of these claims, individually or in the aggregate, will not have a
material adverse effect on SWEPCO's results of operations or financial
condition. Although the reasons for this expectation differ from site
to site, factors that are the basis for the expectation for specific
sites include the volume and/or type of waste allegedly contributed by
SWEPCO, the estimated amount of costs allocated to SWEPCO and the
participation of other parties.
MGPs
Contaminated former MGPs are a type of site which utilities, and
others, may have to remediate in the future under Superfund or other
federal or state remedial programs. Gas was manufactured at MGPs from
the mid-1800s to the mid-1900s. In some cases, utilities and others
have faced potential liability for MGPs because they, or their alleged
predecessors, owned or operated the plants. In other cases, utilities
or others may have been subjected to such liability for MGPs because
they acquired MGP sites after gas production ceased.
Suspected MGP Site in Marshall, Texas
SWEPCO owns a suspected former MGP site in Marshall, Texas.
SWEPCO has notified the TNRCC that evidence of contamination has been
found at the site. As a result of sampling conducted at the end of
1993 and early 1994, SWEPCO is evaluating the extent, if any, to which
contamination has impacted soil, groundwater and other conditions in
the area. A final range of clean-up costs has not yet been
determined, but, based on a preliminary estimate, SWEPCO has accrued
approximately $2 million as a liability for this site on SWEPCO's
books as of December 31, 1993. As more information is obtained about
the site, and SWEPCO discusses the site with the TNRCC, the
preliminary estimate may change.
Suspected MGP Site in Texarkana, Texas and Arkansas and Shreveport,
Louisiana
SWEPCO also owns a suspected former MGP site in Texarkana, Texas
and Arkansas. The EPA ordered an initial investigation of this site,
as well as one in Shreveport, Louisiana, which is no longer owned by
SWEPCO. The contractor who performed the investigations of these two
sites recommended to the EPA that no further action be taken at this
time.
Suspected Biloxi, Mississippi MGP Site
SWEPCO has been notified by Mississippi Power Company that it may
be a PRP at the former Biloxi MGP site formerly owned and operated by
a predecessor of SWEPCO. SWEPCO is working with Mississippi Power
2-138
Company to investigate the extent of contamination at this site. The
MDEQ approved a site investigation work plan and, in January 1995,
SWEPCO and Mississippi Power Company initiated sampling pursuant to
that work plan. On an interim basis, SWEPCO and Mississippi Power
Company are each paying fifty percent of the cost of implementing the
site investigation work plan. That interim allocation is subject to a
final allocation in the future. SWEPCO and Mississippi Power Company
are investigating whether there are other PRPs at the Biloxi site.
Until the extent of the contamination at the Biloxi site is
identified, it is unknown what, if any, additional investigation or
cleanup may be required.
Management does not expect these matters to have a material
effect on SWEPCO's results of operations or financial position.
Clean Air Act Amendments
In November 1990, the United States Congress passed the Clean
Air Act which places restrictions on the emission of sulfur dioxide
from gas-, coal- and lignite-fired generating plants. Beginning in
the year 2000, SWEPCO will be required to hold allowances in order to
emit sulfur dioxide. EPA issues allowances to owners of existing
generating units based on historical operating conditions. Based on
the CSW System facilities plan, SWEPCO believes that its allowances
will be adequate to meet its needs at least through 2008. Public and
private markets are developing for trading of excess allowances.
SWEPCO presently has no intention of engaging in trading of
allowances, but may seek to do so in the future if market conditions
warrant and appropriate regulatory approvals are obtained.
The Clean Air Act also establishes a federal operating source
permit program to be administered by the states.
The Clean Air Act also directs the EPA to issue regulations
governing nitrogen oxide emissions and requires government studies to
determine what controls, if any, should be imposed on utilities to
control air toxics emissions. The impact that the nitrogen oxide
emission regulations and the air toxics study will have on SWEPCO
cannot be determined at this time.
As a result of requirements imposed by the Clean Air Act, SWEPCO
expects to spend an additional $1.3 million for annual testing of,
software modifications to, and maintenance of continuous emission
monitoring equipment from 1995 through 1997.
EMFs
Research is ongoing whether exposure to EMFs may result in
adverse health effects. Although a few of the studies to date have
suggested certain associations between EMFs and some types of effects,
the research to date has not established a cause-and-effect
relationship between EMFs and adverse health effects. SWEPCO cannot
predict the impact on SWEPCO 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.
See ITEM 1. BUSINESS - ENVIRONMENTAL MATTERS and NOTE 10,
Commitments and Contingent Liabilities, for additional discussion of
environmental issues.
Results of Operations
Electric Operating Revenues
Total electric operating revenues decreased $11.9 million or 1%
during 1994 due primarily to decreased fuel revenues partially offset
by a 3% increase in retail KWH sales due to customer growth and a 15%
increase in sales for resale. Sales for resale to non-affiliated
electric utilities and rural electric cooperatives increased
approximately $9.4 million during the year. Total revenues increased
approximately $59 million in 1993 when compared to the prior year.
The increase was due primarily to a 6% increase in KWH sales
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resulting from favorable weather and customer growth due to the
acquisition of BREMCO in 1993 as well as increased sales for resale.
Fuel and Purchased Power Expenses
Fuel expense decreased approximately $27.2 million or 7% during
1994 and increased approximately $28 million or 8% during 1993. The
decrease in 1994 is due primarily to a decrease in unit fuel costs
from $1.94 in 1993 to $1.75 in 1994. The decrease in unit fuel costs
is primarily due to coal contract settlements and a decrease in the
cost of spot market gas. This decrease was partially offset by a 4%
increase in generation. The increase in 1993 is attributable to an
8% increase in generation and an increase in unit fuel costs from
$1.93 in 1992 to $1.94 in 1993.
Purchased power costs increased approximately $7.1 million in
1994 and $6.5 million in 1993. The 1994 increase was due primarily
to a purchased power contract negotiated as a part of the 1993
purchase of BREMCO. The increase in 1993 was largely due to scheduled
and unscheduled maintenance at the Company's generating facilities
and the above-mentioned purchased power contract.
Operating Expenses and Taxes
Other operating expenses increased approximately $18.1 million
in 1993 due primarily to expensing of reserves for certain lignite
properties, outside and legal services, and an increase in employee
benefit expenses in 1993 resulting form the adoption of SFAS No. 106.
Restructuring charges reflect the initial estimated cost of the
restructuring of $25.2 million. As the restructuring progressed,
this amount was adjusted during 1994 to approximately $20 million.
Maintenance expense decreased approximately $7.4 million in 1994
and increased approximately $8 million in 1993 when compared to 1992.
The changes during both periods are due to increased maintenance of
distribution facilities and general plant in 1993.
Taxes, other than federal income, increased approximately $4.4
million or 10% in 1993 due primarily to a Texas franchise tax refund
recognized in 1992.
Federal income tax expense increased approximately $13.1 million
or 48% in 1994 primarily as a result of increased pre-tax income. In
1993, federal income taxes decreased approximately $5.8 million or
18% as a result of lower pre-tax income partially offset by an
increase in the federal income tax rate from 34% to 35%.
Inflation
Annual inflation rates, as measured by the national Consumer
Price Index, have averaged approximately 2.7% for the three-year
period ending December 31, 1994. Inflation at these levels does not
materially affect SWEPCO's results of operations or financial
condition. Under existing regulatory practice, however, 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.
Allowance for Equity and Debt Funds Used During Construction
AFUDC is a function of the amounts of construction on which
AFUDC is calculated and the rate used. The increases in 1994 and
1993 were due primarily to increased construction work in process.
Interest on Long-Term Debt
Interest expense on long-term debt increased in 1994
approximately $2.4 million or 6% due primarily to an increase in
average balances outstanding. The 1993 decrease of approximately $6.5
million is attributable to the refinancing of higher cost debt with
lower cost debt.
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Interest on Short-Term Debt and Other
Interest expense on short-term debt and other increased
approximately $2.7 million in 1994 when compared to 1993 due
primarily to an interest accrual pursuant to the terms of a
settlement agreement approved by the Texas Commission in connection
with SWEPCO's fuel reconciliation and increased interest expense
associated with short-term debt.
Cumulative Effect of Changes in Accounting Principles
Accounting changes in 1993 include the adoption of SFAS 112.
SWEPCO also changed its method of accounting for unbilled revenues.
These accounting changes had a cumulative effect of increasing net
income by $3.4 million.
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Statements of Income
Southwestern Electric Power Company
For the Years Ended December 31,
1994 1993 1992
(thousands)
Electric Operating Revenues
Residential $266,620 $273,707 $249,182
Commercial 173,718 175,059 165,836
Industrial 243,518 250,912 243,508
Sales for resale 102,723 93,337 78,814
Other 38,717 44,177 40,963
825,296 837,192 778,303
Operating Expenses and Taxes
Fuel 336,389 363,627 335,594
Purchased power 20,244 13,145 6,620
Other operating 119,277 118,665 100,598
Restructuring charges (4,978) 25,203 --
Maintenance 42,782 50,164 42,191
Depreciation and amortization 79,845 74,385 72,300
Taxes, other than federal
income 45,735 46,942 42,502
Federal income taxes 40,080 27,004 32,771
679,374 719,135 632,576
Operating Income 145,922 118,057 145,727
Other Income and Deductions
Allowance for equity funds
used during construction 3,579 1,560 132
Other 4,656 3,658 537
8,235 5,218 669
Income Before Interest Charges 154,157 123,275 146,396
Interest Charges
Interest on long-term debt 43,395 40,958 47,490
Interest on short-term debt
and other 7,568 4,866 4,073
Allowance for borrowed funds
used during construction (2,518) (1,020) (50)
48,445 44,804 51,513
Income Before Cumulative Effect
of Changes in Accounting
Principles 105,712 78,471 94,883
Cumulative Effect of Changes
in Accounting Principles -- 3,405 --
Net Income 105,712 81,876 94,883
Preferred stock dividends 3,361 3,362 3,445
Net Income for Common Stock $ 102,351 $ 78,514 $ 91,438
The accompanying notes to financial statements are an integral part of
these statements.
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Statements of Retained Earnings
Southwestern Electric Power Company
For the Years Ended December 31,
1994 1993 1992
(thousands)
Retained Earnings at Beginning of Year $265,071 $266,557 $265,120
Net income for common stock 102,351 78,514 91,438
Gain on reacquisition of preferred stock 40 -- --
Deduct: Common stock dividends 70,000 80,000 90,000
Preferred stock redemption cost -- -- 1
Retained Earnings at End of Year $297,462 $265,071 $266,557
The accompanying notes to financial statements are an integral part of
these statements.
2-143
Balance Sheets
Southwestern Electric Power Company
As of December 31,
1994 1993
(thousands)
ASSETS
Electric Utility Plant
Production $1,401,418 $1,392,058
Transmission 385,113 350,625
Distribution 733,707 678,788
General 213,563 188,193
Construction work in progress 149,508 126,258
2,883,309 2,735,922
Less - Accumulated depreciation 1,026,751 947,792
1,856,558 1,788,130
Current Assets
Cash and temporary cash investments 1,296 6,723
Accounts receivable 54,344 24,363
Materials and supplies, at average cost 28,109 25,218
Fuel inventory, at average cost 61,701 49,487
Accumulated deferred income taxes 6,592 3,912
Prepayments and other 13,071 14,965
165,113 124,668
Deferred Charges and Other Assets 57,536 55,487
$2,079,207 $1,968,285
The accompanying notes to financial statements are an integral part of
these statements.
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Balance Sheets
Southwestern Electric Power Company
As of December 31,
1994 1993
(thousands)
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock: $18 par value
Authorized: 7,600,000 shares
Issued and Outstanding: 7,536,640
shares $ 135,660 $ 135,660
Paid-in capital 245,000 245,000
Retained earnings 297,462 265,071
Total Common Stock Equity 678,122 645,731
Preferred stock
Not subject to mandatory redemption 16,032 16,032
Subject to mandatory redemption 34,828 36,028
Long-term debt 595,833 602,065
Total Capitalization 1,324,815 1,299,856
Current Liabilities
Long-term debt and preferred stock due
within twelve months 5,270 5,028
Advances from affiliates 81,868 27,864
Accounts payable 50,138 41,598
Fuel refunds due customers 12,200 2,358
Customer deposits 13,075 14,244
Accrued restructuring charges 1,110 25,203
Accrued taxes 12,495 27,340
Accrued interest 17,175 17,354
Other 29,505 30,499
222,836 191,488
Deferred Credits
Income taxes 365,441 332,522
Investment tax credits 81,023 85,301
Income tax related regulatory
liabilities, net 44,836 52,828
Other 40,256 6,290
531,556 476,941
$2,079,207 $1,968,285
The accompanying notes to financial statements are an integral part of
these statements.
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Statements of Cash Flows
Southwestern Electric Power Company
For the Years Ended December 31,
1994 1993 1992
(thousands)
OPERATING ACTIVITIES
Net Income $105,712 $ 81,876 $ 94,883
Non-cash Items Included in Net Income
Depreciation and amortization 89,646 93,120 79,051
Restructuring charges (4,978) 25,203 --
Deferred income taxes and
investment tax credits 17,970 (4,775) 3,393
Cumulative effect of changes in
accounting principles -- (3,405) --
Allowance for equity funds used
during construction (3,579) (1,560) (132)
Changes in Assets and Liabilities
Accounts receivable (29,981) (3,632) (8,067)
Fuel inventory (12,214) 21,101 12,722
Accounts payable 8,540 8,612 5,313
Accrued taxes (14,845) 11,561 (5,817)
Accrued restructuring charges (11,694) -- --
Unrecovered fuel/Fuel refund
due customers 9,842 1,946 1,274
Other deferred credits 33,966 (9,468) (1,875)
Other (10,264) 11,519 (11,892)
178,121 232,098 168,853
INVESTING ACTIVITIES
Construction expenditures (146,865) (138,510) (96,676)
Acquisition expenditures -- (35,333) --
Allowance for borrowed funds used
during construction (2,518) (1,020) (50)
Sale of electric utility plant and other (4,980) (4,113) (2,339)
(154,363) (178,976) (99,065)
FINANCING ACTIVITIES
Proceeds from sale of long-term debt -- 221,511 221,067
Reacquisition of long-term debt (5,475) (198,962) (176,474)
Redemption of preferred stock (1,160) -- (1,190)
Retirement of long-term debt (3,213) (39,835) (3,488)
Change in advances from affiliates 54,004 (286) 28,149
Special deposits for reacquisition
of long-term debt -- 53,500 (53,500)
Payment of dividends (73,341) (83,386) (93,443)
(29,185) (47,458) (78,879)
Net Change in Cash and Cash Equivalents (5,427) 5,664 (9,091)
Cash and Cash Equivalents at Beginning of
Year 6,723 1,059 10,150
Cash and Cash Equivalents at End of Year $ 1,296 $ 6,723 $ 1,059
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized $ 45,260 $ 42,271 $ 53,129
Income taxes paid $ 36,632 $ 21,112 $ 37,181
The accompanying notes to financial statements are an integral part of
these statements.
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Statements of Capitalization
Southwestern Electric Power Company
As of December 31,
1994 1993
(thousands)
COMMON STOCK EQUITY $ 678,122 $ 645,731
PREFERRED STOCK
Cumulative $100 Par Value, Authorized
1,860,000 shares
Number Current
of Shares Redemption
Series Outstanding Price
Not Subject to Mandatory Redemption
5.00% 75,000 $109.00 7,500 7,500
4.65% 25,000 102.75 2,500 2,500
4.28% 60,000 103.90 6,000 6,000
Premium 32 32
16,032 16,032
Subject to Mandatory Redemption
6.95% 352,000 104.64 36,400 37,600
Issuance Expense (372) (372)
Amount to be redeemed within one year (1,200) (1,200)
34,828 36,028
LONG-TERM DEBT
First Mortgage Bonds
Series U, 9 1/8%, due November 1, 2019 -- 5,830
Series V, 7 3/4%, due June 1, 2004 40,000 40,000
Series W, 6 1/8%, due September 1, 1999 40,000 40,000
Series X, 7%, due September 1, 2007 90,000 90,000
Series Y, 6 5/8%, due February 1, 2003 55,000 55,000
Series Z, 7 1/4%, due July 1, 2023 45,000 45,000
Series AA, 5 1/4%, due April 1, 2000 45,000 45,000
Series BB, 6 7/8%, due October 1, 2025 80,000 80,000
1976 Series A, 6.20%, due November 1, 2006 * 6,665 6,810
1976 Series B, 6.20%, due November 1, 2006 * 1,000 1,000
Installment Sales Agreements - PCRBs
1978 Series A, 6%, due January 1, 2008 14,420 14,420
Series 1986, 8.2%, due July 1, 2014 81,700 81,700
1991 Series A, 8.2%, due August 1, 2011 17,125 17,125
1991 Series B, 6.9%, due November 1, 2004 12,290 12,290
Series 1992, 7.6%, due January 1, 2019 53,500 53,500
Bank Loan, Variable Rate, due June 15, 2000 50,000 50,000
Railcar lease obligations 17,922 20,635
Unamortized discount and premium (3,745) (4,034)
Unamortized costs of reacquired debt (45,974) (48,383)
Amount to be redeemed within one year (4,070) (3,828)
595,833 602,065
TOTAL CAPITALIZATION $1,324,815 $1,299,856
*Obligations incurred in connection with the sale by public
authorities of tax-exempt PCRBs.
The accompanying notes to financial statements are an integral part of
these statements.
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NOTES TO FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies
Public Utility Regulation
SWEPCO is subject to regulation by the SEC under the Holding
Company Act and the FERC under the Federal Power Act, and follows
the Uniform System of Accounts prescribed by the FERC. SWEPCO is
subject to further regulation with regard to rates and other
matters by state regulatory commissions including the Arkansas
Commission, Louisiana Commission and the Texas Commission.
SWEPCO, as a member of the CSW System, engages in transactions and
coordinates its activities and operations with other members of
the CSW System.
The more significant accounting policies of SWEPCO 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 electric utility plant are computed
using the straight-line method, generally at individual rates
applied to the various classes of depreciable property. The
annual average consolidated composite rates were 3.2% in 1994,
1993 and 1992.
Electric Revenues and Fuel
Prior to January 1, 1993, electric revenues 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 operating revenues of
the next month. To conform to general industry standards, SWEPCO
changed its method of accounting to accrue for estimated unbilled
revenues. The effect of this change on 1993 income was an
increase of $5.4 million included in cumulative effect of changes
in accounting principles.
SWEPCO recovers fuel costs in Texas as a fixed component of base
rates whereby over-recoveries of fuel are payable to customers and
under-recoveries may be billed to customers after Texas Commission
approval. The cost of fuel is charged to expense as consumed.
SWEPCO recovers fuel costs in Arkansas and Louisiana through
automatic fuel recovery mechanisms. The application of these
mechanisms varies by jurisdiction.
SWEPCO recovers fuel costs applicable to wholesale customers,
which are regulated by the FERC, through an automatic fuel
adjustment clause.
Accounts Receivable
SWEPCO sells its billed and unbilled accounts receivable, without
recourse, to CSW Credit.
Regulatory Assets and Liabilities
For its regulated activities, SWEPCO follows SFAS No. 71, which
defines the criteria for establishing regulatory assets and
regulatory liabilities. Regulatory assets represent probable
future revenue to the company associated with certain costs which
will be recovered from customers through the ratemaking process.
Regulatory liabilities represent probable future refunds to
customers. At December 31, 1994 and 1993, SWEPCO had recorded the
following significant regulatory assets and liabilities:
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1994 1993
(thousands)
Regulatory Assets
(Included in Deferred Charges and
Other Assets on the
Balance Sheets)
SFAS No. 106 Costs $ 1,949 $ 993
Regulatory Liabilities
Fuel refund due customers $12,200 $ 2,358
Income tax related
regulatory liabilities, net $44,836 $52,828
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 are considered cash
equivalents.
Reclassification
Certain financial statement items for prior years have been
reclassified to conform to the 1994 presentation.
Accounting Changes
Effective January 1, 1993, SWEPCO adopted SFAS Nos. 106, 112 and
109. See NOTE 2, Federal Income Taxes, for further information
regarding SFAS No. 109. In addition, SWEPCO also changed its
method of accounting for unbilled revenues. See Electric Revenues
and Fuel above for further information.
The adoption of SFAS No. 106 resulted in an increase in 1993
operating expenses of $3 million. The adoption of SFAS No. 112
and the change in accounting for unbilled revenues are presented
as a cumulative effect of changes in accounting principles as
shown below:
Pre-Tax Tax Net Income
Effect Effect Effect
SFAS No. 112 $(3,047) $ 1,066 $(1,981)
Unbilled revenues 8,286 (2,900) 5,386
Total $ 5,239 $(1,834) $ 3,405
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
SWEPCO adopted the provisions of SFAS No. 109 effective January 1,
1993. The implementation of SFAS No. 109 had no material effect on
SWEPCO's earnings. As a result of this change, SWEPCO recognized
additional accumulated deferred income taxes and corresponding
regulatory assets and liabilities to ratepayers in amounts equal
to future revenues or the reduction in future revenues required
when the income tax temporary differences reverse and are
recovered or settled in rates. As a result of a favorable
earnings history, SWEPCO did not record any valuation allowance
against deferred tax assets at December 31, 1994 and 1993.
SWEPCO, together with other members of the CSW System, files a
consolidated federal income tax return and participates in a tax
sharing agreement.
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Components of income taxes follow:
1994 1993 1992
Included in Operating Expenses and Taxes (thousands)
Current $22,110 $31,779 $29,377
Deferred 22,248 418 10,258
Deferred ITC (4,278) (5,193) (6,864)
40,080 27,004 32,771
Included in Other Income and Deductions
Current (3,732) (1,916) 278
Deferred -- -- --
(3,732) (1,916) 278
Tax Effects of Cumulative Effect of Changes
in Accounting Principles -- 1,834 --
$36,348 $26,922 $33,049
Investment tax credits deferred in prior years are included in
income over the lives of the related properties.
Total income taxes differ from the amounts computed by applying
the statutory income tax rates to income before taxes. The
reasons for the differences follow:
1994 % 1993 % 1992 %
(dollars in thousands)
Tax at statutory rates $49,721 35.0 $38,079 35.0 $43,497 34.0
Differences
Amortization of ITC (4,277) (3.0) (5,193) (4.8) (5,384) (4.2)
Prior period adjustments (2,718) (1.9) -- -- (3,218) (2.5)
Consolidated savings (2,476) (1.7) (2,575) (2.4) -- --
Other (3,902) (2.8) (3,389) (3.1) (1,846) (1.6)
$36,348 25.6 $26,922 24.7 $33,049 25.7
The significant components of the net deferred income tax
liability follow:
1994 1993
(thousands)
Deferred Income Tax Liabilities
Depreciable utility plant $ 389,016 $ 352,629
Income tax related regulatory assets 33,847 33,028
Other 41,150 39,405
Total Deferred Income Tax Liabilities $ 464,013 $ 425,062
Deferred Income Tax Assets
Income tax related regulatory liability (50,162) (52,250)
Unamortized ITC (29,482) (31,039)
Other (25,520) (13,163)
Total Deferred Income Tax Assets (105,164) (96,452)
Net Accumulated Deferred Income Taxes - Total $ 358,849 $ 328,610
Net Accumulated Deferred Income Taxes - Noncurrent $ 365,441 $ 332,522
Net Accumulated Deferred Income Taxes - Current (6,592) (3,912)
Net Accumulated Deferred Income Taxes - Total $ 358,849 $ 328,610
2-150
3.Long-Term Debt
The mortgage indenture, as amended and supplemented, securing
first mortgage bonds issued by SWEPCO, constitutes a direct first
mortgage lien on substantially all electric utility plant. SWEPCO
may offer additional first mortgage bonds subject to market
conditions and other factors.
Annual Requirements
Certain series of outstanding first mortgage bonds have annual
sinking fund requirements, which are generally 1% of the amount of
each such series issued. These requirements may be, and generally
have been, satisfied by the application of net expenditures for
bondable property in an amount equal to 166-2/3% of the annual
requirements. At December 31, 1994, the annual sinking fund
requirements and annual maturities for the next five years follow:
Sinking Fund
Requirements Maturities
(thousands)
1995 $ 145 $ 4,100
1996 145 3,900
1997 145 2,600
1998 145 2,400
1999 595 44,000
Dividends
SWEPCO's mortgage indenture, as amended and supplemented, contains
certain restrictions on the payment of common dividends. At
December 31, 1994, all of SWEPCO's retained earnings were
available for the payment of cash dividends to its parent, CSW.
Reacquired Long-term Debt
Reference is made to MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and
Capital Resources - Long-term Financing, for further information
related to long-term debt, including new issues and
reacquisitions.
4.Preferred Stock
SWEPCO's 6.95% Series, $100 par value preferred stock required a
mandatory sinking fund sufficient to retire 12,000 shares
annually.
The outstanding preferred stock not subject to mandatory
redemption is redeemable at the option of SWEPCO upon 30 days
notice at the current redemption price per share.
5.Financial Instruments
The following methods and assumptions were used to estimate the
fair value of each class of financial instruments for which it is
practicable to estimate fair value.
Cash and temporary cash investments
The carrying amount approximates fair value because of the short
maturity of those instruments.
Advances from affiliates
The carrying amount approximates fair value because of the short
maturity of those instruments.
Long-term debt
The fair value of the SWEPCO'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 SWEPCO for debt of the same remaining
maturities.
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Current maturities of long-term debt and preferred stock due
within 12 months
The fair values of the SWEPCO's current maturities of long-term
debt and preferred stock due within 12 months are estimated based
on quoted market prices for the same or similar issues or on the
current rates offered to SWEPCO for long-term debt or preferred
stock with the same or similar remaining redemption provisions.
Preferred stock
The fair value of SWEPCO's preferred stock is estimated based on
quoted market prices for the same or similar issues or on the
current rates offered to SWEPCO for preferred stock with the same
or similar remaining redemption provisions.
The estimated fair values of SWEPCO's financial instruments
follow:
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(thousands)
Cash and temporary cash investments $ 1,296 $ 1,296 $ 6,723 $ 6,723
Long-term debt and preferred stock
due within 12 months 5,270 5,171 -- --
Advances from affiliates 81,868 81,868 32,892 32,892
Long-term debt 595,833 555,659 602,065 631,150
Preferred stock subject to mandatory
redemption 34,828 31,968 36,028 38,038
The fair value does not affect SWEPCO's liabilities unless the
issues are redeemed prior to their maturity dates.
6.Short-Term Financing
SWEPCO, together with other members of the CSW System, has
established a money pool to coordinate short-term borrowings and
to make borrowings outside the money pool through CSW's issuance
of commercial paper. Money pool balances are shown as advances to
or from affiliates on the Balance Sheets. At December 31, 1994,
the CSW System had bank lines of credit aggregating $930 million
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.
7.Benefit Plans
Defined Benefit Pension Plan
SWEPCO, together with other members of the CSW System, maintains a
tax qualified, non-contributory defined benefit pension plan
covering substantially all employees. Benefits are based on
employees' years of credited service, age at retirement, and final
average annual earnings with an offset for the participants'
primary Social Security benefit. The CSW System's funding policy
is based on actuarially determined contributions, taking into
account amounts which are deductible for income tax purposes and
minimum contributions required by ERISA. Pension plan assets
consist primarily of common stocks and short-term and intermediate-
term fixed income investments.
Contributions to the plan for the years ended December 31, 1994,
1993 and 1992 were $5.9 million, $6.1 million and $5.2 million,
respectively.
The approximate maximum number of participants in the plan during
1994 was 2,000 active employees, 800 retirees and beneficiaries
and 100 terminated employees.
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The components of net periodic pension cost and the assumptions
used in accounting for pensions follow:
1994 1993 1992
(thousands)
Net Periodic Pension Cost
Service cost $ 4,843 $ 4,239 $ 3,857
Interest cost on projected
benefit obligation 13,361 12,063 10,920
Actual return on plan assets (945) (14,658) (9,375)
Net amortization and deferral (15,018) 55 (4,253)
$ 2,341 $ 1,699 $ 1,149
Discount rate 8.25% 7.75% 8.50%
Long-term compensation increase 5.46% 5.46% 5.96%
Return on plan assets 9.50% 9.50% 9.50%
At December 31, 1994, the plan's net assets were approximately
equal to the total actuarial present value of the accumulated
benefit obligation. At December 31, 1993 and 1992, the plan's net
assets exceeded the total actuarial present value of the
accumulated benefit obligation. No reconciliation of the funding
status of the plan is presented because such information is
unavailable.
Health and Welfare Plans
SWEPCO had medical, dental, group life insurance, dependent life
insurance, and accidental death and dismemberment plans for
substantially all active SWEPCO employees during 1994. The
contributions, recorded on a pay-as-you-go basis, for the years
ended December 31, 1994 and 1993 were approximately $4.1 million
and $5.4 million, respectively. Effective January 1993, SWEPCO's
method of providing health benefits was modified to include such
benefits as a health maintenance organization, preferred provider
options, managed prescription drug and mail-order program and a
mental health and substance abuse program in addition to the self-
insured indemnity plans.
Postretirement Benefits Other Than Pensions
SWEPCO adopted SFAS No. 106 on January 1, 1993. The effect on
operating expense in 1993 was $3 million. SWEPCO is amortizing
its transition obligation over twenty years, with eighteen years
remaining. In prior years, these benefits were accounted for on a
pay-as-you-go basis.
The components of net periodic postretirement benefit cost follow:
1994 1993
(thousands)
Net Periodic Postretirement
Benefit Cost
Service cost $1,965 $1,813
Interest cost on APBO 4,266 3,782
Actual return on plan assets (464) (230)
Amortization of transition obligation 1,967 1,967
Net amortization and deferral (765) (474)
$6,969 $6,858
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A reconciliation of the funded status of the plan to the amounts
recognized on the balance sheets follow:
December 31,
1994 1993
APBO (thousands)
Retirees $ 32,938 $ 31,883
Other fully eligible participants 7,945 7,505
Other active participants 12,726 14,199
Total APBO 53,609 53,587
Plan assets at fair value (18,775) (13,139)
APBO in excess of plan assets 34,834 40,448
Unrecognized transition obligation (35,403) (37,370)
Unrecognized gain or (loss) 608 (4,410)
Accrued/(Prepaid) Cost $ 39 $ (1,332)
The following assumptions were used in accounting for SFAS No.
106.
1994 1993
Discount rate 8.25% 7.75%
Return on plan assets 9.50% 9.00%
Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions
Pre-65 Participants: 1994 Rate of 11.75% grading down .75% per
year to an ultimate rate of 6.5% in 2001.
Post-65 Participants: 1994 Rate of 11.25% 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, 1994 by $6 million and increase the aggregate of the
service and interest costs components on net postretirement
benefits by $0.9 million.
8.Jointly Owned Electric Utility Plant
SWEPCO has joint ownership agreements with non-affiliated
entities. Such agreements provide for the joint ownership and
operation of the Flint Creek, Pirkey and Dolet Hills power plants
and related facilities. The statements of income reflect SWEPCO's
portion of operating costs associated with jointly owned plants.
At December 31, 1994, SWEPCO had interests as shown below:
Flint Dolet
Creek Pirkey Hills
Coal Lignite Lignite
Plant Plant Plant
(dollars in millions)
Plant in service $79 $431 $226
Accumulated depreciation $39 $135 $62
Plant capacity-MW 480 650 650
Participation 50.0% 85.9% 40.2%
Share of capacity-MW 240 559 262
2-154
9.Litigation and Regulatory Proceedings
Fuel Reconciliation
On March 17, 1994, SWEPCO filed a petition with the Texas
Commission to reconcile fuel costs for the period November 1989
through December 1993. Total Texas jurisdictional fuel expenses
subject to reconciliation for this 50-month period were
approximately $559 million. SWEPCO's net under-recovery for the
reconciliation period was approximately $0.9 million. SWEPCO and
the intervening parties in this proceeding were able to negotiate
a stipulated agreement providing a $3.2 million fuel cost
disallowance and settling all issues except one. That issue
involved the recovery of certain fuel related litigation and
settlement negotiation expenses. The Texas Commission, at its
Final Order hearing on January 18, 1995, approved the stipulated
disallowance and granted SWEPCO recovery of the fuel related
litigation expense. The $3.2 million disallowance is included in
SWEPCO's 1994 results of operations. SWEPCO recognized the
litigation costs as expenses in prior periods.
Burlington Northern Transportation Contract
On January 20, 1995, a state district court in Bowie County,
Texas, entered judgment in favor of SWEPCO against Burlington
Northern in a lawsuit between the parties regarding rates charged
under two rail transportation contracts for delivery of coal to
SWEPCO's Welsh and Flint Creek power plants. The court awarded
SWEPCO approximately $72 million covering damages for the period
from April 27, 1989 through September 26, 1994 and prejudgment
interest fees and granted certain declaratory relief requested by
SWEPCO.
Kansas City Southern Railway Company Transportation Contracts
In March 1994, SWEPCO entered into a settlement with the Kansas
City Southern Railway Company of litigation between parties
regarding two coal transportation contracts. Pursuant to the
settlement, SWEPCO and the Kansas City Southern Railway Company
executed a new coal transportation agreement. The settlement is
expected to result in a reduction of SWEPCO's coal transportation
costs now and in the future. Burlington Northern, another party
to the prior contracts and to the litigation, did not participate
in the settlement and the litigation is still pending between
SWEPCO and Burlington Northern.
Other
SWEPCO 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 SWEPCO's results of operations or financial
condition.
10. Commitments and Contingent Liabilities
It is estimated that SWEPCO will spend approximately $96 million
in construction expenditures during 1995. Substantial commitments
have been made in connection with this capital expenditure
program.
To supply a portion of the fuel requirements, SWEPCO has entered
into various commitments for procurement of fuel.
Henry W. Pirkey Power Plant
In connection with the South Hallsville lignite mining contract for
its Henry W. Pirkey Power Plant, SWEPCO has agreed, under certain
conditions, to assume the obligations of the mining contractor. As
of December 31, 1994, the maximum amount SWEPCO would have to assume
was $73.7 million. The maximum amount may vary as the mining
contractor's need for funds fluctuates. The contractor's actual
obligation outstanding at December 31, 1994 was $60.9 million.
South Hallsville Lignite Mine
As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining at the South Hallsville
lignite mine, SWEPCO has agreed to provide bond guarantees on mine
reclamation in the amount of $70 million. Since SWEPCO uses self-
2-155
bonding, the guarantee provides for SWEPCO to commit to use its
resources to complete the reclamation in the event the work is not
completed by the third party miner. The current cost to reclaim
the mine is estimated to be approximately $25 million.
Coal Transportation
SWEPCO has entered into various financing arrangements primarily
with respect to coal transportation and related equipment, which
are treated as operating leases for rate-making purposes. At
December 31, 1994, leased assets of $46 million, net of
accumulated amortization of $30.1 million, were included in
electric plant on the balance sheet and at December 31, 1993,
leased assets were $46 million, net of accumulated amortization of
$26.8 million. Total charges to operating expenses for leases
were $6.8 million, $7.1 million, and $6.9 million for the years
1994, 1993, and 1992.
Suspected MGP Site in Marshall, Texas
SWEPCO owns a suspected former MGP site in Marshall, Texas.
SWEPCO has notified the TNRCC that evidence of contamination has
been found at the site. As a result of sampling conducted at the
end of 1993 and early 1994, SWEPCO is evaluating the extent, if
any, to which contamination has impacted soil, groundwater and
other conditions in the area. A final range of clean-up costs has
not yet been determined, but, based on a preliminary estimate,
SWEPCO has accrued approximately $2 million as a liability for
this site on SWEPCO's books as of December 31, 1993. As more
information is obtained about the site, and SWEPCO discusses the
site with the TNRCC, the preliminary estimate may change.
Suspected MGP Site in Texarkana, Texas and Arkansas and
Shreveport, Louisiana
SWEPCO also owns a suspected former MGP site in Texarkana, Texas
and Arkansas. The EPA ordered an initial investigation of this
site, as well as one in Shreveport, Louisiana, which is no longer
owned by SWEPCO. The contractor who performed the investigations
of these two sites recommended to the EPA that no further action
be taken at this time.
Biloxi, Mississippi MGP Site
SWEPCO has been notified by Mississippi Power Company that it may
be a PRP at the former Biloxi MGP site formerly owned and operated
by a predecessor of SWEPCO. SWEPCO is working with Mississippi
Power Company to investigate the extent of contamination at this
site. The MDEQ approved a site investigation work plan and, in
January 1995, SWEPCO and Mississippi Power Company initiated
sampling pursuant to that work plan. On an interim basis, SWEPCO
and Mississippi Power Company are each paying fifty percent of the
cost of implementing the site investigation work plan. That
interim allocation is subject to a final allocation in the future.
SWEPCO and Mississippi Power Company are investigating whether
there are other PRPs at the Biloxi site. Until the extent of the
contamination at the Biloxi site is identified, it is unknown
what, if any, additional investigation or cleanup may be required.
Management does not expect these matters to have a material effect
on SWEPCO's results of operations or financial position.
2-156
11. Quarterly Information (Unaudited)
The following unaudited quarterly information includes, in the
opinion of management, all adjustments necessary for a fair
presentation of such amounts.
Operating Operating Net
Quarter Ended Revenues Income Income
1994 (thousands)
March 31 $190,066 $ 24,820 $ 14,537
June 30 211,989 36,699 25,851
September 30 245,331 53,304 41,854
December 31 177,910 31,099 23,470
$825,296 $145,922 $105,712
1993
March 31 $175,601 $ 23,953 $ 16,269
June 30 193,225 31,954 21,363
September 30 276,594 58,639 48,353
December 31 191,772 3,511 (4,109)
$837,192 $118,057 $ 81,876
Information for quarterly periods is affected by seasonal
variations in sales, rate changes, timing of fuel expense recovery
and other factors.
2-157
Report of Independent Public Accountants
To the Stockholders and Board of Directors of Southwestern Electric
Power Company:
We have audited the accompanying balance sheets and statements
of capitalization of Southwestern Electric Power Company (a Delaware
corporation and a wholly-owned subsidiary of Central and South West
Corporation) as of December 31, 1994 and 1993, and the related
statements of income, retained earnings and cash flows for each of
the three years in the period ended December 31, 1994. These
financial statements are the responsibility of SWEPCO'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
Southwestern Electric Power Company as of December 31, 1994 and
1993, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 1994, in
conformity with generally accepted accounting principles.
In 1993, as discussed in NOTE 1, SWEPCO changed its method 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
Schedule II 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. This schedule 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 LLP
Dallas, Texas
February 13, 1995
2-158
Report of Management
Management is responsible for the preparation, integrity and
objectivity of the financial statements of Southwestern Electric
Power Company as well as other information contained in this Annual
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 Annual Report is
consistent with that in the financial statements.
The financial statements have been audited by the independent
accounting firm, Arthur Andersen LLP, which was given unrestricted
access to all financial records and related data, including minutes
of all meetings of shareholders, the board of directors and
committees of the board. SWEPCO believes that representations made
to the independent auditors during its audit were valid and
appropriate. Arthur Andersen LLP's audit report is presented
elsewhere in this report.
SWEPCO maintains a system of internal controls to provide
reasonable assurance that transactions are executed in accordance
with management's authorization, that the financial statements are
prepared in accordance with generally accepted accounting principles
and that the assets of the companies are properly safeguarded against
unauthorized acquisition, use or disposition. The system includes a
documented organizational structure and division of responsibility,
established policies and procedures including a policy on ethical
standards which provides that SWEPCO will maintain the highest legal
and ethical standards, and the careful selection, training and
development of our employees.
Internal auditors continuously monitor the effectiveness of the
internal control system following standards established by the
Institute of Internal Auditors. Actions are taken by management to
respond to deficiencies as they are identified. The board, operating
through its audit committee, which is comprised entirely of directors
who are not officers or employees of SWEPCO provides oversight to the
financial reporting process.
Due to the inherent limitations in the effectiveness of internal
controls, no internal control system can provide absolute assurance
that errors will not occur. However, management strives to maintain
a balance, recognizing that the cost of such a system should not
exceed the benefits derived.
SWEPCO believes that, in all material respects, its system of
internal controls over financial reporting and over safeguarding of
assets against unauthorized acquisition, use or disposition
functioned effectively during 1994.
Richard H. Bremer R. Russell Davis
President and CEO - SWEPCO Controller - SWEPCO
2-159
WTU
WEST TEXAS UTILITIES COMPANY
2-160
Selected Financial Data
WTU
The following selected financial data for each of the five years
ended December 31 are provided to highlight significant trends in the
financial condition and results of operations for WTU.
1994 1993 1992 1991 1990
(thousands, except ratios)
Operating Revenues $342,991 $345,445 $315,370 $318,966 $327,065
Income Before Cumulative
Effect of Changes in
Accounting Principles 37,366 26,517 35,007 36,368 34,173
Cumulative Effect of
Changes in Accounting
Principles (1) -- 3,779 -- -- --
Net Income 37,366 30,296 35,007 36,368 34,173
Preferred Stock Dividends 452 967 1,451 1,868 2,077
Net Income for Common Stock 36,914 29,329 33,556 34,500 32,096
Total Assets 778,895 754,443 744,829 734,053 735,969
Common Stock Equity 271,954 266,092 266,874 259,373 261,466
Preferred Stock
Not Subject to Mandatory
Redemption 6,291 6,291 6,291 6,291 6,291
Subject to Mandatory
Redemption -- -- 9,537 14,482 22,376
Long-term Debt 210,047 176,882 211,610 217,855 216,837
Ratio of Earnings to Fixed
Charges (SEC Method) Before
Cumulative Effect of Changes
in Accounting Principles 3.37 2.79 3.22 3.30 3.05
Capitalization Ratios
Common Stock Equity 55.7% 59.2% 54.0% 52.1% 51.6%
Preferred Stock 1.3 1.4 3.2 4.2 5.6
Long-term Debt 43.0 39.4 42.8 43.7 42.8
(1) The 1993 cumulative effect relates to the changes in accounting
for unbilled revenues and adoption of SFAS No. 112. See NOTE 1,
Summary of Significant Accounting Policies.
WTU 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 reported for prior years and therefore have
not been restated.
2-161
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
WEST TEXAS UTILITIES COMPANY
Reference is made to WTU's Financial Statements and related Notes
and Selected Financial Data. The information contained therein should
be read in conjunction with, and is essential to understanding, the
following discussion and analysis.
Overview
Net income for common stock was $37 million in 1994, a 26%
increase when compared to 1993. This increase was due primarily to an
increase in retail base revenues and other income and a decrease in
restructuring charges.
Restructuring
As previously reported, WTU has taken steps to implement a
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 restructuring is to enable
WTU to focus on and be accountable for serving the customer. The
restructuring costs were initially estimated to be $15 million and
were expensed in 1993. The final costs of the restructuring were
approximately $13 million. Approximately $12 million of the
restructuring expenditures were incurred during 1994, with the
remaining $1 million expected to be incurred during 1995.
Approximately $1 million of the restructuring expenses relate to
employee termination benefits, $7 million relate to enhanced benefit
costs and $5 million relate to employees that will not be terminated.
Approximately $9 million of the restructuring costs were paid from or
will be paid from general corporate funds. The remaining $4 million
represent the present value of enhanced benefit amounts to be paid
from the benefit plan trusts to participants over future years in
accordance with the early retirement program. The cost of these
enhanced benefit amounts will be paid from general corporate funds to
the benefit plan trusts over future years. The restructuring is
substantially completed, with the remaining activity to take place
during 1995. Certain aspects of the restructuring are pending SEC
approval under the Holding Company Act.
WTU expects to realize a number of benefits from the
restructuring. Beginning in 1994 and continuing into the future,
increased efficiencies and synergies are expected to be realized with
the elimination of previously duplicated functions. This leads to
enhanced communication and efficiency, which should translate into a
reduction in the rate of growth in O&M costs. The CSW System expects
that all restructuring costs will be recovered by early 1996 with
reductions in the rate of growth of O&M costs continuing thereafter.
Rates and Regulatory Matters
See NOTE 9, Litigation and Regulatory Proceedings, for
information regarding the WTU fuel and rate proceedings, and deferred
accounting matters.
New Accounting Standards
SFAS No. 115 was effective for fiscal years beginning after
December 15, 1993. WTU adopted SFAS No. 115 in 1994. The adoption of
SFAS No. 115 did not have a material effect on WTU's results of
operations or financial condition.
In June 1993, the FASB issued SFAS No. 116. The statement,
effective for fiscal years beginning after December 15, 1994, will be
adopted by WTU for 1995. The statement establishes accounting
standards for contributions and applies to all entities that receive
or make contributions. Management does not believe the adoption of
SFAS No. 116 will have a material impact on WTU's results of
operations or financial condition.
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SFAS No. 119 was effective for fiscal years ending after December
15, 1994. WTU currently does not use derivative instruments, but may
use these instruments in the future to manage the increased market
risks associated with greater competition in the electric utility
industry. The adoption of this new statement had no material effect
on WTU's results of operations or financial condition.
Liquidity and Capital Resources
Overview
WTU's need for capital results primarily from the construction of
facilities to provide reliable electric service to its customers.
Accordingly, internally generated funds should meet most of the
capital requirements. However, if internally generated funds are not
sufficient, WTU's financial condition and credit rating should allow
it access to the capital markets.
Capital Expenditures
Construction expenditures including AFUDC were $42 million, $37
million and $29 million for the years 1994, 1993 and 1992. It is
estimated that construction expenditures, including AFUDC, during the
1995 through 1997 period will aggregate $109 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 construction program continues to be monitored, reviewed and
adjusted to reflect changes in estimated load growth in WTU's service
area, variations in prices of alternative fuel sources, the cost of
labor, materials, equipment and capital, and other external factors.
The CSW System facilities plan presently includes projected coal-
and lignite-fired generating plants for which WTU has invested
approximately $15 million in prior years for plant sites, engineering
studies and lignite reserves. Should future plans exclude these
plants for environmental or other reasons, WTU would evaluate the
probability of recovery of these investments and may record
appropriate reserves.
Long-Term Financing
As of December 31, 1994, the capitalization ratios of WTU were
56% common stock equity, 1% preferred stock and 43% long-term debt.
WTU continually monitors the capital markets for opportunities to
lower its cost of capital through refinancing. WTU continues to be
committed to maintaining financial flexibility by maintaining its
strong capital structure and favorable securities ratings which should
allow funds to be obtained from the capital markets when required.
WTU's long-term financing activity is shown below:
In February 1994, WTU issued $40 million of 6-1/8% FMBs, Series
S, due February 1, 2004. Proceeds were used to reimburse WTU's
treasury for (i) $12 million aggregate principal amount of 7-1/4%
First Mortgage Bonds, Series G, due January 1, 1999, redeemed on
January 1, 1994, and, (ii) $23 million aggregate principal amount of 7-
7/8% FMBs, Series H, due July 1, 2003, redeemed on December 30, 1993.
The balance of the proceeds was used to repay outstanding short-term
borrowings.
In July 1994, WTU redeemed its remaining $4.7 million outstanding
of 7-1/4% Series Preferred Stock in accordance with mandatory sinking
fund provisions. The funds required for this transaction were
provided from internal sources and short-term borrowings.
In October and November 1994, WTU reacquired $7.8 million
aggregate principal amount of its 9-1/4% FMBs, Series O, due December
1, 2019 in open market transactions. The funds required for these
transactions were provided from short-term borrowings and internal
sources. The premiums and reacquisition costs of reacquired long-term
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debt are included in long-term debt on the balance sheets and are
being amortized over 10 to 30 years in accordance with the anticipated
regulatory treatment.
In December 1994, pursuant to sinking fund requirements, WTU
elected to redeem at par $650,000 Series O, FMBs.
In March 1995, WTU issued $40 million of 7-1/2% FMBs, Series T,
due April 1, 2000. Proceeds were used to repay a portion of WTU's
short-term debt, to provide working capital and for other general
corporate purposes.
WTU Shelf Registration
WTU expects to obtain a majority of their 1995 capital
requirements from internal sources, but may issue additional
securities subject to market conditions and other factors. The
proceeds of any such offerings will be used principally to redeem
higher cost preferred stock and to repay short-term debt. WTU has
filed shelf registration statements with the SEC for the sale of
securities. As of March 1995, WTU had $20 million remaining for
issuance of first mortgage bonds under a shelf registration filed with
the SEC in 1993. WTU may issue additional debt securities subject to
market conditions and other factors. The proceeds of any such
offerings will be used principally to redeem higher cost FMBs, to
lower embedded cost of debt, to repay short-term debt, to provide
working capital and for other general corporate purposes.
WTU may issue additional preferred stock subject to market
conditions and other factors. The proceeds of any such offerings will
be used principally to redeem higher cost preferred stock and to
redeem short-term debt.
Short-Term Financing
WTU, 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.
WTU's short-term borrowing limit from the money pool is $50 million.
During 1994, the annual weighted average interest rate was 4.5% and
the average amount of short-term month-end borrowings outstanding was
$22 million. The maximum amount of short-term borrowings outstanding
at any month-end during 1994 was $46 million, which was the amount
outstanding at December 31, 1994.
Internally Generated Funds
Internally generated funds consist of cash flows from operating
activities less common and preferred stock dividends. WTU uses short-
term debt to meet fluctuations in working capital requirements due to
the seasonal nature of energy sales. During 1993 and 1994, WTU
experienced several non-recurring transactions that resulted in
negative internally generated funds in 1994, including the refinancing
of Series G and Series H FMBs with Series S FMBs which occurred from
December 1993 through February 1994. This refinancing caused an
abnormally high accounts payable balance at December 31, 1993 which
was subsequently reduced by the issuance of Series S in February 1994,
resulting in the appearance of a large out flow of cash from operating
funds. WTU anticipates that capital requirements for the period 1995
to 1997 will be met, in large part, from internal sources. WTU also
expects that some external financings maybe required during the
period, but the nature, timing and extent have not yet been
determined. Information concerning internally generated funds
follows:
1994 1993 1992
(millions)
Internally Generated Funds ($4) $59 $49
Construction Expenditures Provided
by Internally Generated Funds -- 163% 169%
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As discussed above, WTU issued $40 million of 7-1/2% FMBs during
the first quarter of 1995, which were used to reduce short-term debt.
Sales of Accounts Receivable
WTU sells its billed and unbilled accounts receivable, without
recourse, to CSW Credit. The sales provide WTU with cash immediately,
thereby reducing working capital needs and revenue requirements. The
average and year end amounts of accounts receivable sold were $35
million and $18 million in 1994, as compared to $36 million and $34
million in 1993.
Recent Developments and Trends
Competition and Industry Challenges
Competitive forces at work in the electric utility industry are
impacting WTU and electric utilities generally. Increased competition
facing electric utilities is driven by complex economic, political and
technological factors. These factors have resulted in legislative and
regulatory initiatives that are likely to result in even greater
competition at both the wholesale and retail level in the future. As
competition in the industry increases, WTU will have the opportunity
to seek new customers and at the same time be at risk of losing
customers to other competitors. WTU believes that its prices for
electricity and the quality and reliability of its service currently
place it in a position to compete effectively in the marketplace.
The Energy Policy Act, which was enacted in 1992, significantly
alters the way in which electric utilities compete. The Energy Policy
Act creates exemptions from regulation under the Holding Company Act
and permits utilities, including registered utility holding companies
and non-utility companies, to form EWGs. EWGs are a new category of
non-utility wholesale power producer that are 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. The Energy Policy Act also 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. A FERC order requiring a transmitting utility
to provide wholesale transmission service must include provisions
generally that permit (i) the utility to recover from the FERC
applicant all of the costs incurred in connection with the
transmission services and (ii) any enlargement of the transmission
system and associated services. While WTU believes that the Energy
Policy Act will continue to make the wholesale markets more
competitive, WTU is unable to predict the extent to which the Energy
Policy Act will impact its operations.
Increasing competition in the utility industry brings an
increased need to stabilize or reduce rates. The retail regulatory
environment is beginning to shift from traditional rate base
regulation to incentive regulation. Incentive rate and performance-
based plans encourage efficiencies and increased productivity while
permitting utilities to share in the results. Retail wheeling, a
major industry issue which may require utilities to "wheel" or move
power from third parties to their own retail customer, is evolving
gradually.
Wholesale energy markets, including the market for wholesale
electric power, have been extremely competitive since the enactment of
the Energy Policy Act. WTU competes in the wholesale energy markets
with other public utilities, cogenerators, qualified facilities,
exempt wholesale generators and others for sales of electric power.
Under the Energy Policy Act, the FERC has approved several
proposals by utility companies to sell wholesale power at market-based
rates and provide to electric utilities "open access" to transmission
systems, subject to certain requirements. The adoption of these
proposals increases marketing opportunities for electric utilities,
but also exposes them to the risk of loss of load or reduced revenues
due to competition with alternative suppliers.
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WTU believes that, compared to other electric utilities, it is
well positioned to meet future competition. WTU benefits from
economies of scale and scope by virtue of its size and its
relationship to the CSW System. WTU is also a relatively low-cost
producer of electric power. Moreover, WTU is taking steps to enhance
its marketing and customer service, reduce costs, improve and
standardize business practices, and grow through strategic
acquisitions, in order to position itself for increased competition in
the future.
WTU is unable to predict the ultimate outcome or impact of
competitive forces on the electric utility industry or on WTU. As the
wholesale and retail electricity markets become more competitive,
however, the principal factor determining success is likely to be
price, and to a lesser extent, reliability, availability of capacity,
and customer service.
Public Utility Regulatory Act
PURA is the legal foundation for electric utility regulation in
Texas. PURA will expire on September 1, 1995, in accordance with the
sunset policy of the Texas Legislature, which applies to all state
agencies, unless the Texas Legislature reenacts PURA in its current
form or in modified form. Several proposals have been made to amend
PURA which, among other things, provide for a market-driven integrated
resource planning process, pricing flexibility for utilities faced
with competitive challenges, incentive regulation and deregulation of
the wholesale bulk power market in ERCOT. WTU is unable to predict
the ultimate outcome of the 1995 session of the Texas Legislature and
in particular whether amendments to PURA will be adopted.
Regulatory Accounting
Consistent with industry practice and the provisions of SFAS No.
71, which allows for the recognition and recovery of regulatory
assets, WTU has recognized significant regulatory assets and
liabilities. Management believes that WTU will continue to meet the
criteria for following SFAS No. 71. However, in the event WTU no
longer meets the criteria for following SFAS No. 71, a write-off of
regulatory assets and liabilities would be required. For additional
information regarding SFAS No. 71 reference is made to NOTE 1,
Summary of Significant Accounting Policies - Regulatory Assets and
Liabilities.
Consolidated Taxes
The Texas Commission before 1992 allowed income taxes to be
recovered in rates based on the federal income tax incurred by a
utility as if it were a stand-alone company. This stand-alone
approach treated the regulated activities of a utility as a separate
entity and considered only those revenues and expenses that are
included in the utility's cost of service to calculate the federal
income tax liability for ratemaking purposes.
Beginning in 1992, the Texas Commission changed its method of
calculating the federal income tax component of rates to the "actual
tax approach." The actual tax approach is an evolving concept but
generally seeks to reflect in rates the actual tax liability of the
utility irrespective of its relationship to the utility's cost of
service. The approach reduces rates by the tax benefits of deductions
which are not considered for or included in setting rates for the
utility.
The Texas Commission is expected to use the actual tax approach
for calculating the recovery of federal income tax in the pending rate
case for WTU. The impact of the actual tax approach on the
prospective rates for WTU cannot be determined since the application
of the concept is unsettled.
WTU believes that the recovery of federal income taxes in rates
should be determined on the stand-alone approach for ratemaking
purposes, but there is no assurance this approach will be adopted in
the pending WTU rate case.
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Environmental Matters
CERCLA and Related Matters
The operations of WTU, like those of other utilities, generally
involve the use and disposal of substances subject to environmental
laws. The 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. PRPs include owners and operators of
contaminated sites and transporters and/or generators of hazardous
substances. 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.
WTU is subject to various pending claims alleging it is a PRP
under federal or state remedial laws for investigating and cleaning up
contaminated property. WTU anticipates that resolution of these
claims, individually or in the aggregate, will not have a material
adverse effect on WTU's results of operations or financial condition.
Although the reasons for this expectation differ from site to site,
factors that are the basis for the expectation for specific sites
include the volume and/or type of waste allegedly contributed by WTU,
the estimated amount of costs allocated to WTU and the participation
of other parties.
Clean Air Act Amendments
In November 1990, the United States Congress passed the Clean
Air Act which places restrictions on the emission of sulfur dioxide
from gas-, coal- and lignite-fired generating plants. Beginning in
the year 2000, the Electric Operating Companies will be required to
hold allowances in order to emit sulfur dioxide. The EPA issues
allowances to owners of existing generating units based on historical
operating conditions. Based on the CSW System facilities plan, WTU
believes that its allowances will be adequate to meet its needs at
least through 2008. Public and private markets are developing for
trading of excess allowances. WTU presently has no intention of
engaging in trading of allowances, but may seek to do so in the
future if market conditions warrant and appropriate regulatory
approvals are obtained.
The Clean Air Act also establishes a federal operating source
permit program to be administered by the states.
The Clean Air Act also directs the EPA to issue regulations
governing nitrogen oxide emissions and requires government studies to
determine what controls, if any, should be imposed on utilities to
control air toxics emissions. The impact that the nitrogen oxide
emission regulations and the air toxics study will have on WTU cannot
be determined at this time.
As a result of requirements imposed by the Clean Air Act, WTU
expects to spend $0.5 million for annual testing of, software
modifications to, and maintenance of continuous emission monitoring
equipment from 1995 through 1997.
EMFs
Research is ongoing whether exposure to EMFs may result in
adverse health effects. Although a few of the studies to date have
suggested certain associations between EMFs and some types of effects,
the research to date has not established a cause-and-effect
relationship between EMFs and adverse health effects. WTU cannot
predict the impact on WTU 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.
Results of Operations
Electric Operating Revenues
Electric operating revenues in 1994 decreased approximately
$2.5 million or 1% when compared to 1993. This decrease was due
primarily to a reduction in lower margin off-system sales of $8
million resulting from decreased market place demand. This decrease
was partially offset by higher on system revenues of $6.5 million
attributable to an increase in retail KWH sales of 3% resulting from
customer growth and increased usage. Also contributing to the
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decrease was an interim rate reduction of approximately $5.7 million
on an annual basis effective October 1, 1994. Revenues for 1993,
when compared to 1992, increased approximately $30.1 million, or
10%. The increase is attributed to a 10% increase in KWH sales and
a $9.1 million increase in fuel-related revenues. The increase in
KWH sales is attributable to a warmer summer in 1993 and increased
sales for resale to an affiliated company.
Fuel and Purchased Power Expenses
Fuel expenses decreased approximately $3.8 million or 3% during
1994 when compared to 1993 and increased approximately $15.1 million
or 13% when compared to 1992. The decrease in 1994 is primarily
attributable to a 2% decrease in average unit fuel costs from $1.91
in 1993 to $1.88 in 1994 and a 2% decrease in generation. The
increase in 1993 is due primarily to a 5% increase in average unit
fuel cost to $1.91 in 1993 from $1.82 in 1992 and a 7% increase in
generation. The change in unit fuel costs during both years is due
primarily to changes in the price of natural gas on the spot market.
Purchased power expenses decreased approximately $2.3 million
and increased $4.3 million during 1994 and 1993, respectively, when
compared to the prior years. The change during both periods is
primarily attributable to increased economy purchases in 1993.
Expenses and Taxes
Other operating expenses increased approximately $4.9 million
and $3.8 million during 1994 and 1993, respectively, when compared
to prior years. The increase during 1994 reflects a reimbursement
in 1993 for the settlement of a dispute relating to a coal supply
contract which lowered expenses in 1993. Higher outside services
for fuel related issues and other employee related expenses in 1994
also contributed to the increase. The increase during 1993 was due
primarily to higher employee pensions and benefits.
Restructuring charges reflect the original accrual of $15
million in December 1993 which was subsequently adjusted by $2
million in 1994, resulting in total restructuring charges for WTU of
$13 million at December 31, 1994.
Maintenance expense in 1994 increased over 1993 by
approximately $1.7 million or 13% due primarily to increased
production maintenance of boiler and electric plant. Maintenance
increased approximately $1.3 million in 1993 compared with 1992
because of higher production and general expenses resulting from
boiler plant maintenance.
Depreciation and amortization expenses increased approximately
$1.2 million and $3.6 million during 1994 and 1993, respectively,
when compared to prior years due primarily to increases in
depreciable property.
Federal income taxes increased approximately $4.3 million or
32% in 1994 when compared with 1993 due to higher pre-tax income.
The decrease in 1993 compared to 1992 was largely attributable to
lower pre-tax income partially offset by an increase in the federal
corporate income tax rate to 35% from 34%.
Other income increased approximately $2.3 million in 1994
resulting from tax benefits received under WTU's tax sharing
agreement with CSW.
Interest on Long-Term Debt
Interest on long-term debt decreased approximately $0.7 million
in 1994 when compared to the prior year due to WTU's refinancing of
higher cost debt with lower cost debt and decreased balances
outstanding.
Inflation
Annual inflation rates, as measured by the national Consumer
Price Index, have averaged approximately 2.7% for the three-year
period ending December 31, 1994. WTU believes that inflation, at
these levels, does not materially affect its results of operations
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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.
Cumulative Effect of Changes in Accounting Principles
In 1993, WTU changed it method of accounting for unbilled
revenue and implemented SFAS No. 112. These accounting changes had
a cumulative effect of increasing net income by $3.8 million.
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Statements of Income
West Texas Utilities Company
For the Years Ended December 31,
1994 1993 1992
(thousands)
Electric Operating Revenues
Residential $118,525 $115,932 $106,497
Commercial 66,483 65,085 62,244
Industrial 52,626 53,709 52,651
Sales for resale 67,076 72,252 60,833
Other 38,281 38,467 33,145
342,991 345,445 315,370
Operating Expenses and Taxes
Fuel 131,258 135,048 119,983
Purchased power 5,144 7,411 3,086
Other operating 66,290 61,357 57,578
Restructuring charges (2,037) 15,250 --
Maintenance 14,978 13,251 11,959
Depreciation and amortization 31,569 30,405 26,784
Taxes, other than federal
income 23,072 22,496 21,970
Federal income taxes 17,954 13,651 16,708
288,228 298,869 258,068
Operating Income 54,763 46,576 57,302
Other Income and Deductions
Allowance for equity funds
used during construction 150 109 51
Other 4,210 1,907 1,114
4,360 2,016 1,165
Income Before Interest Charges 59,123 48,592 58,467
Interest Charges
Interest on long-term debt 18,547 19,225 21,368
Interest on short-term debt
and other 3,534 2,988 2,197
Allowance for borrowed funds
used during construction (324) (138) (105)
21,757 22,075 23,460
Income Before Cumulative Effect
of Changes in Accounting
Principles 37,366 26,517 35,007
Cumulative Effect of Changes in
Accounting Principles -- 3,779 --
Net Income 37,366 30,296 35,007
Preferred stock dividends 452 967 1,451
Net Income for Common Stock $ 36,914 $ 29,329 $ 33,556
The accompanying notes to financial statements are an integral part of
these statements.
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Statements of Retained Earnings
West Texas Utilities Company
For the Years Ended December 31,
1994 1993 1992
(thousands)
Retained Earnings at Beginning of Year $126,642 $127,424 $119,923
Net income for common stock 36,914 29,329 33,556
Deduct: Common stock dividends 31,000 30,000 26,000
Preferred stock redemption cost 52 111 55
Retained Earnings at End of Year $132,504 $126,642 $127,424
The accompanying notes to financial statements are an integral part of
these statements.
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Balance Sheets
West Texas Utilities Company
As of December 31,
1994 1993
(thousands)
ASSETS
Electric Utility Plant
Production $427,736 $425,340
Transmission 194,402 190,300
Distribution 308,905 291,509
General 73,938 69,780
Construction work in progress 23,257 14,385
1,028,238 991,314
Less - Accumulated depreciation 364,383 337,888
663,855 653,426
Current Assets
Cash 2,501 706
Accounts receivable 23,165 24,497
Materials and supplies, at average cost 16,519 14,451
Fuel inventory, at average cost 9,229 9,150
Coal inventory, at LIFO cost 6,442 5,511
Accumulated deferred income taxes 3,068 1,222
Prepayments and other 1,091 450
62,015 55,987
Deferred Charges and Other Assets
Deferred Oklaunion costs 26,914 27,735
Other 26,111 17,295
53,025 45,030
$778,895 $754,443
The accompanying notes to financial statements are an integral part of
these statements.
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Balance Sheets
West Texas Utilities Company
As of December 31,
1994 1993
(thousands)
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock: $25 par value
Authorized: 7,800,000 shares
Issued and outstanding: 5,488,560
shares $137,214 $137,214
Paid-in capital 2,236 2,236
Retained earnings 132,504 126,642
Total Common Stock Equity 271,954 266,092
Preferred stock
Not subject to mandatory redemption 6,291 6,291
Long-term debt 210,047 176,882
Total Capitalization 488,292 449,265
Current Liabilities
Long-term debt and preferred stock due
within twelve months 650 17,298
Advances from affiliates 46,315 11,784
Accounts payable 35,407 51,041
Accrued restructuring charges 571 15,250
Accrued taxes 7,452 14,620
Accrued interest 4,394 4,128
Other 3,758 1,979
98,547 116,100
Deferred Credits
Accumulated deferred income taxes 146,146 134,595
Investment tax credits 31,882 33,203
Income tax related regulatory
liabilities, net 9,217 10,545
Other 4,811 10,735
192,056 189,078
$778,895 $754,443
The accompanying notes to financial statements are an integral part of
these statements.
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Statements of Cash Flows
West Texas Utilities Company
For the Years Ended December 31,
1994 1993 1992
(thousands)
OPERATING ACTIVITIES
Net Income $ 37,366 $ 30,296 $ 35,007
Non-cash Items Included in Net Income
Depreciation and amortization 33,362 31,925 28,354
Restructuring charges (2,037) 15,250 --
Deferred income taxes and
investment tax credits 7,056 3,159 4,911
Cumulative effect of changes in
accounting principles -- (3,779) --
Allowance for equity funds used
during construction (150) (109) (51)
Changes in Assets and Liabilities
Accounts receivable 1,332 (3,159) (6,804)
Fuel inventory (1,010) (6) 141
Accounts payable (15,103) 21,552 13,417
Accrued taxes (7,168) 4,085 1,343
Accrued restructuring charges (8,918) -- --
Other deferred credits (5,924) (6,502) (777)
Other (10,802) (2,694) 1,152
28,004 90,018 76,693
INVESTING ACTIVITIES
Construction expenditures (41,504) (36,318) (28,902)
Allowance for borrowed funds used
during construction (324) (138) (105)
Disposition of plant (1,315) 3,302 (854)
(43,143) (33,154) (29,861)
FINANCING ACTIVITIES
Proceeds from issuance of
long-term debt 39,354 (77) 98,506
Reacquisition of long-term debt (20,731) (24,250) (106,757)
Redemption of preferred stock (4,700) (10,000) (5,000)
Payment of dividends (31,520) (30,816) (27,874)
Change in advances from affiliates 34,531 7,241 (5,714)
16,934 (57,902) (46,839)
Net Change in Cash and Cash Equivalents 1,795 (1,038) (7)
Cash and Cash Equivalents at Beginning of
Year 706 1,744 1,751
Cash and Cash Equivalents at End of Year $ 2,501 $ 706 $ 1,744
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized $ 18,128 $ 18,430 $ 21,257
Income taxes paid $ 12,720 $ 325 $ 6,174
The accompanying notes to financial statements are an integral part of
these statements.
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Statements of Capitalization
West Texas Utilities Company
As of December 31,
1994 1993
(thousands)
COMMON STOCK EQUITY $271,954 $266,092
PREFERRED STOCK
Cumulative $100 Par Value, Authorized
810,000 shares
Number Current
of Shares Redemption
Series Outstanding Price
Not Subject to Mandatory Redemption
4.40% 60,000 $107.00 6,000 6,000
Premium 291 291
6,291 6,291
Subject to Mandatory Redemption
7.25% 47,000 $100.91 -- 4,700
Issuance Expense -- (52)
Amount to be Redeemed Within One Year -- (4,648)
-- --
LONG-TERM DEBT
First Mortgage Bonds
Series G, 7 1/4%, due January 1, 1999 -- 12,000
Series O, 9 1/4%, due December 1, 2019 55,203 63,700
Series P, 7 3/4%, due June 1, 2007 25,000 25,000
Series Q, 6 7/8%, due October 1, 2002 35,000 35,000
Series R, 7%, due October 1, 2004 40,000 40,000
Series S, 6 1/8%, due February 1, 2004 40,000 --
Installment Sales Agreements - PCRBs
Series 1984, 7 7/8%, due September 15, 2014 44,310 44,310
Unamortized discount and premium (1,323) (1,162)
Unamortized costs of reacquired debt (27,493) (29,316)
Amount to be redeemed within one year (650) (12,650)
210,047 176,882
TOTAL CAPITALIZATION $488,292 $449,265
The accompanying notes to financial statements are an integral part
of these statements.
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NOTES TO FINANCIAL STATEMENTS
1.Summary of Significant Accounting Policies
Public Utility Regulation
WTU is subject to regulation by the SEC under the Holding Company
Act, and the FERC under the Federal Power Act, and follows the
Uniform System of Accounts prescribed by the FERC. WTU is subject
to further regulation with regard to rates and other matters by
the Texas Commission. WTU, as a member of the CSW System, engages
in transactions and coordinates its activities and operations with
other members of the CSW System.
The more significant accounting policies of WTU 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 electric utility plant are computed
using the straight-line method, generally at individual rates
applied to the various classes of depreciable property. The
annual average consolidated composite rates were 3.2% in both 1994
and 1993 and 3.1% in 1992.
Electric Revenues and Fuel
Prior to January 1, 1993, electric revenues 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 operating revenues of
the next month. To conform to general industry standards, WTU
changed its method of accounting to accrue for estimated unbilled
revenues. The effect of this change on 1993 net income was an
increase of $5.4 million included in cumulative effect of changes
in accounting principles.
WTU recovers fuel costs in Texas as a fixed component of base
rates whereby over-recoveries of fuel are payable to customers and
under-recoveries of fuel may be billed to customers after Texas
Commission approval. The cost of fuel is charged to expense as
consumed. WTU recovers fuel costs applicable to wholesale
customers, which are regulated by the FERC, through an automatic
fuel adjustment clause.
Accounts Receivable.
WTU sells its billed and unbilled accounts receivable, without
recourse, to CSW Credit.
Regulatory Assets and Liabilities.
For its regulated activities, WTU follows SFAS No. 71, which
defines the criteria for establishing regulatory assets and
regulatory liabilities. Regulatory assets represent probable
future revenue to the company associated with certain costs which
will be recovered from customers through the ratemaking process.
Regulatory liabilities represent probable future refunds to
customers. At December 31, 1994 and 1993, WTU had recorded the
following significant regulatory assets and liabilities:
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1994 1993
(thousands)
Regulatory Assets
Deferred plant costs $26,914 $27,735
Regulatory Liabilities
Income tax related
regulatory liabilities, net $ 9,217 $10,545
Deferred Plant Costs
In accordance with orders of the Texas Commission, WTU deferred
operating, depreciation and tax costs incurred for Oklaunion Power
Station Unit 1. This deferral was for the period beginning on the
date when the plant began commercial operation until the date the
plant was included in rate base. The deferred costs are being
amortized and recovered through rates over the remaining life of
the plant. See NOTE 9, Litigation and Regulatory Proceedings, for
further discussion of WTU's deferred accounting.
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 are considered cash
equivalents.
Reclassification
Certain financial statement items for prior years have been
reclassified to conform to the 1994 presentation.
Accounting Changes
Effective January 1, 1993, WTU adopted SFAS Nos. 106, 112 and 109.
See NOTE 2, Federal Income Taxes, for further information
regarding SFAS No. 109. In addition, WTU also changed its method
of accounting for unbilled revenues. See Electric Revenues and
Fuel above for further information.
The adoption of SFAS No. 106 resulted in an increase in 1993
operating expenses of $1.9 million. The adoption of SFAS No. 112
and the change in accounting for unbilled revenues are presented
as a cumulative effect of changes in accounting principles as
shown below:
Pre-Tax Tax Net Income
Effect Effect Effect
(thousands)
SFAS No. 112 $(2,534) $ 887 $(1,647)
Unbilled revenues 8,347 (2,921) 5,426
Total $ 5,813 $(2,034) $ 3,779
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
WTU adopted the provisions of SFAS No. 109 effective January 1,
1993. The implementation of SFAS No. 109 had no material effect on
WTU's earnings. As a result of this change, WTU recognized
additional accumulated deferred income taxes and corresponding
regulatory assets and liabilities to ratepayers in amounts equal
to future revenues or the reduction in future revenues required
when the income tax temporary differences reverse and are
recovered or settled in rates. As a result of a favorable
earnings history, WTU did not record any valuation allowance
against deferred tax assets at December 31, 1994 and 1993.
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WTU, together with other members of the CSW System, files a
consolidated federal income tax return and participates in a tax
sharing agreement.
Components of income taxes follow:
1994 1993 1992
Included in Operating Expenses and Taxes (thousands)
Current $10,898 $11,379 $11,797
Deferred 8,377 3,593 6,426
Deferred ITC (1,321) (1,321) (1,515)
17,954 13,651 16,708
Included in Other Income and Deductions
Current (2,998) (510) 590
Deferred -- -- --
(2,998) (510) 590
Tax Effects of Cumulative Effect of Changes
in Accounting Principles -- 2,034 --
$14,956 $15,175 $17,298
Investment tax credits deferred in prior years are included in
income over the lives of the related properties.
Total income taxes differ from the amounts computed by applying
the statutory income tax rates to income before taxes. The
reasons for the differences follow:
1994 % 1993 % 1992 %
(dollars in thousands)
Tax at statutory rates $18,313 35.0 $15,915 35.0 $17,784 34.0
Differences
Amortization of ITC (1,321) (2.5) (1,321) (2.9) (1,321) (2.5)
Other (2,036) (3.9) 581 1.3 835 1.7
$14,956 28.6 $15,175 33.4 $17,298 33.2
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The significant components of the net deferred income tax
liability follow:
1994 1993
(thousands)
Deferred Income Tax Liabilities
Depreciable utility plant $144,501 $120,015
Deferred plant costs 9,420 9,707
Income tax related regulatory liability 10,908 11,074
Other 10,120 18,963
Total Deferred Income Tax Liabilities 174,949 159,759
Deferred Income Tax Assets
Income tax related regulatory liability (14,134) (14,765)
Unamortized ITC (11,159) (11,621)
Other (6,578) --
Total Deferred Income Tax Assets (31,871) (26,386)
Net Accumulated Deferred Income Taxes - Total $143,078 $133,373
Net Accumulated Deferred Income Taxes - Noncurrent $146,146 $134,595
Net Accumulated Deferred Income Taxes - Current (3,068) (1,222)
Net Accumulated Deferred Income Taxes - Total $143,078 $133,373
3.Long-Term Debt
The mortgage indenture, as amended and supplemented, securing
first mortgage bonds issued by WTU, constitutes a direct first
mortgage lien on substantially all electric utility plant. WTU
may offer additional FMBs subject to market conditions and other
factors.
Annual Requirements
Series O FMBs have annual sinking fund requirements, which may be
satisfied by the application of net expenditures for bondable
property in an amount equal to 166-2/3% of the annual requirements
or at WTU's option, the redemption of 1% of the amount originally
issued. At December 31, 1994, the annual sinking fund
requirements for the next five years, exclusive of maturities, of
WTU's first mortgage bonds are $650,000. Pursuant to these
sinking fund requirements, WTU elected to redeem at par $650,000
Series O, FMBs in December 1994.
Dividends
WTU's mortgage indenture, as amended and supplemented, contains
certain restrictions on the payment of common stock dividends. At
December 31, 1994, $133 million of retained earnings were
available for the payment of cash dividends to its parent, CSW.
Reacquired long-term debt
Reference is made to MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and
Capital Resources, for further information related to long-term
debt, including new issues and reacquisition.
4.Preferred Stock
In July 1993, WTU redeemed 100,000 shares of its 7.25% Series,
$100 par value, Preferred Stock, for $10 million, in accordance
with mandatory and optional sinking fund provisions. The capital
required for this transaction was provided by short-term
borrowings from the CSW System money pool and internal sources.
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In July 1994, WTU redeemed the remaining 47,000 shares of its
7.25% Series, $100 par value, Preferred Stock.
5.Financial Instruments
The following methods and assumptions were used to estimate the
fair value of each class of financial instruments for which it is
practicable to estimate fair value.
Cash and temporary cash investments
The carrying amount approximates fair value because of the short
maturity of those instruments.
Advances from affiliates
The carrying amount approximates fair value because of the short
maturity of those instruments.
Long-term debt
The fair value of the WTU'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 WTU for debt of the same remaining
maturities.
Preferred stock subject to mandatory redemption
The fair value of the WTU's preferred stock subject to mandatory
redemption is estimated based on quoted market prices for the same
or similar issues or on the current rates offered to WTU for
preferred stock with the same or similar remaining redemption
provisions.
Current maturities of long-term debt
The fair value of current maturities is estimated based on quoted
market prices for the same or similar issues or the current rates
offered for long-term debt.
The estimated fair values of WTU's financial instruments follow:
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(thousands)
Cash and temporary cash
investments $ 2,501 $ 2,501 $ 706 $ 706
Current maturities of long-term debt 650 666 12,650 12,800
Advances from affiliates 46,315 46,315 36,285 36,285
Long-term debt 210,047 228,802 176,882 225,082
Preferred stock -- -- 4,648 4,671
The fair value does not affect WTU's liabilities unless the issues
are redeemed prior to their maturity dates.
6.Short-Term Financing
WTU, together with other members of the CSW System, has
established a money pool to coordinate short-term borrowings and
to make borrowings outside the money pool through CSW's issuance
of commercial paper. Money pool balances are shown as advances to
or from affiliates on the Balance Sheets. At December 31, 1994,
the CSW System had bank lines of credit aggregating $930 million
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.
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7.Benefit Plans
Defined Benefit Pension Plan
WTU, together with other members of the CSW System, maintains a
tax qualified, non-contributory defined benefit pension plan
covering substantially all employees. Benefits are based on
employees' years of credited 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 which are deductible for income tax purposes and
minimum contributions required by the ERISA. Pension plan assets
consist primarily of common stocks and short-term and intermediate-
term fixed income investments.
Contributions to the plan for the years ended December 31, 1994,
1993 and 1992 were $3.8 million, $3.9 million and $3.4 million,
respectively.
The approximate maximum number of participants in the plan during
1994 were 1,300 active employees, 500 retirees and beneficiaries
and 100 terminated employees.
The components of net periodic pension cost and the assumptions
used in accounting for pensions follow:
1994 1993 1992
(thousands)
Net Periodic Pension Cost
Service cost $ 3,082 $ 2,732 $ 2,569
Interest cost on projected
benefit obligation 8,501 7,776 7,274
Actual return on plan assets (601) (9,448) (6,242)
Net amortization and deferral (9,556) 35 (2,836)
$ 1,426 $ 1,095 $ 765
Discount rate 8.25% 7.75% 8.50%
Long-term compensation increase 5.46% 5.46% 5.96%
Return on plan assets 9.50% 9.50% 9.50%
At December 31, 1994, the plan's net assets were approximately
equal to the total actuarial present value of the accumulated
benefit obligation. At December 31, 1993 the plan's net
assets exceeded the total actuarial present value of the
accumulated benefit obligation. No reconciliation of the funding
status of the plan is presented because such information is
unavailable.
Health and Welfare Plans
WTU had medical, dental, group life insurance, dependent life
insurance, and accidental death and dismemberment plans for
substantially all active WTU employees during 1994. The
contributions, recorded on a pay-as-you-go basis for the years
ended December 31, 1994 and 1993 were approximately $2.7 million
and $3.5 million, respectively. Effective January 1993, WTU's
method of providing health benefits was modified to include such
benefits as preferred provider options, managed prescription drug
and mail-order program and a mental health and substance abuse
program in addition to the self-insured indemnity plans.
Postretirement Benefits Other Than Pensions
WTU adopted SFAS No. 106 January 1, 1993. The effect on operating
expense in 1993 was $1.9 million. WTU is amortizing its
transition obligation over twenty years, with eighteen years
remaining. In prior years, these benefits were accounted for on a
pay-as-you-go basis.
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The components of net periodic postretirement benefit cost follow:
1994 1993
(thousands)
Net Periodic Postretirement
Benefit Cost
Service cost $1,233 $1,157
Interest cost on APBO 2,559 2,316
Actual return on plan assets (113) (104)
Amortization of transition
obligation 1,225 1,225
Net amortization and deferral (418) (296)
$4,486 $4,298
A reconciliation of the funded status of the plan to the amounts
recognized on the consolidated balance sheets follow:
December 31,
1994 1993
APBO (thousands)
Retirees $ 19,703 $ 18,722
Other fully eligible participants 4,764 4,624
Other active participants 7,519 8,758
Total APBO 31,986 32,104
Plan assets at fair value (9,636) (6,064)
APBO in excess of plan assets 22,350 26,040
Unrecognized transition obligation (22,047) (23,272)
Unrecognized gain or (loss) 91 (2,374)
Accrued/(Prepaid) Cost $ 394 $ 394
The following assumptions were used in accounting for SFAS No.
106:
1994 1993
Discount rate 8.25% 7.75%
Return on plan assets 9.50% 9.00%
Tax rate for taxable trusts 39.60% 39.60%
Health Care Cost Trend Rate Assumptions
Pre-65 Participants: 1994 Rate of 11.75% grading down .75% per
year to an ultimate rate of 6.5% in 2001.
Post-65 Participants: 1994 Rate of 11.25% 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, 1994 by $3.5 million and increase the aggregate of
the service and interest costs components on net postretirement
benefits by $.5 million.
8.Jointly Owned Electric Utility Plant
WTU has a joint ownership agreement with other members of the CSW
System and other non-affiliated entities. Such agreements provide
for the joint ownership and operation of Oklaunion Power Station.
Each participant provided financing for its share of the project,
which was placed in service in December 1986. The statements of
income reflect WTU's portion of operating costs associated with
jointly owned plant in service. WTU's share is 370 MW or a 54.7%
interest in the generating station. WTU's total investment,
including AFUDC is $280 million and accumulated depreciation at
December 31, 1994 is $59 million.
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9.Litigation and Regulatory Proceedings
Rate Proceeding - Docket No. 13369
On August 25, 1994, WTU filed a petition with the Texas Commission
and with cities with original jurisdiction to review WTU's rates,
proposed an interim across-the-board base rate reduction of 3.25%
or, approximately $5.7 million, effective October 1, 1994, and
sought until February 28, 1995, the time to develop and file a
RFP. WTU also requested the ability to "true-up", back to October
1, 1994, any difference in revenue requirements upon final order
of the Texas Commission, and proposed that any increases over the
pre-October 1, 1994, base rates be implemented prospectively on
the effective date of the final order.
As discussed below, WTU's fuel reconciliation was consolidated
with this proceeding in September 1994. Reconcilable fuel costs
during the reconciliation period were approximately $300 million.
At June 30, 1994, the fuel cost under-recovery totaled
approximately $5.1 million, including interest. At December 31,
1994, this amount had become an over-recovery of approximately
$0.2 million. WTU is not seeking a change in fuel factors.
On February 28, 1995, WTU filed with the Texas Commission and
cities with original jurisdiction the RFP which indicates a
revenue deficiency of approximately $14.5 million. However, WTU
simultaneously filed with the parties a settlement proposal to
reduce overall base rate revenue by 3.25%, effective October 1,
1994, an annual impact in the rate year beginning January 1, 1996
of approximately $5.9 million. The settlement proposal reflects
WTU's desire to maintain competitive rates, recognizes the
importance of competitive rates in the changing electric service
marketplace, and demonstrates WTU's strong commitment to the long-
term success of WTU and its customers.
Unless a settlement accelerates the schedule, WTU anticipates
hearings in mid-1995 with a final order in the fourth quarter of
1995. Management cannot predict the outcome of the rate
proceeding, the fuel reconciliation, or the settlement proposal,
but believes that the ultimate resolution of these matters will
not have a material adverse effect on WTU's results of operations
or financial condition.
Fuel Reconciliation - Docket No. 13172
On June 30, 1994, WTU filed a petition with the Texas Commission
to reconcile fuel costs for the period January 1991 through
February 1994. Subsequently, in September 1994, this fuel
reconciliation proceeding was consolidated into Docket No. 13369
described above, and the reconciliation period was extended
through June 1994.
Rate Case Proceeding - Docket No. 7510
In November 1987, the Texas Commission issued a final order in
WTU's retail rate case providing for WTU to receive an annual
increase in base retail revenues of $34.9 million. Rates
reflecting the final order were implemented in December 1987.
WTU, along with certain intervenors in the retail rate proceeding,
appealed the Texas Commission's final order to the District Court
seeking reversal of various provisions of the final order,
including the inclusion of deferred accounting in rate base.
The appeals were consolidated and in September 1988, the District
Court affirmed the final order of the Texas Commission. In
November 1988, certain intervenors filed appeals of the District
Court's judgment with the Court of Appeals. In February 1990, the
Court of Appeals ruled that an intervenor had improperly been
excluded from presenting its appeal to the District Court,
reversed the District Court's judgment and remanded the case to
the District Court for further proceedings.
In October 1992, the District Court heard the remanded appeals of
the final order of the Texas Commission and in March 1993 issued
an order affirming the Texas Commission's order in all material
respects with the single exception of the inclusion of deferred
Oklaunion carrying costs in rate base. In its treatment of
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deferred costs, the District Court followed a then-current opinion
of the Court of Appeals which precluded recovery of deferred post-
in-service carrying costs. In April 1993, WTU and other parties
filed appeals, and oral argument was held on the appeals in
December 1993 on the non-deferred accounting issues. With respect
to the deferred accounting issues, the parties recognized certain
Supreme Court of Texas decisions regarding other deferred
accounting cases would be influential in WTU's case.
In June 1994, the Supreme Court of Texas issued its opinion in the
three other cases involving deferred accounting holding that the
Texas Commission has the authority to allow deferred accounting
treatment during the deferral period, including deferred post-in-
service carrying costs. The Supreme Court of Texas upheld the
Court of Appeals in all respects except it reversed the Court of
Appeals to the extent it disallowed carrying costs deferrals and
remanded to the Court of Appeals for consideration of the
unresolved arguments of the improperly excluded intervenor.
Motions for rehearing were filed by certain parties which were
denied by the Supreme Court of Texas. These rulings influenced
the Court of Appeals' decision in WTU's rate case appeals, as
described below.
On February 15, 1995, the Court of Appeals affirmed all aspects of
the District Court judgment relating to the Texas Commission's
allowance of non-Oklaunion depreciation rates and the surcharge of
rate case expenses, reversed the District Court's judgment
relating to the exclusion of deferred Oklaunion carrying costs in
rate base, and remanded the cause to the Texas Commission to
reexamine the issue of deferred costs in light of the remand of
Docket No. 7289, as described below. However, on March 3, 1995,
WTU filed a motion for rehearing at the Court of Appeals seeking
clarification of certain aspects of its order and arguing that the
Court of Appeals erred in remanding the case to the Texas
Commission for it to determine to what extent deferred costs are
necessary to preserve WTU's financial integrity because the issue
has been waived since it was not briefed or argued to the Court of
Appeals. WTU expects other parties may also file motions for
rehearing.
WTU's motion for rehearing may, if granted, prevent further review
of financial integrity issues with respect to deferred accounting
in any remand of Docket No. 7510. If a broader remand is
permitted and if the Texas Commission concludes in Docket No. 7289
that deferred accounting was necessary to preserve WTU's financial
integrity during the deferral period, the Texas Commission must
decide to what extent the deferred Oklaunion costs, including
carrying costs, were necessary to preserve WTU's financial
integrity. If WTU's deferred accounting treatment is ultimately
reversed or is substantially reduced, WTU could experience a
material adverse impact on its results of operations. While
management can give no assurances as to the outcome of the
remanded proceeding or the motion for rehearing, management
believes that 100 percent of the Oklaunion deferred costs will be
determined by the Texas Commission to have been necessary to
preserve WTU's financial integrity during the deferral period so
that there will be no material adverse effect on WTU's results of
operations or financial condition.
Deferred Accounting - Docket No. 7289
WTU received approval from the Texas Commission in September 1987
to defer operating expenses and carrying costs associated with
Oklaunion incurred subsequent to its December 1986 commercial
operation date until December 1987 (the deferral period) when
retail rates including Oklaunion in WTU's rate base became
effective. WTU has recorded approximately $32 million of
Oklaunion deferred costs, of which $25 million are carrying costs.
The deferred costs are being recovered and amortized over the
remaining life of the plant. In November 1987, OPUC filed an
appeal in the District Court challenging the Texas Commission's
final order authorizing WTU to defer the costs associated with
Oklaunion. In October 1988, the District Court affirmed the final
order of the Texas Commission. In December 1988, OPUC filed an
appeal of the District Court judgment in the Court of Appeals. In
September 1990, the Court of Appeals upheld the District Court's
affirmance of the Texas Commission's final order and in October
1990, OPUC filed a motion for rehearing of the Court of Appeals'
decision, which was denied in November 1990. On further appeal,
the Supreme Court heard oral argument in September 1993, in WTU's
case as well as three other cases involving deferred accounting
2-184
and in June 1994 issued its opinions in these cases affirming the
Texas Commission's authority to allow deferred accounting
treatment, but establishing a financial integrity standard rather
than the measurable harm standard used by the Texas Commission.
In October 1994, the Supreme Court of Texas issued a mandate
remanding WTU's deferred accounting case to the Texas Commission.
While no schedule has yet been established for the proceedings on
remand at the Texas Commission, this remand may be considered in
tandem with WTU's pending rate case, Docket No. 13369. In the
remanded proceeding, the Texas Commission must make a formal
finding that the deferral of Oklaunion costs was necessary to
prevent WTU's financial integrity during the deferral period from
being jeopardized.
If WTU's deferred accounting treatment is ultimately reversed and
not favorably resolved, WTU could experience a material adverse
impact on its results of operations. While management cannot
predict the ultimate outcome of these proceedings, management
believes that WTU's deferred accounting will be ultimately
sustained by the Texas Commission on the basis of the financial
integrity standard set forth by the Supreme Court of Texas, so
that there will be no material adverse effect on WTU's results of
operations or financial condition.
FERC Order
On April 4, 1994, the FERC issued an order pursuant to section 211
of the Federal Power Act forcing a regional utility to transmit
power to Tex-La on behalf of WTU. The order was one of the first
issued by FERC under that provision, which was added by the Energy
Policy Act to increase competition in wholesale power markets. On
December 1, 1994, the FERC issued an order requiring a regional
utility to provide this transmission service at a cost which was
acceptable to Tex-La. The FERC also ordered the same regional
utility to enter into an interconnection and remote control area
load agreement with WTU within 30 days. This agreement was
executed on January 3, 1995. On January 5, 1995, WTU began
selling 92 MW of power and energy to Tex-La. Tex-La has a peak
requirement of approximately 120 MWs. WTU will serve Tex-La until
facilities are completed to connect Tex-La to SWEPCO, at which
time SWEPCO will provide 85 MW and WTU will retain 35 MW of the
Tex-La electric load.
Other
WTU 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 WTU's results of operations or financial condition.
10. Commitments and Contingent Liabilities
Construction
It is estimated that WTU will spend approximately $37 million in
construction expenditures during 1995. Substantial commitments
have been made in connection with this capital expenditure
program.
Fuel
To supply a portion of its fuel requirements WTU has entered into
various commitments for the procurement of fuel. WTU has a
sale/leaseback agreement with Transok, an affiliated company, for
full capacity use of a natural gas pipeline to WTU's Ft. Phantom
generating plant. The lease agreement also provides for full
capacity use of Transok's natural gas pipelines serving WTU's San
Angelo and Oak Creek generating plants. The initial terms of the
agreement are for twelve years with renewable options thereafter.
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11. Quarterly Information (Unaudited)
The following unaudited quarterly information includes, in the
opinion of management, all adjustments necessary for a fair
presentation of such amounts.
Quarter Ended Operating Operating Net
Revenues Income Income
1994 (thousands)
March 31 $ 83,319 $ 8,487 $ 3,546
June 30 83,016 12,958 8,192
September 30 109,348 27,987 23,271
December 31 67,308 5,331 2,357
$342,991 $54,763 $37,366
1993
March 31 $ 73,109 $ 9,540 $ 7,898
June 30 86,973 14,060 9,086
September 30 109,897 24,172 19,490
December 31 75,466 (1,196) (6,178)
$345,445 $45,576 $30,296
Information for quarterly periods is affected by seasonal
variations in sales, rate changes, timing of fuel expense recovery
and other factors.
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Report of Independent Public Accountants
To the Stockholders and Board of Directors of West Texas Utilities
Company:
We have audited the accompanying balance sheets and statements
of capitalization of West Texas Utilities Company (a Texas
corporation and a wholly-owned subsidiary of Central and South West
Corporation) as of December 31, 1994 and 1993, and the related
statements of income, retained earnings and cash flows for each of
the three years in the period ended December 31, 1994. These
financial statements are the responsibility of WTU'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
West Texas Utilities Company as of December 31, 1994 and 1993, and
the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1994, in conformity
with generally accepted accounting principles.
In 1993, as discussed in NOTE 1, WTU 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
Schedule II 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. This schedule 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 LLP
Dallas, Texas
February 13, 1995
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Report of Management
Management is responsible for the preparation, integrity and
objectivity of the financial statements of West Texas Utilities
Company as well as other information contained in this Annual 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 Annual Report is
consistent with that in the financial statements.
The financial statements have been audited by the independent
accounting firm, Arthur Andersen LLP, which was given unrestricted
access to all financial records and related data, including minutes
of all meetings of shareholders, the board of directors and
committees of the board. WTU believes that representations made to
the independent auditors during their audit were valid and
appropriate. Arthur Andersen LLP's audit report is presented
elsewhere in this report.
WTU maintains a system of internal controls to provide
reasonable assurance that transactions are executed in accordance
with management's authorization, that the financial statements are
prepared in accordance with generally accepted accounting principles
and that the assets of the companies are properly safeguarded against
unauthorized acquisition, use or disposition. The system includes a
documented organizational structure and division of responsibility,
established policies and procedures including a policy on ethical
standards which provides that WTU will maintain the highest legal and
ethical standards, and the careful selection, training and
development of our employees.
Internal auditors continuously monitor the effectiveness of the
internal control system following standards established by the
Institute of Internal Auditors. Actions are taken by management to
respond to deficiencies as they are identified. The board, operating
through its audit committee, which is comprised entirely of directors
who are not officers or employees of WTU provides oversight to the
financial reporting process.
Due to the inherent limitations in the effectiveness of internal
controls, no internal control system can provide absolute assurance
that errors will not occur. However, management strives to maintain
a balance, recognizing that the cost of such a system should not
exceed the benefits derived.
WTU believes that, in all material respects, its system of
internal controls over financial reporting and over safeguarding of
assets against unauthorized acquisition, use or disposition
functioned effectively during 1994.
Glenn Files R. Russell Davis
President and CEO - WTU Controller - WTU
2-188
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
None.
3-1
PART III
CPL, PSO, SWEPCO and WTU
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 REGISTRANTS.
CSW
CSW has filed with the SEC its Notice of Annual Meeting of
Stockholders and Proxy Statement relating to its 1995 Annual Meeting
of Stockholders. The information required by ITEM 10, other than
with respect to certain information regarding the executive officers
of CSW which is included in ITEM 1. BUSINESS - Executive Officers
of the Registrant, is hereby incorporated by reference to pages 3-5
and 8 of such Proxy Statement.
CPL, PSO, SWEPCO AND WTU
(a) The following is a list of directors of each of the
Electric Operating Companies, together with certain information with
respect to each of them:
Name, Age, Principal Year
Occupation, Business Experience First Became
and Other Directorships Director
CPL
E. R. BROOKS. . . . . . . . . . . . . . . . . . AGE - 57 1991
Chairman, President and CEO of CSW since 1991.
President of CSW from 1990 to 1991. President and
COO of CSW from January 1990 to September 1990.
Director of CSW and each of its subsidiaries.
Director of Hubbell, Inc., Orange, Connecticut.
Trustee of Baylor University Medical Center, Dallas,
Texas and Hardin Simmons University, Abilene, Texas.
ROBERT R. CAREY. . . . . . . . . . . . . . AGE - 57 1989
President and CEO of CPL since 1990. Executive Vice
President and COO of CPL from 1989 to 1990. Director
of NationsBank, Corpus Christi, Texas.
RUBEN M. GARCIA. . . . . . . . . . . . . . AGE - 63 1981
President or principal of several firms engaged
primarily in construction and land development in the
Laredo, Texas area.
DAVID L. HOOPER. . . . . . . . . . . . . . .AGE - 39 1994
Vice President, Marketing and Business Development of
CPL since 1994. Director of Marketing and Business
Development of CSWS from 1993 to 1994. Director of
Marketing and Business Development of CPL from 1991
to 1993. Area manager of CPL from 1990 to 1991.
Director of Corporate Communications of CPL from 1988
to 1990.
HARRY D. MATTISON. . . . . . . . . . . . AGE - 58 1994
Executive Vice President of CSW since 1990 and CEO of
CSWS since 1993. COO of CSW from 1990 to 1993.
President and CEO of SWEPCO from 1988 to 1990.
Director of CSW and each of CSW's wholly-owned
subsidiaries.
3-2
Name, Age, Principal Year
Occupation, Business Experience First Became
and Other Directorships Director
ROBERT A. McALLEN. . . . . . . . . . . . AGE - 60 1983
Robert A. McAllen, Insurance Agency, Weslaco, Texas.
PETE MORALES, JR. . . . . . . . . . . . . .AGE - 54 1990
President and General Manager of Morales Feed Lots,
Inc., Devine, Texas. Director of The Bank of Texas,
Devine, Texas.
S. LOYD NEAL, JR. . . . . . . . . . . . . . AGE - 57 1990
President of Hilb, Rogal and Hamilton Company of
Corpus Christi, an insurance agency, Corpus Christi,
Texas. Director of Bay Area Medical Center, Corpus
Christi, Texas.
JIM L. PETERSON. . . . . . . . . . . . . . .AGE - 59 1989
President and CEO of Whataburger, Inc., Corpus
Christi, Texas. President of Peterson Ranch and
Cattle Company, Goliad, Texas. President and CEO of
Bojangles Restaurants Inc., Charlotte, North
Carolina. Director of Mercantile Bank of Corpus
Christi and Brownsville, Texas.
H. LEE RICHARDS. . . . . . . . . . . . . . .AGE - 61 1987
Chairman of the Board of Hygeia Dairy Company,
Harlingen, Texas.
MELANIE J. RICHARDSON. . . . . . . . . AGE - 38 1993
Vice President, Administration of CPL since 1993.
Treasurer of CPL from 1992 to 1994. Vice President,
Corporate Services of CPL from 1992 to 1993.
Director of Internal Audits of CPL from 1991 to 1992.
Manager of Personnel Services of CPL from 1986 to
1991.
J. GONZALO SANDOVAL. . . . . . . . . . AGE - 46 1992
Vice President, Operations/Engineering of CPL since
1993. Vice President, Regional Operations of CPL
from 1992 to 1993. Vice President, Corporate
Services of CPL from 1991 to 1992. General Manager
of the Southern Region from 1988 to 1991.
GERALD E. VAUGHN. . . . . . . . . . . . . AGE - 52 1993
Vice President, Nuclear of CSWS since 1994. Vice
President, Nuclear Affairs of CPL since 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.
Each of the directors and executive officers of CPL is elected
to hold office until the first meeting of CPL's Board of Directors
after the 1995 Annual Meeting of Stockholders. CPL's 1995 Annual
Meeting of Stockholders is presently scheduled to be held on April
13, 1995. All outside directors have engaged in their principal
occupations listed above for a period of more than five years,
unless otherwise indicated.
3-3
Name, Age, Principal Year
Occupation, Business Experience First Became
and Other Directorships Director
PSO
E. R. BROOKS. . . . . . . . . . . . . . . . . . AGE - 57 1991
Chairman, President and CEO of CSW since 1991.
President of CSW from 1990 to 1991. President and
COO of CSW from January 1990 to September 1990.
Director of CSW and each of its subsidiaries.
Director of Hubbell, Inc., Orange, Connecticut.
Trustee of Baylor University Medical Center, Dallas,
Texas and Hardin Simmons University, Abilene, Texas.
HARRY A. CLARKE. . . . . . . . . . . . . . . . . . . . . AGE - 66 1972
HAC Investments, Afton, Oklahoma.
PAUL K. LACKEY, JR. . . . . . . . . . . . . . . . . . . . AGE - 51 1992
Consultant, Flint Industries, Inc., a construction,
electronics manufacturing, and environmental services
company, Tulsa, Oklahoma. Advisory Director of Bank
IV-Tulsa, Tulsa, Oklahoma.
PAULA MARSHALL-CHAPMAN . . . . . . . . . . . . . . . . . .AGE - 41 1991
General Partner/CEO of Bama Pie Ltd., a baked goods
produce company, Tulsa, Oklahoma.
HARRY D. MATTISON. . . . . . . . . . . . .AGE - 58 1994
Executive Vice President of CSW since 1990 and CEO of
CSWS since 1993. COO of CSW from 1990 to 1993.
President and CEO of SWEPCO from 1988 to 1990.
Director of CSW and each of CSW's wholly-owned
subsidiaries.
WILLIAM R. McKAMEY . . . . . . . . . . . . . . . . . . . .AGE - 48 1993
Vice President, Marketing and Business Development of
PSO since 1993. Director of Marketing and Business
Development of CSW from 1992 to 1993. Director of
Marketing of SWEPCO from 1990 to 1992.
MARY M. POLFER . . . . . . . . . . . . . . . . . . . . . .AGE - 50 1991
Vice President, Administration of PSO since 1993.
Vice President, Finance of PSO from 1990 to 1993.
Director Corporate Projects from 1987 to 1990,
Farmland Industries, Inc., a federated cooperative,
Kansas City, Missouri.
DR. ROBERT B. TAYLOR, JR. . . . . . . . . . . . . . . . . AGE - 66 1975
Dentist, Okmulgee, Oklahoma.
ROBERT L. ZEMANEK . . . . . . . . . . . . . . . . . . . . AGE - 45 1990
President and CEO of PSO since 1992. Executive Vice
President of PSO from 1990 to 1992. Vice President,
Corporate Services of PSO from 1989 to 1990.
3-4
Name, Age, Principal Year
Occupation, Business Experience First Became
and Other Directorships Director
WALDO J. ZERGER, JR. . . . . . . . . . . . . . . . . . . .AGE - 48 1991
Vice President, Operations and Engineering of PSO
since 1994. Vice President of Division Operations of
PSO from 1990 to 1994.
Each of the directors and executive officers of PSO is elected
to hold office until the first meeting of PSO's Board of Directors
after the 1995 Annual Meeting of Stockholders. PSO's 1995 Annual
Meeting of Stockholders is presently scheduled to be held on April
18, 1995. All outside directors have engaged in their principal
occupations listed above for a period of more than five years,
unless otherwise indicated.
SWEPCO
RICHARD H. BREMER . . . . . . . . . . . . . . . . . . . . AGE - 46 1989
President and CEO of SWEPCO since 1990. Vice
President, Operations of SWEPCO from 1989 to 1990.
Director of Commercial National Bank, Shreveport,
Louisiana. Director of Deposit Guaranty Corporation,
Jackson, Mississippi.
E. R. BROOKS. . . . . . . . . . . . . . . . . . AGE - 57 1991
Chairman, President and CEO of CSW since 1991.
President of CSW from 1990 to 1991. President and
COO of CSW from January 1990 to September 1990.
Director of CSW and each of its subsidiaries.
Director of Hubbell, Inc., Orange, Connecticut.
Trustee of Baylor University Medical Center, Dallas,
Texas and Hardin Simmons University, Abilene, Texas.
JAMES E. DAVISON . . . . . . . . . . . . . AGE - 57 1993
Sole Proprietor of Paul M. Davison Petroleum
Products. President and Chief Executive Officer of
Davison Transport, Inc. and Davison Terminal
Services, Inc. Advisory Board member of Heritage
Financial Group. All of the above entities are
located in Ruston, Louisiana.
AL P. EASON, JR. . . . . . . . . . . . . . . . . . . . . .AGE - 69 1975
Retired as Chairman and CEO of the First Federal
Savings and Loan Association of Fayetteville,
Arkansas in 1990. President, Eason and Company, a
general insurance company, Fayetteville, Arkansas.
W. J. GOOGE, JR. . . . . . . . . . . . . . . . . . . . . .AGE - 52 1990
Vice President, Administration of SWEPCO since 1993.
Vice President, Corporate Services of SWEPCO from
1990 to 1993. Vice President, Personnel, Safety and
Insurance of SWEPCO from 1984 to 1990.
DR. FREDERICK E. JOYCE . . . . . . . . . . . . . . . . . .AGE - 60 1990
Physician. President of Chappell-Joyce Pathology
Association, P.A., Texarkana, Texas. President of
Doctors Diagnostic Laboratory, Inc., Texarkana,
Texas. Director of State First National Bank and
State First Financial Corporation, Texarkana,
Arkansas. Director of First Commercial Corporation,
Little Rock, Arkansas.
3-5
Name, Age, Principal Year
Occupation, Business Experience First Became
and Other Directorships Director
MICHAEL H. MADISON . . . . . . . . . . . . . . . . . . . .AGE - 46 1992
Vice President, Operations and Engineering of SWEPCO
since 1993. Vice President, Engineering and
Production of SWEPCO from 1992 to 1993. Vice
President, Corporate Services of WTU from 1990 to
1992. Eastern Division Manager of PSO in 1990.
HARRY D. MATTISON. . . . . . . . . . . . .AGE - 58 1994
Executive Vice President of CSW since 1990 and CEO of
CSWS since 1993. COO of CSW from 1990 to 1993.
President and CEO of SWEPCO from 1988 to 1990.
Director of CSW and each of CSW's wholly-owned
subsidiaries.
MARVIN R. McGREGOR. . . . . . . . . . . . . . . . . . . . AGE - 48 1990
Vice President, Marketing and Business Development of
SWEPCO since 1990.
WILLIAM C. PEATROSS . . . . . . . . . . . . . . . . . . . AGE - 51 1990
President of Caddo Abstract and Title Co., Inc.,
Partner-Baucum, Hamilton and Peatross, a law firm;
Partner-Kernmass-X Oil Company, Partner-Coastal Land
Association, Director of Commercial National Bank.
All of the above entities are located in Shreveport,
Louisiana.
JACK L. PHILLIPS . . . . . . . . . . . . . . . . . . . . .AGE - 70 1986
Owner of Jack L. Phillips Oil & Gas Exploration and
Production, Gladewater, Texas. Director of Longview
National Bank, Longview, Texas.
Each of the directors and executive officers of SWEPCO is
elected to hold office until the first meeting of SWEPCO's Board of
Directors after the 1995 Annual Meeting of Stockholders. SWEPCO's
1995 Annual Meeting of Stockholders is presently scheduled to be
held on April 12, 1995. All outside directors have engaged in their
principal occupations listed above for a period of more than five
years, unless otherwise indicated.
WTU
RICHARD F. BACON . . . . . . . . . . . . . . . . . . . . .AGE - 68 1980
Retired President and CEO of Merchants, Inc.
Companies, a freight common carrier, Abilene, Texas.
C. HARWELL BARBER . . . . . . . . . . . . . . . . . . . . AGE - 68 1990
Chairman of Rita Barber, Inc., a burial clothing
company, Abilene, Texas.
E. R. BROOKS. . . . . . . . . . . . . . . . . . AGE - 57 1980
Chairman, President and CEO of CSW since 1991.
President of CSW from 1990 to 1991. President and
COO of CSW from January 1990 to September 1990.
Director of CSW and each of its subsidiaries.
Director of Hubbell, Inc., Orange, Connecticut.
Trustee of Baylor University Medical Center, Dallas,
Texas and Hardin Simmons University, Abilene, Texas.
3-6
Name, Age, Principal Year
Occupation, Business Experience First Became
and Other Directorships Director
PAUL J. BROWER . . . . . . . . . . . . . . . . . . . . . AGE - 46 1991
Vice President, Marketing and Business Development of
WTU since 1991. Division Manager of PSO from 1990 to
1991 and Corporate Sales Manager of PSO from 1986 to
1990.
T. D. CHURCHWELL. . . . . . . . . . . . . . . . . . . . .AGE - 50 1994
Executive Vice President of WTU since 1994. Vice
President, Corporate Services of CSWS from 1991 to
1993. Central Region Manager of CPL from 1989 to
1991.
GLENN FILES . . . . . . . . . . . . . . . . . . . . . . .AGE - 47 1991
President and CEO of WTU since 1992. Executive Vice
President of WTU from 1991 to 1992. Vice President,
Marketing and Business Development of CPL from 1990
to 1991. Director of Corporate Planning of PSO from
1988 to 1990. Director of First National Bank of
Abilene, Texas.
HARRY D. MATTISON. . . . . . . . . . . . AGE - 58 1994
Executive Vice President of CSW since 1990 and CEO of
CSWS since 1993. COO of CSW from 1990 to 1993.
President and CEO of SWEPCO from 1988 to 1990.
Director of CSW and each of CSW's wholly-owned
subsidiaries.
TOMMY MORRIS . . . . . . . . . . . . . . . . . . . . . . AGE - 60 1976
Independent insurance agent, Abilene, Texas.
DIAN G. OWEN . . . . . . . . . . . . . . . . . . . . . . AGE - 55 1994
Chairman of Owen Healthcare, Inc., hospital services,
Abilene, Texas. Director of First National Bank of
Abilene, Abilene, Texas. Director of First Financial
Bankshares, Inc., Abilene, Texas.
JAMES M. PARKER . . . . . . . . . . . . . . . . . . . . .AGE - 64 1987
President and CEO of J. M. Parker and Associates,
Inc., an investment company, Abilene, Texas.
Director of First Financial Bankshares, Inc. and
First National Bank of Abilene, Abilene, Texas.
DENNIS M. SHARKEY . . . . . . . . . . . . . . . . . . . .AGE - 50 1994
Vice President, Administration of WTU since 1994.
Vice President, Finance and Director of SWEPCO from
1990 to 1993. Vice President and Corporate Secretary
of WTU from 1989 to 1990.
F. L. STEPHENS . . . . . . . . . . . . . . . . . . . . . AGE - 57 1980
Chairman and CEO of Town & Country Food Stores, Inc.,
San Angelo, Texas. Director of First National Bank at
Lubbock, Lubbock, Texas. Director of Norwest Texas,
Lubbock, Texas.
DONALD A. WELCH . . . . . . . . . . . . . . . . . . . . .AGE - 55 1982
Vice President, Operations and Engineering of WTU
since 1993. Vice President, Division Operations of
WTU from 1991 to 1992. Vice President, District
Operations of WTU from 1990 to 1991.
3-7
Each of the directors and executive officers of WTU is elected
to hold office until the first meeting of WTU's Board of Directors
after the 1995 Annual Meeting of Stockholders. WTU's 1995 Annual
Meeting of Stockholders is presently scheduled to be held on March
28, 1995. All outside directors have engaged in their 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 registrants, together with certain information
with respect to each of them:
Year First
Name, Age, Principal Elected to
Occupation, Business Experience Present Position
CPL, PSO, SWEPCO and WTU
SHIRLEY S. BRIONES . . . . . . . . . . . . . . . . . . . AGE - 43 1994
Treasurer of CPL, PSO, SWEPCO, WTU and CSWS since
1994. Manager, Budgets and Accounting Systems of CPL
from 1992 to 1994. Supervisor of Accounting of CPL
from 1990 to 1992. Supervisor, Financial Planning of
CPL from 1988 to 1990.
R. RUSSELL DAVIS . . . . . . . . . . . . . . . . . . . . AGE - 38 1994
Controller of CPL, WTU, SWEPCO and CSWS since 1994.
Controller of PSO since 1993. Assistant Controller
of CSW from 1992 to 1993. Assistant Controller of
CSWS from 1991 to 1992. Business Improvement Project
Manager of WTU in 1991. Manager of Financial
Reporting of WTU from 1988 to 1991.
CPL
DAVID P. SARTIN. . . . . . . . . . . . . . . . . . . . . AGE - 38 1991
Director of Planning and Analysis of CPL since 1994.
Secretary of CPL since 1991. Controller and
Secretary of CPL from 1991 to 1994. Controller of
WTU from 1989 to 1991.
PSO
BETSY J. POWERS . . . . . . . . . . . . . . . . . . . . .AGE - 59 1989
Secretary of PSO since 1989.
SWEPCO
ELIZABETH D. STEPHENS . . . . . . . . . . . . . . . . . .AGE - 39 1988
Secretary of SWEPCO since 1988.
WTU
MARTHA MURRAY . . . . . . . . . . . . . . . . . . . . . .AGE - 49 1992
Secretary of WTU since 1992. Previously a senior
secretary at WTU.
3-8
ITEM 11. EXECUTIVE COMPENSATION.
Cash and Other Forms of Compensation
CSW
Information required by ITEM 11 is hereby incorporated by
reference to pages 15-19 of CSW's Proxy Statement.
CPL, PSO, SWEPCO and WTU
The following table sets forth the aggregate cash and other
compensation for services rendered for the fiscal years of 1994,
1993, and 1992 paid or awarded by each registrant to the CEO and
each of the four most highly compensated Executive Officers, other
than the CEO, whose salary and bonus exceeds $100,000, and up to two
additional individuals, if any, not holding an executive officer
position as of year-end but who held such a position at any time
during the year, and whose compensation for the year would have
placed them among the four most highly compensated executive
officers.
Summary Compensation Table
Long Term Compensation
Annual Compensation Awards Payouts
CSW
Other CSW Securities
Annual Restricted Underlying All Other
Compen- Stock Options/ LTIP Compen-
Name and Salary Bonus sation Award(s) SARs Payouts sation
Principal Position Year ($) ($)(1) ($)(2) ($)(1)(3) (#) ($) ($) (4)
CPL
Robert R. Carey, 1994 293,344 -- 516 -- 15,901 -- 23,763
President and CEO 1993 272,893 32,943 9,548 33,608 -- -- 27,587
1992 248,384 47,150 5,718 47,151 12,431 -- 27,498
J. Gonzalo Sandoval, 1994 129,932 -- 989 -- 4,010 -- 5,847
Vice President, Operations 1993 120,327 7,878 4,963 7,986 -- -- 4,221
and Engineering (2) 1992 111,107 13,583 27,649 -- 2,916 -- 3,333
Melanie J. Richardson, Vice 1994 122,230 -- 454 -- 4,010 -- 3,667
President, Administration 1993 109,228 8,399 1,598 -- -- -- 3,277
1992 69,161 2,561 852 -- -- -- 2,075
C. Wayne Stice, Assistant 1994 112,427 -- 1,095 -- -- -- 217
to the President (5) 1993 119,628 7,664 2,279 -- -- -- 1,049
1992 112,854 8,403 2,486 -- 2,295 -- --
B. W. Teague, Vice President, 1994 49,039 -- 12,705 -- -- -- 2,207
Marketing and Business 1993 128,308 5,085 4,169 5,143 -- -- 5,309
Development (2) (5) 1992 122,200 9,905 1,885 9,874 3,135 -- 5,499
PSO
Robert L. Zemanek, 1994 262,962 -- 2,981 -- 14,792 -- 17,472
President and CEO 1993 238,269 24,051 3,927 24,503 -- -- 26,835
1992 197,519 12,255 561 12,292 10,638 -- 7,825
Waldo J. Zerger, Jr., Vice 1994 138,108 -- 2,634 -- 4,010 -- 12,847
President, Operations and 1993 128,866 4,988 2,571 5,052 -- -- 5,347
Engineering 1992 121,097 11,874 875 11,838 3,135 -- 5,449
Mary M. Polfer, Vice 1994 135,820 -- 3,417 -- 4,010 -- 8,439
President, Administration 1993 127,403 4,635 3,071 4,179 -- -- 3,518
1992 120,835 13,248 670 15,320 -- -- 3,854
William R. McKamey, Vice 1994 119,900 -- 2,401 -- 4,010 -- 6,074
President, Marketing and 1993 52,953 -- 33,903 -- -- -- 4,487
Business Development (2) (5) 1992 -- -- -- -- -- -- --
E. Michael Williams, Vice 1994 5,769 -- -- -- 4,010 -- --
President, Engineering and 1993 120,120 5,385 3,359 5,475 -- -- 4,109
Production (2) (5) 1992 48,231 -- 26,580 -- 3,135 -- 3,388
3-9
Summary Compensation Table (continued)
Long Term Compensation
Annual 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 ($) ($)(1) ($)(2) ($)(1)(3) (#) ($) ($)(4)
SWEPCO
Richard H. Bremer, 1994 277,359 50,000 13,978 -- 15,901 -- 22,235
President and CEO (2) 1993 263,833 36,017 13,206 36,724 -- -- 24,088
1992 239,167 51,646 45,720 51,685 12,431 -- 24,065
Marvin R. McGregor, 1994 133,773 -- 4,292 -- 4,010 -- 6,695
Vice President, Marketing 1993 126,620 8,196 5,769 8,319 -- -- 5,197
and Business Development 1992 114,340 10,064 3,815 10,075 3,135 -- 5,145
Michael H. Madison, Vice 1994 131,621 -- 3,625 -- 4,010 -- 6,600
President, Operating and 1993 126,215 7,140 30,742 7,260 -- -- 5,188
Engineering (2) (5) 1992 51,100 852 36,321 -- -- -- 4,983
W. J. Googe, Jr., 1994 122,769 -- 2,543 -- 4,010 -- 6,213
Vice President, 1993 117,644 7,001 4,965 9,620 -- -- 6,632
Administration 1992 107,992 9,636 2,335 9,622 2,916 -- 5,069
WTU
Glenn Files, President 1994 246,699 50,000 10,032 -- 13,758 -- 6,750
and CEO (2) 1993 223,333 24,675 39,223 25,138 -- -- 26,126
1992 188,000 21,239 40,043 14,810 9,895 -- 8,460
T. D. Churchwell, 1994 163,329 -- 180,191 -- 6,133 -- 4,500
Executive Vice President 1993 -- -- -- -- -- -- --
(2) (5) 1992 -- -- -- -- -- -- --
Dennis M. Sharkey, 1994 157,046 -- 72,927 -- 4,010 -- 4,500
Vice President, 1993 -- -- -- -- -- -- --
Administration (2) (5) 1992 -- -- -- -- -- -- --
Donald A. Welch, Vice 1994 136,962 -- 5,003 -- 4,010 -- 6,163
President Division Operations 1993 129,650 7,178 1,628 7,290 -- -- 5,339
and Engineering (2) 1992 118,985 7,976 18,850 8,010 3,135 -- 5,354
Paul J. Brower, Vice 1994 132,058 -- 5,519 -- 4,010 -- 3,962
President, Marketing and 1993 123,133 7,231 673 7,351 -- -- 3,366
Business Development (2) 1992 112,960 6,733 38,485 5,642 3,135 -- 3,389
(1) Amounts in this column are paid or awarded in a calendar year
for performance in a preceding year.
(2) The following are the perquisites and other personal benefits
required to be identified in respect of each Named Executive
Officer.
CPL
In 1994 Mr. Teague received $10,393 in severance pay and company
loan discount.
In 1992, Mr. Sandoval was reimbursed $18,745 for relocation
expenses.
PSO
In 1993, Mr. McKamey was reimbursed $24,641 for relocation
expenses.
In 1992, Mr. Williams was reimbursed $18,067 for relocation
expenses.
SWEPCO
In 1993, Mr. Madison was reimbursed $14,848 for relocation
expenses.
3-10
In 1992, a portion of Mr. Bremer's use of company aircraft
resulted in taxable income to him. SWEPCO estimated that such
usage by Mr. Bremer resulted in incremental costs of $12,702.
Also in 1992, Mr. Bremer was reimbursed $11,127 for the cost of
certain club dues. In 1992, Mr. Madison was reimbursed $34,697
for relocation expenses.
WTU
In 1994, Mr. Churchwell and Mr. Sharkey were reimbursed $21,052
and $43,816, respectively, for relocation expenses. Mr.
Churchwell was reimbursed $73,490 for loss on the sale of his
home, due to structural problems.
In 1993, Mr. Files was reimbursed $8,482 for spouse travel
expenses.
In 1992, Mr. Files and Mr. Brower were reimbursed $15,632 and
$17,439, respectively, for relocation expenses. Mr. Welch and
Mr. Brower were reimbursed $9,942 and $8,915, respectively, for
the cost of security systems.
CPL, PSO, SWEPCO and WTU
(3) 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 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 re-
issued without restrictions. The individuals receive dividends
and may vote shares of restricted stock, even before they are
vested. The amount reported in the table represents the market
value of the shares at the date of grant. As of the end of 1994,
the aggregate restricted stock holdings of each of the Named
Executive Officers were:
Restricted Stock Market Value
Name Held at December 31, 1994 at December 31, 1994
CPL
Robert R. Carey 2,851 $64,504
B. W. Teague -- --
J. Gonzalo Sandoval 211 4,774
C. Wayne Stice -- --
Melanie J. Richardson -- --
PSO
Robert L. Zemanek 1,094 24,752
Waldo J. Zerger, Jr. 478 10,815
E. Michael Williams 254 5,747
Mary M. Polfer 439 9,932
William R. McKamey -- --
SWEPCO
Richard H. Bremer 2,609 59,029
W. Jerry Googe, Jr. 539 12,195
Marvin R. McGregor 518 11,720
Michael H. Madison 484 10,951
WTU
Glenn Files 1,071 24,231
Donald A. Welch 515 11,652
Paul J. Brower 330 7,466
T. D. Churchwell 424 9,593
Dennis M. Sharkey 662 14,978
3-11
CPL, PSO, SWEPCO and WTU
(4) Amounts shown in this column consist of (i) the annual employer
matching payments to CSW's Thrift Plus Plan, (ii) premiums paid
per participant for personal liability insurance, and (iii)
average amounts of premiums paid per participant in those years
under CSW's memorial gift program. 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 for up to three organizations of an aggregate of $500,000,
payable by CSW upon such person's death. CSW maintains corporate-
owned life insurance policies to fund the program. The annual
premiums paid by CSW are based on pooled risks and average
$17,013 for 1994 and 1993. In 1992 the pooled average was
$17,200. During 1994, Messrs. Carey and Bremer participated. Mr
Files and Mr. Zemanek also participated in the plan in 1994, but
coverage was provided by CSW. During 1993, Messrs. Bremer,
Carey, Files, and Zemanek participated. In 1992 Messrs. Carey
and Bremer participated.
(5) CSW System Affiliations.
CPL
Mr.Teague retired in May of 1994. Mr. Stice resigned in February
of 1994.
PSO
Mr. Williams was employed by CSW in January 1994 and SWEPCO for a
portion of 1992. Mr. McKamey was employed by CSW during a
portion of 1993 and all of 1992.
SWEPCO
Mr. Madison was employed by WTU during a portion of 1992.
WTU
Mr. Churchwell was employed by CSW during 1992 and 1993. Mr.
Sharkey was employed by SWEPCO during 1992 and 1993.
3-12
Option/SAR Grants
Shown below is information on grants of stock options made in 1994
pursuant to the 1992 LTIP to the Named Executives Officers of each
of the Electric Operating Companies. No stock appreciation rights
were granted in 1994.
CSW Option/SAR Grants in 1994 (1)
Individual Grants
Number of CSW Potential Realizable Value
Securities at Assumed Annual Rates
Underlying % of Total of CSW Stock Price
Options/ Options/SARs Appreciation for Option
SARs Granted to Exercise or Terms(3)
Granted Employees In Base Price Expiration
Name (#)(2) Fiscal Year (4) ($/Sh) Date 5% ($) 10% ($)
CPL
Robert R. Carey 15,901 16.4 % $24.813 4/1/2004 $248,567 $627,337
Melanie J. Richardson 4,010 4.1 24.813 4/1/2004 62,685 158,205
C. Wayne Stice -- -- -- -- -- --
B. W. Teague -- -- -- -- -- --
J. Gonzalo Sandoval 4,010 4.1 24.813 4/1/2004 62,685 158,205
PSO
Robert L. Zemanek 14,792 15.4 24.813 4/1/2004 231,231 583,584
William R. McKamey 4,010 4.2 24.813 4/1/2004 62,685 158,205
Mary M. Polfer 4,010 4.2 24.813 4/1/2004 62,685 158,205
E. Michael Williams 4,010 4.2 24.813 4/1/2004 62,685 158,205
Waldo J. Zerger, Jr. 4,010 4.2 24.813 4/1/2004 62,685 158,205
SWEPCO
Richard H. Bremer 15,901 15.3 24.813 4/1/2004 248,567 627,337
W. J. Googe, Jr. 4,010 3.9 24.813 4/1/2004 62,685 158,205
Michael H. Madison 4,010 3.9 24.813 4/1/2004 62,685 158,205
Marvin R. McGregor 4,010 3.9 24.813 4/1/2004 62,685 158,205
WTU
Glenn Files 13,758 12.4 24.813 4/1/2004 215,068 542,790
Paul J. Brower 4,010 3.6 24.813 4/1/2004 62,685 158,205
T. D. Churchwell 6,133 5.5 24.813 4/1/2004 95,872 241,963
Dennis M. Sharkey 4,010 3.6 24.813 4/1/2004 62,685 158,205
Donald A. Welch 4,010 3.6 24.813 4/1/2004 62,685 158,205
(1)The stock option plans are administered by the Executive
Compensation Committee of the CSW Board of Directors, which has
the authority to determine the individuals to whom and the terms
at which option and SAR grants shall be made.
(2)All options were granted on April 20, 1994, and are first
exercisable 12 months after the grant date, with one-third of the
shares becoming exercisable at that time and with an additional
one-third of the aggregate becoming exercisable on each of the
next two anniversary dates.
(3)The annual rates of appreciation of 5% and 10% are specifically
required by SEC disclosure rules and in no way guarantee that
such annual rates of appreciation will be achieved by CSW nor
should this be construed in any way to constitute any
representation by CSW that such growth will be achieved.
(4)Determined separately for each Electric Operating Company.
Option/SAR Exercises and Year-End Value Table
Shown below is information regarding option/SAR exercises during
1994 and unexercised options/SARs at December 31, 1994 for the Named
Executives Officers.
Aggregated CSW Option/SAR Exercises in 1994
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)
CPL
Robert R. Carey -- -- 9,786/20,046 --/--
Melanie J. Richardon -- -- 870/4,447 --/--
J. Gonzalo Sandoval -- -- 1,942/4,984 --/--
C. Wayne Stice 250 3,375 765/1,530 --/--
B. W. Teague -- -- 1,045/1,045 --/--
PSO
Robert L. Zemanek 1,500 9,563 7,902/18,338 --/--
William R. McKamey -- -- 1,322/4,674 --/--
Mary M Polfer -- -- 1,942/4,984 --/--
E. Michael Williams -- -- 6,890/6,394 --/--
Waldo J. Zerger, Jr. -- -- 2,090/5,055 --/--
SWEPCO
Richard H. Bremer -- -- 8,286/20,046 --/--
W. Jerry Googe, Jr. -- -- 1,942/4,984 --/--
Michael H. Madison -- -- 2,090/5,055 --/--
Marvin R. McGregor -- -- 2,090/5,055 --/--
WTU
Glenn Files -- -- 6,596/17,057 --/--
Paul J. Brower -- -- 2,090/5,055 --/--
T. D. Churchwell -- -- 2,090/7,178 --/--
Dennis M. Sharkey -- -- 8,342/4,984 27,506/--
Donald A. Welch -- -- 2,090/5,055 --/--
(1) Based on the New York Stock Exchange December 31, 1994, closing
price of CSW's Common Stock of $22.625 per share and the exercise
prices of $29.625, $24.813, $16.250, and $16.125 per share.
Long-term Incentive Plan Awards Table
The following table shows information concerning awards made to the
Named Executive Officers during 1994 under cycle III of the LTIP:
Performance or Estimated Future Payouts under
Number of CSW Other Period Non-Stock Price Based Plans
Shares, Units or Until Maturation Threshold Target Maximum
Name Other Rights (#) or Payout (1) ($) ($) ($)
CPL
Robert R. Carey -- 2 years -- 142,038 213,057
Melanie J. Richardson -- 2 years -- 29,087 43,631
J. Gonzalo Sandoval -- 2 years -- 29,087 43,631
C. Wayne Stice -- -- -- -- --
B. W. Teague -- -- -- -- --
PSO
Robert L. Zemanek -- 2 years -- 132,128 198,192
William R. McKamey -- 2 years -- 29,087 43,631
Mary M. Polfer -- 2 years -- 29,087 43,631
E. Michael Williams -- -- -- -- --
Waldo J. Zerger, Jr. -- 2 years -- 29,087 43,631
SWEPCO
Richard H. Bremer -- 2 years -- 142,038 213,057
W. Jerry Googe, Jr. -- 2 years -- 29,087 43,631
Michael H. Madison -- 2 years -- 29,087 43,631
Marvin R. McGregor -- 2 years -- 29,087 43,631
WTU
Glenn Files -- 2 years -- 122,897 184,346
Paul J. Brower -- 2 years -- 29,087 43,631
T. D. Churchwell -- 2 years -- 57,065 85,598
Dennis M. Sharkey -- 2 years -- 29,087 43,631
Donald A. Welch -- 2 years -- 29,087 43,631
(1) As these grants were established in March, 1994 with a
three-year performance measurement period, two years now remain
until maturation.
3-15
CPL, PSO, SWEPCO and WTU
Payouts of the awards are contingent upon CSW achieving a
specified level of total stockholder return, relative to a peer
group of utility companies, for the three-year period, or cycle, and
exceeding a certain defined minimum threshold. Total stockholder
return is calculated by dividing (i) the sum of (a) the cumulative
amount of dividends per share for the three-year period, assuming
full dividend reinvestment, and (b) the change in share price over
the three-year period, by (ii) the share price at the beginning of
the three-year period. 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 canceled. The first awards under LTIP were established in
1992 for a three-year cycle through 1994. The Executive
Compensation Committee is scheduled to evaluate cycle I performance
under the LTIP in March, 1995.
The LTIP contains a provision accelerating awards upon a change
in control of CSW. If a change in control of CSW occurs, (i) all
options and SARs become fully exercisable, (ii) all restrictions,
terms and conditions applicable to all restricted stock are deemed
lapsed and satisfied and 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 Plan
CPL, PSO, SWEPCO and WTU
PENSION PLAN TABLE
Annual Benefits After
Specified Years of Credited Service
Average
Compensation 15 20 25 30 or more
$100,000 . . . . . .$ 25,050 $ 33,333 $ 41,667 $ 50,000
150,000 . . . . . . 37,575 50,000 62,500 75,000
200,000 . . . . . . 50,100 66,667 83,333 100,000
250,000 . . . . . . 62,625 83,333 104,167 125,000
300,000 . . . . . . 75,150 100,000 125,000 150,000
350,000 . . . . . . 87,675 116,667 145,833 175,000
450,000 . . . . . . 112,725 150,000 187,500 225,000
550,000 . . . . . . 137,775 183,333 229,167 275,000
650,000 . . . . . . 162,825 216,667 270,833 325,000
750,000 . . . . . . 187,875 250,000 312,500 375,000
Executive officers are eligible to participate in the tax-
qualified CSW Pension Plan like other employees of the registrants.
Certain executive officers, including the Named Executive Officers,
are also eligible to participate in the 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 62
or later Social Security benefit and (ii) certain other offset
benefits.
"Average Compensation" is the covered compensation for the
plans and equals the average annual compensation, reported as salary
3-16
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 benefits, are based on 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, 1994, for the Named Executive Officers are as follows:
Named Executive Officer Years of Credited Service Age
CPL
Robert R. Carey 27 57
Melanie J. Richardson 13 38
J. Gonzalo Sandoval 21 45
C. Wayne Stice 30 57
B. W. Teague 30 56
PSO
Robert L. Zemanek 22 45
William R. McKamey 24 48
Mary M. Polfer 4 50
E. Michael Williams 22 46
Waldo J. Zerger, Jr. 24 48
SWEPCO
Richard H. Bremer 17 46
W. Jerry Googe, Jr. 30 52
Michael H. Madison 23 46
Marvin R. McGregor 25 48
WTU
Glenn Files 23 47
Paul J. Brower 18 45
T. D. Churchwell 16 50
Dennis M. Sharkey 16 50
Donald A. Welch 30 55
Meetings and Compensation
CPL and PSO
The Board of Directors held four regular meetings during 1994.
Directors who are not also executive officers and employees of the
CPL and PSO or their 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.
3-17
SWEPCO
The Board of Directors held four meetings during 1994.
Directors who are not also executive officers and employees of
SWEPCO or its affiliates receive annual directors' fees of $6,600
for serving on the board, and a fee of $300 plus expenses for each
meeting of the board or committee attended.
WTU
The Board of Directors held five meetings during 1994.
Directors who are not also executive officers and employees of WTU
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.
CPL, SWEPCO and WTU
Those directors who are not also officers of CPL, SWEPCO and
WTU 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
CPL, PSO, SWEPCO and WTU
No person serving during 1994 as a member of the Executive
Compensation Committee of the Board of Directors of CSW served as an
officer or employee of each registrant during or prior to 1994. No
person serving during 1994 as an executive officer of the Electric
Operating Companies serves or has served on the compensation
committee or as a director of another company whose executive
officers serve or has served as a member of the Executive
Compensation Committee of CSW or as a director of one of the
Electric Operating Companies.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.
CSW
The information required by ITEM 12 is hereby incorporated by
reference to page 5-6 of CSW's Proxy Statement.
CPL, PSO, SWEPCO and WTU
All outstanding Common Stock shares are owned beneficially and
of record by CSW, 1616 Woodall Rodgers Freeway, Dallas, Texas 75202.
Company Shares Par Value
CPL 6,755,535 $25 par value
PSO 9,013,000 $15 par value
SWEPCO 7,536,640 $18 par value
WTU 5,488,560 $25 par value
3-18
Security Ownership of Management
The following table shows securities beneficially owned as of
December 31, 1994, by each director, the CEO and the four other most
highly compensated executive officers and, as a group, all directors
and executive officers of each registrant. Share amounts shown in
this table include options exercisable within 60 days after year-
end, restricted stock, shares of CSW Common credited to CSW Thrift
Plus accounts and all other shares of CSW Common beneficially owned
by the listed persons. Each person has sole voting and investment
power with respect to all shares listed in the table below,
excluding the shares underlying the unexercised options.
CPL
Beneficial Ownership as of December 31, 1994
Name CSW Common Stock Preferred Stock
(1)(2) (2)
E. R. Brooks 81,940
Robert R. Carey 24,260
Ruben M. Garcia --
David L. Hooper 1,775
Harry D. Mattison 33,111
Robert A. McAllen 3,500
Pete Morales, Jr. --
S. Loyd Neal, Jr. 2,950
Jim L. Peterson --
H. Lee Richards 1,700
Melanie J. Richardson 1,356
J. Gonzalo Sandoval 11,328
C. Wayne Stice 5,568
B. W. Teague 3,371
Gerald E. Vaughn 151
All of the above and other
executive officers as a group 175,673
(1)Shares for Messrs., Brooks, Carey, Mattison, Sandoval and CPL
directors and executives as a group, include 4,760, 2,851, 3,236,
211 and 11,058 shares of restricted stock, respectively. These
individuals currently have voting power, but not investment
power, with respect to these shares. The above shares also
include 870, 19,062, 9,786, 12,352, 1,942, 1,530, 1,045 and
49,535 shares underlying immediately exercisable options held by
Ms. Richardson and Messrs. Brooks, Carey, Mattison, Sandoval,
Stice, Teague and CPL directors and executives as a group,
respectively.
(2)Percentages are all less than one percent and therefore are
omitted.
3-19
PSO
Beneficial Ownership as of December 31, 1994
Name CSW Common Stock Preferred Stock
(1)(2) (2)
E. R. Brooks 81,940
Harry A. Clarke --
Paul K. Lackey, Jr. --
Paula Marshall-Chapman --
Harry D. Mattison 33,111
William R. McKamey 8,176
Mary M. Polfer 3,378
Jack E. Raulston --
Dr. Robert B. Taylor, Jr. --
Robert L. Zemanek 10,920
Waldo J. Zerger, Jr. 9,635
E. Michael Williams 254
All of the above and other
executive officers as a group 154,146
(1)Shares for Ms. Polfer and Messrs. Brooks, Mattison, Williams,
Zemanek, Zerger and PSO directors and executives as a group,
include 439, 4,760, 3,236, 254, 1,094, 478 and 10,261 shares of
restricted stock, respectively. These individuals currently have
voting power, but not investment power, with respect to these
shares. The above shares also include 1,942, 19,062, 12,352,
1,322, 7,092, 2,090 and 45,732 shares underlying immediately
exercisable options held by Ms. Polfer and Messrs. Brooks,
Mattison, McKamey, Zemanek, Zerger, and PSO directors and
executives as a group, respectively.
(2)Percentages are all less than one percent and therefore are
omitted.
3-20
SWEPCO
Beneficial Ownership as of December 31, 1994
Name CSW Common Stock Preferred Stock
(1)(2) (2)
Richard H. Bremer 28,578
E. R. Brooks 81,940
James E. Davison --
Al P. Eason, Jr. 2,000
W. J. Googe, Jr. 6,558
Dr. Frederick E. Joyce 2,000
Michael H. Madison 4,241
Harry D. Mattison 33,111
Marvin R. McGregor 3,892
William C. Peatross --
Jack L. Phillips --
All of the above and other
executive officers as a group 166,116
(1)Shares for Messrs. Bremer, Brooks, Googe, Madison, Mattison,
McGregor and SWEPCO directors and executives as a group, include
2,609, 4,760, 539, 484, 3,236, 518 and 12,146 shares of
restricted stock, respectively. These individuals currently have
voting power, but not investment power, with respect to these
shares. The above shares also include 8,286, 19,062, 1,942,
2,090, 12,352, 2,090 and 47,011 shares underlying immediately
exercisable options held by Messrs. Bremer, Brooks, Googe,
Madison, Mattison, McGregor, and SWEPCO directors and executives
as a group, respectively.
(2)Percentages are all less than one percent and therefore are
omitted.
21
WTU
Beneficial Ownership as of December 31, 1994
Name CSW Common Stock Preferred Stock
(1)(2) (2)
Richard F. Bacon 2,643
C. Harwell Barber 12,292
E. R. Brooks 81,940
Paul J. Brower 3,698
T. D. Churchwell 3,131
Glenn Files 9,164
Harry D. Mattison 33,111
Tommy Morris 2,000
Dian G. Owen 50
James M. Parker 6,700
Dennis M. Sharkey 16,205
F. L. Stephens 1,596
Donald A. Welch 7,920
All of the above and other
executive officers as a group. 184,360
(1)Shares for Messrs. Brooks, Brower, Churchwell, Files, Mattison,
Sharkey, Welch and WTU directors and executives as a group,
include 4,760, 330, 424, 1,071, 3,236, 662, 515 and 10,998 shares
of restricted stock, respectively. These individuals currently
have voting power, but not investment power, with respect to
these shares. The above shares also include 19,062, 2,090,
2,090, 6,596, 12,352, 8,342, 2,090 and 53,558 shares underlying
immediately exercisable options held by Messrs. Brooks, Brower,
Churchwell, Files, Mattison, Sharkey, Welch and WTU directors and
executives as a group, respectively.
(2)Percentages are all less than one percent and therefore are
omitted.
3-22
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
CSW
The information required by ITEM 13 is hereby incorporated by
reference to pages 6-9 of CSW's Proxy Statement.
CPL, PSO, SWEPCO and WTU
None.
4-1
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K.
(a) The following documents are filed as a part of this report on
this Form 10-K.
(1) Financial Statements:
Reports of Independent Public Accountants on the financial
statements for CSW and subsidiary companies, CPL, PSO, SWEPCO and WTU
are listed under Item 8 herein.
The financial statements filed as a part of this report for CSW
and subsidiary companies, CPL, PSO, SWEPCO and WTU are listed under
Item 8 herein.
(2) Financial Statement Schedules:
Report of Independent Public Accountants as to Schedules for
CSW, CPL, PSO, SWEPCO and WTU are included in the Report of
Independent Public Accountants for each registrant.
Financial Statement Schedules for CSW, CPL, PSO, SWEPCO and WTU
are listed in the Index to the Financial Statement Schedules at page
4-15.
(3) Exhibits
Exhibits for CSW, CPL, PSO, SWEPCO and WTU are listed in the
Exhibit Index at page 4-21.
(b) Reports on Form 8-K:
CSW and CPL
CSW and CPL filed a Current Report on Form 8-K dated October 31,
1994, reporting ITEM 5. "Other Events" relating to the CPL rate case.
PSO and SWEPCO
No reports were filed on Form 8-K during the quarter ended
December 31, 1994.
WTU
WTU filed a Current Report on Form 8-K dated February 17, 1995
providing unaudited 1994 financial data associated with a debt
financing.
(c) Management Contracts, Compensatory Plans or Arrangements:
The management contracts, compensatory plans or arrangements
required to be filed as exhibits to this Form 10-K are listed in
10(a)1-10(a)6 in item (d) Exhibits below.
4-2
CSW
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 20, 1995. The signature of the undersigned
registrant shall be deemed to relate only to matters having reference
to such registrant and any subsidiaries thereof.
CENTRAL AND SOUTH WEST CORPORATION
By: Wendy G. Hargus
Controller
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 20,
1995. The signature of each of the undersigned shall be deemed to
relate only to matters having reference to the above named registrant
and any subsidiaries thereof.
Signature Title
E. R. Brooks President and CEO and Director
(Principal Executive Officer)
Glenn D. Rosilier Chief Financial Officer
(Principal Financial Officer)
Wendy G. Hargus Controller
(Principal Accounting Officer)
*T. J. Barlow Director
*Glenn Biggs Director
*Molly Shi Boren Director
*Donald M. Carlton Director
*Joe H. Foy Director
*Robert Lawless Director
*Harry D. Mattison Executive Vice President and Director
*James L. Powell Director
*Arthur E. Rasmussen Director
*T. V. Shockley, III Executive Vice President and Director
*J. C. Templeton Director
*Lloyd D. Ward Director
*Wendy G. Hargus, 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: Wendy G. Hargus
Attorney-in-Fact
4-3
CPL
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 20, 1995. The signature of the undersigned
registrant shall be deemed to relate only to matters having reference
to such registrant.
CENTRAL POWER AND LIGHT COMPANY
By: R. Russell Davis
Controller
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 20,
1995. The signature of each of the undersigned shall be deemed to
relate only to matters having reference to the above named
registrant.
Signature Title
Robert R. Carey President and CEO and Director
(Principal Executive Officer)
R. Russell Davis Controller
(Principal Accounting and Financial Officer)
*E. R. Brooks Director
*Ruben M. Garcia Director
*David L. Hooper 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
*Melanie J. Richardson Director
*J. Gonzalo Sandoval Director
*Gerald E. Vaughn Director
*R. Russell Davis, by signing his 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: R. Russell Davis
Attorney-in-Fact
4-4
PSO
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 20, 1995. The signature of the undersigned
registrant shall be deemed to relate only to matters having reference
to such registrant.
PUBLIC SERVICE COMPANY OF OKLAHOMA
By: R. Russell Davis
Controller
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 20,
1995. The signature of each of the undersigned shall be deemed to
relate only to matters having reference to the above named
registrant.
Signature Title
Robert L. Zemanek President and CEO and Director
(Principal Executive Officer)
R. Russell Davis Controller
(Principal Accounting and Financial Officer)
*E. R. Brooks Director
*Harry A. Clark Director
*Paul K. Lackey, Jr. Director
*Paula Marshall-Chapman Director
*Harry D. Mattison Director
*William R. McKamey Director
*Mary M. Polfer Director
*Dr. Robert B. Taylor, Jr. Director
*Waldo J. Zerger, Jr. Director
*R. Russell Davis, by signing his 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: R. Russell Davis
Attorney-in-Fact
4-5
SWEPCO
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 20, 1995. The signature of the undersigned
registrant shall be deemed to relate only to matters having reference
to such registrant.
SOUTHWESTERN ELECTRIC POWER COMPANY
By: R. Russell Davis
Controller
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 20,
1995. The signature of each of the undersigned shall be deemed to
relate only to matters having reference to the above named
registrant.
Signature Title
Richard H. Bremer President and CEO and Director
(Principal Executive Officer)
R. Russell Davis Controller
(Principal Accounting and Financial Officer)
*E. R. Brooks Director
*James E. Davison Director
*Al P. Eason, Jr.. Director
*W. J. Googe, Jr. Director
*Dr. Frederick E. Joyce Director
*Michael H. Madison Director
*Harry D. Mattison Director
*Marvin R. McGregor Director
*William C. Peatross Director
*Jack L. Phillips Director
*R. Russell Davis, by signing his 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: R. Russell Davis
Attorney-in-Fact
4-6
WTU
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 20, 1995. The signature of the undersigned
registrant shall be deemed to relate only to matters having reference
to such registrant.
WEST TEXAS UTILITIES COMPANY
By: R. Russell Davis
Controller
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 20,
1995. The signature of each of the undersigned shall be deemed to
relate only to matters having reference to the above named
registrant.
Signature Title
Glenn Files President and CEO and Director
(Principal Executive Officer)
R. Russell Davis Controller
(Principal Accounting and Financial Officer)
*Richard Bacon Director
*C. Harwell Barber Director
*E. R. Brooks Director
*Paul J. Brower Director
*T. D. Churchwell Director
*Harry D. Mattison Director
*Tommy Morris Director
*Dian G. Owen Director
*James M. Parker Director
*F. L. Stephens Director
*Dennis M. Sharkey Director
*Donald A. Welch Director
*R. Russell Davis, by signing his 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: R. Russell Davis
Attorney-in-Fact
4-7
INDEX TO FINANCIAL STATEMENT SCHEDULES
Paper
Copy
Schedule Page
II. Valuation and Qualifying Accounts.
Central and South West Corporation 4-16
Central Power and Light Company 4-17
Public Service Company of Oklahoma 4-18
Southwestern Electric Power Company 4-19
West Texas Utilities Company 4-20
CSW, CPL, PSO, SWEPCO and WTU
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 or
related notes to financial statements.
4-8
CENTRAL AND SOUTH WEST CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E
Additions
Balance at Charged to Charged Balance
Beginning Costs and to Other at End
Description of Year Expenses Accounts (b) Deductions (c) of Year
(millions)
1994
Accrued Restructuring
Charges $97 $ (9) (a) $(27) $57 $ 4
1993
Accrued Restructuring
Charges $-- $ 97 $ -- $-- $ 97
(a) Reflects true-up to revised estimate of restructuring charges.
(b) Effects of early retirement related to SFAS No. 87 Employers'
Accounting for Pensions and SFAS No. 112 Employers' Accounting for
Postemployment Benefits follow:
(millions)
SFAS No. 87 $(31)
SFAS No. 112 4
Total $(27)
(c) Payments of accrued restructuring charges.
4-9
CENTRAL POWER AND LIGHT COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E
Additions
Balance at Charged to Charged Balance
Beginning Costs and to Other at End
Description of Year Expenses Accounts(b) Deductions(c) of Year
(thousands)
1994
Accrued Restructuring
Charges $29,365 $ 98 (a) $(7,893) $20,245 $ 1,325
1993
Accrued Restructuring
Charges $ -- $29,365 $ -- $ -- $29,365
(a) Reflects true-up to revised estimate of restructuring charges.
(b) Effects of early retirement related to SFAS No. 87 Employers'
Accounting for Pensions and SFAS No. 112 Employers' Accounting for
Postemployment Benefits follow:
(thousands)
SFAS No. 87 $(9,099)
SFAS No. 112 1,206
Total $(7,893)
(c) Payments of accrued restructuring charges.
4-10
PUBLIC SERVICE COMPANY OF OKLAHOMA
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E
Additions
Balance at Charged to Charged Balance
Beginning Costs and to Other at End
Description of Year Expenses Accounts(b) Deductions(c) of Year
(thousands)
1994
Accrued Restructuring
Charges $24,995 $ (197) (a) $(8,126) $15,626 $ 1,046
1993
Accrued Restructuring
Charges $ -- $24,995 $ -- $ -- $24,995
(a) Reflects true-up to revised estimate of restructuring charges.
(b) Effects of early retirement related to SFAS No. 87 Employers'
Accounting for Pensions and SFAS No. 112 Employers' Accounting for
Postemployment Benefits follow:
(thousands)
SFAS No. 87 $(9,880)
SFAS No. 112 1,754
Total $(8,126)
(c) Payments of accrued restructuring charges.
4-11
SOUTHWESTERN ELECTRIC POWER COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E
Additions
Balance at Charged to Charged Balance
Beginning Costs and to Other at End
Description of Year Expenses Accounts(b) Deductions(c) of Year
(thousands)
1994
Accrued Restructuring
Charges $25,203 $ (4,978)(a) $(7,421) $11,694 $ 1,110
1993
Accrued Restructuring
Charges $ -- $ 25,203 $ -- $ -- $25,203
(a) Reflects true-up to revised estimate of restructuring charges.
(b) Effects of early retirement related to SFAS No. 87 Employers'
Accounting for Pensions and SFAS No. 112 Employers' Accounting for
Postemployment Benefits follow:
(thousands)
SFAS No. 87 $(8,016)
SFAS No. 112 595
Total $(7,421)
(c) Payments of accrued restructuring charges.
4-12
WEST TEXAS UTILITIES COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COL. A COL. B COL. C COL. D COL. E
Additions
Balance at Charged to Charged Balance
Beginning Costs and to Other at End
Description of Year Expenses Accounts(b) Deductions(c) of Year
(thousands)
1994
Accrued Restructuring
Charges $15,250 $ (2,037)(a) $(3,724) $8,918 $ 571
1993
Accrued Restructuring
Charges $ -- $ 15,250 $ -- $ -- $15,250
(a) Reflects true-up to revised estimate of restructuring charges.
(b) Effects of early retirement related to SFAS No. 87 Employers'
Accounting for Pensions and SFAS No. 112 Employers' Accounting for
Postemployment Benefits follow:
(thousands)
SFAS No. 87 $(3,992)
SFAS No. 112 268
Total $(3,724)
(c) Payments of accrued restructuring charges.
4-13
(d) Exhibit Index:
The following exhibits indicated by an asterisk (*) preceding
the exhibit number are filed herewith. The balance of the exhibits
have heretofore been filed with the SEC, respectively, as the
exhibits and in the file numbers indicated and are incorporated
herein by reference. The exhibits marked with a plus (+) are
management contracts or compensatory plans or arrangements required
to be filed herewith and required to be identified as such by ITEM
14. of Form 10-K. Reference is made to a duplicate list of exhibits
being filed as a part of this Form 10-K, which list, prepared in
accordance with Item 102 of Regulation S-T of the SEC, immediately
precedes the exhibits being physically filed with this Form 10-K.
(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
CSW
(a) 1 Agreement and Plan of Merger Among
El Paso Electric Company, Central and South West
Corporation and CSW Sub, Inc. Dated as of May 3, 1993 as
Amended May 18, 1993 (incorporated herein by reference to
Exhibit 2.1 to CSW's Form 8-K dated December 29, 1993, File
No. 1-1443).
(a) 2 Second Amendment Dated as of August
26, 1993 to Agreement and Plan of Merger Among El Paso
Electric Company, Central and South West Corporation and
CSW Sub, Inc. Dated as of May 3, 1993 as amended on May 18,
1993 (incorporated herein by reference to Exhibit 2.2 to
CSW's Form 8-K dated December 29, 1993, File No. 1-1443).
(a) 3 Third Amendment Dated as of
December 1, 1993 to Agreement and Plan of Merger Among El
Paso Electric Company, Central and South West Corporation
and CSW Sub, Inc. Dated as of May 3, 1993 as amended on
May 18, 1993 and August 26, 1993 (incorporated herein by
reference to Exhibit 2.3 to CSW's Form 8-K dated December
29, 1993, File No. 1-1443).
(a) 4 Modified Third Amended Plan of
Reorganization of El Paso Electric Company Providing for
the Acquisition of El Paso Electric Company by Central and
South West Corporation as corrected December 6, 1993, and
confirmed by the Bankruptcy Court (incorporated herein by
reference to Exhibit 2.4 to CSW's Form 8-K dated December
29, 1993, File No. 1-1443).
(a) 5 Order and Judgement Confirming El
Paso Electric Company's Third Amended Plan of
Reorganization, as Modified, Under Chapter 11 of the United
States Bankruptcy Code and Granting Related Relief
(incorporated herein by reference to Exhibit 2.5 to CSW's
Form 8-K dated December 29, 1993, File No. 1-1443).
(3) Articles of Incorporation and By-laws
CSW
(a) 1 Second Restated Certificate of
Incorporation of CSW, as amended (incorporated herein by
reference to Exhibit 3 (a) to CSW's 1990 Form 10-K, File
No. 1-1443).
(a) 2 Bylaws of CSW, as amended
(incorporated herein by reference to Exhibit 3 (b) to CSW's
1990 Form 10-K, File No. 1-1443).
4-14
(d) Exhibit Index:
(3) Articles of Incorporation and By-laws (continued)
CPL
(b) 1 Restated Articles of Incorporation,
as amended, of CPL (incorporated herein by reference to
Exhibit 4(a) to CPL'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 CPL's
Form 10-Q for the quarterly period ended September 30,
1992, ITEM 6, Exhibit 1).
* (b) 2
Bylaws of CPL, as amended.
PSO
(c) 1
Restated Certificate of Incorporation of PSO (incorporated
herein by reference to Exhibit 3 to PSO's 1987 Form 10-K,
File No. 0-343).
* (c) 2
Bylaws of PSO, as amended.
SWEPCO
(d) 1
Restated Certificate of Incorporation, as amended, of
SWEPCO (incorporated herein by reference to Exhibit 3 to
SWEPCO's 1980 Form 10-K, File No. 1-3146, Exhibit 2 to Form
U-1 File No. 70-6819, Exhibit 3 to Form U-1, File No. 70-
6924 and Exhibit 4 to Form U-1 File No. 70-7360).
* (d) 2
Bylaws of SWEPCO, as amended.
WTU
* (e) 1
Restated Articles of Incorporation, as amended, of WTU.
* (e) 2
Bylaws of WTU, as amended.
(4) Instruments Defining the Rights of Security Holder,
Including Indentures
CPL
(a) 1 Indenture of Mortgage or Deed of Trust dated November 1,
1943, executed by CPL to The First National Bank of Chicago
and Robert L. Grinnell, as Trustee, as amended through
October 1, 1977 (incorporated herein by reference to
Exhibit 5.01 in File No. 2-60712), and the Supplemental
Indentures of CPL 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, April 1, 1993 and May
1, 1994 (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. 70-7725 and
Exhibit 10 (a), 10 (b), 10 (c), 10 (d) and 10(e),
respectively, to Form U-1, File No. 70-8053).
4-15
(d) Exhibit Index:
(4) Instruments Defining the Rights of Security Holder,
Including Indentures (continued)
PSO
(b) 1 Indenture dated July 1, 1945, as
amended, of PSO (incorporated herein by reference to
Exhibit 5.03 in Registration No. 2-60712) and the
Supplemental Indenture of PSO dated June 1, 1979
(incorporated herein by reference to Exhibit 2.02 in
Registration No. 2-64432), the Supplemental Indenture of
PSO dated December 1, 1979 (incorporated herein by
reference to Exhibit 2.02 in Registration No. 2-65871), the
Supplemental Indenture of PSO dated March 1, 1983
(incorporated herein by reference to Exhibit 2 to Form U-1,
File No. 70-6822), the Supplemental Indenture of PSO dated
May 1, 1986 (incorporated herein by reference to Exhibit 3
to Form U-1, File No. 70-7234), the Supplemental Indenture
of PSO dated July 1, 1992 (incorporated herein by reference
to Exhibit 4 (b) to Form S-3, File No. 33-48650), the
Supplemental Indenture of PSO dated December 1, 1992
(incorporated herein by reference to to Exhibit 4 (c) to
Form S-3, File No. 33-49143), the Supplemental Indenture of
PSO dated April 1, 1993 (incorporated herein by reference
to Exhibit 4 (b) to Form S-3, File No. 33-49575), and
Supplemental Indenture of PSO dated June 1, 1993
(incorporated herein by reference to Exhibit 4 (b) to PSO's
1993 Form 10-K, File No. 0-343).
SWEPCO
(c) 1 Indenture dated February 1, 1940,
as amended through November 1, 1976, of SWEPCO
(incorporated herein by reference to Exhibit 5.04 in
Registration No. 2-60712), the Supplemental Indenture dated
August 1, 1978 incorporated herein by reference to Exhibit
2.02 in Registration No. 2-61943), the Supplemental
Indenture dated January 1, 1980 (incorporated herein by
reference to Exhibit 2.02 in Registration No. 2-66033), the
Supplemental Indenture dated April 1, 1981 (incorporated
herein by reference to Exhibit 2.02 in Registration No. 2-
71126), the Supplemental Indenture dated May 1, 1982
(incorporated herein by reference to Exhibit 2.02 in
Registration No. 2-77165), the Supplemental Indenture dated
August 1, 1985 (incorporated herein by reference to Exhibit
4 to Form U-1, File No. 70-7121), the Supplemental
Indenture dated May 1, 1986 (incorporated herein by
reference to Exhibit 3 to Form U-1 File No. 70-7233), the
Supplemental Indenture dated November 1, 1989 (incorporated
herein by reference to Exhibit 3 to Form U-1, File No. 70-
7676), the Supplemental Indenture dated June 1, 1992
(incorporated herein by reference to Exhibit 10 to Form U-
1, File No. 70-7934), the Supplemental Indenture dated
September 1, 1992 (incorporated herein by reference to
Exhibit 10 (b) to Form U-1, File No.72-8041), the
Supplemental Indenture dated July 1, 1993 (incorporated
herein by reference to Exhibit 10 (c) to Form U-1, File No.
70-8041) and the Supplemental Indenture dated October 1,
1993 (incorporated herein by reference to Exhibit 10 (a) to
Form U-1, File No. 70-8239).
WTU
(d) 1 Indenture dated August 1, 1943, as
amended through July 1, 1973 (incorporated herein by
reference to Exhibit 5.05 in File No. 2-60712),
Supplemental Indenture dated May 1, 1979 (incorporated
herein by reference to Exhibit No. 2.02 in File No. 2-
63931), Supplemental Indenture dated November 15, 1981
(incorporated herein by reference to Exhibit No. 4.02 in
File No. 2-74408), Supplemental Indenture dated Nobember 1,
1983 (incorporated herein by reference to Exhibit 12 to
Form U-1, File No. 70-6820), Supplemental Indenture dated
April 15, 1985 (incorporated herein by reference to Amended
Exhibit 13 to Form U-1, File No. 70-6925), Supplemental
Indenture dated August 1, 1985 (incorporated herein by
reference to Exhibit 4 (b) in File No. 2-98843),
Supplemental Indenture dated May 1, 1986 (incorporated
herein by reference to Exhibit 4 to Form U-1, File No. 70-
7237), Supplemental Indenture dated December 1, 1989
(incorporated herein by reference to Exhibit 3 to Form U-1,
in File No. 70-7719), Supplemental Indenture dated June 1,
1992 (incorporated herein by reference to Exhibit 10 to
Form U-1, File No. 70-7936), Supplemental Indenture dated
October 1, 1992 (incorporated herein by reference to
Exhibit 10 to Form U-1, File No. 70-8057), Supplemental
Indenture dated February 1, 1994 (incorporated herein by
reference to Exhibit 10-Form U-1, File No. 70-8265) and
Supplemental Indenture dated March 1, 1995 (incorporated
herein by reference to Exhibit 10(b) to Form U-1, File No.
70-8057).
4-16
(d) Exhibit Index:
(10) Material Contracts
CSW
+ (a) 1 Restricted Stock Plan for Central
and South West Corporation (incorporated herein by
reference to Exhibit 10(a) to CSW's 1990 Form 10-K, File
No. 1-1443).
+ (a) 2 Central and South West System
Special Executive Retirement Plan (incorporated herein by
reference to Exhibit 10(b) to CSW's 1990 Form 10-K, File
No. 1-1443).
+ (a) 3 Executive Incentive Compensation
Plan for Central and South West System (incorporated herein
by reference to Exhibit 10(c) to the Corporation's 1990
Form 10-K, File No. 1-1443).
(a) 4 Central and South West
Corporation Stock Option Plan (incorporated herein by
reference to Exhibit 10(d) to the Corporation's 1990 Form
10-K, File No. 1-1443).
(a) 5 Central and South West
Corporation Deferred Compensation Plan for Directors
(incorporated herein by reference to Exhibit 10(e) to the
Corporation's 1990 Form 10-K, File No. 1-1443).
+ (a) 6 Central and South West Corporation
1992 Long-Term Incentive Plan (incorporated herein by
reference to Appendix A to the Central and South West
Corporation Notice of 1992 Annual Meeting of Shareholders
and Proxy Statement).
(12) Statements Re Computation of Ratios
CPL
* (a) 1 Statement re computation of
Ratio of Earnings to Fixed Charges for the five years ended
December 31, 1994.
PSO
* (b) 1 Statement re computation of
Ratio of Earnings to Fixed Charges for the five years ended
December 31, 1994.
SWEPCO
* (c) 1 Statement re computation of
Ratio of Earnings to Fixed Charges for the five years ended
December 31, 1994.
WTU
* (d) 1 Statement re computation of
Ratio of Earnings to Fixed Charges for the five years ended
December 31, 1994.
(21) Subsidiaries of the registrant
CSW
* (a) 1 Subsidiaries of the registrant.
(23) Consent of Experts and Counsel
CSW
* (a) 1 Consent of Independent Public Accountants.
4-17
(d) Exhibit Index:
(23) Consent of Experts and Counsel (continued)
CPL
* (b) 1 Consent of Independent Public Accountants.
WTU
* (c) 1 Consent of Independent Public
Accountants.
(24) Power of Attorney
* CSW
(a) 1 Power of Attorney.
(a) 2 Power of Attorney.
(a) 3 Power of Attorney.
(a) 4 Power of Attorney.
* CPL
(b) 1 Power of Attorney.
(b) 2 Power of Attorney.
(b) 3 Power of Attorney.
* PSO
(c) 1 Power of Attorney.
(c) 2 Power of Attorney.
(c) 3 Power of Attorney.
* SWEPCO
(d) 1 Power of Attorney.
(d) 2 Power of Attorney.
(d) 3 Power of Attorney.
* WTU
(e) 1 Power of Attorney.
(e) 2 Power of Attorney.
(e) 3 Power of Attorney.