UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) COMBINED QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarter Ended September 30, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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) 673-3000
0-340 West Texas Utilities Company 75-0646790
(A Texas Corporation)
301 Cypress Street
Abilene, Texas 79601-5820
(915) 674-7000
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 (or for such shorter period that the
Registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No__
Common Stock Outstanding at November 5, 1999 Shares
Central and South West Corporation 212,648,293
Central Power and Light Company 6,755,535
Public Service Company of Oklahoma 9,013,000
Southwestern Electric Power Company 7,536,640
West Texas Utilities Company 5,488,560
This Combined Form 10-Q 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.
<PAGE>
CENTRAL AND SOUTH WEST CORPORATION AND SUBSIDIARY COMPANIES
TABLE OF CONTENTS TO QUARTERLY REPORT ON FORM 10-Q
SEPTEMBER 30, 1999
GLOSSARY OF TERMS..............................................................3
FORWARD-LOOKING INFORMATION....................................................5
PART I. - FINANCIAL INFORMATION................................................6
ITEM 1. FINANCIAL STATEMENTS................................................6
CENTRAL AND SOUTH WEST CORPORATION.........................................6
CENTRAL POWER AND LIGHT COMPANY...........................................16
PUBLIC SERVICE COMPANY OF OKLAHOMA........................................24
SOUTHWESTERN ELECTRIC POWER COMPANY.......................................32
WEST TEXAS UTILITIES COMPANY..............................................40
NOTES TO FINANCIAL STATEMENTS.............................................49
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.......................................................68
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.........88
PART II. - OTHER INFORMATION..................................................90
ITEM 1. LEGAL PROCEEDINGS..................................................90
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K...................................90
SIGNATURES....................................................................91
2
<PAGE>
GLOSSARY OF TERMS
The following abbreviations or acronyms used in this text are defined below:
Abbreviation or Acronym Definition
AEP ....................American Electric Power Company, Inc.
AEP Merger .............Proposed merger between AEP and CSW in which CSW would
become a wholly-owned subsidiary of AEP
ALJ ....................Administrative Law Judge
Alpek ..................Alpek S.A. de C.V.
Altamira................CSW International cogeneration project in Altamira,
Tamaulipas, Mexico
Arkansas Commission ....Arkansas Public Service Commission
Btu ....................British thermal unit
C3 Communications ......C3 Communications, Inc., Austin, Texas (formerly CSW
Communications, Inc.)
Cajun ..................Cajun Electric Power Cooperative, Inc.
CLECO ..................Central Louisiana Electric Company, Inc.
Court of Appeals .......Court of Appeals, Third District of Texas, Austin, Texas
CPL ....................Central Power and Light Company, Corpus Christi, Texas
CPL 1997 Final Order ...Final orders received from the Texas Commission in CPL's
rate case Docket No., 14965, including both the order
received on September 10, 1997 and the revised order
received on October 16, 1997
CSW ....................Central and South West Corporation, Dallas, Texas
CSW Credit .............CSW Credit, Inc., Dallas, Texas
CSW Energy .............CSW Energy, Inc., Dallas, Texas
CSW International ......CSW International, Inc., Dallas, Texas
CSW Services ...........Central and South West Services, Inc., Dallas, Texas and
Tulsa, Oklahoma
CSW System .............CSW and its subsidiaries
DHMV ...................Dolet Hills Mining Venture
Diversified Electric ...CSW Energy and CSW International and their subsidiaries
ECOM ...................Excess cost over market
EITF 97-4...............Emerging Issues Task Force Consensus 97-4, Deregulation
of the Pricing of Electricity - Issues Related to the
Application of SFAS Nos. 71 and 101.
EPA ....................United States Environmental Protection Agency
ERCOT ..................Electric Reliability Council of Texas
ESPS....................Electricity Supply Pension Scheme
Exchange Act ...........Securities Exchange Act of 1934, as amended
EWG ....................Exempt Wholesale Generator
FCC.....................Federal Communications Commission
FERC ...................Federal Energy Regulatory Commission
Frontera................A 500 MW merchant power plant located near the city of
Mission, Texas owned by CSW Energy
FUCO ...................Foreign utility company as defined in the Holding
Company Act
FMBs....................First Mortgage Bonds
Holding Company Act ....Public Utility Holding Company Act of 1935, as amended
IBEW ...................International Brotherhood of Electrical Workers
July 1999 SWEPCO Plan...The amended plan of reorganization for Cajun filed by
the Members Committee and SWEPCO on July 28, 1999 with
the U.S. Bankruptcy Court for the Middle District of
Louisiana
Legislative Joint Electric Utility
Task Force............Task force created by the Oklahoma Legislature to
study electric utility industry restructuring issues in
the state of Oklahoma
LIFO ...................Last-in first-out (inventory accounting method)
Louisiana Commission ...Louisiana Public Service Commission
MD&A ...................Management's Discussion and Analysis of Financial
Condition and Results of Operations
MDEQ ...................Mississippi Department of Environmental Quality
MGP ....................Manufactured gas plant or coal gasification plant
Mississippi Power ......Mississippi Power Company
MMbtu ..................Million Btu
MW .....................Megawatt
MWH ....................Megawatt-hour
National Grid Group ....National Grid Group plc
National Power..........National Power plc
Northeastern Power
Station...............Northeastern Power Station, Oologah, Oklahoma
NRC ....................Nuclear Regulatory Commission
Numanco.................Nuvest, Inc., Numanco, LLC and Numanco, Inc.
3
<PAGE>
GLOSSARY OF TERMS (continued)
The following abbreviations or acronyms used in this text are defined below:
Abbreviation or Acronym Definition
OFGEM...................The Office of Gas and Electricity Markets, United
Kingdom
Oklahoma Commission ....Corporation Commission of the State of Oklahoma
PCB ....................Polychlorinated biphenyl
PRP ....................Potentially responsible party
PSO ....................Public Service Company of Oklahoma, Tulsa, Oklahoma
Registrant(s) ..........CSW, CPL, PSO, SWEPCO and WTU
SEC ....................United States Securities and Exchange Commission
SEEBOARD ...............SEEBOARD Group plc, Crawley, West Sussex, United Kingdom
SEEBOARD USA............CSW's investment in SEEBOARD as consolidated and
converted pursuant to U.S. Generally Accepted Accounting
Principles
SFAS ...................Statement of Financial Accounting Standards
SFAS No. 34.............Capitalization of Interest Cost
SFAS No. 52 ............Foreign Currency Translation
SFAS No. 71 ............Accounting for the Effects of Certain Types of
Regulation
SFAS No. 101............Regulated Enterprises - Accounting for the
Discontinuance of Application of SFAS No. 71
SFAS No. 121............Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of
STP ....................South Texas Project nuclear electric generating station
SWEPCO .................Southwestern Electric Power Company, Shreveport,
Louisiana
Texas Commission .......Public Utility Commission of Texas
Texas Legislation.......Texas Senate Bill 7 relating to deregulation of electric
utility industry
Trust Preferred
Securities............Collective term for securities issued by business trusts
of CPL, PSO and SWEPCO classified on the balance sheet
as Certain Subsidiary (or CPL/PSO/SWEPCO)-obligated,
mandatorily redeemable preferred securities of
subsidiary trusts holding solely Junior Subordinated
Debentures of such Subsidiaries (or CPL/PSO/SWEPCO)
U.K. Electric...........SEEBOARD USA
U.S. Electric Operating Companies or
U.S. Electric .....CPL, PSO, SWEPCO and WTU
UWUA....................Utility Workers Union of America
Vale ...................Empresa De Electricidade Vale Paranapanema S/A, a
Brazilian Electric Distribution Company
WTU ....................West Texas Utilities Company, Abilene, Texas
Yorkshire ..............Yorkshire Electricity Group plc, a regional electricity
company in the United Kingdom
4
<PAGE>
FORWARD-LOOKING INFORMATION
This report made by CSW and certain of its subsidiaries contains forward-looking
statements within the meaning of Section 21E of the Exchange Act. Although CSW
and each of its subsidiaries believe that their expectations are based on
reasonable assumptions, any such statements may be influenced by factors that
could cause actual outcomes and results to be materially different from those
projected. Important factors that could cause actual results to differ
materially from those in the forward-looking statements include, but are not
limited to:
- - the impact of general economic changes in the United States and in
countries in which CSW either currently has made or in the future may
make investments,
- - the impact of the proposed AEP Merger including any regulatory
conditions imposed on the merger, the inability to consummate the AEP
Merger, or other merger and acquisition activity,
- - increased competition and the restructuring of the electric utility
industry in the United States,
- - federal and state regulatory developments and changes in law which may
have a substantial adverse impact on the value of CSW System generating
and other assets,
- - timing and adequacy of rate relief,
- - adverse changes in electric load and customer growth,
- - climatic changes or unexpected changes in weather patterns,
- - changing fuel prices, generating plant and distribution facility
performance,
- - decommissioning costs associated with nuclear generating facilities,
- - costs associated with any year 2000 computer related failure(s) either
within the CSW System or supplier failures that adversely affect the
CSW System,
- - uncertainties in foreign operations and foreign laws affecting CSW's
investments in those countries,
- - the effects of retail competition in the natural gas and electricity
distribution and supply businesses in the United Kingdom,
- - the timing and success of efforts to develop domestic and international
power projects, and
- - risks associated with hedging and other risk management techniques.
In the non-utility area, the previously mentioned factors apply and also
include, but are not limited to:
- - the ability to compete effectively in new areas, including
telecommunications, power marketing and brokering, and other energy
related services, and
- - evolving federal and state regulatory legislation and policies that may
adversely affect those industries generally or the CSW System's
business in areas in which it operates.
5
<PAGE>
CSW
CENTRAL AND SOUTH WEST CORPORATION
PART I. - FINANCIAL INFORMATION.
ITEM 1. FINANCIAL STATEMENTS.
6
<PAGE>
CSW
Consolidated Statements of Income (unaudited)
Central and South West Corporation
- --------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
---------------- ----------------
1999 1998 1999 1998
------- ------- ------ -------
(millions, except per share amounts)
Operating Revenues
U.S. Electric $1,170 $1,172 $2,758 $2,746
United Kingdom 354 352 1,192 1,288
Other diversified 94 57 212 148
------- ------- ------ -------
1,618 1,581 4,162 4,182
Operating Expenses and Taxes
U.S. Electric fuel 386 388 908 939
U.S. Electric purchased power 54 39 119 86
United Kingdom cost of sales 211 224 747 879
Other operating 299 232 816 705
Maintenance 42 41 144 114
Depreciation and amortization 159 126 424 375
Taxes, other than income 39 44 152 145
Income taxes 93 143 162 218
------- ------- ------ -------
1,283 1,237 3,472 3,461
------- ------- ------ -------
Operating Income 335 344 690 721
------- ------- ------ -------
Other Income and (Deductions)
Other 9 5 33 33
Non-operating income taxes (2) 3 (9) 2
------- ------- ------ -------
7 8 24 35
------- ------- ------ -------
Income Before Interest and Other Charges 342 352 714 756
------- ------- ------ -------
Interest and Other Charges
Interest on long-term debt 74 78 227 238
Interest on short-term debt and other 29 33 83 92
Distributions on Trust Preferred Securities 7 7 20 20
Preferred dividend requirements of
subsidiaries 2 1 6 6
(Gain)/loss on reacquired preferred stock -- -- -- 1
------- ------- ------ -------
112 119 336 357
Income Before Extraordinary Item 230 233 378 399
Extraordinary loss (net of tax of $5) (8) -- (8) --
------- ------- ------ -------
Net Income for Common Stock $ 222 $ 233 $ 370 $ 399
======= ======= ====== =======
Average Common Shares Outstanding 212.6 212.5 212.6 212.3
Basic & Diluted Earnings per Share before
Extraordinary Item 1.08 1.10 1.78 1.88
Basic & Diluted Earnings per Share from
Extraordinary Item (0.04) 0.00 (0.04) 0.00
------- ------- ------ -------
Basic and Diluted Earnings per Share $ 1.04 $ 1.10 $ 1.74 $ 1.88
======= ======= ====== =======
Dividends Paid per Share of Common Stock $0.435 $0.435 $1.305 $1.305
======= ======= ====== =======
The accompanying notes to consolidated financial statements are an
integral part of these statements.
7
<PAGE>
CSW
Consolidated Statements of Stockholders' Equity
Central and South West Corporation
(millions)
<TABLE>
<CAPTION>
Accumulated
Additional Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------------------------------------------- ------
<S> <C> <C> <C> <C> <C>
(audited)
Beginning Balance -- January 1, 1998 $743 $1,039 $1,751 $23 $3,556
Sale of common stock 1 10 -- -- 11
Common stock dividends -- -- (370) -- (370)
Other -- -- 2 -- 2
-------
3,199
Comprehensive Income:
Foreign currency translation adjustment
(net of tax of $2) -- -- -- 7 7
Unrealized loss on securities
(net of tax of $8) -- -- -- (14) (14)
Adjustment for gain included in net
income(net of tax of $4) -- -- -- (7) (7)
Minimum pension liability
(net of tax of $0.6) -- -- -- (1) (1)
Net Income -- -- 440 -- 440
-------
Total comprehensive income 425
Ending Balance -- December 31, 1998 $744 $1,049 $1,823 $8 $3,624
=========================================== ======
(unaudited)
Beginning Balance -- January 1, 1999 $744 $1,049 $1,823 $8 $3,624
Sale of common stock -- 2 -- -- 2
Common stock dividends -- -- (277) -- (277)
Other -- -- (1) -- (1)
------
3,348
Comprehensive Income:
Foreign currency translation adjustment
(net of tax of $27) -- -- -- (50) (50)
Unrealized gain on securities
(net of tax of $5) -- -- -- 9 9
Net Income -- -- 370 -- 370
------
Total comprehensive income 329
------------------------------------------- ------
Ending Balance -- September 30, 1999 $744 $1,051 $1,915 ($33) $3,677
=========================================== ======
</TABLE>
The accompanying notes to consolidated financial statements are an
integral part of these statements.
8
<PAGE>
CSW
Consolidated Balance Sheets
Central and South West Corporation
September 30 December 31,
1999 1998
(unaudited) (audited)
------------ ------------
(millions)
ASSETS
Fixed Assets
Electric
Production $ 5,883 $ 5,887
Transmission 1,636 1,594
Distribution 4,843 4,681
General 1,418 1,380
Construction work in progress 214 166
Nuclear fuel 219 207
------------ ------------
14,213 13,915
Other diversified 452 333
------------ ------------
14,665 14,248
Less - Accumulated depreciation and amortization 5,941 5,652
------------ ------------
8,724 8,596
------------ ------------
Current Assets
Cash and temporary cash investments 160 157
Accounts receivable 1,462 1,110
Materials and supplies, at average cost 145 191
Electric utility fuel inventory 112 90
Under-recovered fuel costs 45 4
Notes receivable 119 109
Prepayments and other 126 90
------------ ------------
2,169 1,751
------------ ------------
Deferred Charges and Other Assets
Regulatory assets 1,251 1,266
Other non-utility investments 406 432
Securities available for sale 62 66
Goodwill 1,362 1,402
Other 457 384
------------ ------------
3,538 3,550
------------ ------------
$14,431 $13,897
============ ============
The accompanying notes to consolidated financial statements are an
integral part of these statements.
9
<PAGE>
CSW
Consolidated Balance Sheets
Central and South West Corporation
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
(unaudited) (audited)
------------ ------------
CAPITALIZATION AND LIABILITIES (millions)
<S> <C> <C> <C> <C>
Capitalization
Common stock: $3.50 par value
Authorized shares: 350.0 million
Issued and outstanding shares: 212.6 million $ 744 $ 744
Paid-in capital 1,051 1,049
Retained earnings 1,915 1,823
Accumulated other comprehensive income/(loss) (33) 8
------------ ------------
Total Common Stock Equity 3,677 46% 3,624 45%
------------ --- ------------ ---
Preferred stock 176 2% 176 2%
------------ --- ------------ ---
Certain Subsidiary-obligated, mandatorily
redeemable preferred securities of
subsidiary trusts holding solely
Junior Subordinated Debentures of such
Subsidiaries 335 4% 335 4%
Long-term debt 3,804 48% 3,938 49%
------------ --- ------------ ---
Total Capitalization 7,992 100% 8,073 100%
------------ --- ------------ ---
Current Liabilities
Long-term debt and preferred stock due within
twelve months 223 169
Short-term debt 1,064 811
Short-term debt - CSW Credit 944 749
Loan notes 30 32
Accounts payable 501 624
Accrued taxes 280 190
Accrued interest 107 84
Customer deposits 78 80
Other 200 138
------------ ------------
3,427 2,877
------------ ------------
Deferred Credits
Accumulated deferred income taxes 2,406 2,410
Investment tax credits 257 267
Other 349 270
------------ ------------
3,012 2,947
------------ ------------
$ 14,431 $ 13,897
============ ============
</TABLE>
The accompanying notes to consolidated financial statements are an
integral part of these statements.
10
<PAGE>
CSW
Consolidated Statements of Cash Flows (unaudited)
Central and South West Corporation
- --------------------------------------------------------------------------------
Nine Months Ended
September 30,
----------------
1999 1998
------- -------
OPERATING ACTIVITIES (millions)
Net Income for Common Stock $ 370 $ 399
Non-cash Items and Adjustments
Depreciation and amortization 444 436
Deferred income taxes and investment tax credits (17) (19)
Preferred stock dividends included in Net Income for
Common Stock 6 6
Loss on reacquired preferred stock -- 1
Extraordinary loss related to SFAS No. 71 8 --
Changes in Assets and Liabilities
Accounts receivable (352) (486)
Accounts payable (17) 62
Accrued taxes 97 211
Fuel inventory (22) (19)
Fuel recovery (66) 73
Other 1 (40)
------- -------
452 624
------- -------
INVESTING ACTIVITIES
Construction expenditures (439) (339)
CSW Energy/CSW International projects (103) (143)
Other (23) 1
------- -------
(565) (481)
------- -------
FINANCING ACTIVITIES
Common stock sold 2 8
Long-term debt sold 33 5
Reacquisition/retirement of long-term debt (202) (181)
Reacquisition of preferred stock -- (28)
Change in short-term debt 448 365
Payment of dividends (283) (279)
Other 120 73
------- -------
118 (37)
------- -------
Effect of exchange rate changes on cash and cash equivalents (2) 2
Net Change in Cash and Cash Equivalents 3 108
Cash and Cash Equivalents at Beginning of Period 157 75
------- -------
Cash and Cash Equivalents at End of Period $ 160 $ 183
======= =======
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized $ 289 $ 249
======= =======
Income taxes paid $ 105 $ 49
======= =======
The accompanying notes to consolidated financial statements are an
integral part of these statements.
11
<PAGE>
CENTRAL AND SOUTH WEST CORPORATION AND SUBSIDIARY COMPANIES RESULTS OF
OPERATIONS
Set forth below is information concerning the consolidated results of
operations of CSW for the three and nine month periods ended September 30, 1999
and September 30, 1998. For information concerning the results of operations for
each of the U.S. Electric Operating Companies, see the discussion under the
heading RESULTS OF OPERATIONS following the financial statements of each of the
U.S. Electric Operating Companies.
COMPARISON OF THE QUARTERS ENDED SEPTEMBER 30, 1999 AND 1998
CSW's net income for common stock decreased $11 million to $222 million in
the third quarter of 1999 compared to $233 million in 1998. Earnings decreased
due primarily to increased other operating expenses and higher depreciation and
amortization. Partially offsetting these increased expenses were increased
operating revenues from CSW Energy and lower income tax expense. See NOTE 2.
LITIGATION AND REGULATORY PROCEEDINGS Electric Utility Restructuring Legislation
for information affecting earnings due to restructuring legislation in Texas and
Arkansas. Various factors affecting third quarter earnings are discussed below.
In the third quarter of 1999, the U.S. Electric Operating Companies and
U.K. Electric contributed the following percentages to CSW's results of
operations.
Corporate
U.S. U.K. Total Items and
Electric Electric Electric Other Total
--------------------------------------------------
Operating Revenues 72% 22% 94% 6% 100%
Operating Income 84% 13% 97% 3% 100%
Income before
Extraordinary Item 95% 9% 104% (4)% 100%
Operating revenues increased $37 million or 2% in the third quarter of
1999 compared to the same period a year ago due primarily to an increase in
other diversified revenue resulting from the Frontera plant beginning commercial
operations. Although operating revenues from U.S. Electric operations for the
third quarter of 1999 were virtually flat when compared to the third quarter of
1998, there were large changes in the components of operating revenue. Fuel
related revenues increased $11 million due to higher combined fuel expense as
discussed in the following paragraph and increased sales to wholesale customers.
Non-fuel related revenues decreased $14 million. Although non-fuel revenues from
wholesale customers increased $21 million due to increased demand, non-fuel
revenue from retail customers decreased $17 million due to milder weather in the
third quarter of 1999. Also contributing to the decrease, revenue from electric
service rendered and not yet billed decreased $12 million, and other non-MWH
revenue decreased $10 million due primarily to the charge to revenues to reflect
the excess earnings provision under the Texas Legislation. See NOTE 2.
LITIGATION AND REGULATORY PROCEEDINGS - Electric Utility Restructuring
Legislation. Partially offsetting these decreases to non-fuel revenue,
transmission related revenues increased $4 million primarily from changes to
CSW's transmission coordination agreement. See NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS - Transmission Coordination Agreement.
U.S. Electric fuel expense decreased $2 million or 1% during the third
quarter of 1999 compared to the same period a year ago due primarily to a
decrease of $30 million in the recovery of deferred fuel costs resulting from a
significant difference in fuel factors used to recover fuel expense from
customers at PSO. The decrease was almost entirely offset by an increase in the
12
<PAGE>
average unit fuel cost to $1.93 per MMbtu from $1.70 per MMbtu. The increase was
due to higher spot market natural gas prices. Purchased power expense increased
$15 million or 38% for the comparison periods due primarily to higher economy
energy purchases and the unscheduled outage of a coal-fired generating power
plant. United Kingdom cost of sales decreased $13 million or 6% in the third
quarter of 1999 compared to the same period a year ago due primarily to
fluctuation in exchange rates.
Other operating expense increased $67 million or 29% in the third quarter
of 1999 compared to the same period a year ago. Other operating expenses
increased $28 million at SEEBOARD primarily as a result of additional operating
costs related to SEEBOARD's Powerlink joint venture to operate and maintain the
electricity assets for the London Underground Rail System as well as increased
expenses associated with operating in the competitive electricity market in the
United Kingdom. CSW Energy's operating expenses also increased $27 million as a
result of increased business activity at several of its plants. Also
contributing to the increase in other operating expense were increased
transmission expenses at the U.S. Electric operating companies related to the
1999 transmission coordination agreement adjustments. See NOTE 2. LITIGATION AND
REGULATORY PROCEEDINGS - Transmission Coordination Agreement.
Depreciation and amortization expense increased $33 million or 26% in the
third quarter of 1999 compared to the same period a year ago due primarily to
the recording of accelerated capital recovery under the excess earnings
provisions of the Texas Legislation. See NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS - Electric Utility Restructuring Legislation.
Taxes, other than income decreased $5 million or 11% in the third quarter
of 1999 due to decreased ad valorem tax expense partially offset by higher state
franchise taxes.
Income taxes decreased $50 million or 35% in the third quarter of 1999
compared to the same period a year ago due to lower taxable income, the
reclassification of income tax related regulatory assets amortization to
depreciation and amortization expense consistent with the Texas Legislation at
CPL, and prior year adjustments to prior year income taxes. See NOTE 2.
LITIGATION AND REGULATORY PROCEEDINGS - Electric Utility Restructuring
Legislation.
Interest and other charges decreased $7 million or 6% in the third quarter
of 1999 compared to the same period a year ago due primarily to the maturity and
reacquisition of long-term debt during 1998 and 1999 which was partially offset
by higher interest charges related to an increase in short-term borrowings.
The extraordinary loss resulted from legislation passed in Texas and
Arkansas under which the electricity generation portion of CPL's, SWEPCO's and
WTU's business in those states to no longer meet the criteria to apply SFAS No.
71. These changes resulted in an extraordinary loss, which had a cumulative
effect of decreasing net income by $8.0 million. See NOTE 2. LITIGATION AND
REGULATORY PROCEEDINGS - Electric Utility Restructuring Legislation.
COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
Net income for common stock decreased $29 million to $370 million in the
first nine months of 1999 from $399 million for the same period in 1998 due
primarily to increased operations and maintenance expenses and higher
depreciation and amortization. The decrease in earnings was offset in part by
higher non-fuel revenue for U.S. Electric operations due primarily to increased
off-system sales and customer usage and growth, which were partially offset by
milder weather. Various factors affecting earnings are discussed below.
13
<PAGE>
In the first nine months of 1999, the U.S. Electric Operating Companies
and U.K. Electric contributed the following percentages to CSW's results of
operations.
Corporate
U.S. U.K. Total Items and
Electric Electric Electric Other Total
-------------------------------------------------
Operating Revenues 66% 29% 95% 5% 100%
Operating Income 79% 19% 98% 2% 100%
Income before
Extraordinary Item 91% 18% 109% (9)% 100%
Operating revenues decreased $20 million in the first nine months of 1999
compared to the same period in 1998 due to lower revenues from United Kingdom
operations. U.K. Electric revenues decreased $96 million in the first nine
months of 1999 compared to the same period a year ago due primarily to lower
sales volumes in the business market and the loss of domestic customers
following the opening of the electricity market to competition. Also
contributing to the decrease in U.K. Electric revenues were the absence of
revenues in 1999 from SEEBOARD's retail business, which was sold in June 1998,
and unfavorable British pound to U.S. dollar exchange rate movements, partially
offset by revenues from SEEBOARD's new Powerlink joint venture. Partially
offsetting the decrease in operating revenues was an increase in other
diversified revenues of $64 million for the comparison periods due primarily to
increased business activity at CSW Energy. Also partially offsetting the decline
in operating revenues was higher U.S. Electric fuel revenues due to higher
combined fuel expense as discussed in the following paragraph and increased
sales to wholesale customers. Further offsetting the decrease in operating
revenues was higher non-fuel revenues of $4 million at the U.S. Electric
Operating Companies due primarily to increased customer usage and growth and
increased off-system sales.
U.S. Electric fuel expense decreased $31 million or 3% during the first
nine months of 1999 compared to the same period a year ago due primarily to a
$41 million decrease in the recovery of deferred fuel costs that resulted from a
significant difference in fuel factors used to recover fuel expense from
customers at PSO. The decrease in fuel expense was offset in part by an increase
in the average unit fuel cost to $1.78 per MMbtu in 1999 from $1.71 per MMbtu in
1998. The increase resulted primarily from higher natural gas and coal prices.
Purchased power expenses increased $33 million or 38% for the comparison periods
primarily at CPL and WTU. Purchased power expense increased at CPL due primarily
to the refueling and 10-year inspection of STP Unit 1 as well as increased
short-term economy energy purchases. Purchased power expense increased at WTU
due primarily to an unscheduled outage at a coal-fired generating plant. United
Kingdom cost of sales decreased $132 million or 15% in the first nine months of
1999 compared to the same period a year ago. The decrease was due primarily to a
lower level of sales of electricity, the absence in 1999 of cost of sales for
SEEBOARD's retail business and a lower British pound to U.S. dollar exchange
rate compared to 1998.
Other operating expense increased $111 million or 16% in the first nine
months of 1999 compared to the same period a year ago due primarily to increased
expenses of $51 million at SEEBOARD. Expenses increased at SEEBOARD as a result
of additional operating costs related to SEEBOARD's Powerlink joint venture to
operate and maintain the electricity assets for the London Underground Rail
System as well as increased expenses associated with operating in the
competitive electricity market in the United Kingdom. CSW Energy's operating
expenses also increased $30 million as a result of increased business activity
at several of its plants. Also contributing to the increase in other operating
expense were increased transmission expenses at the U.S. Electric operating
companies related to the 1999 transmission coordination agreement adjustments.
See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - Transmission Coordination
Agreement. Maintenance expense increased $30 million or 26% due primarily to
increased expenses associated with the 10-year inspection of STP Unit 1, as well
as scheduled maintenance at other CSW System power plants.
14
<PAGE>
Depreciation and amortization expense increased $49 million or 13% in the
first nine months of 1999 compared to the same period a year ago due to the
recording of accelerated capital cost recovery under the excess earnings
provisions of the Texas Legislation and to higher levels of depreciable plant.
See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - Electric Utility
Restructuring Legislation.
Taxes, other than income increased $7 million or 5% in the first nine
months of 1999 compared to the same period a year ago due primarily to higher
Texas state franchise taxes. Operating income taxes decreased $56 million or 26%
due primarily to lower taxable income, the reclassification of income tax
related regulatory assets amortization to depreciation and amortization expense
consistent with the Texas Legislation at CPL, and prior year adjustments to
prior year income taxes. See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS -
Electric Utility Restructuring Legislation.
Interest and other charges decreased $21 million or 6% in the first nine
months of 1999 compared to the same period a year ago. This resulted primarily
from lower interest expense on long-term debt in the amount of $11 million
related to the maturity and reacquisition of long-term debt. Also contributing
to the decrease in Interest and other charges was lower Interest on short-term
debt and other of $9 million due primarily to the absence in 1999 of the
interest expense related to the CPL 1998 bonded rate refund and lower interest
rates on short-term financing.
The extraordinary loss resulted from legislation passed in Texas and
Arkansas under which the electricity generation portion of CPL's, SWEPCO's and
WTU's business in those states to no longer meet the criteria to apply SFAS No.
71. These changes resulted in an extraordinary loss, which had a cumulative
effect of decreasing net income by $8.0 million. See NOTE 2. LITIGATION AND
REGULATORY PROCEEDINGS - Electric Utility Restructuring Legislation.
15
<PAGE>
CPL
CENTRAL POWER AND LIGHT COMPANY
PART I. - FINANCIAL INFORMATION.
ITEM 1. FINANCIAL STATEMENTS.
16
<PAGE>
CPL
Consolidated Statement of Income (unaudited)
Central Power and Light Company
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- --------- ---------
(thousands)
Electric Operating Revenues $495,653 $454,403 $1,161,714 $1,092,506
-------- -------- --------- ---------
Operating Expenses and Taxes
Fuel 138,020 121,129 312,333 302,406
Purchased power 24,229 12,198 53,624 28,733
Other operating 68,947 55,276 196,471 178,030
Maintenance 13,615 15,361 48,797 42,886
Depreciation and amortization 68,160 42,903 154,531 126,892
Taxes, other than income 14,899 14,664 61,194 55,719
Income taxes 40,062 64,369 80,382 104,541
-------- -------- --------- ---------
367,932 325,900 907,332 839,207
-------- -------- --------- ---------
Operating Income 127,721 128,503 254,382 253,299
-------- -------- --------- ---------
Other Income and (Deductions)
Allowance for equity funds used
during construction (1) 59 (1) 51
Other (539) (3,141) (1,919) (592)
Non-operating income taxes 2,620 1,964 6,147 3,055
-------- -------- --------- ---------
2,080 (1,118) 4,227 2,514
-------- -------- --------- ---------
Income Before Interest Charges 129,801 127,385 258,609 255,813
-------- -------- --------- ---------
Interest Charges
Interest on long-term debt 21,006 23,331 65,433 70,397
Distributions on Trust Preferred
Securities 3,000 3,000 9,000 9,000
Interest on short-term debt and
other 2,430 1,200 13,494 16,025
Allowance for borrowed funds used
during construction (846) (607) (2,464) (1,948)
-------- -------- --------- ---------
25,590 26,924 85,463 93,474
-------- -------- --------- ---------
Net Income 104,211 100,461 173,146 162,339
Less: Preferred stock dividends 1,979 1,320 5,527 4,929
-------- -------- --------- ---------
Net Income for Common Stock $102,232 $99,141 $167,619 $157,410
======== ======== ========= =========
The accompanying notes to consolidated financial statements as they relate to
CPL are an integral part of these statements.
17
<PAGE>
CPL
Consolidated Balance Sheets
Central Power and Light Company
September 30, December 31,
1999 1998
(unaudited) (audited)
------------- -------------
(thousands)
ASSETS
Electric Utility Plant
Production $3,150,632 $ 3,146,269
Transmission 547,040 527,146
Distribution 1,133,759 1,090,175
General 298,247 298,352
Construction work in progress 100,626 67,300
Nuclear fuel 218,571 206,949
------------- -------------
5,448,875 5,336,191
------------- -------------
Less - Accumulated depreciation 2,230,908 2,072,686
------------- -------------
3,217,967 3,263,505
------------- -------------
Current Assets
Cash and temporary investments 12,460 5,195
Accounts receivable from affiliates 13,678 5,276
Accounts receivable 46,941 45,780
Materials and supplies, at average cost 57,937 59,814
Fuel inventory, at LIFO cost 23,383 20,340
Under-recovered fuel cost 22,676 --
Accumulated deferred income taxes -- 713
Prepayments and other 10,269 2,952
------------- -------------
187,344 140,070
------------- -------------
Deferred Charges and Other Assets
Regulatory assets 1,184,066 1,099,631
Nuclear decommissioning trust 76,948 65,972
Other 107,331 167,011
------------- -------------
1,368,345 1,332,614
------------- -------------
$4,773,656 $ 4,736,189
============= =============
The accompanying notes to consolidated financial statements as they relate to
CPL are an integral part of these statements.
18
<PAGE>
CPL
Consolidated Balance Sheets
Central Power and Light Company
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
(unaudited) (audited)
------------ ------------
CAPITALIZATION AND LIABILITIES (thousands)
<S> <C> <C> <C> <C>
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 795,651 739,031
------------ ------------
Total Common Stock Equity 1,369,539 49% 1,312,919 46%
------------ ---- ------------ ----
Preferred stock 163,203 6% 163,204 6%
CPL-obligated, mandatorily redeemable preferred
securities of subsidiary trust holding
solely Junior Subordinated Debentures
of CPL 150,000 5% 150,000 5%
Long-term debt 1,101,136 40% 1,225,706 43%
------------ ---- ------------ ----
Total Capitalization 2,783,878 100% 2,851,829 100%
------------ ---- ------------ ----
Current Liabilities
Long-term debt due within twelve months 125,000 125,000
Advances from affiliates 251,692 160,298
Payables to affiliates 19,027 38,331
Accounts payable 98,555 86,998
Customer deposits 11,621 9,272
Accrued interest 27,255 27,036
Accrued taxes 74,789 46,855
Accumulated deferred income taxes 3,973 --
Over-recovered fuel costs -- 9,135
Other 11,721 9,547
------------ ------------
623,633 512,472
------------ ------------
Deferred Credits
Accumulated deferred income taxes 1,220,732 1,221,561
Investment tax credits 134,608 138,513
Other 10,805 11,814
------------ ------------
1,366,145 1,371,888
------------ ------------
$ 4,773,656 $ 4,736,189
============ ============
</TABLE>
The accompanying notes to consolidated financial statements as they relate t
CPL are an integral part of these statements.
19
<PAGE>
CPL
Consolidated Statements of Cash Flows (unaudited)
Central Power and Light Company
Nine Months Ended
September 30,
------------------------
1999 1998
--------- ---------
(thousands)
OPERATING ACTIVITIES
Net Income $173,146 $162,339
Non-cash Items Included in Net Income
Depreciation and amortization 169,023 181,237
Deferred income taxes and investment tax
credits (6,142) (3,886)
Refund due customers -- (63,713)
Changes in Assets and Liabilities
Accounts receivable (9,563) (40,844)
Fuel inventory (3,043) (4,279)
Material and supplies 1,877 6,822
Accounts payable (8,041) 10
Accrued taxes 27,935 85,068
Fuel recovery (31,811) 49,413
Other (23,337) (29,735)
--------- ---------
290,044 342,432
--------- ---------
INVESTING ACTIVITIES
Construction expenditures (138,506) (84,348)
Other 5,810 (6,400)
--------- ---------
(132,696) (90,748)
--------- ---------
FINANCING ACTIVITIES
Payment of dividends (116,476) (172,684)
Retirement of long-term debt (125,000) (64,000)
Redemption of preferred stock (1) --
Change in advances from affiliates 91,394 (15,000)
--------- ---------
(150,083) (251,684)
--------- ---------
Net Change in Cash and Cash Equivalents 7,265 --
Cash and Cash Equivalents at Beginning of Year 5,195 --
--------- ---------
Cash and Cash Equivalents at End of Period $ 12,460 $ --
========= =========
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized (includes
distributions on Trust Preferred Securities) $ 75,012 $ 88,021
========= =========
Income taxes paid $ 50,798 $ 19,364
========= =========
The accompanying notes to consolidated financial statements as they relate to
CPL are an integral part of these statements.
20
<PAGE>
CENTRAL POWER AND LIGHT COMPANY
RESULTS OF OPERATIONS
COMPARISON OF THE QUARTERS ENDED SEPTEMBER 30, 1999 AND 1998
CPL's net income for common stock for the third quarter of 1999 was $102.2
million, which was $3.1 million higher than the comparable period in 1998. The
increase was primarily the result of higher non-fuel related revenues and lower
tax expenses which were partially offset by an increase in other operating
expenses and higher depreciation and amortization expenses.
Electric operating revenues for the third quarter of 1999 were $495.7
million, which was $41.3 million or 9% higher than the comparable period in
1998. The increase was attributable to higher fuel-related revenue of $30.4
million due to higher combined fuel expense and purchased power expense as
discussed in the following paragraph. The $10.9 million increase in non-fuel
related revenue was primarily the result of changes to CSW's transmission
coordination agreement of $21.0 million which were offset in part by a decrease
in revenue from electric services rendered and not yet billed as well as a
decrease in retail MWH sales attributable to milder weather in 1999. See NOTE 2.
LITIGATION AND REGULATORY PROCEEDINGS - Transmission Coordination Agreement.
Fuel expense during the third quarter of 1999 was $138.0 million, which
was $16.9 million or 14% higher than the comparable period in 1998. The average
unit fuel cost for the quarter increased from $1.60 per MMbtu in 1998 to $1.94
per MMbtu in 1999, which was the result of higher spot market natural gas and
coal prices. Purchased power expense during the third quarter of 1999 was $24.2
million, which was $12.0 million or 99% higher than the comparable period in
1998. The increase was due primarily to an increase in short-term economy energy
purchases.
Other operating expenses for the third quarter of 1999 were $68.9 million,
which was $13.7 million or 25% higher than the same period in 1998. The increase
was due primarily to higher outside service expenses, as well as higher
transmission expenses. The increase in transmission expense was due to the
absence in 1999 of a transmission service agreement adjustment made in 1998
related to the final order in Texas Commission Docket No. 17285. See NOTE 2.
LITIGATION AND REGULATORY PROCEEDINGS - CPL and WTU Complaint Versus Texas
Utilities Electric Company (Docket No. 17285).
Depreciation and amortization expenses increased $25.3 million or 59% for
the third quarter of 1999 due primarily to the recording of accelerated capital
recovery under the provisions of the Texas Legislation. See NOTE 2. LITIGATION
AND REGULATORY PROCEEDINGS Electric Utility Restructuring Legislation.
Income tax expense associated with utility operations were $40.1 million,
which was $24.3 million lower than the third quarter of 1998 as a result of
lower taxable income for the third quarter of 1999, the reclassification of
income tax related regulatory assets amortization to depreciation and
amortization expense consistent with the Texas Legislation, and prior year
adjustments to prior year income taxes. See NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS - Electric Utility Restructuring Legislation.
Interest charges during the third quarter of 1999 were $25.6 million,
which was $1.3 million or 5% lower than the comparable period in 1998. The
21
<PAGE>
decrease was due primarily to the maturity and reacquisition of long-term debt
during 1998 and 1999 which was partially offset by higher interest charges
related to an increase in short-term borrowings.
COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
CPL's net income for common stock for the nine months ended September 30,
1999 was $167.6 million, which was $10.2 million or 6% higher than the
comparable period in 1998. The increase resulted from higher non-fuel related
revenues and lower tax expenses partially offset by an increase in other
operating expenses, maintenance expenses, as well as higher depreciation and
amortization expenses.
Electric operating revenues for the nine months ended September 30, 1999
were $1,161.7 million, which was $69.2 million or 6% higher than the comparable
period in 1998. The increase was attributable to higher fuel-related revenue of
$36.4 million due to higher combined fuel expense and purchased power expense as
discussed in the following paragraph. The $32.8 million increase in non-fuel
related revenue was primarily the result of changes to CSW's transmission
coordination agreement of $21.0 million offset in part by revenue from electric
services rendered and not yet billed. See NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS - Transmission Coordination Agreement. Additionally, non-fuel
related revenues increased $14.5 million due primarily to a 3% increase in
retail MWH sales for higher customer demand.
Fuel expense for the nine months ended September 30, 1999 was $312.3
million, which was $9.9 million or 3% higher than the comparable period in 1998.
The average unit fuel cost for the nine months increased from $1.61 per MMbtu in
1998 to $1.69 per MMbtu in 1999 which was the result of higher spot market
natural gas and coal prices. Purchased power expense for the nine months ended
September 30, 1999 was $53.6 million, which was $24.9 million or 87% higher than
the comparable period in 1998. The increase resulted primarily from a
combination of several scheduled power plant outages for routine maintenance,
including STP Unit 1 for refueling and 10-year inspection, and short-term
economy energy purchases.
Other operating expense for the nine months ended September 30, 1999 was
$196.5 million, which was $18.4 million or 10% higher than the comparable period
in 1998. The increase was due primarily to higher outside service expense, as
well as, higher transmission expenses. The increase in transmission expenses was
due to the absence in 1999 of a transmission service agreement adjustment made
in 1998 related to the final order in Texas Commission Docket No. 17285. See
NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - CPL AND WTU Complaint versus
Texas Utilities Electric Company (Docket No. 17285).
Maintenance expense for the nine months ended September 30, 1999 was $48.8
million, which was $5.9 million or 14% higher than the comparable period in
1998. This was largely due to scheduled power plant repairs and maintenance,
including the refueling and 10-year inspection of STP Unit 1.
Depreciation and amortization expenses increased $27.6 million or 22% for
the nine months ended September 30, 1999 due primarily to the recording of
accelerated capital recovery under the excess earnings provisions of Texas
Legislation. See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - Electric
Utility Restructuring Legislation.
Taxes, other than income for the nine months ended September 30, 1999 were
$61.2 million, which was $5.5 million or 10% higher than the comparable period
of 1998. The increase was primarily attributable to higher state franchise
taxes.
22
<PAGE>
Income tax expense associated with utility operations was $80.4 million,
which was $24.2 million or 23% lower than the comparable period of 1998 as a
result of lower taxable income for 1999, the reclassification of income tax
related regulatory assets amortization to depreciation and amortization expense
consistent with the Texas Legislation, and prior year adjustments to prior year
income taxes. See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - Electric
Utility Restructuring Legislation.
Interest charges for the nine months ended September 30, 1999 were $85.5
million, which was $8.0 million or 9% lower than the comparable period of 1998.
The decrease was due primarily to the reacquisition and maturity of long-term
debt during 1998 and 1999. In addition, interest charges in 1998 were higher
related to the one time 1998 bonded rate refund which were partially offset by
higher interest charges related to an increase in short-term borrowings in 1999.
23
<PAGE>
PSO
PUBLIC SERVICE COMPANY OF OKLAHOMA
PART I. - FINANCIAL INFORMATION.
ITEM 1. FINANCIAL STATEMENTS.
24
<PAGE>
PSO
Consolidated Statements of Income (unaudited)
Public Service Company of Oklahoma
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
1999 1998 1999 1998
-------- -------- -------- --------
(thousands)
Electric Operating Revenues $258,656 $279,833 $588,385 $623,110
-------- -------- -------- --------
Operating Expenses and Taxes
Fuel 82,076 104,704 208,873 242,891
Purchased power 20,278 17,594 50,450 44,891
Other operating 35,533 20,102 88,083 75,478
Maintenance 8,768 8,014 30,695 23,899
Depreciation and amortization 18,558 18,202 55,557 54,358
Taxes, other than income 7,591 7,363 23,810 22,583
Income taxes 27,995 40,282 37,173 52,564
-------- -------- -------- --------
200,799 216,261 494,641 516,664
-------- -------- -------- --------
Operating Income 57,857 63,572 93,744 106,446
-------- -------- -------- --------
Other Income and (Deductions)
Allowance for equity funds used
during construction 125 293 206 519
Other 157 242 (1,638) 24
Non-operating income taxes 1,148 56 2,352 430
-------- -------- -------- --------
1,430 591 920 973
-------- -------- -------- --------
Income Before Interest Charges 59,287 64,163 94,664 107,419
-------- -------- -------- --------
Interest Charges
Interest on long-term debt 6,809 7,287 20,031 22,524
Distributions on Trust Preferred
Securities 1,500 1,500 4,500 4,500
Interest on short-term debt and
other 1,072 736 3,749 3,200
Allowance for borrowed funds
used during construction (488) (281) (1,072) (943)
-------- -------- -------- --------
8,893 9,242 27,208 29,281
-------- -------- -------- --------
Net Income 50,394 54,921 67,456 78,138
Less: Preferred stock dividends 54 54 160 160
-------- -------- -------- --------
Net Income for Common Stock $ 50,340 $ 54,867 $ 67,296 $ 77,978
======== ======== ======== ========
The accompanying notes to consolidated financial statements as they relate to
PSO are an integral part of these statements.
25
<PAGE>
PSO
Consolidated Balance Sheets
Public Service Company of Oklahoma
- --------------------------------------------------------------------------------
September 30, December 31,
1999 1998
(unaudited) (audited)
---------------- --------------
(thousands)
ASSETS
Electric Utility Plant
Production $ 914,073 $ 913,083
Transmission 390,500 378,719
Distribution 877,664 855,277
General 214,645 211,124
Construction work in progress 39,295 33,519
---------------- --------------
2,436,177 2,391,722
Less - Accumulated depreciation 1,104,846 1,082,081
---------------- --------------
1,331,331 1,309,641
---------------- --------------
Current Assets
Cash 3,792 4,670
Accounts receivable 24,840 32,916
Materials and supplies, at average cost 33,426 33,006
Fuel inventory, at LIFO cost 17,631 16,441
Under-recovered fuel costs 9,555 --
Accumulated deferred income taxes 22,003 11,789
Prepayments and other 6,783 2,881
---------------- --------------
118,030 101,703
---------------- --------------
Deferred Charges and Other Assets 82,117 71,384
---------------- --------------
$ 1,531,478 $ 1,482,728
================ ==============
The accompanying notes to consolidated financial statements as they relate to
PSO are an integral part of these statements.
26
<PAGE>
PSO
Consolidated Balance Sheets
Public Service Company of Oklahoma
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
(unaudited) (audited)
------------ -----------
CAPITALIZATION AND LIABILITIES (thousands)
<S> <C> <C> <C> <C>
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 166,922 144,626
------------ -----------
Total Common Stock Equity 504,152 53% 481,856 51%
------------ --------- ----------- -----
Preferred stock 5,286 -- % 5,287 -- %
PSO-obligated, mandatorily redeemable
preferred securities of subsidiary trust
holding solely Junior Subordinated
Debentures of PSO 75,000 8% 75,000 8%
Long-term debt 374,440 39% 384,064 41%
------------ --------- ----------- -----
Total Capitalization 958,878 100% 946,207 100%
------------ --------- ----------- -----
Current Liabilities
Long-term debt due within twelve months 10,000 --
Advances from affiliates 20,392 15,892
Payables to affiliates 23,201 33,489
Accounts payable 46,444 52,888
Customer deposits 17,671 17,368
Accrued interest 10,184 7,606
Accrued taxes 38,858 23,095
Over-recovered fuel costs -- 15,240
Other 9,376 6,599
------------ -----------
176,126 172,177
------------ -----------
Deferred Credits
Accumulated deferred income taxes 304,273 277,181
Investment tax credits 38,022 39,365
Income tax related regulatory
liabilities, net 31,438 35,818
Other 22,741 11,980
------------ -----------
396,474 364,344
------------ -----------
$ 1,531,478 $1,482,728
============ ===========
</TABLE>
The accompanying notes to consolidated financial statements as they relate to
PSO are an integral part of these statements.
27
<PAGE>
PSO
Consolidated Statements of Cash Flows (unaudited)
Public Service Company of Oklahoma
Nine Months Ended
September 30,
------------------------
1999 1998
-------- --------
(thousands)
OPERATING ACTIVITIES
Net Income $ 67,456 $ 78,138
Non-cash Items Included in Net Income
Depreciation and amortization 56,290 56,616
Deferred income taxes and investment
tax credits 11,155 7,864
Changes in Assets and Liabilities
Accounts receivable (1,479) (564)
Fuel inventory (1,190) (2,050)
Prepayments and other (3,902) 2,339
Equity and other investments (5,802) (2,146)
Accounts payable (21,869) (10,108)
Payables to affiliates (10,288) (23,633)
Accrued taxes 15,763 49,696
Other deferred credits 10,761 5,979
Other 245 3,822
-------- --------
117,140 165,953
-------- --------
INVESTING ACTIVITIES
Construction expenditures (73,204) (45,004)
Other (3,711) (4,966)
-------- --------
(76,915) (49,970)
-------- --------
FINANCING ACTIVITIES
Payment of dividends (45,159) (42,159)
Change in advances from affiliates 4,500 (4,874)
Reacquisition of long-term debt (33,700) (55,231)
Issuance of long-term debt 33,257 --
Redemption of preferred stock (1) --
-------- --------
(41,103) (102,264)
-------- --------
Net Change in Cash and Cash Equivalents (878) 13,719
Cash and Cash Equivalents at Beginning of Year 4,670 2,171
-------- --------
Cash and Cash Equivalents at End of Period $ 3,792 $ 15,890
======== ========
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized (includes
distributions on Trust Preferred
Securities) $ 23,454 $ 26,713
======== ========
Income taxes paid $ 16,614 $ 6,606
======== ========
The accompanying notes to consolidated financial statements as they relate to
PSO are an integral part of these statements.
28
<PAGE>
PUBLIC SERVICE COMPANY OF OKLAHOMA
RESULTS OF OPERATIONS
COMPARISON OF THE QUARTERS ENDED SEPTEMBER 30, 1999 AND 1998
PSO's net income for common stock for the third quarter of 1999 was $50.3
million, which was $4.5 million or 8% lower than the comparable period in 1998.
The decrease resulted primarily from lower non-fuel related revenues and higher
other operating expenses which was partially offset by lower tax expenses.
Electric operating revenues during the third quarter of 1999 were $258.7
million, which was $21.2 or 8% lower than the comparable period in 1998. Fuel
related revenues decreased $19.0 million due to lower combined fuel expense and
purchased power expense as discussed in the following paragraph. Non-fuel
related revenues decreased $2.2 million due primarily to an 8% decrease in
residential MWH sales attributable to milder weather in 1999. The decrease in
operating revenues was partially offset by an increase in demand for
non-affiliated wholesale energy. Additionally there was a $3.2 million decrease
in non-MWH related revenues for electric service rendered and not yet billed,
offset in part by a $3.7 million increase in transmission related revenues
resulting from changes to CSW's transmission coordination agreement. See NOTE 2.
LITIGATION AND REGULATORY PROCEEDINGS - Transmission Coordination Agreement.
Fuel expense during the third quarter of 1999 was $82.1 million, which was
$22.6 million or 22% lower than the comparable period in 1998. This decline was
due primarily to a $30.4 million decrease in the recovery of deferred fuel costs
resulting from a significant difference in fuel factors used to recover fuel
expense from customers. The decrease in fuel expense was offset in part by
higher average unit fuel costs. The average unit cost of fuel for the quarter
increased from $1.82 per MMbtu in 1998 to $2.12 per MMbtu in 1999 due primarily
to higher spot market natural gas prices. Purchased power expense during the
third quarter of 1999 was $20.3 million, which was $2.7 million or 15% higher
than the comparable period in 1998 due primarily to an increase in economy
energy purchases.
Other operating expense during the third quarter of 1999 was $35.5
million, which was $15.4 million or 77% higher than the comparable period in
1998. The increase was due primarily to higher transmission expenses resulting
from a $5.9 million change in the CSW transmission coordination agreement, and
the absence in 1999 of $6.2 million transmission service agreement adjustment
related to the final order in Texas Commission Docket No. 17285. See NOTE 2.
LITIGATION AND REGULATORY PROCEEDINGS - Transmission Coordination Agreement and
CPL and WTU Complaint versus Texas Utilities Electric Company (Docket No.
17285).
Income tax expense associated with utility operations during the third
quarter of 1999 was $28.0 million, which was $12.3 million or 31% lower than the
comparable period in 1998 due primarily to lower taxable income in the third
quarter of 1999 and prior year adjustments to prior year income taxes.
29
<PAGE>
COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
PSO's net income for common stock for the nine months ended September 30,
1999 was $67.3 million, which was $10.7 million or 14% lower than the comparable
period in 1998. The decrease resulted primarily from lower non-fuel related
revenues and higher other operating and maintenance expenses which were offset
in part by lower tax expense and interest charges.
Electric operating revenues for the nine months ended September 30, 1999
were $588.4 million, which was $34.7 million or 6% lower than the comparable
period in 1998. Fuel related revenues decreased $28.9 million for the nine
months of 1999 compared to 1998 due to lower combined fuel expense and purchased
power expense as discussed in the following paragraph. Non-fuel related revenues
decreased $5.8 million due primarily to a 6% decrease in residential MWH sales
attributable to milder weather in 1999. The decrease in operating revenues was
partially offset by an increase in demand for non-affiliated wholesale energy.
Additionally, there was a $6.6 million decrease in non-MWH related revenues for
electric service rendered and not yet billed which was offset in part by a $3.1
million increase in transmission related revenues resulting from changes to
CSW's transmission coordination agreement. See NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS - Transmission Coordination Agreement.
Fuel expense for the nine months ended September 30, 1999 was $208.9
million, which was $34.0 million or 14% lower than the comparable period in
1998. This decline resulted primarily from a $41.3 million decrease in the
recovery of deferred fuel costs due to a significant difference in fuel factors
used to recover fuel expense from customers. The decrease in fuel expense was
offset in part by higher average unit fuel costs. The average unit cost of fuel
increased from $1.80 per MMbtu in 1998 to $1.93 per MMbtu in 1999 due primarily
to higher spot market natural gas prices. Purchased power expense for the nine
months ended September 30, 1999 was $50.5 million, which was $5.6 million or 12%
higher than the comparable period in 1998 due primarily to an increase in
economy energy and firm contract purchases.
Other operating expenses for the nine months ended September 30, 1999 were
$88.1 million, which was $12.6 million or 17% higher than the comparable period
in 1998. The increase was due primarily to higher transmission expenses
resulting from a $5.9 million change in the CSW transmission coordination
agreement, and the absence in 1999 of a $4.1 million transmission service
agreement adjustment related to the final order in Texas Commission Docket No.
17285. See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS Transmission
Coordination Agreement and CPL and WTU Complaint versus Texas Utilities Electric
Company (Docket No. 17285).
Maintenance expense for the nine months ended September 30, 1999 was $30.7
million, which was $6.8 million or 28% higher than the comparable period in 1998
due primarily to higher production and distribution maintenance expenses. The
production maintenance expense increase related to scheduled power plant
maintenance as well as the restart of a power plant generating unit and an
unscheduled outage. The distribution maintenance expense increase was due
primarily to an increase in tree trimming activities in 1999.
Taxes, other than income for the nine months ended September 30, 1999 was
$23.8 million, which was $1.2 million or 5% higher than the comparable period in
1998 as a result of higher ad valorem tax expenses. Income tax expense
associated with utility operations for the nine months ended September 30, 1999
was $37.2 million, which was $15.4 million or 29% lower than the comparable
period in 1998 due primarily to lower taxable income in 1999 and prior year
adjustments to prior year income taxes.
30
<PAGE>
Interest charges for the nine months ended September 30, 1999 were $27.2
million, which was $2.1 million or 7% lower than the comparable period in 1998.
This decrease was due primarily to the reacquisition of $55 million of FMBs
during the third quarter of 1998.
31
<PAGE>
SWEPCO
SOUTHWESTERN ELECTRIC POWER COMPANY
PART I. - FINANCIAL INFORMATION.
ITEM 1. FINANCIAL STATEMENTS.
32
<PAGE>
SWEPCO
Consolidated Statements of Income (unaudited)
Southwestern Electric Power Company
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- -----------------
1999 1998 1999 1998
--------- --------- -------- --------
(thousands)
Electric Operating Revenues $312,035 $311,549 $751,987 $756,044
--------- --------- -------- --------
Operating Expenses and Taxes
Fuel 124,737 124,210 292,698 298,530
Purchased power 10,130 12,230 26,895 30,234
Other operating 41,623 36,168 104,694 100,490
Maintenance 15,598 12,341 49,860 35,770
Depreciation and amortization 25,464 24,675 76,988 74,303
Taxes, other than income 8,148 14,239 39,733 43,320
Income taxes 24,548 28,164 37,476 45,416
--------- --------- -------- --------
250,248 252,027 628,344 628,063
--------- --------- -------- --------
Operating Income 61,787 59,522 123,643 127,981
--------- --------- -------- --------
Other Income and (Deductions)
Allowance for equity funds used
during construction (4) 219 38 925
Other (6,019) (462) (6,932) (564)
Non-operating income taxes 2,961 522 4,617 1,734
--------- --------- -------- --------
(3,062) 279 (2,277) 2,095
--------- --------- -------- --------
Income Before Interest Charges 58,725 59,801 121,366 130,076
--------- --------- -------- --------
Interest Charges
Interest on long-term debt 9,598 9,808 29,201 29,426
Distributions on Trust Preferred
Securities 2,166 2,166 6,497 6,497
Interest on short-term debt and other 2,322 1,566 7,485 5,763
Allowance for borrowed funds used
during construction (515) (369) (1,254) (1,066)
--------- --------- -------- --------
13,571 13,171 41,929 40,620
--------- --------- -------- --------
Income Before Extraordinary Item 45,154 46,630 79,437 89,456
Extraordinary loss (net of tax of $1,621) (3,011) -- (3,011) --
--------- --------- -------- --------
Net Income 42,143 46,630 76,426 89,456
Less: Preferred stock dividends 57 57 172 648
Loss on reacquired preferred stock -- -- -- (855)
--------- --------- -------- --------
Net Income for Common Stock $ 42,086 $ 46,573 $ 76,254 $ 87,953
========= ========= ======== ========
The accompanying notes to consolidated financial statements as they relate to
SWEPCO are an integral part of these statements.
33
<PAGE>
SWEPCO
Consolidated Balance Sheets
Southwestern Electric Power Company
- --------------------------------------------------------------------------
September 30, December 31,
1999 1998
(unaudited) (audited)
------------ ----------
(thousands)
ASSETS
Electric Utility Plant
Production $ 1,393,236 $1,397,924
Transmission 480,520 474,035
Distribution 945,639 916,293
General 329,626 321,136
Construction work in progress 55,101 48,523
------------ ----------
3,204,122 3,157,911
Less - Accumulated depreciation 1,368,345 1,317,057
------------ ----------
1,835,777 1,840,854
------------ ----------
Current Assets
Cash 3,032 4,444
Accounts receivable 56,478 33,014
Accounts receivable from affiliates 18,258 7,416
Materials and supplies, at average cost 26,211 25,135
Fuel inventory, at average cost 55,566 40,238
Accumulated deferred income taxes 2,548 4,869
Prepayments and other 18,264 16,651
------------ ----------
180,357 131,767
------------ ----------
Deferred Charges and Other Assets 94,964 108,770
------------ ----------
$ 2,111,098 $2,081,391
============ ==========
The accompanying notes to consolidated financial statements as they relate to
SWEPCO are an integral part of these statements.
34
<PAGE>
SWEPCO
Consolidated Balance Sheets
Southwestern Electric Power Company
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
(unaudited) (audited)
----------- -----------
CAPITALIZATION AND LIABILITIES (thousands)
<S> <C> <C> <C> <C>
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 295,846 300,592
----------- -----------
Total Common Stock Equity 676,506 53% 681,252 51%
----------- --------- ----------- -----
Preferred stock 4,706 --% 4,707 --%
SWEPCO-obligated, mandatorily redeemable
preferred securities of subsidiary
trust holding solely Junior
Subordinated Debentures of SWEPCO 110,000 9% 110,000 8%
Long-term debt 496,114 38% 543,741 41%
----------- --------- ----------- -----
Total Capitalization 1,287,326 100% 1,339,700 100%
----------- --------- ----------- -----
Current Liabilities
Long-term debt due within twelve months 47,807 43,932
Advances from affiliates 88,075 40,705
Payables to affiliates 40,643 37,795
Accounts payable 64,820 73,507
Customer deposits 13,860 13,316
Accrued interest 12,816 14,275
Accrued taxes 58,600 23,189
Over-recovered fuel costs 5,155 5,378
Other 14,716 12,538
----------- -----------
346,492 264,635
----------- -----------
Deferred Credits
Accumulated deferred income taxes 381,765 398,664
Investment tax credits 58,790 62,213
Other 36,725 16,179
----------- -----------
477,280 477,056
----------- -----------
$2,111,098 $2,081,391
=========== ===========
</TABLE>
The accompanying notes to consolidated financial statements as they relate to
SWEPCO are an integral part of these statements.
35
<PAGE>
SWEPCO
Consolidated Statements of Cash Flows (unaudited)
Southwestern Electric Power Company
Nine Months Ended
September 30,
----------------------------
1999 1998
--------- ---------
(thousands)
OPERATING ACTIVITIES
Net Income $ 76,426 $ 89,456
Non-cash Items Included in Net Income
Depreciation and amortization 81,122 78,353
Deferred income taxes and investment tax
credits (19,077) (8,237)
Extraordinary loss related to SFAS No. 71 3,011 --
Changes in Assets and Liabilities
Accounts receivable (34,306) (6,048)
Fuel inventory (15,328) (11,501)
Accounts payable (8,624) (2,403)
Payables to affiliates 2,848 (9,878)
Accrued taxes 35,411 44,209
Other deferred credits 20,546 6,196
Other 10,821 5,359
--------- ---------
152,850 185,506
--------- ---------
INVESTING ACTIVITIES
Construction expenditures (73,127) (55,690)
Other (3,545) (4,456)
--------- ---------
(76,672) (60,146)
--------- ---------
FINANCING ACTIVITIES
Payment of dividends (81,172) (79,126)
Change in advances from affiliates 47,370 (13,258)
Retirement of long-term debt (43,787) (2,209)
Redemption of preferred stock (1) (27,988)
--------- ---------
(77,590) (122,581)
--------- ---------
Net Change in Cash and Cash Equivalents (1,412) 2,779
Cash and Cash Equivalents at Beginning of Year 4,444 2,298
--------- ---------
Cash and Cash Equivalents at End of Period $ 3,032 $ 5,077
========= =========
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized (includes
distributions on Trust Preferred Securities) $ 40,056 $ 39,257
========= =========
Income taxes paid $ 32,812 $ 30,849
========= =========
The accompanying notes to consolidated financial statements as they relate to
SWEPCO are an integral part of these statements.
36
<PAGE>
SOUTHWESTERN ELECTRIC POWER COMPANY
RESULTS OF OPERATIONS
COMPARISON OF THE QUARTERS ENDED SEPTEMBER 30, 1999 AND 1998
SWEPCO's net income for common stock for the third quarter of 1999 was
$42.1 million, which was $4.5 million or 10% lower than the comparable period in
1998. The decrease resulted primarily from increased other operating and
maintenance expenses, the write-off of Cajun acquisition expense and the effect
of the extraordinary loss.
Electric operating revenues for the third quarter of 1999 increased $0.5
million to $312.0 million when compared to the same period of 1998. Revenues
were affected by increased sales for resale to other utilities of $16.2 million
as a result of increased demand. Revenues also increased due to an unfavorable
$3.7 million transmission service agreement adjustment in 1998 related to the
final order in Texas Commission Docket No. 17285. See NOTE 2. LITIGATION AND
REGULATORY PROCEEDINGS - CPL and WTU Complaint versus Texas Utilities Electric
Company (Docket No. 17285). These increases in revenues were offset in part by
decreased fuel related revenues of $4.5 million, decreased non-fuel related
retail revenues of $5.9 million and an unfavorable adjustment of $9.0 million
adjustment related to changes to CSW's transmission coordination agreement. See
NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - Transmission Coordination
Agreement. The decrease in fuel related revenues was due to lower combined fuel
expense and purchased power expense as discussed in the following paragraph.
Non-fuel related retail revenues were affected by a 3% decrease in retail MWH
sales due primarily to a decrease in weather related customer demand.
Fuel and purchased power expenses had a net decrease for the third quarter
of 1999 compared to the same period in 1998. Fuel expense increased slightly to
$124.7 million resulting primarily from an increase in average unit fuel costs.
Average unit fuel costs increased from $1.68 per MMbtu in 1998 to $1.73 per
MMbtu in 1999 due to higher spot market natural gas prices. Fuel expense was
affected by the absence in 1999 of a 1998 transmission service agreement
adjustment related to the final order in Texas Commission Docket No. 17285. See
NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - CPL and WTU Complaint versus
Texas Utilities Electric Company (Docket No. 17285). Purchased power expenses
for the third quarter of 1999 decreased $2.1 million or 17% compared to the same
period in 1998 due primarily to a decrease in economy energy purchases.
Other operating expenses for the third quarter of 1999 were $41.6 million,
an increase of $5.5 million or 15% compared to the same period of 1998 as a
result of increased transmission expenses. The increase in transmission expense
was due to the absence in 1999 of a transmission service agreement adjustment in
1998 related to the final order in Texas Commission Docket No. 17285. See NOTE
2. LITIGATION AND REGULATORY PROCEEDINGS - CPL and WTU Complaint versus Texas
Utilities Electric company (Docket No. 17285). Transmission expenses were also
affected by changes related to CSW's transmission coordination agreement. See
NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS Transmission Coordination
Agreement.
Maintenance expenses increased during the third quarter of 1999 to $15.6
million, which was $3.3 million or 26% higher than the comparable period in 1998
as a result of increased tree trimming maintenance activities.
37
<PAGE>
Taxes, other than income for the third quarter of 1999 were $8.1 million,
a $6.1 million or 43% decrease compared to $14.2 million for the third quarter
of 1998 due primarily to decreased ad valorem tax expense.
Income tax expenses associated with utility operations during the third
quarter of 1999 were $24.5 million, which was $3.6 million or 13% lower than the
comparable period in 1998 due to lower taxable income and prior year adjustments
to prior year income taxes.
Other income and deductions decreased as a result of the after tax
write-off of Cajun acquisition expense of $3.7 million. See NOTE 3. COMMITMENTS
AND CONTINGENT LIABILITIES - Withdrawal of SWEPCO Cajun Asset Proposal.
The extraordinary loss resulted from legislation passed in Texas and
Arkansas under which the electricity generation portion of SWEPCO's business in
those states no longer meets the criteria to apply SFAS No. 71. These changes
resulted in an extraordinary loss, which decreased net income by $3.0 million.
See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - Electric Utility
Restructuring Legislation.
COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
SWEPCO's net income for common stock for the nine months ended September
30, 1999 was $76.3 million, which was $11.7 million or 13% lower than the
comparable period in 1998. This decrease resulted primarily from increased other
operating and maintenance expenses, the write-off of Cajun acquisition expenses
and the effect of the extraordinary loss.
Electric operating revenues for the nine months ended September 30, 1999
were $752.0 million, which was $4.1 million lower than the comparable period in
1998. This decrease resulted from decreased fuel related revenues of $13.3
million due to lower combined fuel expense and purchased power expense as
discussed in the following paragraph, decreased non-fuel related revenues of
$7.5 million and a $9.0 million increase related to changes to CSW's
transmission coordination agreement. See NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS - Transmission Coordination Agreement. Non-fuel related retail
revenues were affected by a 3% decrease in retail MWH sales due primarily to
decreased weather-related customer demand. These reductions were partially
offset by increased sales for resale to other utilities of $16.2 million as a
result of increased demand and the absence in 1999 of a $3.7 million
transmission service agreement adjustment in 1998 related to the final order in
Texas Commission Docket No. 17285. See NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS - CPL and WTU Complaint versus Texas Utilities Electric Company
(Docket No. 17285). Additionally, the reductions in revenue were offset in part
by the absence in 1999 of a 1998 provision for rate refund of $2.6 million
primarily in connection with the annual determination of cost of service formula
rates for SWEPCO's wholesale customers. Also affecting revenues is the absence
in 1999 of a 1998 reduction in fuel revenues of $3.2 million in accordance with
a Texas Commission order in SWEPCO's fuel reconciliation regarding transmission
equalization expense recovery.
Fuel and purchased power expense decreased for the nine months ended
September 30, 1999 when compared to the same period in 1998. Fuel expense
decreased $5.8 million or 2% due primarily to a decrease in average unit fuel
costs for coal and lignite which were partially offset by increased generation.
The change in average unit fuel costs resulted from lower spot market coal and
lignite prices. Fuel expense also decreased due in part to the absence in 1999
of a 1998 transmission service agreement adjustment related to the final order
in Texas Commission Docket No. 17285. See NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS - CPL and WTU Complaint versus Texas Utilities Electric Company
38
<PAGE>
(Docket No. 17285). Purchased power expenses for the nine months ended September
30, 1999 decreased $3.3 million or 11% compared to the same period of 1998 due
primarily to a decrease in economy energy purchases.
Other operating expenses for the nine months ended September 30, 1999 were
$104.7 million, an increase of $4.2 million or 4% compared to the same period of
1998 as a result of increased transmission expenses. The increase in
transmission expenses was due to the absence in 1999 of a transmission service
agreement adjustment in 1998 related to the final order in Texas Commission
Docket No. 17285. See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - CPL and
WTU Complaint versus Texas Utilities Electric Company (Docket No. 17285). The
increase in other operating expenses was partially offset by transmission
expenses related to changes in CSW's transmission coordination agreement. See
NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - Transmission Coordination
Agreement.
Maintenance expenses for the nine months ended September 30, 1999 were
$49.9 million, which was $14 million or 39% higher than the comparable period in
1998. This was due to increased power station maintenance, increased
tree-trimming maintenance and increased overhead line maintenance.
Taxes, other than income for the nine months ended September 30, 1999,were
$39.7 million, a decrease of $3.6 million or 8% compared to the same period in
1998. This decrease was due to lower ad valorem taxes.
Income tax expenses associated with utility operations during the nine
months ended September 30, 1999 were $37.5 million, which was $7.9 million or
18% lower than the comparable period in 1998 due to lower taxable income and
prior year adjustments to prior year income taxes.
Other income and deductions decreased as a result of the write-off of the
Cajun acquisition expenses of $3.7 million, net of tax. See NOTE 3. COMMITMENTS
AND CONTENGENT LIABILTIES - SWEPCO Cajun Asset Proposal.
The extraordinary loss was a result of legislation passed in Texas and
Arkansas where the electricity generation portion of SWEPCO's business in those
states no longer meets the criteria to apply SFAS No. 71. These accounting
changes resulted in an extraordinary loss, which decreased net income by $3.0
million, net of tax. See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS -
Electric Utility Restructuring Legislation.
39
<PAGE>
WTU
WEST TEXAS UTILITIES COMPANY
PART I. - FINANCIAL INFORMATION.
ITEM 1. FINANCIAL STATEMENTS.
40
<PAGE>
WTU
Statements of Income (unaudited)
West Texas Utilities Company
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- ---------------------
1999 1998 1999 1998
--------- --------- --------- ----------
(thousands)
Electric Operating Revenues $ 154,304 $ 147,343 $ 343,138 $ 335,644
--------- --------- --------- ----------
Operating Expenses and Taxes
Fuel 41,478 38,546 93,821 95,231
Purchased power 28,328 17,169 49,096 37,831
Other operating 24,652 19,637 64,824 62,496
Maintenance 4,284 4,911 14,744 11,816
Depreciation and amortization 10,934 10,719 32,558 32,108
Taxes, other than income 6,464 5,827 21,049 18,008
Income taxes 11,064 16,623 16,076 21,705
--------- --------- --------- ----------
127,204 113,432 292,168 279,195
--------- --------- --------- ----------
Operating Income 27,100 33,911 50,970 56,449
--------- --------- --------- ----------
Other Income and (Deductions)
Allowance for equity funds used
during construction 138 193 234 421
Other 544 (22) 194 1,476
Non-operating income taxes (350) 259 76 282
--------- --------- --------- ----------
332 430 504 2,179
--------- --------- --------- ----------
Income Before Interest Charges 27,432 34,341 51,474 58,628
--------- --------- --------- ----------
Interest Charges
Interest on long-term debt 5,088 5,088 15,264 15,264
Interest on short-term debt and
other 1,027 1,319 3,558 3,405
Allowance for borrowed funds used
during construction (166) (182) (466) (469)
--------- --------- --------- ----------
5,949 6,225 18,356 18,200
--------- --------- --------- ----------
Income Before Extraordinary Item 21,483 28,116 33,118 40,428
Extraordinary loss (net of tax
of $2,941) (5,461) -- (5,461) --
--------- --------- --------- ----------
Net Income 16,022 28,116 27,657 40,428
Less: Preferred stock dividends 26 26 78 78
--------- --------- --------- ----------
Net Income for Common Stock $ 15,996 $ 28,090 $ 27,579 $ 40,350
========= ========= ========= ==========
The accompanying notes to financial statements as they relate to WTU
are an integral part of these statements.
41
<PAGE>
WTU
Balance Sheets
West Texas Utilities Company
September 30, December 31,
1999 1998
(unaudited) (audited)
------------- ------------
(thousands)
ASSETS
Electric Utility Plant
Production $ 425,231 $ 429,896
Transmission 217,614 213,630
Distribution 396,938 382,373
General 112,851 108,878
Construction work in progress 19,243 11,805
------------- ------------
1,171,877 1,146,582
------------- ------------
Less - Accumulated depreciation 489,856 473,503
------------- ------------
682,021 673,079
------------- ------------
Current Assets
Cash 5,217 2,093
Advances to affiliates 12,751 --
Accounts receivable from affiliates 3,855 2,998
Accounts receivable 27,075 28,691
Materials and supplies, at average cost 13,564 14,191
Fuel inventory, at LIFO cost 15,191 13,186
Accumulated deferred income taxes -- 366
Under-recovered fuel costs 13,032 3,980
Prepayments and other 10,664 5,988
------------- ------------
101,349 71,493
------------- ------------
Deferred Charges and Other Assets
Deferred Oklaunion costs 9,285 14,910
Other 66,851 60,330
------------- ------------
76,136 75,240
------------- ------------
$ 859,506 $ 819,812
============= ============
The accompanying notes to financial statements as they relate to WTU
are an integral part of these statements.
42
<PAGE>
WTU
Balance Sheets
West Texas Utilities Company
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
(unaudited) (audited)
------------ ------------
CAPITALIZATION AND LIABILITIES (thousands)
<S> <C> <C> <C> <C>
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 123,769 117,189
------------ ------------
Total Common Stock Equity 263,219 50% 256,639 46%
------------ ---- ------------ ----
Preferred stock 2,482 --% 2,482 --%
Long-term debt 263,644 50% 303,519 54%
------------ ---- ------------ ----
Total Capitalization 529,345 100% 562,640 100%
------------ ---- ------------ ----
Current Liabilities
Long-term debt due within twelve months 40,000 --
Advances from affiliates -- 4,573
Payables to affiliates 16,584 19,917
Accounts payable 44,422 31,473
Accrued taxes 17,446 10,031
Accrued interest 7,955 4,125
Customer deposits 2,327 2,076
Accumulated deferred income taxes 735 --
Other 12,323 1,721
------------ ------------
141,792 73,916
------------ ------------
Deferred Credits
Accumulated deferred income taxes 145,671 140,731
Investment tax credits 25,641 26,597
Income tax related regulatory
liabilities, net 13,093 12,088
Other 3,964 3,840
------------ ------------
188,369 183,256
------------ ------------
$ 859,506 $ 819,812
============ ============
</TABLE>
The accompanying notes to financial statements as they relate to WTU
are an integral part of these statements.
43
<PAGE>
WTU
Statements of Cash Flows (unaudited)
West Texas Utilities Company
Nine Months Ended
September 30,
-----------------------
1999 1998
--------- ---------
(thousands)
OPERATING ACTIVITIES
Net Income $ 27,657 $ 40,428
Non-cash Items Included in Net Income
Depreciation and amortization 32,558 32,890
Deferred income taxes and investment tax credits 7,309 (7,377)
Extraordinary loss related to SFAS No. 71 5,461 --
Changes in Assets and Liabilities
Accounts receivable 759 (32,177)
Accounts payable 12,949 (313)
Payables to affiliates (3,333) (1,652)
Accrued taxes 7,415 13,761
Fuel recovery (9,052) 1,371
Other (1,925) (1,589)
--------- ---------
79,798 45,342
--------- ---------
INVESTING ACTIVITIES
Construction expenditures (35,444) (33,049)
Other (2,828) 2,950
--------- ---------
(38,272) (30,099)
--------- ---------
FINANCING ACTIVITIES
Payment of dividends (21,078) (18,078)
Change in advances from affiliates (4,573) --
--------- ---------
(25,651) (18,078)
--------- ---------
Net Change in Cash and Cash Equivalents 15,875 (2,835)
Cash and Cash Equivalents at Beginning of Year 2,093 20,613
--------- ---------
Cash and Cash Equivalents at End of Period $ 17,968 $17,778
========= =========
SUPPLEMENTARY INFORMATION
Interest paid less amounts capitalized $ 10,067 $ 9,813
========= =========
Income taxes paid $ 1,749 $15,042
========= =========
The accompanying notes to financial statements as they relate to WTU
are an integral part of these statements.
44
<PAGE>
WEST TEXAS UTILITIES COMPANY
RESULTS OF OPERATIONS
COMPARISON OF THE QUARTERS ENDED SEPTEMBER 30, 1999 AND 1998
WTU's net income for common stock for the third quarter of 1999 was $16.0
million, which was $12.1 million or 43% lower than the comparable period in
1998. The decrease was primarily the result of higher other operating expenses
and the effect of the extraordinary loss and a charge against earnings relating
to the Texas Legislation partially offset by increased transmission related
revenue and lower income tax expense.
Electric operating revenues for the quarter ended September 30, 1999 were
$154.3 million, which was $7.0 million or 5% higher than the comparable period
in 1998. Fuel related revenues increased $5.4 million due to higher combined
fuel expense and purchased power expense as discussed in the following
paragraph. Non-fuel related revenues increased $1.6 million due to an increase
in non-MWH related revenues for service rendered and not yet billed as well as
an increase in transmission related revenues including changes to CSW's
transmission coordination agreement which were partially offset by the charge to
reflect the excess earnings provision under the Texas Legislation. See NOTE 2.
LITIGATION AND REGULATORY PROCEEDINGS - Transmission Coordination Agreement and
Electric Utility Restructuring Legislation.
Fuel expense during the third quarter of 1999 was $41.5 million, which was
$2.9 million or 8% higher than the comparable period in 1998. The average unit
fuel costs for the quarter increased from $1.81 per MMbtu in 1998 to $2.17 per
MMbtu in 1999 which was the result of higher spot market natural gas prices.
Purchased power expense during the third quarter of 1999 was $28.3 million,
which was $11.2 million or 65% higher than the comparable period in 1998 due
primarily to an 8% decrease in generation. The decrease in generation was mainly
attributable to the unscheduled outage of a coal-fired generating power plant.
Other operating expenses for the third quarter of 1999 were $24.7 million,
which was $5.0 million or 26% higher than the comparable period in 1998 due
primarily to higher transmission expenses. The increase in transmission expense
was due mainly to the absence in 1999 of a transmission service agreement
adjustment made in 1998 related to the final order in Texas Commission Docket
No. 17285. See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - CPL and WTU
Complaint versus Texas Utilities Electric Company (Docket No. 17285).
Income taxes for the third quarter of 1999 decreased to $11.1 million,
which was $5.6 million or 33% lower than the comparable period in 1998 as a
result of lower taxable income for 1999 and prior year adjustments to prior year
income taxes.
The extraordinary loss resulted from legislation passed in Texas under
which the electricity generation portion of WTU's business in Texas no longer
meets the criteria to apply SFAS No. 71. These changes resulted in an
extraordinary loss which decreased net income by $5.5 million, net of tax. See
NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS Electric Utility Restructuring
Legislation.
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COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
WTU's net income for common stock for the nine months ended September 30,
1999 was $27.6 million, which was $12.8 million or 32% lower than the comparable
period in 1998. The decrease was primarily the result of an increase in other
operating expense, maintenance expense and taxes, other than income as well as a
decrease in other income and deductions and the effect of the extraordinary
loss. The decrease in earnings was partially offset by a reduction in income tax
expense and increased transmission related revenue.
Electric operating revenues for the nine months ended September 30, 1999
were $343.1 million, which was $7.5 million or 2% higher than the comparable
period in 1998. Fuel related revenues increased $8.6 million due to higher net
fuel and purchased power expense as discussed below. Non-fuel related revenues
decreased $1.1 million due to a decrease in electric service rendered and not
yet billed as well as a charge to reflect the excess earnings provision of the
Texas Legislation and a 4% decrease in residential MWH sales due primarily to
decreased customer demand. The decrease in revenues was offset in part by higher
transmission related revenues including changes to CSW's transmission
coordination agreement and a 13% increase in sales for resale to other utilities
as a result of increased demand. See NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS - Transmission Coordination Agreement and Electric Utility
Restructuring Legislation.
Fuel expense for the nine months ended September 30, 1999 was $93.8
million, which was $1.4 million or 1% lower than the comparable period in 1998
due primarily to a 4.6% decrease in generation. Purchased power for the nine
months ended September 30, 1999 was $49.1 million, which was $11.3 million or
30% higher than the comparable period in 1998 due primarily to an unscheduled
outage at a coal-fired generating plant.
Maintenance expense for the nine months ended September 30, 1999 was $14.7
million, which was $2.9 million or 25% higher than the comparable period in 1998
due primarily to increased power plant maintenance, overhead line maintenance
and tree trimming maintenance.
Other operating expenses for the nine months ended September 30, 1999 were
$64.8 million, which was $2.3 million or 4% higher than the comparable period in
1998 due to higher transmission expenses. The increase in transmission expense
was due to the absence in 1999 of a transmission service agreement adjustment
made in 1998 related to the final order in Texas Commission Docket No. 17285.
See NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS - CPL and WTU Complaint versus
Texas Utilities Electric Company (Docket No. 17285).
Taxes, other than income, for the nine months ended September 30, 1999
were $21.0 million, which was $3.0 million or 17% higher than the comparable
period in 1998 primarily attributable to higher state franchise taxes.
Income taxes associated with utility operations for the nine months ended
September 30, 1999 were $16.1 million, which was $5.6 million or 26% lower than
the comparable period in 1998 as a result of lower taxable income for 1999 and
prior year adjustments to prior year income taxes.
Other income and deductions for the nine months ended September 30, 1999
decreased $1.7 million from the comparable period in 1998. The decrease was a
result of a decline in interest income from a lower balance of under-recovered
fuel costs, as well as a decline in income from merchandise operations.
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The extraordinary loss resulted from legislation passed in Texas under
which the electricity generation portion of WTU's business in Texas no longer
meets the criteria to apply SFAS No. 71. These changes resulted in an
extraordinary loss which decreased net income by $5.5 million, net of tax. See
NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS Electric Utility Restructuring
Legislation.
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INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
NOTE 1. PRINCIPLES OF PREPARATION CSW, CPL, PSO, SWEPCO, WTU
NOTE 2. LITIGATION AND REGULATORY
PROCEEDINGS CSW, CPL, PSO, SWEPCO, WTU
NOTE 3. COMMITMENTS AND CONTINGENT
LIABILITIES CSW, CPL, PSO, SWEPCO, WTU
NOTE 4. COMMON STOCK AND DIVIDENDS CSW, CPL, PSO, SWEPCO, WTU
NOTE 5. PROPOSED AEP MERGER CSW, CPL, PSO, SWEPCO, WTU
NOTE 6. BUSINESS SEGMENTS CSW
NOTE 7. SOUTH AMERICAN INVESTMENTS CSW
NOTE 8. LONG-TERM DEBT CSW, CPL, PSO
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NOTES TO FINANCIAL STATEMENTS
(Unaudited)
1. PRINCIPLES OF PREPARATION
General
The condensed financial statements of the Registrants have been prepared
by each Registrant pursuant to the rules and regulations of the SEC. Certain
information and note disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted pursuant to such rules and regulations, although each
Registrant believes that the disclosures are adequate to make the information
presented not misleading. These condensed financial statements should be read in
conjunction with the financial statements and the notes included in the
Registrants' Combined Annual Report on Form 10-K for the year ended December 31,
1998 and the Registrants' Combined Quarterly Reports on Form 10-Q for the
quarters ended March 31, 1999 and June 30, 1999.
The unaudited financial information reflects all adjustments of a normal
recurring nature which are, in the opinion of management of each Registrant,
necessary for a fair statement of the results of operations for the interim
periods. Information for quarterly periods is affected by seasonal variations in
sales, rate changes, timing of fuel expense recovery and other factors.
CPL Nuclear Decommissioning of STP
At the end of STP's service life, decommissioning is expected to be
accomplished using the decontamination method, which is one of the techniques
accepted by the NRC. Using this method, the decontamination activities occur as
soon as possible after the end of plant operations. Contaminated equipment is
cleaned and removed to a permanent disposal location, and the site is generally
returned to its original condition.
CPL's decommissioning costs are accrued and paid to an external trust over
the expected service life of the STP units. The existing NRC operating licenses
permit the operation of STP Unit 1 until 2027 and Unit 2 until 2028. CPL pays
annual decommissioning costs based on the estimated future cost to decommission
STP, including escalation for expected inflation to the expected time of
decommissioning.
CPL estimates its portion of the costs of decommissioning STP to be $289
million in 1999 dollars based on a study completed this year. CPL is accruing
and recovering decommissioning costs through rates based on the service life of
STP using a rate of $8.2 million per year. The funds are deposited with a
trustee under the terms of an irrevocable trust and are reflected in CPL's
consolidated balance sheets as Nuclear decommissioning trust with a
corresponding amount accrued in Accumulated depreciation. On CSW's consolidated
balance sheets the irrevocable trust is included in Deferred Charges and Other
Assets, Other, with a corresponding amount accrued in Accumulated depreciation.
In CSW's and CPL's consolidated statements of income, the income related to the
irrevocable trust is recorded in Other Income and Deductions, Other. In CPL's
consolidated statements of income the interest expense related to the
irrevocable trust is recorded in Interest Charges, Interest on short-term debt
and other. In CSW's consolidated statements of income the interest expense
related to the irrevocable trust is recorded in Interest and Other Charges,
Interest on short-term debt and other. On September 30, 1999, the nuclear trust
balance was $76.9 million.
Regulatory Assets and Liabilities
The financial statements of the U.S. Electric Operating Companies have
historically reflected regulatory assets and liabilities under cost-based rate
regulation in accordance with SFAS No. 71. Rate-regulated companies are
generally required to write off regulatory assets and liabilities against
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current earnings whenever changes in facts and circumstances cause SFAS No. 71
to no longer apply. As a result of legislation passed in Texas and Arkansas, the
electricity generation business in those jurisdictions for CPL, SWEPCO and WTU
no longer meet the criteria to apply SFAS No. 71. Instead, the principles of
SFAS No. 101, as interpreted by EITF 97-4, have been applied. See NOTE 2.
LITIGATION AND REGULATORY - Electric Utility Restructuring Legislation.
Foreign Currency Translation
The financial statements of SEEBOARD USA, which are included in CSW's
consolidated financial statements, have been translated from British pounds to
U.S. dollars in accordance with SFAS No. 52. All balance sheet accounts are
translated at the exchange rate at the end of the period, and all income
statement items are translated at the weighted average exchange rate for the
applicable period. All the resulting translation adjustments are recorded
directly to Accumulated other comprehensive income on CSW's Consolidated Balance
Sheets. Cash flow statement items are translated at a combination of average,
historical and current exchange rates. The non-cash impact of the changes in
exchange rates on cash and cash equivalents, resulting from the translation of
items at the different exchange rates, is shown on CSW's Consolidated Statements
of Cash Flows in Effect of exchange rate changes on cash and cash equivalents.
One British pound equals the following U.S. dollar amounts:
1999 1998
------------- --------------
At September 30 $1.65 $1.70
Weighted average for 3
months ended September $1.64 $1.65
30
Weighted average for 9
months ended September $1.62 $1.65
30
See NOTE 7. SOUTH AMERICAN INVESTMENTS for information regarding CSW's
investments in Brazil.
Risk Management
CSW has, at times, been exposed to currency and interest rate risks which
reflect the floating exchange rate that exists between the U.S. dollar and the
British pound. CSW utilizes certain risk management tools, including cross
currency swaps, foreign currency futures and foreign currency options, to manage
adverse changes in exchange rates and to facilitate financing transactions
resulting from CSW's acquisition of SEEBOARD.
SEEBOARD has entered into contracts for differences to reduce exposure to
fluctuations in the price of electricity purchased from the United Kingdom's
electricity power pool. This pool was established upon privatization of the
United Kingdom's electric industry for the bulk trading of electricity between
generators and suppliers.
CSW also utilizes a variety of other derivatives instruments
including swaps, forwards and options. CSW accounts for these transactions as
hedge transactions and any gains or losses associated with the risk management
tools are recognized in the financial statements at the time the hedge
transactions are settled. CSW believes its credit risk in these contracts is
negligible.
Reclassifications
Certain financial statement items for prior periods have been reclassified
to conform to the 1999 presentation.
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2. LITIGATION AND REGULATORY PROCEEDINGS
See the Registrants' Combined Annual Report on Form 10-K for the year
ended December 31, 1998 and the Registrants' Combined Quarterly Reports on Form
10-Q for the quarters ended March 31, 1999 and June 30, 1999 for additional
discussion of litigation and regulatory proceedings. Reference is also made to
NOTE 3. COMMITMENTS AND CONTINGENT LIABILITIES and ITEM 2. MD&A - RATES AND
REGULATORY MATTERS for additional discussion of litigation and regulatory
matters.
Electric Utility Restructuring Legislation
On June 18, 1999, legislation was signed into law in Texas that will
restructure the electric utility industry in the state. The new law, among other
things: gives Texas customers of investor-owned utilities the opportunity to
choose their electric provider beginning January 1, 2002; provides for the
recovery of stranded costs which are defined as the excess of net book value of
generation assets over the defined market value of those assets; requires
reductions in nitrogen oxide and sulfur dioxide emissions; provides a rate
freeze until January 1, 2002 followed by a 6% rate reduction for residential and
small commercial customers, additional rate reduction for low income customers
and a number of customer protections and sets certain limits on capacity owned
and controlled by power generation companies. Rural electric cooperatives and
municipal electric systems can choose whether to participate in retail
competition. Delivery of the electricity will continue to be the responsibility
of the local electric transmission and distribution utility company at regulated
prices. Each utility must unbundle its business activities into a retail
electric provider, a power generation company and a transmission and
distribution utility. CPL, SWEPCO and WTU will file their business separation or
"unbundling" plans with the Texas Commission in January 2000.
During 1999, legislation was also enacted in Arkansas that will ultimately
restructure the electric utility industry in that state. SWEPCO will file a
business unbundling plan in Arkansas in the first quarter of 2000 as required by
the legislation.
The financial statements of the U.S. Electric Operating Companies have
historically reflected the effects of applying the requirements of SFAS No. 71.
Pursuant to those requirements, the U.S. Electric Operating Companies have
recorded regulatory assets and liabilities (probable future revenues and
refunds) to reflect the economic effect of cost-based regulation. When a company
determines that its operations or a segment of its operations no longer meets
the criteria for applying SFAS No. 71, it is required to apply the requirements
of SFAS No. 101. Pursuant to those requirements and further guidance provided in
EITF 97-4, a company is required to write off regulatory assets and liabilities
related to deregulated operations, unless recovery of such amounts is provided
through rates to be collected in a continuing regulated portion of the company's
operations. Additionally, it is required to determine if any plant assets are
impaired under SFAS No. 121.
As a result of the scheduled deregulation of generation in Texas and
Arkansas, CSW has concluded that it should discontinue the application of SFAS
No. 71 for the Texas generation portion of the business for CPL and WTU and the
Texas and Arkansas jurisdictional portions of the generation business for
SWEPCO. Consequently, WTU recorded an extraordinary charge to earnings of $5.5
million and SWEPCO recorded an extraordinary charge to earnings of $3.0 million
to reflect the effects of discontinuing the application of SFAS No. 71 and to
write off net of regulatory assets that are not probable of recovery.
The discontinuance of SFAS No. 71 for CPL did not result in a net charge
to earnings as such net regulatory assets, pursuant to the legislation, are
expected to be recovered from transmission and distribution customers through
rates that will continue to be regulated.
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Electric utilities under the Texas Legislation are allowed to recover
generation-related regulatory assets and stranded costs that otherwise may not
be recoverable in the future competitive market. All or a majority of those
costs can be refinanced through securitization, which is a financing structure
designed to provide lower financing costs than is available through the
conventional utility cost of capital model. The securitized amounts are then
recovered through a non-bypassable transmission charge. On October 18, 1999, CPL
filed an application with the Texas Commission to securitize approximately $1.27
billion of its retail generation-related regulatory assets and approximately $47
million in other qualified costs. If approval is received from the Texas
Commission, CPL expects to issue the securitization bonds in March or April
2000, depending on market conditions and the timing of an order from the Texas
Commission. A second phase of securitization relating to additional plant
related stranded costs should occur in 2001 depending upon market conditions,
timing and Texas Commission approvals. A non-bypassable charge may be used to
recover additional unsecuritized stranded cost amounts.
Under the provisions of EITF 97-4, CPL's generation-related net regulatory
assets were transferred to the transmission and distribution portion of the
business and will be amortized as they are recovered through charges to
customers. Management currently believes all regulatory and stranded costs
related to generation assets for CPL will be recovered as provided under Texas
Legislation. CPL believes it will have stranded costs related to its generation
assets in excess of the $1.27 billion of costs contained in its securitization
filing made with the Texas Commission on October 18, 1999. If future events were
to occur that made the recovery of these assets no longer probable, CPL would
write off any non-recoverable portion of such assets as a non-cash charge to
earnings. CPL's amount of regulatory assets and stranded costs are subject to a
final determination by the Texas Commission in 2004. The Texas Legislation
provides that all such finally determined stranded costs will be recovered.
Since SWEPCO and WTU are not expected to have net stranded costs, all
generation-related non-recoverable net regulatory assets were written off and
reflected on the statement of income as an extraordinary item.
Additionally, CPL, SWEPCO and WTU performed an accounting impairment
analysis of generation assets under SFAS No. 121 at September 30, 1999 and
concluded there was no impairment of generation assets at that time. An
impairment analysis involves estimating future net cash flows arising from the
use of an asset. If the net cash flows exceed the net book value of the asset,
then there is no impairment of the asset for accounting purposes. CPL, SWEPCO
and WTU will continue to review their assets for potential impairment if events
or changes in circumstances indicate the carrying amount of an asset may not be
recoverable.
The Texas Legislation also provides that each year during the 1999 through
2001 rate freeze period, utilities with stranded costs are required to apply any
earnings in excess of the most recently approved cost of capital in a company's
last rate case (if issued on or after January 1, 1992) to reduce stranded costs.
As a result, CPL recorded a net charge to earnings of $4.6 million to reflect
the impact of this provision. Utilities without stranded costs must either flow
such amounts back to customers or make capital expenditures, at no charge to
customers, to improve transmission or distribution facilities or to improve air
quality. As a result, WTU recorded a charge to earnings of $6.4 million from the
effect of the earnings cap under the Texas Legislation. The charges were based
on estimates for the current year and are subject to final determination by the
Texas Commission. Following CPL's discontinuation of SFAS No. 71, it is expected
that any future excess earnings will only be applied to reduce stranded costs
for regulatory purposes.
The discontinuance of SFAS No. 71 for CPL's and WTU's Texas generation
business and SWEPCO's Texas and Arkansas generation business requires that these
businesses no longer defer costs or recognize liabilities strictly resulting
from the actions of a regulator. For example, operations and maintenance
expenditures will be expensed as incurred regardless of regulatory treatment. In
addition, the equity component of allowance for funds used during construction
can no longer be accrued for generation-related capital projects. Instead, the
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businesses will be required to follow the interest capitalization rules in SFAS
No. 34.
CSW continues to analyze the impact of the electric utility industry
restructuring legislation on the U.S. Electric Operating Companies. The Texas
Commission has established numerous task forces, including representatives from
CPL, SWEPCO and WTU, to address various issues associated with the Texas
Legislation and to provide guidance regarding implementation of restructuring.
Based on the overall framework and objective of the Texas Legislation regarding
recovery of stranded costs and regulatory assets, and additional guidance
obtained through participation in various task force workshop sessions, certain
adjustments were recorded by CSW in the third quarter of 1999 to recognize the
estimated effect of the legislation. CSW also recorded certain adjustments for
the Arkansas jurisdictional portion of SWEPCO's generation business as a result
of legislation enacted in Arkansas.
As previously discussed, as a result of the Texas Legislation, CPL filed
its application for securitization on October 18, 1999 with the Texas
Commission. CPL, SWEPCO and WTU expect to make additional filings with the Texas
Commission for business separation plans in January 2000, earnings cap reports
in March 2000, cost unbundling plans in April 2000 and the ECOM reports in April
2000.
Also see ITEM 2. MD&A - RECENT DEVELOPMENTS AND TRENDS, Electric Utility
Restructuring Legislation for a discussion on restructuring legislation.
CPL Rate Review - Docket No. 14965
In November 1995, CPL filed with the Texas Commission a request to
increase its retail base rates by $71 million. On October 16, 1997, the Texas
Commission issued the CPL 1997 Final Order which lowered the annual retail base
rates of CPL by approximately $19 million or 2.5% from CPL's rate level existing
prior to May 1996. The Texas Commission also included a "glide path" rate
reduction methodology in the CPL 1997 Final Order pursuant to which CPL's annual
rates were reduced by $13 million on May 1, 1998 with an additional reduction of
$13 million on May 1, 1999.
CPL filed an appeal of the CPL 1997 Final Order to the State District
Court of Travis County to raise several issues related to the rate case. The
primary issues include: (i) the classification of $800 million of invested
capital in STP as ECOM which was assigned a lower return on equity than non-ECOM
property; (ii) the Texas Commission's application of the "glide path" rate
reduction methodology applied on May 1, 1998 and May 1, 1999; and (iii) the $18
million of disallowed affiliate expenses from CSW Services. As part of the
appeal, CPL sought a temporary injunction to prohibit the Texas Commission from
implementing the "glide path" rate reduction methodology. The court denied the
temporary injunction, and the "glide path" rate reductions were implemented in
May 1998 and May 1999. Hearings on the appeal were held during the third quarter
of 1998, and a judgment was issued in February 1999 affirming the Texas
Commission order, except for a consolidated tax issue in the amount of $6
million, which was remanded to the Texas Commission. CPL filed an appeal of this
most recent order to the Court of Appeals and management is unable to predict
how the final resolution of these issues will ultimately affect CSW's and CPL's
results of operations and financial condition. On May 4, 1999, AEP and CSW
announced that they had reached a stipulated agreement with the General Counsel
of the Texas Commission and other intervenors in the state of Texas related to
the AEP/CSW merger case. The Texas Commission approved the AEP Merger in early
November 1999. If the AEP Merger is ultimately consummated, CSW will withdraw
its appeal with respect to the "glide path" rate reduction methodology as
discussed above as issue "(ii)" but will continue seeking the appeal of issues
"(i) and (iii)" also discussed above. See NOTE 5. PROPOSED AEP MERGER and ITEM
2. MD&A - PROPOSED AEP MERGER for a discussion on the stipulated agreement.
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Also see ITEM 2. MD&A - RATES AND REGULATORY MATTERS, CPL Rate Review -
Docket No. 14965 for a discussion of the CPL 1997 Final Order.
CPL Fuel Proceeding
On December 31, 1998, CPL filed with the Texas Commission an application
to reconcile fuel costs and to request authority to carry the reconciled balance
forward into the next reconciliation period. During the reconciliation period of
July 1, 1995 through June 30, 1998, CPL incurred $828.5 million of eligible fuel
and fuel-related expenses. The Texas jurisdictional allocation of such fuel and
fuel-related expenses is $783.4 million.
In addition to requesting reconciliation of its fuel and fuel-related
expenses for the reconciliation period, CPL requested authority from the Texas
Commission to recover the reward earned during the reconciliation period under
the performance standard adopted in the 1997 CPL Final Order for CPL's share of
STP. The Texas Commission adopted a three-year average capacity factor of 83%
performance standard for STP in that order. During the reconciliation period,
STP operated at a net capacity factor of 93.1%, resulting in a reward of $19.2
million.
CPL requested authority to recover the Texas portion of 50% of the reward
by including 1/36th of this amount in Texas retail eligible fuel expense each
month for the three-year period following the Texas Commission's order in the
fuel reconciliation case. CPL further requested authority to apply the amounts
of the reward recovered through Texas retail eligible fuel expense toward
additional amortization of its STP deferred accounting regulatory asset. The
remaining 50% of the reward would be "banked" to be used against potential
future penalties or other disallowance of fuel costs. Hearings were held before
an ALJ in June 1999. In July 1999, all parties reached a settlement in
principle. The settlement resolves all disputed issues and includes a
disallowance of $7.44 million recorded in the third quarter of 1999 and no STP
performance reward either now or in the future. The Texas Commission issued its
final order on September 23, 1999 in accordance with the stipulation of the
parties.
CPL and WTU Complaint vs. Texas Utilities Electric Company (Docket No.
17285)
A joint complaint filed by CPL and WTU with the Texas Commission asserted
that since January 1, 1997, Texas Utilities Electric Company had been
effectively double charging for transmission service within ERCOT. A proposal
for decision in February 1998 recommended approval of a proposal by CPL and WTU
to reduce by $15.5 million annually their payments to Texas Utilities Electric
Company. The Texas Commission approved the proposal in September 1998. Although
Texas Utilities Electric Company has appealed the Texas Commission final order,
it refunded $26.6 million to CPL and WTU in November 1998. Prior to the Texas
Commission's September 1998 decision, the $15.5 million annual payment to Texas
Utilities Electric Company had been allocated to the U.S. Electric Operating
Companies. As a result of this order, the payment will continue to be recorded
on CPL's and WTU's books as a reduction of ERCOT transmission expense, and there
will be no future expenses recorded on the books of PSO and SWEPCO.
Transmission Coordination Agreement
The transmission coordination agreement provides the means by which the
U.S. Electric Operating Companies plan, operate and maintain the four separate
transmission systems as a single unit. The agreement also establishes the method
by which the U.S. Electric Operating Companies allocate revenues received under
open access transmission tariffs. In August 1998, the FERC accepted the
transmission coordination agreement for filing, suspended it for a nominal
period, and made it effective retroactive to January 1, 1997, subject to refund
and investigation. In the fourth quarter of 1998, the U.S. Electric Operating
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Companies and supporting intervenor signatories filed an uncontested offer of
settlement. The FERC issued an order on June 18, 1999, accepting the offer of
settlement. The FERC further ordered that appropriate refunds be made to reflect
the terms of the revised transmission coordination agreement. In the second
quarter of 1999, the FERC also issued an order accepting the U.S. Electric
Operating Companies' compliance filing of their open access transmission tariff.
The FERC previously had ordered the compliance filing to review the method by
which certain open access transmission tariff customers were to be charged for
transmission service. As a result of that order, certain changes were made in
the transmission coordination agreement related to the allocation of certain
open access transmission tariff revenues. Each U.S. Electric Operating Company
will be allocated revenue in proportion to the company's respective revenue
requirement for the service it provides under the revised open access
transmission tariff. The U.S. Electric Operating Companies requested and
received from the FERC a deferral of their refund obligation until the FERC
issues an order accepting the revised transmission coordination agreement.
On October 29, 1999, CSW filed with the FERC a revised transmission
coordination agreement. The revised transmission coordination agreement includes
changes to the original transmission coordination agreement to ensure the above
mentioned allocation of revenues to each U.S. Electric Operating Company. In the
third quarter of 1999, each of the U.S. Electric Operating Companies recorded
the estimated impact of the reallocation of open access transmission tariff
revenues, which increased CSW's income before taxes by approximately $8.75
million.
PSO PCB Cases
PSO was named a defendant in petitions filed in state court in Oklahoma in
February and August 1996. The petitions allege that the plaintiffs suffered
personal injury and fear future injury as a result of contamination by PCBs from
a transformer malfunction that occurred in April 1982 at the Page Belcher
Federal Building in Tulsa, Oklahoma. Each of the plaintiffs seeks actual and
punitive damages in excess of $10,000. Other claims arising from this incident
were settled and the suits dismissed. During the third quarter of 1999, all but
12 of the cases were settled for a nominal amount covered by PSO's insurance.
Management believes that PSO has defenses to the remaining complaints and
intends to defend the suits vigorously. Management believes that the remaining
claims, excluding claims for punitive damages, are also covered by insurance.
Management also believes that the ultimate resolution of the remaining lawsuits
will not have a material effect on CSW's or PSO's results of operations or
financial condition.
SWEPCO Louisiana Rate Review
In December 1997, the Louisiana Commission announced it would review
SWEPCO's rates and service. The Louisiana Commission has selected consultants
and legal counsel to perform a review of SWEPCO's rates and charges and to
review SWEPCO's quality of service. The Louisiana Commission's legal counsel
issued a report in June 1999, reflecting Louisiana revenues in excess of $28
million. SWEPCO believes the report contained significant theoretical and
mathematical errors and filed its rebuttal testimony on August 10, 1999.
In October 1999, SWEPCO and the Staff of the Louisiana Commission reached
an Agreement and Stipulation, which was filed on October 14, 1999. In support of
the Agreement and Stipulation, supplemental testimony was also filed. The
provisions of the Agreement and Stipulation are:
- - SWEPCO's Louisiana retail jurisdictional revenues are reduced by $11
million, effective with the December 1999 billing cycle;
- - SWEPCO will be allowed to earn an 11.1% return on common equity;
- - SWEPCO will recover certain regulatory assets totaling $7.1
million;
- - SWEPCO will be subject to a two-year base rate freeze, which will be
subject to force majeure provisions and;
- - Increased depreciation rates for transmission, distribution and general
plant.
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Hearings were held before an ALJ on October 19, 1999. To meet the December
1999 implementation date contemplated in the Agreement and Stipulation, an order
from the Louisiana Commission must be received in November 1999. The Louisiana
Commission is scheduled to vote on the Agreement and Stipulation at its November
17, 1999 meeting.
SWEPCO Arkansas Rate Review
In June 1998, the Arkansas Commission indicated that it would conduct a
review of SWEPCO's earnings. The review began in July 1998. SWEPCO entered into
a settlement agreement with the general staff of the Arkansas Commission and the
Arkansas Attorney General's Office. The settlement agreement was filed on July
30, 1999 and reduces revenues by $5.4 million or 3%. Additionally, the
Stipulation and Settlement Agreement provides for a 10.75% return on common
equity, an increase in depreciation rates, and an agreement by SWEPCO not to
seek recovery of generation related stranded costs.
On August 20, 1999, SWEPCO filed a Supplemental Stipulation and Settlement
Agreement, which was reached with the one remaining party. The Supplemental
Stipulation and Settlement Agreement did not alter or replace any of the
original monetary terms of the Stipulation and Settlement Agreement filed on
July 30, 1999.
On September 23, 1999, the Arkansas Commission issued an order approving
the Stipulation and Settlement Agreement and the Supplemental Stipulation and
Settlement Agreement. On October 25, 1999, SWEPCO filed compliance rate tariffs
with the Arkansas Commission, which are consistent with the Arkansas Commission
order. After a review of the compliance rate tariffs by the Staff of the
Arkansas Commission, new rates will be implemented. SWEPCO anticipates
implementing the new rates with the December 1999 billing cycle.
SWEPCO Interim Fuel Refund
On August 24, 1999, SWEPCO filed an application at the Texas Commission to
make an interim refund of fuel cost over-recoveries of $7.5 million received by
SWEPCO from its Texas retail jurisdictional customers. The application requested
that the refund be made in October 1999. On September 20, 1999, a stipulation
between all parties was filed with the Texas Commission, which preserved
SWEPCO's application to refund $7.5 million to SWEPCO's Texas retail customers.
An order granting interim approval to make the refund in October 1999 was issued
by the hearings examiner on September 24, 1999. SWEPCO began implementing the
refund on customer bills during the first billing cycle of October 1999. On
October 21, 1999, the Texas Commission issued a final order which affirmed
approval to refund the fuel cost over-recoveries.
SWEPCO Lignite Mining Agreement Litigation
SWEPCO and CLECO are each a 50% owner of Dolet Hills Power Station Unit 1
and jointly own lignite reserves in the Dolet Hills area of northwestern
Louisiana. In 1982, SWEPCO and CLECO entered into a lignite mining agreement
with the DHMV, a partnership for the mining and delivery of lignite from a
portion of these reserves.
On April 15, 1997, SWEPCO and CLECO sued DHMV and its partners in the
United States District Court for the Western District of Louisiana seeking to
enforce various obligations of DHMV to SWEPCO and CLECO under the lignite mining
agreement, including provisions relating to the quality of the delivered
lignite, pricing, and mine reclamation practices. On June 15, 1997, DHMV filed
an answer denying the allegations in the suit and filed a counterclaim asserting
various contract-related claims against SWEPCO and CLECO. SWEPCO and CLECO have
denied the allegations contained in the counterclaims. On January 8, 1999,
SWEPCO and CLECO amended the claims against DHMV in the lawsuit to include a
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request that the lignite mining agreement be terminated. The trial date has been
reset to May 22, 2000 to allow settlement discussions.
Although SWEPCO cannot predict the ultimate outcome of this matter,
management believes that the resolution of this matter will not have a material
effect on SWEPCO's results of operations or financial condition.
WTU Fuel Factor and Interim Fuel Surcharge Filing
In September 1999, WTU filed with the Texas Commission an Application for
Authority to Implement an increase in fuel factors of $13.5 million or 12.2% on
an annual basis. Additionally, WTU proposed to implement an interim fuel
surcharge of $6.5 million, including accumulated interest over a six-month
period to collect its under-recovered fuel costs. WTU proposed to implement the
revised fuel factors with its December 1999 billing cycle. On November 4, 1999,
the Texas Commission approved WTU's application. The order allows an increase in
fuel factors of 12.2% on an annual basis beginning in the billing cycle for
December 1999 and to surcharge customers to recover $6.5 million of
under-recovered fuel costs and associated interest for six months beginning in
the billing cycle for January 2000.
Regulatory Draft Price Proposal for SEEBOARD
On October 8, 1999, OFGEM published its revised draft price proposals and
results from its current United Kingdom electricity distribution review. OFGEM
has recommended revenue reductions in SEEBOARD's distribution business. In
addition, OFGEM has proposed the reallocation of a further 12%, or $45 million
of pre-tax costs out of SEEBOARD's distribution business into its supply
business. If adopted, these proposals would reduce SEEBOARD's net income in the
year 2000 by $40 million, and by $60 million on an annual basis thereafter,
depending upon the level of further cost reductions that can be achieved. CSW's
net income from SEEBOARD USA, its United Kingdom business segment, was $95
million for the twelve months ended September 30, 1999.
SEEBOARD continues to analyze the revised draft recommendations and their
potential effects on earnings and to seek further changes in OFGEM's proposed
recommendations to mitigate their effect on net income. SEEBOARD is also
currently analyzing future potential cost reductions that would partially
mitigate the impact of these proposals. OFGEM is expected to finalize its
recommendations in early December 1999, which would take effect in April 2000
for five years. SEEBOARD cannot predict whether the draft price proposals
ultimately will be adopted by OFGEM and, if they are adopted, the final form of
the proposals.
If OFGEM's draft price proposals for SEEBOARD ultimately were adopted
without change, implementation of the price proposals would have a material
adverse effect on the future results of operations of SEEBOARD USA and CSW. In
addition, implementation of the price proposals as drafted could adversely
affect the financial condition of SEEBOARD USA, but would not be expected to
adversely affect the financial condition of CSW.
OFGEM has published draft price proposals for the electricity supply
businesses. OFGEM has recommended that the price cap for charges levied to
electricity supply domestic and small business customers should be extended for
two years from April 2000. If adopted, the proposals are expected to be broadly
neutral on the results of operations of SEEBOARD USA.
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3. COMMITMENTS AND CONTINGENT LIABILITIES
PSO Guarantee of Numanco Obligations
In April 1999, PSO received an order from the SEC authorizing an increase
in its guarantee authority related to the outstanding debt of Numanco, a PSO
business venture. On November 3, 1999, PSO sold its investment in Numanco to CSW
Energy Services, Inc., another CSW subsidiary. Prior to the sale, PSO had
guaranteed obligations for Numanco in the amount of $29 million. The PSO
guarantee obligation was released upon the sale. There are no other guarantees
in place for Numanco by any of the CSW companies.
SWEPCO Henry W. Pirkey Power Plant
In connection with the South Hallsville lignite-mining contract for its
Henry W. Pirkey Power Plant, SWEPCO agreed, under certain conditions, to assume
the obligations of the mining contractor. As of September 30, 1999, the amount
SWEPCO may have to assume is approximately $68 million, which is the
contractor's actual obligation outstanding at September 30, 1999.
SWEPCO 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 and expansion
into the Marshall South lignite project area, SWEPCO agreed to guarantee the
costs of mine reclamation up to $85 million in the event the work is not
completed by the third party miner. At September 30, 1999, the cost to reclaim
the mine is estimated to be approximately $36 million.
Withdrawal of SWEPCO Cajun Asset Proposal
Cajun filed a petition for reorganization under Chapter 11 of the United
States Bankruptcy Code on December 21, 1994 under the supervision of the United
States Bankruptcy Court for the Middle District of Louisiana. Both SWEPCO and
Louisiana Generating LLC had filed competing plans of reorganization for the
non-nuclear assets of Cajun with the bankruptcy court.
On August 26, 1999, SWEPCO, together with the Cajun Members Committee and
Washington-St. Tammany Electric Cooperative, reached a settlement agreement to
withdraw the jointly filed July 1999 SWEPCO Plan to acquire all of the
non-nuclear assets of Cajun during a settlement conference ordered by the United
States District Court in Baton Rouge, Louisiana.
SWEPCO had deferred approximately $13.0 million in costs related to the
Cajun acquisition on its consolidated balance sheet. Under the settlement
agreement, SWEPCO received $7.5 million on November 8, 1999. The after tax loss
reflected in the third quarter of 1999 was $3.7 million.
SWEPCO Biloxi, Mississippi MGP Site
SWEPCO was notified by Mississippi Power in 1994 that it may be a PRP at a
MGP site in Biloxi, Mississippi. Since then, SWEPCO has worked with Mississippi
Power investigating the extent of contamination at the site. The sampling
results indicate contamination at the property as well as the possible
contamination of an adjacent property. After submitting a risk assessment, the
MDEQ requested that a future residential exposure scenario be evaluated for
comparison with commercial and industrial exposure scenarios. However,
Mississippi Power and SWEPCO do not believe that cleanup to a residential
scenario is appropriate since the site has been an industrial/commercial site
for more than 100 years, and Mississippi Power plans to continue this type of
usage. Mississippi Power and SWEPCO presented a report to the MDEQ demonstrating
that the ground water on the site is not potable and that cleanup to residential
standards is not necessary. Resolution of this issue is still pending.
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Currently, a feasibility study is being conducted to evaluate remedial
strategies for the property. The feasibility study process will require public
input prior to a final decision and will result in a remediation strategy and a
projection of the cost to remediate the property.
SWEPCO has incurred costs of approximately $200,000 for its portion of the
cleanup of this site and based on preliminary estimates, anticipates that an
additional $2 million may be incurred. Accordingly, SWEPCO has accrued an
additional $2 million for the cleanup of the site.
SWEPCO Wilkes Power Plant Copper Limit Compliance
The EPA has cited SWEPCO's Wilkes power plant in an administrative order
for wastewater permit violations related to copper level limits. Planned
compliance activities, including activities that have been conducted to
determine the source of copper, were presented by SWEPCO to the EPA during an
administrative meeting, held on August 13, 1998. SWEPCO and the EPA negotiated a
$41,500 penalty pending final approval.
SEEBOARD London Underground Commitment
In 1998, SEEBOARD, through its subsidiary SEEBOARD Powerlink, signed a
$1.6 billion, 30 year contract as a joint venture partner to operate, maintain,
finance and renew the high-voltage power distribution network of the London
Underground transportation system. Power Asset Development Company, an associate
of SEEBOARD, has committed (pound)62 million or $102 million for costs
associated with its contract related to the London Underground transportation
system.
SEEBOARD Third Party Pension Litigation
In the U.K., National Grid Group and National Power have been involved in
continuing litigation regarding their use of actuarial surpluses set forth in
the electricity industry's occupational pension plan, the ESPS. A High Court
decision in favor of the National Grid Group and National Power was appealed. On
February 10, 1999, the U.K. Court of Appeal ruled that the particular
arrangements made by these corporations to dispose of part of the surplus were
invalid due to procedural defects. This decision was confirmed at a later
hearing of the U.K. Court of Appeal held in May 1999, although an opportunity
for an appeal to be taken to the House of Lords, the highest court of appeal in
the U.K., was granted.
SEEBOARD employees are members of the ESPS, and SEEBOARD has made similar
use of its actuarial surplus. As a result of subsequent legal clarification of
certain issues arising from the hearing held in May 1999, the potential impact
of the ruling on SEEBOARD has increased. The amount of the payments cancelled by
SEEBOARD, both for past and future liabilities, amounts, in the aggregate, to
approximately $78 million, excluding interest.
The U.K. Court of Appeal did not order the National Grid Group or National
Power to make payment into the ESPS, and the court indicated that any
requirement to make such payments would be extreme since the ESPS already is in
surplus. In the event that the court finally decides a payment by SEEBOARD into
the ESPS is necessary, such a payment is likely to create additional pension
fund surplus, which the company should then be able to utilize over the next
several years to reduce pension expense.
The National Grid Group has indicated its intention to appeal to the House
of Lords. The final outcome of this appeal cannot presently be determined.
Management is unable currently to predict the amount of any payment that it may
be required to make to ESPS or the effect, if any, of the ultimate outcome of
the appeal on CSW's results of operations and financial condition.
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Diversified Electric Loans and Commitments
CSW Energy began construction in August 1998 of a 500 MW power plant,
known as Frontera, in the Rio Grande Valley, near the city of Mission, Texas.
The Frontera project is being built as a merchant power plant. Frontera is
expected to supply power to the rapidly growing Rio Grande Valley and to supply
customers throughout Texas. In addition to funds already spent, at September 30,
1999, CSW Energy has committed costs of approximately $15 million, including
development, construction and financing costs. The natural gas-fired facility
began simple cycle operation of 330 MW in July 1999 and is scheduled to commence
combined cycle operation by early 2000. Pursuant to AEP's and CSW's stipulated
settlement with several intervenors in the state of Texas related to the AEP
Merger, CSW Energy will sell 250 MW of Frontera after completion of the merger.
See NOTE 5. PROPOSED AEP MERGER and ITEM 2. MD&A, PROPOSED AEP MERGER.
CSW Energy has entered into an agreement with Eastman Chemical Company to
construct and operate a 440 MW cogeneration facility in Longview, Texas. This
facility will be known as the Eastex Cogeneration Project. Construction of the
facility is scheduled to begin in the fourth quarter of 1999, with expected
operation in 2001. Excess electricity generated by the plant will be sold by CSW
Energy in the wholesale electricity market. Since Eastex will be built as a
qualifying facility, CSW Energy will be required to sell 50% of the plant prior
to commercial operation.
In October 1999, GE Capital Structured Finance Group's purchased 50
percent of the equity ownership of Sweeny Cogeneration Limited Partnership. CSW
Energy's after-tax earnings from the proceeds of the transaction will be
approximately $33 million and will be recorded in the fourth quarter of 1999.
The agreement between CSW Energy and GE Capital Structured Finance Group also
provides for additional payments subject to completion of a planned expansion of
the Sweeny cogeneration facility.
CSW International and its 50% partner, Scottish Power plc, have entered
into a joint venture to construct and operate the South Coast power project, a
400-MW combined cycle gas turbine power station in Shoreham, United Kingdom. CSW
International has guaranteed approximately (pound)19 million of the (pound)190
million projected construction costs, and the permanent financing is
unconditionally guaranteed by the project. Construction of the project began in
March 1999, and commercial operation is expected to begin in 2000.
CSW, CSW Energy and CSW International have provided letters of credit and
guarantees on behalf of independent power projects totaling approximately $29
million, $56 million, and $235 million, respectively, as of September 30, 1999.
4. COMMON STOCK AND DIVIDENDS
CSW's basic earnings per share of common stock for a period are computed
by dividing net income for common stock by the average number of common shares
outstanding for the period. CSW's dividends per common share reflect the
dividend paid for each period.
At September 30, 1999, approximately $1.9 billion of CSW's subsidiary
companies' retained earnings were available for payment of cash dividends to
CSW. The amount of retained earnings available for dividends from each of the
U.S. Electric Operating Companies at September 30, 1999 was as follows:
CPL - $796 million PSO - $167 million SWEPCO - $296 million WTU - $124 million
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5. PROPOSED AEP MERGER
On December 22, 1997, CSW and AEP announced that their boards of directors
had approved a definitive merger agreement for a tax-free, stock-for-stock
transaction. The combined company would serve more than 4.6 million customers in
11 states and approximately 4 million customers outside the United States. On
May 27, 1998, AEP shareholders approved the issuance of the additional shares of
stock required to complete the merger. On May 28, 1998, CSW stockholders
approved the merger.
Under the merger agreement, each common share of CSW will be converted
into 0.6 share of AEP common stock. CSW stockholders will own approximately 40%
of the combined company. CSW plans to continue to pay dividends on its common
stock until the closing of the AEP Merger at approximately the same times and
rates per share as in 1998, subject to continuing evaluation of CSW's financial
condition, earnings, prospects and other factors by the CSW board of directors.
Under the merger agreement, there will be no changes required with respect
to the public debt issues, the outstanding preferred stock or the Trust
Preferred Securities of CSW's subsidiaries.
AEP and CSW anticipate net savings related to the merger of approximately
$2 billion over a 10-year period from the elimination of duplication in
corporate and administrative programs, greater efficiencies in operations and
business processes, increased purchasing efficiencies and the combination of the
two work forces. AEP and CSW continue to seek opportunities for additional
savings. At the same time, the companies expect to continue their commitment to
high quality, reliable service. Job reductions related to the merger are
expected to be approximately 1,050 out of a total domestic workforce of
approximately 25,000. The combined company expects to use a combination of
growth, reduced hiring and attrition to minimize the need for employee
separations. Transition teams of employees from both companies will make
organizational and staffing recommendations.
The electric systems of AEP and CSW will operate on an integrated and
coordinated basis as required by the Holding Company Act. AEP and CSW project
fuel savings of approximately $98 million over a 10-year period resulting from
the coordinated operation of the combined company, which will be passed through
to customers.
The merger agreement contains covenants and agreements that restrict the
manner in which the parties may operate their respective businesses until the
time of closing of the merger. In particular, without the prior written consent
of AEP, CSW may not engage in a number of activities that could affect its
sources and uses of funds. Pending closing of the merger, CSW's and its
subsidiaries' strategic investment activity, capital expenditures and non-fuel
operating and maintenance expenditures are limited to specific agreed upon
projects and in agreed upon amounts. In addition, prior to consummation of the
merger, CSW and its subsidiaries are restricted from: (i) issuing shares of
common stock other than pursuant to employee benefit plans; (ii) issuing shares
of preferred stock or similar securities other than to refinance existing
obligations or to fund permitted investment or capital expenditures; and (iii)
incurring indebtedness other than pursuant to existing credit facilities, in the
ordinary course of business, or to fund permitted projects or capital
expenditures. These limitations do not preclude CSW and its subsidiaries from
making investments and expenditures in amounts previously budgeted.
Cook Nuclear Plant
On June 25, 1999, AEP announced a comprehensive plan to restart the idle
Cook nuclear power plant. Unit 2 is scheduled to return to service in April
2000, and Unit 1 is scheduled to return to service in September 2000. AEP stated
that its announcement follows a comprehensive systems readiness review of all
operating systems at Cook nuclear power plant and a cost/benefit analysis of
whether to restart the plant or shut it down completely. Plant officials
originally shut down both units of the facility, located in Bridgman, Michigan,
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in September 1997 because of questions raised during a design inspection by the
NRC. AEP estimated that its costs to restart the idle plant should be
approximately $574 million of which $280 million has been spent through
September 1999.
Merger Regulatory Approvals
The merger is conditioned, among other things, upon the approval of
several state and federal regulatory agencies.
General
Testimony submitted in the filings in Arkansas, Louisiana, Oklahoma, Texas
and at the FERC outlined the expected company-wide benefits of the merger to AEP
and CSW customers and shareholders.
FERC
On April 30, 1998, AEP and CSW jointly filed a request with the FERC for
approval of their proposed merger.
On May 25, 1999, AEP and CSW announced they had reached a settlement with
the FERC trial staff resolving competition and rate issues relating to the
proposed merger. On July 13, 1999, AEP and CSW reached an additional settlement
with the FERC trial staff resolving additional issues. The settlement has been
submitted to the FERC for approval.
Under the terms of the settlements, in June 1999 AEP filed with the FERC a
regional transmission organization proposal whereby it will transfer the
operation and control of AEP's bulk transmission facilities to an undetermined
independent system operator. The transmission facilities subject to this
commitment are located in Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia
and West Virginia.
The settlements also cover rates for transmission services and ancillary
services as well as resolving issues related to the system integration
agreement, the transmission reassignment tariff and the system transmission
integration agreement. The settlements confirm, subject to FERC guidance on
certain elements, that the proposed generation divestiture will satisfy the
market power concerns of the FERC staff. In their merger filing with the FERC,
AEP and CSW proposed divesting ownership of 300 MW of generation capacity at
PSO's Northeastern Power Station Units 3 and 4 in Oklahoma and 250 MW of
generation capacity at the Frontera power plant, a merchant plant constructed in
Texas by a CSW subsidiary.
On June 28, 1999, AEP and CSW filed a motion asking the FERC to waive the
requirement for a post-hearing decision by the ALJ and consideration of the
matter by the FERC based on the hearing record and briefs. The FERC subsequently
issued an order requiring the ALJ to issue an initial decision as soon as
possible, but no later than November 24, 1999. The FERC order also set a
procedural schedule that should allow the FERC to issue a final order in the
first quarter of 2000.
AEP and CSW have reached settlements with the Missouri Public Service
Commission and various wholesale customers and intervenors in the FERC merger
proceeding.
Hearings at the FERC concluded on July 19, 1999.
Arkansas
On June 12, 1998, AEP and CSW jointly filed a request with the Arkansas
Commission for approval of the proposed merger. The Arkansas Commission issued
an order approving the merger on August 13, 1998, subject to approval of the
associated regulatory plan. On December 17, 1998, the Arkansas Commission issued
a final order granting conditional approval of a stipulated agreement related to
a proposed merger regulatory plan. The stipulated agreement calls for SWEPCO to
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reduce rates through a net merger savings rider for its Arkansas retail
customers by $6 million over the five-year period following completion of the
merger. The Arkansas Commission order notes the possibility of decisions in
other jurisdictions adversely affecting provisions of the stipulated agreement.
Consequently, the Arkansas Commission conditioned its final order on its
consideration of approval of the merger in other state and federal
jurisdictions.
Louisiana
On May 15, 1998, AEP and CSW jointly filed a request with the Louisiana
Commission for approval of the proposed merger and for a finding that the merger
is in the public interest.
On September 27, 1999, the Louisiana Commission issued a final order
granting conditional approval of the pending merger between AEP and CSW. In
granting approval, the Louisiana Commission also approved a stipulated
settlement with the Louisiana Commission staff. Under the stipulated settlement,
AEP and CSW have agreed to share with SWEPCO's Louisiana customers merger
savings created as a result of the merger over the eight years following its
completion. A savings mechanism will be implemented to calculate merger savings
annually. AEP and CSW estimate that the customer rate credits in Louisiana will
total more than $18 million during that eight-year period. During the second
year following completion of the merger, customers will begin receiving a
monthly rate credit for 50% of calculated merger savings. This credit will be
updated annually and continue for the remainder of the eight-year period
following the merger's completion.
Oklahoma
On August 14, 1998, AEP and CSW jointly filed a request with the Oklahoma
Commission for approval of their proposed merger.
An amended application was filed with the Oklahoma Commission on February
25, 1999. On May 11, 1999, the Oklahoma Commission approved the proposed merger
between AEP and CSW. The approval follows a partial settlement between the
Oklahoma Commission Utility Division Staff, the Oklahoma Commission Consumer
Services Division, the Office of the Attorney General for Oklahoma, PSO, AEP and
CSW. The Oklahoma Commission order was appealed by the Municipal Electric
Systems of Oklahoma, Inc. and the Oklahoma Association of Electric Cooperatives.
On October 13, 1999, the Oklahoma Supreme Court dismissed the appeal of the
Oklahoma Association of Electric Cooperatives. The Municipal Electric System of
Oklahoma, Inc. withdrew its appeal and the Oklahoma Association of Electric
Cooperatives filed a motion to dismiss its appeal of the Oklahoma Commission
order approving the merger.
Under the partial settlement agreement, AEP and CSW would: (i) share
merger savings with Oklahoma customers as well as AEP shareholders, effective
with the merger closing; (ii) not increase Oklahoma base rates prior to January
1, 2003; (iii) file by December 31, 2001 with the FERC an application to join a
regional transmission organization; and (iv) establish additional quality of
service standards for PSO's retail customers. Oklahoma's share of the $50.2
million in guaranteed net merger savings over the first five years after the
merger is consummated would be split between Oklahoma customers and AEP
shareholders, with customers receiving approximately 55% of the savings.
The Oklahoma Commission has withdrawn its opposition to the merger at the
FERC.
Texas
On April 30, 1998, AEP and CSW jointly filed a request with the Texas
Commission for a finding that the merger is in the public interest.
On May 4, 1999, AEP and CSW announced a proposed settlement with several
intervenor groups for the proposed merger between AEP and CSW. The settlement
would result in combined rate reductions totaling $221 million over a six-year
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period for Texas customers of the three CSW Texas electric operating companies
(CPL, SWEPCO and WTU) if the merger is completed as planned and issues are
resolved associated with CPL, SWEPCO and WTU rate and fuel reconciliation
proceedings.
The settlement was reached with the General Counsel of the Texas
Commission, the State of Texas, the Texas Industrial Energy Consumers, the Low
Income Intervenors, the Office of Public Utility Counsel of Texas and the
steering committee of the Cities of McAllen, Corpus Christi, Victoria, Abilene,
Big Lake, Vernon and Paducah. The settlement expands upon a previous Texas
settlement announced on November 12, 1998, with the Office of Public Utility
Counsel of Texas and the cities' steering committee. That prior settlement
agreement provided for Texas retail rate reductions of $180 million over the six
years following completion of the merger. The new settlement agreement proposes
additional rate reductions totaling $41 million for a total of $221 million. The
settlement also calls for the divestiture of a total of 1,604 MW of existing and
proposed generating capacity within Texas.
The first rate-reduction rider provides for $84.4 million in net-merger
savings. The amounts are to be credited to Texas customers' bills through a
net-merger-savings rate-reduction rider over six years following completion of
the merger.
Additional rate-reduction riders will be implemented to resolve issues
associated with CPL, WTU and SWEPCO rate and fuel reconciliation proceedings and
court appeals in Texas. The settlement provides for an additional reduction of
$136.6 million, which will be implemented over the six years following
completion of the merger.
Hearings on the merger in Texas began August 9, 1999 and concluded on
August 10, 1999. As the hearings began, settlements were reached with all but
one of the parties in the case. The settling parties are all wholesale electric
customers of the three CSW Texas electric operating companies, and the
settlements call for the withdrawal of their opposition to the merger in all
regulatory approval proceedings. On October 1, 1999, an ALJ for the Texas State
Office of Administrative Hearings issued a proposal for decision recommending
that the Texas Commission approve the pending merger between AEP and CSW. In the
proposal for decision, the ALJ determined that, consistent with the terms of the
proposed settlement, the merger is in the public interest. On November 2, 1999,
the Texas Commission approved the proposed merger with AEP.
NRC
On June 19, 1998, CPL filed a license transfer application with the NRC
requesting the NRC's consent to the indirect transfer of control of CPL's
interests in the NRC licenses issued for STP from CSW to AEP. CPL would continue
to own its 25.2% interest in STP, and CPL's name would remain on the NRC
operating license. On November 5, 1998, the NRC approved the license transfer
application with a condition that the merger must be completed by December 31,
1999. CPL will request an extension of the license transfer with the NRC in the
fourth quarter of 1999.
Other Federal
On October 13, 1998, AEP and CSW jointly filed an application with the SEC
for approval of the proposed merger. The SEC merger filing is similar to
requests currently pending before other jurisdictions and outlines the expected
combined company benefits of the merger to AEP and CSW customers and
shareholders. Since then, AEP and CSW have filed several amendments to the
application. Several parties have filed petitions opposing the proposed merger
at the SEC. On July 23, 1999, AEP and CSW filed a brief in response to the
intervenor petitions at the SEC. AEP and CSW will file a further amendment to
the application in the fourth quarter of 1999.
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On July 29, 1999, applications were made with the FCC to authorize the
transfer of control of licenses of several CSW entities to AEP. The granting of
such authority is expected by the end of 1999 and will be effective upon
completion of the proposed merger.
On July 26, 1999, AEP and CSW submitted filings to the Department of
Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. On
August 26, 1999, AEP and CSW received a request for additional information from
the Department of Justice. AEP and CSW plan to file the additional information
with the Department of Justice in the fourth quarter of 1999.
United Kingdom
CSW has a 100% interest in SEEBOARD and AEP has a 50% interest in
Yorkshire. The proposed merger of CSW into AEP would result in common ownership
of the United Kingdom entities. Although the merger of CSW into AEP is not
subject to approval of United Kingdom regulatory authorities, the common
ownership of the United Kingdom entities could be referred by the United Kingdom
Secretary of State for Trade and Industry for an investigation by the United
Kingdom Competition Commission. CSW is unable to predict the ultimate outcome of
any such regulatory proceeding.
AEP
On April 20, 1999, AEP reached a settlement with the Indiana Utility
Regulatory Commission staff addressing matters pertinent to Indiana regarding
the proposed merger. The Indiana Utility Regulatory Commission approved the
settlement on April 26, 1999. The settlement agreement resulted from an
investigation of the proposed merger between AEP and CSW initiated by the
Indiana Utility Regulatory Commission.
On April 21, 1999, AEP and CSW announced that they had reached separate
settlements with six wholesale customers that address issues related to the
proposed merger.
On April 28, 1999, AEP and CSW announced that they ratified a settlement
agreement with local unions of the IBEW representing employees of AEP and CSW.
The settlement agreement covered issues related to the pending merger between
AEP and CSW. As part of the settlement, the IBEW local unions have withdrawn
their opposition to the merger.
On May 26, 1999, AEP and CSW announced that they had reached a settlement
agreement with the Kentucky Attorney General and several AEP customers in
Kentucky addressing matters pertinent to Kentucky regarding the pending merger
between AEP and CSW. The Kentucky Public Service Commission has approved the
settlement.
On August 6, 1999, AEP announced that it had ratified a settlement
agreement with local unions of the UWUA representing employees of AEP. The
settlement agreement covered issues raised in the pending merger between AEP and
CSW. As part of the settlement, the UWUA local unions will not oppose the
merger.
On October 21, 1999, the Public Utility Commission of Ohio issued a
decision stating that it will notify the FERC that it is no longer opposed to
AEP's proposed merger with CSW and that it will no longer seek conditions to the
merger.
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Completion of the Merger
AEP and CSW have targeted consummation of the AEP Merger in the second
quarter of 2000. The merger is conditioned, among other things, upon the
approval of several state and federal regulatory agencies. The transaction must
satisfy many conditions, including the condition that it must be accounted for
as a pooling of interests. The parties may not waive some of these conditions.
AEP and CSW continue the process of seeking regulatory approvals, but there can
be no assurance as to when, on what terms or whether the required approvals will
be received or whether there will be any regulatory proceedings in the United
Kingdom. After December 31, 1999, either CSW or AEP may terminate the merger
agreement if all of the conditions to its obligation to close have not been
satisfied, provided that either party may extend the merger agreement, under
certain circumstances, through June 30, 2000. There can be no assurance that the
AEP Merger will be consummated.
Merger Costs
As of September 30, 1999, CSW had deferred $38.6 million in costs related
to the AEP Merger on its consolidated balance sheet, which will be charged to
expense if AEP and CSW are not successful in completing their proposed merger.
6. BUSINESS SEGMENTS
CSW's business segments include the U.S. Electric and U.K. Electric
segments. The U.S. Electric segment is comprised of CSW's four domestic electric
operating companies, CPL, PSO, SWEPCO and WTU. The U.K. Electric segment is
comprised of CSW's foreign electric operating company, SEEBOARD USA. The U.S.
Electric segment's primary business is the generation, transmission and
distribution of electricity. The U.K. Electric segment's primary business is the
supply and distribution of electricity. Financial data for each business segment
for the three-month and nine-month periods ended September 30, 1999 and 1998,
respectively, covered is set forth below.
U.S. U.K. Other and CSW
Electric Electric Reconciling Consolidated
----------------------------------------------
(millions)
Three months ended September 30,
1999
Operating Revenues $1,170 $354 $94 $1,618
Income/(Loss) before
Extraordinary Item 221 19 (10) 230
Three months ended September 30,
1998
Operating Revenues $1,172 $352 $57 $1,581
Income/(Loss) before
Extraordinary Item 230 31 (28) 233
U.S. U.K. Other and CSW
Electric Electric Reconciling Consolidated
----------------------------------------------
(millions)
Nine months ended September 30, 1999
Operating Revenues $2,758 $1,192 $212 $4,162
Income/(Loss) before
Extraordinary Item 353 63 (38) 378
Total Assets at September 30, 1999 8,999 3,089 2,343 14,431
Total Assets at December 31, 1998 8,994 3,032 1,871 13,897
Nine months ended September 30, 1998
Operating Revenues $2,746 $1,288 $148 $4,182
Income/(Loss) before
Extraordinary Item 370 85 (56) 399
Total Assets at September 30, 1998 9,117 3,136 2,008 14,261
Total Assets at December 31, 1997 9,186 2,931 1,499 13,616
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7. SOUTH AMERICAN INVESTMENTS
Through September 30, 1999, CSW International had purchased a 36% equity
interest in Vale for $80 million. CSW International also extended $100 million
of debt to Vale. CSW International anticipates converting $69 million of the
debt to equity by the end of 1999 with the remainder to be converted over the
next two years. Currently, CSW International accounts for its $80 million
investment in Vale on the equity method of accounting, and the $100 million of
debt as a loan.
In mid-January 1999, amid market instability, the Brazilian government
abandoned its policy of pegging the Brazilian Real in a broad range against the
dollar. This action resulted in a 45% devaluation of the Brazilian currency by
the end of September 1999. Vale is unfavorably affected by the devaluation due
primarily to the revaluation of foreign denominated debt.
CSW International has a put option, which, if exercised, requires Vale to
purchase its shares from CSW International at a minimum price equal to the
purchase price paid for the shares by CSW International. As a result of the put
option arrangement, management has concluded that CSW International's investment
carrying amount will not be reduced below the put option value unless there is
deemed to be a permanent impairment. Pursuant to the put option arrangement, CSW
International will not recognize its proportionate share of any future earnings
until its proportionate share of any losses of Vale are recognized. At September
30, 1999, CSW International had deferred losses, after tax, of approximately $23
million related to its Vale investment. CSW International views its investment
in Vale as a long-term investment, which has significant long-term value.
Management will continue to closely evaluate the changes in the Brazilian
economy and its impact on CSW International's investment in Vale.
As of September 30, 1999, CSW International had invested $110 million in
stock of a Chilean electric company. The investment is classified as securities
available for sale and accounted for by the cost method. Based on the market
value of the shares and foreign exchange rates, the value of the investment at
September 30, 1999 was $62 million. The reduction in the carrying value of this
investment has been reflected in Other Comprehensive Income in CSW's
Consolidated Statements of Stockholders' Equity. Management views its investment
in Chile as a long-term investment strategy and believes this investment
continues to have significant long-term value and that it is recoverable.
Management will continue to closely evaluate the changes in the South American
economy and its impact on CSW International's investment in the Chilean electric
company.
8. LONG-TERM DEBT
In November 1999, Matagorda County Navigation District No. 1 (Texas) will
sell for the benefit of CPL $111.7 million of 4.90% Series 1999A and $50.0
million of 4.95% Series 1999B unsecured tax exempt pollution control revenue
refunding bonds. The bonds mature in 2030 but will be subject to remarketing and
an interest rate reset in two years. The proceeds will be used to refund $111.7
million aggregate principal amount of outstanding Matagorda 7-1/2% Series 1984A
bonds due December 15, 2014 and $50.0 million aggregate principal amount
of outstanding 7-1/2% Matagorda Series 1990 bonds due March 21, 2020.
In July 1999, the Oklahoma Development Finance Authority sold for the
benefit of PSO $33.7 million of 4-7/8% unsecured tax exempt pollution control
revenue refunding bonds. The bonds mature in fifteen years but will be subject
to remarketing and an interest rate reset in five years. In late August 1999,
the proceeds were used to refund $33.7 million aggregate principal amount of
outstanding Oklahoma Environmental Finance Authority (PSO Project) 5.9% Series A
bonds due December 1, 2007.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Reference is made to Management's Discussion and Analysis of Financial
Condition and Results of Operations included in the Registrants' Combined Annual
Report on Form 10-K for the year ended December 31, 1998 and the Registrants'
Combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999
and June 30, 1999. Reference is also made to each Registrant's unaudited
Financial Statements and related Notes to Financial Statements included in this
document. The information should be read in conjunction with, and is essential
to understanding, the following discussion and analysis.
RESULTS OF OPERATIONS
Reference is made to ITEM 1. FINANCIAL STATEMENTS for each of the
Registrants' RESULTS OF OPERATIONS for the three month and nine month periods
ended September 30, 1999.
LIQUIDITY AND CAPITAL RESOURCES
Overview of CSW Operating, Investing, and Financing Activities
Net cash inflows from operating activities decreased $172 million to $452
million for the nine month period ended September 30, 1999 compared to the same
period last year due primarily to decreased fuel recoveries from customers. Also
contributing to the decrease in cash flows from operating activities was a
decrease in accrued taxes for the comparison periods due primarily to lower
pre-tax income and a larger refund received in 1998. Further contributing to the
decrease in cash flows from operating activities were increased payments on
accounts payable. Partially offsetting the decrease in cash flows from operating
activities was a lower change in accounts receivable balance in 1999 compared to
1998 resulting from more favorable collections. Further offsetting the decrease
in cash flows from operating activities was the absence in 1999 of a refund paid
to CPL customers in the first six months of 1998.
Net cash outflows from investing activities increased $84 million to $565
million during the first nine months of 1999 compared to the same period a year
ago. The increase in net cash outflows from investing activities resulted
primarily from higher levels of spending in 1999 for CSW Energy projects, U.S.
Electric Operating Companies' construction expenditures and U.K. Electric's
construction expenditures. Also contributing to the increase in net cash
outflows from investing activities was the assumption in 1998 by CSW
International's Altamira partner, Alpek, of a 50% obligation related to a power
plant project, which was not present in 1999. Partially offsetting the increase
in cash outflows from investing activities was the absence in 1999 of additional
CSW International loans to Vale and lower construction expenditures in 1999 at
C3 Communications.
Net cash inflows from financing activities increased $155 million to $118
million for the first nine months of 1999 compared to the same period in 1998.
The increase was due primarily to the absence in 1999 of the repayment of a $60
million variable rate bank loan at CSW Services and the redemption of $28
million of preferred stock at SWEPCO. Also contributing to the increase in cash
flows from financing activities was a lower change in short-term debt due
primarily to lower interest rates and the absence in 1999 of the CPL 1998 bonded
rate refund. Partially offsetting the increase in net cash inflows was a higher
level of long-term maturities and reacquisitions in 1999 compared to 1998.
Construction Expenditures
CSW's construction expenditures, including allowance for funds used during
construction, totaled $549 million for the nine months ended September 30, 1999.
Such expenditures for the U.S. Electric Operating Companies totaled $141
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million, $74 million, $74 million and $36 million, for CPL, PSO, SWEPCO and WTU,
respectively. Construction expenditures at the U.S. Electric Operating Companies
were due primarily to improvements to existing production, transmission and
distribution facilities. The improvements are required to meet the needs of new
customers and the changing requirements of existing customers. CSW anticipates
that substantially all funds required for construction for the remainder of the
year will be provided from internal sources.
Other Financing Issues
The CSW System uses short-term debt to meet fluctuations in working
capital requirements and other interim capital needs. CSW has established a
system money pool to coordinate short-term borrowings for certain of its
subsidiaries, primarily the U.S. Electric Operating Companies. In addition, CSW
also incurs borrowings for other subsidiaries that are not included in the money
pool. As of September 30, 1999, CSW had revolving credit facilities totaling
$1.4 billion to back up its commercial paper program. On June 25, 1999, CSW
Credit closed its third amended and restated secured revolving credit agreement.
The $1.2 billion facility will expire on June 23, 2000.
On April 2, 1999, C3 Communications announced a major expansion of C3
Networks, its long haul fiber network division. C3 Networks plans to invest over
$26 million in existing routes and new construction in 1999, of which $13
million was spent through September 30, 1999. C3 Networks delivers networking
and services in Texas and Louisiana and plans to expand the network to Oklahoma.
In November 1999, Matagorda County Navigation District No. 1 (Texas) will
sell for the benefit of CPL $111.7 million of 4.90% Series 1999A and $50.0
million of 4.95% Series 1999B unsecured tax exempt pollution control revenue
refunding bonds. The bonds mature in 2030 but will be subject to remarketing and
an interest rate reset in two years. The proceeds will be used to refund $111.7
million aggregate principal amount of outstanding Matagorda 7-1/2% Series 1984A
bonds due December 15, 2014 and $50.0 million aggregate principal amount
of outstanding 7-1/2% Matagorda Series 1990 bonds due March 21, 2020.
In July 1999, the Oklahoma Development Finance Authority sold for the
benefit of PSO $33.7 million of 4-7/8% unsecured tax-exempt pollution control
revenue refunding bonds. The bonds mature in fifteen years but will be subject
to remarketing and an interest rate reset in five years. In August 1999, the
proceeds were used to refund $33.7 million aggregate principal amount
outstanding of Oklahoma Environmental Finance Authority (PSO Project) 5.9%
Series A bonds due December 1, 2007.
The foregoing discussion of liquidity and capital resources contains
forward-looking information within the meaning of Section 21E of the Exchange
Act. Actual results may differ materially from such projected information due to
changes in the underlying assumptions. See FORWARD-LOOKING INFORMATION.
PROPOSED AEP MERGER
On December 22, 1997, CSW and AEP announced that their boards of directors
had approved a definitive merger agreement for a tax-free, stock-for-stock
transaction. The combined company would serve more than 4.6 million customers in
11 states and approximately 4 million customers outside the United States. On
May 27, 1998, AEP shareholders approved the issuance of the additional shares of
stock required to complete the merger. On May 28, 1998, CSW stockholders
approved the merger.
Under the merger agreement, each common share of CSW will be converted
into 0.6 share of AEP common stock. CSW stockholders will own approximately 40%
of the combined company. CSW plans to continue to pay dividends on its common
stock until the closing of the AEP Merger at approximately the same times and
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rates per share as in 1998, subject to continuing evaluation of CSW's financial
condition, earnings, prospects and other factors by the CSW Board of Directors.
Under the merger agreement, there will be no changes required with respect
to the public debt issues, the outstanding preferred stock or the Trust
Preferred Securities of CSW's subsidiaries.
AEP and CSW anticipate net savings related to the merger of approximately
$2 billion over a 10-year period from the elimination of duplication in
corporate and administrative programs, greater efficiencies in operations and
business processes, increased purchasing efficiencies and the combination of the
two work forces. AEP and CSW continue to seek opportunities for additional
savings. At the same time, the companies expect to continue their commitment to
high quality, reliable service. Job reductions related to the merger are
expected to be approximately 1,050 out of a total domestic workforce of
approximately 25,000. The combined company expects to use a combination of
growth, reduced hiring and attrition to minimize the need for employee
separations. Transition teams of employees from both companies will make
organizational and staffing recommendations.
The electric systems of AEP and CSW will operate on an integrated and
coordinated basis as required by the Holding Company Act. AEP and CSW project
fuel savings of approximately $98 million over a 10-year period resulting from
the coordinated operation of the combined company, which will be passed through
to customers.
The merger agreement contains covenants and agreements that restrict the
manner in which the parties may operate their respective businesses until the
time of closing of the merger. In particular, without the prior written consent
of AEP, CSW may not engage in a number of activities that could affect its
sources and uses of funds. Pending closing of the merger, CSW's and its
subsidiaries' strategic investment activity, capital expenditures and non-fuel
operating and maintenance expenditures are limited to specific agreed upon
projects and in agreed upon amounts. In addition, prior to consummation of the
merger, CSW and its subsidiaries are restricted from: (i) issuing shares of
common stock other than pursuant to employee benefit plans; (ii) issuing shares
of preferred stock or similar securities other than to refinance existing
obligations or to fund permitted investment or capital expenditures; and (iii)
incurring indebtedness other than pursuant to existing credit facilities, in the
ordinary course of business, or to fund permitted projects or capital
expenditures. These limitations do not preclude CSW and its subsidiaries from
making investments and expenditures in amounts previously budgeted.
Cook Nuclear Plant
On June 25, 1999, AEP announced a comprehensive plan to restart the idle
Cook nuclear power plant. Unit 2 is scheduled to return to service in April
2000, and Unit 1 is scheduled to return to service in September 2000. AEP stated
that its announcement follows a comprehensive systems readiness review of all
operating systems at Cook nuclear power plant and a cost/benefit analysis of
whether to restart the plant or shut it down completely. Plant officials
originally shut down both units of the facility, located in Bridgman, Michigan,
in September 1997 because of questions raised during a design inspection by the
NRC. AEP estimated that its costs to restart the idle plant should be
approximately $574 million of which $280 million has been spent through
September 1999.
Merger Regulatory Approvals
The merger is conditioned, among other things, upon the approval of
several state and federal regulatory agencies.
General
Testimony submitted in the filings in Arkansas, Louisiana, Oklahoma, Texas
and at the FERC outlined the expected company-wide benefits of the merger to AEP
and CSW customers and shareholders.
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FERC
On April 30, 1998, AEP and CSW jointly filed a request with the FERC for
approval of their proposed merger.
On May 25, 1999, AEP and CSW announced they had reached a settlement with
the FERC trial staff resolving competition and rate issues relating to the
proposed merger. On July 13, 1999, AEP and CSW reached an additional settlement
with the FERC trial staff resolving additional issues. The settlement has been
submitted to the FERC for approval.
Under the terms of the settlements, in June 1999 AEP filed with the FERC a
regional transmission organization proposal whereby it will transfer the
operation and control of AEP's bulk transmission facilities to an undetermined
independent system operator. The transmission facilities subject to this
commitment are located in Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia
and West Virginia.
The settlements also cover rates for transmission services and ancillary
services as well as resolving issues related to the system integration
agreement, the transmission reassignment tariff and the system transmission
integration agreement. The settlements confirm, subject to FERC guidance on
certain elements, that the proposed generation divestiture will satisfy the
market power concerns of the FERC staff. In their merger filing with the FERC,
AEP and CSW proposed divesting ownership of 300 MW of generation capacity at
PSO's Northeastern Power Station Units 3 and 4 in Oklahoma and 250 MW of
generation capacity at the Frontera power plant, a merchant plant being
constructed in Texas by a CSW subsidiary.
On June 28, 1999, AEP and CSW filed a motion asking the FERC to waive the
requirement for a post-hearing decision by the ALJ and consideration of the
matter by the FERC based on the hearing record and briefs. The FERC subsequently
issued an order requiring the ALJ to issue an initial decision as soon as
possible, but no later than November 24, 1999. The FERC order also set a
procedural schedule that should allow the FERC to issue a final order in the
first quarter of 2000.
AEP and CSW have reached settlements with the Missouri Public Service
Commission and various wholesale customers and intervenors in the FERC merger
proceeding.
Hearings at the FERC concluded July 19, 1999.
Arkansas
On June 12, 1998, AEP and CSW jointly filed a request with the Arkansas
Commission for approval of the proposed merger. The Arkansas Commission issued
an order approving the merger on August 13, 1998, subject to approval of the
associated regulatory plan. On December 17, 1998, the Arkansas Commission issued
a final order granting conditional approval of a stipulated agreement related to
a proposed merger regulatory plan. The stipulated agreement calls for SWEPCO to
reduce rates through a net merger savings rider for its Arkansas retail
customers by $6 million over the five-year period following completion of the
merger. The Arkansas Commission order notes the possibility of decisions in
other jurisdictions adversely affecting provisions of the stipulated agreement.
Consequently, the Arkansas Commission conditioned its final order on its
consideration of approval of the merger in other state and federal
jurisdictions.
Louisiana
On May 15, 1998, AEP and CSW jointly filed a request with the Louisiana
Commission for approval of the proposed merger and for a finding that the merger
is in the public interest.
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On September 27, 1999, the Louisiana Commission issued a final order
granting conditional approval of the pending merger between AEP and CSW. In
granting approval, the Louisiana Commission also approved a stipulated
settlement with the Louisiana Commission staff. Under the stipulated settlement,
AEP and CSW have agreed to share with SWEPCO's Louisiana customers merger
savings created as a result of the merger over the eight years following its
completion. A savings mechanism will be implemented to calculate merger savings
annually. AEP and CSW estimate that the customer rate credits in Louisiana will
total more than $18 million during that eight-year period. During the second
year following completion of the merger, customers will begin receiving a
monthly rate credit for 50% of calculated merger savings. This credit will be
updated annually and continue for the remainder of the eight-year period
following the merger's completion.
Oklahoma
On August 14, 1998, AEP and CSW jointly filed a request with the Oklahoma
Commission for approval of their proposed merger.
An amended application was filed with the Oklahoma Commission on February
25, 1999. On May 11, 1999, the Oklahoma Commission approved the proposed merger
between AEP and CSW. The approval follows a partial settlement between the
Oklahoma Commission Utility Division Staff, the Oklahoma Commission Consumer
Services Division, the Office of the Attorney General for Oklahoma, PSO, AEP and
CSW. The Oklahoma Commission order was appealed by the Municipal Electric
Systems of Oklahoma, Inc. and the Oklahoma Association of Electric Cooperatives.
On October 13, 1999, the Oklahoma Supreme Court dismissed the appeal of the
Oklahoma Association of Electric Cooperatives. The Oklahoma Association of
Electric Cooperatives filed a motion to dismiss its appeal of the Oklahoma
Commission order approving the merger.
Under the partial settlement agreement, AEP and CSW would: (i) share
merger savings with Oklahoma customers as well as AEP shareholders, effective
with the merger closing; (ii) not increase Oklahoma base rates prior to January
1, 2003; (iii) file by December 31, 2001 with the FERC an application to join a
regional transmission organization; and (iv) establish additional quality of
service standards for PSO's retail customers. Oklahoma's share of the $50.2
million in guaranteed net merger savings over the first five years after the
merger is consummated would be split between Oklahoma customers and AEP
shareholders, with customers receiving approximately 55% of the savings.
The Oklahoma Commission has withdrawn its opposition to the merger at the
FERC.
Texas
On April 30, 1998, AEP and CSW jointly filed a request with the Texas
Commission for a finding that the merger is in the public interest.
On May 4, 1999, AEP and CSW announced a proposed settlement with several
intervenor groups for the proposed merger between AEP and CSW. The settlement
would result in combined rate reductions totaling $221 million over a six-year
period for Texas customers of the three CSW Texas electric operating companies
(CPL, SWEPCO and WTU) if the merger is completed as planned and issues are
resolved associated with CPL, SWEPCO and WTU rate and fuel reconciliation
proceedings.
The settlement was reached with the General Counsel of the Texas
Commission, the State of Texas, the Texas Industrial Energy Consumers, the Low
Income Intervenors, the Office of Public Utility Counsel of Texas and the
steering committee of the cities of McAllen, Corpus Christi, Victoria, Abilene,
Big Lake, Vernon and Paducah. The settlement expands upon a previous Texas
settlement announced on November 12, 1998, with the Office of Public Utility
Counsel of Texas and the cities' steering committee. That prior settlement
agreement provided for Texas retail rate reductions of $180 million over the six
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years following completion of the merger. The new settlement agreement proposes
additional rate reductions totaling $41 million for a total of $221 million. The
settlement also calls for the divestiture of a total of 1,604 MW of existing and
proposed generating capacity within Texas.
The first rate-reduction rider provides for $84.4 million in net-merger
savings. The amounts are to be credited to Texas customers' bills through a
net-merger-savings rate-reduction rider over six years following completion of
the merger.
Additional rate-reduction riders will be implemented to resolve issues
associated with CPL, WTU and SWEPCO rate and fuel reconciliation proceedings and
court appeals in Texas. The settlement provides for an additional reduction of
$136.6 million, which will be implemented over the six years following
completion of the merger.
Hearings on the merger in Texas began August 9, 1999 and concluded on
August 10, 1999. As the hearings began, settlements were reached with all but
one of the parties in the case. The settling parties are all wholesale electric
customers of the three CSW Texas electric operating companies, and the
settlements call for the withdrawal of their opposition to the merger in all
regulatory approval proceedings. On October 1, 1999, an ALJ for the Texas State
Office of Administrative Hearings issued a proposal for decision recommending
that the Texas Commission approve the pending merger between AEP and CSW. In the
proposal for decision, the ALJ determined that, consistent with the terms of the
proposed settlement, the merger is in the public interest. On November 2, 1999,
the Texas Commission approved the proposed merger with AEP.
NRC
On June 19, 1998, CPL filed a license transfer application with the NRC
requesting the NRC's consent to the indirect transfer of control of CPL's
interests in the NRC licenses issued for STP from CSW to AEP. CPL would continue
to own its 25.2% interest in STP, and CPL's name would remain on the NRC
operating license. On November 5, 1998, the NRC approved the license transfer
application with a condition that the merger must be completed by December 31,
1999. CPL will request an extension for a license transfer with the NRC in the
fourth quarter of 1999.
Other Federal
On October 13, 1998, AEP and CSW jointly filed an application with the SEC
for approval of the proposed merger. The SEC merger filing is similar to
requests currently pending before other jurisdictions and outlines the expected
combined company benefits of the merger to AEP and CSW customers and
shareholders. AEP and CSW have filed several amendments to the application.
Several parties have filed petitions opposing the proposed merger at the SEC. On
July 23, 1999, AEP and CSW filed a brief in response to the intervenor petitions
at the SEC. AEP and CSW will file an amendment to the application in the fourth
quarter of 1999.
On July 29, 1999, applications were made with the FCC to authorize the
transfer of control of licenses of several CSW entities to AEP. The granting of
such authority is expected by the end of 1999 and will be effective upon
completion of the proposed merger.
On July 26, 1999, AEP and CSW submitted filings to the Department of
Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. On
August 26, 1999, AEP and CSW received a request for additional information from
the Department of Justice. AEP and CSW plan to file the additional information
with the Department of Justice in the fourth quarter of 1999.
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United Kingdom
CSW has a 100% interest in SEEBOARD and AEP has a 50% interest in
Yorkshire. The proposed merger of CSW into AEP would result in common ownership
of the United Kingdom entities. Although the merger of CSW into AEP is not
subject to approval of United Kingdom regulatory authorities, the common
ownership of the United Kingdom entities could be referred by the United Kingdom
Secretary of State for Trade and Industry for an investigation by the United
Kingdom Competition Commission. CSW is unable to predict the ultimate outcome of
any such regulatory proceeding.
AEP
On April 20, 1999, AEP reached a settlement with the Indiana Utility
Regulatory Commission staff addressing matters pertinent to Indiana regarding
the proposed merger. The Indiana Utility Regulatory Commission approved the
settlement on April 26, 1999. The settlement agreement resulted from an
investigation of the proposed merger between AEP and CSW initiated by the
Indiana Utility Regulatory Commission.
On April 21, 1999, AEP and CSW announced that they had reached separate
settlements with six wholesale customers that address issues related to the
proposed merger.
On April 28, 1999, AEP and CSW announced that they ratified a settlement
agreement with local unions of the IBEW representing employees of AEP and CSW.
The settlement agreement covered issues related to the pending merger between
AEP and CSW. As part of the settlement, the IBEW local unions have withdrawn
their opposition to the merger.
On May 26, 1999, AEP and CSW announced that it had reached a settlement
agreement with the Kentucky Attorney General and several AEP customers in
Kentucky addressing matters pertinent to Kentucky regarding the pending merger
between AEP and CSW. The Kentucky Public Service Commission has approved the
settlement.
On August 6, 1999, AEP announced that they ratified a settlement agreement
with local unions of the UWUA representing employees of AEP. The settlement
agreement covered issues raised in the pending merger between AEP and CSW. As
part of the settlement, the UWUA local unions will not oppose the merger.
On October 21, 1999, the Public Utility Commission of Ohio issued a
decision stating that it will notify the FERC that it is no longer opposed to
AEP's proposed merger with CSW and that it will no longer seek conditions on the
merger.
Completion of the Merger
AEP and CSW have targeted consummation of the AEP Merger to occur in the
second quarter of 2000. The merger is conditioned, among other things, upon the
approval of several state and federal regulatory agencies. The transaction must
satisfy many conditions, including the condition that it must be accounted for
as a pooling of interests. The parties may not waive some of these conditions.
AEP and CSW have initiated the process of seeking regulatory approvals, but
there can be no assurance as to when, on what terms or whether the required
approvals will be received or whether there will be any regulatory proceedings
in the United Kingdom. After December 31, 1999, either CSW or AEP may terminate
the merger agreement if all of the conditions to its obligation to close have
not been satisfied, provided that either party may extend the merger agreement,
under certain circumstances, through June 30, 2000. There can be no assurance
that the AEP Merger will be consummated.
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Merger Costs
As of September 30, 1999, CSW had deferred $38.6 million in costs related
to the AEP Merger on its consolidated balance sheet, which will be charged to
expense if AEP and CSW are not successful in completing their proposed merger.
RECENT DEVELOPMENTS AND TRENDS
Industry restructuring and legislative initiatives in the U.S. Congress
Several bills have been introduced in the 106th U.S.Congress which provide
for the restructuring and/or deregulating of the electric utility industry. Most
of the bills seek to clarify state authority to mandate retail choice, repeal
the Holding Company Act, repeal prospectively the Public Utility Regulatory
Policies Act of 1978, expand FERC authority over public power entities, address
transmission reliability, and other issues. Recently, HR 2944 "The Electricity
Competition and Reliability Act" was reported by the House Commerce Subcommittee
on Energy and Power on October 27, 1999. Among other provisions, if enacted, the
legislation would repeal the Holding Company Act twelve months after the bill is
signed into law and clarifies that states have the authority to order retail
competition without a federal mandate. Management cannot predict the ultimate
outcome of any legislative initiatives.
Industry Restructuring Legislation in Texas, Louisiana, Oklahoma and
Arkansas
Several initiatives to restructure the electric utility industry and enact
retail competition have been undertaken in the four states in which the U.S.
Electric Operating Companies operate. Legislation was enacted in Oklahoma in
1997 and 1998, and in Texas and Arkansas in 1999. CSW will make business
unbundling plan filings in Texas and Arkansas in the first quarter of 2000 as
required by the legislation. Legislative activity in Louisiana has, to date,
stopped short of any such definitive action.
Oklahoma
In 1997, the Oklahoma Legislature passed restructuring legislation
providing for retail access by July 1, 2002. That legislation called for a
number of studies to be completed on a variety of restructuring issues,
including independent system operator issues, technical issues, financial
issues, transition issues and consumer issues. The study on independent system
operator issues was completed in January 1998.
In 1998, the Oklahoma Legislature passed Senate Bill 888, which
accelerated the schedule for completion of the remaining studies to October
1999. Those studies were conducted under the direction of the Legislative Joint
Electric Utility Task Force, rather than by the Oklahoma Commission as the
previous legislation required. The task force organized the study effort into
several working groups, which were directed to evaluate assigned issues. On
October 1, 1999, the task force completed its report to the Oklahoma Legislature
based on the work performed by these working groups. The report primarily is a
compilation of the positions taken by the various parties participating in the
working groups. The information in the report is expected to be used in the
development of additional industry legislation during the 2000 legislative
session. Management is unable to predict the ultimate impact of the report or
the effects of any 2000 industry restructuring legislation on the results of
operations and financial condition of CSW and PSO.
Louisiana
In 1998, a special legislative committee created by the Louisiana Senate
studied the impact of retail competition on the state of Louisiana. No
legislation has been enacted as a result of that effort. In addition, during
1998 and 1999, the Louisiana Commission conducted a proceeding to study
restructuring and retail competition. Since the Louisiana Commission is a
constitutionally created body, it can implement industry restructuring on its
own without additional legislation. Parties submitted comments, and hearings
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were held on a number of specific restructuring topics. Also, as a part of that
proceeding, utilities filed rate unbundling information with the Louisiana
Commission staff.
As a result of that proceeding, the Louisiana Commission staff released
its report on industry restructuring, including its recommendations regarding
retail competition in Louisiana. In its report, the Louisiana Commission staff
recommended that electric industry restructuring should not proceed at this time
because it is not in the public interest. However, the Louisiana Commission
staff proposed a restructuring plan as an alternative, in the event the
Louisiana Commission decides to move forward with the electric industry
restructuring and retail competition. The Louisiana Commission voted to begin
additional study and analysis of the issues associated with restructuring and
has adopted a procedural schedule that will result in a final restructuring plan
by January 1, 2001.
Other
Management cannot predict the ultimate outcome of the initiatives
concerning restructuring and retail competition in Arkansas, Louisiana, Texas
and Oklahoma, or their ultimate impact on the results of operations, financial
condition, or competitive position of CSW and the U.S. Electric Operating
Companies.
The foregoing discussion constitutes forward-looking information within
the meaning of Section 21E of the Exchange Act. Actual results may differ
materially from such projected information. See FORWARD -LOOKING INFORMATION.
SEEBOARD Third Party Pension Litigation
In the U.K., National Grid Group and National Power have been involved in
continuing litigation regarding their use of actuarial surpluses set forth in
the electricity industry's occupational pension plan, the ESPS. A High Court
decision in favor of the National Grid Group and National Power was appealed. On
February 10, 1999, the U.K. Court of Appeal ruled that the particular
arrangements made by these corporations to dispose of part of the surplus were
invalid due to procedural defects. This decision was confirmed at a later
hearing of the U.K. Court of Appeal held in May 1999, although an opportunity
for an appeal to be taken to the House of Lords, the highest court of appeal in
the U.K., was granted.
SEEBOARD employees are members of the ESPS, and SEEBOARD has made similar
use of its actuarial surplus. As a result of subsequent legal clarification of
certain issues arising from the hearing held in May 1999, the potential impact
of the ruling on SEEBOARD has increased. The amount of the payments cancelled by
SEEBOARD, both for past and future liabilities, amounts, in the aggregate, to
approximately $78 million, excluding interest.
The U.K. Court of Appeal did not order the National Grid Group or National
Power to make payment into the ESPS, and the court indicated that any
requirement to make such payments would be extreme since the ESPS already is in
surplus. In the event that the court finally decides a payment by SEEBOARD into
the ESPS is necessary, such a payment is likely to create additional pension
fund surplus, which the company should then be able to utilize over the next
several years to reduce pension expense.
The National Grid Group has indicated its intention to appeal to the House
of Lords. The final outcome of this appeal cannot presently be determined.
Management is unable currently to predict the amount of any payment that it may
be required to make to ESPS or the effect, if any, of the ultimate outcome of
the appeal on CSW's results of operations and financial condition.
The foregoing discussion constitutes forward-looking information within
the meaning of Section 21E of the Exchange Act. Actual results may differ
materially from such projected information. See FORWARD -LOOKING INFORMATION.
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RATES AND REGULATORY MATTERS
Electric Utility Restructuring Legislation
On June 18, 1999, legislation was signed into law in Texas that will
restructure the electric utility industry in the state. The new law, among other
things: gives Texas customers of investor-owned utilities the opportunity to
choose their electric provider beginning January 1, 2002; provides for the
recovery of stranded costs which are defined as the excess of net book value of
generation assets over the defined market value of those assets; requires
reductions in nitrogen oxide and sulfur dioxide emissions; provides a rate
freeze until January 1, 2002 followed by a 6% rate reduction for residential and
small commercial customers, additional rate reduction for low income customers
and a number of customer protections and sets certain limits on capacity owned
and controlled by power generation companies. Rural electric cooperatives and
municipal electric systems can choose whether to participate in retail
competition. Delivery of the electricity will continue to be the responsibility
of the local electric transmission and distribution utility company at regulated
prices. Each utility must unbundle its business activities into a retail
electric provider, a power generation company and a transmission and
distribution utility. CPL, SWEPCO and WTU will file their business separation or
"unbundling" plans with the Texas Commission in January 2000.
During 1999, legislation was also enacted in Arkansas that will ultimately
restructure the electric utility industry in that state. SWEPCO will file a
business unbundling plan in Arkansas in the first quarter of 2000 as required by
the legislation.
The financial statements of the U.S. Electric Operating Companies have
historically reflected the effects of applying the requirements of SFAS No. 71.
Pursuant to those requirements, the U.S. Electric Operating Companies have
recorded regulatory assets and liabilities (probable future revenues and
refunds) to reflect the economic effect of cost-based regulation. When a company
determines that its operations or a segment of its operations no longer meets
the criteria for applying SFAS No. 71, it is required to apply the requirements
of SFAS No. 101. Pursuant to those requirements and further guidance provided in
EITF 97-4, a company is required to write off regulatory assets and liabilities
related to deregulated operations, unless recovery of such amounts is provided
through rates to be collected in a continuing regulated portion of the company's
operations. Additionally, it is required to determine if any plant assets are
impaired under SFAS No. 121.
As a result of the scheduled deregulation of generation in Texas and
Arkansas, CSW has concluded that it should discontinue the application of SFAS
No. 71 for the Texas generation portion of the business for CPL and WTU and the
Texas and Arkansas jurisdictional portions of the generation business for
SWEPCO. Consequently, WTU recorded an extraordinary charge to earnings of $5.5
million and SWEPCO recorded an extraordinary charge to earnings of $3.0 million
to reflect the effects of discontinuing the application of SFAS No. 71 and to
write off net of regulatory assets that are not probable of recovery.
The discontinuance of SFAS No. 71 for CPL did not result in a net charge
to earnings as such net regulatory assets, pursuant to the legislation, are
expected to be recovered from transmission and distribution customers through
rates that will continue to be regulated.
Electric utilities under the Texas Legislation are allowed to recover
generation-related regulatory assets and stranded costs that otherwise may not
be recoverable in the future competitive market. All or a majority of those
costs can be refinanced through securitization, which is a financing designed to
provide lower financing costs than is available through the conventional utility
cost of capital model. The securitized amounts are then recovered through a
non-bypassable charge. On October 18, 1999, CPL filed an application with the
Texas Commission to securitize approximately $1.27 billion of its retail
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generation-related regulatory assets and approximately $47 million in other
qualified costs. If approval is received from the Texas Commission, CPL expects
to issue the securitization bonds in March or April 2000, depending on market
conditions and the timing of an order from the Texas Commission. A second phase
of securitization relating to additional plant related stranded costs should
occur in 2001 depending upon market conditions, timing and Texas Commission
approvals. A non-bypassable charge may be used to recover additional
unsecuritized stranded cost amounts.
Under the provisions of EITF 97-4, CPL's generation-related net regulatory
assets were transferred to the transmission and distribution portion of the
business and will be amortized as they are recovered through charges to
customers. Management currently believes all regulatory and stranded costs
related to generation assets for CPL will be recovered as provided under Texas
Legislation. CPL believes it will have stranded costs related to its generation
assets in excess of the $1.27 billion of costs contained in its securitization
filing made with the Texas Commission on October 18, 1999. If future events were
to occur that made the recovery of these assets no longer probable, CPL would
write off any non-recoverable portion of such assets as a non-cash charge to
earnings. CPL's amount of regulatory assets and stranded costs are subject to a
final determination by the Texas Commission in 2004. The Texas Legislation
provides that all such finally determined stranded costs will be recovered.
Since SWEPCO and WTU are not expected to have net stranded costs, all
generation-related non-recoverable net regulatory assets were written off and
reflected on the statement of income as an extraordinary item.
Additionally, CPL, SWEPCO and WTU performed an accounting impairment
analysis of generation assets under SFAS No. 121 at September 30, 1999 and
concluded there was no impairment of generation assets at this time. An
impairment analysis involves estimating future net cash flows arising from the
use of an asset. If the net cash flows exceed the net book value of the asset,
then there is no impairment of the asset for accounting purposes. CPL, SWEPCO
and WTU will continue to review their assets for potential impairment if events
or changes in circumstances indicate the carrying amount of an asset may not be
recoverable.
The Texas Legislation also provides that each year during the 1999 through
2001 rate freeze period, utilities with stranded costs are required to apply any
earnings in excess of the most recently approved cost of capital in a company's
last rate case (if issued on or after January 1, 1992) to reduce stranded costs.
As a result, CPL recorded a net charge to earnings of $4.6 million to reflect
the impact of this provision. Utilities without stranded costs must either flow
such amounts back to customers or make capital expenditures, at no charge to
customers, to improve transmission or distribution facilities or to improve air
quality. As a result, WTU recorded a charge to earnings of $6.4 million from the
effect of the earnings cap under the Texas Legislation. The charges were based
on estimates for the current year and are subject to final determination by the
Texas Commission. Following CPL's discontinuation of SFAS No. 71, it is expected
that any future excess earnings will only be applied to reduce stranded costs
for regulatory purposes.
The discontinuance of SFAS No. 71 for CPL's and WTU's Texas generation
business and SWEPCO's Texas and Arkansas generation business requires that these
businesses no longer defer costs or recognize liabilities strictly resulting
from the actions of a regulator. For example, operations and maintenance
expenditures will be expensed as incurred regardless of regulatory treatment. In
addition, the equity component of allowance for funds used during construction
can no longer be accrued for generation-related capital projects. Instead, the
businesses will be required to follow the interest capitalization rules in SFAS
No. 34.
CSW continues to analyze the impact of the electric utility industry
restructuring legislation on the U.S. Electric Operating Companies. The Texas
Commission has established numerous task forces, including representatives from
CPL, SWEPCO and WTU, to address various issues associated with the Texas
Legislation and to provide guidance regarding implementation of restructuring.
Based on the overall framework and objective of the Texas Legislation regarding
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recovery of stranded costs and regulatory assets, and additional guidance
obtained through participation in various task force workshop sessions, certain
adjustments were recorded by CSW in the third quarter of 1999 to recognize the
estimated effect of the legislation. CSW also recorded certain adjustments for
the Arkansas jurisdictional portion of SWEPCO's generation business as a result
of legislation enacted in Arkansas.
As previously discussed, as a result of the Texas Legislation, CPL filed
its application for securitization on October 18, 1999 with the Texas
Commission. CPL, SWEPCO and WTU expect to make additional filings with the Texas
Commission for business separation plans in January 2000, earnings cap reports
in March 2000, cost unbundling plans in April 2000 and the ECOM reports in April
2000.
The foregoing discussion constitutes forward-looking information within
the meaning of Section 21E of the Exchange Act. Actual results may differ
materially from such projected information. See FORWARD -LOOKING INFORMATION.
Also see ITEM 2. MD&A - RECENT DEVELOPMENTS AND TRENDS, Texas for a
discussion on legislation.
CPL Rate Review - Docket No. 14965
In November 1995, CPL filed with the Texas Commission a request to
increase its retail base rates by $71 million. On October 16, 1997, the Texas
Commission issued the CPL 1997 Final Order. The CPL 1997 Final Order lowered the
annual retail base rates of CPL by approximately $19 million or 2.5% from CPL's
rate level existing prior to May 1996. The Texas Commission also included a
"glide path" rate reduction methodology in the CPL 1997 Final Order pursuant to
which CPL's annual rates would be reduced by $13 million on May 1, 1998 and an
additional $13 million on May 1, 1999.
CPL filed an appeal of the CPL 1997 Final Order to the State District
Court of Travis County to raise several issues related to the rate case. The
primary issues include: (i) the classification of $800 million of invested
capital in STP as ECOM which was assigned a lower return on equity than non-ECOM
property; (ii) the Texas Commission's application of the "glide path" rate
reduction methodology applied on May 1, 1998 and May 1, 1999; and (iii) the $18
million of disallowed affiliate expenses from CSW Services. As part of the
appeal, CPL sought a temporary injunction to prohibit the Texas Commission from
implementing the "glide path" rate reduction methodology. The court denied the
temporary injunction, and the "glide path" rate reductions were implemented in
May 1998 and May 1999. Hearings on the appeal were held during the third quarter
of 1998, and a judgment was issued in February 1999 affirming the Texas
Commission order, except for a consolidated tax issue in the amount of $6
million, which was remanded to the Texas Commission. CPL filed an appeal of this
most recent order to the Court of Appeals and management is unable to predict
how the final resolution of these issues will ultimately affect CSW's and CPL's
results of operations and financial condition. On May 4, 1999, AEP and CSW
announced that they had reached a stipulated agreement with the General Counsel
of the Texas Commission and other intervenors in the state of Texas related to
the AEP/CSW merger case. The Texas Commission approved the AEP Merger in early
November 1999. If the AEP Merger is ultimately consummated, CSW will withdraw
its appeal with respect to the "glide path" rate reduction methodology as
discussed above as issue "(ii)" but will continue seeking the appeal of issues
"(i) and (iii)" also discussed above.. See NOTE 5. PROPOSED AEP MERGER and ITEM
2. MD&A - PROPOSED AEP MERGER for a discussion on the stipulated agreement.
Also see ITEM 1 - NOTE 2. LITIGATION AND REGULATORY PROCEEDINGS, CPL Rate
Review Docket No. 14965 for a discussion of the CPL 1997 Final Order.
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SWEPCO Louisiana Rate Review
In December 1997, the Louisiana Commission announced it would review
SWEPCO's rates and service. The Louisiana Commission has selected consultants
and legal counsel to perform a review of SWEPCO's rates and charges and to
review SWEPCO's quality of service. The Louisiana Commission's legal counsel
issued a report in June 1999, reflecting a Louisiana revenue excess of $28
million. SWEPCO believed the report contained significant theoretical and
mathematical errors and filed its rebuttal testimony on August 10, 1999.
In October 1999, SWEPCO and the Staff of the Louisiana Commission reached
an Agreement and Stipulation, which was filed on October 14, 1999. In support of
the Agreement and Stipulation, supplemental testimony was also filed. The
provisions of the Agreement and Stipulation are:
- - SWEPCO's Louisiana retail jurisdictional revenues are reduced by $11
million, effective with the December 1999 billing cycle;
- - SWEPCO will be allowed to earn an 11.1% return on common equity;
- - SWEPCO will recover certain regulatory assets totaling $7.1 million;
- - SWEPCO will be subject to a two-year base rate freeze, which will be
subject to force majeure provisions and;
- - Increased depreciation rates for transmission, distribution and general
plant.
Hearings were held before an ALJ on October 19, 1999. To meet the December
1999 implementation date contemplated in the Agreement and Stipulation, an order
from the Louisiana Commission must be received in November 1999. The Louisiana
Commission is scheduled to vote on the Agreement and Stipulation at its November
17, 1999 meeting.
SWEPCO Arkansas Rate Review
In June 1998, the Arkansas Commission indicated that it would conduct a
review of SWEPCO's earnings. The review began in July 1998. SWEPCO entered into
a settlement with the general staff of the Arkansas Commission and the Arkansas
Attorney General's Office. The settlement was filed on July 30, 1999 and reduces
revenues $5.4 million or 3%. Additionally, the Stipulation and Settlement
Agreement provides for a 10.75% return on common equity, an increase in
depreciation rates, and an agreement by SWEPCO not to seek recovery of
generation related stranded costs.
On August 20, 1999, SWEPCO filed a Supplemental Stipulation and Settlement
Agreement, which was reached with the one remaining party. The Supplemental
Stipulation and Settlement Agreement did not alter or replace any of the
original monetary terms of the Stipulation and Settlement Agreement filed on
July 30, 1999.
On September 23, 1999, the Arkansas Commission issued an order approving
the Stipulation and Settlement Agreement and the Supplemental Stipulation and
Settlement Agreement. On October 25, 1999, SWEPCO filed compliance rate tariffs
with the Arkansas Commission, which are consistent with the Arkansas Commission
order. After review of the compliance rate tariffs by the Staff of the Arkansas
Commission, new rates will be implemented. SWEPCO anticipates implementing the
new rates with the December 1999 billing cycle.
Regulatory Draft Price Proposal for SEEBOARD
On October 8, 1999, OFGEM published its revised draft price proposals and
results from its current United Kingdom electricity distribution review. OFGEM
has recommended revenue reductions in SEEBOARD's distribution business. In
addition, OFGEM has proposed the reallocation of a further 12%, or $45 million
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of pre-tax costs out of SEEBOARD's distribution business into its supply
business. If adopted, these proposals would reduce net income for SEEBOARD in
the year 2000 by $40 million, and by $60 million on an annual basis, dependent
upon the level of further cost reductions that can be achieved. CSW's net income
from SEEBOARD USA, its United Kingdom business segment, was $95 million for the
twelve months ended September 30, 1999.
SEEBOARD continues to analyze the draft recommendations and their
potential effects on earnings and to seek a reduction in the severity of OFGEM's
proposed recommendations. SEEBOARD is also currently analyzing future potential
cost reductions that can partially mitigate the impact of these proposals. OFGEM
is expected to finalize its recommendations in early December 1999, which would
take effect in April 2000 for five years. SEEBOARD cannot predict whether the
draft price proposals ultimately will be adopted by OFGEM and, if they are
adopted, the final form of the proposals.
If OFGEM's draft price proposals for SEEBOARD ultimately were adopted
without change, implementation of the price proposals would have a material
adverse effect on the future results of operations of SEEBOARD USA and CSW. In
addition, implementation of the price proposals as drafted could adversely
affect the financial condition of SEEBOARD USA, but would not be expected to
adversely affect the financial condition of CSW.
OFGEM has published draft price proposals for the electricity supply
businesses. OFGEM has recommended that the price cap for charges levied to
electricity supply domestic and small business customers should be extended for
two years from April 2000. If adopted, the proposals are expected to have a
broadly neutral effect on the results of SEEBOARD USA.
The foregoing discussion constitutes forward-looking information within
the meaning of Section 21E of the Exchange Act. Actual results may differ
materially from such projected information. See FORWARD -LOOKING INFORMATION.
Other
Reference is made to NOTE 2 LITIGATION AND REGULATORY PROCEEDINGS for
information regarding fuel proceedings at CPL, SWEPCO and WTU.
ENVIRONMENTAL
Clean Air Provisions of the Texas Legislation
The Texas Legislation requires that grandfathered electric generating
facilities be permitted, reduce emission levels 50% and provide for a cost
recovery mechanism for companies with stranded costs. Final regulations are
expected by January 1, 2000. The total costs to comply with the expected
regulations for CPL, SWEPCO and WTU are expected to range from $3 million to $10
million. Expenditures at the high end of the range are estimated to be $4.2
million for CPL, $4.8 million for SWEPCO and $1.0 million for WTU. Expenditures
have begun to meet the requirements of the legislation. Although CPL could seek
recovery of these costs, there is no mechanism for SWEPCO and WTU to recover
these costs under the Texas Legislation.
Proposed Regional Control Strategy Regulations
The Texas Natural Resource Conservation Commission is expected to release
for comment proposed regulations that, if adopted as proposed, would require
reductions in nitrogen oxide emissions for existing permited electric generating
facilities in the East Texas Region in addition to the Clean Air Provisions of
the Texas Legislation discussed above. The final regulations could be issued in
April 2000 with an implementation date of May 2003. The current estimate for
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compliance with the proposed rules could be as much as $38 million for CPL and
$151 million for SWEPCO in capital project costs and as much as $3 million for
CPL and $11 million for SWEPCO in additional annual operating costs.
The foregoing discussion constitutes forward-looking information within
the meaning of Section 21E of the Exchange Act. Actual results may differ
materially from such projected information. See FORWARD -LOOKING INFORMATION.
DIVERSIFIED ELECTRIC
CSW Energy
CSW Energy presently owns interests in seven operating power projects
totaling 1,308 MW which are located in Colorado, Florida and Texas. CSW Energy
began construction in August 1998 of a 500 MW merchant power plant, known as
Frontera, in the Rio Grande Valley, near the city of Mission, Texas. The natural
gas-fired facility began simple cycle operation of 330 MW in July 1999 and is
scheduled to commence combined cycle operation by the end of 1999. Pursuant to
AEP's and CSW's stipulated agreement with several intervenors in the state of
Texas related to the AEP Merger, CSW Energy will sell 250 MW of Frontera upon
completion of the merger. See ITEM 1. - NOTE 5. PROPOSED AEP MERGER and
MD&A-PROPOSED AEP MERGER for a discussion including timing of the sale.
CSW Energy has entered into an agreement with Eastman Chemical Company to
construct and operate a 440 MW cogeneration facility in Longview, Texas. This
facility will be known as the Eastex Cogeneration Project. Construction of the
facility is scheduled to begin in the fourth quarter of 1999, with expected
operation in 2001. Excess electricity generated by the plant will be sold by CSW
Energy in the wholesale electricity market. Since Eastex will be built as a
qualifying facility, CSW Energy will be required to sell 50% of the plant prior
to commercial operation.
In addition to these projects, CSW Energy has other projects in various
stages of development.
In October 1999, GE Capital Structured Finance Group purchased 50
percent of the equity ownership of Sweeny Cogeneration Limited Partnership. CSW
Energy's after-tax earnings from the proceeds of the transaction will be
approximately $33 million and will be recorded in the fourth quarter of 1999.
The agreement between CSW Energy and GE Capital Structured Finance Group also
provides for additional payments subject to completion of a planned expansion of
the Sweeny cogeneration facility.
The preceding discussion contains forward-looking information within the
meaning of Section 21E of the Exchange Act. Actual results may differ materially
from such projected information. See FORWARD-LOOKING INFORMATION.
CSW International
CSW International was organized to pursue investment opportunities in EWGs
and FUCOs and currently holds investments in the United Kingdom, Mexico and
South America.
CSW International and its 50% partner, Scottish Power plc, have entered
into a joint venture to construct and operate the South Coast power project, a
400-MW combined cycle gas turbine power station in Shoreham, United Kingdom. CSW
International has guaranteed approximately (pound)19 million of the (pound)190
million construction financing, and the permanent financing is unconditionally
guaranteed by the project. Construction of the project began in March 1999 and
commercial operation is expected to begin in 2000.
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Through June 30, 1999, CSW International had purchased a 36% equity
interest in Vale for $80 million. CSW International also extended $100 million
of debt to Vale. CSW International anticipates converting $69 million of the
$100 million to equity by the end of 1999, with the remaining $31 million to be
converted over the next two years. Currently, CSW International accounts for its
$80 million investment in Vale on the equity method of accounting, and the $100
million of debt as a loan.
In mid-January 1999, amid market instability, the Brazilian government
abandoned its policy of pegging the Brazilian Real in a broad range against the
dollar. This action resulted in a 60% devaluation of the Brazilian currency by
the end of September 1999. Vale is unfavorably affected by the devaluation due
primarily to the revaluation of foreign denominated debt.
CSW International has a put option, which, if exercised, requires Vale to
purchase CSW International shares at a minimum price equal to the purchase price
for Vale. As a result of the put option arrangement, management has concluded
that CSW International's investment carrying amount will not be reduced below
the put option value unless there is deemed to be a permanent impairment.
Pursuant to the put option arrangement, CSW International will not recognize its
proportionate share of any future earnings until its proportionate share of any
losses of Vale are recognized. At September 30, 1999, CSW International had
deferred losses, after tax, of approximately $23 million related to its Vale
investment. CSW International views its investment in Vale as a long-term
investment, which has significant long-term value. Management will continue to
closely evaluate the changes in the Brazilian economy and its impact on CSW
International's investment in Vale.
As of September 30, 1999, CSW International had invested $110 million in
stock of a Chilean electric company. The investment is classified as securities
available for sale and accounted for by the cost method. Based on the market
value of the shares and foreign exchange rates, the value of the investment at
September 30, 1999 is $62 million. The reduction in the carrying value of this
investment has been reflected in Other Comprehensive Income in CSW's
Consolidated Statements of Stockholders' Equity. Management views its investment
in Chile as a long-term investment strategy and believes this investment
continues to have significant long-term value and that it is recoverable.
Management will continue to closely evaluate the changes in the South American
economy and its impact on CSW International's investment in the Chilean electric
company.
In addition to these projects, CSW International has other projects in
various stages of development.
The preceding discussion contains forward-looking information within the
meaning of Section 21E of the Exchange Act. Actual results may differ materially
from such projected information. See FORWARD-LOOKING INFORMATION.
OTHER MATTERS
Year 2000
On a system-wide basis, CSW initiated a year 2000 project to prepare
internal computer systems and applications for the year 2000. These systems and
applications include management information systems that support business
operations such as customer billing, payroll, inventory and maintenance. Other
systems with computer-based controls such as telecommunications, elevators,
building environmental management, metering, plant, transmission, distribution
and substations are included in this project as well.
CSW considers year 2000 readiness a top priority. The formal project was
initiated in late 1996 at which time an executive sponsor and project manager
were named and a centralized project management office was formed. More than 30
readiness teams were initiated and they have completed the readiness activities
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for critical systems. Those teams represent the equivalent of about 90 full-time
employee positions working on year 2000 readiness. The teams used a formal
approach that included inventory, assessment, remediation, testing of systems
and development of contingency plans. Formal progress checkpoints continue on a
biweekly basis. An executive oversight council comprised of the functional vice
presidents continues to convene monthly to review progress and address issues.
The project executive sponsor provides updates to top management on a weekly
basis and at every Board of Directors' Audit Committee meeting.
CSW completed a comprehensive review of its year 2000 project in 1998.
External consultants assisted in the review. The review covered assessment of
the project plans and processes to ensure that any risks to CSW associated with
the year 2000 would be prudently managed. Several changes were incorporated into
the year 2000 project as a result of the 1998 review findings. After completing
the year 2000 readiness processes on all critical systems in June 1999, the
internal audit and project management teams reviewed the remediation and testing
process, continuing readiness processes, and the contingency plans. The
post-review was conducted to determine if year 2000 related risks had been
mitigated. The review findings indicated that risk had been mitigated, solid
processes were in place to maintain readiness, and the contingency plans would
minimize the impact of any year 2000 computer problems.
State of Readiness
Key milestones for the CSW system-wide year 2000 program, excluding
SEEBOARD and Vale, are listed below:
- - Readiness teams completed a detailed inventory and assessment of critical
control systems in the third quarter of 1998. The systems include
switchboards, elevators, environmental controls, vehicles, metering systems,
and embedded logic or real time control systems in support of generation and
delivery of electricity. The findings indicate that less than 15% of
installed controls have microprocessors, very few have date logic and over
90% of those with date logic already process new millennium dates correctly.
The need for additional functionality in the early 1990's resulted in the
modernization of several electric operation systems that has reduced the
conversion requirements. On June 2, 1999, CSW announced that it completed
year 2000 readiness activities within its critical power production and
delivery systems at the U.S. Electric Operating Companies.
- - Readiness teams completed inventory and assessment of business applications
and vendor-supplied software in the first quarter of 1997. Only 25% of the
business application programs were determined to require remediation by
December 1999.
- - Readiness teams completed plans for modification and certification testing of
business application software in the third quarter of 1997.
- - Readiness teams established and initiated remediation plans and schedules for
business applications in the fourth quarter of 1997. As of June 30, 1999,
these teams had converted and certified all business critical applications of
the U.S. Electric Operating Companies and shared services organizations.
SEEBOARD completed an inventory of date dependent assets including, but
not limited to, embedded chip technology, software, hardware, applications,
telecommunications, access and security systems in the third quarter of 1998.
SEEBOARD completed an assessment of all critical systems in January 1999.
SEEBOARD completed remediation and testing of mission critical distribution and
safety systems in March 1999. SEEBOARD completed the remediation and testing of
all critical path systems in August 1999.
84
<PAGE>
Vale completed an inventory of date dependent assets and critical systems
in the fourth quarter of 1998. As of June 30, 1999, Vale had also completed the
remediation and testing of all critical systems. Vale also completed contingency
plans for its critical systems in the third quarter of 1999.
Cost to Address Year 2000 Issues
A combination of internal and external resources perform the work related
to the year 2000 project. CSW's budget includes the funds for year 2000 project
expenditures. The costs related to the project are expensed as incurred. As of
September 30, 1999, cost incurred to date for the year 2000 project amounts to
$27 million, including $17 million in the first nine months of 1999. Remaining
activities are expected to cost an additional $9 million over the next 6 months.
Redeployment of existing labor resources accounts for approximately 40% of the
project cost. Outside contract labor makes up approximately 35% of the project
cost. Computer hardware and software purchases account for the remaining 25% of
the project cost.
In the first quarter of 1999, a software version upgrade to provide
contract management features to the materials management information system was
deferred until calendar year 2000 in order to minimize risk. The financial
impact of this deferral is minimal, as minor enhancements to the current design
have provided an alternative, interim solution for the needed functionality. No
other planned CSW computer information system projects have been affected by the
year 2000 project, but that may change as the year 2000 approaches and change
freezes are implemented to further minimize risk. Accordingly, no estimate has
been made for the financial impact of any future projects foregone due to
resources allocated to the year 2000 project.
Risk of Year 2000 Issues
The greatest financial risk to the CSW domestic operation would be a total
inability to generate and deliver electricity. Many primary systems and backup
systems would have to fail in order for that total inability to occur.
On May 31, 1999, CSW completed year 2000 readiness activities within its
critical power production and delivery systems at its U.S. Electric Operating
Companies and no year 2000 issues were found that would have caused power plants
to fail. Risk of power plant failure is limited because 50% of power plant
controls do not operate with date sensitive logic. Additionally, the year 2000
issues, which were identified in the plants, are generally minor issues
typically affecting reporting systems.
The vast majority of the transmission and distribution system consists of
wires, poles, transformers, switches and fuses for which year 2000 is not an
issue. Fewer than 15% of control systems that operate transmission and
distribution equipment are micro-processor based, and of those, 95% were found
to process year 2000 dates correctly. The standard residential meter is not
affected; however, about 10% of industrial and large commercial meters have
microprocessors. Most of those microprocessors process dates correctly and those
that did not have been modified and certified year 2000 ready.
The systems that required the greatest amount of work are the software
applications that support business functions such as customer billing and
accounting. CSW completed all year 2000 readiness activities on these critical
business support systems on June 30, 1999.
If CSW's domestic operations encountered a total inability to generate and
deliver electricity, CSW estimates that it would lose approximately 24 hours of
revenues and would incur additional costs to restart power plants in a worst
case scenario.
The greatest risk to SEEBOARD is that it is part of a large supplier
chain. While SEEBOARD is confident of its ability to ensure that there will be
no year 2000 impact to the distribution network, it is reliant upon both the
generators and the National Grid in the U.K. However, the risk is considered
minimal.
85
<PAGE>
To date at SEEBOARD, the year 2000 testing on embedded chip technology
revealed a less than 2% failure rate.
Contingency Plans
Contingency plans have been in place in CSW's domestic electric operation
for years to address problems resulting from weather. These plans have been
updated to include year 2000 issues. Contingency planning is engineered into the
transmission and distribution systems as it is designed with the capability to
bypass failed equipment. A margin of power generation reserve above what is
needed is normally maintained. This reserve is a customary operating contingency
plan that allows CSW to operate normally even when a power plant unexpectedly
quits operating. Backup supplies of fuels are normally maintained at CSW power
plants. Natural gas plants have fuel oil as a backup and multiple pipelines
provide redundant supplies. At coal plants about 40-45 days of extra coal is
kept on hand.
The North American Electric Reliability Council has coordinated with all
national power regions to assess the risks and to develop contingency plans
within the national electric delivery system. During the fourth quarter of 1998,
CSW developed first drafts of the contingency plans to address year 2000 issues.
These contingency plans were completed in the second quarter of 1999. CSW
participated in an industry-wide drill focused on sustaining reliable operations
with a simulated partial loss of voice and data communications on April 9, 1999.
The drill results clearly demonstrated CSW's ability to successfully sustain
reliable operations while using backup or alternative communication means.
Additionally, CSW participated in an industry-wide drill to test its operational
preparedness in the third quarter of 1999. This drill was a rehearsal of
December 31, 1999 and January 1, 2000 operations and further validated the
contingency plans and communication and coordination processes. Another drill is
planned for the mid-November 1999 time frame to help ensure the communication
and coordination processes are effective before transition to the new
millennium.
The CSW supply chain has contacted over 6,000 suppliers to determine their
organization readiness and over 70% responded. Approximately 250 of those 6,000
are mission critical suppliers, of which 100% have responded that their
organizations are either ready for the year 2000 or will be before December 31,
1999. Contingency plans have been developed to cover the possible failure of any
critical suppliers that may not achieve their readiness goals on time.
Additionally, mission critical inventories will be increased.
Like CSW's U.S. operations, SEEBOARD also has contingency plans that have
been in place for years to address problems resulting from weather. These plans
are covered effectively within the distribution and customer service business
areas and are being updated to include year 2000 scenarios. Each service
provider group within SEEBOARD has presented its plans for coverage over the
millennium period to the rest of the organization. The business contingency
planners appointed within each business are now incorporating this information
in the business continuity plans. These plans are continually being reviewed by
SEEBOARD's year 2000 central team. SEEBOARD is working with other utilities
through interest groups and the national grid on interface contingency plans and
testing. In addition to contingency plans, business areas are identifying key
tasks that will be performed during the year-end roll-over period to ensure
continuity of business.
In view of a pending merger, the CSW and AEP year 2000 project management
teams engage in frequent communication to share best practices and to exchange
information on progress, obstacles and issues relative to the year 2000 efforts.
Under the present schedule, it does not appear that the merger will occur before
the transition to year 2000 is complete. There are no plans to consolidate or
convert existing computer systems before the AEP Merger closes.
86
<PAGE>
Portions of the preceding discussion contains forward-looking information
within the meaning of Section 21E of the Exchange Act. Actual results may differ
materially from such projected information due to changes in the underlying
assumptions. See FORWARD-LOOKING INFORMATION.
87
<PAGE>
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In 1997, CSW's Board of Directors adopted a risk management resolution
authorizing CSW to engage in currency, interest rate and energy spot and forward
transactions and related derivative transactions on behalf of CSW with foreign
and domestic parties as deemed appropriate by executive officers of CSW. The
risk management program is necessary to meet the growing demands of CSW's
customers for competitive prices and price stability, to enable CSW to compete
in a deregulated power industry, to manage the risks associated with domestic
and foreign investments and to take advantage of strategic investment
opportunities.
The U.S. Electric Operating Companies experience commodity price exposures
related to the purchase of fuel supplies for the generation of electricity and
for the sale and purchase of energy. Contracts that provide for the future
delivery of these commodities may contain spot and forward pricing, volume
and/or derivative terms designed to manage price exposure for the benefit of
customers and to take advantage of strategic opportunities.
In response to the development of a more competitive electric energy
market, CSW has received regulatory approval which authorizes the U.S. Electric
Operating Companies to conduct a pilot program involving power sales agreements
at tariffed rates with a fixed fuel cost. To offset the commodity price risk
associated with these contracts, CSW has entered into natural gas swaps and
futures contracts. These agreements cover natural gas deliveries through
December 31, 2000. Natural gas volumes purchased to perform these contracts for
which CSW has secured swap agreements represents approximately 1% of annual
natural gas purchases.
The table below provides information about CSW's contracts that are
sensitive to changes in commodity prices. The swaps hedge commodity price
exposure through the year 2000. Cash outflows on the swap agreements should be
offset by increased margins on electricity sales to customers under tariffed
rates with fixed fuel costs. The electricity forward contracts hedge a portion
of CSW's energy requirements through 2000. The average contract price for
forward power purchases is $33 per MWH, and the average contract price for
forward power sales is $70 per MWH. Also, the average contract price for forward
fuel purchases is $2.90 per MMbtu.
Contractual commitments at September 30, 1999 are as follows:
Net Notional Fair Value of Fair Value of
Products Amount Assets Liabilities
----------------------------------------------------------------------------
(thousands)
Swaps 7,440,000 MMbtu $1,539 $--
Forwards: Purchases 2,730,000 MMbtu -- 297
Purchases 252,000 MWH 159 --
Sales 86,400 MWH 268 --
Futures: Purchases 190,000 MMbtu 40 --
Sales 100,000 MMbtu -- 4
CSW has, at times, been exposed to currency and interest rate risks which
reflect the floating exchange rate that exists between the U.S. dollar and the
British pound. CSW has utilized certain risk management tools to manage adverse
changes in exchange rates and to facilitate financing transactions resulting
from CSW's acquisition of SEEBOARD. At September 30, 1999, CSW had positions in
two cross currency swap contracts, which were used to eliminate currency
fluctuations in respect of the $400 million of debt. The following table
presents information relating to these contracts. The market value represents
the foreign exchange/interest rate terms inherent in the cross currency swaps at
88
<PAGE>
current market pricing. CSW expects to hold these contracts to maturity. At
exchange rates on September 30, 1999, this liability is included in long-term
debt on the balance sheet at a carrying value of approximately $425 million.
Expected Expected Cash
Cash Inflows Outflows
Contract Maturity Date (Maturity Value) (Market Value)
- ------------------------------------------------------------------------------
Cross currency swaps August 1, 2001 $200 million $215.3 million
Cross currency swaps August 1, 2006 $200 million $228.2 million
For information related to currency risk in South America see ITEM 1. -
NOTE 7. SOUTH AMERICAN INVESTMENTS.
The preceding discussion constitutes forward-looking information within
the meaning of Section 21E of the Exchange Act. Actual results may differ
materially from such projected information. See FORWARD-LOOKING INFORMATION.
89
<PAGE>
PART II. - OTHER INFORMATION
For background and earlier developments relating to PART II information,
reference is made to the Registrants' Combined Annual Report on Form 10-K for
the year ended December 31, 1998 and Combined Quarterly Report on Form 10-Q for
the quarters ended March 31, 1999 and June 30, 1999.
ITEM 1. LEGAL PROCEEDINGS.
Other Legal Claims and Proceedings
The CSW System is party to various other legal claims and proceedings
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 PART I. - NOTE 2. LITIGATION AND
REGULATORY PROCEEDINGS and NOTE 3.
COMMITMENTS AND CONTINGENT LIABILITIES.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) EXHIBITS:
(12) Computation of Ratio of Earnings to Fixed Charges
CPL - (Exhibit 12.1), filed herewith.
PSO - (Exhibit 12.2), filed herewith.
SWEPCO - (Exhibit 12.3), filed herewith.
WTU - (Exhibit 12.4), filed herewith.
(27) Financial Data Schedules
CSW - (Exhibit 27.1), filed herewith.
CPL - (Exhibit 27.2), filed herewith.
PSO - (Exhibit 27.3), filed herewith.
SWEPCO - (Exhibit 27.4), filed herewith.
WTU - (Exhibit 27.5), filed herewith.
(b) REPORTS FILED ON FORM 8-K:
CSW and SWEPCO
Date of earliest event reported: August 27, 1999
Date of report: September 1, 1999
Item 5. Other Events and Item 7 Financial Statements and Exhibits, reporting
SWEPCO's withdrawal of its joint plan to acquire the non-nuclear assets of
Cajun.
CSW
Date of earliest event reported: October 8, 1999
Date of report: October 18, 1999
Item 5. Other Events and Item 7 Financial Statements and Exhibits, news release
related to the sale of 50% equity interest in the Sweeny electric generating
plant.
90
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signature for each undersigned
Registrant shall be deemed to relate only to matters having reference to such
Registrant or its subsidiaries.
CENTRAL AND SOUTH WEST CORPORATION
Date: November 15, 1999 /s/ Lawrence B. Connors
------------------------
Lawrence B. Connors
Controller and Chief Accounting Officer
(Principal Accounting Officer)
CENTRAL POWER AND LIGHT COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
WEST TEXAS UTILITIES COMPANY
Date: November 15, 1999 /s/ R. Russell Davis
------------------------
R. Russell Davis
Controller and Chief Accounting Officer
(Principal Accounting Officer)
91
EXHIBIT 12.1
CENTRAL POWER AND LIGHT COMPANY (CONSOLIDATED)
RATIO OF EARNINGS TO FIXED CHARGES
FOR THE TWELVE MONTHS ENDED SEPTEMBER 30, 1999
(Thousands Except Ratio)
(Unaudited)
Operating Income $284,009
Adjustments:
Income taxes 101,742
Provision for deferred income taxes (9,159)
Deferred investment tax credits (5,207)
Other income and deductions 2,472
Allowance for borrowed and equity funds
used during construction 3,286
---------
Earnings $377,143
=========
Fixed Charges:
Interest on long-term debt $ 88,337
Interest on short-term debt and other 16,975
Distributions on Trust Preferred Securities 12,000
---------
Fixed Charges $117,312
=========
Ratio of Earnings to Fixed Charges 3.21
=========
92
EXHIBIT 12.2
PUBLIC SERVICE COMPANY OF OKLAHOMA (CONSOLIDATED)
RATIO OF EARNINGS TO FIXED CHARGES
FOR THE TWELVE MONTHS ENDED SEPTEMBER 30, 1999
(Thousands Except Ratio)
(Unaudited)
Operating Income $ 102,306
Adjustments:
Income taxes 31,891
Provision for deferred income taxes 1,593
Deferred investment tax credits (1,791)
Other income and deductions (691)
Allowance for borrowed and equity funds
used during construction 1,845
-----------
Earnings $ 135,153
===========
Fixed Charges:
Interest on long-term debt $ 26,643
Interest on short-term debt and other 4,656
Distributions on Trust Preferred Securities 6,000
-----------
Fixed Charges $ 37,299
===========
Ratio of Earnings to Fixed Charges 3.62
===========
93
EXHIBIT 12.3
SOUTHWESTERN ELECTRIC POWER COMPANY (CONSOLIDATED)
RATIO OF EARNINGS TO FIXED CHARGES
FOR THE TWELVE MONTHS ENDED SEPTEMBER 30, 1999
(Thousands Except Ratio)
(Unaudited)
Operating Income $146,449
Adjustments:
Income taxes 62,611
Provision for deferred income taxes (22,739)
Deferred investment tax credits (4,581)
Other income and deductions (2,370)
Allowance for borrowed and equity funds
used during construction 1,988
Interest portion of financing leases 414
-----------
Earnings $181,772
===========
Fixed Charges:
Interest on long-term debt $39,008
Interest on short-term debt and other 10,313
Distributions on Trust Preferred Securities 8,662
Interest portion of financing leases 414
-----------
Fixed Charges $58,397
===========
Ratio of Earnings to Fixed Charges 3.11
===========
94
EXHIBIT 12.4
WEST TEXAS UTILITIES COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
FOR THE TWELVE MONTHS ENDED SEPTEMBER 30, 1999
(Thousands Except Ratio)
(Unaudited)
Operating Income $ 53,886
Adjustments:
Income taxes 7,981
Provision for deferred income taxes 8,072
Deferred investment tax credits (1,286)
Other income and deductions 546
Allowance for borrowed and equity funds
used during construction 1,157
-----------
Earnings $ 70,356
===========
Fixed Charges:
Interest on long-term debt $20,352
Interest on short-term debt and other 4,733
-----------
Fixed Charges $ 25,085
===========
Ratio of Earnings to Fixed Charges 2.80
===========
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0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 290,161
<TOT-CAPITALIZATION-AND-LIAB> 859,506
<GROSS-OPERATING-REVENUE> 343,138
<INCOME-TAX-EXPENSE> 16,076
<OTHER-OPERATING-EXPENSES> 276,092
<TOTAL-OPERATING-EXPENSES> 292,168
<OPERATING-INCOME-LOSS> 50,970
<OTHER-INCOME-NET> 504
<INCOME-BEFORE-INTEREST-EXPEN> 51,474
<TOTAL-INTEREST-EXPENSE> 18,356
<NET-INCOME> 27,657
78
<EARNINGS-AVAILABLE-FOR-COMM> 27,579
<COMMON-STOCK-DIVIDENDS> 21,000
<TOTAL-INTEREST-ON-BONDS> 15,264
<CASH-FLOW-OPERATIONS> 79,798
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
