ITEM 1. BUSINESS.
The Company. The Company, a Texas corporation, is a public utility engaged in generating, purchasing, transmitting, distributing and selling electricity in south Texas. It is a wholly owned subsidiary of CSW, a registered holding company under the Holding Company Act.
At December 31, 1993, the Company supplied electric service to approximately 589,000 retail customers in a 44,000 square mile area with an estimated population of 1,945,000. It supplied at wholesale all or a portion of the electric energy requirements of two municipalities and five rural electric cooperatives. The three largest metropolitan areas served by the Company are Corpus Christi, Laredo and McAllen, which have estimated populations of 265,000, 133,000 and 88,000, respectively.
The economic base of the territory served by the Company includes manufacturing, metal refining, petroleum, petrochemical, agriculture and tourism.
In 1993, industrial customers accounted for approximately 23% of the Company's total operating revenues. Contracts with substantially all industrial customers provide for both demand and energy charges. Demand charges continue under such contracts even during periods of reduced industrial activity, thus mitigating the effect of reduced activity on operating income.
Regulation and Rates
Regulation. The Company, as a subsidiary of CSW, is subject to the jurisdiction of the SEC under the Holding Company Act with respect to the issuance, acquisition and sale of securities, acquisition and sale of certain assets or any interest in any business, including certain aspects of fuel exploration and development programs, accounting practices and other matters.
The FERC has jurisdiction under the Federal Power Act over certain of the Company's electric utility facilities and operations, wholesale rates and certain other matters.
The Texas Commission has jurisdiction over accounts, certification of utility service territories, sale or acquisition of certain utility property, mergers and certain other matters. Neither the Texas Commission nor the governing bodies of incorporated municipalities have jurisdiction over the issuance of securities.
National Energy Policy Act of 1992. The Energy Policy Act, adopted in October 1992, significantly changed U.S. energy policy, including that governing the electric utility industry. The Energy Policy Act allows the FERC, on a case-by-case basis and with certain restrictions, to order wholesale transmission access and to order electric utilities to enlarge their transmission systems. The Energy Policy Act does, however, prohibit FERC- ordered retail wheeling, including "sham" wholesale transactions. Further, under the Energy Policy Act a FERC transmission order requiring a transmitting utility to provide wholesale transmission services must include provisions generally that permit the utility to recover from the FERC applicant all of the costs incurred in connection with the transmission services, any enlargement of the transmission system and associated services.
In addition, the Energy Policy Act revised the Holding Company Act to permit utilities, including registered holding companies, and non-utilities to form exempt wholesale generators. An exempt wholesale generator is a new category of non-utility wholesale power producer that is free from most federal and state regulation, including the principal restrictions of the Holding Company Act. These provisions enable broader participation in wholesale power markets by reducing regulatory hurdles to such participation. Management believes that this Act will make wholesale markets more competitive. However, the Company is unable to predict the extent to which the Energy Policy Act will affect its operations.
See ITEM 1. BUSINESS -- Environmental Matters, for information relating to Environmental regulation.
Rates. The Texas Commission has original jurisdiction over retail rates in the unincorporated areas of Texas. The governing bodies of incorporated municipalities have such jurisdiction over rates within their incorporated limits. Municipalities may elect, and some have elected, to surrender this jurisdiction to the Texas Commission. The Texas Commission has appellate jurisdiction over rates set by incorporated municipalities.
See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, Rate Case Filings in ITEM 8, for further information with respect to current rate proceedings.
Electric utilities in Texas are not allowed to make automatic adjustments to recover changes in fuel costs from retail customers. A utility is allowed to recover its known or reasonably predictable fuel costs through a fixed fuel factor. The Texas Commission established procedures effective May 1, 1993, subject to certain transition rules, whereby each utility under its jurisdiction may petition to revise its fuel factors every six months according to a specified schedule. Fuel factors may also be revised in the case of an emergency or in a general rate proceeding. Under the revised procedures, a utility will remain subject to the prior rules until after its first fuel reconciliation, or in some instances a general rate proceeding including a fuel reconciliation, subject to the new rules. Management does not believe that the new rules substantially change the manner in which the Company will recover retail fuel costs.
Fuel factors are in the nature of temporary rates, and the utility's collection of revenues by such is subject to adjustment at the time of a fuel reconciliation proceeding. At the utility's semi-annual adjustment date, a utility is required to petition the Texas Commission for a surcharge or to make a refund when it has materially under- or over-collected its fuel costs and projects that it will continue to materially under- or over-collect. Material under- or over-collections including interest are defined as four percent of the most recent Texas Commission adopted annual estimated fuel cost for the utility, which is approximately $10.4 million for the Company. A utility does not have to revise its fuel factor when requesting a surcharge or refund. An interim emergency fuel factor order must be issued by the Texas Commission within 30 days after such petition is filed by the utility.
Final reconciliation of fuel costs are made through a reconciliation proceeding, which may contain a maximum of three years and a minimum of one year of reconcilable data, and must be filed with the Texas Commission no later than six months after the end of the period to be reconciled. In addition, a utility must include a reconciliation of fuel costs in any general rate proceeding regardless of the time since its last fuel reconciliation proceeding. Any fuel costs which are determined unreasonably incurred in a reconciliation proceeding must be refunded to customers. In the event that the Company does not recover all of its fuel costs under the above procedures, the Company could experience an adverse impact on its results of operations.
All of the Company's contracts with its wholesale customers contain FERC approved fuel-adjustment provisions that permit it to automatically pass actual fuel costs through to its customers.
See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, in ITEM 8, for further information with respect to regulation and rates.
STP
The ownership of a nuclear generating unit exposes the Company to significant special risks. Under the Atomic Energy Act of 1954 and Energy Reorganization Act of 1974, operation of nuclear plants is intensively regulated by the NRC, which has broad power to impose licensing and safety-related requirements. Along with other federal and state agencies, the NRC also has extensive regulations pertaining to the environmental aspects of nuclear reactors. The NRC has the authority to impose fines and/or shutdown a unit until compliance is achieved, depending upon its assessment of the severity of the situation.
The high degree of regulatory monitoring and controls to assure safe operation could cause the STP units to be out of service for long periods of time. Outages are also necessary approximately every 18 months for refueling. Because STP's fuel costs currently are lower than any of the Company's other units, the Company's average fuel costs are expected to be higher whenever an STP unit is down or operates below the prior period's average capacity.
Risks of substantial liability arise from the operation of nuclear-fueled generating units and from the use, handling, and possible radioactive emissions associated with nuclear fuel. While the Company carries insurance, the availability, amount and coverage thereof is limited and may become more limited in the future. The available insurance will not cover all types or amounts of loss expense which may be experienced in connection with the ownership of STP. See NOTE 10, COMMITMENTS AND CONTINGENCIES - Nuclear Insurance, in ITEM 8 for further information.
See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, in ITEM 8 for a discussion of the STP outage.
Operations
Peak Loads and System Capabilities. The following table sets forth for the years 1991 through 1993 the net system capabilities of the Company (including the net amounts of contracted purchases and contracted sales) at the time of peak demand, the maximum coincident system demand on a one-hour integrated basis (exclusive of sales to other electric utilities) and the respective amounts and percentages of peak demand generated by the Company and net purchases and sales: Percent Increase Maximum (Decrease) Net Purchases Coincident In Peak Generation at (Sales) at Net System System Demand Time of Peak Time of Peak Capabilities(a) Demand(b) Over Prior Year Mw Mw Period Mw % Mw %
1991 4,005 3,291 5.8 3,424 104.0 (133) (4.0) 1992 4,165 3,347 1.7 3,003 89.7 344 10.3 1993 4,480 3,518 5.1 2,943 83.7 575 16.3 ___________________
(a) Does not include 452 Mw of system capability in long-term storage in 1991 and 310 Mw in 1992 and 1993 as described under "ITEM 2.


ITEM 2. PROPERTIES.
Facilities. At December 31, 1993, the Company owned the following electric generating plants (or portions thereof in the cases of the jointly owned plants).
(See "ITEM 1. BUSINESS -- Fuel Supply.")
Net Dependable Type of Fuel Capability Plant Name and Location Primary/Secondary Mw
Barney M. Davis gas/oil(a) 339 Corpus Christi, Texas gas/oil 340
Coleto Creek coal 604 Goliad, Texas
Lon C. Hill gas/oil(a) 549 Corpus Christi, Texas
Nueces Bay gas/oil(a) 512(b) Corpus Christi, Texas
Victoria gas/oil(a) 258(b) Victoria, Texas
La Palma gas/oil 47 San Benito, Texas gas/oil(a) 156(b)
E. S. Joslin gas/oil(a) 252 Point Comfort, Texas
J. L. Bates gas/oil(a) 182 Mission, Texas
Laredo gas/oil(a) 66 Laredo, Texas gas/oil 106
Eagle Pass Eagle Pass, Texas hydro 6
Oklaunion coal 53(c) Vernon, Texas
STP nuclear 630(d) Bay City, Texas
Total 4,100
_______________________
(a) For extended periods of operation, oil can be used only in combination with gas. Use of oil in facilities primarily designed to burn gas results in increased maintenance expense and a reduction of approximately 15% in capability.
(b) Excludes units in long-term storage - 34 Mw at Nueces Bay, 228 Mw at Victoria and 48 Mw at La Palma.
(c) The Company owns 7.81% of the 676 Mw unit operated by WTU.
(d) The Company owns 25.2% of the two 1,250 Mw units operated by HLP.
All of the generating plants described above are located on land owned by the Company or jointly with the other participants in jointly owned plants. The Company's electric transmission and distribution facilities are for the most part located over or under highways, streets and other public places or property owned by others, for which permits, grants, easements or licenses (which the Company believes to be satisfactory, but without examination of underlying land titles) have been obtained. The principal plants and properties of the Company are subject to the lien of the first mortgage indenture under which the Company's first mortgage bonds are issued.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
See ITEM 1. BUSINESS - Environmental Matters, for information relating to environmental and certain other proceedings.
See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS, in ITEM 8, for information relating to regulatory and legal proceedings.
The Company is party to various other legal claims, actions and complaints arising in the normal course of business. Management does not expect disposition of these matters to have a material adverse effect on the Company's results of operations or financial condition.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
All of the outstanding shares of Common Stock of the Company are owned by its parent company, CSW.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
Reference is made to the Company's Financial Statements and related Notes and Selected Financial Data in ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Statements Of Income
CENTRAL POWER AND LIGHT COMPANY For the Years Ended December 31, 1993 1992 1991 (thousands)
Electric Operating Revenues Residential $ 474,426 $ 432,295 $ 435,860 Commercial 369,426 342,201 343,437 Industrial 281,247 240,341 221,885 Sales for resale 45,369 50,342 48,834 Other 53,060 48,244 48,714 --------- --------- --------- 1,223,528 1,113,423 1,098,730 --------- --------- --------- Operating Expenses and Taxes Fuel 350,268 306,939 303,428 Purchased power 64,025 17,160 15,041 Other operating 225,034 184,514 196,817 Restructuring charges 29,365 - - Maintenance 81,352 61,399 68,092 Depreciation and amortization 131,825 129,131 127,341 Taxes, other than Federal income 86,394 70,343 62,453 Federal income taxes 65,186 77,272 75,985 --------- --------- --------- 1,033,449 846,758 849,157 --------- --------- --------- Operating Income 190,079 266,665 249,573 --------- --------- --------- Other Income and Deductions Mirror CWIP liability amortization 75,702 82,527 96,671 Other 2,737 1,298 3,590 --------- --------- --------- 78,439 83,825 100,261 --------- --------- --------- Income Before Interest Charges 268,518 350,490 349,834 --------- --------- --------- Interest Charges Interest on long-term debt 112,939 125,476 124,987 Interest on short-term debt and other 10,449 6,503 7,641 --------- --------- --------- 123,388 131,979 132,628 --------- --------- --------- Income Before Cumulative Effect of Changes in Accounting Principles 145,130 218,511 217,206
Cumulative Effect of Changes in Accounting Principles 27,295 - - --------- --------- --------- Net Income 172,425 218,511 217,206 Preferred stock dividends 14,003 16,070 19,844 --------- --------- --------- Net Income for Common Stock $ 158,422 $ 202,441 $ 197,362 ========= ========= =========
Statements Of Retained Earnings
For the Years Ended December 31, 1993 1992 1991 (thousands)
Retained Earnings at Beginning of Year $863,988 $854,659 $875,521 Net income for common stock 158,422 202,441 197,362 Deduct: Common stock dividends 172,000 193,000 215,000 Preferred stock redemption costs 103 112 3,224
-------- -------- -------- Retained Earnings at End of Year $850,307 $863,988 $854,659 ======== ======== ========
The accompanying notes to financial statements are an integral part of these statements.
Balance Sheets
CENTRAL POWER AND LIGHT COMPANY As of December 31,
1993 1992 (thousands)
ASSETS Electric Utility Plant Production $3,061,911 $3,051,969 Transmission 351,584 329,400 Distribution 765,266 715,633 General 209,170 210,204 Construction work in progress 168,421 94,736 Nuclear fuel 160,326 152,494 ---------- ---------- 4,716,678 4,554,436 Less - Accumulated depreciation 1,263,372 1,148,348 ---------- ---------- 3,453,306 3,406,088 ---------- ---------- Current Assets Cash and temporary cash investments 2,435 3,666 Special deposits 1,967 151,589 Accounts receivable 23,850 20,296 Materials and supplies, at average cost 64,359 58,839 Fuel inventory, at average cost 16,934 29,259 Deferred income taxes 4,831 31,289 Unrecovered fuel costs 52,959 - Prepayments and other 2,255 2,198 ---------- ---------- 169,590 297,136 ---------- ---------- Deferred Charges and Other Assets Deferred STP costs 489,773 490,458 Mirror CWIP asset 331,845 341,865 Income tax related regulatory assets 266,597 - Other 70,634 48,113 ---------- ---------- 1,158,849 880,436 ---------- ---------- $4,781,745 $4,583,660 ========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization Common stock, $25 par value, authorized 12,000,000 shares, issued and outstanding 6,755,535 shares $ 168,888 $ 168,888 Paid-in capital 405,000 405,000 Retained earnings 850,307 863,988 ---------- ---------- Total Common Stock Equity 1,424,195 1,437,876 ---------- ---------- Preferred stock Not subject to mandatory redemption 250,351 250,351 Subject to mandatory redemption 22,021 28,393 Long-term debt 1,362,799 1,347,887 ---------- ---------- Total Capitalization 3,059,366 3,064,507 ---------- ---------- Current Liabilities Long-term debt and preferred stock due within twelve months 3,928 143,900 Advances from affiliates 171,165 91,766 Accounts payable 79,604 60,392 Accrued taxes 33,769 27,224 Accrued interest 24,683 25,729 Accrued restructuring charges 29,365 - Other 28,020 31,047 ---------- ---------- 370,534 380,058 ---------- ---------- Deferred Credits Income taxes 1,057,453 727,953 Investment tax credits 164,322 170,128 Mirror CWIP liability and other 130,070 241,014 ---------- ---------- 1,351,845 1,139,095 ---------- ---------- $4,781,745 $4,583,660 ========== ========== The accompanying notes to financial statements are an integral part of these statements.
Statements of Cash Flows
CENTRAL POWER AND LIGHT COMPANY For the Years Ended December 31, 1993 1992 1991 (thousands)
OPERATING ACTIVITIES Net Income $172,425 $218,511 $217,206 Non-cash Items Included in Net Income Depreciation and amortization 140,223 154,716 148,012 Deferred income taxes and investment tax credits 84,714 42,773 30,990 Mirror CWIP liability amortization (75,702) (82,527) (96,671) Restructuring charges 29,365 - - Cumulative effect of changes in accounting principles (27,295) - - Changes in Assets and Liabilities Accounts receivable (3,554) (6,415) 12,473 Fuel inventory 12,325 (3,137) 1,175 Accounts payable 19,151 6,209 7,057 Accrued taxes (9,311) (2,165) 17,065 Unrecovered fuel costs (57,386) (1,195) 5,001 Other (6,388) (23,020) (23,199) -------- -------- -------- 278,567 303,750 319,109 -------- -------- -------- INVESTING ACTIVITIES Construction expenditures (177,120) (100,805) (98,199) Other (1,544) (763) (1,056) -------- -------- -------- (178,664) (101,568) (99,255) -------- -------- -------- FINANCING ACTIVITIES Proceeds from issuance of long-term debt 441,131 435,497 - Retirement of long-term debt (431) (405) (168) Reacquisition of long-term debt (573,776) (304,650) (210) Retirement of preferred stock (6,578) (7,050) (7,050) Special deposits for reacquisition of long-term debt 145,482 (145,482) - Change in short-term debt 79,399 29,618 21,523 Payment of dividends (186,361) (209,196) (235,674) -------- -------- -------- (101,134) (201,668) (221,579) -------- -------- -------- NET CHANGE IN CASH AND CASH EQUIVALENTS (1,231) 514 (1,725) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 3,666 3,152 4,877 -------- -------- -------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 2,435 $ 3,666 $ 3,152 ======== ======== ========
SUPPLEMENTARY INFORMATION Interest paid less amounts capitalized $116,664 $130,078 $125,760 Income taxes paid 3,631 45,314 35,715 ======== ======== ========
The accompanying notes to financial statements are an integral part of these statements.
Statements of Capitalization
CENTRAL POWER AND LIGHT COMPANY As of December 31, 1993 1992 (thousands) COMMON STOCK EQUITY
$1,424,195 $1,437,876 ---------- ---------- PREFERRED STOCK Cumulative $100 Par Value, Authorized 3,035,000 Shares Number Current of Shares Redemption Series Outstanding Price Not Subject to Mandatory Redemption 4.00% 100,000 $105.75 10,000 10,000 4.20% 75,000 103.75 7,500 7,500 7.12% 260,000 101.00 26,000 26,000 8.72% 500,000 102.91 50,000 50,000 Auction Money Market 750,000 100.00 75,000 75,000 Auction Series A 425,000 100.00 42,500 42,500 Auction Series B 425,000 100.00 42,500 42,500 Issuance Expense (3,149) (3,149) -------- --------
250,351 250,351 -------- -------- Subject to Mandatory Redemption 10.05% 223,750 104.76 22,375 28,850 Issuance Expense (354) (457) -------- --------
22,021 28,393 -------- -------- LONG-TERM DEBT First Mortgage Bonds Series J, 6 5/8%, due January 1, 1998 28,000 28,000 Series L, 7%, due February 1, 2001 36,000 36,000 Series M, 8%, due November 1, 2003 - 46,000 Series O, 8 1/4%, due October 1, 2007 - 75,000 Series T, 7 1/2%, due December 15, 2014 111,700 111,700 Series U, 9 3/4%, due July 1, 2015 31,765 81,700 Series Y, 9 3/4%, due June 1, 1998 - 150,000 Series Z, 9 3/8%, due December 1, 2019 140,000 148,000 Series AA, 7 1/2%, due March 1, 2020 50,000 50,000 Series BB, 6%, October 1, 1997 200,000 200,000 Series CC, 7 1/4%, October 1, 2004 100,000 100,000 Series DD, 7 1/8%, December 1, 1999 25,000 25,000 Series EE, 7 1/2%, December 1, 2002 115,000 115,000 Series FF, 6 7/8%, due February 1, 2003 50,000 -
Series GG, 7 1/8%, due February 1, 2008 75,000 -
Series HH, 6%, due April 1, 2000 100,000 - Series II, 7 1/2%, due April 1, 2023 100,000 -
Installment Sales Agreements - PCRBs Series 1974A, 7 1/8%, due June 1, 2004 8,700 8,955 Series 1977, 6%, due November 1, 2007 34,235 34,235 Series 1984, 7 7/8%, due September 15, 2014 6,330 6,330 Series 1984, 10 1/8%, due October 15, 2014 68,870 139,200 Series 1986, 7 7/8%, due December 1, 2016 60,000 60,000 Series 1993, 6%, due July 1, 2028 120,265 -
Notes Payable, 6 1/2%, due December 8, 1995 448 651 Unamortized Discount (12,265) (17,923) Unamortized Costs of Reacquired Debt (86,249) (49,961) --------- ---------
1,362,799 1,347,887
--------- --------- TOTAL CAPITALIZATION $3,059,366 $3,064,507 ========= =========
The accompanying notes to financial statements are an integral part of these statements.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Central Power and Light Company is subject to regulation by the SEC, under the Holding Company Act, and by the FERC, under the Federal Power Act, and follows the Uniform System of Accounts prescribed by the FERC. The Company is subject to further regulation for rates and other matters by the Texas Commission. The Company, as a member of the CSW System, engages in transactions and coordinates its activities and operations with other members of the CSW System. The most significant accounting policies are summarized below.
Electric Utility Plant. Electric utility plant is stated at the original cost of construction which includes the cost of contracted services, direct labor, materials, overhead items and allowances for borrowed and equity funds used during construction.
Depreciation. Provisions for depreciation of utility plant are computed using the straight-line method generally at individual rates applied to the various classes of depreciable property. The annual composite rates averaged 3.0% for each of the years 1993, 1992 and 1991.
Nuclear Decommissioning. The Company's portion of the estimated costs of decommissioning STP is $85 million in 1986 dollars based on a site specific study completed in 1986. The Company will continue to review and update this cost estimate and a new study will be completed in 1994. The Company is recovering decommissioning costs through rates over the 38 year life of STP. The $4.2 million annual cost of decommissioning is reflected on the income statement as other operating expense. The funds received from customers applicable to decommissioning are paid to an irrevocable external trust and as such are not reflected on the Company's balance sheet. At December 31, 1993, the trust balance was $15.2 million.
At the end of STP's 38 year life, decommissioning is expected to be accomplished using the decontamination method, which is one of three techniques acceptable by the NRC. Using this method the decontamination activities occur as soon as possible after the end of plant operation. Contaminated equipment is cleaned or removed to a permanent disposal location and the site is generally returned to its pre-plant state.
Electric Revenues and Fuel. Prior to January 1, 1993, electric revenues generally were recorded at the time billings were made to customers on a cycle- billing basis. Electric service provided subsequent to billing dates through the end of each calendar month became part of electric revenues of the next month. To conform to general industry standards the Company in 1993 began accruing unbilled base revenues for electricity used by customers but not yet billed. This adjustment was recorded in 1993 as a cumulative effect of a change in accounting principle. The effect of this change on the Company's net income for 1993 was an increase of $45.4 million, or $29.5 million net of taxes. If this change in accounting method was applied retroactively, the effect on net income for 1992 and 1991 would have been immaterial.
The cost of fuel is charged to expense as consumed. The cost of nuclear fuel is amortized to fuel expense based on a ratio of the estimated Btu's used and available to generate electric energy, and includes a provision for the disposal of spent nuclear fuel.
The Company recovers fuel costs applicable to sales to wholesale customers, regulated by the FERC, through an automatic fuel adjustment clause.
The Company recovers fuel costs in Texas as a fixed component of base rates. The difference between fuel revenues billed and fuel expense incurred is recorded as an addition to or a reduction of revenues, with a corresponding entry to unrecovered fuel cost or other current liabilities as appropriate. Over-recoveries of fuel are payable to customers, and under-recoveries may be billed to customers after Texas Commission approval.
Accounts Receivable. The Company sells its accounts receivable, without recourse, to CSW Credit, Inc., a wholly owned subsidiary of CSW.
Deferred STP Costs. In accordance with Texas Commission orders, the Company deferred plant costs for STP Units 1 and 2 incurred subsequent to their commercial operation dates until retail rates which included the units in rate base became effective. The deferred plant costs are amortized and recovered through rates over the life of the plant in increasing amounts. See NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS for further discussion of the deferred accounting proceedings.
Mirror CWIP. In accordance with Texas Commission orders, the Company previously recorded Mirror CWIP, which is being amortized over the life of STP, as more fully discussed in NOTE 9, LITIGATION AND REGULATORY PROCEEDINGS.
Statements of Cash Flows. Cash equivalents are considered to be highly liquid debt instruments purchased with a maturity of three months or less. Accordingly, temporary cash investments and advances to affiliates are considered cash equivalents.
Reclassification. Certain financial statement items for prior years have been reclassified to conform to the 1993 presentation.
Accounting Changes. Effective January 1, 1993, the Company adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, SFAS No. 112, Employers' Accounting for Postemployment Benefits (See NOTE 8, BENEFITS PLANS), and SFAS No. 109, Accounting for Income Taxes (See NOTE 2, FEDERAL INCOME TAXES). The Company also changed its method of accounting for unbilled revenues (See Electric Revenues and Fuel above).
The adoption of SFAS No. 109 had no effect on the Company's results of operations. The adoption of SFAS No. 112 and the change in accounting for unbilled revenues are presented as cumulative effect of changes in accounting principles as shown below:
Pre-Tax Tax Net Income Effect Effect Effect (thousands)
SFAS No. 112 $(3,371) $ 1,180 $(2,191) Unbilled revenues 45,363 (15,877) 29,486 ------ ------- ------ Total $41,992 $(14,697) $27,295 ====== ======= ====== Pro forma amounts, assuming that the change in accounting for unbilled revenues had been adopted retroactively, are not materially different from amounts previously reported for prior years.
2. FEDERAL INCOME TAXES
The Company, together with other members of the CSW System, files a consolidated Federal income tax return and participates in a tax sharing agreement.
The Company adopted the provisions of SFAS No. 109, effective January 1, 1993. This standard had no impact on the Company's results of operations.
SFAS No. 109 requires the recognition of deferred tax liabilities for income customers associated with temporary differences previously passed through to rate payers and the equity component of allowance for funds used during construction. In addition, SFAS No. 109 requires reclassification of certain deferred income tax liabilities to reflect the Company's obligation to reduce revenue requirements for deferred income taxes provided at rates higher than the current 35% Federal income tax rate.
As a result, the Company recognized additional accumulated deferred income taxes and corresponding regulatory assets and liabilities to customers in amounts equal to future revenues or the reduction in future revenues that will be required when the income tax temporary differences reverse and are recovered or settled in rates.
Components of Federal income taxes are as follows:
1993 1992 1991 (thousands) Included in Operating Expenses and Taxes Current $(19,690) $ 34,336 $ 44,832 Deferred 90,682 48,773 36,984 Deferred ITC (5,806) (5,837) (5,831) ------- ------- ------- 65,186 77,272 75,985 ------- ------- ------- Included in Other Income and Deductions Current 736 390 (1,963) Deferred (162) (163) (163) ------- ------- ------- 574 227 (2,126) ------- ------- ------- Tax Effects of Cumulative Effects of Changes in Accounting Principles 14,697 - - ------- ------- ------- $ 80,457 $ 77,499 $ 73,859 ======= ======= =======
Total income taxes differ from the amounts computed by applying the statutory income tax rates to income before taxes. The reasons for the differences are as follows:
1993 % 1992 % 1991 %
(dollars in thousands)
Tax at statutory rates $ 88,509 35.0 $100,643 34.0 $ 98,962 34.0 Differences Amortization of ITC (5,806) (2.3) (5,789) (2.0) (5,789) (2.0) Mirror CWIP (22,989) (9.1) (24,652) (8.3) (29,463) (10.1) Prior period adjustments 19,101 7.6 - - - - Other 1,642 .6 7,297 2.5 10,149 3.5 ------- ---- ------- ---- ------- ---- $ 80,457 31.8 $ 77,499 26.2 $ 73,859 25.4 ======= ==== ======= ==== ======= ====
ITC deferred in prior years are included in income over the lives of the related properties.
The significant components of the net deferred income tax liability are as follows:
December 31, January 1, 1993 1993 (thousands) Deferred Tax Liabilities Property related book/tax basis differences $ 745,164 $ 640,275 Income tax related regulatory assets 178,984 172,657 Mirror CWIP asset 116,146 116,234 Deferred STP costs 171,421 166,756 Other 37,989 38,061 --------- --------- Total Deferred Tax Liabilities $1,249,704 $1,133,983 --------- --------- Deferred Tax Assets Income tax related regulatory liabilities (85,675) (105,370) Mirror CWIP liability (38,150) (62,799) Unamortized ITC (57,513) (57,843) Alternative minimum tax (15,744) (13,402) --------- --------- Total Deferred Tax Assets (197,082) (239,414) --------- --------- Net Accumulated Deferred Income Taxes-Total $1,052,622 $ 894,569 ========= ========= Net Accumulated Deferred Income Taxes-Noncurrent $1,057,453 $ 925,858 Net Accumulated Deferred Income Taxes-Current (4,831) (31,289) --------- --------- Net Accumulated Deferred Income Taxes-Total $1,052,622 $ 894,569 ========= ========= 3. LONG-TERM DEBT
The mortgage indenture, as amended and supplemented, securing first mortgage bonds issued by the Company, constitutes a direct first mortgage lien on substantially all electric utility plant.
Annual Requirements. Certain series of the Company's outstanding first mortgage bonds have annual sinking fund requirements which are generally one percent of the greatest amount outstanding at any time of each series of first mortgage bonds issued. These requirements may be, and have historically been, satisfied by the application of net expenditures for bondable property in an amount equal to 166-2/3% of the annual requirements. Series J, L, and Z first mortgage bonds are subject to this annual sinking fund requirement.
At December 31, 1993, the annual sinking fund requirements exclusive of maturities, and the annual aggregate maturities including sinking fund requirements, of long-term debt are as follows:
Annual Sinking Annual Aggregate Fund Requirements Maturities (thousands) 1994 2,120 3,299 1995 2,120 3,563 1996 2,120 3,135 1997 2,120 203,155 1998 1,840 30,895
Dividends. The Company's mortgage indenture, as amended and supplemented, contains certain restrictions on the payment of common stock dividends. At December 31, 1993, $630 million of retained earnings were available for the payment of cash dividends to CSW.
Reacquired Long-Term Debt. During 1993, the Company issued first mortgage bonds, the proceeds of such offerings were used to refinance higher cost debt in order to lower the embedded cost of long-term debt.
The premiums and reacquisition costs of reacquired long-term debt are included in long-term debt on the balance sheets and are being amortized over 5 to 35 years. Reference is made to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, for additional information on reacquired long-term debt.
Due Within Twelve Months. In December 1992, the Company issued Series DD and EE first mortgage bonds in the aggregate amount of $140 million to reacquire Series K, N and P first mortgage bonds in January 1993. Accordingly, at December 31, 1992, the Company reclassified these bonds totaling $140 million from long-term debt on the balance sheet to current liabilities, long-term debt and preferred stock due within twelve months.
4. PREFERRED STOCK
The dividends on the Company's $160 million auction preferred stocks are adjusted every 49 days, based on current market rates. The dividend rate averaged 2.7%, 3.6%, and 5.5% during 1993, 1992 and 1991.
The Company's 10.05%, $100 par value preferred stock requires a mandatory sinking fund sufficient to retire 35,250 shares annually until January 31, 2001, and a specified number of shares in each 12-month period thereafter. The sinking fund redemption price is $100 per share. The portion to be retired within twelve months is reflected as such on the balance sheet under current liabilities.
Each series of preferred stock, with the exception of the 10.05% Series and the auction preferred stock, is redeemable at the option of the Company upon 30 days notice at the current redemption price per share. Redemption prices of the 8.72% and 10.05% Series decline at specified intervals in future years. The 10.05% Series is redeemable as of February 1, 1994. The Company's three issues of auction preferred stock may be redeemed at par on any dividend payment date.
The premiums and reacquisition costs of reacquired preferred stock are treated as a reduction to retained earnings.
5. SHORT-TERM FINANCING
The Company, together with other members of the CSW System, has established a money pool to coordinate short-term borrowings through the issuance of CSW's commercial paper. Money pool borrowings are shown as advances from affiliates on the balance sheet. At December 31, 1993, the CSW System had bank lines of credit aggregating $797 million, including the Company's lines of credit, to back up its commercial paper program. Short-term cash surpluses transferred to the money pool receive interest income in accordance with the money pool arrangement.
6. FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value:
Cash, temporary cash investments, special deposits and short-term debt. The carrying amount approximates fair value because of the short maturity of those instruments.
Long-term debt. The fair value of the Company's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for the debt of the same or similar remaining maturities.
Preferred stock subject to mandatory redemption. The fair value of this preferred stock is estimated based on the quoted market prices for the same or
similar issues or on the current rates offered to the Company for preferred stock with the same or similar remaining redemption provisions.
The estimated fair values of the Company's financial instruments are as follows:
1993 1992
Carrying Fair Carrying Fair Amount Value Amount Value (thousands) Cash and temporary cash investments $ 2,435 $ 2,435 $ 3,666 $ 3,666 Special deposits 1,967 1,967 151,589 151,589 Short-term debt 171,165 171,165 91,766 91,766 Long-term debt 1,362,799 1,456,533 1,347,887 1,424,128 Preferred stock subject to mandatory redemption 22,021 23,086 28,393 29,766 Long-term debt and preferred stock due within twelve months 3,928 4,096 143,900 149,632
7. BENEFIT PLANS
Defined Benefit Pension Plan. The Company, together with other members of the CSW System, maintains a tax qualified, non-contributory defined benefit pension plan covering substantially all of its employees. Participants in the plan during 1993 included approximately 2,300 active employees, 1,200 retirees and beneficiaries and 300 terminated employees with vested benefits. Benefits are based on employees' years of service, age at retirement and final average annual earnings with an offset for the participant's primary Social Security benefit. The CSW System's funding policy is based on actuarially determined contributions, taking into account amounts deductible for income tax purposes and minimum contributions required by ERISA. Contributions to the plan for the years ended December 31, 1993, 1992 and 1991 were $11.0 million, $11.7 million and $10.1 million, respectively. Pension plan assets consist primarily of common stocks and short- and intermediate-term fixed income investments.
The components of net periodic pension cost and the assumptions used in accounting for pensions are as follows:
1993 1992 1991 (thousands) Net Periodic Pension Cost Service cost $ 5,228 $ 4,834 $ 4,324 Interest cost on projected benefit obligation 14,878 13,686 12,072 Actual return on plan assets (18,079) (11,750) (26,785) Net amortization and deferral 68 (5,330) 12,269 ------ ------ ------ $ 2,095 $ 1,440 $ 1,880 ====== ====== ====== Assumptions: Discount rate 7.75% 8.50% 8.50% Long-term compensation increase 5.46% 5.96% 5.96% Return on plan assets 9.50% 9.50% 9.50%
As of December 31, 1993 and 1992, the plan's net assets exceeded the total actuarial present value of accumulated benefit obligations.
Postretirement Benefits Other Than Pensions. The Company adopted SFAS No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions, January 1, 1993. The adoption resulted in an increase in operating of $5.9 million for 1993. The Company's accumulated postretirement benefit obligation was $66.5 million. The transition obligation was $58.0 million and is being amortized over twenty years. In prior years the Company accounted for these benefits on a pay-as-you-go basis. Expenses for 1992 and 1991 were $3.8 million and $3.5 million, respectively. The CSW System's funding policy is based on actuarially determined contributions taking into account amounts which are
deductible income tax purposes. The Company contributed approximately $8.6 million in 1993.
The components of net periodic postretirement benefit cost and the assumptions used in accounting for postretirement benefits are as follows:
(thousands) Net Periodic Postretirement Benefit Cost Service cost $2,257 Interest cost on accumulated postretirement benefit obligation 5,505 Actual return on plan assets (249) Amortization of transition obligation 2,900 Net amortization and deferral (703) ----- $9,710 ===== Assumptions: Discount rate 7.75% Return on plan assets 9.00%
Health Care Cost Trend Rate Assumptions: Pre-65 Participants: 1993 Rate of 12.50% grading down .75% per year to an ultimate rate of 6.5% in 2001.
Post-65 Participants: 1993 Rate of 12.00% grading down .75% per year to an ultimate rate of 6.0% in 2001.
Increasing the assumed health care cost trend rates by one percentage point in each year would increase the APBO as of December 31, 1993 by $8.8 million and increase the aggregate of the service and interest cost components of net postretirement benefits by $1.2 million.
Postemployment Benefits. In November 1992, the Financial Accounting Standards Board issued SFAS No. 112, Employers' Accounting for Postemployment Benefits. This statement requires the accrual method of accounting for certain types of postemployment benefits provided to former or inactive employees after employment, but before retirement. This new standard requires that the expected costs of these benefits be accrued during the period employees render service to qualify for benefits. The most significant costs for the Company are the continued medical and salary benefits during long-term disability. Effective January 1, 1993, the Company adopted SFAS No. 112 and the effect of the change on 1993 income was $2.2 million reflected in cumulative effect of changes in accounting principles.
Restructuring Charges. The Company recently announced an early retirement program as a part of the Company's restructuring efforts in order to streamline operations and reduce future costs. It is anticipated that this restructuring will affect employee benefit costs incurred by the Company in future periods. Due to the timing of the implementation of the program, many variables regarding specific costs cannot be identified until mid-1994. As a result, no adjustments have been made to the employee benefit cost data presented above.
8. JOINTLY OWNED ELECTRIC UTILITY PLANT
The Company is party to joint ownership agreements with nonaffiliated entities. Such agreements provide for the joint ownership and operation of STP consisting of two nuclear generating units. The Company also has a joint ownership agreement with other members of the CSW System and nonaffiliated entities to provide for the joint ownership and operation of Oklaunion and its related facilities. The statements of income reflect the Company's portion ofoperating costs associated with jointly owned plant in service. At December 31, 1993, the Company had interests in the generating stations and related facilities as shown below:
STP Oklaunion (dollars in thousands) Plant in service $2,340,336 $36,045 Accumulated depreciation $318,101 $7,058 Plant capacity - mw 2,500 676 Participation 25.2% 7.8% Share of capacity - mw 630 53
9. LITIGATION AND REGULATORY PROCEEDINGS
STP Introduction. The Company owns 25.2% of STP, a two-unit nuclear power plant which is located near Bay City, Texas. In addition to the Company, HLP, the Project Manager, owns 30.8%, San Antonio owns 28.0%, and Austin owns 16.0%. STP Unit 1 was placed in service in August 1988 and STP Unit 2 was placed in service in June 1989.
STP Final Orders. In October 1990, the Texas Commission issued a final order (STP Unit 1 Order) which fully implemented a stipulated agreement filed in February 1990 to resolve dockets then pending before the Texas Commission. In December 1990, the Texas Commission issued a final order (STP Unit 2 Order) which fully implemented a stipulated agreement to resolve all issues regarding the Company's investment in STP Unit 2.
The STP Unit 1 Order allowed the Company to increase retail base rates by $144 million. This base rate increase made permanent a $105 million interim base rate increase placed into effect in March 1990 and a $39 million interim base rate increase placed into effect in September 1989. The STP Unit 2 Order provided for a retail base rate increase of $120 million effective January 1, 1991. The STP Unit 1 Order also provided for the deferral of operating expenses and carrying costs on STP Unit 2. A prior Texas Commission order (see "Deferred Accounting" below) had authorized deferral of STP Unit 1 costs. Such costs are being recovered through rates over the remaining life of STP. Also, the STP Unit 1 Order authorized use of Mirror CWIP, pursuant to which the Company recognized $360 million of carrying costs as deferred costs, and established a corresponding liability to customers recorded in Mirror CWIP liability and other deferred credits on the balance sheets. In compliance with the order, carrying costs collected through rates during periods when CWIP was included in rate base were recognized as a loan from customers. The loan is being repaid through lower rates from 1991 through 1995, which approximates the length of time during which the carrying costs were collected from customers. The Mirror CWIP liability is being reduced by the recognition of non-cash income during the period 1991 through 1995.
The STP Unit 1 and 2 Orders resolved all issues pertaining to the reasonable original costs of STP and the appropriate amount to be included in rate base. Pursuant to the Texas Commission orders, the original cost of the Company's total investment in STP is included in rate base.
As part of the stipulated agreement, the Company has agreed to freeze base rates from January 1, 1991 through 1994, subject to certain force majeure events including double-digit inflation, major tax increases, extraordinary increases in operating expenses or serious declines in operating revenues. The Company may file for increases in base rates, which would be effective after 1994 and subject to certain limitations. The fuel portion of customers' bills is subject to adjustment following the normal review and approval by the Texas Commission.
The stipulated agreements, as discussed above, were entered into by the Company, the Texas Commission Staff and a majority of intervenors including major cities in the Company's service territory and major industrial customers. These intervenors represent a significant majority of the Company's customers. The Company and the TSA reached agreements, which were subsequently approved by the Texas Commission Staff and other signatories, whereby TSA agreed not to oppose the stipulated agreements in any respect, except with regard to deferred accounting and rate design issues in the STP Unit 1 Order. OPUC and a coalition of low-income customers declined to enter into the stipulated agreements.
In January 1991, the TSA, OPUC and the coalition of low-income customers filed appeals of the STP Unit 1 Order in District Court requesting reversal of the deferred accounting for STP Unit 2 and other aspects of that order. In March 1991, the TSA, OPUC and the coalition of low-income customers filed appeals of the STP Unit 2 Order in the District Court requesting reversal of that order. These appeals are pending before the District Court. If these orders are ultimately reversed on appeal, the stipulated agreements would be nullified and the Company could experience a significant adverse effect on its results of operations. However, the parties to the stipulated agreement, should it be nullified, are bound to renegotiate and try to reach a revised agreement that would achieve the same results. Management believes that the STP Unit 1 and 2 Orders will be upheld.
Deferred Accounting. The Company was granted deferred accounting for STP Unit 1 and 2 costs by Texas Commission orders. These orders allowed the Company to defer post-in-service operating and maintenance costs, including taxes and depreciation, and carrying costs until these costs were reflected in retail rates. Deferred accounting had an immediate positive effect on net income in the years allowed, but cash earnings were not increased until rates went into effect reflecting STP in service (see "STP Final Orders" above). The total deferrals for the periods affected were approximately $492 million with an after-tax net income effect of approximately $325 million. This total deferral included approximately $270 million of pre-tax debt carrying costs. Pursuant to the STP Unit 1 and 2 Orders, the Company's retail rates include recovery of all STP Unit 1 and 2 deferrals over the remaining life of the plant.
In July 1989, OPUC and the TSA filed appeals of the Texas Commission's final order in District Court requesting reversal of deferred accounting for STP Unit 1. In September 1990, the District Court issued a judgment affirming the Texas Commission's order for STP Unit 1, which was subsequently appealed to the Court of Appeals by OPUC and the TSA. The hearing of the Company's STP Unit 1 deferred accounting order was combined by the Court of Appeals with similar appeals of HLP deferred accounting orders.
In September 1992, the Court of Appeals issued a decision that allows the Company to include STP Unit 1 deferred post-in-service operating and maintenance costs in rate base. However, the Court of Appeals held that deferred post-in- service carrying costs could not be included in rate base, thereby prohibiting the Company from earning a return on such costs.
After the Court of Appeal's denial of each party's motion for rehearing of the decision, the Company and the Texas Commission in December 1992 filed Applications for Writ of Error petitioning the Supreme Court of Texas to review the September 1992 decision denying rate base treatment of deferred post-in- service carrying costs by the Court of Appeals. Additionally, the TSA and OPUC filed Applications for Writ of Error petitioning the Supreme Court of Texas to reverse the Court of Appeal's decision, challenging generally the legality of deferred accounting for or rate base treatment of any deferred costs. In May 1993, the Supreme Court of Texas granted the Company's application for writ of error. The Company's case was consolidated with the deferred accounting cases of El Paso Electric Company and HLP. Oral arguments were heard in September 1993 and the Supreme Court's decision is pending.
If the Company's orders granting deferred accounting were ultimately reversed and not favorably revised, the Company could experience a material adverse effect on its results of operations. While management cannot predict the ultimate outcome of the deferred accounting appeal, management believes the Company will successfully receive approval of its deferred accounting orders or will be successful in renegotiation of its rate orders, so that there will be no material adverse effect on the Company's results of operations or financial condition.
STP Outage. In February 1993, Units 1 and 2 of STP were shut down by HLP, the Project Manager, in an unscheduled outage resulting from mechanical problems relating to two auxiliary feedwater pumps. HLP determined that the units would not be restarted until the equipment failures had been corrected and the NRC briefed on the causes of these failures and the corrective actions that were taken. The NRC formalized that commitment in a confirmatory action letter, and sent an Augmented Inspection Team to STP to review the matter. In March 1993, the NRC began a diagnostic evaluation of STP. Conducted infrequently, diagnostic evaluations are broad-based evaluations of overall plant operations and are intended to review the strengths and weaknesses of the licensee's performance and to identify the root cause of performance problems. During and subsequent to the June 1993 completion of the evaluation, the NRC supplemented its confirmatory action letter to identify additional issues to be resolved and verified by the NRC before restart of STP. Such issues included the need to reduce backlogs of engineering and maintenance work and to simplify work processes which placed excessive burdens on operating and other plant personnel. The report also identified the need to strengthen management communications, oversight and teamwork as well as the capability to identify and correct the root causes of problems.
The NRC announced in June 1993 that STP was placed on its "watch list" of plants with "weaknesses that warrant increased NRC attention." Plants on the watch list are subject to closer NRC oversight. STP will remain on the NRC's watch list until both units return to service and a period of good performance is demonstrated.
During the outage, the necessary improvements have been made by HLP to address the issues in the confirmatory action letter, as supplemented. On February 15, 1994, the NRC agreed that the confirmatory action letter issues had been resolved with respect to Unit 1, and that it supported HLP's recommendation that Unit 1 was ready to restart. Unit 1 restarted in late February 1994 and operated at low power for three days. The Project Manager then shut down Unit 1 due to a problem with a steam generator feedwater valve and a steam generator tube leak. The Project Manager expects to make the necessary repairs and restart Unit 1 in late March 1994, although additional delays may occur.
While many of the corrective actions taken are common to both units, HLP must demonstrate to the NRC that these issues are also resolved with respect to Unit 2 before it is restarted. HLP estimates that Unit 2 will restart during the second quarter of 1994 after the completion of refueling, which began in March 1993 but was delayed in order to focus on the issues discussed above. The outage has not affected the Company's ability to meet customer demands because of existing capacity and the Company's ability to purchase additional energy from affiliates and nonaffiliates.
During 1993, the NRC imposed a total of $500,000 in fines against HLP in connection with violations of NRC requirements that occurred prior to the February 1993 shut down. No fines have been imposed for activities subsequent to the shut down. The Company has paid its portion (25.2%) of the cost of fines.
The Company's share of increased non-fuel operation and maintenance costs in 1993, related to the outage at STP, necessary to effect the needed improvements were approximately $29 million, and were expensed as incurred. Included in these expenses were detailed inspections of both units' steam generators, and the acceleration of certain maintenance activities from 1994 to 1993. This acceleration is expected to eliminate the need for any planned outages for either unit in 1994. The 1994 budgeted STP non-fuel operation and maintenance expenses are expected to be significantly lower than the 1993 actual expenses; but even though lower, they are expected to be sufficient to continue enhancements that will result in improved long-term performance of STP.
Pursuant to the substantive rules of the Texas Commission, the Company generally is allowed to recover its fuel costs through a fixed fuel factor. These fuel factors are in the nature of temporary rates, and the Company's collection of revenues by such fuel factors is subject to adjustment at the time of a fuel reconciliation proceeding before the Texas Commission. The difference between fuel revenues billed and fuel expense incurred is recorded as an addition to or a reduction of revenues, with a corresponding entry to unrecovered fuel cost or other current liabilities, as appropriate. Any fuel costs (not limited to under- or over-recoveries) which the Texas Commission determines as unreasonable in a reconciliation proceeding are not recoverable from customers.
During the outage, the Company's fuel and purchased power costs have been, and are expected to continue to be, increased as the power normally generated by STP must be replaced through sources with higher costs. It is unclear how the Texas Commission will address the reasonableness of higher costs associated with the outage. At January 31, 1993, before the start of the STP outage, the Company had an over-recovered fuel balance of $5.2 million, exclusive of interest. At January 31, 1994, the Company's under-recovered fuel balance was $55.7 million, exclusive of interest. This under-recovery of fuel costs, while due primarily to the STP outage, was also affected by changes in fuel prices and timing differences. The Company cannot accurately estimate the amount of any future under- or over-recoveries due to the unpredictable nature of the above factors. Although there is the potential for disallowance of fuel-related costs, such determination cannot be made until fuel costs are reconciled with the Texas Commission. If a significant portion of fuel costs were disallowed by the Texas Commission, the Company could experience a material adverse effect on its results of operations in the year of any disallowance. The Company is required by Texas Commission's rules to file a reconciliation of its fuel costs by May 1, 1994. However, the Texas Commission Staff is proposing a revised filing deadline that would not require the Company to file before the fourth quarter of 1994.
In July 1993, the Company filed a fuel surcharge petition, which is separate from a fuel reconciliation proceeding, with the Texas Commission to comply with the mandatory provisions of the Texas Commission's fuel rules. The petition requested approval of a customer surcharge to recover under-recovered fuel and purchased power costs resulting from the STP outage, increased natural gas costs and other factors. The petition also requested that the Texas Commission postpone consideration of the surcharge until the STP outage concluded or at the time fuel costs are next reconciled as discussed above. In August 1993, a Texas Commission ALJ granted the Company's request to postpone consideration of the surcharge. In January 1994, the Company updated its fuel surcharge petition to reflect amounts of under-recovery through November 1993. Likewise, the Company requested and was granted postponement of the updated petition until the STP outage concluded or at the time fuel costs are next reconciled.
Management believes that the operating outage at STP will not have a material effect on its financial condition or on its results of operations.
Rate Case Filings. During December 1993 and January 1994, several cities (Cities) in the Company's service territory exercised their rights to require the Company to file rate cases to determine if its rates are fair, just and reasonable. The Cities, together, account for approximately 40% of the Company's base revenues. The governing bodies of these Cities have original jurisdiction over rates only within their incorporated limits. The Cities have ordered the Company to file rate cases by various dates from February 17 through March 18, 1994, with hearings scheduled in February and March 1994.
The Cities have informed the Company that this rate review was precipitated by the outage at STP leading the Cities to question whether STP should continue to be included in the Company's rate base. Further, the Cities question whether the Company is earning an excessive return on equity. In February 1994, a consultant for the Cities filed its report with the Cities. The consultant recommended that STP Unit 2 be removed from the Company's rate base, resulting in a reduction of the Company's total base revenues of $106.5 million. The consultant did not recommend a reduction in revenues relating to STP Unit 1, nor did it suggest a revenue reduction for its contention that the Company's earnings have been excessive, but it suggested that those issues be reserved for future proceedings if circumstances warrant action. Furthermore, the consultant made no recommendations concerning STP operation and maintenance expenses.
The Company contends that both units of STP belong in rate base because of the long-term benefits nuclear generation provides to customers. The Company is not aware of any Texas Commission precedent directly supporting the removal of a nuclear plant from rate base because of outages of the duration experienced by Unit 1 and expected for Unit 2. The Company also believes that its return on equity is below the level specified for the rate freeze period in accordance with the stipulated agreement entered into by the Company and parties to its last rate order, including the Cities. This rate order does not restrict the Cities from exercising their original jurisdiction over rates during the rate freeze period. The Texas Commission has appellate jurisdiction over rates set by municipalities.
In February and early March 1994, some of the Cities passed resolutions ordering the Company to reduce rates by $73 million, if applied on a total company basis. These Cities' revenues represent approximately 20% of the Company's total base revenues. The orders only affect the rates of customers who take service within these Cities' limits. The orders call for rates to be reduced in April unless, on appeal, the Texas Commission takes action which would stay their effectiveness. The Company has appealed these orders to the Texas Commission seeking the actions necessary to stay their effectiveness. The Company cannot predict if other cities acting in their capacity as regulatory authorities will initiate similar proceedings.
In December 1993, a complaint was filed at the Texas Commission by a customer of the Company who takes service outside of municipal limits, where the Texas Commission has original jurisdiction. The complaint seeks a review of the Company's rates due to the outage at STP. The Texas Commission has docketed the proceeding, but has taken no other action in the matter. In March 1994, the OPUC and General Counsel petitioned the Texas Commission to review the Company's rates. Any rate orders which might ultimately be entered as a result of these filings would affect customers served by the Company in all areas where individual city regulatory authorities do not have original jurisdiction.
Management cannot predict the ultimate outcome of these rate filings, although management believes that their ultimate resolution will not have a material adverse effect on the Company's results of operations or financial condition.
Westinghouse Litigation. The Company and other owners of STP are plaintiffs in a lawsuit filed October 1990 in the District Court in Matagorda County, Texas against Westinghouse, seeking damages and other relief. The suit alleges that Westinghouse supplied STP with defective steam generator tubes that are susceptible to stress corrosion cracking. Westinghouse filed an answer to the suit in March 1992, denying the plaintiff's allegations. The suit is currently in the discovery phase.
Inspections during the current STP outage have detected early signs of stress corrosion cracking in tubes at STP Unit 1, but the resulting remedial measures to date have not resulted in a material expense to the Company. Management believes that any additional problems would develop gradually and could be monitored by the operators of STP. An accurate estimate of the costs of remedying any further problems currently is unavailable due to many uncertainties, including among other things, the timing of repairs, which may coincide with scheduled outages, and the recoverability of amounts from Westinghouse and any insurers. Management believes that the ultimate resolution of this matter will not have a material adverse effect on the Company's results of operations.
General. The Company is party to various other legal claims, actions and complaints arising in the normal course of business. Management does not expect disposition of these matters to have a material adverse effect on the Company's results of operations or financial condition.
10. COMMITMENTS AND CONTINGENT LIABILITIES
It is estimated that the Company will spend approximately $187 million for construction purposes in 1994. Substantial commitments have been made in connection with the construction program.
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various commitments for the procurement of fuel.
Nuclear Insurance
In connection with the licensing and operation of STP, the owners have purchased the maximum limits of nuclear liability insurance, as required by law, and have executed indemnification agreements with the NRC in accordance with the financial protection requirements of the Price-Anderson Act.
The Price-Anderson Act, a comprehensive statutory arrangement providing limitations on nuclear liability and governmental indemnities is in effect until August 1, 2002. The limit of liability under the Price-Anderson Act for licensees of nuclear power plants is $9.3 billion per incident effective February 1994. The owners of STP are insured for their share of this liability through a combination of private insurance amounting to $200 million and a mandatory industry-wide program for self-insurance totaling $9.1 billion. The maximum amount that each licensee may be assessed for each licensed reactor under the industry-wide program of self-insurance following a nuclear incident at an insured facility is $75.5 million which may be adjusted for inflation plus a five percent charge for legal expenses, but not more than $10 million per reactor for each nuclear incident in any one year. The Company and each of the other STP owners are subject to such assessments, which the Company and the other owners have agreed will be borne on the basis of their respective ownership interests in STP. For purposes of these assessments, STP has two licensed reactors.
The owners of STP currently maintain on-site decontamination liability and property damage insurance in the amount of $2.7 billion provided by American Nuclear Insurers (ANI) and the Nuclear Electric Insurance Limited (NEIL) II program. Policies of insurance issued by ANI and NEIL II stipulate that policy proceeds must be used first to pay decontamination and clean-up costs, before being used to cover direct losses to property. The Company and the other owners of STP have entered into an agreement that provides for the total cost of decontamination liability and property insurance for STP (including premiums and assessments) to be shared pro rata based upon each owner's respective ownership interests in STP.
The Company purchases, for its own account, business interruption and extra expense insurance under the NEIL I Business Interruption and/or Extra Expense Program. This insurance will reimburse the Company for extra expenses incurred, up to $1.7 million per week, for replacement generation or purchased power as the result of a covered accident that shuts down production at STP for more than 21 weeks. The maximum amount recoverable for Unit 1 is $103.4 million and for Unit 2 is $105.9 million. The Company is subject to an additional assessment up to approximately $2.2 million for the current policy year in the event that losses as a result of a covered accident at a nuclear facility insured under NEIL I exceeds the accumulated funds available under the NEIL I Business Interruption and/or Extra Expense Program.
11. QUARTERLY INFORMATION (UNAUDITED)
The following unaudited quarterly information includes, in the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of such amounts:
Electric Operating Operating Net Revenues Income Income Quarter Ended (thousands)
March 31 $240,910 $41,346 $28,598 Adjustment (2,656) (1,753) 25,962 ------- ------ ------ March 31 Restated $238,254 $39,593 $54,560 ======= ====== ======
June 30 298,863 55,400 42,334 Adjustment 17,190 11,345 11,345 ------- ------ ------ June 30 Restated $316,053 $66,745 $53,679 ======= ====== ======
September 30 383,087 85,916 75,510 Adjustment 4,103 2,522 2,102 ------- ------ ------ September 30 Restated $387,190 $88,438 $77,612 ======= ====== ======
December 31 (1) $282,031 $(4,697) $(13,426) ======= ====== ====== March 31 $227,513 $46,838 $34,022 June 30 267,959 60,984 47,527 September 30 338,215 95,474 83,426 December 31 279,736 63,369 53,536
(1) Operating and net income includes the effect of a pre-tax charge of $29 million related to the Company's restructuring as discussed in ITEM 7. MANAGEMENTS'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Restructuring.
Quarterly information for 1993 has been restated to reflect the change in accounting for unbilled revenues and the adoption of SFAS No. 112, Employers' Accounting for Postemployment Benefits See NOTE 1, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES. These changes were made in December 1993, but were effective January 1, 1993.
Information for quarterly periods is affected by seasonal variations in sales, rate changes, timing of fuel expense recovery and other factors.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of Central Power and Light Company:
We have audited the accompanying balance sheets and statements of capitalization of Central Power and Light Company (a Texas corporation and wholly owned subsidiary of Central and South West Corporation) as of December 31, 1993 and 1992, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Central Power and Light Company as of December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. In 1993, as discussed in the Notes to the financial statements, the Company changed its methods of accounting for unbilled revenues, postretirement benefits other than pensions, income taxes and postemployment benefits. Our audits were made for the purpose of forming an opinion on the financial statements taken as a whole. The supplemental schedules V, VI, IX, X and Exhibit 12 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules and exhibit have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen & Co.
Dallas, Texas February 25, 1994
REPORT OF MANAGEMENT
Management is responsible for the preparation, integrity and objectivity of the financial statements of Central Power and Light Company as well as all other information contained in this report. The financial statements have been prepared in conformity with generally accepted accounting principles applied on a consistent basis and, in some cases, reflect amounts based on the best estimates and judgments of management, giving due consideration to materiality. Financial information contained elsewhere in this report is consistent with that in the financial statements. The Company maintains an adequate system of internal controls to provide reasonable assurance that transactions are executed in accordance with management's authorization, that financial statements are prepared in accordance with generally accepted accounting principles and that the assets of the Company are properly safeguarded. The system of internal controls is documented, evaluated and tested by the Company's internal auditors on a continuing basis. Due to the inherent limitations of the effectiveness of internal controls no internal control system can provide absolute assurance that errors and irregularities will not occur. However, management strives to maintain a balance, recognizing that the cost of such a system should not exceed the benefits derived. No material internal control weaknesses have been reported to management. Arthur Andersen & Co. was engaged to audit the financial statements of the Company and issue a report thereon. Their audit was conducted in accordance with generally accepted auditing standards. Such standards require an examination of selected transactions and other procedures sufficient to provide reasonable assurance that the financial statements are not misleading and do not contain material errors. The Report of Independent Public Accountants does not limit the responsibility of management for information contained in the financial statements and elsewhere in the report.
Robert R. Carey President and Chief Executive Officer
Melanie J. Richardson Vice President and Treasurer
David P. Sartin Controller and Secretary
REPORT OF AUDIT COMMITTEE
The Audit Committee of the Board of Directors is composed of six outside directors. The members of the Audit Committee are: Robert A. McAllen, Chairman, Jim L. Peterson, Ruben M. Garcia, H. Lee Richards, Pete Morales, Jr. and S. Loyd Neal, Jr. The Committee held two meetings during 1993. The Committee oversees the Company's financial reporting process on behalf of the Board of Directors. The Committee discusses with the internal auditors and the independent public accountants the overall scope and specific plans for their respective audits. The Committee also discusses the Company's financial statements and the adequacy of internal controls. The Committee meets regularly with the Company's internal auditors and independent public accountants to discuss the results of their audits, their evaluations of internal controls, and the overall quality of the Company's financial reporting. The meetings are designed to facilitate any private communication with the Committee desired by the internal auditors or independent public accountants.
Robert A. McAllen Chairman, Audit Committee
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None. PART III
CSW common stock amounts in ITEM 11 and ITEM 12 reflect the two-for-one common stock split, effected by a 100% common stock dividend paid March 6, 1992 to shareholders of record on February 10, 1992.
ITEM 10.


ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
(a) The following is a list of directors of the Company, together with certain information with respect to each of them:
Name, Age, Principal Year Occupation, Business Experience First Became and Other Directorships Director
E. R. BROOKS. . . . . . . . . . . . . . . . . . . AGE - 56 1991
Chairman, President and CEO of CSW since February 1991. President of CSW from September 1990 to February 1991. President and Chief Operating Officer of CSW from January 1990 to September 1990 and Executive Vice President of CSW from 1987 to 1989. Director of CSW and each of its subsidiaries. Director of Hubbell, Electric, Inc. and of Baylor University Medical Center, Dallas, Texas.
ROBERT R. CAREY. . . . . . . . . . . . . . . . . .AGE - 56 1989
President and CEO of the Company since January 1990. Executive Vice President and Chief Operating Officer of the Company from 1989 to 1990. Vice President, Operations of the Company from 1988 to 1989. Director of Corpus Christi National Bank, Corpus Christi, Texas.
RUBEN M. GARCIA. . . . . . . . . . . . . . . . . .AGE - 62 1981
President or principal of several firms engaged primarily in construction and land development in the Laredo, Texas area.
HARRY D. MATTISON (1). . . . . . . . . . . . . . .AGE - 57 1994
Executive Vice President of CSW since September 1990 and Chief Executive Officer of CSWS since December 1993. Chief Operating Officer of CSW from September 1990 to December 1993. President and Chief Executive Officer of SWEPCO from September 1988 to September 1990. Director of each of CSW's wholly owned subsidiaries.
ROBERT A. McALLEN. . . . . . . . . . . . . . . . .AGE - 59 1983
Robert A. McAllen Investments, Inc., Weslaco, Texas. Consultant to First National Bank, Edinburg, Texas.
PETE MORALES, JR. . . . . . . . . . . . . . . . . AGE - 53 1990
President and General Manager of Morales Feed Lots, Inc., Devine, Texas. Director of Devine State Bank, Devine, Texas.
S. LOYD NEAL, JR. . . . . . . . . . . . . . . . . AGE - 56 1990
President of Hilb, Rogal and Hamilton Company of Corpus Christi, an insurance agency, Corpus Christi, Texas.
Name, Age, Principal Year Occupation, Business Experience First Became and Other Directorships Director
JIM L. PETERSON. . . . . . . . . . . . . . . . . .AGE - 58 1989
President and CEO of Whataburger, Inc. from 1974 to 1993. Director of Mercantile Bank of Corpus Christi.
H. LEE RICHARDS. . . . . . . . . . . . . . . . . .AGE - 60 1987
Chairman of the Board of Hygeia Dairy Company, Harlingen, Texas. Director of Harlingen National Bank, Harlingen, Texas.
MELANIE J. RICHARDSON. . . . . . . . . . . . . . .AGE - 37 1993
Vice President, Administration and Treasurer of the Company since 1993. Vice President, Corporate Services and Treasurer of the Company from 1992 to 1993. Treasurer of the Company since March 1992. Director of Internal Audits of the Company 1991 to 1992. Manager of Personnel Services of the Company 1990 to 1991. Manager of Financial Audits of the Company 1986 to 1990.
J. GONZALO SANDOVAL. . . . . . . . . . . . . . . .AGE - 45 1992
Vice President, Operations/Engineering of the Company since 1993. Vice President, Regional Operations of the Company from 1992 to 1993. Vice President, Corporate Services of the Company from 1991 to 1992. General Manager of the Southern Region from 1988 to 1991.
B. W. TEAGUE. . . . . . . . . . . . . . . . . . . AGE - 55 1984
Vice President, Marketing and Business Development of the Company since 1991. Vice President, Corporate Services of the Company from 1988 to 1991. Senior Vice President, District Operations of the Company from 1986 to 1988.
GERALD E. VAUGHN. . . . . . . . . . . . . . . . . AGE - 51 1993
Vice President, Nuclear of CSWS since January 1994. Vice President, Nuclear Affairs of the Company since July 1993. Vice President for Nuclear Services of Carolina Power and Light Company, Raleigh, North Carolina, from 1990 to 1993. Vice President of Nuclear Operations at HLP from 1987 to 1990. __________________________
(1) Mr. Mattison was elected to the Board effective February 1, 1994, replacing Dale E. Ward. Mr. Ward resigned from the Board in January 1994 upon his transfer to CSWS as Vice President of Production Engineering.
All outside directors have engaged in their respective principal occupations listed above for a period of more than five years, unless otherwise indicated.
(b) The following is a list of the executive officers who are not directors of the Company, together with certain information with respect to each of them:
Year First Elected to Present Name Age Present Position Position
David P. Sartin 37 Controller and Secretary 1991
__________________________
Each of the directors and executive officers of the Company is elected to hold office until the first meeting of the Company's Board of Directors after the 1994 annual meeting of stockholders, presently scheduled to be held on April 14, 1994. Each of the executive officers listed in the table above has been employed by the Company or an affiliate in the CSW System in an executive or managerial capacity for at least the last five years except for Mr. Vaughn.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Cash and Other Forms of Compensation
The following table sets forth the aggregate cash and other compensation for services rendered for the fiscal years of 1993, 1992, and 1991 paid or awarded by the Company to the Named Executive Officers.
Option/SAR Grants
No grants of CSW common stock options or CSW SARs were made in 1993.
Option/SAR Exercises and Year-End Value Table
Shown below is information regarding CSW common stock option/SAR exercises during 1993 and unexercised CSW common stock options/SARs at year-end for the Named Executives Officers.
Long-term Incentive Plan Awards Table
The following table shows information concerning awards made to the Named Executive Officers during 1993 under CSW's Long-Term Incentive Plan ("LTIP"):
Long-Term Incentive Plan Awards Made in 1993
Performance Estimated Future or Payouts under Number of CSW Other Period Non-Stock Price Based Plans
Until Shares, Units or Maturation Threshold Target Maximum Name Other Rights (#) or Payout ($) ($) ($)
Robert R. Carey 1 2 years - 137,238 205,857 Dale E. Ward 1 2 years - 28,105 42,158 B. W. Teague 1 2 years - 28,105 42,158 J. Gonzalo Sandoval 1 2 years - 28,105 42,158 C. Wayne Stice 1 - - - -
Payouts of the awards are contingent upon CSW's achieving a specified level of total shareholder return, relative to a peer group of utility companies, for the three-year period ended December 1995. Such return must also exceed the average six-month treasury bill rate for the same period in order for any payout to be made. If the Named Executive Officer's employment is terminated during the performance period for any reason other than death, total and permanent disability or retirement, then the award is generally canceled.
The LTIP contains a provision accelerating awards upon a change in control of CSW. If a change in control of CSW occurs, (a) all options and SARs become fully exercisable, (b) all restrictions, terms and conditions applicable to all restricted stock are deemed lapsed and satisfied and (c) all performance units are deemed to have been fully earned, as of the date of the change in control. Awards which have been granted and outstanding for less than six months as of the date of change in control are not then exercisable, vested or earned on an accelerated basis. The LTIP also contains provisions designed to prevent circumvention of the above acceleration provisions generally through coerced termination of an employee prior to the change in control of CSW.
Retirement Plans Pension Plan Table
Annual Benefits After Average Compensation Specified Years of Credited Service 20 25 30 or more $100,000 . . . . . . . . . . . . . . . $ 33,333 $ 41,667 $ 50,000 150,000 . . . . . . . . . . . . . . . 50,000 62,500 75,000 200,000 . . . . . . . . . . . . . . . 66,667 83,333 100,000 250,000 . . . . . . . . . . . . . . . 83,333 104,167 125,000 300,000 . . . . . . . . . . . . . . . 100,000 125,000 150,000 350,000 . . . . . . . . . . . . . . . 116,333 145,833 175,000
Executive officers are eligible to participate in the tax-qualified, CSW Pension Plan like other employees of the Company. Certain executive officers, including the Named Executive Officers, are also eligible to participate in the CSW Special Executive Retirement Plan (SERP), a non-qualified ERISA excess benefit plan. Such pension benefits depend upon years of credited service, age at retirement and amount of covered compensation earned by a participant. The annual normal retirement benefits payable under the pension and the SERP are based on 1.67% of "average compensation" times the number of years of credited service (reduced by (i) no more than 50% of a participant's age 55 Social Security benefit, and (ii) certain other offset benefits).
"Average compensation" means the average covered compensation (salary as reported in the Summary Compensation Table) during the 36 consecutive months of highest pay during the 120 months prior to retirement. The combined benefit levels in the table above, which include both the pension and SERP, are based on assumed retirement at age 65, the years of credited service shown, continued existence of the plans without substantial change, and payment in the form of a single life annuity.
Respective years of credited service and ages, as of December 31, 1993, for the Named Executive Officers are as follows: Mr. Carey, 26 and 56; Mr. Stice, 30 and 56; Mr. Ward, 21 and 46; Mr. Sandoval, 20 and 45, and Mr. Teague, 30 and 55.
Meetings and Compensation. The Board of Directors held four meetings during 1993. Directors who are not also executive officers and employees of the Company or its affiliates receive annual directors' fees of $6,000 for serving on the Board and a fee of $300 plus expenses for each meeting of the Board or committee attended.
Those directors who are not also officers of the Company are eligible to participate in a deferred compensation plan. Under this plan such directors may elect to defer payment of annual directors' and meeting fees until they retire from the Board or as they otherwise direct.
Compensation Committee Interlocks and Insider Participation. No person serving during 1993 as a member of the Executive Compensation Committee of the Board of Directors of CSW served as an officer or employee of the Company during or prior to 1993. No person serving during 1993 as an executive officer of the Company serves or has served on the compensation committee or as a director of another company, one of whose executive officers serves as a member of the Executive Compensation Committee of CSW or as a director of the Company.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
All 6,755,535 shares of the Company's outstanding Common Stock, $25 par value, per share, are owned beneficially and of record by CSW, 1616 Woodall Rodgers Freeway, Dallas, Texas 75202.
Security Ownership of Management
The following table shows CSW common stock beneficially owned as of December 31, 1993, by each director, the Named Executive Officers and, as a group, all directors and executive officers of the Company. Share amounts shown in this table include restricted stock, options exercisable within 60 days after year-end shares of CSW common stock credited to Central and South West Corporation Thrift plan accounts, and all other shares of CSW common stock beneficially owned by the listed persons. Each person has a sole voting and investment power with respect to all shares listed in the table below unless otherwise indicated.
Beneficial Ownership as of December 31, 1993 Name CSW Common Stock (1)(2)
E. R. Brooks 60,959 Robert R. Carey 10,734 Ruben M. Garcia - Robert A. McAllen 2,000 Pete Morales, Jr. - S. Loyd Neal, Jr. 323 Jim L. Peterson - H. Lee Richards - Melanie J. Richardson 757 J. Gonzalo Sandoval 6,225 C. Wayne Stice 4,087 B. W. Teague 2,701 Gerald E. Vaughn 500 Dale E. Ward 8,659
All of the above and other executive officers as a group 99,192 ____________________
(1) Included in these amounts for Mr. Brooks, Mr. Carey, Mr. Mattison, Mr. Stice, Mr. Ward, Mr. Teague and Mr. Sandoval are restricted stock of 7,172, 3,963, 4,708, 0, 948, 726 and 264, respectively. These individuals have voting power, but not investment power with respect to these shares. The above shares also include 9,531, 5,643, 6,176, 1,015, 1,045, 0, 971, and 938 shares underlying immediately exercisable options held by Mr. Brooks, Mr. Carey, Mr. Mattison, Mr. Stice, Mr. Ward, Mr. Teague, Mr. Sandoval and the directors and executive officers as a group, respectively.
(2) All directors' and executive officers' shares owned as of January 1, 1994, as indicated are owned directly and aggregate less than one percent of the outstanding shares of such class.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None. PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
Page Reference
(a) Financial Statements (Included under "ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA"):
Report of Independent Public Accountants. 42
Statements of Income for the years ended 24 December 31, 1993, 1992 and 1991.
Statements of Retained Earnings for the 24 years ended December 31, 1993, 1992 and 1991.
Balance Sheets as of December 31, 1993 25 and 1992.
Statements of Cash Flows for the years 26 ended December 31, 1993, 1992 and 1991.
Statements of Capitalization as of 27 December 31, 1993 and 1992.
Notes to Financial Statements. 28-41
(b) Reports on Form 8-K:
The Company filed a report on Form 8-K dated March 10, 1994, reporting ITEM 5. OTHER EVENTS relating to the STP outage and current rate case proceedings.
(c) Exhibits:
3. (a) Restated Articles of Incorporation, as - amended, of the Company (incorporated herein by reference to Exhibit 4(a) to the Company's Registration Statement No. 33-4897, Exhibits 5 and 7 to Form U-1 File No. 70-7171, Exhibits 5, 8.1, 8.2 and 19 to Form U-1 File No. 70-7472 and the Company's Form 10-Q for the quarterly period ended September 30, 1992, ITEM 6, Exhibit 1).
(b) Bylaws, as amended, of the Company. - (Incorporated herein by reference to Exhibit 3(b) to the Company's 1991 Form 10-K, file No. 0-346.)
Page Reference
4. Indenture of Mortgage or Deed of - Trust dated November 1, 1943, executed by the Company to The First National Bank of Chicago and Robert L. Grinnell, as Trustees, as amended through October 1, 1977 (incorporated herein by reference to Exhibit 5.01 in File No. 2-60712), and the Supplemental Indentures of the Company dated September 1, 1978 (incorporated herein by reference to Exhibit 2.02 in File No. 2-62271) and December 15, 1984, July 1, 1985, May 1, 1986 and November 1, 1987 (incorporated herein by reference to Exhibit 17 to Form U-1 File No. 70-7003, Exhibit 4(b) in File No. 2-98944, Exhibit 4 to Form U-1 File No. 70-7236 and Exhibit 4 to Form U-1 File No. 70-7249) and June 1, 1988, December 1, 1989, March 1, 1990, October 1, 1992, December 1, 1992, February 1, 1993 and April 1, 1993 (incorporated herein by reference to Exhibit 2 to Form U-1 File No. 70-7520, Exhibit 3 to Form U-1 File No. 70-7721, Exhibit 10 to Form U-1 File No. 70-7735 and Exhibit 10(a), 10(b), 10(c) and 10(d), respectively, to Form U-1 File No. 70-8053).
12. Statement re computation of Ratio of 61 Earnings to Fixed Charges for the five years ended December 31, 1993.
18. Letter from Independent Public Accountants 62 for change in accounting principle.
23. Consent of Independent Public 63 Accountants.
24. (a) Powers of Attorney. 64
(b) Powers of Attorney. 65
(c) Powers of Attorney. 66
Page Reference
(d) Schedules:
Report of Independent Public 42 Accountants on Supplemental Schedules and Exhibit.
V. Property, Plant and Equipment for the 56 years ended December 31, 1993, 1992 and 1991.
VI. Accumulated Depreciation, Depletion 57 and Amortization of Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991.
IX. Short-Term Borrowings for the years 58 ended December 31, 1993, 1992 and 1991.
X. Supplementary Income Statement 59 Information for the years ended December 31, 1993, 1992 and 1991.
All other exhibits and schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements and related notes to financial statements.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 15, 1994.
CENTRAL POWER AND LIGHT COMPANY
By: David P. Sartin Controller and Secretary
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 15, 1994.
Signature Title
Robert R. Carey President and CEO and Director (Principal executive officer)
Melanie J. Richardson Vice President, Treasurer and Director (Principal financial officer)
David P. Sartin Controller and Secretary (Principal accounting officer)
*E. R. Brooks Director *Ruben M. Garcia Director *Harry D. Mattison Director *Robert A. McAllen Director *Pete Morales, Jr. Director *S. Loyd Neal, Jr. Director *Jim L. Peterson Director *H. Lee Richards Director *J. Gonzalo Sandoval Director *B. W. Teague Director *Gerald E. Vaughn Director
*Melanie J. Richardson, by signing her name hereto, does sign this document on behalf of the persons indicated above pursuant to a power of attorney duly executed by each such person.
*By: Melanie J. Richardson Attorney-in-Fact
SCHEDULE X
CENTRAL POWER AND LIGHT COMPANY SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31
1993 1992 1991 (thousands)
Real estate and personal property taxes $55,255 $41,003 $38,817 State gross receipts taxes 14,173 13,685 13,099 Payroll taxes 8,300 7,288 7,032 Franchise taxes 6,420 6,284 1,265(a) State utility commission assessments 1,913 1,822 1,784 Other taxes 333 261 456
$86,394 $70,343 $62,453
____________________
(a) A refund of approximately $3.6 million related to prior years was received in 1991.
The amounts of taxes, depreciation and maintenance charged to accounts other than income and expense accounts were not significant. Rents, royalties, advertising and research and development costs during these years were not significant.
INDEX TO EXHIBITS Exhibit Transmission Number Exhibit Method
3(a) Restated Articles of Incorporation, as Incorporated amended, of the Company (incorporated by Reference herein by reference to Exhibit 4(a) to the Company's Registration Statement No. 33-4897, Exhibits 5 and 7 to Form U-1 File No. 70-7171, Exhibits 5, 8.1, 8.2 and 19 to Form U-1 File No. 70-7472 and the Company's Form 10-Q for the quarterly period ended September 30, 1992, ITEM 6, Exhibit 1).
3(b) Bylaws, as amended, of the Company. Incorporated (Incorporated herein by reference to by Reference Exhibit 3(b) to the Company's 1990 Form 10-k, File No. 0-346).
4 Indenture of Mortgage or Deed of Trust Incorporated dated November 1, 1943, executed by the by Reference Company to The First National Bank of Chicago and Robert L. Grinnell, as Trustees, as amended through October 1, 1977 (incorporated herein by reference to Exhibit 5.01 in File No. 2-60712), and the Supplemental Indentures of the Company dated September 1, 1978 (incorporated herein by reference to Exhibit 2.02 in File No. 2-62271) and December 15, 1984, July 1, 1985, May 1, 1986 and November 1, 1987 (incorporated herein by reference to Exhibit 17 to Form U-1 File No. 70-7003, Exhibit 4(b) in File No. 2-98944, Exhibit 4 to Form U-1 File No. 70-7236 and Exhibit 4 to Form U-1 File No. 70-7249) and June 1, 1988, December 1, 1989, March 1, 1990, October 1, 1992, December 1, 1992, February 1, 1993 and April 1, 1993, (incorporated herein by reference to Exhibit 2 to Form U-1 File No. 70-7520 and Exhibit 3 to Form U-1 File No. 70-7721, Exhibit 10 to Form U-1 File No. 70-7725 and Exhibit 10(a), 10(b), 10(c) and 10(d), respectively, to Form U-1 File No. 70-8053).
12 Statement re computation of Ratio of Electronic Earnings to Fixed Charges for the five years ended December 31, 1992.
18 Letter from Independent Public Accountants for change in accounting principle. Electronic
23 Consent of Independent Public Accountants. Electronic
24(a) Powers of Attorney. Electronic
24(b) Powers of Attorney. Electronic
24(c) Powers of Attorney. Electronic
EXHIBIT 12